99-8939. Acid Rain Program; Continuous Emission Monitoring Rule Revisions  

  • [Federal Register Volume 64, Number 101 (Wednesday, May 26, 1999)]
    [Rules and Regulations]
    [Pages 28564-28672]
    From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
    [FR Doc No: 99-8939]
    
    
    
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    _______________________________________________________________________
    
    Part II
    
    
    
    
    
    Environmental Protection Agency
    
    
    
    
    
    _______________________________________________________________________
    
    
    
    40 CFR Parts 72 and 75
    
    
    
    Acid Rain Program; Continuous Emission Monitoring Rule Revisions; Final 
    Rule
    
    Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules 
    and Regulations
    
    [[Page 28564]]
    
    
    
    ENVIRONMENTAL PROTECTION AGENCY
    
    40 CFR Parts 72 and 75
    
    [FRL-6320-8]
    RIN 2060-AG46
    
    
    Acid Rain Program; Continuous Emission Monitoring Rule Revisions
    
    AGENCY: Environmental Protection Agency (EPA).
    
    ACTION: Final rule.
    
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    SUMMARY: Title IV of the Clean Air Act (CAA or the Act), as amended by 
    the Clean Air Act Amendments of 1990, authorizes the Environmental 
    Protection Agency (EPA or Agency) to establish the Acid Rain Program. 
    The Acid Rain Program and the provisions in this final rule benefit the 
    environment by ensuring that the sulfur dioxide (SO2), 
    nitrogen oxides (NOX) and carbon dioxide (CO2) 
    air pollution emissions to be measured and tracked pursuant to the 
    provisions of 40 CFR part 75 are accurately monitored and reported. 
    These provisions also benefit the regulated entities by providing 
    additional flexibility and improved cost effectiveness to the 
    monitoring and reporting options available to part 75 subject sources. 
    On January 11, 1993, the Agency promulgated final rules, including the 
    final continuous emission monitoring (CEM) rule, under title IV. On May 
    17, 1995 and November 20, 1996, the Agency revised the CEM rule to make 
    the implementation simpler. On May 21, 1998, the Agency proposed 
    additional revisions to the CEM rule, to make implementation easier and 
    more efficient for both EPA and the facilities affected by the rule, to 
    improve quality assurance requirements, and to create new alternative 
    monitoring options. EPA promulgated final rule revisions addressing 
    some of these additional proposed revisions, based on comments 
    received, when EPA promulgated a Finding of Significant Contribution 
    and Rulemaking for Certain States in the Ozone Transport Assessment 
    Group Region for Purposes of Reducing Regional Transport of Ozone 
    (NOX SIP call).
        In this action, EPA is issuing final rule revisions addressing the 
    remaining May 21, 1998 proposed revisions to the CEM rule, with certain 
    changes to the proposal based on the public comments received. Some of 
    these revisions will be relevant for sources that become subject to 
    part 75 requirements in response to the NOX SIP call.
    
    DATES: The effective date of this rule is June 25, 1999. The 
    incorporation by reference of certain publications listed in the 
    regulations is approved by the Director of the Federal Register as of 
    June 25, 1999.
    
    ADDRESSES: Docket. Supporting information used in developing the 
    regulations is contained in Docket No. A-97-35. This docket is 
    available for public inspection and photocopying between 8:00 a.m. and 
    5:30 p.m. Monday through Friday, excluding government holidays and is 
    located at: EPA Air Docket (MC 6102) , Room M-1500, Waterside Mall, 401 
    M Street, SW, Washington, DC 20460. A reasonable fee may be charged for 
    photocopying.
    
    FOR FURTHER INFORMATION CONTACT: Monika Chandra, Acid Rain Division 
    (6204J), U.S. Environmental Protection Agency, 401 M Street, SW, 
    Washington, DC 20460, (202) 564-9781.
    
    SUPPLEMENTARY INFORMATION: The contents of the preamble are listed in 
    the following outline:
    
    I. Regulated Entities
    II. Background and Summary of Final Rule
    III. Summary of Major Comments and Responses
        A. Certification/Recertification Procedural Changes
        B. Quality Assurance Requirements for Quantifying Stack Gas 
    Moisture Content
        C. Percent Monitor Availability
        D. Span and Range Requirements
        E. Flow-to-Load Ratio Test Requirements
        F. RATA and Bias Test Requirements
        1. RATA Load Levels
        2. Single Point Reference Method Sampling
        G. Data Validation
        1. Data Validation During Monitor Certification and 
    Recertification
        2. Data Validation for RATAs and Linearity Checks
        H. Appendix D--Sulfur Dioxide Emissions from the Combustion of 
    Gaseous Fuels
        1. Summary of EPA Analysis of Appendix D Gaseous Fuel 
    SO2 and Heat Input Methodologies
        2. Changes to the Definitions of ``Pipeline Natural Gas'' and 
    ``Natural Gas''
        3. Changes to the Methodology for Calculating SO2 
    Emissions Under Appendix D
        4. Changes to the Applicability of Appendix D
        5. Changes to the Method of Determining the Sulfur Content 
    Sampling Frequency for Gaseous Fuels
        6. Changes to the Method of Determining the GCV Sampling 
    Frequency for Gaseous Fuels
        I. Electronic Transfer of Quarterly Reports
        J. Bias, Relative Accuracy and Availability Determinations
        K. Appendix I--Proposed Optional Stack Flow Monitoring 
    Methodology
        L. Subpart H--Clarifications to NOX Mass Monitoring 
    Requirements
    IV. Administrative Requirements
        A. Public Docket
        B. Executive Order 12866
        C. Unfunded Mandates Reform Act
        D. Executive Order 12875
        E. Executive Order 13084
        F. Paperwork Reduction Act
        G. Regulatory Flexibility
        H. Submission to Congress and the General Accounting Office
        I. Executive Order 13045
        J. National Technology Transfer and Advancement Act
    
    I. Regulated Entities
    
        Entities regulated by this action are fossil fuel-fired boilers and 
    turbines that serve generators producing electricity, generate steam, 
    or cogenerate electricity and steam. While part 75 primarily regulates 
    the electric utility industry, the recent promulgation of 40 CFR part 
    96 and certain revisions to part 75 (see 63 FR 57356, October 27, 1998) 
    means that part 75 could potentially affect other industries. The 
    recent adoption of part 96, together with revisions to part 75, include 
    nitrogen oxides (NOX) mass provisions for the purpose of 
    serving as a model which could be adopted by a state, tribal, or 
    federal NOX mass reduction program covering the electric 
    utility and other industries. Regulated categories and entities 
    include:
    
    ------------------------------------------------------------------------
                                                    Examples of regulated
                     Category                             entities
    ------------------------------------------------------------------------
    Industry..................................  Electric service providers,
                                                 boilers, turbines and other
                                                 process sources where
                                                 emissions exhaust through a
                                                 stack.
    ------------------------------------------------------------------------
    
    This table is not intended to be exhaustive, but rather provides a 
    guide for readers regarding entities likely to be regulated by this 
    action. This table lists the types of entities which EPA is now aware 
    could potentially be regulated by this action. Other types of entities 
    not listed in the table could also be regulated. To determine whether 
    your facility, company, business, organization, etc., is regulated by 
    this action, you should carefully examine the applicability provisions 
    in Secs. 72.6, 72.7, 72.8, and part 96 of title 40 of the Code of 
    Federal Regulations. If you have questions regarding the applicability 
    of this action to a particular entity, consult the person listed in the 
    preceding FOR FURTHER INFORMATION CONTACT section of this preamble.
    
    II. Background and Summary of Final Rule
    
        Title IV of the Act requires EPA to establish an Acid Rain Program 
    to reduce the adverse effects of acidic deposition. On January 11, 
    1993, the
    
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    Agency promulgated final rules implementing the program, including the 
    CEM rule (58 FR 3590). Notices of direct final rulemaking and of 
    interim final rulemaking further amending the regulations were 
    published on May 17, 1995 (60 FR 26510 and 60 FR 26560). Subsequently, 
    on November 20, 1996, a final rule was published in response to public 
    comments received on the direct final and interim rules (61 FR 59142). 
    On May 21, 1998, the Agency published proposed revisions to the part 75 
    CEM regulations (62 FR 28032). As noted above, EPA recently promulgated 
    final revisions to part 75 addressing some of the May 21, 1998, 
    proposed revisions in conjunction with the promulgation of a Model 
    NOX Trading Rule in part 96 and the NOX SIP call 
    (see 63 FR 57356).
        Today's action adopts final part 75 revisions to address the 
    remaining May 21, 1998, proposed revisions and to make minor technical 
    corrections to the part 75 provisions promulgated in conjunction with 
    part 96 and the NOX SIP Call. The final revisions involve 
    the following matters: (1) revised definitions of gas-fired, oil-fired, 
    and peaking unit to allow for changes in unit fuel usage and/or 
    operation; (2) a minor wording correction to the applicability 
    provisions in part 72; (3) new quality assurance/quality control (QA/
    QC) requirements for quantifying stack gas moisture content; (4) 
    clarifying changes to the certification and recertification process; 
    (5) substitute data requirements for carbon dioxide (CO2), 
    heat input and moisture; (6) clarifying revisions to the petition 
    provisions for alternatives to part 75 requirements; (7) clarifying 
    changes to span and range requirements; (8) clarifying revisions to 
    general QA/QC requirements; (9) calibration error test requirements; 
    (10) linearity test requirements; (11) a new flow-to-load QA test for 
    flow monitors; (12) reductions in and/or clarifications to the relative 
    accuracy test audit (RATA) and bias test requirements; (13) clarifying 
    revisions to the procedures for CEM data validation; (14) clarifying 
    revisions to the sulfur dioxide (SO2) emissions data 
    protocol for gas-fired and oil-fired units (Appendix D); (15) 
    determination of CO2 emissions under Appendix G; (16) 
    recordkeeping and reporting changes to reflect the proposed revisions; 
    (17) a revised traceability protocol for calibration gases (Appendix 
    H); and (18) NOX mass emission recordkeeping and reporting 
    provisions, and minor revisions to NOX mass monitoring 
    requirements.
        Many of these changes are minor technical revisions based on 
    comments received from facilities following the initial implementation 
    of part 75. Based on experience gained in the early years of the 
    program, facilities have developed a number of suggestions that will 
    simplify and streamline the monitoring process without sacrificing data 
    quality. The Agency has also amended quality assurance requirements 
    based on gaps identified by EPA during evaluation of the initial 
    implementation of part 75. Finally, several minor technical changes 
    have been made in order to maintain uniformity within the rule itself 
    and to clarify various provisions.
    
    III. Summary of Major Comments and Responses
    
    A. Certification/Recertification Procedural Changes
    
        Background: EPA proposed to revise the recertification application 
    review period in Sec. 75.20(b)(5) from 60 days to 120 days, which is 
    the same review period as for the initial certification application. 
    The Agency believes that this will reduce confusion, simplify 
    certification/recertification application tracking, and will result in 
    the more efficient allocation of resources by local, state, and federal 
    agencies. Therefore, EPA has adopted this change in the final rule with 
    certain modifications in response to issues raised by commenters.
        Discussion: Two states responded positively to the proposed change. 
    One state commented that the increased review time ``will allow more 
    effective use of staff resources and provide ample time for a thorough 
    review of the data submitted in the application'' (see Docket A-97-35, 
    Item IV-D-6). Another state commenter remarked that extending the 
    review period ``adds uniformity and consistency to the certification 
    and recertification process. This change is positive, and it allows the 
    state agencies the time to resolve minor deficiencies which may 
    otherwise serve as grounds to recommend disapproval. Based on 
    experience, the 120 day period is absolutely essential for the review 
    of certification/recertification applications'' (see Docket A-97-35, 
    Item IV-D-9).
        Several commenters suggested that if EPA disapproved a 
    recertification application after the 120 day period, data recorded 
    during the entire 120 day period would become invalid and the use of 
    substitute data would be required (see Docket A-97-35, Items IV-D-17, 
    IV-D-20 and IV-D-24). However, as EPA stated in the preamble to the 
    proposal, ``less than 2 percent of all monitoring system applications 
    submitted between 1992 and September 1997 were disapproved'' (63 FR 
    28045, citing Docket A-97-35, Item II-A-4). As experience with the 
    program increases, the number of disapprovals is expected to decrease 
    even further. In addition, EPA's position is that the owners or 
    operators of affected facilities are responsible for initiating, 
    conducting, evaluating and certifying the results of the required 
    testing prior to submission to the appropriate regulatory Agencies. The 
    Agencies' role is to ``certify'' or verify the results. Thus, there is 
    no reason to expect that the additional time provided to meet the 
    administrative needs of the program will result in any significant 
    compliance risk to the regulated sources, except in instances where 
    insufficient care is taken to ensure proper conduct of the testing.
        Two commenters stated that the owner or operator would be in 
    violation of the requirements of proposed Sec. 75.33(d) and 
    Sec. 75.10(a) if a recertification application were disapproved after 
    120 days (see Docket A-97-35, Items IV-D17 and IV-D-23) because the 
    percent monitor availability would be below 80%. These proposed 
    penalties have been withdrawn from the final rule in response to 
    comments received. Today's final rule does not treat a percent monitor 
    data availability of less than 80% as a violation. Instead, the final 
    rule provides that if percent monitor data availability is less than 
    80%, then the appropriate maximum value (e.g., maximum potential 
    concentration) or, in some cases, the appropriate minimum potential 
    value will be used to provide substitute data (see Section C of this 
    preamble for a further discussion of these provisions).
        Several commenters suggested that since the review of the initial 
    certification applications for the Acid Rain Phase I and Phase II units 
    has been completed, the burden on the states and EPA has been removed . 
    Therefore, it should not take EPA 120 days to review recertification 
    applications (see Docket A-97-35, Items IV-D-14, IV-D-20, and IV-D-24). 
    This argument would be more compelling if the Acid Rain Program were 
    the only program that the various regulatory agencies are required to 
    implement. However, EPA and the States are currently responsible for 
    implementing several other programs that require comprehensive 
    administrative review of various types of applications and petitions 
    (e.g., Compliance Assurance Monitoring (CAM), the OTC NOX 
    Budget Program, the PSD program and Title V permitting). EPA also 
    anticipates that the NOX SIP call will further increase the 
    number of certification and recertification applications and
    
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    petitions that need to be reviewed by the regulatory agencies.
        Many recertifications require the same tests as for initial 
    certification. Therefore, recertification applications often take as 
    much effort to review as certification applications. It is also 
    sometimes difficult to distinguish a recertification application 
    package from an initial certification application package, which can 
    complicate tracking the two types of applications if they have 
    different review periods. The recertification process usually requires 
    that a state or local program perform the initial review and forward 
    the results to the EPA regional office which will then make a 
    recommendation to EPA headquarters on whether to approve or disapprove 
    the application. This requires a significant amount of time and does 
    not allow much time to coordinate with the source to get additional 
    information, when needed. There is more likelihood of a disapproval 
    being issued under a short time frame. Finally, EPA notes that it does 
    not have control over the number of recertification applications that 
    are submitted. Individual utility choices, changes in rules, market 
    conditions, and technology all influence the number of 
    recertifications. Therefore, EPA has concluded that extending the 
    application review period from 60 to 120 days is both necessary and 
    appropriate.
    
    B. Quality Assurance Requirements for Quantifying Stack Gas Moisture 
    Content
    
        Background: Section 75.11(b) of the January 11, 1993 Acid Rain rule 
    requires the owner or operator to continuously (or on an hourly basis) 
    account for the moisture content of the stack gas when SO2 
    concentration is measured on a dry basis. The moisture content is 
    needed to correct the measured hourly stack gas volumetric flow rates 
    to a dry basis when calculating SO2 mass emission rates in 
    lb/hr. Section 75.13(a) of the rule, as amended on May 17, 1995, 
    contains provisions for CO2 monitoring paralleling the 
    provisions of Sec. 75.11(b); that is, when CO2 concentration 
    is measured on a dry basis, a correction for stack gas moisture content 
    is needed to accurately determine the CO2 mass emissions. 
    The stack gas moisture content is also needed when a dry-basis 
    O2 monitor is used to account for CO2 emissions 
    and, in some instances, when accounting for unit heat input or when 
    determining NOX emission rate in lb/mmBtu.
        As presently codified, part 75 does not specify any quality 
    assurance requirements for moisture measurement devices. Approximately 
    5 to 10 percent of the continuous emission monitors in the Acid Rain 
    Program require moisture corrections to accurately measure 
    SO2, CO2, or NOX emissions or heat 
    input (see Docket A-97-35, Item II-I-6 ). The accuracy of the stack gas 
    moisture measurements directly affects the accuracy of the reported 
    SO2 mass emission rates, CO2 mass emission rates, 
    NOX emission rates and heat input values. An error of 1.0 
    percent H2O in measured moisture content causes a 1.0 
    percent error in the reported emission rate or heat input value. 
    Failure to quality assure the moisture data can therefore result in 
    significant under-reporting of SO2, CO2, and 
    NOX emissions and heat input.
        In the May 21, 1998 proposed rule, EPA set forth quality assurance 
    procedures that would apply to moisture monitoring systems because the 
    Agency believes that when moisture corrections must be applied, 
    continuous, quality assured, direct measurement of the stack gas 
    moisture content or continuous measurement of surrogate parameters for 
    moisture, such as wet-and dry-basis oxygen concentrations, is the best 
    way to ensure the accuracy of the reported emission data. The proposed 
    rule specified that a moisture monitoring system could consist of 
    either: (1) a continuous moisture sensor; (2) an oxygen (O2) 
    analyzer (or analyzers) capable of measuring O2 on both a 
    wet basis and on a dry basis; or (3) a system consisting of a 
    temperature sensor and a certified data acquisition and handling system 
    (DAHS) component capable of determining moisture from a lookup table, 
    i.e., a psychometric chart (this third option would apply only to 
    saturated gas streams following wet scrubbers).
        The proposed rule included requirements for the initial 
    certification of moisture monitoring systems. For continuous moisture 
    sensors, a 7-day calibration error test and a relative accuracy test 
    audit (RATA) would be required. For moisture monitoring systems 
    consisting of one or more wet-and dry-basis oxygen analyzers, the 
    proposed requirements included a 7-day calibration error test, a 
    linearity test and a cycle time test of each O2 analyzer, 
    and a RATA of the moisture measurement system. For the lookup table 
    option (saturated streams, only), the certification requirement would 
    consist of a DAHS verification. The proposed rule specified that owners 
    or operators would have to complete all moisture monitoring system 
    certification tests no later than January 1, 2000.
        The proposed rule contained performance specifications for moisture 
    monitoring systems. These specifications would apply to continuous 
    moisture sensors and to wet-and dry-basis oxygen analyzers. For 
    moisture monitoring systems consisting of wet-and dry-basis 
    O2 analyzers, the proposed span values and performance 
    specifications for calibration error, linearity, and cycle time would 
    be the same as the current specifications for O2 monitors. 
    For moisture sensors, a calibration error specification of 3.0% of span 
    was proposed. The proposed relative accuracy (RA) specification for all 
    moisture monitoring systems would be 10.0 percent. An alternative RA 
    specification was also proposed, i.e., the RA test results would be 
    considered acceptable if the mean difference of the reference method 
    measurements and the moisture monitoring system measurements is within 
     1.0 percent H2O.
        On-going QA requirements for moisture monitoring systems were also 
    proposed. Appendix B would be revised to require daily calibrations of 
    moisture monitoring systems, quarterly linearity checks of wet-and dry-
    basis oxygen analyzer(s), and semiannual RATAs of moisture monitoring 
    systems. Any moisture monitoring system achieving a relative accuracy 
    of 7.5 percent or a mean difference between the CEMS and 
    reference method values within  0.7 percent H2O, 
    would qualify for an annual, rather than semiannual RATA frequency.
        Missing data procedures for moisture were included in the proposed 
    rule in a new section, Sec. 75.37. Provided that the moisture data 
    availability is high (90.0 percent), the average of the 
    ``hour before'' and ``hour after'' moisture values would be used for 
    each hour of the missing data period. When the percent data 
    availability drops below 90.0 percent, 0.0 percent moisture would be 
    substituted for each hour of the missing data period.
        Finally, the proposed rule specified that records must be kept for 
    the moisture monitoring systems, including hourly average moisture 
    readings, percent data availability, and records of all calibration 
    error tests, linearity tests and relative accuracy test audits.
        Today's final rule provides a number of options by which owners or 
    operators of affected sources may account for the stack gas moisture 
    content on an hourly basis. The rule also includes quality assurance 
    provisions for moisture monitoring systems. Today's rule differs from 
    the proposed rule as follows: (1) the alternate specification in terms 
    of the mean difference has been increased
    
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    from  1.0 to  1.5% H2O, but the 
    principal relative accuracy specification for moisture monitoring 
    systems has been promulgated as proposed, at 10.0 percent; (2) the 
    daily calibration requirement for continuous moisture sensors has been 
    withdrawn; (3) the use of the lookup table option has been expanded to 
    include any demonstrably saturated gas stream, rather than limiting it 
    to gas streams following wet scrubbers; (4) a site-specific coefficient 
    or constant (``K'' factor), determined at the time of the RATA, may be 
    used to calibrate the moisture monitoring system with respect to EPA 
    Reference Method 4; and (5) in lieu of continuously monitoring the 
    stack gas moisture content, a conservative, fuel-specific default 
    moisture percentage may be reported for each unit operating hour (for 
    coal and wood, only).
        Discussion: Two state agencies agreed with EPA that there is a need 
    for quality assurance of moisture monitoring systems (see Docket A-97-
    35, Items IV-D-06 and IV-D-09). A third state agency disagreed with the 
    proposed QA/QC for the moisture monitors, contending that the proposed 
    amendments provide no added benefit in terms of data quality (see 
    Docket A-97-35, Item IV-D-11). That same state agency objected to 
    quality assuring a ``sub-channel'' parameter such as moisture, claiming 
    that it is inconsistent with the way EPA quality assures other combined 
    monitoring systems (such as a NOX-diluent system). The 
    commenter expressed confidence that existing daily, quarterly, 
    semiannual and annual QA/QC on the gas and flow rate monitors is 
    sufficient to ensure data quality, and that if the CEMS moisture value 
    is significantly in error, RATA limits would probably not be met. EPA 
    notes, however, that the commenter provided no data to demonstrate that 
    this is true. The Agency also does not agree with the commenter's 
    characterization of moisture as a ``sub-channel'' parameter. The 
    attempt to draw an analogy between moisture monitoring and the 
    NOX-diluent monitoring system is inappropriate. Under part 
    75, the moisture measurement system is a separate entity and should be 
    quality-assured as such. The moisture monitor is not a component of any 
    ``combined'' monitoring system. The only true combined monitoring 
    systems under part 75 are the NOX-diluent and 
    SO2-diluent monitoring systems, for which the relative 
    accuracy is determined on a combined basis, in lb/mmBtu (i.e., the 
    individual relative accuracies of the pollutant and diluent component 
    monitors are not determined).
        Several commenters indicated that they do not believe that a 
    moisture monitoring system can meet the proposed relative accuracy (RA) 
    specifications of 10.0% for a semiannual RATA frequency or 7.5% for an 
    annual RATA frequency. One commenter expressed the opinion that the RA 
    for a moisture monitoring system should be 15.0% (see Docket A-97-35, 
    Item IV-G-04). Another commenter suggested that the principal RA 
    specification should be 10% 15% for a semiannual RATA 
    frequency and RA 10% for an annual RATA frequency, and that 
    the alternate RA specification, in terms of the mean difference, should 
    be  2.0% H2O for a semiannual frequency and 
     1.5% for an annual RATA frequency (see Docket A-97-35, 
    Item IV-D-23). Another commenter noted that even slight drift in 
    measurements can result in significant errors in the moisture 
    measurements (see Docket A-97-35, Item IV-D-20). One commenter 
    requested that EPA consider the following alternatives to the proposed 
    QA/QC requirements for moisture monitors: (1) eliminate the moisture RA 
    requirement; (2) for wet and dry oxygen analyzers, allow relative 
    accuracy testing of the oxygen analyzer(s) rather than requiring a RATA 
    of the moisture system; (3) allow the use of a default value for 
    moisture, in lieu of monitoring moisture continuously; or (4) subtract 
    the absolute value of the average moisture values generated by the 
    moisture monitoring system from the average reference method value at 
    the time of a RATA and use the difference to correct all subsequent 
    moisture data until the next RATA (see Docket A-97-35, Item IV-D-02).
        Only one set of data was submitted by the commenters for a moisture 
    monitoring system RATA. The data set indicated that the moisture 
    monitoring system, which consisted of wet and dry-basis oxygen 
    analyzers, could achieve an RA of 16.5% (see Docket A-97-35, Item, IV-
    D-02). Note, however, that when the moisture monitoring system data and 
    the reference method data were compared, the moisture monitoring system 
    consistently indicated a moisture value that was approximately 3% 
    H2O higher than the reference method, with a confidence 
    coefficient of 0.507. The low confidence coefficient indicates that the 
    moisture monitoring system readings were consistently biased high with 
    respect to the reference method. Therefore, it appears that a suitable 
    coefficient or constant (``K'' factor) could be applied to the moisture 
    system readings, to make the moisture monitoring system readings agree 
    with the reference method. In this case, subtracting 3% moisture from 
    the average moisture monitoring system values for each run caused the 
    relative accuracy to drop from 16.5% to 2.4%, which is well below the 
    proposed 10.0% semiannual and 7.5% annual RA specifications. For the 
    alternate RA specification, after applying the 3% moisture correction, 
    the mean difference was essentially zero, which is also well below the 
    value of 1.0% moisture proposed for a semiannual RATA frequency and the 
    value of 0.7% moisture proposed for an annual RATA frequency. This 
    ``K'' factor approach, which was suggested by one of the commenters, 
    has a precedent in the Acid Rain Program. Nearly all flow monitors must 
    be calibrated to match the EPA reference method (i.e., Method 2), by 
    using either a constant or a polynomial equation with multiple 
    coefficients. Section 6.5.7 of Appendix A of today's rule allows such 
    ``K'' factors to be developed for moisture monitoring systems. The 
    ``K'' value, which would be established at the time of the semiannual 
    or annual RATA, would be programmed into the DAHS and applied to the 
    subsequent moisture data. Sections 75.56 (a)(5)(ix) and 75.59 
    (a)(5)(vii) of today's rule require the owner or operator to keep 
    records on-site, indicating the current value of the coefficient or 
    ``K'' factor and the date on which it began to be used. The rule 
    further requires a RATA of the moisture monitoring system whenever the 
    coefficient or ``K'' factor is changed.
        Relative accuracy specifications of 10.0% (for semiannual RATA 
    frequency) and 7.5% (for annual RATA frequency) for moisture monitoring 
    systems have been promulgated in today's rule, as proposed. The 
    alternate RA specifications of  1.0% H2O (for 
    semiannual RATA frequency) and
     0.7% H2O (for annual RATA frequency) have been 
    increased, respectively, to
     1.5% H2O and 1.0% H2O. 
    In view of EPA's decision to allow the use of site-specific ``K'' 
    factors for moisture monitoring systems, the Agency believes that 
    affected utilities will be able to meet these RA specifications.
        The proposed rule set forth a missing data procedure for moisture 
    monitoring systems. Two commenters expressed concern regarding the 
    establishment of such a ``conservative'' missing data procedure (see 
    Docket A-97-35, Items IV-D-11 and IV-D-20). One of these commenters 
    further stated that there are insufficient data to know what 
    availability can reasonably be expected from moisture monitoring 
    systems,
    
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    especially in view of the proposed moisture QA/QC specifications. After 
    careful consideration, the Agency agrees with the commenter and, in 
    response, the final rule adopts the missing data procedures in 
    Sec. 75.37 that are less conservative than the procedures in the 
    proposed rule and that more closely resemble the standard missing data 
    procedures for SO2, NOX, and flow, as recommended 
    by the commenters. The moisture missing data algorithm is modeled after 
    the standard SO2 missing data algorithm in Sec. 75.33(b). 
    This is consistent with the provisions in Secs. 75.35 and 75.36 of 
    today's rule, which adopt this algorithm for CO2 and heat 
    input missing data. However, in finalizing the moisture missing data 
    provisions, it became evident that a single mathematical algorithm is 
    not adequate to cover all of the part 75 emission rate and heat input 
    equations that require moisture corrections. In most of the equations, 
    the lower moisture values are more conservative, and an ``inverted'' 
    SO2 missing data algorithm is appropriate (for further 
    discussion of the ``inverted'' algorithm, see section C of this 
    preamble, below). However, there are certain emission rate equations 
    for which the opposite is true (i.e., the higher moisture values are 
    more conservative and the regular SO2 missing data algorithm 
    is appropriate). The specific equations for which the regular 
    SO2 algorithm applies are Equations F-3, F-4 and F-8 in 
    Method 19 in Appendix A of 40 CFR 60. Provided that all of the 
    moisture-corrected emission and heat input equations used by an 
    affected facility employ the same moisture missing data algorithm 
    (regular or inverted), it is a simple matter to substitute for missing 
    moisture data. However, when two or more equations require different 
    moisture algorithms, an alternative way of addressing missing moisture 
    data is needed. EPA believes that this situation will rarely be 
    encountered (at present, the Agency's records indicate that there are 
    only two such affected units in the Acid Rain Program). Therefore, 
    Sec. 75.37(d) of today's rule requires the owner or operator of such 
    units to petition the Administrator under Sec. 75.66(l), for an 
    alternative moisture missing data procedure.
        Finally, several commenters requested that EPA allow the use of a 
    default moisture value in lieu of the required moisture monitoring (see 
    Docket A-97-35, Items IV-D-11, IV-D-02 and IV-D-23). The Agency has 
    performed a moisture data analysis for various fuels (see Docket A-97-
    35, Item IV-A-2) and, based on the results, has provided fuel-specific 
    default values for moisture in today's rule (for coal and wood, only), 
    which may be reported for each unit operating hour, as an alternative 
    to operating and maintaining a continuous moisture monitoring system. 
    The default values are found in Secs. 75.11(b)(1) and 75.12(b) of 
    today's rule. Note that two sets of default values appear in the rule 
    to address the variability in format among the equations used for 
    determining pollutant emissions and heat input (as discussed in the 
    previous paragraph). The lower default values in Sec. 75.11(b)(1) apply 
    to Equations F-2, F-14b, F-16, F-17 and F-18 in Appendix F of part 75 
    and to Equations 19-5 and 19-9 in EPA Method 19 in Appendix A of 40 CFR 
    60. The higher default values in Sec. 75.12(b) apply when Equation 19-
    3, 19-4 or 19-8 in EPA Method 19 in Appendix A of 40 CFR 60 is used to 
    determine the NOX emission rate. The default values were 
    determined as follows. The moisture percentage values (which included 
    both ultimate moisture and free moisture) for each fuel type were taken 
    from the appropriate tables in Docket Item IV-A-2, cited above. The 
    moisture values were then ranked from the lowest percentage value to 
    the highest percentage value, and the 10th percentile value was 
    selected for the ``low'' default value and the 90th percentile value 
    was selected for the ``high'' default value. Each default moisture 
    percentage was rounded to the nearest whole number.
    
    C. Percent Monitor Availability
    
        Background: EPA proposed that if the annual monitor data 
    availability dropped below 80% for SO2, NOX, flow 
    rate or CO2, this would violate the primary measurement 
    requirement of Sec. 75.10(a). In response to comments, today's final 
    rule does not treat a percent monitor data availability of less than 
    80% as a violation. Instead, the final rule provides that if percent 
    monitor data availability is less than 80%, then the appropriate 
    maximum value (i.e., maximum potential concentration (MPC) for 
    SO2 and CO2, maximum potential emission rate 
    (MER) for NOX and maximum potential flow rate for flow) will 
    have to be used as substitute data for any hour for which valid data is 
    not available. For O2, the minimum potential concentration 
    will be used to provide substitute data. For moisture, consistent with 
    the discussion in section B of this preamble, the minimum potential 
    moisture percentage will be used in most instances to provide 
    substitute data; however, for certain emission rate equations, the 
    maximum potential moisture percentage must be used.
        Discussion: EPA received one comment that supported making a 
    percent monitor availability of less than 80% a violation (see Docket 
    A-97-35, Item IV-D-11) and another commenter favored the provision that 
    if percent monitor availability is below 80% due to ``unforseen events 
    beyond our control,'' this would be taken into consideration (see 
    Docket A-97-35, Item IV-G-9). EPA also received comments objecting to 
    making a percent monitor data availability of less than 80% a violation 
    and suggesting that EPA should modify the standard missing data 
    algorithms for SO2, NOX and flow rate to require 
    the use of a maximum substitute data value when monitor availability 
    drops below 80 percent (see Docket A-97-35, Items IV-D-17, IV-D-19, IV-
    D-23, IV-D-24). In response to the comments, the final rule does not 
    make percent monitor availability of less than 80% a violation and 
    instead provides that if percent monitor data availability at a source 
    is less than 80%, then the owner or operator of the source will have to 
    substitute the appropriate maximum value (i.e., MPC for SO2 
    and CO2, MER for NOX emission rate and maximum 
    potential flow rate for flow) as suggested by the commenters. Note that 
    for O2 and, in most cases, for moisture, minimum potential 
    values will be substituted rather than maximum values, since the lower 
    values of these parameters are more conservative. However, if Equation 
    19-3, 19-4 or 19-8 in EPA Method 19 in Appendix A of 40 CFR 60 is used 
    to determine NOX emission rate, higher moisture values are 
    more conservative and the maximum potential moisture percentage will be 
    used to provide substitute data.
        The missing data approach set forth in today's rule to address low 
    monitor data availability retains the basic design of the part 75 
    program and appropriately addresses the need for accountability from 
    sources that are inadequately maintaining their monitoring systems. The 
    Agency maintains that this provides a strong incentive to achieve at 
    least 80% monitor availability. Unlike the proposed approach of 
    considering sources to be in violation, the substitute data approach 
    adopted today creates this incentive while rendering unnecessary the 
    task of determining and evaluating the reason(s) for low monitor data 
    availability.
    
    D. Span and Range Requirements
    
        Background: The span of a CEMS provides an estimate of the highest 
    expected value for the parameter being
    
    [[Page 28569]]
    
    measured by the CEMS. For instance, the span value of an SO2 
    monitor is an approximation of the highest SO2 concentration 
    likely to be recorded by the CEMS during operation of the affected 
    unit. The range of a CEMS is the full-scale setting of the instrument. 
    Under part 75, the range of a monitor must be equal to or greater than 
    the span value. Section 2.1 of Appendix A further specifies that the 
    range must be chosen such that the majority of the readings during 
    normal operation fall between 25.0 and 75.0 percent of full-scale. The 
    span value is important because the reference gas concentrations and 
    signals used for daily calibration of the CEMS are expressed as 
    percentages of the span value. The allowable daily calibration error 
    for a CEMS is also expressed as a percentage of span.
        Sections 2.1.1 through 2.1.4 of Appendix A of the January 11, 1993 
    rule specified procedures for determining the span values for 
    SO2, NOX, diluent gas (O2 or 
    CO2), and volumetric flow rate. For SO2, the 
    ``maximum potential concentration'' (MPC) was first calculated based on 
    fuel sampling. The MPC values for NOX were specified in the 
    rule and were based on the type of fuel being combusted. The 
    SO2 and NOX span values were then determined by 
    multiplying the MPC by 1.25. For CO2 and O2, a 
    span value of 20.0 percent CO2 or O2 was required 
    for all diluent monitors. For flow rate, the ``maximum potential 
    velocity'' (MPV) was first determined. Then, the span value was 
    obtained by multiplying the MPV by 1.25 and rounding off the result.
        In the January 11, 1993 rule, the SO2 or NOX 
    monitor range derived from the MPC was referred to as the ``high-
    scale.'' The rule further specified that whenever the majority of the 
    readings during normal operation were expected to be less than 25.0 
    percent of the high full-scale range value (e.g., if a scrubber is used 
    to reduce SO2 emissions), a second, ``low-scale'' span and 
    range would be required. The low scale span value of the CEMS would be 
    defined as 1.25 times the ``maximum expected concentration'' (MEC).
        In the first two years of Acid Rain Program implementation, it 
    became clear that the span and range provisions of part 75 lacked 
    sufficient flexibility and clarity. The May 17, 1995 rule revisions 
    attempted to address these deficiencies. Two alternative methods of 
    determining the MPC or MEC were added, i.e., from historical CEMS data 
    or from emission test results. For NOX, a comprehensive list 
    of MPC values was promulgated (Tables 2-1 and 2-2 in Appendix A), 
    taking into consideration the unit type in addition to the fuel type. 
    Flexibility was also added to the dual-range requirements for 
    NOX monitors. For flow rate, a more detailed procedure for 
    determining the span value was added.
        The May 17, 1995 rule also revised the procedures for adjusting the 
    span and range of SO2, NOX, and flow monitors. 
    The original rule had specified that span and range adjustments were 
    required whenever the MPC, the MEC, or the MPV changed significantly 
    (although a ``significant'' change was undefined). When a significant 
    change in the MPC, MEC, or MPV occurred, a new range setting was to be 
    established and a new span value defined, equal to 80.0 percent of the 
    adjusted range value. The May 17, 1995 rule changed this procedure, 
    requiring the new span value to be determined first, followed by the 
    new range. The May 17, 1995 rule also added procedures for addressing 
    full-scale exceedances, specifying that the full-scale value is to be 
    reported for an exceedance of one hour and that a range adjustment is 
    required for an exceedance greater than one hour.
        After promulgation of the May 17, 1995 rule, EPA continued to 
    receive questions and comments about the span and range sections of 
    part 75. Apparently, the span and range sections of the rule were still 
    not sufficiently clear, flexible, or detailed and were in need of 
    further revision. Therefore, on May 21, 1998, further revisions to the 
    span and range provisions were proposed.
        The proposed rule provided an alternative procedure for determining 
    the MPC of SO2 or NOX, requiring the MPC to be 
    based upon a minimum of 720 quality assured monitor operating hours, 
    rather than 30 unit operating days. A specific requirement to calculate 
    the maximum potential NOX emission rate (MER) was also 
    proposed. The owner or operator could use the diluent cap value of 5.0 
    percent CO2 or 14.0 percent O2 for boilers (or 
    1.0 percent CO2 or 19.0 percent O2 for turbines) 
    in the NOX MER calculation.
        The proposed rule provided a definition of the MPC for 
    CO2. The MPC would be 14.0 percent CO2 for 
    boilers and 6.0 percent CO2 for combustion turbines. 
    Alternatively, the MPC for CO2 could be based on a minimum 
    of 720 hours of representative quality assured historical CEM data. A 
    standardized procedure for calculating the maximum potential flow rate 
    (MPF) was proposed and a clear distinction between the ``calibration 
    span value'' of a flow monitor (expressed in the units of measure used 
    for the daily calibrations) and the ``flow rate span value'' (expressed 
    in the units used for electronic data reporting) was provided.
        The proposed rule set forth changes to the procedures for 
    determining the maximum expected concentration (MEC) of SO2 
    and NOX, and to the criteria for determining whether dual 
    span and range requirements apply. A separate MEC determination would 
    be required for each type of fuel combusted, except for fuels that are 
    only used for unit startup or for flame stabilization. To determine 
    whether a second, low-scale span is required in addition to the high-
    scale span based on the MPC, each of the maximum expected concentration 
    (MEC) values would be compared against the MPC. If any of the MEC 
    values was <20.0 percent="" of="" the="" mpc,="" a="" low-scale="" span="" would="" be="" required.="" the="" proposed="" rule="" provided="" additional="" flexibility="" in="" the="" method="" of="" calculating="" span="" values.="" the="">2, NOX or flow 
    rate span value could be set anywhere between 1.00 and 1.25 times the 
    applicable maximum value (i.e., the MPC, MEC or MPF). For 
    CO2 and O2 monitors, the owner or operator would 
    be given maximum flexibility in selecting an appropriate span value. 
    For CO2 monitors installed on boilers, any representative 
    span value between 14.0 percent and 20.0 percent CO2 would 
    be acceptable. For combustion turbines, any representative 
    CO2 span value between 6.0 and 14.0 percent CO2 
    could be used. For O2 monitors, a span value between 15.0 
    percent and 25.0 percent O2 could be selected and an 
    alternative O2 span value of less than 15.0 percent could be 
    used, if supported by an acceptable technical justification.
        The proposed rule expanded and clarified the guideline in section 
    2.1 of Appendix A for selecting an appropriate full-scale range. The 
    full-scale range would be selected so that the readings during typical 
    unit operation fall between 20.0 and 80.0 percent of full-scale, which 
    represents a slight increase in flexibility from the 25 to 75 percent 
    of full-scale guideline in the current rule. The proposal also cited 
    three specific cases in which the guideline in section 2.1 is 
    inapplicable: (1) during the combustion of very low sulfur fuels 
    (0.05% sulfur by weight); (2) for SO2 or 
    NOX readings on the high range for an affected unit with 
    SO2 or NOX emission controls and two span values; 
    and (3) when SO2 or NOX readings are less than 
    20.0 percent of the low measurement range for a dual-span unit with 
    SO2 or NOX emission controls, provided that the 
    low readings occur during periods of high control device efficiency.
    
    [[Page 28570]]
    
        The proposed rule specified that the following monitoring 
    configurations could be used to meet dual span and range requirements: 
    (1) a single analyzer with two ranges, or (2) two separate analyzers 
    connected to a common probe and sample interface. The high and low 
    ranges could be designated in the monitoring plan as two separate, 
    primary monitoring systems, or as separate components of a single, 
    primary monitoring system, or the ``normal'' range could be designated 
    as a primary monitoring system, and the other range as a non-redundant 
    backup monitoring system.
        The proposed rule would allow the owner or operator to use a 
    ``default high-range value'' in lieu of operating, maintaining, and 
    quality assuring a high-scale monitor range. The default high-range 
    value would be 200.0 percent of the MPC. This value would be reported 
    whenever the SO2 or NOX concentration exceeded 
    the full-scale of the low-range analyzer.
        Finally, the proposed rule provided detailed guidelines and 
    procedures for adjusting the span and range of the CEMS. First, if the 
    maximum value upon which the high span value is based (i.e., the MPC or 
    MPF) was exceeded during a calendar quarter, but the span was not 
    exceeded, the span or range would not have to be adjusted. However, if 
    any quality assured hourly concentration or flow rate exceeded the MPC 
    or MPF by 5.0 percent during the quarter, a new MPC or MPF 
    would have to be defined. Second, if any quality assured reading on the 
    high measurement range exceeded the span value by 10.0 
    percent during the quarter but did not exceed the range, a new MPC or 
    MPF (as applicable) would have to be defined, and the span value (and 
    range, if necessary) would also have to be changed. Third, for full-
    scale exceedances of a high monitor range, corrective action would be 
    required to adjust the span and range. A value of 200.0 percent of the 
    current full-scale range would be reported to EPA for each hour of each 
    full-scale exceedance.
        Today's rule finalizes the proposed revisions to the span and range 
    sections of Appendix A. Most of the provisions have been finalized as 
    proposed, with only minor changes and clarifications. However, there 
    are three notable exceptions: (1) the proposed requirement for 
    mandatory quarterly evaluations of the MPC, MEC and MPF values and the 
    associated prescriptive criteria for adjusting the spans and ranges 
    have been withdrawn; (2) the proposed change in methodology for 
    determining dual span and range requirements (i.e., comparing the MEC 
    value(s) to the MPC) has been withdrawn; and (3) an additional 
    monitoring configuration option has been provided for units with dual 
    span requirements. For units with a dual-range SO2 or 
    NOX analyzer, the final rule allows the low and high ranges 
    to be represented as a single component of a primary SO2 or 
    NOX monitoring system.
        Discussion: EPA received supportive comments from a number of 
    utilities, regarding several of the proposed span and range revisions 
    (see Docket A-97-35, Items IV-D-20, IV-D-23, IV-D-24, IV-D-25, and IV-
    G-01). The commenters generally favored the increased flexibility in 
    determining SO2, NOX, CO2 and 
    O2 span values and supported the concept of a ``default high 
    range value.'' One commenter, however, opposed the use of purified 
    instrument air for O2 monitor calibrations (see Docket A-97-
    35, Item IV-D-11) and, as discussed in greater detail below, two 
    commenters who supported the ``default high range'' concept took issue 
    with the proposed default value (see Docket A-97-35, Items IV-D-05 and 
    IV-D-24). One commenter asked EPA to give guidance as to what type of 
    technical justification would be required to use an alternative 
    O2 span value of less than 15 percent (see Docket A-97-35, 
    Item IV-D-23). The final rule provides an example, in section 2.3.1 of 
    Appendix A.
        Several commenters stated that the proposed procedures for making 
    span and range adjustments were particularly complicated and burdensome 
    (see Docket A-97-35, Items IV-D-19, IV-D-20, IV-D-23, IV-D-24 and IV-G-
    09). Two commenters stated that the requirement to perform quarterly 
    evaluations of the MPC, MEC and MPF values is unnecessary and excessive 
    (see Docket A-97-35, Items IV-D-11 and IV-G-02). One commenter 
    recommended using the guideline in section 2.1 of Appendix A to 
    determine whether span and range adjustments are needed (see Docket A-
    97-35, Item IV-D-11). Another commenter recommended that EPA allow data 
    points that are clear ``outliers'' to be excluded from quarterly span 
    and range evaluations (see Docket A-97-35, Item IV-D-04). After 
    carefully considering these comments, EPA has decided to withdraw the 
    prescriptive proposed procedures for making span and range adjustments. 
    Instead, the final rule requires that span and range adjustments be 
    made only when the MPC, MEC or MPF changes ``significantly.'' This is 
    similar to the original guideline in the January 11, 1993 rule, except 
    that a ``significant'' change was undefined in that rule. In today's 
    rule, a significant change in the MPC, MEC or MPF means that the 
    guideline of section 2.1 of Appendix A ( for the majority of the 
    readings to be between 20 and 80% of the range, with certain allowable 
    exceptions) cannot be met, as determined either by the owner or 
    operator or through an audit by a regulatory agency. The Agency has 
    also reduced the frequency of mandatory evaluations of the MPC, MEC and 
    MPF values. In the final rule, only an annual evaluation of these 
    values is required. The results of the annual evaluations must be kept 
    on-site, in a format suitable for inspection.
        Two commenters stated that the proposed requirement to treat the 
    two ranges of a dual-range monitor as separate monitoring systems or as 
    two separate components of the same system would cause additional 
    programming costs and would be technically difficult to implement (see 
    Docket A-97-35, Items IV-D-4 and IV-G-02). The commenters requested 
    that EPA continue to allow the low and high ranges to be represented in 
    the monitoring plan by a single component. After consideration, the 
    Agency has decided that the commenters' request is reasonable and has 
    included this option in the final rule. Note, however, that the use of 
    this option is restricted to dual-range analyzers that use electronic 
    gain to produce the two ranges. Today's rule requires the use of a 
    special dual-range component type code when this option is selected. 
    EPA will provide the necessary type code and reporting guidance in the 
    electronic data reporting (EDR) instructions for EDR version 2.1.
        Two commenters stated that 200% of MPC is too high for the proposed 
    default high range value in sections 2.1.1.3(f) and 2.1.1.4(e) of 
    Appendix A, for the case where the owner or operator uses a default 
    value instead of operating a high-range monitor (see Docket A-97-35, 
    Items IV-D-05 and IV-D-24). A third commenter objected to the proposed 
    value of 200% of the range, which is to be reported during full-scale 
    exceedances (see Docket A-97-35, Item IV-G-05). Without a functional 
    high range monitor, it is not possible to determine the exact pollutant 
    concentration when a control device malfunctions or when a full-scale 
    exceedance occurs. In the preamble to the proposed rule, EPA cited one 
    instance in which the high SO2 range was exceeded and the 
    estimated SO2 concentration (based on fuel sampling) was 
    estimated to be about 150% of the range (see 63 FR 28058). For this 
    reason, the proposed values of 200% of the range (for full-scale 
    exceedances) and
    
    [[Page 28571]]
    
    200% of the MPC (for the default high range value) have been retained 
    in the final rule. EPA maintains that these values must be 
    conservative, based on a ``worst case'' analysis to ensure that 
    emissions will not be under-reported. The Agency believes that if spans 
    and ranges are properly set, full-scale exceedances will be relatively 
    rare. Also, EPA anticipates that the majority of the units for which 
    owners or operators will elect to use the default high range option 
    have reliable emission controls and the default value will rarely, if 
    ever, have to be used.
        One commenter objected to the proposed changes to the method of 
    calculating MPC and MEC values, expressing concern that the revisions 
    might require his existing span and range values to be re-calculated 
    (see Docket A-97-35, Item IV-G-02). Another commenter (mistakenly) 
    interpreted the proposed definition of the MPC for CO2 in 
    section 2.3.1 of Appendix A to mean that his existing CO2 
    span values would have to be re-determined (see Docket A-97-35, Item 
    IV-D-04). A third commenter asked EPA to ``grandfather'' existing span 
    and range values (see Docket A-97-35, Item IV-D-20). It is not, and 
    never has been EPA's intent to require utilities to change their 
    existing spans and ranges, provided that they meet the guideline of 
    section 2.1 of Appendix A ( for the majority of the readings to be 
    between 20 and 80% of full-scale, with certain allowable exceptions). 
    The Agency does not believe that ``grandfathering'' of any existing 
    part 75 span and range values is necessary. The final rule simply adds 
    flexibility to the procedures for determining spans and ranges. 
    Affected units with previously-determined span and range values that 
    meet the guideline of section 2.1 of Appendix A do not have to change 
    their current span or range values. To further alleviate undue concern 
    about this, the Agency has withdrawn the proposed changes to the method 
    of determining whether a dual span is required. Rather than comparing 
    the MEC value(s) to the MPC value(s) (as proposed), today's rule 
    specifies that the MEC value should be compared to the high range 
    value. This is essentially the same as the requirement in the current 
    rule.
        Finally, one commenter objected to the proposed requirement to 
    perform the RATA at the low range of the monitor on units that have 
    scrubbers. The commenter urged EPA to revert to the original rule and 
    allow the RATA to be performed at whatever range the CEMS is operating 
    on at the time of the RATA (see Docket A-97-35, Item IV-G-3). EPA does 
    not agree with the commenter. For units with SO2 scrubbers, 
    the vast majority of the data is collected on the low range. Therefore, 
    the SO2 RATA should be performed on that range. If the 
    scrubber malfunctions at the time of a scheduled SO2 RATA, 
    the RATA should either be rescheduled later in the quarter or should be 
    done during the 720 unit operating hour grace period allowed under 
    revised section 2.3.3 of Appendix B.
    
    E. Flow-to-Load Ratio Test Requirements
    
        Background: The quality assurance requirements for flow rate 
    monitoring systems in Appendices A and B of part 75 include daily 
    calibration error tests, daily interference checks, quarterly leak 
    checks (for differential pressure type monitors only), and semiannual 
    or annual RATAs. Of these required QA tests, only the RATA provides a 
    true evaluation of a flow monitor's measurement accuracy by direct 
    comparison against an independent reference method. The daily 
    calibration error test checks the system's internal electronic 
    components by means of reference signals. The calibration error test is 
    useful in that it can diagnose certain types of monitor problems, but 
    it does not evaluate the system's ability to measure an actual stack 
    gas flow rate. Because of this limitation, EPA believes that a more 
    substantive, periodic QA test is needed to ensure that the accuracy of 
    the reported flow rate data is maintained in the interval between 
    successive RATAs. The Agency is particularly concerned about the 
    potential for poor data quality from flow monitors that are not 
    properly maintained.
        In view of this, EPA proposed to add a new flow monitor quality 
    assurance test, the ``flow-to-load ratio test,'' to part 75 in section 
    7.7 of Appendix A and section 2.2.5 of Appendix B. A similar test was 
    first suggested to the Agency by a flow monitor manufacturer (see 
    Docket A-97-35, Item II-D-69). The flow-to-load ratio test, which would 
    be performed quarterly, would be required beginning in the second 
    quarter of the year 2000. The basic premise of the flow-to-load ratio 
    test is that a meaningful correlation exists between the stack gas 
    volumetric flow rate and unit load. In general, for a single unit 
    discharging to a single stack, as the load increases, the flow rate 
    increases proportionally, and the flow rate at a given load should 
    remain relatively constant if the same type of fuel is burned. Common 
    stacks are somewhat less predictable, because the same combined unit 
    load can be produced in a number of ways by using different 
    combinations of boilers. Despite this, if the diluent gas concentration 
    is properly taken into account, the flow-to-load characteristics of 
    common stacks often become more normalized. The flow-to-load ratio, or 
    a normalized ratio, such as the gross heat rate (GHR) can thus serve as 
    a quantitative indicator of flow monitor accuracy from quarter to 
    quarter until the next RATA is performed.
        The proposed rule provided a calculation methodology for the 
    quarterly flow-to-load or GHR evaluation. A ``reference'' flow-to-load 
    ratio or GHR would be established at the time of each normal-load flow 
    RATA, using data from the flow rate reference method. Then, in 
    subsequent quarters, hourly data from the flow monitor would be 
    compared to the reference ratio or GHR, and an absolute average 
    percentage difference between the hourly data and the reference ratio 
    would be calculated. If the percentage difference exceeded certain 
    limits, the utility would be required to investigate to try to 
    establish the cause of the test failure. If the investigation indicated 
    a problem with the flow monitor, the utility could perform corrective 
    actions, followed by an abbreviated flow-to-load diagnostic test, to 
    demonstrate that the corrective actions were effective. However, if the 
    investigation could not establish the cause of the flow-to-load test 
    failure, a normal load flow RATA would be required.
        Today's final rule adopts the flow-to-load ratio test provisions. 
    The final rule is essentially the same as the proposal except for a few 
    minor changes in response to comments received.
        Discussion: EPA received comments on the proposed quarterly flow-
    to-load ratio test from seven utilities, two state agencies, one 
    utility regulatory response group and one flow monitor vendor. One 
    state agency was supportive of the test, because it can serve as a 
    quantitative indicator of flow monitor performance from quarter to 
    quarter (see Docket A-97-35, Item IV-D-9). The flow monitor vendor also 
    favored the test, because it will help to ensure that all flow 
    monitoring technologies perform in a reliable manner (see Docket A-97-
    35, Item IV-D-12). Several utility commenters objected to the proposed 
    test, believing it would be burdensome, time-consuming, expensive to 
    implement (requiring significant DAHS software modifications), and 
    difficult to pass (see Docket A-97-35, Items IV-D-16, IV-G-5, IV-G-9, 
    IV-G-2). One commenter suggested that the test be used as a warning to 
    take corrective action rather than using it to directly validate or 
    invalidate flow rate data (see
    
    [[Page 28572]]
    
    Docket A-97-35, Item IV-D-11). Another commenter recommended that for 
    common stacks, additional hours be exempted from the data analysis, 
    specifically hours in which the combination of boilers and loads does 
    not match the combination used during the last normal load flow RATA 
    (see Docket A-97-35, Item IV-D-17). Two commenters recommended 
    increasing the threshold to qualify for a less stringent flow-to-load 
    specification from 50 MW to 60 or 70 MW (see Docket A-97-35, Items IV-
    D-11, IV-D-2). Two commenters recommended reducing the frequency of 
    flow RATAs based on good performance in the flow-to-load test; 
    specifically, one commenter advocated performing flow RATAs every other 
    year and the other commenter recommended performing a flow RATA once 
    every five years (see Docket A-97-35, Items IV-D-22, IV-G-2). One 
    commenter stated that the proposed flow-to-load methodology does not 
    adequately address multiple stack configurations where one of the 
    stacks is a bypass stack, and also recommended that EPA make it clear 
    that the flow-to-load data analysis only applies to reported data and 
    not to redundant backup monitor data which are not reported (see Docket 
    A-97-35, Item IV-G-2). Finally, the utility regulatory response group 
    found the proposal to be an improvement over the pre-proposal draft 
    that was circulated in May, 1997, but took issue with the following: 
    (1) The method of calculating the test results, using the absolute 
    value of, rather than the arithmetic, percentage of differences between 
    the hourly flow-to-load ratios and the reference ratio; (2) failure of 
    the proposal to address units with bypass stacks or other complex stack 
    configurations; and (3) allowing only one week after the end of the 
    quarter to investigate and troubleshoot the flow monitor when a flow-
    to-load test failure occurs, before a RATA requirement is triggered 
    (see Docket A-97-35, Item IV-D-20).
        Today's rule includes flow-to-load test provisions in section 7.7 
    of Appendix A and section 2.2.5 of Appendix B. The final rule is 
    essentially the same as the proposal, except for the following changes, 
    which have been incorporated in response to the comments received. 
    First, a new section 7.8 has been added to Appendix A, which allows 
    owners or operators of units with complex stack configurations to 
    petition for an exemption from quarterly flow-to-load testing. Any such 
    petition would have to provide information and data which demonstrate 
    to the satisfaction of the Administrator that the flow rate through the 
    complex stack configuration cannot be reasonably correlated to unit 
    load. Second, for a unit with a multiple stack discharge configuration 
    consisting of a main stack and a bypass stack (e.g., for a unit with a 
    wet SO2 scrubber), the flow-to-load test is to be performed 
    on an individual stack basis and hours in which emissions are 
    discharged simultaneously through both stacks may be excluded from the 
    quarterly flow-to-load analysis. Third, the threshold to qualify for a 
    less stringent flow-to-load specification has been raised from 50 MW to 
    60 MW. Fourth, when a flow-to-load or GHR test is failed, two weeks, 
    rather than one, are allowed after the end of the quarter to 
    investigate the cause of the test failure before triggering a RATA 
    requirement.
        EPA does not agree with the commenters who characterized the 
    proposed flow-to-load test as time-consuming, burdensome, and difficult 
    to implement (requiring extensive software revision). The Agency 
    believes that implementation of the flow-to-load test will not require 
    any special modification of existing part 75 DAHS systems or software. 
    All of the information needed to perform the quarterly flow-to-load or 
    GHR analysis is currently reported in the electronic quarterly report 
    required under Sec. 75.64. Rather, a PC-based computer program will be 
    needed, which can extract the essential information from the quarterly 
    report and analyze it. Once such a computer program is written, 
    analysis of the quarterly flow rate and load data should become a 
    routine operation which will be neither burdensome nor time-consuming.
        The Agency also disagrees with those commenters who contended that 
    the flow-to-load test will be difficult to pass. On the contrary, the 
    flow-to-load test should be relatively easy to pass, provided that the 
    flow monitor is properly operated and well-maintained. Prior to issuing 
    the proposed rule, EPA analyzed quarterly flow rate and load data from 
    the third quarter of 1996 for 21 units and stacks, including 9 single 
    units, 11 common stacks, and 1 multiple-stack unit. The units chosen 
    for this analysis were selected as a representative sample of units 
    that would be affected by this QA test requirement and included various 
    operational circumstances (e.g., base loaded and peaking units, single 
    fuel units, and units that burn multiple fuels). The flow-to-load and 
    GHR test methodologies were applied to each unit or stack, excluding 
    none of the normal load data from the analysis. The results of the 
    flow-to-load and GHR data analyses were nearly the same. Only one 
    failure of the quarterly flow-to-load test was observed in each 
    analysis (i.e., the failure rate was <5.0 percent).="" the="" value="" of="">f (the average percentage difference between the hourly 
    ratios and the reference ratio) was 6.1 percent for the analysis of the 
    flow-to-load ratios and 6.4 percent for the simulated GHR analysis 
    (with diluent gas corrections). However, as noted by one of the 
    commenters, the Agency acknowledges that these data analyses were 
    performed using the calculation method described in the May, 1997 pre-
    proposal draft of the rule revisions, i.e., using the arithmetic 
    percentage difference between each hourly flow-to-load ratio and the 
    reference ratio, rather than the absolute percentage difference 
    prescribed in the proposed rule. To address the commenter's concern, 
    EPA has re-analyzed the data using the absolute percentage difference. 
    The results of the data analysis using the absolute percentage 
    difference were nearly the same as the results using the arithmetic 
    percentage difference. The failure rate was the same (<5%) and="" the="" value="" of="">f was 7.3 percent for the analysis of the flow-to-
    load ratios and 8.0 percent for the simulated GHR analysis (with 
    diluent gas corrections), which is still well below the 15.0 percent 
    tolerance limit (see Docket A-97-35, Item IV-A-3). Thus, it appears to 
    make very little difference, in terms of ease of passing, whether the 
    absolute percentage difference or the arithmetic percentage difference 
    is used in the flow-to-load and GHR calculations. Therefore, the flow-
    to-load and GHR calculation methodology has been finalized as proposed 
    using the absolute percentage difference.
        Two commenters suggested that the flow RATA frequency should be 
    reduced based on good performance on the quarterly flow-to-load test 
    (see Docket A-97-35, Items IV-D-22 and IV-G-02). The Agency agrees with 
    the commenters that with the addition of the new QA tests it is 
    reasonable to lessen the frequency of the annual three load flow RATA. 
    Therefore, EPA is also adopting the following three provisions reducing 
    the flow RATA requirements: (1) Routine flow RATAs are changed from 
    three-load tests to two-load tests; (2) a single-load annual flow RATA 
    is allowed if the unit operates at one load level for 85 
    percent of the time since the last annual flow RATA; and (3) a three-
    load flow RATA is required only once every five years and whenever the 
    instrument is re-linearized. EPA has adopted these reduced flow RATA
    
    [[Page 28573]]
    
    requirements principally because of the reasonable assurance of data 
    quality that will be provided in between RATAs by the new flow-to-load 
    test. Note, however, that the flow-to-load ratio test, which analyzes a 
    limited amount of flow rate data at a single load level, does not serve 
    as a replacement for annual RATA testing. Rather, the flow-to-load 
    ratio test helps to ensure that the flow monitor remains accurate in 
    between successive semiannual or annual RATAs.
    
    F. RATA and Bias Test Requirements
    
    1. RATA Load Levels
        Background: The previous provisions of part 75 were neither 
    sufficiently standardized nor clear in defining the appropriate load 
    levels for RATAs. For example, the previous rule required gas monitor 
    RATAs to be conducted at normal load and required gas and flow rate 
    monitor bias adjustment factors to be determined at normal load, but no 
    definition of normal load was provided. In addition, section 6.5.2 of 
    Appendix A specified that the ``low'' load audit point for a 3-level 
    flow RATA can be located anywhere from the minimum safe, stable load to 
    50.0 percent of the maximum load, and no minimum separation is required 
    between the audit points at adjacent load levels. If adjacent audit 
    points are too close together, a multiple load flow evaluation loses 
    its significance.
        EPA proposed revisions to Appendix A of part 75, which would more 
    clearly define the load levels at which RATAs are done in order to 
    achieve greater consistency in the way that RATAs are performed. The 
    proposed methodology, which would become effective as of April 1, 2000, 
    would require the utility to define the ``range of operation'' for each 
    affected unit or common stack (except for peaking units). The range of 
    operation would extend from the minimum safe, stable load to the 
    maximum achievable load. The ``low'' load level would then be defined 
    as 0-30% of the range of operation, the ``mid'' load level would be 30-
    60% of the range and the ``high'' load level would be 60-100% of the 
    range. The proposed methodology would require a load frequency 
    distribution (histogram) to be developed, prior to each annual RATA, to 
    determine the percentage of time the unit or stack has operated at each 
    load level in the previous four ``QA operating quarters.'' A summary of 
    the data used for the load frequency determination would be maintained 
    on-site in a format suitable for inspection, and the results of the 
    determination would be included in the electronic quarterly report 
    under Sec. 75.64. The most frequently used load level would then be 
    designated as the ``normal'' load. The second most frequently used load 
    could, at the discretion of the owner or operator, be designated as a 
    second normal load level. Gas monitor RATAs would be required at the 
    normal load level. Routine quality assurance RATAs for flow monitors 
    would be done at the two most frequently used load levels. Today's rule 
    adopts the proposed changes with certain modifications in response to 
    comments.
        Discussion: The Agency received comments on the proposed method of 
    determining RATA load levels from three individual utilities and from 
    two utility regulatory response groups. Only two comments were received 
    on the proposed definitions of ``range of operation,'' ``low,'' 
    ``mid,'' and ``high'' load levels. One commenter supported the effort 
    to establish load level definitions, but found the proposal to be too 
    inflexible and complicated and suggested that EPA should permit 
    overlapping load ranges (see Docket A-97-35, Item IV-D-20). The other 
    commenter requested that EPA modify the proposed definition of the 
    ``minimum safe, stable load'' for common stacks. The commenter 
    expressed concern that for base-loaded units which share a common 
    stack, the proposed definition might require a unit to be shut down to 
    attain the low load level in a 3-load flow RATA (see Docket A-97-35, 
    Item IV-D-24). Four commenters opposed the proposed requirement to 
    develop a historical load frequency distribution to establish the 
    normal load level(s) for the unit or stack, stating that the load 
    frequency is too variable (being dependent on unit availability, 
    operation, and dispatch) and that the new requirement would add another 
    level of unnecessary data collection and manipulation (see Docket A-97-
    35, Items IV-D-20, IV-D-24, IV-D-19, and IV-D-23). Another commenter 
    suggested that RATA load ranges should be based on the typical load 
    requirements for the quarter in which the RATA is done, particularly if 
    the historical data are no longer representative. The commenters 
    further recommended that EPA should: (1) eliminate the requirement to 
    use four operating quarters of data; (2) allow extenuating data to be 
    excluded; (3) allow recent changes to be considered when selecting load 
    ranges; and (4) allow utilities to consider forecasted usage of a unit 
    when selecting load ranges (see Docket A-97-35, Item IV-D-20). Finally, 
    one commenter objected to the proposed requirement to report the 
    results of the load frequency data analysis electronically, stating 
    that requiring electronic reporting of the results provides no 
    advantage over keeping the data analysis on-site and that such 
    reporting would require DAHS software changes (see Docket A-97-35, Item 
    IV-G-2).
        Today's rule finalizes the proposed definitions of the ``range of 
    operation,'' and the ``low,'' ``mid,'' and ``high'' load levels in 
    section 6.5.2.1 of Appendix A and the associated requirement to report 
    the upper and lower boundaries of the range of operation, with one 
    minor revision. A provision has been added for frequently-operated 
    (e.g., base-loaded) units that share a common stack, which allows the 
    ``minimum safe, stable load'' to be determined in a different manner. 
    For such units, the owner or operator may use the sum of the minimum 
    safe, stable loads for the individual units as the minimum safe stable 
    load for the common stack (rather than using the lowest of the minimum 
    safe, stable load values for the individual units). The Agency believes 
    that this adequately addresses the commenter's concern that one or more 
    units might have to be shut down in order to attain the ``low'' load 
    level during a 3-load flow RATA.
        Section 6.5.2.1 of Appendix A of today's rule also finalizes the 
    proposed methodology for determining normal load and for selecting the 
    appropriate load levels for the annual 2-load flow RATAs, with 
    revisions based on comments received. In the final rule, a 
    determination of the normal load level(s) and the appropriate flow RATA 
    load levels is still required, but it has been made a one-time 
    requirement, rather than an annual requirement. The requirement becomes 
    effective on April 1, 2000, but owners or operators may comply with it 
    prior to that date. The owner or operator must review historical load 
    data for the unit or stack, for a minimum of four representative 
    operating quarters. From these data, the percentage of unit operating 
    time at each load level (``low,'' ``mid'' or ``high'') will be 
    determined. The historical load data may be analyzed by any suitable 
    means; construction of a histogram, per se, is not required. The load 
    level used the most frequently will be designated normal, and the 
    second most frequently used load level may, at the discretion of the 
    owner or operator, be designated as a second normal load. The two most 
    frequently used load levels are the load levels at which the annual 2-
    load flow RATA will be performed. The results of the historical load 
    data analysis will be reported in the electronic quarterly report as 
    part of the electronic monitoring plan. EPA
    
    [[Page 28574]]
    
    believes that reporting one additional monitoring plan record will not 
    prove to be burdensome. A summary of the data used for the load 
    determinations and the calculated results must be kept on-site, in a 
    format suitable for inspection.
        EPA continues to believe that a review of historical operating load 
    data is a reasonable way to standardize the determination of the normal 
    load level(s) and the appropriate flow RATA load levels for a unit or 
    stack. In order to maintain national consistency and to ensure that a 
    ``level playing field'' is maintained among affected utilities, the 
    Agency believes that a standardized procedure is necessary. Although 
    several commenters took issue with the specifics of the proposed 
    methodology, none of them provided a sufficiently detailed alternative 
    procedure for serious consideration by the Agency. Requests to ``allow 
    exclusion of extenuating data'' and ``permit consideration of recent 
    changes when selecting load ranges'' do not provide a sufficient basis 
    for the development of appropriate regulatory language. Further, since 
    the standardized procedure is based on data for four operating 
    quarters, any unrepresentative data is likely to have minimal effect. 
    Therefore, EPA did not incorporate most of the commenters' suggestions. 
    However, to address the concern of several commenters about possible 
    variability in unit load and manner of unit operation, a provision has 
    been added to section 6.5.2.1 of Appendix A which requires the 
    historical load analysis to be repeated if the way in which a unit 
    operates changes significantly and the previously-determined normal 
    load level(s) and the two most frequently used load levels change. The 
    new provision requires a minimum of two representative operating 
    quarters of historical load data to document that a change in the 
    manner of unit operation has actually occurred.
    2. Single-Point Reference Method Sampling
        Background: Section 6.5.6 of Appendix A to part 75 gives the 
    traverse point location requirements for reference method sampling 
    during relative accuracy test audits (RATAs) of gas monitoring systems. 
    The reference method sampling points are to be located along a line, in 
    accordance with section 3.2 of Performance Specification No. 2 in 
    Appendix B to 40 CFR part 60. Performance Specification No. 2 requires 
    three reference method sampling points for each RATA test run. EPA 
    proposed changes to section 6.5.6 of Appendix A, pertaining to RATA 
    traverse point selection. Proposed section 6.5.6 would allow single-
    point reference method sampling to be used in two specific instances: 
    (1) for all moisture determinations, a single reference method point, 
    located at least 1.0 meter from the stack wall, could be used; and (2) 
    for flue gas sampling, a single reference method measurement point, 
    located no less than 1.0 meter from the stack wall, could be used at 
    any test location if a stratification test is performed prior to each 
    RATA at the location and certain acceptance criteria are met.
        In order to implement the second option (single-point gas 
    sampling), a 12-point stratification test, as described in proposed 
    section 6.5.6.1, would have to be passed one time at the sampling 
    location, meeting the acceptance criteria for single-point sampling 
    given in proposed section 6.5.6.3 of Appendix A. The location would 
    qualify for single-point gas sampling if the concentration at each 
    individual traverse point differed by no more than  5.0 
    percent from the arithmetic average concentration for all traverse 
    points. The results would also be acceptable if the concentration at 
    each individual traverse point differed by no more than  
    3.0 ppm or 0.3 percent CO2 (or O2) from the 
    arithmetic average concentration for all traverse points. Once a 12-
    point stratification test was passed at the candidate sampling 
    location, either the 12-point test or an abbreviated 3-point or 6-point 
    stratification test, as described in proposed section 6.5.6.2, would 
    have to be passed prior to subsequent RATAs at the location.
        Today's rule finalizes the provisions for single-point moisture and 
    gas reference method sampling, with certain modifications in response 
    to comments received. The criteria in today's rule to qualify for 
    single-point sampling are more stringent than the criteria in the 
    proposed rule.
        Discussion: EPA received comments from two utilities and three 
    State air regulatory agencies on the proposal to allow single-point 
    reference method sampling. One of the utility commenters favored 
    allowing single-point sampling, viewing it as an excellent step to 
    improve the overall efficiency of RATA testing (see Docket A-97-35, 
    Item IV-D-21). The other utility commenter also favored the proposal, 
    believing that it would reduce the manpower requirements for gas RATA 
    testing (see Docket A-97-35, Item IV-D-22). One State agency commenter 
    opposed the unrestricted use of single-point moisture sampling, stating 
    that the moisture results could be biased if gas stratification is 
    present in the stack. Another State agency commenter viewed the 
    proposal to allow single-point reference method sampling as 
    unfavorable, expressing concern that single-point sampling may not 
    yield valid results, particularly if the sampling point is too near the 
    stack wall, where air in-leakage can occur (see Docket A-97-35, Item 
    IV-D-9). The third State agency commenter appeared to take issue with 
    the use of a 3-point abbreviated stratification test, stating that for 
    the large-diameter stacks in the Acid Rain Program, a three point test 
    is not adequate to demonstrate the absence of stratification.
        In response to the comments received, the single-point reference 
    method provisions in section 6.5.6 of Appendix A of today's rule are 
    more restrictive than the provisions in the proposal. After careful 
    consideration, EPA has decided to allow single-point reference method 
    sampling, but to place additional restrictions on its use. The Agency 
    believes that some of the state agency commenters' concerns about the 
    proposed single-point sampling methodology are valid. Accordingly, 
    today's final rule addresses these concerns.
        Today's rule allows the unrestricted use of single-point moisture 
    sampling only in applications where the moisture data are used to 
    determine the stack gas molecular weight. For all other moisture 
    measurement applications, i.e., for moisture monitoring system RATAs or 
    when moisture data are used to correct emission data from a dry basis 
    to a wet basis (or vice-versa), single-point moisture sampling is only 
    permitted if a 12-point pollutant or diluent gas stratification test is 
    performed and passed (at the 5.0 percent specification in section 
    6.5.6.3 of Appendix A) prior to the RATA. Similarly, for flue gas 
    sampling, today's rule allows the use of single-point reference method 
    sampling only if a 12-point gas stratification test is performed and 
    passed at the 5.0 percent specification prior to the RATA. Use of an 
    abbreviated (3- or 6-point) stratification test as a means of 
    qualifying for single-point sampling is not allowed.
        Finally, when a test location qualifies for single-point reference 
    method sampling, today's rule specifies that the measurement point must 
    be located at least 1.0 meter from the stack wall and must be situated 
    along one of the measurement lines used in the 12-point stratification 
    test. EPA believes that these modifications to the proposed single-
    point reference method sampling methodology are necessary to ensure
    
    [[Page 28575]]
    
    that representative samples will continue to be obtained.
    
    G. Data Validation
    
    1. Data Validation During Monitor Certification and Recertification
        Background: The previous version of part 75 specified that for any 
    replacement, change, or modification to a monitoring system requiring 
    recertification of the CEMS, all data from the CEMS are invalid from 
    the hour of that replacement, change, or modification until the hour of 
    completion of all required recertification tests. The proposed rule 
    would have revised Sec. 75.20(b)(3) to conditionally allow emission 
    data generated by the CEMS during a recertification test period to be 
    used for part 75 reporting, provided that the required tests are 
    successfully completed in a timely manner and that certain data 
    validation rules are followed during the recertification test period. 
    Proposed sections 6.2, 6.3.1, and 6.5 of Appendix A would have allowed 
    these new data validation procedures to also be applied to the initial 
    certification of monitoring systems. The intended purpose of the 
    proposed revisions is to minimize the number of hours of substitute 
    data or maximum potential values that must be reported during a monitor 
    certification or recertification period.
        In proposed Sec. 75.20(b)(3), specific rules were provided for data 
    validation during the recertification test period. The recertification 
    test period would begin with the first successful calibration error 
    test (known as a ``probationary calibration error test'') after making 
    the change to the CEMS and completing all necessary post-change 
    adjustments (e.g., reprogramming or linearization) of the CEMS. The 
    post-change activities could include preliminary tests such as trial 
    RATA runs or a challenge of the monitor with calibration gases. Data 
    from the CEMS would be considered invalid from the hour in which the 
    replacement, modification, or change to the system is commenced until 
    the hour of completion of the probationary calibration error test, at 
    which point the data status would become ``conditionally valid.''
        The conditionally valid status of the CEMS data would continue 
    throughout the recertification test period, provided that the required 
    recertification tests were done ``hands-off'' (i.e., with no 
    adjustments, such as reprogramming or linearization of the CEMS, other 
    than the calibration adjustments allowed under proposed section 2.1.3 
    of Appendix B) and provided that the recertification tests and required 
    daily calibration error tests continued to be passed. If all of the 
    required recertification tests and calibration error tests were passed 
    hands-off, with no failures and within the required time period, then 
    all of the conditionally valid emission data recorded by the CEMS 
    during the recertification test period would be considered quality 
    assured and suitable for part 75 reporting. However, if any required 
    test was failed, the conditionally valid data would, in most cases, be 
    invalidated and a new recertification test period would have to be 
    initiated, following corrective actions.
        Today's rule finalizes the CEMS validation procedures for 
    certifications and recertifications, with certain modifications in 
    response to comments received.
        Discussion: EPA received strongly supportive comments on the 
    proposed revisions to Sec. 75.20(b)(3) from five utilities, one state 
    air regulatory agency and two utility regulatory response groups. 
    However, two utilities asked the Agency to modify the proposal to allow 
    trial gas injections and preliminary RATA runs to be done during the 
    recertification test period, rather than prior to it. One commenter 
    stated that preliminary gas injections and RATA runs, which are 
    considered to be a valuable maintenance tool, should be allowed 
    following the probationary calibration error test, and, provided that 
    the results of the trial runs are acceptable, the recertification 
    should be allowed to proceed (see Docket A-97-35, Item IV-G-3). Another 
    commenter requested that the proposal be revised to allow a single 
    challenge with each of the three gases prior to a linearity test and to 
    allow up to five preliminary trial runs prior to a RATA (see Docket A-
    97-35, Item IV-G-5).
        Today's rule finalizes the proposed data validation procedures in 
    Sec. 75.20(b)(3) for monitor certification and recertification, with 
    the following modifications in response to the comments. First, an 
    introductory statement of applicability has been added at the beginning 
    of Sec. 75.20(b)(3), clearly indicating that the provisions of the 
    section apply both to recertifications and to initial certifications. 
    The statement of applicability also allows the data validation 
    procedures to be applied, at the discretion of the owner or operator, 
    to the routine quality assurance linearity tests and RATAs required 
    under Appendix B of part 75 (see the section on ``Data Validation for 
    RATAs and Linearity Checks'' in this preamble, for a further discussion 
    of this option). Second, proposed paragraph (b)(3)(x) of Sec. 75.20 has 
    been merged with proposed paragraph (b)(3)(i), for greater clarity; 
    both paragraphs deal with missing data substitution prior to the 
    recertification test period. Third, the definition of a ``hands-off'' 
    recertification test in Sec. 75.20(b)(3)(v) has been revised to make it 
    clear that once a recertification test has begun, only routine 
    calibration adjustments following daily calibration error tests are 
    permitted until the test is completed. Fourth, language has been added 
    to Sec. 75.20(b)(3) to address the case in which a multi-load flow RATA 
    is passed at one or more load levels and then failed at a subsequent 
    load level.
        Regarding the fourth revision to Sec. 75.20(b)(3) described in the 
    previous paragraph, 2.3.2(e) of Appendix B of today's rule states that 
    in such cases, only the RATA at the failed load level needs to be 
    repeated (unless re-linearization of the monitor is necessary, in which 
    case a 3-load RATA is required). Because of this new Appendix B 
    provision, the following corresponding data validation provisions have 
    been added to Secs. 75.20(b)(3)(vii)(A) and 75.20(b)(3)(vii)(B): (1) 
    upon failure of the RATA at the particular load level, the length of 
    the new recertification test period is not 720 unit operating hours, 
    but is equal to the number of hours remaining in the original 
    recertification test period at the time of test failure; and (2) data 
    invalidation is prospective, beginning with the hour of failure of the 
    RATA at the particular load level; therefore, conditionally valid data 
    recorded prior to the test failure at the particular load level are not 
    invalidated. Finally, in response to the comments received, a new 
    paragraph, (b)(3)(vii)(E), has been added to Sec. 75.20 to address the 
    issue of trial RATA runs and pre-test gas injections. Section 
    75.20(b)(3)(vii)(E) allows pre-test trial gas injections and pre-RATA 
    runs to be done during the recertification period, for the purpose of 
    optimizing the performance of the monitoring system. A trial run or 
    injection will not affect the status of previously-recorded 
    conditionally valid data, provided that: (1) the results of the trial 
    run are within the Appendix A specifications for a passed linearity 
    test or RATA (i.e., for a trial gas injection, within 5% or 
    5 ppm of the reference gas or, for a trial RATA run, if the average 
    reference method and the average CEMS readings differ by no more than 
    10% of the reference method value, or 15 ppm, 
    or 0.02
    lb/mmBtu, or 1.5% H2O, as applicable); (2) no 
    adjustments are made
    
    [[Page 28576]]
    
    to the calibration of the CEMS following the trial run, other than the 
    adjustments allowed under section 2.1.3 of Appendix B; and (3) the CEMS 
    is not repaired, re-linearized, or reprogrammed after the trial run. As 
    long as these conditions continue to be met, the CEMS can be further 
    optimized without data loss. However, if, for any trial run or 
    injection the conditions are not met, the trial run or injection is 
    treated as a failed or aborted linearity check or RATA and the 
    applicable provisions in Secs. 75.20(b)(3)(vii)(A) and 
    75.20(b)(3)(vii)(B) pertaining to aborted or failed recertification 
    tests must be followed.
    2. Data Validation for RATAs and Linearity Checks
        Background: EPA proposed rules for CEMS data validation prior to 
    and during the periodic linearity tests and RATAs required by part 75. 
    These new provisions were found in proposed sections 2.2.3 and 2.3.2 of 
    Appendix B. According to these provisions, a linearity test or RATA 
    could not be started if the CEMS were operating ``out-of-control'' with 
    respect to any of its other daily, semiannual, or annual quality 
    assurance tests. Prior to the test, both routine and non-routine 
    calibration adjustments, as defined in proposed section 2.1.3 of 
    Appendix B, would be permitted. During the linearity or RATA test 
    period, however, no adjustment of the monitor would be permitted except 
    for routine daily calibration adjustments following successful daily 
    calibration error tests. For 2-level and 3-level flow RATAs, no 
    linearization of the monitor would be permitted between load levels. If 
    a linearity check or RATA was failed or aborted due to a problem with 
    the monitor, the monitor would be declared out-of-control as of the 
    hour in which the test is failed or aborted. Data from the monitor 
    would remain invalid until the hour of completion of a subsequent 
    successful test of the same type.
        The proposed rule also attempted to clarify the way in which 
    linearity and RATA test results are to be reported to EPA in the 
    electronic quarterly report required under Sec. 75.64. Proposed 
    sections 2.2.3 and 2.3.2 of Appendix B specified that only the results 
    of completed and partial tests which affect data validation would have 
    to be reported. That is, all completed passed tests, all completed 
    failed tests, and all tests aborted due to a problem with the CEMS 
    would have to be included in the quarterly report. Therefore, aborted 
    test attempts followed by corrective maintenance, re-linearization of 
    the monitor, or any other adjustments other than those allowed under 
    proposed section 2.1.3 of Appendix B would have to be reported. 
    However, tests which are aborted or invalidated due to problems with 
    the calibration gases or reference method or due to operational 
    problems with the affected unit(s) would not need to be reported, 
    because such runs do not affect the validation status of emission data 
    recorded by the CEMS. In addition, aborted RATA attempts which are part 
    of the process of optimizing a monitoring system's performance would 
    not have to be reported, provided that in the period from the end of 
    the aborted test to the commencement of the next RATA attempt: (1) no 
    corrective maintenance or re-linearization of the CEMS was performed, 
    and (2) no adjustments other than the calibration adjustments allowed 
    under proposed section 2.1.3 of Appendix B were made. However, such 
    aborted RATA runs would still have to be documented and kept on-site as 
    part of the official test log.
        Today's rule finalizes the CEMS data validation requirements for 
    RATAs and linearity checks. The final rule has been modified from the 
    proposal, based on comments received.
        Discussion: EPA received comments on the proposed data validation 
    procedures for RATAs and linearity checks from one state air regulatory 
    agency, two utilities and one utility regulatory response group. Two of 
    the commenters found the proposed rule language defining the allowable 
    pre-test adjustments to be inconsistent with the preamble language 
    found at 63 FR 28075. The commenters noted an apparent contradiction 
    between the preamble statement that there is ``no significant risk in 
    allowing pre-RATA adjustments provided that the monitor's accuracy 
    between successive RATAs can be reasonably established'' and the rule 
    language in section 6.5(a)(1) of Appendix A that ``no adjustments, 
    linearizations or reprogramming of the CEMS other than the calibration 
    adjustments described in section 2.1.3 of Appendix B to this part, are 
    permitted prior to and during the RATA test period.'' Both commenters 
    expressed concern that this proposed rule language appeared to exclude 
    important activities such as re-linearization of a flow monitor (see 
    Docket A-97-35, Items IV-D-20, IV-G-2). Another commenter also objected 
    to the proposed language in section 6.5(a)(1) of Appendix A, stating 
    that technicians need to be able to perform evaluations and adjustments 
    of flow and gas measurement systems prior to conducting a RATA (see 
    Docket A-97-35, Item IV-G-3). Another commenter took issue with the 
    provisions in proposed sections 2.2.3 and 2.3.2 of Appendix B which 
    allow ``non-routine'' adjustments to be made prior to linearity tests 
    and RATAs. The commenter especially objected to the idea of allowing 
    adjustments in a direction away from the reference gas tag value, 
    believing that this compromises the integrity of the audit and sets an 
    ``unfortunate precedent'' (see Docket A-97-35, Item IV-D-11).
        Today's rule finalizes the data validation provisions for linearity 
    checks and RATAs in sections 2.2.3 and 2.3.2 of Appendix B. Based on 
    the comments received, EPA has made substantive revisions to the 
    proposed rule in an attempt to clarify the allowable pre-test 
    adjustments and the rules for validating the CEMS data. Today's rule 
    specifies that when a linearity check or RATA is due, the owner or 
    operator has three options. First, the test may be done ``cold,'' with 
    no pre-test adjustments of any kind. Second, the test may be done after 
    making only the routine or non-routine calibration adjustments allowed 
    under section 2.1.3 of Appendix B. Under this second option, trial gas 
    injections and preliminary RATA runs are allowed, followed by 
    additional adjustments (if necessary) within the limits of section 
    2.1.3 of Appendix B, to optimize the monitor's performance. The trial 
    runs or injections need not be reported, provided that they meet the 
    acceptance criteria for trial RATA runs and gas injections in 
    Sec. 75.20(b)(3)(vii)(E) (see the section of this preamble entitled 
    ``Data Validation During Monitor Certification and Recertification'' 
    for further discussion of these acceptance criteria). If the acceptance 
    criteria are not met, the trial run is counted as a failed or aborted 
    test. Third, the CEMS may be repaired, re-linearized or reprogrammed 
    prior to the quality assurance test. In this case, the CEMS may either 
    be considered out-of-control from the hour of commencement of the 
    corrective maintenance, re-linearization or reprogramming until 
    completion of the required quality assurance test or the owner or 
    operator may follow the data validation procedures in Sec. 75.20(b)(3) 
    upon completion of the necessary corrective maintenance, re-
    linearization, or reprogramming.
        EPA believes that the revisions to sections 2.2.3 and 2.3.2 of 
    Appendix B address the commenters' concerns about pre-test adjustments. 
    For example, if, at the time of a scheduled flow RATA, the owner or 
    operator decides to re-linearize the primary flow monitor to optimize 
    its performance, this would be permissible under the third option 
    above. However, re-linearization of a flow monitor
    
    [[Page 28577]]
    
    triggers a requirement to perform a 3-load RATA. Therefore, if the 
    monitor is declared out-of-control from the hour of the re-
    linearization until the hour of completion of the 3-load RATA (as would 
    be required by the proposed rule), this could result in significant 
    data loss, since a 3-load RATA can take days (or even weeks) to 
    complete, depending on electrical demand. For this reason, today's rule 
    allows the owner or operator to use the recertification data validation 
    procedures in Sec. 75.20(b)(3) to supplement the quality assurance 
    provisions in Appendix B. In this example, if the owner or operator 
    opts to use the data validation procedures in Sec. 75.20(b)(3), data 
    from the flow monitor would be considered conditionally valid upon 
    completion of a ``probationary calibration error test,'' following the 
    re-linearization of the monitor. The procedures in 
    Sec. 75.20(b)(3)(vii)(E) allow for trial runs and further optimization 
    of the monitor prior to the RATA. If the 3-level flow RATA is then 
    passed in accordance with the procedures of Sec. 75.20(b)(3) and within 
    the allotted time frame (indicating that the re-linearization was 
    successful), the conditionally valid data will become quality assured 
    and may be used for reporting.
        For the following reasons, EPA does not agree with the commenter 
    who opposed allowing ``non-routine'' calibration adjustments prior to a 
    quality assurance test. The ``non-routine'' adjustments described in 
    section 2.1.3 of Appendix B allow adjustments only within the 
    performance specifications of the instrument. When a monitor is 
    initially certified, it must pass several quality assurance tests, one 
    of which is a 7-day calibration error test. The monitor must 
    demonstrate, for 7 consecutive operating days, that it is capable of 
    meeting a calibration error specification of 2.5 percent of 
    the instrument span (3.0 percent for flow monitors). Once a 
    monitor has been certified, the ``control limits'' for daily 
    calibration error tests of the monitor are twice the performance 
    specification value, i.e., 5.0 percent of span for gas 
    monitors and 6.0 percent for flow monitors. Thus, when the 
    ``non-routine'' adjustments described under section 2.1.3 of Appendix B 
    are made prior to a linearity test or RATA, the monitor is actually 
    being held to a tighter specification than is used for daily operation. 
    The Agency therefore does not agree that keeping the instrument's 
    calibration within the performance specification ``band'' at the time 
    of linearity tests or RATAs compromises the integrity of the audits or 
    sets a bad precedent. On the contrary, it demonstrates that the monitor 
    continues to perform in a comparable manner to its performance at the 
    time of initial certification. When the monitor is held to the 
    calibration error specification required for initial certification, the 
    monitor is shown to be capable of passing a linearity test or RATA.
    
    H. Appendix D--Sulfur Dioxide Emissions From the Combustion of Gaseous 
    Fuels
    
        Background: EPA proposed several revisions to the procedures in 
    Appendix D of part 75 for determining sulfur dioxide emissions from 
    gas-fired and oil-fired units. Most of the proposed revisions would 
    provide affected utilities with additional flexibility and sampling 
    options. These changes were generally supported by the comments 
    received and have either been finalized as proposed or with minor 
    revisions and clarifications. However, for gaseous fuels, EPA received 
    a number of significant comments concerning the proposed changes to the 
    definition of the term ``pipeline natural gas'' under Sec. 72.2 and 
    received other comments which have prompted the Agency to re-evaluate 
    the applicability and use of Appendix D. In response to the significant 
    comments received, the Agency is adopting the following final revisions 
    to Appendix D and to Sec. 72.2:
        (1) Revised definitions of ``pipeline natural gas,'' ``natural 
    gas'' and ``gas-fired'' have been promulgated in Sec. 72.2;
        (2) The applicability of Appendix D has been expanded to include 
    gaseous fuels with any sulfur content (previously, Appendix D had been 
    limited to gaseous fuels with a sulfur content of 20 grains per 100 
    scf, or less); and
        (3) The methodology for determining the frequency of fuel gross 
    calorific value (GCV) under section 2.3 of Appendix D has been 
    modified.
        In order to put today's revisions in context, it is necessary to 
    review how the Agency addressed these issues in previous rulemakings. 
    Section 2.4 of Appendix D of the core rules of the Acid Rain Program 
    issued on January 11, 1993, allowed units combusting ``natural gas'' 
    (as defined in Sec. 72.2) to calculate SO2 mass emissions 
    through either: (1) fuel sulfur sampling and measurement of the fuel 
    flow rate by a certified fuel flowmeter; or (2) the use of a default 
    SO2 emission rate of 0.0006 lb/mmBtu and heat input 
    determined using a certified fuel flowmeter and monthly analysis for 
    fuel GCV. In the preamble to the January 11, 1993 rule, the Agency 
    stated, ``the definition of ``natural gas'' does not, therefore, 
    include landfill gas, digester gas, biomass, or gasified coal'' (58 FR 
    3590 and 3596). The Agency further stated in the preamble that, 
    ``essentially sulfur-free fuels such as natural gas, landfill methane, 
    or synthetic propane'' should qualify for the use of Appendix D 
    methodologies. The intent of the Agency in that rulemaking was to allow 
    the use of a default emission rate for SO2 mass emissions 
    calculations for natural gas and other fuels which have a similar low 
    sulfur content, but not for fuels which have higher sulfur content than 
    natural gas. Appendix D did not effectively address how to determine 
    SO2 mass emissions for gaseous fuels other than natural gas.
        On May 17, 1995 the Agency revised the core Acid Rain rules to add 
    a new definition for ``pipeline natural gas,'' and revised the 
    definitions of ``natural gas'' and ``gas-fired.'' The most significant 
    change in the definition of ``natural gas'' was the addition of the 
    requirement that ``natural gas'' must contain ``one grain or less 
    hydrogen sulfide per 100 standard cubic feet and 20 grains or less 
    total sulfur per 100 standard cubic feet.'' The intent of this 
    additional language was to clarify which gaseous fuels qualified as 
    ``natural gas.'' The criteria used (1 grain hydrogen sulfide 
    (H2S) and 20 grains total sulfur) were based on contracts 
    and tariff sheets for pipeline natural gas regulated by the Federal 
    Energy Regulatory Commission (FERC). Consistent with this approach, the 
    Agency defined ``pipeline natural gas'' as natural gas provided by a 
    supplier through a pipeline. In addition, the Agency modified the 
    definition of ``gas-fired'' to make it clear that the use of Appendix D 
    was limited to units combusting ``fuel oil,'' ``natural gas,'' and 
    ``gaseous fuels containing no more sulfur than natural gas.'' The 
    default SO2 emission rate of 0.0006 lb/mmBtu could only be 
    used for the combustion of either natural gas or a fuel with a sulfur 
    content no greater than natural gas. To use the default SO2 
    emission rate, the owner or operator was required to demonstrate that 
    the fuel being combusted qualified as natural gas, based on contract or 
    tariff values which indicate that the gas meets the criteria for 
    natural gas H2S content and total sulfur content.
        As noted in the preamble of the proposed rule, the May 12, 1995 
    revisions apparently did not eliminate confusion concerning the use of 
    the default SO2 emission rate. The SO2 default 
    emission rate of 0.0006 lb/mmBtu is equivalent to approximately 0.2 
    grains hydrogen sulfide per 100
    
    [[Page 28578]]
    
    standard cubic feet (scf) of gas, when hydrogen sulfide is the sole 
    source of total sulfur in the gas (as is the case for refined natural 
    gas), or 0.2 grains total sulfur per 100 scf of gas. The Agency did not 
    intend that fuels with average sulfur content much higher than 0.2 
    grains per 100 scf should be allowed to use the default value. In this 
    context, the current definition of ``natural gas'' under Sec. 72.2, 
    which includes the term ``20 grains of total sulfur,'' is somewhat 
    confusing. Further, use of the 0.0006 lb/mmBtu default emission rate 
    for ``natural gas'' with one grain of H2S per 100 scf would 
    result in an approximately five-fold underestimation of SO2 
    emissions. Therefore, in the proposed rule, the Agency modified the 
    definition of pipeline natural gas to include only natural gas with a 
    hydrogen sulfide content less than or equal to 0.3 grains hydrogen 
    sulfide per 100 scf, thereby clarifying that the default emission rate 
    of 0.0006 lb/mmBtu could only be used for natural gas with an 
    appropriately low hydrogen sulfide content.
        The proposed rule required documentation of the hydrogen sulfide 
    content of the natural gas either through quality characteristics 
    specified by a purchase contract or pipeline transportation contract, 
    through certification of the gas vendor, based on routine vendor 
    sampling and analysis, or through at least one year's worth of 
    analytical data on the fuel hydrogen sulfide content from samples taken 
    at least monthly, demonstrating that all samples contain 0.3 grains or 
    less of hydrogen sulfide per 100 standard cubic feet. For a fuel to be 
    classified as ``pipeline natural gas'' the fuel would, of course, first 
    have to meet the current definition of ``natural gas'' in Sec. 72.2, 
    which states, ``Natural gas means a naturally occurring fluid mixture 
    of hydrocarbons (e.g., methane, ethane, or propane) containing 1 grain 
    or less hydrogen sulfide per 100 standard cubic feet, and 20 grains or 
    less total sulfur per 100 standard cubic feet), produced in geological 
    formations beneath the Earth's surface, and maintaining a gaseous state 
    at standard atmospheric temperature and pressure under ordinary 
    conditions.''
        Discussion: Several comments were received on the proposed changes 
    to the definition of ``pipeline natural gas,'' and comments were also 
    received on the current definition of ``natural gas.'' In responding to 
    the comments, the Agency is revising both the definition of ``pipeline 
    natural gas'' and ``natural gas,'' as well as making various 
    corresponding changes to wording in part 75 to ensure consistency 
    within the rule.
        Two commenters were opposed to the change to the definition of 
    pipeline natural gas (see Docket A-97-35, Items IV-D-23 and IV-D-24). 
    Both commenters suggested that the requirement to document that a 
    gaseous fuel has 0.3 gr/100 scf of H2S, as 
    opposed to the previous requirement to document an H2S 
    content 1.0 gr/100 scf, would either disqualify some sources 
    currently using the default emission rate of 0.0006 lb/mmBtu or force 
    those sources to use means other than the contract or tariff provisions 
    to demonstrate that the hydrogen sulfide content of the gas is less 
    than 0.3 gr./100 scf. Under the proposed Appendix D revisions, any 
    sources disqualified from the use of the default SO2 
    emission rate would either be required to begin daily gas sampling of 
    the fuel sulfur content or would have to install an SO2 
    CEMS.
        Two other commenters suggested that the use of two sulfur content 
    criteria in the natural gas definition (the dual criteria of 1 grain 
    H2S and 20 grains total sulfur per 100 scf) was confusing 
    and could lead to misinterpretation of which fuels could be classified 
    as either ``pipeline natural gas'' or ``natural gas'' under Sec. 72.2 
    (see Docket A-97-35, Items IV-G-3 and IV-G-10). One of these commenters 
    suggested that the definition of natural gas should be changed to 
    incorporate only the requirement of 20 grains or less of total sulfur 
    per 100 scf. If this suggestion were followed, a source with 20 grains 
    total sulfur per 100 scf could use an SO2 emission rate of 
    0.0006 lb/mmBtu, thereby underestimating SO2 emissions 100-
    fold. This would clearly be unacceptable and contrary to the Agency's 
    intent since the initial adoption of Appendix D.
        One commenter suggested that the requirement to determine the fuel 
    GCV on the same frequency as sulfur sampling be removed from Appendix D 
    and that monthly GCV sampling be allowed in all cases (see Docket A-97-
    35, Item IV-D-20). The commenter claimed that the variability of fuel 
    GCV is not necessarily the same as the variability of the sulfur 
    content of a fuel.
    1. Summary of EPA Analysis of Appendix D Gaseous Fuel SO2 
    and Heat Input Methodologies
        In responding to the comments received, the Agency first attempted 
    to quantify the SO2 emissions from the combustion of gaseous 
    fuels under the current Acid Rain rules. A data analysis was performed, 
    assuming that the vast majority of SO2 emissions from the 
    combustion of gaseous fuel are from affected units reporting gas as the 
    primary fuel. The data analysis (which was limited to 1997 emission 
    data) indicates the following: (1) there are 582 units that list gas as 
    the primary fuel (representing about 30% of the units in the program); 
    (2) these 582 units accounted for approximately 10% of the total heat 
    input reported for all Acid Rain-affected units; (3) the total amount 
    of SO2 emitted by these 582 units was 14,728 tons in 1997 or 
    0.1% of the total SO2 mass emissions in the program; and (4) 
    of the 14,728 tons of SO2 emitted by the 582 units, 12,844 
    tons were from only 17 units and the remaining 1,884 tons were from the 
    remaining 565 units (see Docket A-97-35, Item IV-A-4). Thus it appears 
    that gas-fired units account for a significant portion of the total 
    heat input and electrical generation under the Acid Rain Program, but 
    contribute only a fraction of one percent of the total SO2 
    emissions. Note, however, that even though emissions from the 
    individual gas-fired units are very small, the cumulative emissions 
    from all 582 units are roughly equivalent to the typical SO2 
    emissions from a coal-fired unit. For this reason, the method of 
    calculating the SO2 emissions from the gas-fired units must 
    be sufficiently accurate to prevent significant underestimation of 
    emissions. The methodology in the current rule allows the default 
    SO2 emission rate of 0.0006 lb/mmBtu to be used for all 
    types of natural gas. As previously noted, the default emission rate 
    corresponds to 0.2 grains of H2S per 100 scf, but the 
    definition of natural gas allows fuels with up to 1.0 grain of 
    H2S and 20 grains of total sulfur to be classified as 
    ``natural gas.'' In view of this, it is possible that the reported 
    cumulative SO2 emissions reported in 1997 for the 582 gas-
    fired units may be inaccurate by several orders of magnitude. This 
    level of uncertainty in reported emissions is unacceptable in an 
    allowance trading program such as the Acid Rain Program. Consequently, 
    a more representative method is needed to characterize the actual 
    sulfur content of the gaseous fuels combusted by Acid Rain-affected 
    units.
        The Agency also performed an analysis of all available gaseous fuel 
    GCV sampling data from all Acid Rain sources reporting such data in 
    1997. Gaseous fuels were analyzed in two categories, pipeline natural 
    gas and ``other'' gas. Only 14 Acid Rain sources reported sampling and 
    analysis of ``other'' gases in 1997. The data analysis showed that for 
    275,669 pipeline natural gas analyses, the average fuel GCV was 1023 
    Btu/ft3 and the 95th
    
    [[Page 28579]]
    
    percentile value was 1051 Btu/ft3, a difference of only 
    2.6%. For the ``other'' gaseous fuels, the average GCV from 14,282 
    analyses was 819 Btu/ft3 and the 95th percentile value was 
    1118 Btu/ft3, a difference of approximately 26%. This 
    demonstrates the consistency of the GCV of pipeline natural gas and the 
    high variability of the few ``other'' gaseous fuels for which Appendix 
    D is currently being used (see Docket A-97-35, Item IV--A-1).
        In finalizing today's rule, the Agency also considered the 
    potential impact of the revisions to Appendix D on the new Subpart H of 
    part 75 (which establishes the requirements for monitoring of 
    NOX mass emissions). Currently, the provisions of Subpart H 
    are being used by the Ozone Transport Commission (OTC) NOX 
    Budget Program and, in the future, Subpart H may be adopted as part of 
    an implementation plan as a means of complying with the NOX 
    SIP Call (see 63 FR 57356). Subpart H of part 75 allows heat input 
    determined by the procedures of Appendix D to be used in determining 
    NOX mass emissions from gas-fired units. In the process of 
    implementing part 75 and the OTC NOX Budget Program, the 
    Agency has encountered an increasing number of sources that combust 
    gaseous fuels which neither qualify as ``pipeline natural gas'' or 
    ``natural gas.'' These fuels include refinery gas, landfill gas, 
    digester gas, coke oven gas, process gas, propane liquified gas, 
    liquified petroleum gas, blast furnace gas and coal-derived gas. Under 
    the previous version of part 75 units combusting these fuels would 
    either be required to install SO2 and stack flow monitoring 
    systems or would have to petition the Agency to use Appendix D. It is 
    likely that under the OTC NOX Budget Program and under the 
    SIP call, the number of sources combusting these ``other'' gaseous 
    fuels and required to monitor heat input using part 75 methods will 
    increase significantly. The Agency anticipates that the owners or 
    operators of the majority of these sources would petition to use the 
    procedures of Appendix D to determine heat input used for 
    NOX mass calculations, in lieu of installing CEMS. However, 
    the current Appendix D does not address how to determine hourly heat 
    input for gaseous fuels with variable GCV. The Agency also notes that 
    any error in hourly heat input determined under Appendix D would result 
    in a corresponding and equal error in the reported NOX mass 
    emissions. It is therefore particularly important to establish 
    consistent and easily implementable heat input monitoring criteria for 
    all types of gaseous fuels under Appendix D. Clear, flexible and 
    reasonable requirements for gaseous fuel GCV sampling and analysis are 
    needed.
        Based on the comments received and the data analyses described 
    above, the Agency has concluded that:
    
         The use of the default SO2 emission rate of 
    0.0006 lb/mmBtu is only appropriate for natural gas with a 
    documented contractual or tariff limit of 0.3 grains hydrogen 
    sulfide per hundred standard cubic feet or for fuels which are 
    demonstrated to have a similar low total sulfur content.
         For natural gas with a contract or tariff hydrogen 
    sulfide limit up to 1.0 grain of hydrogen sulfide per 100 standard 
    cubic feet, or for fuels which are demonstrated to have a similar 
    low total sulfur content, a site-specific default SO2 
    emission rate should be allowed, which more closely represents the 
    potential SO2 emission rate for that fuel.
         The applicability of Appendix D should be expanded to 
    include any gaseous fuel (rather than limiting it to fuels with a 
    total sulfur content  20 grains per 100 scf. For gaseous 
    fuels with highly variable sulfur content, hourly sampling using 
    advanced monitoring such as on-line gas chromatography should be 
    required. The frequency of determination of the GCV of a gaseous 
    fuel should be independent of the requirements for sulfur sampling 
    and should be based solely on the variability of the GCV.
    2. Changes to the Definitions of ``Pipeline Natural Gas'' and ``Natural 
    Gas''
        As previously stated, the Agency is revising the definitions of 
    ``pipeline natural gas'' and ``natural gas'' in Sec. 72.2. Since the 
    definition of ``pipeline natural gas'' necessarily includes the 
    definition of ``natural gas'', and the definitions therefore involve 
    similar issues, EPA is addressing both definitions in today's final 
    rule. In particular, ``pipeline natural gas'' is defined in such a way 
    that only fuels with the appropriate sulfur content can meet the 
    definition and can use the default emission rate of 0.0006 lb/mmBtu. 
    Under the revised definition, pipeline natural gas must contain less 
    than 0.3 grains of hydrogen sulfide per 100 scf. Consistent with this 
    approach, the definition of ``natural gas'' is revised so that only the 
    requirement for the hydrogen sulfide content to be less than one grain 
    per 100 scf remains, and the requirement for the total sulfur content 
    to be 20 grains per 100 scf is deleted. Further, EPA is 
    adding to both definitions a requirement that hydrogen sulfide content 
    must account for at least 50% (by weight) of the total sulfur in the 
    fuel. This ensures that a fuel with a high total sulfur content, but a 
    relatively small hydrogen sulfide content, cannot qualify to use a 
    default SO2 emission rate. The Agency believes that in 
    general, any ``natural gas'' with 1.0 grain of 
    H2S/100 scf will also meet the requirement that hydrogen 
    sulfide must account for 50% of the total sulfur in the 
    fuel. However, the Agency reserves the right to request that the owner 
    or operator provide data to demonstrate compliance with this latter 
    requirement. Finally, EPA is adding a requirement to the ``natural 
    gas'' definition that the gas must have either a methane content of at 
    least 70% or the same GCV as methane (950 to 1100 Btu/scf). This 
    requirement ensures that the gas will have a stable GCV, consistent 
    with the Appendix D provisions which allow monthly GCV sampling for 
    either pipeline natural gas or natural gas. In today's rule, the 
    requirements for documenting that a fuel qualifies as ``pipeline 
    natural gas'' or ``natural gas'' are essentially the same as the 
    proposed rule. The three principal ways of providing the necessary 
    documentation are: (1) gas quality characteristics specified in a 
    purchase contract or pipeline transportation contract; (2) 
    certification by the gas vendor, based on routine sampling and analysis 
    for at least one year; and (3) at least one year of analytical data on 
    the fuel characteristics, derived from monthly (or more frequent) 
    samples. In addition, sections 2.3.5 and 2.3.6 of Appendix D of today's 
    rule allow the owner or operator to conduct a 720 hour demonstration of 
    the fuel's sulfur and GCV characteristics (see Items 5 and 6 in this 
    section, below).
        EPA believes that the revised definitions of ``pipeline natural 
    gas'' and ``natural gas'' will: (1) apply to the low sulfur fuel 
    combusted by the vast majority of the sources in the Acid Rain Program; 
    (2) be documentable, in most cases, based on contract or tariff 
    provisions without other types of demonstrations; and (3) allow most 
    sources currently using 0.0006 lb/mmBtu as a default to continue using 
    that default value or to use an alternative, site-specific default 
    value that will not underestimate SO2 emissions.
    3. Changes to the Methodology for Calculating SO2 Emissions 
    Under Appendix D
        Today's rule adopts a two-tiered approach to the use of default 
    SO2 emission rates, depending on whether a fuel qualifies as 
    ``pipeline natural gas'' or as ``natural gas.'' First, if the owner or 
    operator can demonstrate that the fuel combusted at a unit has 
    0.3 grains of hydrogen sulfide per 100 scf, the default 
    SO2 emission rate of 0.0006 lb/mmBtu may be used. Second, 
    the rule allows units combusting gaseous fuels
    
    [[Page 28580]]
    
    with >0.3 grains, but 1.0 grain of hydrogen sulfide per 100 
    scf to calculate a site-specific default SO2 emission rate, 
    as suggested by two of the commenters (see Docket A-97-35, Items IV-D-
    23 and IV-D-24). The method of calculating the default value is based 
    on the actual conversion of hydrogen sulfide in natural gas to 
    SO2 and utilizes a realistic fuel GCV value of 1023 Btu/scf 
    (from the previously-discussed data analysis, above). The result is a 
    simple equation which converts hydrogen sulfide in natural gas to an 
    SO2 emission rate in lb/mmBtu.
    4. Changes to the Applicability of Appendix D
        In the process of considering comment on the definitions of 
    ``pipeline natural gas'' and ``natural gas'' the Agency also re-
    evaluated the appropriateness of limiting the applicability of Appendix 
    D to gaseous fuels with 20 grains of total sulfur per 100 
    scf. While EPA does not believe that a gaseous fuel with 20 or more 
    grains of total sulfur per 100 scf should be allowed to use a default 
    SO2 emission rate, neither does the Agency believe that 
    units combusting such fuel should be excluded from using Appendix D. 
    Currently, technologies such as on-line gas chromatography allow 
    accurate fuel sulfur analysis to be performed over intervals as short 
    as one hour. This ability to perform hourly sampling is comparable to a 
    CEMS in accuracy, precision and timeliness. Therefore, today's rule 
    removes the 20 grains of sulfur per 100 scf restriction on the use of 
    Appendix D for gaseous fuels.
    5. Changes to the Method of Determining the Sulfur Content Sampling 
    Frequency for Gaseous Fuels
        Section 2.3.6 of Appendix D of today's rule also includes a general 
    procedure for determining the appropriate frequency of sulfur content 
    sampling for any gaseous fuel which is transmitted by a pipeline. The 
    procedure consists of a 720 hour demonstration, similar to the one in 
    section 2.3.3.4 of Appendix D in the proposed rule. The results of the 
    720 hour demonstration may first be used to determine first if a fuel 
    qualifies as either ``pipeline natural gas'' or ``natural gas'' or as 
    ``other'' gaseous fuel, and then to determine the appropriate total 
    sulfur sampling frequency for the fuel. If a fuel qualifies as pipeline 
    natural gas, the default SO2 emission rate of 0.0006 lb/
    mmBtu could be used in lieu of fuel sampling. If the fuel qualifies as 
    ``natural gas'' (but not pipeline natural gas), a site-specific default 
    SO2 emission rate may be used, based on the highest hourly 
    hydrogen sulfide concentration recorded during the 720 hour 
    demonstration. After a fuel qualifies as ``natural gas,'' the owner or 
    operator is required to sample the H2S content at least once 
    monthly for a year following the 720 hour demonstration. The default 
    emission rate for the demonstration may continue to be used, provided 
    that none of the samples taken during the year exceeds 1.0 grain/100 
    scf of H2S. All ``other'' gaseous fuels would require either 
    daily or hourly sampling of the total sulfur content, depending on the 
    fuel sulfur variability.
    6. Changes to the Method of Determining the GCV Sampling Frequency for 
    Gaseous Fuels
        Accurate determinations of heat input are important for the 
    calculation of SO2, NOX and CO2 mass 
    emissions under Appendices D, E, G and Subpart H of part 75. EPA has 
    found that fuels such as refinery gas, digester gas, landfill gas, coke 
    oven gas, process gas, propane liquified gas, liquified petroleum gas, 
    blast furnace gas, and coal derived gas can have highly variable GCV 
    (see Docket A-97-35, Item IV-A-4). For these fuels a standardized test 
    for determining the appropriate GCV sampling and analysis frequency is 
    essential. One commenter on the proposed rule noted that in many cases 
    the GCV of a fuel is relatively stable over a period of time, and 
    sampling each month for fuel heat content is adequate (see Docket A-97-
    35, Item IV-D-20). The Agency agrees that this is true in many cases 
    (e.g., for natural gas), but not often for the fuels listed above. The 
    Agency also notes that the emissions data determined under Appendix D 
    must be as reliable, precise, timely and accessible as data from a 
    CEMS.
        In view of this, the Agency is revising the criteria for 
    determining the frequency of GCV sampling for gaseous fuels. For any 
    fuel which meets the revised definition of either ``pipeline natural 
    gas'' or ``natural gas,'' this ensures that the fuel will have a stable 
    heat content and therefore monthly sampling is appropriate. For fuels 
    which do not qualify as either pipeline natural gas or natural gas and 
    for which ``as-delivered'' fuel sampling and analysis is not performed, 
    the same 720 hour demonstration described in item 5 in this section, 
    above, for fuel sulfur sampling will also be used to determine the 
    appropriate GCV sampling and analysis frequency. The heat content of 
    the fuel will be determined for each hour in the 720 hour period. For 
    units that switch fuels seasonally or when process changes occur (such 
    as refinery fuel gas combustion units) the 720 hour demonstration 
    period must also include data which characterizes the variability of 
    the fuel during the seasonal or process changes. The results of the 720 
    hour demonstration will be used to determine the average heat content 
    of the fuel and the standard deviation. As explained in section 2.3.5 
    of Appendix D in today's rule, depending on the results of the 
    demonstration, the owner or operator will perform either daily or 
    hourly sampling of the fuel GCV.
    
    I. Electronic Transfer of Quarterly Reports
    
        Background: For the reasons discussed in the preamble to the 
    proposed rule revisions (63 FR 57356, May 21, 1998), EPA proposed 
    changes to Sec. 75.64(f) concerning the method of submitting quarterly 
    reports. The proposal provided that all quarterly reports would have to 
    be submitted to EPA by direct computer-to-computer electronic transfer 
    via modem and EPA-provided software, unless otherwise approved by the 
    Administrator. This requirement was to begin with the quarterly report 
    for the first quarter of the year 2000.
        Discussion: EPA received one comment (see Docket A-97-35, Item IV-
    D-20) which opposed the proposed requirement based on difficulty in 
    receiving electronic transfer of quarterly reports due to technical 
    difficulties with EPA computers which may arise due to year 2000 
    conversion difficulties or other technical problems relative to 
    electronic transfer of quarterly reports at times when EPA computers 
    may not be accessible. Concern was expressed regarding the requirement 
    for utilities to provide proof that they attempted to transfer their 
    reports on time but were unsuccessful due to the inability to gain 
    access to the EPA computer system.
        Based on the comment received, EPA has decided to change the 
    electronic reporting requirement in Sec. 75.64(f) so that beginning 
    with the quarterly report for the first quarter of the year 2001, all 
    quarterly reports must be submitted to EPA by direct computer-to-
    computer electronic transfer via modem and EPA-provided software, 
    unless otherwise approved by the Administrator. This will ensure 
    adequate time for all parties to address the year 2000 concerns. EPA 
    notes that its system has already undergone testing and changes to 
    accommodate year 2000 concerns.
    
    J. Bias, Relative Accuracy and Availability Determinations
    
        Background: The preamble to the proposed rule described the 
    findings of studies performed to evaluate the
    
    [[Page 28581]]
    
    provisions for the bias test, relative accuracy, and monitor 
    availability trigger conditions as required by Secs. 75.7 and 75.8. 
    Issues concerning the bias relative accuracy, and monitor availability 
    provisions in the core Acid Rain rules had been raised in litigation 
    (Environmental Defense Fund v. Carol M. Browner, No. 93-120; et al. 
    D.C. Cir., 1993). The purpose of these studies was to address these 
    issues (see 63 FR 28197). The preamble of the proposed rule explained 
    how these findings led to the Agency's proposed determinations to 
    retain the current rule provisions concerning these matters. There were 
    no comments objecting to the substance of the proposed determinations. 
    Therefore, for the reasons set forth in the preamble to the proposed 
    rule, EPA is adopting the proposed rule revisions as final, with the 
    result that Secs. 75.7 and 75.8 are removed and reserved. Moreover, 
    since none of the issues raised concerning the bias, relative accuracy, 
    and monitor availability provisions in the core Acid Rain rules were 
    raised in any comments on the studies, EPA maintains that those 
    litigation issues have been resolved.
        Discussion: Two comments were received. One (see Docket A-97-56, 
    Item IV-D-01) supported the proposed determinations. The second comment 
    (see Docket A-97-56, Item IV-D-02) expressed concern that the bias test 
    studies performed in response to Sec. 75.7 did not evaluate 
    overestimation in flow measurements. The commenter urged EPA to 
    complete its ongoing work as quickly as possible on a separate 
    rulemaking to resolve the commenter's flow overestimation concerns. The 
    Agency is pursuing the separate rulemaking recommended by the 
    commenter.
    
    K. Appendix I--Proposed Optional Stack Flow Monitoring Methodology
    
        Background: EPA proposed to add an F-factor/fuel flow method in 
    Appendix I to part 75 as an excepted method to measure volumetric flow 
    directly with a flow monitor. The Agency proposed this method based on 
    information provided by affected utilities, and based on the assumption 
    that the new excepted method would be used by a significant number of 
    units as a cost-effective option to a volumetric flow monitor. This 
    method would allow fuel flow measurement with a gas or oil flowmeter, 
    fuel sampling data, 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. However, adoption 
    of the proposed method would require the Agency to develop regulations 
    imposing additional reporting and recordkeeping requirements for those 
    units that used this option. This would also place a burden on software 
    vendors to develop software to allow for electronic data reporting of 
    the required data elements.
        Discussion: A few commenters stated generally that they supported 
    the Appendix I option, while two other commenters stated generally that 
    the method should be allowed for other types of units or simplified 
    (see Docket A-97-56, Items IV-D-9, 23, and 24, and IV-G-2 and -8). 
    However, utilities have submitted late comments that suggest that the 
    utilities (including those originally interested in an F-factor/fuel 
    flow method) are in fact unlikely to use the Appendix I option at this 
    time (see Docket A-97-56, Item IV-G-13). Based on a review of Acid Rain 
    program databases, only about 150 units affected by the Acid Rain 
    Program could potentially take advantage of this option. In contrast, 
    there are a significant number of units that implement the other 
    generally available excepted methods under Appendices D and E to Part 
    75 (currently, approximately 540 different units report using one or 
    both of these methods).
        As discussed above there would be substantial effort involved for 
    EPA, utilities and software vendors to implement a new generally 
    available option such as proposed Appendix I. As discussed in the 
    preamble to the proposed rule, the annual savings on a per unit basis 
    for Appendix I units are at most $10-15,000 over the measurement of 
    volumetric flow directly with a flow monitor. The actual cost savings 
    would be less because other provisions of today's rule revise flow 
    monitor quality assurance requirements and significantly reduce the 
    costs of using a flow monitor. Given the relatively small amount of 
    savings on a per unit basis, the indication that no units would use the 
    option at this time, and the significant burden on all interested 
    parties in implementing a generally available option in Appendix I, the 
    Agency has determined not to adopt Appendix I.
        However, if the owner or operator of a unit decides at some time in 
    the future to use this type of procedure for measuring flow, the 
    designated representative of the unit may petition the Agency under 
    Sec. 75.66 to use this type of procedure on a case-by-case basis. In 
    such a petition, the designated representative can reference the 
    information used to support the proposed Appendix I procedure (see 63 
    FR 28113-28115, May 21, 1998, for further details on the information 
    used to develop proposed Appendix I). The Agency will evaluate the 
    petition on the merits at that time.
    
    L. Subpart H--Clarifications to NOX Mass Monitoring 
    Requirements
    
        Background: By notice of proposed rulemaking (NPR, proposal, or 
    ``proposed SIP call'') (62 FR 60318, November 7, 1997) and by 
    supplemental notice (SNPR or supplemental proposal) (63 FR 25902, May 
    11, 1998), EPA proposed to find that NOX emissions from 
    sources in 22 states and the District of Columbia, will significantly 
    contribute to nonattainment of the 1-hour and 8-hour ozone National 
    Ambient Air Quality Standards (NAAQS), or will interfere with 
    maintenance of the 8-hour NAAQS, in one or more downwind states 
    throughout the eastern United States.
        In October, 1998 (63 FR 57356, October 27, 1998), EPA finalized the 
    proposed SIP call rulemaking. The final rule specified dates by which: 
    (1) the affected states must submit State Implementation Plan revisions 
    to reduce NOX emissions to eliminate the amounts of 
    NOX emissions that contribute significantly to 
    nonattainment, or that interfere with maintenance, downwind; and (2) 
    the affected sources must implement the measures chosen by the states 
    to achieve the required NOX emission reductions.
        The provisions of the October 27, 1998 final rule allow each state 
    to determine the best way to achieve the necessary NOX 
    emission reductions. Consistent with the Ozone Transport Assessment 
    Group's recommendation to achieve NOX emissions decreases 
    primarily from large stationary sources in a trading program, EPA 
    promulgated a model rule for the implementation of such a trading 
    program as 40 CFR part 96 (``Part 96'') in the October 27, 1998 
    rulemaking.
        If the states should choose to create a NOX mass trading 
    program and to adopt the provisions of the Part 96 model rule, 
    Sec. 96.70 requires the monitoring and reporting of NOX mass 
    emissions to be done in accordance with either: (1) Subpart H of 40 CFR 
    part 75, the Acid Rain CEM Rule (``Part 75''); or (2) for qualifying 
    low mass-emission units, Sec. 75.19 of Part 75. However, even if a 
    state should choose not to participate in such a trading program, the 
    October 27, 1998 rule still requires the monitoring provisions of 
    Subpart H to be used by
    
    [[Page 28582]]
    
    a core group of sources (large industrial boilers and turbines, and 
    large boilers and turbines used for the generation of electricity for 
    sale) if the NOX mass emission reduction program for that 
    state includes requirements to control such sources. To support these 
    NOX mass emission reduction programs and rulemakings, EPA 
    promulgated both Subpart H of Part 75 and the low mass emission unit 
    provisions in Sec. 75.19 of Part 75 as part of the October 27, 1998 
    rulemaking.
        In the November 7, 1997 proposed SIP Call rule, EPA would have 
    required the affected units in a Federal or state NOX mass 
    emission reduction program to report NOX emissions on a 
    year-round basis and also to quality assure the NOX emission 
    data in accordance with the provisions of Part 75 on a year-round 
    basis. However, in response to comments on the proposed rule, EPA 
    modified Subpart H of Part 75 so that states could choose to allow 
    sources that were not subject to the requirements of Title IV of the 
    Clean Air Act (the Acid Rain Program) to monitor and report either on a 
    year round basis or on an ozone season only basis. Therefore, the 
    October 27, 1998 final rule provides for the monitoring and reporting 
    of NOX mass emissions either on an annual basis or during 
    the ozone season, when this is allowed by the governing state or 
    Federal rule.
        If a state or Federal NOX mass emission reduction 
    program were to allow ``ozone season only'' monitoring and reporting, 
    there would be an issue related to data quality at the start of each 
    ozone season. To address this issue, in the October 27, 1998 final 
    rule, EPA included a provision in Sec. 75.74(c) of Subpart H, which 
    requires the continuous emission monitoring systems used to provide the 
    NOX mass emission data to be recertified prior to the start 
    of each ozone season.
        Although Subpart H was proposed on May 21, 1998 as part of the Acid 
    Rain CEM Rule revisions, it was finalized several months ahead of 
    today's rulemaking, in order to support the SIP call. In the preamble 
    to the October 27, 1998 final rule (63 FR 57467), EPA explained its 
    intention to, where possible, make the provisions of Subpart H 
    consistent with any other changes that EPA promulgated as a result of 
    the May 21, 1998 proposed revisions to Part 75. EPA has re-examined the 
    provisions of Subpart H within the context of today's final rulemaking. 
    The Agency has found that a few minor clarifications of the regulatory 
    language in Subpart H and the addition of one new paragraph are needed 
    for consistency with today's final rule. The textual clarifications 
    affect Secs. 75.70(f)(1)(iv), 75.71(b) and 75.71(d)(2). The new 
    paragraph is found at Sec. 75.70(g)(6). In addition to these minor 
    corrections, EPA has found that certain provisions in Sec. 75.74(c), 
    pertaining to sources that monitor and report data only in the ozone 
    season, are substantially inconsistent with sections of today's final 
    rule (particularly the new CEM data validation provisions). The Agency 
    has also found an instance in which the text of Sec. 75.74(c) is 
    internally inconsistent and a second instance in which a statement in 
    the October 27, 1998 preamble does not agree with the regulatory 
    language in Sec. 75.74(c). In view of these considerations, today's 
    rulemaking revises Sec. 75.74(c), in order to make Subpart H more 
    consistent with the rest of Part 75 and to resolve the apparent 
    discrepancies and inconsistencies in the text of Sec. 75.74(c).
        Discussion of Changes: As previously stated, Subpart H requires 
    owners or operators of sources that monitor and report only during the 
    ozone season to recertify their CEM systems prior to each ozone season. 
    EPA put this requirement in Subpart H because the Agency believes that 
    for sources which are not required to monitor and report on a year-
    round basis, substantial quality assurance testing of the CEMS prior to 
    the ozone season is essential to validate the emission data at the 
    beginning of the ozone season. However, in the light of today's 
    rulemaking, the use of the word ``recertification'' in Sec. 75.74(c) of 
    Subpart H is regarded as inaccurate and inappropriate and does not 
    properly communicate the Agency's intent. In Sec. 75.20(b) of today's 
    final rule, the term ``recertification'' has been carefully defined, so 
    that it is limited to major changes to a CEMS which may affect its 
    ability to accurately measure emissions. Since in most instances 
    sources will be testing existing CEMS that have not undergone major 
    changes, EPA believes that this is more consistent with either 
    diagnostic testing or on-going quality assurance testing rather than 
    recertification. Therefore, in today's final rule, all of the 
    references in Sec. 75.74 to ``recertification testing'' of CEMS prior 
    to the ozone season have been replaced with terms such as ``diagnostic 
    testing'' or ``quality assurance testing,'' which properly convey the 
    Agency's intent and de-couple this testing from the formal 
    administrative process associated with recertification events. Since 
    the required pre-ozone season testing is considered to be quality 
    assurance (QA) or diagnostic testing rather than a recertification, the 
    Agency must specify which QA tests are to be performed. Section 
    75.74(c) therefore lists the specific quality assurance tests that are 
    required prior to the ozone season. For all CEM systems, a relative 
    accuracy test audit (RATA) is required and for all gas monitors, a 
    linearity check is also required. After a required linearity check or 
    RATA is passed, Sec. 75.74(c) requires that daily calibration error 
    tests and (if applicable) flow monitor interference checks begin to be 
    performed. These daily assessments must then continue to be performed 
    until the end of the ozone season.
        Section 75.74(c)(5) of Subpart H, as promulgated on October 27, 
    1998, requires both the recording and reporting of hourly emission data 
    prior to the current ozone season in the time interval from the date 
    and hour that ``recertification'' testing of the CEM systems is 
    completed through the end of the ozone season. EPA believes that most 
    sources that choose this option would do the testing as close to the 
    ozone season as possible. However, there may be some instances in which 
    it would be difficult for a source to perform all of the testing in the 
    second quarter before the beginning of the ozone season. This means 
    that some sources for which the NOX emission data count for 
    compliance only during the ozone season would be required to submit 
    additional electronic quarterly reports outside the ozone season, if 
    they completed the pre-ozone season testing in the first or fourth 
    calendar quarter. In view of this, EPA has reconsidered the 
    implications of this extra reporting requirement and has concluded that 
    it will complicate program implementation. The Agency believes that 
    this complication is unnecessary. Therefore, in Sec. 75.74(c)(6) of 
    today's final rule, the Subpart H reporting provision for these sources 
    has been revised, so that only reporting of emission data in the ozone 
    season, from May 1 through September 30, is required. This means that 
    in the time period from the date and hour of completion of the required 
    pre-ozone season quality assurance testing of the CEM systems through 
    April 30 of the current year, the owner or operator is only required to 
    record and keep records of the hourly emission data on-site. The only 
    pre-ozone season data that must be reported are the results of daily 
    calibration error checks and flow monitor interference checks performed 
    in the time period from April 1 through April 30 and the results of any 
    linearity checks, RATAs, fuel flow meter tests and fuel sampling 
    performed outside of the ozone season for purposes of
    
    [[Page 28583]]
    
    compliance with Subpart H. This will provide the regulatory agencies 
    with added assurance that the CEMS data are quality-assured at the 
    start of the ozone season and will enable the agencies to have a 
    limited pre-ozone season electronic auditing capability. The 
    requirement to report the results of the daily assessments for the 
    month of April is not considered burdensome because April is in the 
    second calendar quarter, which is one of the two reporting quarters for 
    the affected sources. In fact, some affected sources may prefer to 
    report data for April, because it may be easier to generate an 
    electronic quarterly report for the entire second calendar quarter, 
    rather than just for the months of May and June. Therefore, 
    Sec. 75.74(c)(6) of today's final rule gives the owner or operator the 
    option to report unit operating data and emission data for the month of 
    April.
        In reviewing the missing data provisions of Subpart H, EPA found a 
    discrepancy between the Agency's stated intent in the preamble to the 
    October 27, 1998 final rule and the regulatory language in 
    Sec. 75.74(c)(6)(i). The preamble states that ``[h]istorical lookback 
    periods for missing data only need to include data from the ozone 
    season'' (63 FR 57483, October 27, 1998). However, the rule language in 
    Sec. 75.74(c)(6)(i) does not state this explicitly, and could be 
    misinterpreted. The rule language states that all ``quality assured 
    data, in accordance with paragraph (c)(2) or (c)(3) of this section'' 
    are to be used for missing data purposes. This could be interpreted as 
    meaning that the data recorded outside the ozone season, in the time 
    period between completion of the pre-ozone season quality assurance 
    testing of the CEM systems and May 1, are to be included in the missing 
    data lookback periods. This is not what EPA intends; rather, the 
    statement cited above from the October 27, 1998 preamble accurately 
    reflects the Agency's position. Therefore, Sec. 75.74(c)(7) of today's 
    rule clearly states that for purposes of missing data substitution, 
    only data recorded during the ozone season will be used for the 
    historical missing data lookback periods.
        Finally, EPA has examined the quality assurance provisions of 
    Subpart H in view of the many substantial changes to the quality 
    assurance and data validation provisions of Part 75 in today's 
    rulemaking. The Agency has concluded that, in light of the many changes 
    that have been made to Part 75, the general references in Subpart H to 
    the quality assurance provisions in Sec. 75.21 and appendix B to Part 
    75 and references to the data validation procedures in Sec. 75.20 could 
    be clarified to make the requirements easier to understand, 
    particularly for sources that report data only during the ozone season. 
    There are several reasons for this.
        First, sections 2.2.4 and 2.3.3 in appendix B of today's final rule 
    provide ``grace periods'' in which late or missed QA tests can be 
    completed. For linearity checks, the grace period is 168 unit operating 
    hours after the end of the quarter in which the test is due. For RATAs, 
    the grace period is 720 unit operating hours after the end of the 
    quarter in which the RATA is due. Because the grace periods in Part 75 
    are in terms of unit operating hours, they can sometimes extend for 
    more than one calendar quarter beyond the quarter in which the QA test 
    was due (particularly for infrequently-operated or seasonally-operated 
    units). Consequently, the Part 75 grace period provisions in appendix B 
    are considered to be inappropriate for sources that report emissions 
    data only during the ozone season. Without a complete record of unit 
    operation for each year, the regulatory agency will be unable to 
    determine whether the required QA tests have been completed within the 
    allotted grace period.
        Second, Sec. 75.20(b)(3) of today's final rule provides 
    ``conditional'' data validation procedures for CEMS recertifications. 
    These provisions allow a probationary period following a 
    recertification event, during which data from a CEMS are assigned a 
    ``conditionally valid'' status. Provided that all recertification tests 
    are passed within the probationary period, with no test failures, 
    Sec. 75.20(b)(3) allows the conditionally valid data to be reported as 
    quality-assured. Today's rule also allows these data validation 
    procedures to be used for routine linearity checks and RATAs, in cases 
    where significant repair, adjustment or reprogramming of the CEMS is 
    done prior to the QA test. The maximum allowable length of the 
    probationary period is 168 unit operating hours for a linearity check 
    and 720 unit operating hours for a RATA. Once again, because these 
    probationary periods are in terms of unit operating hours, they can 
    extend outside the current calendar quarter, into the next quarter and 
    possibly beyond the next quarter. Therefore, for sources that report 
    only during the ozone season, some restrictions must be placed on the 
    use of the conditional data validation procedures in Sec. 75.20(b)(3).
        In view of the above considerations, EPA has revised Subpart H to 
    make it clear which of the Part 75 QA and data validation provisions 
    are applicable to sources that report only in the ozone season and 
    which provisions are inapplicable. The Agency has replaced the general 
    references in Subpart H to the quality assurance provisions of 
    Sec. 75.21 and appendix B and the references to the provisions of 
    Sec. 75.20 with specific language that delineates the exact QA tests 
    required during each ozone season. Section 75.74(c)(3) of today's rule 
    also contains specific data validation provisions for sources that 
    report only during the ozone season. To the extent possible, these QA 
    and data validation provisions have been made the same as or similar to 
    the requirements for sources that report data on a year-round basis. 
    However, as necessary, special provisions have been added to 
    Sec. 75.74(c) to address the differences between year-round reporters 
    and sources that report only during the ozone season. EPA believes that 
    these revisions to Subpart H will help to achieve consistency in the 
    implementation of state and Federal NOX mass emission 
    reduction programs and will help to ensure the quality of the reported 
    data.
    
    IV. Administrative Requirements
    
    A. Public Docket
    
        EPA has established Docket A-97-35 for the regulations. The docket 
    is an organized and complete file of all the information submitted to, 
    or otherwise considered by, EPA in the development of today's final 
    rule. The principal purposes of the docket are: (1) to allow interested 
    parties a means to identify and locate documents so that they can 
    effectively participate in the rulemaking process; and (2) to serve as 
    the record in case of judicial review. The docket is available for 
    public inspection at EPA's Air Docket, which is listed under the 
    ADDRESSES section of this notice.
    
    B. Executive Order 12866
    
        Under Executive Order 12866 (58 FR 51735, October 4, 1993), the 
    Administrator must determine whether the regulatory action is 
    ``significant'' and therefore subject to Office of Management and 
    Budget (OMB) review and the requirements of the Executive Order. The 
    Order defines ``significant regulatory action'' as one that is likely 
    to result in a rule that may:
    
        (1) Have an annual effect on the economy of $100 million or more 
    or adversely affect in a material way the economy, a sector of the 
    economy, productivity, competition, jobs, the environment, public 
    health or safety, or State, local or tribal governments or 
    communities;
        (2) Create a serious inconsistency or otherwise interfere with 
    an action taken or planned by another agency;
    
    [[Page 28584]]
    
        (3) Materially alter the budgetary impact of entitlements, 
    grants, user fees, or loan programs or the rights and obligations of 
    recipients thereof; or
        (4) Raise novel legal or policy issues arising out of legal 
    mandates, the President's priorities, or the principles set forth in 
    the Executive Order.
    
        This rule is not expected to have an annual effect on the economy 
    of $100 million or more.
        Pursuant to the terms of Executive Order 12866, it has been 
    determined that this rule is a ``significant regulatory action'' due to 
    its policy implications. Therefore, the rule was submitted to OMB for 
    review. Any written comments from OMB and any EPA response to those 
    comments are included in the public docket for this proposal. The 
    docket is available for public inspection at EPA's Air Docket Section, 
    which is listed in the ADDRESSES portion of this preamble.
    
    C. Unfunded Mandates Reform Act
    
        Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub. 
    L. 104-4, establishes requirements for Federal agencies to assess the 
    effects of their regulatory actions on state, local, and tribal 
    governments and the private sector. Under section 202 of the UMRA, EPA 
    generally must prepare a written statement, including a cost-benefit 
    analysis, for proposed and final rules with ``Federal mandates'' that 
    may result in expenditures to state, local, and tribal governments, in 
    the aggregate, or to the private sector, of $100 million or more in any 
    one year. Section 205 of the UMRA generally requires that, before 
    promulgating rules for which a written statement is needed, EPA must 
    identify and consider a reasonable number of regulatory alternatives 
    and adopt the least costly, most cost-effective, or least burdensome 
    alternative that achieves the objectives of the rule. The provisions of 
    section 205 do not apply when they are inconsistent with applicable 
    law. Moreover, section 205 allows EPA to adopt an alternative other 
    than the least costly, most cost-effective, or least burdensome 
    alternative if the Administrator publishes with the final rule an 
    explanation why that alternative was not adopted. Before EPA 
    establishes any regulatory requirements that may significantly or 
    uniquely affect small governments, including tribal governments, it 
    must have developed under section 203 of the UMRA a small government 
    agency plan. The plan must provide for notifying potentially affected 
    small governments, enabling officials of affected small governments to 
    have meaningful and timely input in the development of EPA regulatory 
    proposals with significant Federal intergovernmental mandates, and 
    informing, educating, and advising small governments on compliance with 
    the regulatory requirements.
        This rule is not expected to result in expenditures of more than 
    $100 million in any one year and therefore is not subject to section 
    202 of the UMRA. Although the rule is not expected to significantly or 
    uniquely affect small governments, the Agency notified all potentially 
    affected small governments that own or operate units potentially 
    affected by the rule in order to assure that they had the opportunity 
    to have meaningful and timely input on the rule. EPA will continue to 
    use its outreach efforts related to part 75 implementation, including a 
    policy manual that is generally updated on a quarterly basis, to 
    inform, educate, and advise all potentially impacted small governments 
    about compliance with part 75.
        EPA is not directly establishing any regulatory requirements that 
    may significantly or uniquely affect small governments, including 
    tribal governments. Thus, EPA is not obligated to develop under section 
    203 of the UMRA a small government agency plan.
    
    D. Executive Order 12875
    
        Under Executive Order 12875, EPA may not issue a regulation that is 
    not required by statute and that creates a mandate upon a State, local 
    or tribal government, unless the Federal government provides the funds 
    necessary to pay the direct compliance costs incurred by those 
    governments, or EPA consults with those governments. If EPA complies by 
    consulting, Executive Order 12875 requires EPA to provide to the Office 
    of Management and Budget a description of the extent of EPA's prior 
    consultation with representatives of affected State, local and tribal 
    governments, the nature of their concerns, copies of any written 
    communications from the governments, and a statement supporting the 
    need to issue the regulation. In addition, Executive Order 12875 
    requires EPA to develop an effective process permitting elected 
    officials and other representatives of State, local and tribal 
    governments ``to provide meaningful and timely input in the development 
    of regulatory proposals containing significant unfunded mandates.''
        EPA has concluded that this rule will create a mandate on local and 
    tribal governments and that the Federal government will not provide the 
    funds necessary to pay the direct costs incurred by the local and 
    tribal governments in complying with the mandate. In developing this 
    rule, EPA consulted with local and tribal governments to enable them to 
    provide meaningful and timely input in the development of this rule. 
    Only local or tribal governments that own sources affected by Acid Rain 
    would be affected by this rulemaking. The governments that own an Acid 
    Rain affected source were contacted when the proposed rule was signed 
    and informed of their right to comment on the proposal. EPA received a 
    few comment letters from municipal utilities; these letters contained 
    support for many elements of the rule, as well as concerns with certain 
    provisions. The Agency has attempted to include changes to the proposed 
    rule revisions based on these and other comments wherever possible 
    consistent with the purpose and intent of the rule revisions, and to 
    the extent justified by the commenters. See section III of this 
    preamble and the response to comments document included in the docket 
    for this rulemaking for the Agency's responses to the specific comments 
    raised. EPA also notes generally that these sources already have to 
    comply with part 75. Today's rule adds more compliance flexibility and 
    may reduce the compliance costs for some of the sources owned by local 
    and tribal governments.
    
    E. Executive Order 13084
    
        Under Executive Order 13084, EPA may not issue a regulation that is 
    not required by statute, that significantly or uniquely affects the 
    communities of Indian tribal governments, and that imposes substantial 
    direct compliance costs on those communities, unless the Federal 
    government provides the funds necessary to pay the direct compliance 
    costs incurred by the tribal governments, or EPA consults with those 
    governments. If EPA complies by consulting, Executive Order 13084 
    requires EPA to provide the Office of Management and Budget, in a 
    separately identified section of the preamble to the rule, a 
    description of the extent of EPA's prior consultation with 
    representatives of affected tribal governments, a summary of the nature 
    of their concerns, and a statement supporting the need to issue the 
    regulation. In addition, Executive Order 13084 requires EPA to develop 
    an effective process permitting elected officials and other 
    representatives of Indian tribal governments ``to provide meaningful 
    and timely input in the development of regulatory policies on matters 
    that significantly or uniquely affect their communities.''
    
    [[Page 28585]]
    
        Today's rule does not significantly or uniquely affect the 
    communities of Indian tribal governments. Only tribal governments that 
    own sources affected by the Acid Rain Program are affected by this 
    rulemaking. As noted above in section IV.D. of this preamble, today's 
    rule adds compliance flexibility and may reduce compliance costs for 
    any tribal governments that own or operate affected sources. 
    Accordingly, the requirements of section 3(b) of Executive Order 13084 
    do not apply to this rule.
    
    F. Paperwork Reduction Act
    
        The information collection requirements in this rule have been 
    submitted for approval to the OMB under the Paperwork Reduction Act, 44 
    U.S.C. 3501, et seq. An Information Collection Request (ICR) document 
    has been prepared by EPA (ICR No. 1633.12), and a copy may be obtained 
    from Sandy Farmer, OPPE Regulatory Information Division; U.S. 
    Environmental Protection Agency (2137); 401 M Street, SW, Washington, 
    DC 20460, by calling (202) 260-2740, or via the Internet at 
    www.epa.gov/icr. The information requirements are not effective until 
    OMB approves them.
        Currently, all affected facilities are required to keep records and 
    submit electronic quarterly reports under the provisions of part 75. 
    The revisions to the rule include several new options for compliance 
    with part 75 which have been requested by owners or operators of 
    affected facilities. To implement these options, EPA will have to 
    modify the existing recordkeeping and reporting requirements. In some 
    circumstances, these changes will result in significant reductions in 
    the reporting and recordkeeping burdens or costs for some units (such 
    as low mass emissions units). However, these changes will require 
    modifications to the software used to generate electronic reports. In 
    addition, there will be some increased burden or costs for certain 
    units to fulfill the new quality assurance procedures contained in this 
    rule. Finally, several other technical revisions to the existing 
    reporting and recordkeeping requirements have been adopted to clarify 
    existing provisions or to facilitate reporting for other regulatory 
    programs in the context of Acid Rain Program reporting. Although these 
    one-time software changes will increase the short-term burdens on 
    sources under the Acid Rain Program, the changes should reduce a 
    source's overall long-term burden by streamlining the source's 
    reporting obligations under both the Acid Rain Program and other parts 
    of the Act.
        The average annual projected hour burden is 1,225,633, which is 
    based on an estimated average burden of approximately 421 hours per 
    response, quarterly reporting frequency, and an estimated 728 likely 
    respondents (on a per facility basis). The projected annual cost burden 
    resulting from the collection of information is $192,483,642, which 
    includes a total projected capital and start-up average annualized cost 
    of $92,131,857 (for monitoring equipment/software), total projected 
    fuel sampling and analysis average annual cost of $581,100, and a total 
    projected operation and maintenance average annual cost (which includes 
    purchase of testing contractor services) of $41,398,000. Burden means 
    the total time, effort, or financial resources expended by persons to 
    generate, maintain, retain, disclose, or provide information to or for 
    a Federal agency. This includes the time needed to review instructions; 
    develop, acquire, install, and utilize technology and systems for 
    purposes of collecting, validating, and verifying information, 
    processing and maintaining information, and disclosing and providing 
    information; adjust the existing ways to comply with any previously 
    applicable instructions and requirements; train personnel to be able to 
    respond to a collection of information; search data sources; complete 
    and review the collection of information; and transmit or otherwise 
    disclose the information.
        An agency may not conduct or sponsor and a person is not required 
    to respond to a collection of information, unless it displays a 
    currently valid OMB control number. The OMB control numbers for EPA's 
    regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
    
    G. Regulatory Flexibility
    
        The Regulatory Flexibility Act (RFA), 5 U.S.C. 601, et seq., 
    generally requires an agency to conduct a regulatory flexibility 
    analysis of any rule subject to notice and comment rulemaking 
    requirements unless the agency certifies that the rule will not have a 
    significant economic impact on a substantial number of small entities. 
    Small entities include small businesses, small not-for-profit 
    enterprises, and governmental jurisdictions. This rule will not have a 
    significant impact on a substantial number of small entities.
        Today's revisions to part 75 result in a net cost reduction to 
    facilities affected by the Acid Rain Program, including small entities. 
    Most importantly, the changes to Appendix D will significantly reduce 
    the cost of complying with part 75 for oil-and gas-fired units, many of 
    which are owned or operated by small entities.
        Accordingly, considering all of the above information, EPA 
    concludes that this rule will not have a significant economic impact on 
    a substantial number of small entities.
    
    H. Submission to Congress and the General Accounting Office
    
        The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
    Small Business Regulatory Enforcement Fairness Act of 1996, generally 
    provides that before a rule may take effect, the Agency promulgating 
    the rule must submit a rule report, which includes a copy of the rule, 
    to each House of Congress and to the Comptroller General of the United 
    States. EPA will submit a report containing this rule and other 
    required information to the U.S. Senate, the U.S. House of 
    Representatives, and the Comptroller General of the General Accounting 
    Office prior to publication of the rule in today's Federal Register. 
    This rule is not a ``major rule'' as defined by U.S.C. 804(2).
    
    I. Executive Order 13045
    
        This final rule is not subject to Executive Order 13045, entitled 
    ``Protection of Children from Environmental Health Risks and Safety 
    Risks'' (62 FR 19885, April 23, 1997), because it does not involve 
    decisions on environmental health risks or safety risks that may 
    disproportionately affect children.
    
    J. National Technology Transfer and Advancement Act
    
        Section 12(d) of National Technology Transfer and Advancement Act 
    of 1995 (``NTTAA''), Pub L. 104-113, section 12(d) (15 U.S.C. 272 
    note), directs EPA to use voluntary consensus standards in its 
    regulatory activities unless to do so would be inconsistent with 
    applicable law or otherwise impractical. Voluntary consensus standards 
    are technical standards (e.g., materials specifications, test methods, 
    sampling procedures, business practices, etc.) that are developed or 
    adopted by voluntary consensus standards bodies. The NTTAA requires EPA 
    to provide Congress, through OMB, explanations when the Agency decides 
    not to use available and applicable voluntary consensus standards.
        Part 75 already incorporates a number of voluntary consensus 
    standards. In addition, today's rule includes incorporation on two 
    voluntary consensus standards, in response to comments submitted on the 
    proposed part 75 rulemaking. First, ASTM D5373-93 ``Standard Methods 
    for
    
    [[Page 28586]]
    
    Instrumental Determination of Carbon, Hydrogen and Nitrogen in 
    laboratory samples of Coal and Coke.'' This standard is incorporated by 
    reference for use under section 2.1 of Appendix G to part 75. Second, 
    API Sections 2, 3 and 5 from Chapter 4 of the Manual of Petroleum 
    Standards, October 1988 edition. This standard is incorporated by 
    reference for use under section 2.1.5.1 of Appendix D to part 75.
        Consistent with the Agency's Performance Based Measurement System, 
    part 75 sets forth performance criteria that allow the use of 
    alternative methods to the ones set forth in part 75. The PBMS approach 
    is intended to be more flexible and cost effective for the regulated 
    community; it is also intended to encourage innovation in analytical 
    technology and improved data quality. The EPA is not precluding the use 
    of any method, whether it constitutes a voluntary consensus standard or 
    not, as long as it meets the performance criteria specified, however 
    any alternative methods must be approved in advance before they may be 
    used under part 75.
    
    List of Subjects
    
    40 CFR Part 72
    
        Environmental protection, Acid rain, Air pollution control, 
    Electric utilities, Nitrogen oxides, Sulfur oxides.
    
    40 CFR Part 75
    
        Environmental protection, Air pollution control, Carbon dioxide, 
    Continuous emission monitoring, Electric utilities, Incorporation by 
    reference, Nitrogen oxides, Reporting and recordkeeping, Sulfur 
    dioxide.
    
        Dated: April 1, 1999.
    Carol M. Browner,
    Administrator.
    
        For the reasons set out in the preamble, title 40 chapter I of the 
    Code of Federal Regulations is amended as follows:
    
    PART 72--PERMITS REGULATION
    
        1. The authority for part 72 continues to read as follows:
    
        Authority: 42 U.S.C. 7601 and 7651, et seq.
    
        2. Section 72.2 is amended by correcting the definition of ``diesel 
    fuel;'' by revising the definitions of ``calibration gas,'' ``coal-
    fired'' (introductory text only), ``gas-fired,'' ``natural gas,'' 
    ``pipeline natural gas,'' ``span,'' ``stationary gas turbine,'' and 
    ``zero air material;'' by adding, in alphabetical order, new 
    definitions for ``conditionally valid data,'' ``EPA protocol gas,'' 
    ``fuel flowmeter QA operating quarter,'' ``gas manufacturer's 
    intermediate standard,'' ``probationary calibration error test,'' ``QA 
    operating quarter,'' ``research gas mixture'' ``stack operating hour,'' 
    ``standard reference material-equivalent compressed gas primary 
    reference material (SRM-equivalent PRM),'' and ``very low sulfur 
    fuel;'' by revising paragraphs (1) introductory text, (1)(ii) and (2) 
    of the definition of ``oil-fired'' and paragraph (2) of the definition 
    of ``peaking unit;'' by adding a paragraph (3) to the definition of 
    ``peaking unit;'' and by removing the definition of ``protocol 1 gas'' 
    and to read as follows:
    
    
    Sec. 72.2  Definitions.
    
    * * * * *
        Calibration gas means:
        (1) A standard reference material;
        (2) A standard reference material-equivalent compressed gas primary 
    reference material;
        (3) A NIST traceable reference material;
        (4) NIST/EPA-approved certified reference materials;
        (5) A gas manufacturer's intermediate standard;
        (6) An EPA protocol gas;
        (7) Zero air material; or
        (8) A research gas mixture.
    * * * * *
        Coal-fired means the combustion of fuel consisting of coal or any 
    coal-derived fuel (except a coal-derived gaseous fuel that meets the 
    definition of ``very low sulfur fuel'' in this section), alone or in 
    combination with any other fuel, where:
    * * * * *
        Conditionally valid data means data from a continuous monitoring 
    system that are not quality assured, but which may become quality 
    assured if certain conditions are met. Examples of data that may 
    qualify as conditionally valid are: data recorded by an uncertified 
    monitoring system prior to its initial certification; or data recorded 
    by a certified monitoring system following a significant change to the 
    system that may affect its ability to accurately measure and record 
    emissions. A monitoring system must pass a probationary calibration 
    error test, in accordance with section 2.1.1 of appendix B to part 75 
    of this chapter, to initiate the conditionally valid data status. In 
    order for conditionally valid emission data to become quality assured, 
    one or more quality assurance tests or diagnostic tests must be passed 
    within a specified time period in accordance with Sec. 75.20(b)(3).
    * * * * *
        Diesel fuel means a low sulfur fuel oil of grades 1-D or 2-D, as 
    defined by the American Society for Testing and Materials standard ASTM 
    D975-91, ``Standard Specification for Diesel Fuel Oils,'' grades 1-GT 
    or 2-GT, as defined by ASTM D2880-90a, ``Standard Specification for Gas 
    Turbine Fuel Oils,'' or grades 1 or 2, as defined by ASTM D396-90a, 
    ``Standard Specification for Fuel Oils'' (incorporated by reference in 
    Sec. 72.13).
    * * * * *
        EPA protocol gas means a calibration gas mixture prepared and 
    analyzed according to section 2 of the ``EPA Traceability Protocol for 
    Assay and Certification of Gaseous Calibration Standards,'' September 
    1997, EPA-600/R-97/121 or such revised procedure as approved by the 
    Administrator.
    * * * * *
        Fuel flowmeter QA operating quarter means a unit operating quarter 
    in which the unit combusts the fuel measured by the fuel flowmeter for 
    at least 168 unit operating hours (as defined in this section) or more.
    * * * * *
        Gas-fired means:
        (1) For all purposes under the Acid Rain Program, except for part 
    75 of this chapter, the combustion of:
        (i) Natural gas or other gaseous fuel (including coal-derived 
    gaseous fuel), for at least 90.0 percent of the unit's average annual 
    heat input during the previous three calendar years and for at least 
    85.0 percent of the annual heat input in each of those calendar years; 
    and
        (ii) Any fuel, except coal or solid or liquid coal-derived fuel, 
    for the remaining heat input, if any.
        (2) For purposes of part 75 of this chapter, the combustion of:
        (i) Natural gas or other gaseous fuel (including coal-derived 
    gaseous fuel) for at least 90.0 percent of the unit's average annual 
    heat input during the previous three calendar years and for at least 
    85.0 percent of the annual heat input in each of those calendar years; 
    and
        (ii) Fuel oil, for the remaining heat input, if any.
        (3) For purposes of part 75 of this chapter, a unit may initially 
    qualify as gas-fired if the designated representative demonstrates to 
    the satisfaction of the Administrator that the requirements of 
    paragraph (2) of this definition are met, or will in the future be met, 
    through one of the following submissions:
        (i) For a unit for which a monitoring plan has not been submitted 
    under Sec. 75.62 of this chapter, the designated representative submits 
    either:
        (A) Fuel usage data for the unit for the three calendar years 
    immediately preceding the date of initial submission of the monitoring 
    plan for the unit under Sec. 75.62; or
    
    [[Page 28587]]
    
        (B) If a unit does not have fuel usage data for one or more of the 
    three calendar years immediately preceding the date of initial 
    submission of the monitoring plan for the unit under Sec. 75.62, the 
    unit's designated fuel usage; all available fuel usage data (including 
    the percentage of the unit's heat input derived from the combustion of 
    gaseous fuels), beginning with the date on which the unit commenced 
    commercial operation; and the unit's projected fuel usage.
        (ii) For a unit for which a monitoring plan has already been 
    submitted under Sec. 75.62, that has not qualified as gas-fired under 
    paragraph (3)(i) of this definition, and whose fuel usage changes, the 
    designated representative submits either:
        (A) Three calendar years of data following the change in the unit's 
    fuel usage, showing that no less than 90.0 percent of the unit's 
    average annual heat input during the previous three calendar years, and 
    no less than 85.0 percent of the unit's annual heat input during any 
    one of the previous three calendar years, is from the combustion of 
    gaseous fuels and the remaining heat input is from the combustion of 
    fuel oil; or
        (B) A minimum of 720 hours of unit operating data following the 
    change in the unit's fuel usage, showing that no less than 90.0 percent 
    of the unit's heat input is from the combustion of gaseous fuels and 
    the remaining heat input is from the combustion of fuel oil, and a 
    statement that this changed pattern of fuel usage is considered 
    permanent and is projected to continue for the foreseeable future.
        (iii) If a unit qualifies as gas-fired under paragraph (3)(i) or 
    (ii) of this definition, the unit is classified as gas-fired as of the 
    date of the submission under such paragraph.
        (4) For purposes of part 75 of this chapter, a unit that initially 
    qualifies as gas-fired under paragraph (3)(i) or (ii) of this 
    definition must meet the criteria in paragraph (2) of this definition 
    each year in order to continue to qualify as gas-fired. If such a unit 
    combusts only gaseous fuel and fuel oil but fails to meet such criteria 
    for a given year, the unit no longer qualifies as gas-fired starting 
    January 1 of the year after the first year for which the criteria are 
    not met. If such a unit combusts fuel other than gaseous fuel or fuel 
    oil and fails to meet such criteria in a given year, the unit no longer 
    qualifies as gas-fired starting the day after the first day for which 
    the criteria are not met. If a unit failing to meet the criteria in 
    paragraph (2) of this definition initially qualified as a gas-fired 
    unit under paragraph (3) of this definition, the unit may qualify as a 
    gas-fired unit for a subsequent year only if the designated 
    representative submits the data specified in paragraph (3)(ii)(A) of 
    this definition.
    * * * * *
        Gas manufacturer's intermediate standard (GMIS) means a compressed 
    gas calibration standard that has been assayed and certified by direct 
    comparison to a standard reference material (SRM), an SRM-equivalent 
    PRM, a NIST/EPA-approved certified reference material (CRM), or a NIST 
    traceable reference material (NTRM), in accordance with section 2.1.2.1 
    of the ``EPA Traceability Protocol for Assay and Certification of 
    Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
    * * * * *
        Natural gas means a naturally occurring fluid mixture of 
    hydrocarbons (e.g., methane, ethane, or propane) produced in geological 
    formations beneath the Earth's surface that maintains a gaseous state 
    at standard atmospheric temperature and pressure under ordinary 
    conditions. Natural gas contains 1.0 grain or less of hydrogen sulfide 
    per 100 standard cubic feet and the hydrogen sulfide constitutes more 
    than 50% (by weight) of the total sulfur in the gas fuel. Additionally, 
    natural gas must meet either be composed of at least 70% methane by 
    volume or have a gross calorific value between 950 and 1100 Btu per 
    standard cubic foot. Natural gas does not include the following gaseous 
    fuels: landfill gas, digester gas, refinery gas, sour gas, blast 
    furnace gas, coal-derived gas, producer gas, coke oven gas, or any 
    gaseous fuel produced in a process which might result in highly 
    variable sulfur content or heating value.
    * * * * *
        Oil-fired means:
        (1) For all purposes under the Acid Rain Program, except part 75 of 
    this chapter, the combustion of:
        (i) * * *
        (ii) Any solid, liquid or gaseous fuel (including coal-derived 
    gaseous fuel), other than coal or any other coal-derived solid or 
    liquid fuel, for the remaining heat input, if any.
        (2) For purposes of part 75 of this chapter, combustion of only 
    fuel oil and gaseous fuels, provided that the unit involved does not 
    meet the definition of gas-fired.
    * * * * *
        Peaking unit means:
    * * * * *
        (2) For purposes of part 75 of this chapter, a unit may initially 
    qualify as a peaking unit if the designated representative demonstrates 
    to the satisfaction of the Administrator that the requirements of 
    paragraph (1) of this definition are met, or will in the future be met, 
    through one of the following submissions:
        (i) For a unit for which a monitoring plan has not been submitted 
    under Sec. 75.62, the designated representative submits either:
        (A) Capacity factor data for the unit for the three calendar years 
    immediately preceding the date of initial submission of the monitoring 
    plan for the unit under Sec. 75.62; or
        (B) If a unit does not have capacity factor data for one or more of 
    the three calendar years immediately preceding the date of initial 
    submission of the monitoring plan for the unit under Sec. 75.62, all 
    available capacity factor data, beginning with the date on which the 
    unit commenced commercial operation; and projected capacity factor 
    data.
        (ii) For a unit for which a monitoring plan has already been 
    submitted under Sec. 75.62, that has not qualified as a peaking unit 
    under paragraph (2)(i) of this definition, and where capacity factor 
    changes, the designated representative submits either:
        (A) Three calendar years of data following the change in the unit's 
    capacity factor showing an average capacity factor of no more than 10.0 
    percent during the three previous calendar years and a capacity factor 
    of no more than 20.0 percent in each of those calendar years; or
        (B) One calendar year of data following the change in the unit's 
    capacity factor showing a capacity factor of no more than 10.0 percent 
    and a statement that this changed pattern of operation resulting in a 
    capacity factor less than 10.0 percent is considered permanent and is 
    projected to continue for the foreseeable future.
        (3) For purposes of part 75 of this chapter, a unit that initially 
    qualifies as a peaking unit must meet the criteria in paragraph (1) of 
    this definition each year in order to continue to qualify as a peaking 
    unit. If such a unit fails to meet such criteria for a given year, the 
    unit no longer qualifies as a peaking unit starting January 1 of the 
    year after the year for which the criteria are not met. If a unit 
    failing to meet the criteria in paragraph (1) of this definition 
    initially qualified as a peaking unit under paragraph (2) of this 
    definition, the unit may qualify as a peaking unit for a subsequent 
    year only if the designated representative submits the data specified 
    in paragraph (2)(ii)(A) of this definition.
    * * * * *
        Pipeline natural gas means natural gas, as defined in this section, 
    that is
    
    [[Page 28588]]
    
    provided by a supplier through a pipeline and that contains 0.3 grains 
    or less of hydrogen sulfide per 100 standard cubic feet and the 
    hydrogen sulfide in content of the gas constitutes at least 50% (by 
    weight) of the total sulfur in the fuel;
    * * * * *
        Probationary calibration error test means an on-line calibration 
    error test performed in accordance with section 2.1.1 of appendix B to 
    part 75 of this chapter that is used to initiate a conditionally valid 
    data period.
    * * * * *
        QA operating quarter means a calendar quarter in which there are at 
    least 168 unit operating hours (as defined in this section) or, for a 
    common stack or bypass stack, a calendar quarter in which there are at 
    least 168 stack operating hours (as defined in this section).
    * * * * *
        Research gas mixture (RGM) means a calibration gas mixture 
    developed by agreement of a requestor and NIST that NIST analyzes and 
    certifies as ``NIST traceable.'' RGMs may have concentrations different 
    from those of standard reference materials.
    * * * * *
        Span means the highest pollutant or diluent concentration or flow 
    rate that a monitor component is required to be capable of measuring 
    under part 75 of this chapter.
    * * * * *
        Stack operating hour means any hour (or fraction of an hour) during 
    which flue gases flow through a common stack or bypass stack.
    * * * * *
        Standard reference material-equivalent compressed gas primary 
    reference material (SRM-equivalent PRM) means those gas mixtures listed 
    in a declaration of equivalence in accordance with section 2.1.2 of the 
    ``EPA Traceability Protocol for Assay and Certification of Gaseous 
    Calibration Standards,'' September 1997, EPA-600/R-97/121.
    * * * * *
        Stationary gas turbine means a turbine that is not self-propelled 
    and that combusts natural gas, other gaseous fuel with a total sulfur 
    content no greater than the total sulfur content of natural gas, or 
    fuel oil in order to heat inlet combustion air and thereby turn a 
    turbine in addition to or instead of producing steam or heating water.
    * * * * *
        Very low sulfur fuel means either:
        (1) A fuel with a total sulfur content no greater than 0.05 percent 
    sulfur by weight;
        (2) Natural gas or pipeline natural gas, as defined in this 
    section; or
        (3) Any gaseous fuel with a total sulfur content no greater than 20 
    grains of sulfur per 100 standard cubic feet.
    * * * * *
        Zero air material means either:
        (1) A calibration gas certified by the gas vendor not to contain 
    concentrations of SO2, NOX, or total hydrocarbons 
    above 0.1 parts per million (ppm), a concentration of CO above 1 ppm, 
    or a concentration of CO2 above 400 ppm;
        (2) Ambient air conditioned and purified by a CEMS for which the 
    CEMS manufacturer or vendor certifies that the particular CEMS model 
    produces conditioned gas that does not contain concentrations of 
    SO2, NOX, or total hydrocarbons above 0.1 ppm, a 
    concentration of CO above 1 ppm, or a concentration of CO2 
    above 400 ppm;
        (3) For dilution-type CEMS, conditioned and purified ambient air 
    provided by a conditioning system concurrently supplying dilution air 
    to the CEMS; or
        (4) A multicomponent mixture certified by the supplier of the 
    mixture that the concentration of the component being zeroed is less 
    than or equal to the applicable concentration specified in paragraph 
    (1) of this definition, and that the mixture's other components do not 
    interfere with the CEM readings.
        3. Section 72.3 is amended by adding, in alphabetical order, new 
    acronyms for CEMS, kacfm, kscfh, NIST and RATA to read as follows:
    
    
    Sec. 72.3  Measurements, abbreviations, and acronyms.
    
    * * * * *
        CEMS--continuous emission monitoring system.
    * * * * *
        kacfm--thousands of cubic feet per minute at actual conditions.
        kscfh--thousands of cubic feet per hour at standard conditions.
    * * * * *
        NIST--National Institute of Standards and Technology.
    * * * * *
        RATA--relative accuracy test audit.
    * * * * *
    
    
    Sec. 72.6  [Amended]
    
        4. Section 72.6 is amended by removing from paragraph (b)(1) the 
    word ``operation'' and adding, in its place, the words ``commercial 
    operation.''
        5. Section 72.90 is amended by revising paragraph (c)(3) to read as 
    follows:
    
    
    Sec. 72.90  Annual compliance certification report.
    
    * * * * *
        (c) * * *
        (3) Whether all the emissions from the unit, or a group of units 
    (including the unit) using a common stack, were monitored or accounted 
    for through the missing data procedures and reported in the quarterly 
    monitoring reports, including whether conditionally valid data, as 
    defined in Sec. 72.2, were reported in the quarterly report. If 
    conditionally valid data were reported, the owner or operator shall 
    indicate whether the status of all conditionally valid data has been 
    resolved and all necessary quarterly report resubmissions have been 
    made.
    * * * * *
    
    PART 75--CONTINUOUS EMISSION MONITORING
    
        6. The authority citation for part 75 is revised to read as 
    follows:
    
        Authority: 42 U.S.C. 7601, 7651k, and 7651k note.
    
    Subpart A--General
    
        7. Section 75.4 is amended by revising the last sentence of 
    paragraph (a) introductory text, revising the first sentence of 
    paragraph (d) introductory text, revising paragraph (d)(1), adding a 
    new sentence to the beginning of paragraph (g) introductory text, and 
    adding a new paragraph (i) to read as follows:
    
    
    Sec. 75.4  Compliance dates.
    
        (a) * * * In accordance with Sec. 75.20, the owner or operator of 
    each existing affected unit shall ensure that all monitoring systems 
    required by this part for monitoring SO2, NOX, 
    CO2, opacity, moisture and volumetric flow are installed and 
    that all certification tests are completed no later than the following 
    dates (except as provided in paragraphs (d) through (i) of this 
    section):
    * * * * *
        (d) In accordance with Sec. 75.20, the owner or operator of an 
    existing unit that is shutdown and is not yet operating by the 
    applicable dates listed in paragraph (a) of this section, or an 
    existing unit which has been placed in long-term cold storage after 
    having previously reported emissions data in accordance with this part, 
    shall ensure that all monitoring systems required under this part for 
    monitoring of SO2, NOX, CO2, opacity, 
    and volumetric flow are installed and all certification tests are 
    completed no later than the earlier of 45 unit operating days or 180
    
    [[Page 28589]]
    
    calendar days after the date that the unit recommences commercial 
    operation of the affected unit, notice of which date shall be provided 
    under subpart G of this part. * * *
        (1) The maximum potential concentration of SO2, the 
    maximum potential NOX emission rate, as defined in section 
    2.1.2.1 of appendix A to this part, the maximum potential flow rate, as 
    defined in section 2.1.4.1 of appendix A to this part, or the maximum 
    potential CO2 concentration, as defined in section 2.1.3.1 
    of appendix A to this part;
    * * * * *
        (g) The provisions of this paragraph shall apply unless an owner or 
    operator is exempt from certifying a fuel flowmeter for use during 
    combustion of emergency fuel under section 2.1.4.3 of appendix D to 
    this part, in which circumstance the provisions of section 2.1.4.3 of 
    appendix D shall apply.
        * * *
    * * * * *
        (i) In accordance with Sec. 75.20, the owner or operator of each 
    affected unit at which 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, 
    heat input, or NOX mass emissions for units in a 
    NOX mass reduction program, shall ensure that the continuous 
    moisture monitoring system required by this part is installed and that 
    all applicable initial certification tests required under 
    Sec. 75.20(c)(5), (c)(6), or (c)(7) for the continuous moisture 
    monitoring system are completed no later than the following dates:
        (1) April 1, 2000, for a unit that is existing and has commenced 
    commercial operation by January 2, 2000; or
        (2) For a new affected unit which has not commenced commercial 
    operation by January 2, 2000, no later than 90 days after the date the 
    unit commences commercial operation; or
        (3) For an existing unit that is shutdown and is not yet operating 
    by April 1, 2000, no later than the earlier of 45 unit operating days 
    or 180 calendar days after the date that the unit recommences 
    commercial operation.
        8. Section 75.5 is amended by revising paragraphs (b), (d), and 
    (f)(2) to read as follows:
    
    
    Sec. 75.5  Prohibitions.
    
    * * * * *
        (b) No owner or operator of an affected unit shall operate the unit 
    without complying with the requirements of Secs. 75.2 through 75.75 and 
    appendices A through G to this part.
    * * * * *
        (d) No owner or operator of an affected unit shall operate the unit 
    so as to discharge, or allow to be discharged, emissions of 
    SO2, NOX or CO2 to the atmosphere 
    without accounting for all such emissions in accordance with the 
    provisions of Secs. 75.10 through 75.19.
    * * * * *
        (f) * * *
        (2) The owner or operator is monitoring emissions from the unit 
    with another certified monitoring system or an excepted methodology 
    approved by the Administrator for use at that unit that provides 
    emissions data for the same pollutant or parameter as the retired or 
    discontinued monitoring system; or
    * * * * *
        9. Section 75.6 is amended by revising paragraphs (a)(13), (a)(31), 
    (a)(38), (a)(39), (b), (c), (e)(1) and (e)(2); by redesignating 
    paragraph (a)(40) as paragraph (a)(41); and by adding new paragraphs 
    (a)(40) and (f)(3) to read as follows:
    
    
    Sec. 75.6  Incorporation by reference.
    
    * * * * *
        (a) * * *
        (13) ASTM D1826-88, Standard Test Method for Calorific (Heating) 
    Value of Gases in Natural Gas Range by Continuous Recording 
    Calorimeter, for appendices D and F to this part.
    * * * * *
        (31) ASTM D3588-91, Standard Practice for Calculating Heat Value, 
    Compressibility Factor, and Relative Density (Specific Gravity) of 
    Gaseous Fuels, for appendices D and F to this part.
    * * * * *
        (38) ASTM D4891-89, Standard Test Method for Heating Value of Gases 
    in Natural Gas Range by Stoichiometric Combustion, for appendices D and 
    F to this part.
        (39) ASTM D5291-92, Standard Test Methods for Instrumental 
    Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products 
    and Lubricants, for appendices F and G to this part.
        (40) ASTM D5373-93, ``Standard Methods for Instrumental 
    Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
    of Coal and Coke,'' for appendix G to this part.
        (41) * * *
        (b) The following materials are available for purchase from the 
    American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 
    2350, Fairfield, NJ 07007-2350.
        (1) ASME MFC-3M-1989 with September 1990 Errata, Measurement of 
    Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, for appendix D 
    of this part.
        (2) ASME MFC-4M-1986 (Reaffirmed 1990), Measurement of Gas Flow by 
    Turbine Meters, for appendix D of this part.
        (3) ASME-MFC-5M-1985, Measurement of Liquid Flow in Closed Conduits 
    Using Transit-Time Ultrasonic Flowmeters, for appendix D of this part.
        (4) ASME MFC-6M-1987 with June 1987 Errata, Measurement of Fluid 
    Flow in Pipes Using Vortex Flow Meters, for appendix D of this part.
        (5) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
    Means of Critical Flow Venturi Nozzles, for appendix D of this part.
        (6) ASME MFC-9M-1988 with December 1989 Errata, Measurement of 
    Liquid Flow in Closed Conduits by Weighing Method, for appendix D of 
    this part.
        (c) The following materials are available for purchase from the 
    American National Standards Institute (ANSI), 11 W. 42nd Street, New 
    York NY 10036: ISO 8316: 1987(E) Measurement of Liquid Flow in Closed 
    Conduits-Method by Collection of the Liquid in a Volumetric Tank, for 
    appendices D and E of this part.
    * * * * *
        (e) * * *
        (1) American Gas Association Report No. 3: Orifice Metering of 
    Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General 
    Equations and Uncertainty Guidelines (October 1990 Edition), Part 2: 
    Specification and Installation Requirements (February 1991 Edition) and 
    Part 3: Natural Gas Applications (August 1992 Edition), for appendices 
    D and E of this part.
        (2) American Gas Association Transmission Measurement Committee 
    Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, 
    April, 1996), for appendix D to this part.
        (f) * * *
        (3) American Petroleum Institute (API) Section 2, ``Conventional 
    Pipe Provers,'' Section 3, ``Small Volume Provers,'' and Section 5, 
    ``Master-Meter Provers,'' from Chapter 4 of the Manual of Petroleum 
    Measurement Standards, October 1988 (Reaffirmed 1993), for appendix D 
    to this part.
        10. Section 75.7 is removed and reserved.
    
    
    Sec. 75.7  [Removed and Reserved]
    
        11. Section 75.8 is removed and reserved.
    
    
    Sec. 75.8  [Removed and Reserved]
    
    Subpart B --Monitoring Provisions
    
        12. Section 75.10 is amended by revising paragraphs (d)(3) and (f) 
    to read as follows:
    
    [[Page 28590]]
    
    Sec. 75.10  General operating requirements.
    
    * * * * *
        (d) * * *
        (3) Failure of an 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 emissions, moisture, or flow data for the missing hour by means 
    of the automated data acquisition and handling system, in accordance 
    with the applicable procedure for missing data substitution in subpart 
    D of this part.
    * * * * *
        (f) Minimum measurement capability requirement. The owner or 
    operator shall ensure that each continuous emission monitoring system 
    and component thereof is capable of accurately measuring, recording, 
    and reporting data, and shall not incur an exceedance of the full scale 
    range, except as provided in sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of 
    appendix A to this part.
    * * * * *
        13. Section 75.11 is amended by revising paragraphs (a), (b), 
    (d)(1), (d)(2), (e) introductory text, (e)(1), (e)(2), (e)(3) 
    introductory text, (e)(3)(ii), (e)(3)(iv), and by removing paragraph 
    (e)(4) to read as follows:
    
    
    Sec. 75.11  Specific provisions for monitoring 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 
    gaseous fuel is combusted in the unit, the owner or operator shall 
    comply with the applicable provisions of paragraph (e)(1), (e)(2), or 
    (e)(3) of this section.
        (b) Moisture correction. Where SO2 concentration is 
    measured on a dry basis, the owner or operator shall either:
        (1) Report the appropriate fuel-specific default moisture value for 
    each unit operating hour, selected from among the following: 3.0%, for 
    anthracite coal; 6.0% for bituminous coal; 8.0% for sub-bituminous 
    coal; 11.0% for lignite coal; 13.0% for wood; or
        (2) Install, operate, maintain, and quality assure a continuous 
    moisture monitoring system for measuring and recording the moisture 
    content of the flue gases, in order to correct the measured hourly 
    volumetric flow rates for moisture when calculating 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 
    psychometric chart (for saturated gas streams following wet scrubbers 
    or other demonstrably saturated gas streams, only). The moisture 
    monitoring system shall include as a component the automated data 
    acquisition and handling system (DAHS) for recording and reporting both 
    the raw data (e.g., hourly average wet-and dry-basis 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 and flow 
    monitoring system. If this option is selected, the owner or operator 
    shall comply with the applicable provisions in paragraph (e)(1), 
    (e)(2), or (e)(3) of this section during hours in which the unit 
    combusts only gaseous fuel;
        (2) By providing other information satisfactory to the 
    Administrator using the applicable procedures specified in appendix D 
    to this part for estimating hourly SO2 mass emissions; or
    * * * * *
        (e) Units with SO2 continuous emission monitoring 
    systems during the combustion of gaseous fuel. The owner or operator of 
    an affected unit with an SO2 continuous emission monitoring 
    system shall, during any hour in which the unit combusts only gaseous 
    fuel, determine SO2 emissions in accordance with paragraph 
    (e)(1), (e)(2) or (e)(3) of this section, as applicable.
        (1) If the gaseous fuel meets the definition of ``pipeline natural 
    gas'' or ``natural gas'' in Sec. 72.2 of this chapter, the owner or 
    operator may, in lieu of operating and recording data from the 
    SO2 monitoring system, determine SO2 emissions by 
    using Equation F-23 in appendix F to this part. Substitute into 
    Equation F-23 the hourly heat input, calculated using a certified flow 
    monitoring system and a certified diluent monitor, in conjunction with 
    the appropriate default SO2 emission rate from section 
    2.3.1.1 or 2.3.2.1.1 of appendix D to this part, and Equation D-5 in 
    appendix D to this part. When this option is chosen, the owner or 
    operator shall perform the necessary data acquisition and handling 
    system tests under Sec. 75.20(c), and shall meet all quality control 
    and quality assurance requirements in appendix B to this part for the 
    flow monitor and the diluent monitor.
        (2) The owner or operator may, in lieu of operating and recording 
    data from the SO2 monitoring system, determine 
    SO2 emissions by certifying an excepted monitoring system in 
    accordance with Sec. 75.20 and appendix D to this part, following the 
    applicable fuel sampling and analysis procedures in section 2.3 of 
    appendix D to this part, meeting the recordkeeping requirements of 
    Sec. 75.55 or Sec. 75.58, as applicable, and meeting all quality 
    control and quality assurance requirements for fuel flowmeters in 
    appendix D to this part. If this compliance option is selected, the 
    hourly unit heat input reported under Sec. 75.54(b)(5) or 
    Sec. 75.57(b)(5), as applicable, shall be determined using a certified 
    flow monitoring system and a certified diluent monitor, in accordance 
    with the procedures in section 5.2 of appendix F to this part. The flow 
    monitor and diluent monitor shall meet all of the applicable quality 
    control and quality assurance requirements of appendix B to this part.
        (3) The owner or operator may determine SO2 mass 
    emissions by using a certified SO2 continuous monitoring 
    system, in conjunction with a certified flow rate monitoring system. 
    However, if the unit burns any gaseous fuel that is very low sulfur 
    fuel (as defined in Sec. 72.2 of this chapter), then on and after April 
    1, 2000, the SO2 monitoring
    
    [[Page 28591]]
    
    system shall be subject to the following quality assurance provisions 
    when the very low sulfur fuel is combusted. Prior to April 1, 2000, the 
    owner or operator may comply with these provisions.
    * * * * *
        (ii) EPA recommends that the calibration response of the 
    SO2 monitoring system be adjusted, either automatically or 
    manually, in accordance with the procedures for routine calibration 
    adjustments in section 2.1.3 of appendix B to this part, whenever the 
    zero-level calibration response during a required daily calibration 
    error test exceeds the applicable performance specification of the 
    instrument in section 3.1 of appendix A to this part (i.e., 
    2.5 percent of the span value or 5 ppm, 
    whichever is less restrictive).
    * * * * *
        (iv) In accordance with the requirements of section 2.1.1.2 of 
    appendix A to this part, for units that sometimes burn gaseous fuel 
    that is very low sulfur fuel (as defined in Sec. 72.2 of this chapter) 
    and at other times burn higher sulfur fuel(s) such as coal or oil, a 
    second low-scale SO2 measurement range is not required when 
    the very low sulfur gaseous fuel is combusted. For units that burn only 
    gaseous fuel that is very low sulfur fuel and burn no other type(s) of 
    fuel(s), the owner or operator shall set the span of the SO2 
    monitoring system to a value no greater than 200 ppm.
    * * * * *
        14. Section 75.12 is amended by revising the first sentence in 
    paragraph (a); by redesignating existing paragraphs (b), (c), (d) and 
    (e) as paragraphs (c), (d), (e) and (f), respectively; by adding new 
    paragraph (b); and by revising the newly designated paragraph (c) to 
    read as follows:
    
    
    Sec. 75.12  Specific provisions for monitoring NOX emission 
    rate (NOX and diluent gas monitors).
    
        (a) Coal-fired units, gas-fired nonpeaking units or oil-fired 
    nonpeaking units. The owner or operator shall meet the general 
    operating requirements in Sec. 75.10 of this part for a NOX 
    continuous emission monitoring system for each affected coal-fired 
    unit, gas-fired nonpeaking unit, or oil-fired nonpeaking unit, except 
    as provided in paragraph (d) of this section, Sec. 75.17, and subpart E 
    of this part. * * *
        (b) Moisture correction. If a correction for the stack gas moisture 
    content is needed to properly calculate the NOX emission 
    rate in lb/mmBtu, e.g., if the NOX pollutant concentration 
    monitor measures on a different moisture basis from the diluent 
    monitor, the owner or operator shall either report a fuel-specific 
    default moisture value for each unit operating hour, as provided in 
    Sec. 75.11(b)(1), or shall install, operate, maintain, and quality 
    assure a continuous moisture monitoring system, as defined in 
    Sec. 75.11(b)(2). Notwithstanding this requirement, if Equation 19-3, 
    19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is 
    used to measure NOX emission rate, the following fuel-
    specific default moisture percentages shall be used in lieu of the 
    default values specified in Sec. 75.11(b)(1): 5.0%, for anthracite 
    coal; 8.0% for bituminous coal; 12.0% for sub-bituminous coal; 13.0% 
    for lignite coal; and 15.0% for wood.
        (c) Determination of NOX emission rate. The owner or 
    operator shall calculate hourly, quarterly, and annual NOX 
    emission rates (in lb/mmBtu) by combining the NOX 
    concentration (in ppm), diluent concentration (in percent O2 
    or CO2), and percent moisture (if applicable) measurements 
    according to the procedures in appendix F to this part.
    * * * * *
        15. Section 75.13 is amended by revising paragraphs (a) and (c) to 
    read as follows:
    
    
    Sec. 75.13  Specific provisions for monitoring 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 ``CO2 continuous emission monitoring system'' shall 
    apply rather than ``SO2 continuous emission monitoring 
    system,'' the phrase ``CO2 concentration'' shall apply 
    rather than ``SO2 concentration,'' the term ``maximum 
    potential concentration of CO2'' shall apply rather than 
    ``maximum potential concentration of SO2,'' and the phrase 
    ``CO2 mass emissions'' shall apply rather than 
    ``SO2 mass emissions.''
    * * * * *
        (c) Determination of CO2 mass emissions using an O2 
    monitor according to appendix F to this part. If the owner or operator 
    chooses to use the appendix F method, then the owner or operator may 
    determine hourly 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 specified in Sec. 75.11(b)(2), or a fuel-specific 
    default moisture percentage (if applicable), as defined in 
    Sec. 75.11(b)(1), and by using the methods and procedures specified in 
    appendix F to this part. For units using a common stack, multiple 
    stack, or bypass stack, the owner or operator may use the provisions of 
    Sec. 75.16, except that the phrase ``CO2 continuous emission 
    monitoring system'' shall apply rather than ``SO2 continuous 
    emission monitoring system,'' the term ``maximum potential 
    concentration of CO2'' shall apply rather than ``maximum 
    potential concentration of SO2,'' and the phrase 
    ``CO2 mass emissions'' shall apply rather than 
    ``SO2 mass emissions.''
    * * * * *
        16. Section 75.16 is amended by:
        a. Revising paragraphs (b)(2)(ii)(B), (b)(2)(ii)(D), (d)(2), and 
    (e)(1);
        b. Removing paragraphs (e)(2) and (e)(3);
        c. Redesignating existing paragraphs (e)(4) and (e)(5) as 
    paragraphs (e)(2) and (e)(3), respectively;
        d. Adding a new sentence to the end of the newly designated 
    paragraph (e)(3); and
        e. Adding a new paragraph (e)(4), to read as follows:
    
    
    Sec. 75.16  Special provisions for monitoring emissions from common, 
    bypass, and multiple stacks for 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; and 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
    * * * * *
    
    [[Page 28592]]
    
        (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 term ``heat input'' shall apply rather than ``SO2 mass 
    emissions'' or ``emissions'' and the phrase ``a diluent monitor and a 
    flow monitor'' shall apply rather than ``SO2 continuous 
    emission monitoring system and flow monitoring system.'' The applicable 
    equation in appendix F to this part shall be used to calculate the heat 
    input from the hourly flow rate, diluentmonitor measurements, and (if 
    the equation in appendix F requires a correction for the stack gas 
    moisture content) hourly moisture measurements. Notwithstanding the 
    options for combining heat input in paragraphs (a)(1)(ii), (a)(2)(ii), 
    (b)(1)(ii), and (b)(2)(ii) of this section, the owner or operator of an 
    affected unit with a diluent monitor and a flow monitor installed on a 
    common stack to determine the combined heat input at the common stack 
    shall also determine and report heat input to each individual unit.
    * * * * *
        (3) * * * If using either of these apportionment methods, the owner 
    or operator shall apportion according to section 5.6 of appendix F to 
    this part.
        (4) Notwithstanding paragraph (e)(1) of this section, any affected 
    unit that is using the procedures in this part to meet the monitoring 
    and reporting requirements of a State or federal NOX mass 
    emission reduction program must also meet the requirements for 
    monitoring heat input in Secs. 75.71, 75.72 and 75.75.
        17. Section 75.17 is amended by revising paragraph (a)(2)(i)(C) to 
    read as follows:
    
    
    Sec. 75.17  Specific provisions for monitoring emissions from common, 
    by-pass, and multiple stacks for NOX emission rate.
    
    * * * * *
        (a) * * *
        (2) * * *
        (i) * * *
        (C) Each unit's compliance with the applicable NOX 
    emission limit will be determined by a method satisfactory to the 
    Administrator for apportioning to each of the units the combined 
    NOX emission rate (in lb/mmBtu) measured in the common stack 
    and for reporting the NOX emission rate, as provided in a 
    petition submitted by the designated representative. The Administrator 
    may approve such demonstrated substitute methods for apportioning and 
    reporting NOX emission rate measured in a common stack 
    whenever the demonstration ensures that there is a complete and 
    accurate estimation of all emissions regulated under this part and, in 
    particular, that the emissions from any unit with a NOX 
    emission limitation are not underestimated.
    * * * * *
        18. Section 75.19 is amended by:
        a. Redesignating Tables 1, 2, 3, 4, 5 and 6 as LM-1, LM-2, LM-3, 
    LM-4, LM-5 and LM-6, respectively;
        b. Revising all references to Tables 1, 2, 3, 4, 5 and 6 in 
    Sec. 75.19 to LM-1, LM-2, LM-3, LM-4, LM-5, and LM-6, respectively;
        c. Revising newly designated Table LM-5;
        d. Correcting paragraph (c)(3)(ii)(D)(2) and the term 
    ``EFNOX'' that follows Eq. LM-10 in paragraph (c)(4)(ii)(A) 
    to read as follows:
    
    
    Sec. 75.19  Optional SO2, NOX, and CO2 
    emissions calculation for low mass emissions units.
    
    * * * * *
        (c) * * *
        (3) * * *
        (ii) * * *
        (D) * * *
        (2) Using the appropriate default specific gravity value in Table 
    LM-6 of this section.
    * * * * *
        (4) * * *
        (ii) * * *
        (A) * * *
        Where:
    * * * * *
        EFNNOX = Either the NOX emission factor from 
    Table LM-2 of this section or the fuel- and unit-specific 
    NOX emission rate determined under paragraph (c)(1)(iv) of 
    this section (lb/mmBtu).
    * * * * *
    
      Table LM-5.--Default Gross Calorific Values (GCVs) for Various Fuels
    ------------------------------------------------------------------------
                                                GCV for use in equation LM-2
                       Fuel                                or LM-3
    ------------------------------------------------------------------------
    Pipeline Natural Gas......................  1050 Btu/scf.
    Natural Gas...............................  1100 Btu/scf.
    Residual Oil..............................  19,700 Btu/lb or 167,500 Btu/
                                                 gallon.
    Diesel Fuel...............................  20,500 Btu/lb or 151,700 Btu/
                                                 gallon.
    ------------------------------------------------------------------------
    
    * * * * *
    
    Subpart C--Operation and Maintenance Requirements
    
        19. Section 75.20 is amended by:
        a. Revising the title of the section;
        b. Revising the titles of paragraphs (c), (d) and (g);
        c. Revising the introductory text of paragraphs (a), (c) and (g);
        d. Revising paragraphs (a)(1), (a)(3), (a)(4) introductory text, 
    (a)(4)(i), (a)(4)(ii), (a)(4)(iii), (a)(5)(i), (b), (c)(1), (c)(1)(i), 
    (c)(1)(ii), (c)(1)(iii), (d)(1), (d)(2), (g)(1), (g)(1)(i), (g)(2), 
    (g)(4), (g)(5) and (h)(2);
        e. Removing existing paragraph (c)(3);
        f. Redesignating existing paragraphs (c)(4), (c)(5), (c)(6), 
    (c)(7), and (c)(8) as paragraphs (c)(3), (c)(4), (c)(8), (c)(9), and 
    (c)(10), respectively;
        g. Revising newly redesignated paragraphs (c)(3), (c)(4) 
    introductory text, (c)(8) introductory text, (c)(8)(i), and (c)(10) 
    introductory text; and
        h. Adding new paragraphs (c)(5), (c)(6), (c)(7), (g)(6) and (g)(7), 
    to read as follows:
    
    [[Page 28593]]
    
    Sec. 75.20  Initial certification and recertification procedures.
    
        (a) Initial certification approval process. The owner or operator 
    shall ensure that each continuous emission or opacity monitoring system 
    required by this part, which includes the automated data acquisition 
    and handling system, and, where applicable, the 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. 75.11 through 75.18, where no continuous 
    emission or opacity monitoring system was previously installed, initial 
    certification is required.
        (1) Notification of initial certification test dates. The owner or 
    operator or designated representative shall submit a written notice of 
    the dates of initial certification testing at the unit as specified in 
    Sec. 75.61(a)(1).
    * * * * *
        (3) Provisional approval of certification (or recertification) 
    applications. Upon the successful completion of the required 
    certification (or recertification) procedures of this section for each 
    continuous emission or opacity monitoring system or component thereof, 
    continuous emission or opacity monitoring system or component thereof 
    shall be deemed provisionally certified (or recertified) for use under 
    the Acid Rain Program for a period not to exceed 120 days following 
    receipt by the Administrator of the complete certification (or 
    recertification) application under paragraph (a)(4) of this section. 
    Notwithstanding this paragraph, no continuous emission or opacity 
    monitor systems for a combustion source seeking to enter the Opt-in 
    Program in accordance with part 74 of this chapter shall be deemed 
    provisionally certified (or recertified) for use under the Acid Rain 
    Program. Data measured and recorded by a provisionally certified (or 
    recertified) continuous emission or opacity monitoring system or 
    component thereof, operated in accordance with the requirements of 
    appendix B to this part, will be considered valid quality-assured data 
    (retroactive to the date and time of provisional certification or 
    recertification), provided that the Administrator does not invalidate 
    the provisional certification (or recertification) by issuing a notice 
    of disapproval within 120 days of receipt by the Administrator of the 
    complete certification (or recertification) application. Note that when 
    the data validation procedures of paragraph (b)(3) of this section are 
    used for the initial certification (or recertification) of a continuous 
    emissions monitoring system, the date and time of provisional 
    certification (or recertification) of the CEMS may be earlier than the 
    date and time of completion of the required certification (or 
    recertification) tests.
        (4) Certification (or recertification) application formal approval 
    process. The Administrator will issue a notice of approval or 
    disapproval of the certification (or recertification) application to 
    the owner or operator within 120 days of receipt of the complete 
    certification (or recertification) application. In the event the 
    Administrator does not issue such a notice within 120 days of receipt, 
    each continuous emission or opacity monitoring system which meets the 
    performance requirements of this part and is included in the 
    certification (or recertification) application will be deemed certified 
    (or recertified) for use under the Acid Rain Program.
        (i) Approval notice. If the certification (or recertification) 
    application is complete and shows that each continuous emission or 
    opacity monitoring system meets the performance requirements of this 
    part, then the Administrator will issue a notice of approval of the 
    certification (or recertification) application within 120 days of 
    receipt.
        (ii) Incomplete application notice. A certification (or 
    recertification) application will be considered complete when all of 
    the applicable information required to be submitted in Sec. 75.63 has 
    been received by the Administrator, the EPA Regional Office, and the 
    appropriate State and/or local air pollution control agency. If the 
    certification (or recertification) application is not complete, then 
    the Administrator will issue a notice of incompleteness that provides a 
    reasonable timeframe for the designated representative to submit the 
    additional information required to complete the certification (or 
    recertification) application. If the designated representative has not 
    complied with the notice of incompleteness by a specified due date, 
    then the Administrator may issue a notice of disapproval specified 
    under paragraph (a)(4)(iii) of this section. The 120-day review period 
    shall not begin prior to receipt of a complete application.
        (iii) Disapproval notice. If the certification (or recertification) 
    application shows that any continuous emission or opacity monitoring 
    system or component thereof does not meet the performance requirements 
    of this part, or if the certification (or recertification) application 
    is incomplete and the requirement for disapproval under paragraph 
    (a)(4)(ii) of this section has been met, the Administrator shall issue 
    a written notice of disapproval of the certification (or 
    recertification) application within 120 days of receipt. By issuing the 
    notice of disapproval, the provisional certification (or 
    recertification) is invalidated by the Administrator, and the data 
    measured and recorded by each uncertified continuous emission or 
    opacity monitoring system or component thereof shall not be considered 
    valid quality-assured data as follows: from the hour of the 
    probationary calibration error test that began the initial 
    certification (or recertification) test period (if the data validation 
    procedures of paragraph (b)(3) of this section were used to 
    retrospectively validate data); or from the date and time of completion 
    of the invalid certification or recertification tests (if the data 
    validation procedures of paragraph (b)(3) of this section were not 
    used), until the date and time that the owner or operator completes 
    subsequently approved initial certification or recertification tests. 
    The owner or operator shall follow the procedures for loss of initial 
    certification in paragraph (a)(5) of this section for each continuous 
    emission or opacity monitoring system or component thereof which is 
    disapproved for initial certification. For each disapproved 
    recertification, the owner or operator shall follow the procedures of 
    paragraph (b)(5) of this section.
    * * * * *
        (5) * * *
        (i) Until such time, date, and hour as the continuous emission 
    monitoring system or component thereof can be adjusted, repaired, or 
    replaced and certification tests successfully completed, the owner or 
    operator shall substitute the following values, as applicable, for each 
    hour of unit operation during the period of invalid data specified in 
    paragraph (a)(4)(iii) of this section or in Sec. 75.21: the maximum 
    potential concentration of 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 in lb/mmBtu; the maximum potential concentration of
    
    [[Page 28594]]
    
    NOX, as defined in section 2.1.2.1 of appendix A to this 
    part, to report NOX emissions in ppm (when a NOX 
    concentration monitoring system is used to determine NOX 
    mass emissions, as defined under Sec. 75.71(a)(2)); the maximum 
    potential flow rate, as defined in section 2.1.4.1 of appendix A to 
    this part, to report volumetric flow; the maximum potential 
    concentration of CO2, as defined in section 2.1.3.1 of 
    appendix A to this part, to report CO2 concentration data; 
    and either the minimum potential moisture percentage, as defined in 
    section 2.1.5 of appendix A to this part or, if Equation 19-3, 19-4 or 
    19-8 in Method 19 in appendix A to part 60 of this chapter is used to 
    determine NOX emission rate, the maximum potential moisture 
    percentage, as defined in section 2.1.6 of appendix A to this part; and
    * * * * *
        (b) Recertification approval process. Whenever the owner or 
    operator makes a replacement, modification, or change in a certified 
    continuous emission monitoring system or continuous opacity monitoring 
    system that may significantly affect the ability of the system to 
    accurately measure or record the SO2 or CO2 
    concentration, stack gas volumetric flow rate, NOX emission 
    rate, percent moisture, or opacity, or to meet the requirements of 
    Sec. 75.21 or appendix B to this part, the owner or operator shall 
    recertify the continuous emission monitoring system or continuous 
    opacity monitoring system, according to the procedures in this 
    paragraph. Furthermore, whenever the owner or operator makes a 
    replacement, modification, or change to the flue gas handling system or 
    the unit operation that may significantly change the flow or 
    concentration profile, the owner or operator shall recertify the 
    monitoring system according to the procedures in this paragraph. 
    Examples of changes which require recertification include: replacement 
    of the analyzer; change in location or orientation of the sampling 
    probe or site; and complete replacement of an existing continuous 
    emission monitoring system or continuous opacity monitoring system. The 
    owner or operator shall recertify a continuous opacity monitoring 
    system whenever the monitor path length changes or as required by an 
    applicable State or local regulation or permit. Any change to a flow 
    monitor or gas monitoring system for which a RATA is not necessary 
    shall not be considered a recertification event. In addition, changing 
    the polynomial coefficients or K factor(s) of a flow monitor shall 
    require a 3-load RATA, but is not considered to be a recertification 
    event; however, records of the polynomial coefficients or K factor (s) 
    currently in use shall be maintained on-site in a format suitable for 
    inspection. Changing the coefficient or K factor(s) of a moisture 
    monitoring system shall require a RATA, but is not considered to be a 
    recertification event; however, records of the coefficient or K factor 
    (s) currently in use by the moisture monitoring system shall be 
    maintained on-site in a format suitable for inspection. In such cases, 
    any other tests that are necessary to ensure continued proper operation 
    of the monitoring system (e.g., 3-load flow RATAs following changes to 
    flow monitor polynomial coefficients, linearity checks, calibration 
    error tests, DAHS verifications, etc.) shall be performed as diagnostic 
    tests, rather than as recertification tests. The data validation 
    procedures in paragraph (b)(3) of this section shall be applied to 
    RATAs associated with changes to flow or moisture monitor coefficients, 
    and to linearity checks, 7-day calibration error tests, and cycle time 
    tests, when these are required as diagnostic tests. When the data 
    validation procedures of paragraph (b)(3) of this section are applied 
    in this manner, replace the word ``recertification'' with the word 
    ``diagnostic.''
        (1) Tests required. For all recertification testing, the owner or 
    operator shall complete all initial certification tests in paragraph 
    (c) of this section that are applicable to the monitoring system, 
    except as otherwise approved by the Administrator. For diagnostic 
    testing after changing the flow rate monitor polynomial coefficients, 
    the owner or operator shall complete a 3-level RATA. For diagnostic 
    testing after changing the K factor or mathematical algorithm of a 
    moisture monitoring system, the owner or operator shall complete a 
    RATA.
        (2) Notification of recertification test dates. The owner, 
    operator, or designated representative shall submit notice of testing 
    dates for recertification under this paragraph as specified in 
    Sec. 75.61(a)(1)(ii), unless all of the tests in paragraph (c) of this 
    section are not required for recertification, in which case the owner 
    or operator shall provide notice in accordance with the notice 
    provisions for initial certification testing in Sec. 75.61(a)(1)(i).
        (3) Recertification test period requirements and data validation. 
    The data validation provisions in paragraphs (b)(3)(i) through 
    (b)(3)(ix) of this section shall apply to all CEMS recertifications and 
    diagnostic testing. The provisions in paragraphs (b)(3)(ii) through 
    (b)(3)(ix) of this section may also be applied to initial 
    certifications (see sections 6.2(a), 6.3.1(a), 6.3.2(a), 6.4(a) and 
    6.5(f) of appendix A to this part) and may be used to supplement the 
    linearity check and RATA data validation procedures in sections 
    2.2.3(b) and 2.3.2(b) of appendix B to this part.
        (i) In the period extending from the hour of the replacement, 
    modification or change made to a monitoring system that triggers the 
    need to perform recertification test(s) of the CEMS to the hour of 
    successful completion of a probationary calibration error test 
    (according to paragraph (b)(3)(ii) of this section) following the 
    replacement, modification, or change to the CEMS, the owner or operator 
    shall either substitute for missing data, according to the standard 
    missing data procedures in Secs. 75.33 through 75.37, or report 
    emission data using a reference method or another monitoring system 
    that has been certified or approved for use under this part. 
    Notwithstanding this requirement, if the replacement, modification, or 
    change requiring recertification of the CEMS is such that the 
    historical data stream is no longer representative (e.g., where the 
    SO2 concentration and stack flow rate change significantly 
    after installation of a wet scrubber), the owner or operator shall 
    substitute for missing data as follows, in the period extending from 
    the hour of commencement of the replacement, modification, or change 
    requiring recertification of the CEMS to the hour of commencement of 
    the recertification test period: For a change that results in a 
    significantly higher concentration or flow rate, substitute maximum 
    potential values according to the procedures in paragraph (a)(5) of 
    this section; or for a change that results in a significantly lower 
    concentration or flow rate, substitute data using the standard missing 
    data procedures. The owner or operator shall then use the initial 
    missing data procedures in Sec. 75.31, beginning with the first hour of 
    quality assured data obtained with the recertified monitoring system, 
    unless otherwise provided by Sec. 75.34 for units with add-on emission 
    controls. The first hour of quality-assured data for the recertified 
    monitoring system shall be determined in accordance with paragraphs 
    (b)(3)(ii) through (b)(3)(ix) of this section.
        (ii) Once the modification or change to the CEMS has been completed 
    and all of the associated repairs, component replacements, adjustments, 
    linearization, and reprogramming of the CEMS have been completed, a 
    probationary calibration error test is required to establish the 
    beginning point of the recertification test period. In this
    
    [[Page 28595]]
    
    instance, the first successful calibration error test of the monitoring 
    system following completion of all necessary repairs, component 
    replacements, adjustments, linearization and reprogramming shall be the 
    probationary calibration error test. The probationary calibration error 
    test must be passed before any of the required recertification tests 
    are commenced.
        (iii) Beginning with the hour of commencement of a recertification 
    test period, emission data recorded by the CEMS are considered to be 
    conditionally valid, contingent upon the results of the subsequent 
    recertification tests.
        (iv) Each required recertification test shall be completed no later 
    than the following number of unit operating hours (or unit operating 
    days) after the probationary calibration error test that initiates the 
    test period:
        (A) For a linearity check and/or cycle time test, 168 consecutive 
    unit operating hours, as defined in Sec. 72.2 of this chapter or, for 
    CEMS installed on common stacks or bypass stacks, 168 consecutive stack 
    operating hours, as defined in Sec. 72.2 of this chapter;
        (B) For a RATA (whether normal-load or multiple-load), 720 
    consecutive unit operating hours, as defined in Sec. 72.2 of this 
    chapter or, for CEMS installed on common stacks or bypass stacks, 720 
    consecutive stack operating hours, as defined in Sec. 72.2 of this 
    chapter; and
        (C) For a 7-day calibration error test, 21 consecutive unit 
    operating days, as defined in Sec. 72.2 of this chapter.
        (v) All recertification tests shall be performed hands-off. No 
    adjustments to the calibration of the CEMS, other than the routine 
    calibration adjustments following daily calibration error tests as 
    described in section 2.1.3 of appendix B to this part, are permitted 
    during the recertification test period. Routine daily calibration error 
    tests shall be performed throughout the recertification test period, in 
    accordance with section 2.1.1 of appendix B to this part. The 
    additional calibration error test requirements in section 2.1.3 of 
    appendix B to this part shall also apply during the recertification 
    test period.
        (vi) If all of the required recertification tests and required 
    daily calibration error tests are successfully completed in succession 
    with no failures, and if each recertification test is completed within 
    the time period specified in paragraph (b)(3)(iv)(A), (B), or (C) of 
    this section, then all of the conditionally valid emission data 
    recorded by the CEMS shall be considered quality assured, from the hour 
    of commencement of the recertification test period until the hour of 
    completion of the required test(s).
        (vii) If a required recertification test is failed or aborted due 
    to a problem with the CEMS, or if a daily calibration error test is 
    failed during a recertification test period, data validation shall be 
    done as follows:
        (A) If any required recertification test is failed, it shall be 
    repeated. If any recertification test other than a 7-day calibration 
    error test is failed or aborted due to a problem with the CEMS, the 
    original recertification test period is ended, and a new 
    recertification test period must be commenced with a probationary 
    calibration error test. The tests that are required in the new 
    recertification test period will include any tests that were required 
    for the initial recertification event which were not successfully 
    completed and any recertification or diagnostic tests that are required 
    as a result of changes made to the monitoring system to correct the 
    problems that caused the failure of the recertification test. For a 2- 
    or 3-load flow RATA, if the relative accuracy test is passed at one or 
    more load levels, but is failed at a subsequent load level, provided 
    that the problem that caused the RATA failure is corrected without re-
    linearizing the instrument, the length of the new recertification test 
    period shall be equal to the number of unit operating hours remaining 
    in the original recertification test period, as of the hour of failure 
    of the RATA. However, if re-linearization of the flow monitor is 
    required after a flow RATA is failed at a particular load level, then a 
    subsequent 3-load RATA is required, and the new recertification test 
    period shall be 720 consecutive unit (or stack) operating hours. The 
    new recertification test sequence shall not be commenced until all 
    necessary maintenance activities, adjustments, linearizations, and 
    reprogramming of the CEMS have been completed;
        (B) If a linearity check, RATA, or cycle time test is failed or 
    aborted due to a problem with the CEMS, all conditionally valid 
    emission data recorded by the CEMS are invalidated, from the hour of 
    commencement of the recertification test period to the hour in which 
    the test is failed or aborted, except for the case in which a multiple-
    load flow RATA is passed at one or more load levels, failed at a 
    subsequent load level, and the problem that caused the RATA failure is 
    corrected without re-linearizing the instrument. In that case, data 
    invalidation shall be prospective, from the hour of failure of the RATA 
    until the commencement of the new recertification test period. Data 
    from the CEMS remain invalid until the hour in which a new 
    recertification test period is commenced, following corrective action, 
    and a probationary calibration error test is passed, at which time the 
    conditionally valid status of emission data from the CEMS begins again;
        (C) If a 7-day calibration error test is failed within the 
    recertification test period, previously-recorded conditionally valid 
    emission data from the CEMS are not invalidated. The conditionally 
    valid data status is unaffected, unless the calibration error on the 
    day of the failed 7-day calibration error test exceeds twice the 
    performance specification in section 3 of appendix A to this part, as 
    described in paragraph (b)(3)(vii)(D) of this section; and
        (D) If a daily calibration error test is failed during a 
    recertification test period (i.e., the results of the test exceed twice 
    the performance specification in section 3 of appendix A to this part), 
    the CEMS is out-of-control as of the hour in which the calibration 
    error test is failed. Emission data from the CEMS shall be invalidated 
    prospectively from the hour of the failed calibration error test until 
    the hour of completion of a subsequent successful calibration error 
    test following corrective action, at which time the conditionally valid 
    status of data from the monitoring system resumes. Failure to perform a 
    required daily calibration error test during a recertification test 
    period shall also cause data from the CEMS to be invalidated 
    prospectively, from the hour in which the calibration error test was 
    due until the hour of completion of a subsequent successful calibration 
    error test. Whenever a calibration error test is failed or missed 
    during a recertification test period, no further recertification tests 
    shall be performed until the required subsequent calibration error test 
    has been passed, re-establishing the conditionally valid status of data 
    from the monitoring system. If a calibration error test failure occurs 
    while a linearity check or RATA is still in progress, the linearity 
    check or RATA must be re-started.
        (E) Trial gas injections and trial RATA runs are permissible during 
    the recertification test period, prior to commencing a linearity check 
    or RATA, for the purpose of optimizing the performance of the CEMS. The 
    results of such gas injections and trial runs shall not affect the 
    status of previously-recorded conditionally valid data or result in 
    termination of the recertification test period, provided that the 
    following specifications and conditions are met:
        (1) For gas injections, the stable, ending monitor response is 
    within 5
    
    [[Page 28596]]
    
    percent or within 5 ppm of the tag value of the reference gas;
        (2) For RATA trial runs, the average reference method reading and 
    the average CEMS reading for the run differ by no more than 
    10% of the average reference method value or 15 
    ppm, or 1.5% H2O, or 0.02 lb/mmBtu 
    from the average reference method value, as applicable;
        (3) No adjustments to the calibration of the CEMS are made 
    following the trial injection(s) or run(s), other than the adjustments 
    permitted under section 2.1.3 of appendix B to this part; and
        (4) The CEMS is not repaired, re-linearized or reprogrammed (e.g., 
    changing flow monitor polynomial coefficients, linearity constants, or 
    K-factors) after the trial injection(s) or run(s).
        (F) If the results of any trial gas injection(s) or RATA run(s) are 
    outside the limits in paragraphs (b)(3)(vii)(E)(1) or (2) of this 
    section or if the CEMS is repaired, re-linearized or reprogrammed after 
    the trial injection(s) or run(s), the trial injection(s) or run(s) 
    shall be counted as a failed linearity check or RATA attempt. If this 
    occurs, follow the procedures pertaining to failed and aborted 
    recertification tests in paragraphs (b)(3)(vii)(A) and (b)(3)(vii)(B) 
    of this section.
        (viii) If any required recertification test is not completed within 
    its allotted time period, data validation shall be done as follows. For 
    a late linearity test, RATA, or cycle time test that is passed on the 
    first attempt, data from the monitoring system shall be invalidated 
    from the hour of expiration of the recertification test period until 
    the hour of completion of the late test. For a late 7-day calibration 
    error test, whether or not it is passed on the first attempt, data from 
    the monitoring system shall also be invalidated from the hour of 
    expiration of the recertification test period until the hour of 
    completion of the late test. For a late linearity test, RATA, or cycle 
    time test that is failed on the first attempt or aborted on the first 
    attempt due to a problem with the monitor, all conditionally valid data 
    from the monitoring system shall be considered invalid back to the hour 
    of the first probationary calibration error test which initiated the 
    recertification test period. Data from the monitoring system shall 
    remain invalid until the hour of successful completion of the late 
    recertification test and any additional recertification or diagnostic 
    tests that are required as a result of changes made to the monitoring 
    system to correct problems that caused failure of the late 
    recertification test.
        (ix) If any required recertification test of a monitoring system 
    has not been completed by the end of a calendar quarter and if data 
    contained in the quarterly report are conditionally valid pending the 
    results of test(s) to be completed in a subsequent quarter, the owner 
    or operator shall indicate this by means of a suitable conditionally 
    valid data flag in the electronic quarterly report for that quarter. 
    The owner or operator shall resubmit the report for that quarter if the 
    required recertification test is subsequently failed. In the 
    resubmitted report, the owner or operator shall use the appropriate 
    missing data routine in Sec. 75.31 or Sec. 75.33 to replace with 
    substitute data each hour of conditionally valid data that was 
    invalidated by the failed recertification test. Alternatively, if any 
    required recertification test is not completed by the end of a 
    particular calendar quarter but is completed no later than 30 days 
    after the end of that quarter (i.e., prior to the deadline for 
    submitting the quarterly report under Sec. 75.64), the test data and 
    results may be submitted with the earlier quarterly report even though 
    the test date(s) are from the next calendar quarter. In such instances, 
    if the recertification test(s) are passed in accordance with the 
    provisions of paragraph (b)(3) of this section, conditionally valid 
    data may be reported as quality-assured, in lieu of reporting a 
    conditional data flag. If the recertification test(s) is failed and if 
    conditionally valid data are replaced, as appropriate, with substitute 
    data, then neither the reporting of a conditional data flag nor 
    resubmission is required. In addition, if the owner or operator uses a 
    conditionally valid data flag in any of the four quarterly reports for 
    a given year, the owner or operator shall indicate the final status of 
    the conditionally valid data (i.e., resolved or unresolved) in the 
    annual compliance certification report required under Sec. 72.90 of 
    this chapter for that year. The Administrator may invalidate any 
    conditionally valid data that remains unresolved at the end of a 
    particular calendar year and may require the owner or operator to 
    resubmit one or more of the quarterly reports for that calendar year, 
    replacing the unresolved conditionally valid data with substitute data 
    values determined in accordance with Sec. 75.31 or Sec. 75.33, as 
    appropriate.
        (4) Recertification application. The designated representative 
    shall apply for recertification of each continuous emission or opacity 
    monitoring system used under the Acid Rain Program. The owner or 
    operator shall submit the recertification application in accordance 
    with Sec. 75.60, and each complete recertification application shall 
    include the information specified in Sec. 75.63.
        (5) Approval or disapproval of request for recertification. The 
    procedures for provisional certification in paragraph (a)(3) of this 
    section shall apply to recertification applications. The Administrator 
    will issue a notice of approval, disapproval, or incompleteness 
    according to the procedures in paragraph (a)(4) of this section. In the 
    event that a recertification application is disapproved, data from the 
    monitoring system are invalidated and the applicable missing data 
    procedures in Sec. 75.31 or Sec. 75.33 shall be used from the date and 
    hour of receipt of the disapproval notice back to the hour of the 
    probationary calibration error test that began the recertification test 
    period. Data from the monitoring system remain invalid until a 
    subsequent probationary calibration error test is passed, beginning a 
    new recertification test period. The owner or operator shall repeat all 
    recertification tests or other requirements, as indicated in the 
    Administrator's notice of disapproval, no later than 30 unit operating 
    days after the date of issuance of the notice of disapproval. The 
    designated representative shall submit a notification of the 
    recertification retest dates, as specified in Sec. 75.61(a)(1)(ii), and 
    shall submit a new recertification application according to the 
    procedures in paragraph (b)(4) of this section.
        (c) Initial certification and recertification procedures. Prior to 
    the deadline in Sec. 75.4, the owner or operator shall conduct initial 
    certification tests and in accordance with Sec. 75.63, the designated 
    representative shall submit an application to demonstrate that the 
    continuous emission or opacity monitoring system and components thereof 
    meet the specifications in appendix A to this part. The owner or 
    operator shall compare reference method values with output from the 
    automated data acquisition and handling system that is part of the 
    continuous emission monitoring system being tested. Except as specified 
    in paragraphs (b)(1), (d), and (e) of this section, the owner or 
    operator shall perform the following tests for initial certification or 
    recertification of continuous emission or opacity monitoring systems or 
    components according to the requirements of appendix A to this part:
        (1) For each SO2 pollutant concentration monitor, each 
    NOX concentration monitoring system used to determine 
    NOX mass emissions, as
    
    [[Page 28597]]
    
    defined under Sec. 75.71(a)(2), and for each NOX-diluent 
    continuous emission monitoring system:
        (i) A 7-day calibration error test, where, for the NOX-
    diluent continuous emission monitoring system, the test is performed 
    separately on the NOX pollutant concentration monitor and 
    the diluent gas monitor;
        (ii) A linearity check, where, for the NOX-diluent 
    continuous emission monitoring system, the test is performed separately 
    on the NOX pollutant concentration monitor and the diluent 
    gas monitor;
        (iii) A relative accuracy test audit. For the NOX-
    diluent continuous emission monitoring system, the RATA shall be done 
    on a system basis, in units of lb/mmBtu. For the NOX 
    concentration monitoring system, the RATA shall be done on a ppm basis.
    * * * * *
        (3) The initial certification test data from an 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 monitoring system to a reference method.
        (6) For each continuous moisture sensor: A RATA, directly comparing 
    the percent moisture measured by the monitor sensor to a reference 
    method.
        (7) For a continuous moisture monitoring system consisting of a 
    temperature sensor and a data acquisition and handling system (DAHS) 
    software component programmed with a moisture lookup table:
        (i) A demonstration that the correct moisture value for each hour 
    is being taken from the moisture lookup tables and applied to the 
    emission calculations. At a minimum, the demonstration shall be made at 
    three different temperatures covering the normal range of stack 
    temperatures from low to high.
        (ii) [Reserved]
        (8) The owner or operator shall ensure that initial certification 
    or recertification of a continuous opacity monitor for use under the 
    Acid Rain Program is conducted according to one of the following 
    procedures:
        (i) Performance of the tests for initial certification or 
    recertification, according to the requirements of Performance 
    Specification 1 in appendix B to part 60 of this chapter; or
    * * * * *
        (10) The owner or operator shall provide adequate facilities for 
    initial certification or recertification testing that include:
    * * * * *
        (d) Initial certification and recertification and quality assurance 
    procedures for optional backup continuous emission monitoring systems. 
    (1) Redundant backups. The owner or operator of an optional redundant 
    backup CEMS shall comply with all the requirements for initial 
    certification and recertification according to the procedures specified 
    in paragraphs (a), (b), and (c) of this section. The owner or operator 
    shall operate the redundant backup CEMS during all periods of unit 
    operation, except for periods of calibration, quality assurance, 
    maintenance, or repair. The owner or operator shall perform upon the 
    redundant backup CEMS all quality assurance and quality control 
    procedures specified in appendix B to this part, except that the daily 
    assessments in section 2.1 of appendix B to this part are optional for 
    days on which the redundant backup CEMS is not used to report emission 
    data under this part. For any day on which a redundant backup CEMS is 
    used to report emission data, the system must meet all of the 
    applicable daily assessment criteria in appendix B to this part.
        (2) Non-redundant backups. The owner or operator of an optional 
    non-redundant backup CEMS or like-kind replacement analyzer shall 
    comply with all of the following requirements for initial 
    certification, quality assurance, recertification, and data reporting:
        (i) Except as provided in paragraph (d)(2)(v) of this section, for 
    a regular non-redundant backup CEMS (i.e., a non-redundant backup CEMS 
    that has its own separate probe, sample interface, and analyzer), or a 
    non-redundant backup flow monitor, all of the tests in paragraph (c) of 
    this section are required for initial certification of the system, 
    except for the 7-day calibration error test.
        (ii) For a like-kind replacement non-redundant backup analyzer 
    (i.e., a non-redundant backup analyzer that uses the same probe and 
    sample interface as a primary monitoring system), no initial 
    certification of the analyzer is required. A non-redundant backup 
    analyzer, connected to the same probe and interface as a primary CEMS 
    in order to satisfy the dual span requirements of section 2.1.1.4 or 
    2.1.2.4 of appendix A to this part, shall be treated in the same manner 
    as a like-kind replacement analyzer.
        (iii) Each non-redundant backup CEMS or like-kind replacement 
    analyzer shall comply with the daily and quarterly quality assurance 
    and quality control requirements in appendix B to this part for each 
    day and quarter that the non-redundant backup CEMS or like-kind 
    replacement analyzer is used to report data, and shall meet the 
    additional linearity and calibration error test requirements specified 
    in this paragraph. The owner or operator shall ensure that each non-
    redundant backup CEMS or like-kind replacement analyzer passes a 
    linearity check (for pollutant concentration and diluent gas monitors) 
    or a calibration error test (for flow monitors) prior to each use for 
    recording and reporting emissions. For a primary NOX-diluent 
    or SO2-diluent CEMS consisting of the primary pollutant 
    analyzer and a like-kind replacement diluent analyzer (or vice-versa), 
    provided that the primary pollutant or diluent analyzer (as applicable) 
    is operating and is not out-of-control with respect to any of its 
    quality assurance requirements, only the like-kind replacement analyzer 
    must pass a linearity check before the system is used for data 
    reporting. When a non-redundant backup CEMS or like-kind replacement 
    analyzer is brought into service, prior to conducting the linearity 
    test, a probationary calibration error test (as described in paragraph 
    (b)(3)(ii) of this section), which will begin a period of conditionally 
    valid data, may be performed in order to allow the validation of data 
    retrospectively, as follows. Conditionally valid data from the CEMS or 
    like-kind replacement analyzer are validated back to the hour of 
    completion of the probationary calibration error test if the following 
    conditions are met: if no adjustments are made to the CEMS or like-kind
    
    [[Page 28598]]
    
    replacement analyzer other than the allowable calibration adjustments 
    specified in section 2.1.3 of appendix B to this part between the 
    probationary calibration error test and the successful completion of 
    the linearity test; and if the linearity test is passed within 168 unit 
    (or stack) operating hours of the probationary calibration error test. 
    However, if the linearity test is either failed, aborted due to a 
    problem with the CEMS or like-kind replacement analyzer, or is not 
    completed as required, then all of the conditionally valid data are 
    invalidated back to the hour of the probationary calibration error 
    test, and data from the non-redundant backup CEMS or from the primary 
    monitoring system of which the like-kind replacement analyzer is a part 
    remain invalid until the hour of completion of a successful linearity 
    test.
        (iv) When data are reported from a non-redundant backup CEMS or 
    like-kind replacement analyzer, the appropriate bias adjustment factor 
    shall be determined as follows:
        (A) For a regular non-redundant backup CEMS, as described in 
    paragraph (d)(2)(i) of this section, apply the bias adjustment factor 
    from the most recent RATA of the non-redundant backup system (even if 
    that RATA was done more than 12 months previously); or
        (B) When a like-kind replacement non-redundant backup analyzer is 
    used as a component of a primary CEMS (as described in paragraph 
    (d)(2)(ii) of this section), apply the primary monitoring system bias 
    adjustment factor.
        (v) For each parameter monitored (i.e., SO2, 
    CO2, NOX or flow rate) at each unit or stack, a 
    regular non-redundant backup CEMS may not be used to report data at 
    that affected unit or common stack for more than 720 hours in any one 
    calendar year, unless the CEMS passes a RATA at that unit or stack. For 
    each parameter monitored (SO2, CO2 or 
    NOX) at each unit or stack, the use of a like-kind 
    replacement non-redundant backup analyzer (or analyzers) is restricted 
    to 720 cumulative hours per calendar year, unless the owner or operator 
    redesignates the like-kind replacement analyzer(s) as component(s) of 
    regular non-redundant backup CEMS and each redesignated CEMS passes a 
    RATA at that unit or stack.
        (vi) For each regular non-redundant backup CEMS, no more than eight 
    successive calendar quarters shall elapse following the quarter in 
    which the last RATA of the CEMS was done at a particular unit or stack, 
    without performing a subsequent RATA. Otherwise, the CEMS may not be 
    used to report data from that unit or stack until the hour of 
    completion of a passing RATA at that location.
        (vii) Each regular non-redundant backup CEMS shall be represented 
    in the monitoring plan required under Sec. 75.53 as a separate 
    monitoring system, with unique system and component identification 
    numbers. When like-kind replacement non-redundant backup analyzers are 
    used, the owner or operator shall represent each like-kind replacement 
    analyzer used during a particular calendar quarter in the monitoring 
    plan required under Sec. 75.53 as a component of a primary monitoring 
    system. The owner or operator shall also assign a unique component 
    identification number to each like-kind replacement analyzer and 
    specify the manufacturer, model and serial number of the like-kind 
    replacement analyzer. This information may be added, deleted or updated 
    as necessary, from quarter to quarter. The owner or operator shall also 
    report data from the like-kind replacement analyzer using the system 
    identification number of the primary monitoring system and the assigned 
    component identification number of the like-kind replacement analyzer. 
    For the purposes of the electronic quarterly report required under 
    Sec. 75.64, the owner or operator may manually enter the appropriate 
    component identification number(s) of any like-kind replacement 
    analyzer(s) used for data reporting during the quarter.
        (viii) When reporting data from a certified regular non-redundant 
    backup CEMS, use a method of determination (MODC) code of ``02.'' When 
    reporting data from a like-kind replacement non-redundant backup 
    analyzer, use a MODC of ``17'' (see Table 4a under Sec. 75.57). For the 
    purposes of the electronic quarterly report required under Sec. 75.64, 
    the owner or operator may manually enter the required MODC of ``17'' 
    for a like-kind replacement analyzer.
    * * * * *
        (g) Initial certification and recertification procedures for 
    excepted monitoring systems under appendices D and E. The owner or 
    operator of a gas-fired unit, oil-fired unit, or diesel-fired unit 
    using the optional protocol under appendix D or E to this part shall 
    ensure that an excepted monitoring system under appendix D or E to this 
    part meets the applicable general operating requirements of Sec. 75.10, 
    the applicable requirements of appendices D and E to this part, and the 
    initial certification or recertification requirements of this 
    paragraph.
        (1) Initial certification and recertification testing. The owner or 
    operator shall use the following procedures for initial certification 
    and recertification of an excepted monitoring system under appendix D 
    or E to this part.
        (i) When the optional 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 
    section 2.1.5.1 of appendix D to this part.
    * * * * *
        (2) Initial certification and recertification testing notification. 
    The designated representative shall provide initial certification 
    testing notification and routine periodic retesting notification for an 
    excepted monitoring system under appendix E to this part as specified 
    in Sec. 75.61. The designated representative shall also submit 
    recertification testing notification, as specified in Sec. 75.61, for 
    quality assurance related NOX emission rate re-testing under 
    section 2.3 of appendix E to this part for an excepted monitoring 
    system under appendix E to this part. Initial certification testing 
    notification or periodic retesting notification is not required for 
    testing of a fuel flowmeter or for testing of an excepted monitoring 
    system under appendix D to this part.
    * * * * *
        (4) Initial certification or recertification application. The 
    designated representative shall submit an initial certification or 
    recertification application in accordance with Secs. 75.60 and 75.63.
        (5) Provisional approval of initial certification and 
    recertification applications. Upon the successful completion of the 
    required initial certification or recertification procedures for each 
    excepted monitoring system under appendix D or E to this part, each 
    excepted monitoring system under appendix D or E to this part shall be 
    deemed provisionally certified for use under the Acid Rain Program 
    during the period for the Administrator's review. The provisions for 
    the initial certification or recertification application formal 
    approval process in paragraph (a)(4) of this section shall apply, 
    except that the term ``excepted monitoring system'' shall apply rather 
    than ``continuous emission or opacity monitoring system'' and except 
    that the procedures for loss
    
    [[Page 28599]]
    
    of certification in paragraph (g)(7) of this section shall apply rather 
    than the procedures for loss of certification in either paragraph 
    (a)(5) or (b)(5) of this section. Data measured and recorded by a 
    provisionally certified excepted monitoring system under appendix D or 
    E to this part will be considered quality assured data from the date 
    and time of completion of the last initial certification or 
    recertification test, provided that the Administrator does not revoke 
    the provisional certification or recertification by issuing a notice of 
    disapproval in accordance with the provisions in paragraph (a)(4) or 
    (b)(5) of this section.
        (6) Recertification requirements. Recertification of an excepted 
    monitoring system under appendix D or E to this part is required for 
    any modification to the system or change in operation that could 
    significantly affect the ability of the system to accurately account 
    for emissions and for which the Administrator determines that an 
    accuracy test of the fuel flowmeter or a retest under appendix E to 
    this part to re-establish the NOX correlation curve is 
    required. Examples of such changes or modifications include fuel 
    flowmeter replacement, changes in unit configuration, or exceedance of 
    operating parameters.
        (7) Procedures for loss of certification or recertification for 
    excepted monitoring systems under appendices D and E to this part. In 
    the event that a certification or recertification application is 
    disapproved for an excepted monitoring system, data from the monitoring 
    system are invalidated, and the applicable missing data procedures in 
    section 2.4 of appendix D or section 2.5 of appendix E to this part 
    shall be used from the date and hour of receipt of such notice back to 
    the hour of the provisional certification. Data from the excepted 
    monitoring system remain invalid until all required tests are repeated 
    and the excepted monitoring system is again provisionally certified. 
    The owner or operator shall repeat all certification or recertification 
    tests or other requirements, as indicated in the Administrator's notice 
    of disapproval, no later than 30 unit operating days after the date of 
    issuance of the notice of disapproval. The designated representative 
    shall submit a notification of the certification or recertification 
    retest dates if required under paragraph (g)(2) of this section and 
    shall submit a new certification or recertification application 
    according to the procedures in paragraph (g)(4) of this section.
        (h) * * *
        (2) Certification application. The designated representative shall 
    submit a certification application in accordance with 
    Sec. 75.63(a)(1)(iii).
    * * * * *
        20. Section 75.21 is amended by:
        a. Revising paragraphs (a)(2), (a)(4), (a)(5), (a)(6), and (e);
        b. Redesignating existing paragraphs (a)(7) and (a)(8) as 
    paragraphs (a)(9) and (a)(10), respectively; and revising newly 
    designated paragraphs (a)(9) and (a)(10); and
        c. Adding new paragraphs (a)(7) and (a)(8) to read as follows:
    
    
    Sec. 75.21  Quality assurance and quality control requirements.
    
        (a) * * *
        (2) The owner or operator shall ensure that each non-redundant 
    backup CEMS meets the quality assurance requirements of Sec. 75.20(d) 
    for each day and quarter that the system is used to report data.
    * * * * *
        (4) The owner or operator of a unit with an 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 gaseous fuel is combusted in the unit if, during those days 
    and calendar quarters, SO2 emissions are determined in 
    accordance with Sec. 75.11(e)(1) or (e)(2). However, such assessments 
    are permissible, and if any daily calibration error test or linearity 
    test of the SO2 monitoring system is failed while the unit 
    is combusting only gaseous fuel, the SO2 monitoring system 
    shall be considered out-of-control. The length of the out-of-control 
    period shall be determined in accordance with the applicable procedures 
    in section 2.1.4 or 2.2.3 of appendix B to this part.
        (5) For a unit with an SO2 continuous monitoring system, 
    in which gaseous fuel that is very low sulfur fuel (as defined in 
    Sec. 72.2 of this chapter) is sometimes burned as a primary or backup 
    fuel and in which higher-sulfur fuel(s) such as oil or coal are, at 
    other times, burned as primary or backup fuel(s), the owner shall 
    perform the relative accuracy test audits of the 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 the very low sulfur 
    gaseous fuel is the only fuel being combusted.
        (6) If the designated representative certifies that a unit with an 
    SO2 monitoring system burns only very low sulfur fuel (as 
    defined in Sec. 72.2 of this chapter), the SO2 monitoring 
    system is exempted from the relative accuracy test audit requirements 
    in appendices A and B to this part.
        (7) If the designated representative certifies that a particular 
    unit with an SO2 monitoring system combusts primarily 
    fuel(s) that are very low sulfur fuel(s) (as defined in Sec. 72.2 of 
    this chapter), and combusts higher sulfur fuel (s) only as emergency 
    backup fuel(s) or for short-term testing, the SO2 monitoring 
    system shall be exempted from the RATA requirements of appendices A and 
    B to this part in any calendar year that the unit combusts the higher-
    sulfur fuel(s) for no more than 480 hours. If, in a particular calendar 
    year, the higher-sulfur fuel usage exceeds 480 hours, the owner or 
    operator shall perform a RATA of the SO2 monitor (while 
    combusting the higher-sulfur fuel) either by the end of the calendar 
    quarter in which the exceedance occurs or by the end of a 720 unit (or 
    stack) operating hour grace period (under section 2.3.3 of appendix B 
    to this part) following the quarter in which the exceedance occurs.
        (8) On and after April 1, 2000, the quality assurance provisions of 
    Secs. 75.11(e)(3)(i) through 75.11(e)(3)(iv) shall apply to all units 
    with SO2 monitoring systems during hours in which only very 
    low sulfur fuel (as defined in Sec. 72.2 of this chapter) is combusted 
    in the unit.
        (9) Provided that a unit with an SO2 monitoring system 
    is not exempted under paragraphs (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 very low sulfur fuel (as defined in 
    Sec. 72.2 of this chapter) shall be excluded in determining the quarter 
    in which the next relative accuracy test audit must be performed for 
    the 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, 
    in accordance with paragraph (a)(5) of this section, either by the end 
    of the eighth successive elapsed calendar quarter since the last RATA 
    or by the end of a 720 unit (or stack) operating hour grace period, as 
    provided in section 2.3.3 of appendix B to this part.
        (10) The owner or operator who, in accordance with 
    Sec. 75.11(e)(1), uses a certified flow monitor and a certified diluent 
    monitor and Equation F-23 in appendix F to this part to calculate 
    SO2
    
    [[Page 28600]]
    
    emissions during hours in which a unit combusts only natural gas or 
    pipeline natural gas (as defined in Sec. 72.2 of this chapter) shall 
    meet all quality control and quality assurance requirements in appendix 
    B to this part for the flow monitor and the diluent monitor.
    * * * * *
        (e) Consequences of audits. The owner or operator shall invalidate 
    data from a continuous emission monitoring system or continuous opacity 
    monitoring system upon failure of an audit under appendix B to this 
    part or any other audit, beginning with the unit operating hour of 
    completion of a failed audit as determined by the Administrator. The 
    owner or operator shall not use invalidated data for reporting either 
    emissions or heat input, nor for calculating monitor data availability.
        (1) Audit decertification. Whenever both an audit of a continuous 
    emission or opacity monitoring system (or component thereof, including 
    the data acquisition and handling system), of any excepted monitoring 
    system under appendix D or E to this part, or of any alternative 
    monitoring system under subpart E of this part, and a review of the 
    initial certification application or of a recertification application, 
    reveal that any system or component should not have been certified or 
    recertified because it did not meet a particular performance 
    specification or other requirement of this part, both at the time of 
    the initial certification or recertification application submission and 
    at the time of the audit, the Administrator will issue a notice of 
    disapproval of the certification status of such system or component. 
    For the purposes of this paragraph, an audit shall be either a field 
    audit of the facility or an audit of any information submitted to EPA 
    or the State agency regarding the facility. By issuing the notice of 
    disapproval, the certification status is revoked prospectively by the 
    Administrator. The data measured and recorded by each system shall not 
    be considered valid quality-assured data from the date of issuance of 
    the notification of the revoked certification status until the date and 
    time that the owner or operator completes subsequently approved initial 
    certification or recertification tests. The owner or operator shall 
    follow the procedures in Sec. 75.20(a)(5) for initial certification or 
    Sec. 75.20(b)(5) for recertification to replace, prospectively, all of 
    the invalid, non-quality-assured data for each disapproved system.
        (2) Out-of-control period. Whenever a continuous emission 
    monitoring system or continuous opacity monitoring system fails a 
    quality assurance audit or any another audit, the system is out-of-
    control. The owner or operator shall follow the procedures for out-of-
    control periods in Sec. 75.24.
        21. Section 75.22 is amended by adding a sentence to the end of the 
    introductory text of paragraph (a) and by revising paragraphs (a)(2), 
    (a)(4), (b)(4) and the introductory text of paragraph (c)(1) to read as 
    follows:
    
    
    Sec. 75.22  Reference test methods.
    
        (a) * * * Unless otherwise specified in this part, use only 
    codified versions of Methods 3A, 4, 6C and 7E revised as of July 1, 
    1995 or July 1, 1996 or July 1, 1997.
    * * * * *
        (2) Method 2 or its allowable alternatives, as provided in appendix 
    A to part 60 of this chapter, except for Methods 2B and 2E, are the 
    reference methods for determination of volumetric flow.
    * * * * *
        (4) Method 4 (either the standard procedure described in section 2 
    of the method or the moisture approximation procedure described in 
    section 3 of the method) shall be used to correct pollutant 
    concentrations from a dry basis to a wet basis (or from a wet basis to 
    a dry basis) and shall be used when relative accuracy test audits of 
    continuous moisture monitoring systems are conducted. For the purpose 
    of determining the stack gas molecular weight, however, the alternative 
    techniques for approximating the stack gas moisture content described 
    in section 1.2 of Method 4 may be used in lieu of the procedures in 
    sections 2 and 3 of the method.
    * * * * *
        (b) * * *
        (4) Method 2, or its allowable alternatives, as provided in 
    appendix A to part 60 of this chapter, except for Methods 2B and 2E, 
    for determining volumetric flow. The sample point(s) for reference 
    methods shall be located according to the provisions of section 6.5.5 
    of appendix A to this part.
        (c)(1) Instrumental EPA Reference Methods 3A, 6C, 7E, and 20 shall 
    be conducted using calibration gases as defined in section 5 of 
    appendix A to this part. Otherwise, performance tests shall be 
    conducted and data reduced in accordance with the test methods and 
    procedures of this part unless the Administrator:
    * * * * *
        22. Section 75.24 is amended by revising the section title and by 
    revising paragraph (d) to read as follows:
    
    
    Sec. 75.24  Out-of-control periods and adjustment for system bias.
    
    * * * * *
        (d) When the bias test indicates that an SO2 monitor, a 
    flow monitor, a NOX-diluent continuous emission monitoring 
    system or a NOX concentration monitoring system used to 
    determine NOX mass emissions, as defined in 
    Sec. 75.71(a)(2), is biased low (i.e., the arithmetic mean of the 
    differences between the reference method value and the monitor or 
    monitoring system measurements in a relative accuracy test audit exceed 
    the bias statistic in section 7 of appendix A to this part), the owner 
    or operator shall adjust the monitor or continuous emission monitoring 
    system to eliminate the cause of bias such that it passes the bias test 
    or calculate and use the bias adjustment factor as specified in section 
    2.3.4 of appendix B to this part.
    * * * * *
    
    Subpart D--Missing Data Substitution Procedures
    
        23. Section 75.30 is amended by revising paragraphs (a)(3) and 
    (a)(4), adding new paragraphs (a)(5) and (a)(6), revising the first 
    sentence of paragraph (b) and revising paragraph (d) to read as 
    follows:
    
    
    Sec. 75.30  General provisions.
    
        (a) * * *
        (3) A valid, quality-assured hour of NOX emission rate 
    data (in lb/mmBtu) has not been measured or recorded for an affected 
    unit, either by a certified NOX-diluent continuous emission 
    monitoring system or by an approved alternative monitoring system under 
    subpart E of this part; or
        (4) A valid, quality-assured hour of CO2 concentration 
    data (in percent CO2, or percent O2 converted to 
    percent CO2 using the procedures in appendix F to this part) 
    has not been measured and recorded for an affected unit, either by a 
    certified CO2 continuous emission monitoring system or by an 
    approved alternative monitoring method under subpart E of this part; or
        (5) A valid, quality-assured hour of NOX concentration 
    data (in ppm) has not been measured or recorded for an affected unit, 
    either by a certified NOX concentration monitoring system 
    used to determine NOX mass emissions, as defined in 
    Sec. 75.71(a)(2), or by an approved alternative monitoring system under 
    subpart E of this part; or
        (6) A valid, quality-assured hour of CO2 or 
    O2 concentration data (in percent CO2, or percent 
    O2) used for the determination of heat input has not been 
    measured and recorded for an
    
    [[Page 28601]]
    
    affected unit, either by a certified CO2 or O2 
    diluent monitor, or by an approved alternative monitoring method under 
    subpart E of this part.
        (b) However, the owner or operator shall have no need to provide 
    substitute data according to the missing data procedures in this 
    subpart if the owner or operator uses SO2, CO2, 
    NOX, or O2 concentration, flow rate, or 
    NOX emission rate data recorded from either a certified 
    redundant or regular non-redundant backup CEMS, a like-kind replacement 
    non-redundant backup analyzer, or a backup reference method monitoring 
    system when the certified primary monitor is not operating or is out-
    of-control. * * *
    * * * * *
        (d) The owner or operator shall comply with the applicable 
    provisions of this paragraph during hours in which a unit with an 
    SO2 continuous emission monitoring system combusts only 
    gaseous fuel.
        (1) Whenever a unit with an SO2 CEMS combusts only 
    natural gas or pipeline natural gas (as defined in Sec. 72.2 of this 
    chapter) and the owner or operator is using the procedures in section 7 
    of appendix F to this part to determine 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 CEMS combusts gaseous 
    fuel and the owner or operator uses the gas sampling and analysis and 
    fuel flow procedures in appendix D to this part to determine 
    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), 
    as applicable, 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 
    gaseous fuel 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, for hours 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 gaseous fuel shall be excluded from the definition of 
    ``monitor operating hour,'' ``quality assured monitor operating hour,'' 
    ``unit operating hour,'' and ``unit operating day,'' when 
    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 gaseous fuel 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 75.31 is revised to read as follows:
    
    
    Sec. 75.31  Initial missing data procedures.
    
        (a) During the first 720 quality-assured monitor operating hours 
    following initial certification (i.e., the date and time at which 
    quality assured data begins to be recorded by the CEMS) of an 
    SO2 pollutant concentration monitor, or a CO2 
    pollutant concentration monitor (or an O2 monitor used to 
    determine CO2 concentration in accordance with appendix F to 
    this part), or an O2 or CO2 diluent monitor used 
    to calculate heat input or a moisture monitoring system, and during the 
    first 2,160 quality-assured monitor operating hours following initial 
    certification of a flow monitor, or a NOX-diluent monitoring 
    system, or a NOX concentration monitoring system used to 
    determine NOX mass emissions, the owner or operator shall 
    provide substitute data required under this subpart according to the 
    procedures in paragraphs (b) and (c) of this section. The owner or 
    operator of a unit shall use these procedures for no longer than three 
    years (26,280 clock hours) following initial certification.
        (b) SO2, CO2, or O2 concentration 
    data and moisture data. For each hour of missing SO2 or 
    CO2 pollutant concentration data (including CO2 
    data converted from O2 data using the procedures in appendix 
    F of this part), or missing O2 or CO2 diluent 
    concentration data used to calculate heat input, or missing moisture 
    data, the owner or operator shall calculate the substitute data as 
    follows:
        (1) Whenever prior quality-assured data exist, the owner or 
    operator shall substitute, by means of the data acquisition and 
    handling system, for each hour of missing data, the average of the 
    hourly SO2, CO2 or O2 concentrations 
    or moisture percentages recorded by a certified monitor for the unit 
    operating hour immediately before and the unit operating hour 
    immediately after the missing data period.
        (2) Whenever no prior quality assured SO2, 
    CO2 or O2 concentration data or moisture data 
    exist, the owner or operator shall substitute, as applicable, for each 
    hour of missing data, the maximum potential SO2 
    concentration or the maximum potential CO2 concentration or 
    the minimum potential O2 concentration or (unless Equation 
    19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this 
    chapter is used to determine NOX emission rate) the minimum 
    potential moisture percentage, as specified, respectively, in sections 
    2.1.1.1, 2.1.3.1, 2.1.3.2 and 2.1.5 of appendix A to this part. If 
    Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of 
    this chapter is used to determine NOX emission rate, 
    substitute the maximum potential moisture percentage, as specified in 
    section 2.1.6 of appendix A to this part.
        (c) Volumetric flow and NOX emission rate or 
    NOX concentration data. For each hour of missing volumetric 
    flow rate data, NOX emission rate data or NOX 
    concentration data used to determine NOX mass emissions:
        (1) Whenever prior quality-assured data exist in the load range 
    corresponding to the operating load at the time the missing data period 
    occurred, the owner or operator shall substitute, by means of the 
    automated data acquisition and handling system, for each hour of 
    missing data, the average hourly flow rate or NOX emission 
    rate or NOX concentration recorded by a certified monitoring 
    system. The average flow rate (or NOX emission rate or 
    NOX concentration) shall be the arithmetic average of all 
    data in the corresponding load range as determined using the procedure 
    in appendix C to this part.
        (2) Whenever no prior quality-assured flow or NOX 
    emission rate or NOX concentration data exist for the 
    corresponding load range, the owner or operator shall substitute, for 
    each hour of missing data, the average hourly flow rate or the average 
    hourly NOX emission rate or NOX concentration at 
    the next higher level load range for which quality-assured data are 
    available.
    
    [[Page 28602]]
    
        (3) Whenever no prior quality assured flow rate or NOX 
    emission rate or NOX concentration data exist for the 
    corresponding load range, or any higher load range, the owner or 
    operator shall, as applicable, substitute, for each hour of missing 
    data, the maximum potential flow rate as specified in section 2.1.4.1 
    of appendix A to this part or shall substitute the maximum potential 
    NOX emission rate or the maximum potential NOX 
    concentration, as specified in section 2.1.2.1 of appendix A to this 
    part.
        25. Section 75.32 is amended by revising paragraph (a) introductory 
    text and revising the last sentence in paragraph (a)(3) to read as 
    follows:
    
    
    Sec. 75.32  Determination of monitor data availability for standard 
    missing data procedures.
    
        (a) Following initial certification (i.e., the date and time at 
    which quality assured data begins to be recorded by the CEMS), upon 
    completion of: the first 720 quality-assured monitor operating hours of 
    an SO2 pollutant concentration monitor, or a CO2 
    pollutant concentration monitor (or O2 monitor used to 
    determine CO2 concentration), or an O2 or 
    CO2 diluent monitor used to calculate heat input or a 
    moisture monitoring system; or the first 2,160 quality-assured monitor 
    operating hours of a flow monitor or a NOX-diluent 
    monitoring system or a NOX concentration monitoring system, 
    the owner or operator shall calculate and record, by means of the 
    automated data acquisition and handling system, the percent monitor 
    data availability for the SO2 pollutant concentration 
    monitor, the CO2 pollutant concentration monitor, the 
    O2 or CO2 diluent monitor used to calculate heat 
    input, the moisture monitoring system, the flow monitor, the 
    NOX-diluent monitoring system and the NOX 
    concentration monitoring system as follows:
    * * * * *
        (3) * * * The owner or operator of a unit with an 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 gaseous fuel from calculations of percent monitor 
    data availability for SO2 pollutant concentration monitors, 
    as provided in Sec. 75.30(d).
    * * * * *
        26. Section 75.33 is amended by revising the title of the section, 
    by revising paragraphs (a), (b)(3) and (c), and adding a new paragraph 
    (b)(4) to read as follows:
    
    
    Sec. 75.33  Standard missing data procedures for SO2, 
    NOX and flow rate.
    
        (a) Following initial certification (i.e., the date and time at 
    which quality assured data begins to be recorded by the CEMS) and upon 
    completion of the first 720 quality-assured monitor operating hours of 
    the SO2 pollutant concentration monitor or the first 2,160 
    quality assured monitor operating hours of the flow monitor, 
    NOX-diluent monitoring system or NOX 
    concentration monitoring system used to determine NOX mass 
    emissions, the owner or operator shall provide substitute data required 
    under this subpart according to the procedures in paragraphs (b) and 
    (c) of this section and depicted in Table 1 (SO2) and Table 
    2 of this sectioin (NOX, flow). The owner or operator of a 
    unit shall substitute for missing data using only quality-assured 
    monitor operating hours of data from the three years (26,280 clock 
    hours) prior to the date and time of the missing data period.
    
    Table 1.--Missing Data Procedure for SO2 CEMS, CO2 CEMS, Moisture CEMS and Diluent (CO2 or O2) Monitors for Heat
                                                   Input Determination
    ----------------------------------------------------------------------------------------------------------------
                         Trigger conditions                                      Calculation routines
    ----------------------------------------------------------------------------------------------------------------
       Monitor data availability     Duration (N) of CEMS outage
               (percent)                     (hours) \2\                       Method               Lookback period
    ----------------------------------------------------------------------------------------------------------------
    95 or more....................  N  24              Average........................  HB/HA.
                                    N > 24                        For SO2, CO2 and H2O**, the      .................
                                                                   greater of:                     HB/HA.
                                                                    Average......................  720 hours.*
                                                                    90th percentile..............
                                    ............................  For O2, and H2OX, the lesser     .................
                                                                   of:                             HB/HA.
                                                                    Average......................  720 hours.*
                                                                    10th percentile..............
    90 or more, but below 95......  N  8               Average........................  HB/HA.
                                    N > 8                         For SO2, CO2 and H2O**, the      .................
                                                                   greater of:                     HB/HA.
                                                                    Average......................  720 hours.*
                                                                    95th percentile..............
                                    ............................  For O2, and H2OX, the lesser     .................
                                                                   of:                             HB/HA.
                                                                    Average......................  720 hours.*
                                                                    5th percentile...............
    80 or more, but below 90......  N > 0                         For SO2, CO2 and H2O**,........  .................
                                                                    Maximum value \1\............  720 hours.*
                                    ............................  For O2, and H2OX:                .................
                                                                    Minimum value\1\.............  720 hours.*
    Below 80......................  N > 0                         Maximum potential concentration
                                                                   or % (for SO2, CO2 and H2O**)
                                                                   or
                                    ............................  Minimum potential concentration  None.
                                                                   or % (for O2, and H2OX).
    ----------------------------------------------------------------------------------------------------------------
    HB/HA = hour before and hour after the CEMS outage.
    * = Quality-assured, monitor operating hours, during unit operation.
    \1\ Where unit with add-on emission controls can demonstrate that the controls are operating properly, as
      provided in Sec.  75.34, the unit may, upon approval, use the maximum controlled emission rate from the
      previous 720 operating hours.
    \2\ During unit operating hours.
    X Use this algorithm for moisture except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60
      of this chapter is used for NOX emission rate.
    ** Use this algorithm for moisture only when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60
      of this chapter is used for NOX emission rate.
    
    
    [[Page 28603]]
    
    
                                Table 2.--Missing Data Procedure for NOX-Diluent CEMS, NOX Concentration CEMS and Flow Rate CEMS
    --------------------------------------------------------------------------------------------------------------------------------------------------------
                             Trigger conditions                                                          Calculation routines
    --------------------------------------------------------------------------------------------------------------------------------------------------------
         Monitor data availability         Duration (N) of CEMS outage
                 (percent)                          (hours) 2                            Method                      Lookback period          Load  ranges
    --------------------------------------------------------------------------------------------------------------------------------------------------------
    95 or more........................  N  24................  Average.............................  2160 hours*..............  Yes.
                                        N > 24..........................  The greater of:                                                  .................
                                                                            Average...........................  HB/HA....................  No.
                                                                            90th percentile...................  2160 hours*..............  Yes.
    90 or more, but below 95..........  N  8.................  Average.............................  2160 hours*..............  Yes.
                                        N > 8...........................  The greater of:                                                  .................
                                                                            Average...........................  HB/HA....................  No.
                                                                            95th percentile...................  2160 hours*..............  Yes.
    80 or more, but below 90..........  N > 0...........................  Maximum value 1.....................  2160 hours*..............  Yes.
    Below 80..........................  N > 0...........................  Maximum NOX emission rate; or         None.....................  No.
                                                                           maximum potential NOX
                                                                           concentration; or maximum potential
                                                                           flow rate.
    --------------------------------------------------------------------------------------------------------------------------------------------------------
    HB/HA=hour before and hour after the CEMS outage.
    *=Quality-assured, monitor operating hours, in the corresponding load range (``load bin'') for each hour of the missing data period.
    \1\ Where unit with add-on emission controls can demonstrate that the controls are operating properly, as provided in Sec.  75.34, the unit may, upon
      approval, use the maximum controlled emission rate from the previous 720 operating hours.
    \2\ During unit operating hours.
    
        (b) * * *
        (3) Whenever the monitor data availability is at least 80.0 percent 
    but less than 90.0 percent, the owner or operator shall substitute for 
    each missing data period the maximum hourly SO2 
    concentration recorded by an SO2 pollutant concentration 
    monitor during the previous 720 quality-assured monitor operating 
    hours.
        (4) Whenever the monitor data availability is less than 80.0 
    percent, the owner or operator shall substitute for each missing data 
    period the maximum potential SO2 concentration, as defined 
    in section 2.1.1.1 of appendix A to this part.
        (c) Volumetric flow rate, NOX emission rate and 
    NOX concentration data. For each hour of missing volumetric 
    flow rate data, NOX emission rate data, or NOX 
    concentration data used to determine NOX mass emissions:
        (1) Whenever the monitor or continuous emission monitoring system 
    data availability is equal to or greater than 95.0 percent, the owner 
    or operator shall calculate substitute data by means of the automated 
    data acquisition and handling system for each hour of each missing data 
    period according to the following procedures:
        (i) For a missing data period less than or equal to 24 hours, 
    substitute, as applicable, for each missing hour, the arithmetic 
    average of the flow rates or NOX emission rates or 
    NOX concentrations recorded by a monitoring system during 
    the previous 2,160 quality assured monitor operating hours at the 
    corresponding unit load range, as determined using the procedure in 
    appendix C to this part.
        (ii) For a missing data period greater than 24 hours, substitute, 
    as applicable, for each missing hour, the greater of:
        (A) The 90th percentile hourly flow rate or the 90th percentile 
    NOX emission rate or the 90th percentile NOX 
    concentration recorded by a monitoring system during the previous 2,160 
    quality-assured monitor operating hours at the corresponding unit load 
    range, as determined using the procedure in appendix C to this part; or
        (B) The average of the recorded hourly flow rates, NOX 
    emission rates or NOX concentrations recorded by a 
    monitoring system for the hour before and the hour after the missing 
    data period.
        (2) Whenever the monitor or continuous emission monitoring system 
    data availability is at least 90.0 percent but less than 95.0 percent, 
    the owner or operator shall calculate substitute data by means of the 
    automated data acquisition and handling system for each hour of each 
    missing data period according to the following procedures:
        (i) For a missing data period of less than or equal to 8 hours, 
    substitute, as applicable, the arithmetic average hourly flow rate or 
    NOX emission rate or NOX concentration recorded 
    by a monitoring system during the previous 2,160 quality-assured 
    monitor operating hours at the corresponding unit load range, as 
    determined using the procedure in appendix C to this part.
        (ii) For a missing data period greater than 8 hours, substitute, as 
    applicable, for each missing hour, the greater of:
        (A) The 95th percentile hourly flow rate or the 95th percentile 
    NOX emission rate or the 95th percentile NOX 
    concentration recorded by a monitoring system during the previous 2,160 
    quality-assured monitor operating hours at the corresponding unit load 
    range, as determined using the procedure in appendix C to this part; or
        (B) The average of the hourly flow rates, NOX emission 
    rates or NOX concentrations recorded by a monitoring system 
    for the hour before and the hour after the missing data period.
        (3) Whenever the monitor data availability is at least 80.0 percent 
    but less than 90.0 percent, the owner or operator shall, by means of 
    the automated data acquisition and handling system, substitute, as 
    applicable, for each hour of each missing data period, the maximum 
    hourly flow rate or the maximum hourly NOX emission rate or 
    the maximum hourly NOX concentration recorded during the 
    previous 2,160 quality-assured monitor operating hours at the 
    corresponding unit load range, as determined using the procedure in 
    section 2 of appendix C to this part.
        (4) Whenever the monitor data availability is less than 80.0 
    percent, the owner or operator shall substitute, as applicable, for 
    each hour of each missing data period, the maximum potential flow rate, 
    as defined in section 2.1.4.1 of appendix A to this part, or the 
    maximum NOX emission rate, as defined in section 2.1.2.1 of 
    appendix A to this part, or the maximum potential NOX 
    concentration, as defined in section 2.1.2.1 of appendix A to this 
    part.
        (5) Whenever no prior quality-assured flow rate data, 
    NOX concentration data or NOX emission rate data 
    exist for the corresponding load range, the owner or operator shall 
    substitute, as applicable, for each hour of missing data, the
    
    [[Page 28604]]
    
    maximum hourly flow rate or the maximum hourly NOX 
    concentration or maximum hourly NOX emission rate at the 
    next higher level load range for which quality-assured data are 
    available.
        (6) Whenever no prior quality-assured flow rate data, 
    NOX concentration data or NOX emission rate data 
    exist for either the corresponding load range or a higher load range, 
    the owner or operator shall substitute, as applicable, either the 
    maximum potential NOX emission rate or the maximum potential 
    NOX concentration, as defined in section 2.1.2.1 of appendix 
    A to this part or the maximum potential flow rate, as defined in 
    section 2.1.4.1 of appendix A to this part.
        27-28. Section 75.34 is amended by revising paragraph (a)(3) to 
    read as follows:
    
    
    Sec. 75.34  Units with add-on emission controls.
    
        (a) * * *
        (3) The designated representative may petition the Administrator 
    under Sec. 75.66 for approval of site-specific parametric monitoring 
    procedure(s) for calculating substitute data for missing SO2 
    pollutant concentration, NOX pollutant concentration, and 
    NOX emission rate data in accordance with the requirements 
    of paragraphs (b) and (c) of this section and appendix C to this part. 
    The owner or operator shall record the data required in appendix C to 
    this part, pursuant to Sec. 75.55(b) or Sec. 75.58(b), as applicable.
    * * * * *
        29. Section 75.35 is amended by revising paragraphs (a) and (b) and 
    by adding paragraph (d) to read as follows:
    
    
    Sec. 75.35  Missing data procedures for CO2 data.
    
        (a) On and after April 1, 2000, the owner or operator of a unit 
    with a CO2 continuous emission monitoring system for 
    determining CO2 mass emissions in accordance with Sec. 75.10 
    (or an O2 monitor that is used to determine CO2 
    concentration in accordance with appendix F to this part) shall 
    substitute for missing CO2 pollutant concentration data 
    using the procedures of paragraphs (b) and (d) of this section. The 
    procedures of paragraphs (b) and (d) of this section shall also be used 
    on and after April 1, 2000 to provide substitute CO2 data 
    for heat input determination. Prior to April 1, 2000, the owner or 
    operator shall substitute for missing CO2 data using either 
    the procedures of paragraphs (b) and (c), or paragraphs (b) and (d) of 
    this section.
        (b) During the first 720 quality assured monitor operating hours 
    following initial certification (i.e., the date and time at which 
    quality assured data begins to be recorded by the CEMS), of the 
    CO2 continuous emission monitoring system, or (for a 
    previously certified CO2 monitoring system) during the 720 
    quality assured monitor operating hours preceding implementation of the 
    standard missing data procedures in paragraph (d) of this section, the 
    owner or operator shall provide substitute CO2 pollutant 
    concentration data or substitute CO2 data for heat input 
    determination, as applicable, according to the procedures in 
    Sec. 75.31(b).
    * * * * *
        (d) Upon completion of 720 quality assured monitor operating hours 
    using the initial missing data procedures of Sec. 75.31(b), the owner 
    or operator shall provide substitute data for CO2 
    concentration data or substitute CO2 data for heat input 
    determination, as applicable, in accordance with the procedures in 
    Sec. 75.33(b), except that the term ``CO2 concentration'' 
    shall apply rather than ``SO2 concentration'' and the term 
    ``CO2 pollutant concentration monitor'' or ``CO2 
    diluent monitor'' shall apply rather than ``SO2 pollutant 
    concentration monitor.''
        30. Section 75.36 is amended by revising the section heading and 
    paragraphs (a), (b) and (d) to read as follows:
    
    
    Sec. 75.36  Missing data procedures for heat input determinations.
    
        (a) When hourly heat input is determined using a flow monitoring 
    system and a diluent gas (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 
    April 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 paragraphs (b) and 
    (d) of this section. Prior to April 1, 2000, the owner or operator 
    shall substitute for missing CO2 or O2 
    concentration data in accordance with either paragraphs (c) and (d) or 
    paragraphs (b) and (d) of this section.
        (b) During the first 720 quality assured monitor operating hours 
    following initial certification (i.e., the date and time at which 
    quality assured data begins to be recorded by the CEMS), or (for a 
    previously certified CO2 or O2 monitor) during 
    the 720 quality assured monitor operating hours preceding 
    implementation of the standard missing data procedures in paragraph (d) 
    of this section, the owner or operator shall provide substitute 
    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) * * *
        (d) Upon completion of 720 quality-assured monitor operating hours 
    using the initial missing data procedures of Sec. 75.31(b), the owner 
    or operator shall provide substitute data for CO2 or 
    O2 concentration to calculate heat input, as follows. 
    Substitute CO2 data for heat input determinations shall be 
    provided according to Sec. 75.35(d). Substitute O2 data for 
    the heat input determinations shall be provided in accordance with the 
    procedures in Sec. 75.33(b), except that the term ``O2 
    concentration'' shall apply rather than the term ``SO2 
    concentration'' and the term ``O2 diluent monitor'' shall 
    apply rather than the term ``SO2 pollutant concentration 
    monitor.'' In addition, the term ``substitute the lesser of'' shall 
    apply rather than ``substitute the greater of;'' the terms ``minimum 
    hourly O2 concentration'' and ``minimum potential 
    O2 concentration, as determined under section 2.1.3.2 of 
    appendix A to this part'' shall apply rather than, respectively, the 
    terms ``maximum hourly SO2 concentration'' and ``maximum 
    potential SO2 concentration, as determined under section 
    2.1.1.1 of appendix A to this part;'' and the terms ``10th percentile'' 
    and ``5th percentile'' shall apply rather than, respectively, the terms 
    ``90th percentile'' and ``95th percentile'' (see Table 1 of 
    Sec. 75.33).
        31. Section 75.37 is added to subpart D to read as follows:
    
    
    Sec. 75.37  Missing data procedures for moisture.
    
        (a) On and after April 1, 2000, the owner or operator of a unit 
    with a continuous moisture monitoring system shall substitute for 
    missing moisture data using the procedures of this section. Prior to 
    April 1, 2000, the owner or operator may substitute for missing 
    moisture data using the procedures of this section.
        (b) Where no prior quality assured moisture data exist, substitute 
    the minimum potential moisture percentage, from section 2.1.5 of 
    appendix A to this part, except when Equation 19-3, 19-4 or 19-8 in 
    Method 19 in appendix A to part 60 of this chapter is used to determine 
    NOX emission rate. If Equation 19-3, 19-4 or 19-8 in Method 
    19 in appendix A to part 60 of this chapter is used to
    
    [[Page 28605]]
    
    determine NOX emission rate, substitute the maximum 
    potential moisture percentage, as specified in section 2.1.6 of 
    appendix A to this part.
        (c) During the first 720 quality assured monitor operating hours 
    following initial certification (i.e., the date and time at which 
    quality assured data begins to be recorded by the moisture monitoring 
    system), the owner or operator shall provide substitute data for 
    moisture according to Sec. 75.31(b).
        (d) Upon completion of the first 720 quality-assured monitor 
    operating hours following initial certification of the moisture 
    monitoring system, the owner or operator shall provide substitute data 
    for moisture as follows:
        (1) Unless Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A 
    to part 60 of this chapter is used to determine NOX emission 
    rate, follow the missing data procedures in Sec. 75.33(b), except that 
    the term ``moisture percentage'' shall apply rather than 
    ``SO2 concentration;'' the term ``moisture monitoring 
    system'' shall apply rather than the term ``SO2 pollutant 
    concentration monitor;'' the term ``substitute the lesser of'' shall 
    apply rather than ``substitute the greater of;'' the terms ``minimum 
    hourly moisture percentage'' and ``minimum potential moisture 
    percentage, as determined under section 2.1.5 of appendix A to this 
    part'' shall apply rather than, respectively, the terms ``maximum 
    hourly SO2 concentration'' and ``maximum potential 
    SO2 concentration, as determined under section 2.1.1.1 of 
    appendix A to this part;'' and the terms ``10th percentile'' and ``5th 
    percentile'' shall apply rather than, respectively, the terms ``90th 
    percentile'' and ``95th percentile'' (see Table 1 of Sec. 75.33).
        (2) When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to 
    part 60 of this chapter is used to determine NOX emission 
    rate:
        (i) Provided that none of the following equations is used to 
    determine SO2 emissions, CO2 emissions or heat 
    input: Equation F-2, F-14b, F-16, F-17, or F-18 in appendix F to this 
    part, or Equation 19-5 or 19-9 in Method 19 in appendix A to part 60 of 
    this chapter, use the missing data procedures in Sec. 75.33(b), except 
    that the term ``moisture percentage'' shall apply rather than 
    ``SO2 concentration'' and the term ``moisture monitoring 
    system'' shall apply rather than ``SO2 pollutant 
    concentration monitor;'' or
        (ii) If any of the following equations is used to determine 
    SO2 emissions, CO2 emissions or heat input: 
    Equation F-2, F-14b, F-16, F-17, or F-18 in appendix F to this part, or 
    Equation 19-5 or 19-9 in Method 19 in appendix A to part 60 of this 
    chapter, the owner or operator shall petition the Administrator under 
    Sec. 75.66(l) for permission to use an alternative moisture missing 
    data procedure.
    
    Subpart E--Alternative Monitoring Systems
    
        32. Section 75.48 is amended by revising paragraphs (a)(3)(ii) and 
    (a) (3)(iii), and correcting paragraphs (a)(3)(iv), (a)(3)(viii), 
    (a)(3)(ix), and (a)(3)(xi) to read as follows:
    
    
    Sec. 75.48  Petition for an alternative monitoring system.
    
        (a) * * *
        (3) * * *
        (ii) Hourly test data for the alternative monitoring system at each 
    required operating level and fuel type. The fuel type, operating level 
    and gross unit load shall be recorded.
        (iii) Hourly test data for the continuous emissions monitoring 
    system at each required operating level and fuel type. The fuel type, 
    operating level and gross unit load shall be recorded.
        (iv) Arithmetic mean of the alternative monitoring system 
    measurement values, as specified in Equation 25 in Sec. 75.41(c) of 
    this part, of the continuous emission monitoring system values, as 
    specified in Equation 26 in Sec. 75.41(c) of this part, and of their 
    differences.
    * * * * *
        (viii) Variance of the measured values for the alternative 
    monitoring system and of the measured values for the continuous 
    emission monitoring system, as specified in Equation 23 in 
    Sec. 75.41(c) of this part.
        (ix) F-statistic, as specified in Equation 24 in Sec. 75.41(c) of 
    this part.
    * * * * *
        (xi) Coefficient of correlation, r, as specified in Equation 27 in 
    Sec. 75.41(c) of this part.
    * * * * *
    
    Subpart F--Recordkeeping Requirements
    
    
    Sec. 75.50  [Removed and Reserved]
    
        33. Section 75.50 is removed and reserved.
    
    
    Sec. 75.51  [Removed and Reserved]
    
        34. Section 75.51 is removed and reserved.
    
    
    Sec. 75.52  [Removed and Reserved]
    
        35. Section 75.52 is removed and reserved.
    
    
    Sec. 75.53  Monitoring plan.
    
        36. Section 75.53 is amended by revising paragraphs (a) and (b), 
    correcting paragraph (c)(1), and adding paragraphs (e) and (f) to read 
    as follows:
        (a) General provisions. (1) The provisions of paragraphs (c) and 
    (d) of this section shall remain in effect prior to April 1, 2000. The 
    owner or operator shall meet the requirements of either paragraphs (a) 
    through (d) or paragraphs (a), (b), (e) and (f) of this section prior 
    to April 1, 2000. On and after April 1, 2000, the owner or operator 
    shall meet the requirements of paragraphs (a), (b), (e) and (f) of this 
    section only. In addition, the provisions in paragraphs (e) and (f) of 
    this section that support a regulatory option provided in another 
    section of this part must be followed if the regulatory option is used 
    prior to April 1, 2000.
        (2) The owner or operator of an affected unit shall prepare and 
    maintain a monitoring plan. Except as provided in paragraphs (d) or (f) 
    of this section (as applicable), a monitoring plan shall contain 
    sufficient information on the continuous emission or opacity monitoring 
    systems, excepted methodology under Sec. 75.19, or excepted monitoring 
    systems under appendix D or E to this part and the use of data derived 
    from these systems to demonstrate that all unit 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 CEMS, continuous opacity 
    monitoring system, excepted methodology under Sec. 75.19, excepted 
    monitoring system under appendix D or E to this part, or alternative 
    monitoring system under subpart E of this part, including a change in 
    the automated data acquisition and handling system or in the flue gas 
    handling system, that affects information reported in the monitoring 
    plan (e.g., a change to a serial number for a component of a monitoring 
    system), then the owner or operator shall update the monitoring plan.
        (c) * * *
        (1) Precertification information, including, as applicable, the 
    identification of the test strategy, protocol for the relative accuracy 
    test audit, other relevant test information, span calculations, and 
    apportionment strategies under Secs. 75.10 through 75.18 of this part.
    * * * * *
        (e) Contents of the monitoring plan. Each monitoring plan shall 
    contain the information in paragraph (e)(1) of this section in 
    electronic format and the information in paragraph (e)(2) of this 
    section in hardcopy format. Electronic storage of all monitoring plan
    
    [[Page 28606]]
    
    information, including the hardcopy portions, is permissible provided 
    that a paper copy of the information can be furnished upon request for 
    audit purposes.
        (1) Electronic. (i) ORISPL numbers developed by the Department of 
    Energy and used in the National Allowance Data Base, for all affected 
    units involved in the monitoring plan, with the following information 
    for each unit:
        (A) Short name;
        (B) Classification of the unit as one of the following: Phase I 
    (including substitution or compensating units), Phase II, new, or 
    nonaffected;
        (C) Type of boiler (or boilers for a group of units using a common 
    stack);
        (D) Type of fuel(s) fired by boiler, fuel type start and end dates, 
    primary/secondary fuel indicator, and, if more than one fuel, the fuel 
    classification of the boiler;
        (E) Type(s) of emission controls for 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, 
    primary/secondary methodology indicator, missing data approach for the 
    methodology, methodology start date, and methodology end date (if 
    applicable).
        (iii) The following information:
        (A) Program(s) for which the EDR is submitted;
        (B) Unit classification;
        (C) Reporting frequency;
        (D) Program participation date;
        (E) State regulation code (if applicable); and
        (F) State or local regulatory agency code.
        (iv) Identification and description of each monitoring component 
    (including each monitor and its identifiable components, such as 
    analyzer and/or probe) in the CEMS (e.g., SO2 pollutant 
    concentration monitor, flow monitor, moisture monitor; NOX 
    pollutant concentration monitor and diluent gas monitor), the 
    continuous opacity monitoring system, or the excepted monitoring system 
    (e.g., fuel flowmeter, data acquisition and handling system), 
    including:
        (A) Manufacturer, model number and serial number;
        (B) Component/system identification code assigned by the utility to 
    each identifiable monitoring component (such as the analyzer and/or 
    probe). Each code shall use a three-digit format, unique to each 
    monitoring component and unique to each monitoring system;
        (C) Designation of the component type and method of sample 
    acquisition or operation, (e.g., in situ pollutant concentration 
    monitor or thermal flow monitor);
        (D) Designation of the system as a primary, redundant backup, non-
    redundant backup, data backup, or reference method backup system, as 
    provided in Sec. 75.10(e);
        (E) First and last dates the system reported data;
        (F) Status of the monitoring component; and
        (G) Parameter monitored.
        (v) Identification and description of all major hardware and 
    software components of the automated data acquisition and handling 
    system, including:
        (A) Hardware components that perform emission calculations or store 
    data for quarterly reporting purposes (provide the manufacturer and 
    model number); and
        (B) Software components (provide the identification of the provider 
    and model/version number).
        (vi) Explicit formulas for each measured emission parameter, using 
    component/system identification codes for the primary system used to 
    measure the parameter that links CEMS or excepted monitoring system 
    observations with reported concentrations, mass emissions, or emission 
    rates, according to the conversions listed in appendix D or E to this 
    part. Formulas for backup monitoring systems are required only if 
    different formulas for the same parameter are used for the primary and 
    backup monitoring systems (e.g., if the primary system measures 
    pollutant concentration on a different moisture basis from the backup 
    system). The formulas must contain all constants and factors required 
    to derive mass emissions or emission rates from component/system code 
    observations and an indication of whether the formula is being added, 
    corrected, deleted, or is unchanged. Each emissions formula is 
    identified with a unique three digit code. The owner or operator of a 
    low mass emissions unit for which the owner or operator is using the 
    optional low mass emissions excepted methodology in Sec. 75.19(c) is 
    not required to report such formulas.
        (vii) Inside cross-sectional area (ft2) at flue exit 
    (for all units) and at flow monitoring location (for units with flow 
    monitors, only).
        (viii) Stack height (ft) above ground level and stack base 
    elevation above sea level.
        (ix) Part 75 monitoring location identification, facility 
    identification code as assigned by the Administrator for use under the 
    Acid Rain Program or this part, and the following information, as 
    reported to the Energy Information Administration (EIA): facility 
    identification number, flue identification number, boiler 
    identification number, reporting year, and 767 reporting indicator.
        (x) For each parameter monitored: scale, maximum potential 
    concentration (and method of calculation), maximum expected 
    concentration (if applicable) (and method of calculation), maximum 
    potential flow rate (and method of calculation), maximum potential 
    NOX emission rate, span value, full-scale range, daily 
    calibration units of measure, span effective date/hour, span 
    inactivation date/hour, indication of whether dual spans are required, 
    default high range value, flow rate span, and flow rate span value and 
    full scale value (in scfh) for each unit or stack using 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
    
    [[Page 28607]]
    
        (I) For units using the excepted methodology under Sec. 75.19, the 
    applicable SO2 emission factor.
        (xii) For each unit or common stack (except for peaking units) on 
    which hardware CEMS are installed:
        (A) The upper and lower boundaries of the range of operation (as 
    defined in section 6.5.2.1 of appendix A to this part), expressed in 
    megawatts or thousands of lb/hr of steam;
        (B) The load level(s) designated as normal in section 6.5.2.1 of 
    appendix A to this part, expressed in megawatts or thousands of lb/hr 
    of steam;
        (C) The two load levels (i.e., low, mid, or high) identified in 
    section 6.5.2.1 of appendix A to this part as the most frequently used;
        (D) The date of the load analysis used to determine the normal load 
    level(s) and the two most frequently-used load levels; and
        (E) Activation and deactivation dates, when the normal load 
    level(s) or two most frequently-used load levels change and are 
    updated.
        (xiii) For each unit for which the optional fuel flow-to-load test 
    in section 2.1.7 of appendix D to this part is used:
        (A) The upper and lower boundaries of the range of operation (as 
    defined in section 6.5.2.1 of appendix A to this part), expressed in 
    megawatts or thousands of lb/hr of steam;
        (B) The load level designated as normal, pursuant to section 
    6.5.2.1 of appendix A to this part, expressed in megawatts or thousands 
    of lb/hr of steam; and
        (C) The date of the load analysis used to determine the normal load 
    level.
        (2) Hardcopy. (i) Information, including (as applicable): 
    identification of the test strategy; protocol for the relative accuracy 
    test audit; other relevant test information; calibration gas levels 
    (percent of span) for the calibration error test and linearity check; 
    calculations for determining maximum potential concentration, maximum 
    expected concentration (if applicable), maximum potential flow rate, 
    maximum potential NOX emission rate, and span; and 
    apportionment strategies under Secs. 75.10 through 75.18.
        (ii) Description of site locations for each monitoring component in 
    the continuous emission or opacity monitoring systems, including 
    schematic diagrams and engineering drawings specified in paragraphs 
    (e)(2)(iv) and (e)(2)(v) of this section and any other documentation 
    that demonstrates each monitor location meets the appropriate siting 
    criteria.
        (iii) A data flow diagram denoting the complete information 
    handling path from output signals of CEMS components to final reports.
        (iv) For units monitored by a continuous emission or opacity 
    monitoring system, a schematic diagram identifying entire gas handling 
    system from boiler to stack for all affected units, using 
    identification numbers for units, monitor components, and stacks 
    corresponding to the identification numbers provided in paragraphs 
    (e)(1)(i), (e)(1)(iv), (e)(1)(vi), and (e)(1)(ix) of this section. The 
    schematic diagram must depict stack height and the height of any 
    monitor locations. Comprehensive and/or separate schematic diagrams 
    shall be used to describe groups of units using a common stack.
        (v) For units monitored by a continuous emission or opacity 
    monitoring system, stack and duct engineering diagrams showing the 
    dimensions and location of fans, turning vanes, air preheaters, monitor 
    components, probes, reference method sampling ports, and other 
    equipment that affects the monitoring system location, performance, or 
    quality control checks.
        (f) Contents of monitoring plan for specific situations. The 
    following additional information shall be included in the monitoring 
    plan for the specific situations described:
        (1) For each gas-fired unit or oil-fired unit for which the owner 
    or operator uses the optional protocol in appendix D to this part for 
    estimating heat input and/or SO2 mass emissions, or for each 
    gas-fired or oil-fired peaking unit for which the owner/operator uses 
    the optional protocol in appendix E to this part for estimating 
    NOX emission rate (using a fuel flowmeter), the designated 
    representative shall include the following additional information in 
    the monitoring plan:
        (i) Electronic.
        (A) Parameter monitored;
        (B) Type of fuel measured, maximum fuel flow rate, units of 
    measure, and basis of maximum fuel flow rate (i.e., upper range value 
    or unit maximum) for each fuel flowmeter;
        (C) Test method used to check the accuracy of each fuel flowmeter;
        (D) Submission status of the data;
        (E) Monitoring system identification code; and
        (F) For gaseous fuels fired by the unit, the method used to verify 
    that the fuel meets the definition in Sec. 72.2 of pipeline natural gas 
    or natural gas, if applicable, and the demonstration methods used for 
    other gaseous fuels, if applicable, to determine the appropriate 
    frequency for sampling for GCV or sulfur content of the fuel.
        (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
    between the unit, all fuel supply lines, the fuel flowmeter(s), and the 
    stack(s). The schematic diagram must depict the installation location 
    of each fuel flowmeter and the fuel sampling location(s). Comprehensive 
    and/or separate schematic diagrams shall be used to describe groups of 
    units using a common pipe;
        (B) For units using the optional default SO2 emission 
    rate for ``pipeline natural gas'' or ``natural gas'' in appendix D to 
    this part, the information on the sulfur content of the gaseous fuel 
    used to demonstrate compliance with either section 2.3.1.4 or 2.3.2.4 
    of appendix D to this part;
        (C) For units using the 720 hour test under 2.3.6 of Appendix D of 
    this part to determine the required sulfur sampling requirements, 
    report the procedures and results of the test; and
        (D) For units using the 720 hour test under 2.3.5 of Appendix D of 
    this part to determine the appropriate fuel GCV sampling frequency, 
    report the procedures used and the results of the test;
        (2) For each gas-fired peaking unit and oil-fired peaking unit for 
    which the owner or operator uses the optional procedures in appendix E 
    to this part for estimating NOX emission rate, the 
    designated representative shall include in the monitoring plan:
        (i) Electronic. Unit operating and capacity factor information 
    demonstrating that the unit qualifies as a peaking unit or gas-fired 
    unit, as defined in Sec. 72.2 of this chapter, and NOX 
    correlation test information, including:
        (A) Test date;
        (B) Test number;
        (C) Operating level;
        (D) Segment ID of the NOX correlation curve;
        (E) NOX monitoring system identification;
        (F) Low and high heat input values and corresponding NOX 
    rates;
        (G) Type of fuel; and
        (H) To document the unit qualifies as a peaking unit, current 
    calendar year, capacity factor data as specified in the definition of 
    peaking unit in Sec. 72.2 of this part, and an indication of whether 
    the data are actual or projected data.
        (ii) Hardcopy. (A) A protocol containing methods used to perform 
    the baseline or periodic NOX emission test; and
        (B) Unit operating parameters related to NOX formation 
    by the unit.
        (3) For each gas-fired unit and diesel-fired unit or unit with a 
    wet flue gas pollution control system for which the
    
    [[Page 28608]]
    
    designated representative claims an opacity monitoring exemption under 
    Sec. 75.14, the designated representative shall include in the hardcopy 
    monitoring plan the information specified under Sec. 75.14(b), (c), or 
    (d), demonstrating that the unit qualifies for the exemption.
        (4) For each monitoring system recertification, maintenance, or 
    other event, the designated representative shall include the following 
    additional information in electronic format in the monitoring plan:
        (i) Component/system identification code;
        (ii) Event code or code for required test;
        (iii) Event begin date and hour;
        (iv) Conditionally valid data period begin date and hour (if 
    applicable);
        (v) Date and hour that last test is successfully completed; and
        (vi) Indicator of whether conditionally valid data were reported at 
    the end of the quarter.
        (5) For each unit using the low mass emission excepted methodology 
    under Sec. 75.19 the designated representative shall include the 
    following additional information in the monitoring plan:
        (i) Electronic. For each low mass emissions unit, report the 
    results of the analysis performed to qualify as a low mass emissions 
    unit under Sec. 75.19(c). This report will include either the previous 
    three years actual or projected emissions and the emissions calculated 
    using the methodology which will be used by the unit to estimate future 
    emissions.
        (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
    between the unit, all fuel supply lines and tanks, any fuel 
    flowmeter(s), and the stack(s). Comprehensive and/or separate schematic 
    diagrams shall be used to describe groups of units using a common pipe;
        (B) For units which use the long term fuel flow methodology under 
    Sec. 75.19(c)(3), the designated representative must provide a diagram 
    of the fuel flow to each affected unit or group of units and describe 
    in detail the procedures used to determine the long term fuel flow for 
    a unit or group of units for each fuel combusted by the unit or group 
    of units;
        (C) A statement that the unit burns only natural gas or fuel oil 
    and a list of the fuels that are burned or a statement that the unit is 
    projected to burn only natural gas or fuel oil and a list of the fuels 
    that are projected to be burned;
        (D) A statement that the unit meets the applicability requirements 
    in Secs. 75.19(a) and (b); and
        (E) Any unit historical actual and projected emissions data and 
    calculated emissions data demonstrating that the affected unit 
    qualifies as a low mass emissions unit under Secs. 75.19(a) and 
    75.19(b).
        (6) For each gas-fired unit the designated representative shall 
    include in the monitoring plan, in electronic format, the following: 
    current calendar year, fuel usage data as specified in the definition 
    of gas-fired in Sec. 72.2 of this part, and an indication of whether 
    the data are actual or projected data.
        37. Section 75.54 is amended by revising paragraph (a) introductory 
    text and paragraph (a)(1), and adding a new paragraph (g) to read as 
    follows:
    
    
    Sec. 75.54  General recordkeeping provisions.
    
        (a) Recordkeeping requirements for affected sources. On and after 
    January 1, 1996, and before April 1, 2000, the owner or operator shall 
    meet the requirements of either this section or Sec. 75.57. On and 
    after April 1, 2000, the owner or operator shall meet the requirements 
    of Sec. 75.57. The owner or operator of any affected source subject to 
    the requirements of this part shall maintain for each affected unit a 
    file of all measurements, data, reports, and other information required 
    by this part at the source in a form suitable for inspection for at 
    least three (3) years from the date of each record. Unless otherwise 
    provided, throughout this subpart the phrase ``for each affected unit'' 
    also applies to each group of affected or nonaffected units utilizing a 
    common stack and common monitoring systems, pursuant to Secs. 75.16 
    through 75.18, or utilizing a common pipe header and common fuel 
    flowmeter, pursuant to section 2.1.2 of appendix D to this part. The 
    file shall contain the following information:
        (1) The data and information required in paragraphs (b) through (g) 
    of this section, beginning with the earlier of the date of provisional 
    certification, or the deadline in Sec. 75.4(a), (b) or (c);
    * * * * *
        (g) Missing data records. The owner or operator shall record the 
    causes of any missing data periods and the actions taken by the owner 
    or operator to cure such causes.
        38. Section 75.55 is amended by adding introductory text prior to 
    paragraph (a), by correcting paragraphs (b)(1)(i), (b)(1)(xi), 
    (b)(2)(vii), by revising paragraph (e), and by removing paragraph (f) 
    to read as follows:
    
    
    Sec. 75.55  General recordkeeping provisions for specific situations.
    
        Before April 1, 2000, the owner or operator shall meet the 
    requirements of either this section or Sec. 75.58. On and after April 
    1, 2000, the owner or operator shall meet the requirements of 
    Sec. 75.58.
    * * * * *
        (b) * * *
        (1) * * *
        (i) The information required in Sec. 75.54(c) for SO2 
    concentration and volumetric flow if either one of these monitors is 
    still operating:
    * * * * *
        (xi) Method of determination of SO2 concentration and 
    volumetric flow, using Codes 1-15 in Table 4 of Sec. 75.54; and
     * * * * *
        (2) * * *
        (vii) Method of determination of NOX emission rate using 
    Codes 1-15 in Table 4 of Sec. 75.54; and
     * * * * *
        (e) Specific 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 gaseous fuel is combusted in a unit with an 
    SO2 CEMS, the owner or operator shall record the information 
    in paragraph (c)(3) of this section in lieu of the information in 
    Secs. 75.54(c)(1) and (c)(3) or Secs. 75.57(c)(1) and (c)(4), for those 
    hours.
        (2) The provisions of this paragraph apply to a unit which, in 
    accordance with the provisions of Sec. 75.11(e)(3), uses an 
    SO2 CEMS to determine SO2 emissions during hours 
    in which only gaseous fuel is combusted in the unit. If the unit 
    sometimes burns only gaseous fuel that is very low sulfur fuel (as 
    defined in Sec. 72.2 of this chapter) as a primary and/or backup fuel 
    and at other times combusts higher-sulfur fuels, such as coal or oil, 
    as primary and/or backup fuel(s), then the owner or operator shall keep 
    records on-site, suitable for inspection, of the type(s) of fuel(s) 
    burned during each period of missing SO2 data and the number 
    of hours that each type of fuel was combusted in the unit during each 
    missing data period. This recordkeeping requirement does not apply to 
    an affected unit that burns very low sulfur fuel exclusively, nor does 
    it apply to a unit that burns such gaseous fuel(s) only during unit 
    startup.
        39. Section 75.56 is amended by adding introductory text prior to 
    paragraph (a) adding new paragraphs (a)(5)(vii) through (a)(5)(ix) and 
    removing paragraph (d) to read as follows:
    
    
    Sec. 75.56  Certification, quality assurance, and quality control 
    record provisions.
    
        Before April 1, 2000, the owner or operator shall meet the 
    requirements of
    
    [[Page 28609]]
    
    either this section or Sec. 75.59. On and after April 1, 2000, the 
    owner or operator shall meet the requirements of Sec. 75.59.
        (a) * * *
        (5) * * *
        (vii) For flow monitors, the equation used to linearize the flow 
    monitor and the numerical values of the polynomial coefficients or K 
    factor(s) of that equation.
        (viii) The raw data and calculated results for any stratification 
    tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 in 
    appendix A to this part.
        (ix) For moisture monitoring systems, the coefficient or ``K'' 
    factor or other mathematical algorithm used to adjust the monitoring 
    system with respect to the reference method.
    * * * * *
        40. Section 75.57 is added to subpart F to read as follows:
    
    
    Sec. 75.57  General recordkeeping provisions.
    
        Before April 1, 2000, the owner or operator shall meet the 
    requirements of either this section or Sec. 75.54. However, the 
    provisions of this section which support a regulatory option provided 
    in another section of this part must be followed if that regulatory 
    option is used prior to April 1, 2000. On or after April 1, 2000, the 
    owner or operator shall meet the requirements of this section.
        (a) Recordkeeping requirements for affected sources. The owner or 
    operator of any affected source subject to the requirements of this 
    part shall maintain for each affected unit a file of all measurements, 
    data, reports, and other information required by this part at the 
    source in a form suitable for inspection for at least three (3) years 
    from the date of each record. Unless otherwise provided, throughout 
    this subpart the phrase ``for each affected unit'' also applies to each 
    group of affected or nonaffected units utilizing a common stack and 
    common monitoring systems, pursuant to Secs. 75.16 through 75.18, or 
    utilizing a common pipe header and common fuel flowmeter, pursuant to 
    section 2.1.2 of appendix D to this part. The file shall contain the 
    following information:
        (1) The data and information required in paragraphs (b) through (h) 
    of this section, beginning with the earlier of the date of provisional 
    certification or the deadline in Sec. 75.4(a), (b), or (c);
        (2) The supporting data and information used to calculate values 
    required in paragraphs (b) through (g) of this section, excluding the 
    subhourly data points used to compute hourly averages under 
    Sec. 75.10(d), beginning with the earlier of the date of provisional 
    certification or the deadline in Sec. 75.4(a), (b), or (c);
        (3) The data and information required in Sec. 75.55 or Sec. 75.58 
    for specific situations, as applicable, beginning with the earlier of 
    the date of provisional certification or the deadline in Sec. 75.4(a), 
    (b), or (c);
        (4) The certification test data and information required in 
    Sec. 75.56 or Sec. 75.59 for tests required under Sec. 75.20, beginning 
    with the date of the first certification test performed, the quality 
    assurance and quality control data and information required in 
    Sec. 75.56 or Sec. 75.59 for tests, and the quality assurance/quality 
    control plan required under Sec. 75.21 and appendix B to this part, 
    beginning with the date of provisional certification;
        (5) The current monitoring plan as specified in Sec. 75.53, 
    beginning with the initial submission required by Sec. 75.62; and
        (6) The quality control plan as described in section 1 of appendix 
    B to this part, beginning with the date of provisional certification.
        (b) Operating parameter record provisions. The owner or operator 
    shall record for each hour the following information on unit operating 
    time, heat input rate, and load, separately for each affected unit and 
    also for each group of units utilizing a common stack and a common 
    monitoring system or utilizing a common pipe header and common fuel 
    flowmeter:
        (1) Date and hour;
        (2) Unit operating time (rounded up to the nearest fraction of an 
    hour (in equal increments that can range from one hundredth to one 
    quarter of an hour, at the option of the owner or operator));
        (3) Hourly gross unit load (rounded to nearest MWge) (or steam load 
    in 1000 lb/hr at stated temperature and pressure, rounded to the 
    nearest 1000 lb/hr, if elected in the monitoring plan);
        (4) Operating load range corresponding to hourly gross load of 1 to 
    10, except for units using a common stack or common pipe header, which 
    may use up to 20 load ranges for stack or fuel flow, as specified in 
    the monitoring plan;
        (5) Hourly heat input rate (mmBtu/hr, rounded to the nearest 
    tenth);
        (6) Identification code for formula used for heat input, as 
    provided in Sec. 75.53; and
        (7) For CEMS units only, F-factor for heat input calculation and 
    indication of whether the diluent cap was used for heat input 
    calculations for the hour.
        (c) 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;
        (ii) Date and hour;
        (iii) Hourly average volumetric flow rate (in scfh, rounded to the 
    nearest thousand);
        (iv) Hourly average volumetric flow rate (in scfh, rounded to the 
    nearest thousand), adjusted for bias if bias adjustment factor 
    required, as provided in Sec. 75.24(d);
        (v) Percent monitor data availability (recorded to the nearest 
    tenth of a percent) for the flow monitor, calculated pursuant to 
    Sec. 75.32; and
        (vi) Method of determination for hourly average flow rate using 
    Codes 1-55 in Table 4a of this section.
        (3) For flue gas moisture content during unit operation (where 
    SO2 concentration is measured on a dry basis), as measured 
    and reported from each certified primary monitor, certified back-up 
    monitor, or other approved method of emissions determination:
        (i) Component-system identification code, as provided in 
    Sec. 75.53;
        (ii) Date and hour;
    
    [[Page 28610]]
    
        (iii) Hourly average moisture content of flue gas (percent, rounded 
    to the nearest tenth). If the continuous moisture monitoring system 
    consists of wet- and dry-basis oxygen analyzers, also record both the 
    wet- and dry-basis oxygen hourly averages (in percent O2, 
    rounded to the nearest tenth);
        (iv) Percent monitor data availability (recorded to the nearest 
    tenth of a percent) for the moisture monitoring system, calculated 
    pursuant to Sec. 75.32; and
        (v) Method of determination for hourly average moisture percentage, 
    using Codes 1-55 in Table 4a of this section.
        (4) For 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 and (if applicable) moisture data in paragraphs 
    (c)(1), (c)(2), and (c)(3) of this section, as provided in Sec. 75.53.
    
         Table 4a.--Codes for Method of Emissions and Flow Determination
    ------------------------------------------------------------------------
                                    Hourly emissions/flow measurement or
               Code                          estimation method
    ------------------------------------------------------------------------
    1........................  Certified primary emission/flow monitoring
                                system.
    2........................  Certified backup emission/flow monitoring
                                system.
    3........................  Approved alternative monitoring system.
    4........................  Reference method:
                                 NSO2: Method 6C.
                                 Flow: Method 2 or its allowable
                                alternatives under appendix A to part 60 of
                                this chapter.
                                 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, O2 concentrations, NOX
                                concentrations, flow rates, moisture
                                percentages or NOX emission rates for the
                                hour before and the hour following a missing
                                data period.
    7........................  Hourly average SO2 concentration, CO2
                                concentration, O2 concentration, NOX
                                concentration, moisture percentage, flow
                                rate, or NOX emission rate using initial
                                missing data procedures.
    8........................  90th percentile hourly SO2 concentration, CO2
                                concentration, NOX concentration, flow rate,
                                moisture percentage, or NOX emission rate or
                                10th percentile hourly O2 concentration or
                                moisture percentage (moisture missing data
                                algorithm depends on which equations are
                                used for emissions and heat input).
    9........................  95th percentile hourly SO2 concentration, CO2
                                concentration, NOX concentration, flow rate,
                                moisture percentage, or NOX emission rate or
                                5th percentile hourly O2 concentration or
                                moisture percentage (moisture missing data
                                algorithm depends on which equations are
                                used for emissions and heat input)
    10.......................  Maximum hourly SO2 concentration, CO2
                                concentration, NOX concentration, flow rate,
                                moisture percentage, or NOX emission rate or
                                minimum hourly O2 concentration or moisture
                                percentage in the applicable lookback period
                                (moisture missing data algorithm depends on
                                which equations are used for emissions and
                                heat input).
    11.......................  Average of hourly flow rates, NOX
                                concentrations or NOX emission rates in
                                corresponding load range, for the applicable
                                lookback period.
    12.......................  Maximum potential concentration of SO2,
                                maximum potential concentration of CO2,
                                maximum potential concentration of NOX
                                maximum potential flow rate, maximum
                                potential NOX emission rate, maximum
                                potential moisture percentage, minimum
                                potential O2 concentration or minimum
                                potential moisture percentage, as determined
                                using section 2.1 of appendix A to this part
                                (moisture missing data algorithm depends on
                                which equations are used for emissions and
                                heat input).
    13.......................  Fuel analysis data from appendix G to this
                                part for 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, use 5.0 percent for boilers
                                and 1.0 percent for turbines; if it is
                                replacing an O2 measurement, use 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 2.0 ppm during
                                hours when only ``very low sulfur fuel'', as
                                defined in Sec.  72.2 of this chapter, is
                                combusted.
    17.......................  Like-kind replacement non-redundant backup
                                monitoring analyzer.
    19.......................  200 percent of the MPC; default high range
                                value.
    20.......................  200 percent of the full-scale range setting
                                (full-scale exceedance of high range).
    25.......................  Maximum potential NOX emission rate (MER).
                                (Use only when a NOX concentration full-
                                scale exceedance occurs and the diluent
                                monitor is unavailable.)
    54.......................  Other quality assured methodologies approved
                                through petition. These hours are included
                                in missing data lookback and are treated as
                                unavailable hours for percent monitor
                                availability calculations.
    55.......................  Other substitute data approved through
                                petition. These hours are not included in
                                missing data lookback and are treated as
                                unavailable hours for percent monitor
                                availability calculations.
    ------------------------------------------------------------------------
    
        (d) NOX emission record provisions. The owner or 
    operator shall record the applicable information required by this 
    paragraph for each affected unit for each hour or partial hour during 
    which the unit operates, except for a gas-fired peaking unit or oil-
    fired peaking unit for which the owner or operator is using the 
    optional protocol in appendix E to this part or a low mass emissions 
    unit for which the owner or operator is using the optional low mass 
    emissions excepted methodology in Sec. 75.19(c) for estimating 
    NOX emission rate. For each NOX emission rate (in 
    lb/mmBtu) measured by a NOX-diluent monitoring system, or, 
    if applicable, for each NOX concentration (in ppm) measured 
    by a
    
    [[Page 28611]]
    
    NOX concentration monitoring system used to calculate 
    NOX mass emissions under Sec. 75.71(a)(2), record the 
    following data as measured and reported from the certified primary 
    monitor, certified back-up monitor, or other approved method of 
    emissions determination:
        (1) Component-system identification code, as provided in Sec. 75.53 
    (including identification code for the moisture monitoring system, if 
    applicable);
        (2) Date and hour;
        (3) Hourly average NOX concentration (ppm, rounded to 
    the nearest tenth) and hourly average NOX concentration 
    (ppm, rounded to the nearest tenth) adjusted for bias if bias 
    adjustment factor required, as provided in Sec. 75.24(d);
        (4) Hourly average diluent gas concentration (for NOX-
    diluent monitoring systems, only, in units of percent O2 or 
    percent CO2, rounded to the nearest tenth);
        (5) 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);
        (6) Hourly average NOX emission rate (for 
    NOX-diluent monitoring systems only, in units of lb/mmBtu, 
    rounded either to the nearest hundredth or thousandth prior to April 1, 
    2000 and rounded to the nearest thousandth on and after April 1, 2000);
        (7) Hourly average NOX emission rate (for 
    NOX-diluent monitoring systems only, in units of lb/mmBtu, 
    rounded either to the nearest hundredth or thousandth prior to April 1, 
    2000 and rounded to the nearest thousandth on and after April 1, 2000), 
    adjusted for bias if bias adjustment factor is required, as provided in 
    Sec. 75.24(d). The requirement to report hourly NOX emission 
    rates to the nearest thousandth shall not affect NOX 
    compliance determinations under part 76 of this chapter; compliance 
    with each applicable emission limit under part 76 shall be determined 
    to the nearest hundredth pound per million Btu;
        (8) Percent monitoring system data availability (recorded to the 
    nearest tenth of a percent), for the NOX-diluent or 
    NOX concentration monitoring system, and, if applicable, for 
    the moisture monitoring system, calculated pursuant to Sec. 75.32;
        (9) Method of determination for hourly average NOX 
    emission rate or NOX concentration and (if applicable) for 
    the hourly average moisture percentage, using Codes 1-55 in Table 4a of 
    this section; and
        (10) Identification codes for emissions formulas used to derive 
    hourly average NOX emission rate and total NOX 
    mass emissions, as provided in Sec. 75.53, and (if applicable) the F-
    factor used to convert NOX concentrations into emission 
    rates.
        (e) 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 CEMS 
    (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 
    (including identification code for the moisture monitoring system, if 
    applicable);
        (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 and hourly average CO2 concentration, 
    and, if applicable, for the hourly average moisture percentage, using 
    Codes 1-55 in Table 4a of this section;
        (ix) Identification code for emissions formula used to derive 
    hourly average 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 the sum of 
    combustion-formed emissions and sorbent-related emissions.
        (f) Opacity records. The owner or operator shall record opacity 
    data as specified by the State or local air pollution control agency. 
    If the State or local air pollution control agency does not specify 
    recordkeeping requirements for opacity, then record the information 
    required by paragraphs (f) (1) through (5) of this section for each 
    affected unit, except as provided in Secs. 75.14(b), (c), and (d). The 
    owner or operator shall also keep records of all incidents of opacity 
    monitor downtime during unit operation, including reason(s) for the 
    monitor outage(s) and any corrective action(s) taken for opacity, as 
    measured and reported by the continuous opacity monitoring system:
        (1) Component/system identification code;
        (2) Date, hour, and minute;
        (3) Average opacity of emissions for each six minute averaging 
    period (in percent opacity);
        (4) If the average opacity of emissions exceeds the applicable 
    standard, then a code indicating such an exceedance has occurred; and 
    (5) Percent monitor data availability (recorded to the nearest tenth of 
    a percent), calculated according to the requirements of the procedure 
    recommended for State Implementation Plans in appendix M to part 51 of 
    this chapter.
        (g) Diluent record provisions. The owner or operator of a unit 
    using a flow monitor and an O2 diluent monitor to
    
    [[Page 28612]]
    
    determine heat input, in accordance with Equation F-17 or F-18 of 
    appendix F to this part, or a unit that accounts for heat input using a 
    flow monitor and a CO2 diluent monitor (which is used only 
    for heat input determination and is not used as a CO2 
    pollutant concentration monitor) shall keep the following records for 
    the O2 or CO2 diluent monitor:
        (1) Component-system identification code, as provided in 
    Sec. 75.53;
        (2) Date and hour;
        (3) Hourly average diluent gas (O2 or CO2) 
    concentration (in percent, rounded to the nearest tenth);
        (4) Percent monitor data availability for the diluent monitor 
    (recorded to the nearest tenth of a percent), calculated pursuant to 
    Sec. 75.32; and
        (5) Method of determination code for diluent gas (O2 or 
    CO2) concentration data using Codes 1-55, in Table 4a of 
    this section.
        (h) Missing data records. The owner or operator shall record the 
    causes of any missing data periods and the actions taken by the owner 
    or operator to correct such causes.
        41. Section 75.58 is added to subpart F to read as follows:
    
    
    Sec. 75.58  General recordkeeping provisions for specific situations.
    
        Before April 1, 2000, the owner or operator shall meet the 
    requirements of either this section or Sec. 75.55. However, the 
    provisions of this section which support a regulatory option provided 
    in another section of this part must be followed if that regulatory 
    option is exercised prior to April 1, 2000. On or after April 1, 2000, 
    the owner or operator shall meet the requirements of this section.
        (a) [Reserved]
        (b) Specific parametric data record provisions for calculating 
    substitute emissions data for units with add-on emission controls. In 
    accordance with Sec. 75.34, the owner or operator of an affected unit 
    with add-on emission controls shall either record the applicable 
    information in paragraph (b)(3) of this section for each hour of 
    missing 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 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(c) or Sec. 75.57(c) 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 1-15 in Table 4 of Sec. 75.54 or Codes 1-55 
    in 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 NOX emission controls using 
    the optional parametric monitoring procedures in appendix C to this 
    part, for each hour of missing NOX emission rate data:
        (i) Date and hour;
        (ii) Inlet air flow rate (scfh, rounded to the nearest thousand);
        (iii) Excess O2 concentration of flue gas at stack 
    outlet (percent, rounded to the nearest tenth of a percent);
        (iv) Carbon monoxide concentration of flue gas at stack outlet 
    (ppm, rounded to the nearest tenth);
        (v) Temperature of flue gas at furnace exit or economizer outlet 
    duct ( deg.F);
        (vi) Other parameters specific to NOX emission controls 
    (e.g., average hourly reagent feedrate);
        (vii) Method of determination of NOX emission rate using 
    Codes 1-15 in Table 4 of Sec. 75.54 or Codes 1-55 in Table 4a of 
    Sec. 75.57; and
        (viii) Inlet and outlet NOX emission rate values 
    recorded by a NOX continuous emission monitoring system and 
    the removal efficiency of the add-on emission controls.
        (3) For units with add-on 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 substituting a representative SO2 
    concentration during missing data periods under Sec. 75.34(a)(2), any 
    available inlet and outlet SO2 concentration values recorded 
    by an SO2 continuous emission monitoring system; and
        (iv) For units substituting a representative NOX 
    emission rate during missing data periods under Sec. 75.34(a)(2), any 
    available inlet and outlet NOX emission rate values recorded 
    by a continuous emission monitoring system.
        (c) Specific 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 volumetric flow rate of oil, while the unit 
    combusts oil, with the units in which oil flow is recorded (gal/hr, 
    scf/hr, m3/hr, or bbl/hr, rounded to the nearest tenth) 
    (flag value if derived from missing data procedures);
        (iii) Sulfur content of oil sample used to determine 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) [Reserved];
        (v) Mass flow rate of oil combusted each hour and method of 
    determination (lb/hr, rounded to the nearest tenth)
    
    [[Page 28613]]
    
    (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 and method of 
    determination (flag value if derived from missing data procedures);
        (viii) Gross calorific value of oil used to determine heat input 
    and method of determination (Btu/lb) (flag value if derived from 
    missing data procedures);
        (ix) Hourly heat input rate from oil, according to procedures in 
    appendix D 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);
        (xi) Monitoring system identification code;
        (xii) Operating load range corresponding to gross unit load (01-
    20); and
        (xiii) Type of oil combusted.
        (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 the nearest tenth of a 
    percent).
        (3) For gas-fired units or oil-fired units using the optional 
    protocol in appendix D to this part, when either an assumed oil sulfur 
    content or density value is used, or when as-delivered oil sampling is 
    performed:
        (i) Record the measured sulfur content, gross calorific value, and, 
    if applicable, density from each fuel sample; and
        (ii) Record and report the assumed sulfur content, gross calorific 
    value, 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 and method of determination 
    (rounded to the nearest 0.1 grains/100 scf) (flag value if derived from 
    missing data procedures); or
        (B) Default SO2 emission rate of 0.0006 lb/mmBtu for 
    pipeline natural gas, or calculated SO2 emission rate for 
    natural gas from section 2.3.2.1.1 of appendix D to this part.
        (iv) Hourly flow rate of gaseous fuel, while the unit combusts gas 
    (100 scfh) and source of data code for gas flow rate.
        (v) Gross calorific value of gaseous fuel used to determine heat 
    input rate (Btu/100 scf) (flag value if derived from missing data 
    procedures).
        (vi) SO2 mass emission rate due to the combustion of 
    gaseous fuels (lb/hr).
        (vii) 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).
        (viii) Monitoring system identification code.
        (ix) Operating load range corresponding to gross unit load (01-20).
        (x) Type of gas combusted.
        (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);
        (iii) Gross calorific value (Btu/lb); and
        (iv) Density or specific gravity, if required to convert volume to 
    mass.
        (6) For each sample of gaseous fuel for sulfur content:
        (i) Date of sampling; and
        (ii) Sulfur content (grains/100 scf, rounded to the nearest tenth).
        (7) For each sample of gaseous fuel for gross calorific value:
        (i) Date of sampling; and
        (ii) Gross calorific value (Btu/100 scf)
        (8) For each oil sample or sample of gaseous fuel:
        (i) Type of oil or gas; and
        (ii) Type of sulfur sampling (using codes in tables D-4 and D-5 of 
    appendix D to this part) and value used in calculations, and type of 
    GCV or density sampling (using codes in tables D-4 and D-5 of appendix 
    D to this part).
        (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) and (d)(2)(vii) 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 mass flow rate of oil while the unit combusts 
    oil with the units in which oil flow is recorded (lb/hr);
        (iii) Gross calorific value of oil used to determine heat input 
    (Btu/lb);
        (iv) Hourly average NOX emission rate from combustion of 
    oil (lb/mmBtu, rounded to the nearest hundredth);
        (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);
        (vii) NOX mass emissions, calculated in accordance with 
    section 8.1 of appendix F to this part;
        (viii) NOX monitoring system identification code;
        (ix) Fuel flow monitoring system identification code; and
        (x) Segment identification of the correlation curve.
        (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);
        (iii) Gross calorific value 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);
        (vii) NOX mass emissions, calculated in accordance with 
    section 8.1 of appendix F to this part;
        (viii) NOX monitoring system identification code;
    
    [[Page 28614]]
    
        (ix) Fuel flow monitoring system identification code; and
        (x) Segment identification of the correlation curve.
        (3) For each hour when the unit combusts multiple fuels:
        (i) Date and hour;
        (ii) Hourly average heat input rate from all fuels (mmBtu/hr, 
    rounded to the nearest tenth); and
        (iii) Hourly average NOX emission rate for the unit for 
    all fuels (lb/mmBtu, rounded to the nearest hundredth).
        (4) For each hour when the unit combusts any fuel(s):
        (i) 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 outside of 
    manufacturer's recommended range); and
        (ii) 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).
        (5) For each fuel sample:
        (i) Date of sampling;
        (ii) Gross calorific value (Btu/lb for oil, Btu/100 scf for gaseous 
    fuel); and
        (iii) Density or specific gravity, if required to convert volume to 
    mass.
        (6) Flag to indicate multiple or single fuels combusted.
        (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 gaseous fuel is combusted in a unit with an 
    SO2 CEMS, the owner or operator shall record the information 
    in paragraph (c)(3) of this section in lieu of the information in 
    Secs. 75.54(c)(1) and (c)(3) or Secs. 75.57(c)(1), (c)(3), and (c)(4), 
    for those hours.
        (2) The provisions of this paragraph apply to a unit which, in 
    accordance with the provisions of Sec. 75.11(e)(3), uses an 
    SO2 CEMS to determine SO2 emissions during hours 
    in which only gaseous fuel is combusted in the unit. If the unit 
    sometimes burns only gaseous fuel that is very low sulfur fuel (as 
    defined in Sec. 72.2 of this chapter) as a primary and/or backup fuel 
    and at other times combusts higher sulfur fuels, such as coal or oil, 
    as primary and/or backup fuel(s), then the owner or operator shall keep 
    records on-site, in a form 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 type of fuel was combusted in the unit 
    during each missing data period. This recordkeeping requirement does 
    not apply to an affected unit that burns very low sulfur fuel 
    exclusively, nor does it apply to a unit that burns such gaseous 
    fuel(s) only during unit startup.
        (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 
    Secs. 75.57(b) through (e), the owner or operator shall record 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) All low mass emission units shall report for each hour:
        (i) Date and hour;
        (ii) Unit operating time (units using the long term fuel flow 
    methodology report operating time to be 1);
        (iii) 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 NOX);
        (iv) Average hourly NOX emission rate (lb/mmBtu, rounded 
    to the nearest thousandth);
        (v) Hourly NOX mass emissions (lbs, rounded to the 
    nearest tenth);
        (vi) Hourly SO2 mass emissions (lbs, rounded to the 
    nearest tenth);
        (vii) Hourly CO2 mass emissions (tons, rounded to the 
    nearest tenth);
        (viii) Hourly calculated unit heat input in mmBtu;
        (ix) Hourly unit output in gross load or steam load;
        (x) The method of determining hourly heat input: unit maximum rated 
    heat input, unit long term fuel flow or group long term fuel flow;
        (xi) The method of determining NOX emission rate used 
    for the hour: default based on fuel combusted, unit specific default 
    based on testing or historical data, group default based on 
    representative testing of identical units, unit specific based on 
    testing of a unit with NOX controls operating, or missing 
    data value; and
        (xii) Control status of the unit.
        (2) Low mass emission units using the optional long term fuel flow 
    methodology to determine unit heat input shall report for each quarter:
        (i) Type of fuel;
        (ii) Beginning date and hour of long term fuel flow measurement 
    period;
        (iii) End date and hour of long term fuel flow period;
        (iv) Quantity of fuel measured;
        (v) Units of measure;
        (vi) Fuel GCV value used to calculate heat input;
        (vii) Units of GCV;
        (viii) Method of determining fuel GCV used;
        (ix) Method of determining fuel flow over period;
        (x) Component-system identification code;
        (xi) Quarter and year;
        (xii) Total heat input (mmBtu); and
        (xiii) Operating hours in period.
        42. Section 75.59 is added to subpart F to read as follows:
    
    
    Sec. 75.59  Certification, quality assurance, and quality control 
    record provisions.
    
        Before April 1, 2000, the owner or operator shall meet the 
    requirements of this section or Sec. 75.56. However, the provisions of 
    this section which support a regulatory option provided in another 
    section of this part must be followed if that regulatory option is 
    exercised prior to April 1, 2000. On or after April 1, 2000, the owner 
    or operator shall meet the requirements of this section.
        (a) Continuous emission or opacity monitoring systems. The owner or 
    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 pollutant 
    concentration 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 all 
    daily and 7-day calibration error tests and all off-line calibration 
    demonstrations, 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., 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;
    
    [[Page 28615]]
    
        (x) Description of any adjustments, corrective actions, or 
    maintenance prior to a passed test or following a failed 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) Component-system identification code;
        (ii) Date and hour;
        (iii) Code indicating whether monitor passes or fails the 
    interference check; and
        (iv) Description of any adjustments, corrective actions, or 
    maintenance prior to a passed test or following a failed test.
        (3) For each SO2 or NOX pollutant 
    concentration monitor, CO2 pollutant concentration 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) Calibration gas level;
        (iv) Date and time (hour and minute) of each gas injection at each 
    calibration gas level;
        (v) Reference value (i.e., reference gas concentration for each gas 
    injection at each calibration gas level, in ppm or other appropriate 
    units);
        (vi) Observed value (monitor response to each reference gas 
    injection at each calibration gas level, in ppm or other appropriate 
    units);
        (vii) Mean of reference values and mean of measured values at each 
    calibration gas level;
        (viii) Linearity error at each of the reference gas concentrations 
    (rounded to nearest tenth of a percent) (flag if using alternative 
    performance specification);
        (ix) Test number and reason for test (flag if aborted test); and
        (x) Description of any adjustments, corrective action, or 
    maintenance prior to a passed test or following a failed test.
        (4) For each differential pressure type flow monitor, 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. For each flow monitor, the owner or 
    operator shall record items in paragraphs (a)(4) (vi) and (vii) 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 prior to a passed test or following a failed test.
        (vi) Test data from the flow-to-load ratio or gross heat rate (GHR) 
    evaluation, including:
        (A) Monitoring 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 
    GHR) and hourly ratios (or GHR 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;
        (L) Number of hours exempted for hours preceding a successful 
    diagnostic test, following a documented monitor repair or major 
    component replacement; and
        (M) Number of hours excluded for flue gases discharging 
    simultaneously thorough a main stack and a bypass stack.
        (vii) Reference data for the flow-to-load ratio or gross heat rate 
    evaluation, including (as applicable):
        (A) Reference flow RATA end date and time;
        (B) Test number of the reference RATA;
        (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;
        (H) Reference gross heat rate value;
        (I) Monitoring system identification code;
        (J) Average hourly heat input rate during RATA;
        (K) Average gross unit load; and
        (L) Operating load level.
        (5) For each SO2 pollutant concentration monitor, flow 
    monitor, each CO2 pollutant concentration monitor (including 
    any O2 concentration monitor used to determine 
    CO2 mass emissions or heat input), each NOX-
    diluent continuous emission monitoring system, each SO2-
    diluent continuous emission monitoring system, each NOX 
    concentration monitoring system, each diluent gas (O2 or 
    CO2) monitor used to determine heat input, each moisture 
    monitoring system, and each 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-diluent 
    continuous emission monitoring system, SO2-diluent 
    continuous emission monitoring system, diluent gas (O2 or 
    CO2) monitor used to determine heat input, NOX 
    concentration monitoring system, moisture monitoring system, or 
    approved alternative monitoring system, including:
        (A) Date, hour, and minute of beginning of test run;
        (B) Date, hour, and minute of end of test run;
        (C) Monitoring 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) Normal load indicator for flow RATAs (except for peaking 
    units);
        (G) Units of measure;
        (H) Run number;
        (I) Run value from CEMS being tested, in the appropriate units of 
    measure;
        (J) Run value from reference method, in the appropriate units of 
    measure;
        (K) 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;
        (L) Average gross unit load, expressed as a total gross unit load, 
    rounded to the nearest MWe, or as steam load, rounded to the nearest 
    thousand lb/hr); and
        (M) 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
    
    [[Page 28616]]
    
    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) Statistical ``t'' value used in calculations;
        (E) 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;
        (F) Bias test results as specified in section 7.6.4 in appendix A 
    to this part; and
        (G) Bias adjustment factor from Equation A-12 in appendix A to this 
    part for any monitoring system that failed the bias test (except as 
    otherwise provided in section 7.6.5 of appendix A to this part) and 
    1.000 for any monitoring system that passed the bias test.
        (iv) Description of any adjustment, corrective action, or 
    maintenance prior to a passed test or following a failed or aborted 
    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 equation used to linearize the flow 
    monitor and the numerical values of the polynomial coefficients or K 
    factor(s) of that equation.
        (vii) For moisture monitoring systems, the coefficient or ``K'' 
    factor or other mathematical algorithm used to adjust the monitoring 
    system with respect to the reference method.
        (6) For each SO2, NOX, or CO2 
    pollutant concentration monitor, NOX-diluent continuous 
    emission monitoring system, SO2-diluent continuous emission 
    monitoring system, NOX concentration monitoring system, or 
    diluent gas (O2 or CO2) monitor used to determine 
    heat input, 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;
        (ix) Cycle time result for the entire system;
        (x) Reason for test; and
        (xi) Test number.
        (7) In addition to the information in paragraph (a)(5) of this 
    section, the owner or operator shall record, for each relative accuracy 
    test audit, supporting information sufficient to substantiate 
    compliance with all applicable sections and appendices in this part. 
    Unless otherwise specified in this part or in an applicable test 
    method, the information in paragraphs (a)(7)(i) through (a)(7)(vi) may 
    be recorded either in hard copy format, electronic format or a 
    combination of the two, and the owner or operator shall maintain this 
    information in a format suitable for inspection and audit purposes. 
    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 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 
    (ft2);
        (O) Average velocity (ft/sec);
        (P) Total volumetric flow rate (scfh, wet basis);
        (Q) Flow rate reference method used;
        (R) Average velocity, adjusted for wall effects;
        (S) Calculated (site-specific) wall effects adjustment factor 
    determined during the run, and, if different, the wall effects 
    adjustment factor used in the calculations; and
        (T) Default wall effects adjustment factor used.
        (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) Velocity differential pressure at traverse point (inches of 
    H2O);
        (G) TS, stack temperature at the traverse point 
    ( deg.F);
        (H) Composite (wall effects) traverse point identifier;
        (I) Number of points included in composite traverse point;
        (J) Yaw angle of flow at traverse point (degrees);
        (K) Pitch angle of flow at traverse point (degrees);
        (L) Calculated velocity at traverse point both accounting and not 
    accounting for wall effects (ft/sec); and
        (M) Probe identification number.
        (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;
    
    [[Page 28617]]
    
        (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) Upscale gas concentration (mid or high gas level) used for each 
    pre-run or post-run system bias check or (for dilution type reference 
    method 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) Date(s) of the latest analyzer interference test(s);
        (U) Results of the latest analyzer interference test(s);
        (V) Date of the latest NO2 to NO conversion test (Method 
    7E only);
        (W) Results of the latest NO2 to NO conversion test 
    (Method 7E only); and
        (X) For each calibration gas cylinder used 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) Test number;
        (B) Run number;
        (C) The beginning date, hour, and minute of the run;
        (D) The ending date, hour, and minute of the run;
        (E) Unit operating level (low, mid, high, or normal, as 
    appropriate);
        (F) Moisture measurement method;
        (G) Volume of H2O collected in the impingers (ml);
        (H) Mass of H2O collected in the silica gel (g);
        (I) Dry gas meter calibration factor;
        (J) Average dry gas meter temperature ( deg.F);
        (K) Barometric pressure (inches of mercury);
        (L) Differential pressure across the orifice meter (inches of 
    H2O);
        (M) Initial and final dry gas meter readings (ft3);
        (N) Total sample gas volume, corrected to standard conditions 
    (dscf); and
        (O) Percentage of moisture in the stack gas (percent 
    H2O).
        (vi) The raw data and calculated results for any stratification 
    tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 of 
    appendix A to this part.
        (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) When hardcopy relative accuracy test reports, certification 
    reports, recertification reports, or semiannual or annual reports for 
    gas or flow rate CEMS are required or requested under Sec. 75.60(b)(6) 
    or Sec. 75.63, the reports shall include, at a minimum, the following 
    elements (as applicable to the type(s) of test(s) performed):
        (i) Summarized test results.
        (ii) DAHS printouts of the CEMS data generated during the 
    calibration error, linearity, cycle time, and relative accuracy tests.
        (iii) For pollutant concentration monitor or diluent monitor 
    relative accuracy tests at normal operating load:
        (A) The raw reference method data from each run, i.e., the data 
    under paragraph (a)(7)(iv)(Q) of this section (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, post-test, 
    pre-run and post-run quality assurance checks (i.e., calibration gas 
    injections) of the reference method analyzers, i.e., the data under 
    paragraphs (a)(7)(iv)(E) through (a)(7)(iv)(N) of this section;
        (C) The raw data and results for any moisture measurements made 
    during the relative accuracy testing, i.e., the data under paragraphs 
    (a)(7)(v)(A) through (a)(7)(v)(O) of this section; and
        (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 relative accuracy tests for flow monitors:
        (A) The raw flow rate reference method data, from Reference Method 
    2 (or its allowable alternatives) under appendix A to part 60 of this 
    chapter, including auxiliary moisture data (often in the form of 
    handwritten data sheets), i.e., the data under paragraphs (a)(7)(ii)(A) 
    through (a)(7)(ii)(T), paragraphs (a)(7)(iii)(A) through 
    (a)(7)(iii)(M), and, if applicable, paragraphs (a)(7)(v)(A) through 
    (a)(7)(v)(O) of this section; and
        (B) The tabulated, final volumetric flow rate values used in the 
    relative accuracy calculations (determined from the flow rate reference 
    method data and other necessary measurements, such as moisture, stack 
    temperature and pressure), 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.
        (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
    
    [[Page 28618]]
    
    technical problems encountered during the testing program.
        (viii) Diagrams illustrating test locations and sample point 
    locations (to verify that locations are consistent with information in 
    the monitoring plan). Include a discussion of any special traversing or 
    measurement scheme. The discussion shall also confirm that sample 
    points satisfy applicable acceptance criteria.
        (ix) Names of key personnel involved in the test program, including 
    test team members, plant contacts, agency representatives and test 
    observers on site.
        (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 in paragraph (a)(7)(ii) of this section, except for 
    paragraphs (a)(7)(ii)(A), (F), (H), (L) and (Q) through (T); and
        (E) The data in paragraph (a)(7)(iii)(A), except on a run basis.
        (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) The data in paragraphs (a)(7)(iv)(B) through (I) and (L) 
    through (O); 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 
    (as applicable):
        (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; and
        (vii) Test code.
        (12) For each request for a quality assurance test extension or 
    exemption, for any loss of exempt status, and for each single-load flow 
    RATA claim pursuant to section 2.3.1.3(c)(3) of appendix B to this 
    part, the owner or operator shall record the following (as applicable):
        (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 usage of fuel other than very low sulfur 
    fuel;
        (G) Year to date hours of non-redundant back-up CEMS usage at the 
    unit/stack; and
        (H) Quarter and year.
        (ii) For a linearity test or flow-to-load ratio test quarterly 
    exemption:
        (A) Component-system identification code;
        (B) Type of test;
        (C) Basis for exemption;
        (D) Quarter and year; and
        (E) Span scale.
        (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;
        (E) Number of unit or stack operating hours from the beginning of 
    the grace period to the completion of the quality assurance test or the 
    maximum allowable grace period; and
        (F) Date and hour of end of grace period.
        (iv) For a fuel flowmeter accuracy test extension:
        (A) Component-system identification code;
        (B) Date of last accuracy test;
        (C) Accuracy test expiration date without extension;
        (D) Accuracy test expiration date with extension;
        (E) Type of extension; and
        (F) Quarter and year.
        (v) For a single-load flow RATA claim:
        (A) Monitoring system identification code;
        (B) Ending date of last annual flow RATA;
        (C) The relative frequency (percentage) of unit or stack operation 
    at each load level (low, mid, and high) since the previous annual flow 
    RATA, to the nearest 0.1 percent.
        (D) End date of the historical load data collection period; and
        (E) Indication of the load level (low, mid or high) claimed for the 
    single-load flow RATA.
        (13) An indication that data have been excluded from a periodic 
    span and range evaluation of an SO2 or NOX 
    monitor under section 2.1.1.5 or 2.1.2.5 of appendix A to this part and 
    the reason(s) for excluding the data. For purposes of reporting under 
    Sec. 75.64(a)(2), 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 certification and quality assurance testing of fuel 
    flowmeters tested against a reference fuel flow rate (i.e., flow rate 
    from 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) Unit or common pipe header identification code;
        (ii) Component and system identification codes of the fuel 
    flowmeter being tested;
        (iii) Date and hour of test completion, for a test performed in-
    line at the unit;
        (iv) Date and hour of flowmeter reinstallation, for laboratory 
    tests;
        (v) Test number;
        (vi) Upper range value of the fuel flowmeter;
        (vii) Flowmeter measurements during accuracy test (and mean of 
    values), including units of measure;
        (viii) Reference flow rates during accuracy test (and mean of 
    values), including units of measure;
    
    [[Page 28619]]
    
        (ix) Level of fuel flowrate test during runs (low, mid or high);
        (x) Average flowmeter accuracy for low and high fuel flowrates and 
    highest flowmeter accuracy of any level designated as mid, expressed as 
    a percent of upper range value;
        (xi) Indicator of whether test method was a lab comparison to 
    reference meter or an in-line comparison against a master meter;
        (xii) Test result (aborted, pass, or fail); and
        (xiii) 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) Component and system identification codes of the fuel flowmeter 
    being tested;
        (ii) Completion date and hour of test;
        (iii) For each transmitter or transducer: transmitter or transducer 
    type (differential pressure, static pressure, or temperature); the 
    full-scale value of the transmitter or transducer, transmitter input 
    (pre-calibration) prior to accuracy test, including units of measure; 
    and expected transmitter output during accuracy test (reference value 
    from NIST-traceable equipment), including units of measure;
        (iv) For each transmitter or transducer tested: output during 
    accuracy test, including units of measure; transmitter or transducer 
    accuracy as a percent of the full-scale value; and transmitter output 
    level as a percent of the full-scale value;
        (v) Average flowmeter accuracy at low and high fuel flowrates and 
    highest flowmeter accuracy of any level designated as mid fuel 
    flowrate, expressed as a percent of upper range value;
        (vi) Test result (pass, fail, or aborted);
        (vii) Test number; and
        (viii) Accuracy determination methodology.
        (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 2.1.6.4 of appendix D to this part:
        (i) Date of inspection/test;
        (ii) Hour of completion of inspection/test;
        (iii) Component and system identification codes 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 optional fuel 
    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 fuel flow-to-load ratio 
    or gross heat rate;
        (D) Quarterly average absolute percent difference between baseline 
    for fuel flow-to-load ratio (or baseline gross heat rate and hourly 
    quarterly fuel flow-to-load ratios (or gross heat rate value);
        (E) Test result;
        (F) Number of hours used in the analysis;
        (G) Number of hours excluded due to co-firing;
        (H) Number of hours excluded due to ramping; and
        (I) Number of hours excluded in lower 25.0 percent range of 
    operation.
        (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 date and hour of baseline period;
        (D) Completion date and hour of baseline period;
        (E) Average fuel flow rate, in 100 scfh for gas and lb/hr for oil;
        (F) Average load, in megawatts or 1000 lb/hr of steam;
        (G) Baseline fuel flow-to-load ratio, in the appropriate units of 
    measure (if using fuel flow-to-load ratio);
        (H) Baseline gross heat rate if using gross heat rate, in the 
    appropriate units of measure (if using gross heat rate check);
        (I) Number of hours excluded from baseline data due to ramping;
        (J) Number of hours excluded from baseline data in lower 25.0 
    percent of range of operation;
        (K) Average hourly heat input rate; and
        (L) Flag indicating baseline data collection is in progress and 
    that fewer than four calendar quarters have elapsed since the quarter 
    of the last flowmeter QA test.
        (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, record the following data:
        (A) Unit or common pipe identification code;
        (B) Monitoring system identification code for appendix E system;
        (C) Run start date and time;
        (D) Run end date and time;
        (E) Total heat input during the run (mmBtu);
        (F) NOX emission rate (lb/mmBtu) from reference method;
        (G) Response time of the O2 and NOX reference 
    method analyzers;
        (H) Type of fuel(s) combusted during the run;
        (I) Heat input rate (mmBtu/hr) during the run;
        (J) Test number;
        (K) Run number;
        (L) Operating level during the run;
        (M) NOX concentration recorded by the reference method 
    during the run;
        (N) Diluent concentration recorded by the reference method during 
    the run; and
        (O) Moisture measurement for the run (if applicable).
        (ii) For each run during which oil or mixed fuels are combusted 
    record the following data:
        (A) Unit or common pipe identification code;
        (B) Monitoring system identification code for oil monitoring 
    system;
        (C) Run start date and time;
        (D) Run end date and time;
        (E) Mass flow or volumetric flow of oil, in the units of measure 
    for the type of fuel flowmeter;
        (F) Gross calorific value of oil in the appropriate units of 
    measure;
        (G) Density of fuel oil in the appropriate units of measure (if 
    density is used to convert oil volume to mass);
        (H) Hourly heat input (mmBtu) during run from oil;
        (I) Test number;
        (J) Run number; and
        (K) Operating level during the run.
        (iii) For each run during which gas or mixed fuels are combusted 
    record the following data:
        (A) Unit or common pipe identification code;
        (B) Monitoring system identification code for gas monitoring 
    system;
        (C) Run start date and time;
        (D) Run end date and time;
        (E) Volumetric flow of gas (100 scf);
        (F) Gross calorific value of gas (Btu/100 scf);
        (G) Hourly heat input (mmBtu) during run from gas;
        (H) Test number;
        (I) Run number; and
        (J) Operating level during the run.
        (iv) For each operating level at which runs were performed:
        (A) Completion date and time of last run for operating level;
    
    [[Page 28620]]
    
        (B) Type of fuel(s) combusted during test;
        (C) Average heat input rate at that operating level (mmBtu/hr);
        (D) Arithmetic mean of NOX emission rates from reference 
    method run at this level;
        (E) F-factor used in calculations of NOX emission rate 
    at that operating level;
        (F) Unit operating parametric data related to NOX 
    formation for that unit type (e.g., excess O2 level, water/
    fuel ratio);
        (G) Test number; and
        (H) Operating level for runs.
        (c) 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 keep the following records on-site in the 
    quality assurance/quality control plan required by section 1 of 
    appendix B to this part:
        (1) A list of operating parameters for the add-on emission 
    controls, including parameters in Sec. 75.55(b) or Sec. 75.58(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 monitoring for low mass emissions units under 
    Sec. 75.19(c)(1)(iv). For oil-and gas-fired units using the optional 
    SO2, NOX and CO2 emissions 
    calculations for low mass emission units under Sec. 75.19, the owner or 
    operator shall record the following information for tests performed to 
    determine a fuel and unit-specific default as provided in 
    Sec. 75.19(c)(1)(iv):
        (1) For each run of each test performed under section 2.1 of 
    appendix E to this part, record the following data:
        (i) Unit or common pipe identification code;
        (ii) Run start date and time;
        (iii) Run end date and time;
        (iv) NOX emission rate (lb/mmBtu) from reference method;
        (v) Response time of the O2 and NOX reference 
    method analyzers;
        (vi) Type of fuel(s) combusted during the run;
        (vii) Test number;
        (viii) Run number;
        (ix) Operating level during the run;
        (x) NOX concentration recorded by the reference method 
    during the run;
        (xi) Diluent concentration recorded by the reference method during 
    the run;
        (xii) Moisture measurement for the run (if applicable);
        (xiii) An indicator that the resulting NOX emission rate 
    is the highest NOX emission rate record during any run of 
    the test (if appropriate);
        (xiv) The default NOX emission rate (highest 
    NOX emission rate value during the test multiplied by 1.15);
        (xv) An indicator that control equipment was operating or not 
    operating during each run of the test; and
        (xvi) Parameter data indicating the use and efficacy of control 
    equipment during the test.
        (2) For each unit in a group of identical units qualifying for 
    reduced testing under Sec. 75.19(c)(1)(iv)(B), record the following 
    data:
        (i) The unique group identification code assigned to the group. 
    This code must include the ORIS code of one of the units in the group;
        (ii) The ORIS code or facility identification code for the unit;
        (iii) The plant name of the facility at which the unit is located, 
    consistent with the facility's monitoring plan;
        (iv) The identification code for the unit, consistent with the 
    facility's monitoring plan;
        (v) A record of whether or not the unit underwent fuel and unit-
    specific testing for purposes of establishing a fuel and unit-specific 
    NOX emission rate for purposes of Sec. 75.19;
        (vi) The completion date of the fuel and unit-specific test 
    performed for purposes of establishing a fuel and unit-specific 
    NOX emission rate for purposes of Sec. 75.19;
        (vii) The fuel and unit-specific NOX default rate 
    established for the group of identical units under Sec. 75.19;
        (viii) The type of fuel combusted for the units during testing and 
    represented by the resulting default NOX emission rate;
        (ix) The control status for the units during testing and 
    represented by the resulting default NOX emission rate;
        (x) Documentation supporting the qualification of all units in the 
    group for reduced testing based on the criteria established in 
    Secs. 75.19(c)(1)(iv)(B)(1) and (3); and
        (xi) Purpose of group tests.
    
    Subpart G--Reporting Requirements
    
        43. 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 signatory 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) Semiannual or annual 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 a hardcopy RATA report within 45 days after completing a 
    required semiannual or annual 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)(9) to the applicable EPA 
    Regional Office, appropriate State, and/or appropriate local air 
    pollution control agency that requested the RATA report.
    * * * * *
        44. Section 75.61 is amended by revising paragraphs (a) 
    introductory text, (a)(1) introductory text, and (b), by adding a new 
    sentence to the end of paragraph (a)(6)(ii), 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
    
    [[Page 28621]]
    
    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 to this part, except as provided in 
    paragraphs (a)(1)(iii), (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 notification 
    requirement of paragraph (a)(1) of this section, 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 reinstate 
    the notification requirement of paragraph (a)(1) of this section for 
    future recertification tests of a unit or a group of units.
    * * * * *
        (6) * * *
        (ii) * * * The reporting requirements of this paragraph (a)(6)(ii) 
    also shall apply if the designated representative of a unit is exempt 
    from certifying a fuel flowmeter for use during the combustion of 
    emergency fuel under section 2.1.4.3 of appendix D to this part.
        (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.
    * * * * *
        45. Section 75.62 is amended by revising the title of the section 
    and revising paragraphs (a) and (c) to read as follows:
    
    
    Sec. 75.62  Monitoring plan submittals.
    
        (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 as follows: 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 
    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 as 
    follows: 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). Electronic submittal of all 
    monitoring plan information, including hardcopy portions, is 
    permissible provided that a paper copy of the hardcopy portions can be 
    furnished upon request.
    * * * * *
        (c) Format. The designated representative shall submit each 
    monitoring plan in a format specified by the Administrator.
        46. Section 75.63 is revised to read as follows:
    
    
    Sec. 75.63  Initial certification or recertification application 
    submittals.
    
        (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 for alternative monitoring systems 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) 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), the hardcopy information required by paragraph 
    (b)(2), and a hardcopy certification application form (EPA form 7610-
    14); and
        (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).
        (2) Recertifications. (i) Within 45 days after completing all 
    recertification tests, submit to the Administrator the electronic 
    information required by paragraph (b)(1) and a hardcopy certification 
    application form (EPA form 7610-14). Except for subpart E applications 
    for alternative monitoring systems 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) 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 reinstate 
    the requirement of this paragraph 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, 
    no hardcopy submittal 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; the owner or operator shall keep these test results 
    on-site in a format 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 Secs. 75.53(c) 
    and (d), or Secs. 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
    
    [[Page 28622]]
    
    Sec. Sec. 75.53(c) and (d), or Secs. 75.53(e) and (f), as applicable. 
    Electronic submittal of all monitoring plan information, including the 
    hardcopy portions, is permissible, provided that a paper copy can be 
    furnished upon request.
        (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)(9), 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.
        (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)(9).
        47. Section 75.64 is revised 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); or 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. The initial 
    quarterly report shall contain 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 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 unit recommences commercial operation (where the initial quarterly 
    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)(11) 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 for the data contained in the report; 
    and
        (C) Version of the electronic data reporting format 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 the following:
        (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)(8);
        (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 April 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;
        (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 monitor and moisture monitoring system 
    polynomial equations, coefficients or ``K'' factors required by 
    Sec. 75.56(a)(5)(vii), Sec. 75.56(a)(5)(ix), Sec. 75.59(a)(5)(vi) or 
    Sec. 75.59(a)(5)(vii);
        (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)(vi), (vii), (viii), 
    (ix), and (xiii), and (b)(2)(iii) and (iv) 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 problems unrelated to monitor performance; and
        (xiv) Supplementary RATA information required under 
    Sec. 75.59(a)(7)(i) through Sec. 75.59(a)(7)(v), except that: the data 
    under Sec. 75.59(a)(7)(ii)(A) through (T) and the data under 
    Sec. 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported 
    for flow RATAs in which angular compensation (measurement of pitch and/
    or yaw angles) is used and for flow RATAs in which a site-specific wall 
    effects adjustment factor is determined by direct measurement; and the 
    data under Sec. 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs 
    in which a default wall effects adjustment factor is applied.
        (3) Tons (rounded to the nearest tenth) of SO2 emitted 
    during the quarter and cumulative SO2 emissions for the 
    calendar year.
        (4) Average NOX emission rate (lb/mmBtu, rounded to the 
    nearest hundredth prior to April 1, 2000 and to the nearest thousandth 
    on and after April 1, 2000) during the quarter and cumulative 
    NOX emission rate for the calendar year.
        (5) Tons of CO2 emitted during quarter and cumulative 
    CO2 emissions for calendar year.
        (6) Total heat input (mmBtu) for quarter and cumulative heat input 
    for calendar year.
        (7) Unit or stack or common pipe header operating hours for quarter 
    and cumulative unit or stack or common pipe header operating hours for 
    calendar year.
        (8) If the affected unit is using a qualifying Phase I technology, 
    then the quarterly report shall include the information required in 
    paragraph (e) of this section.
        (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.
        (10) For low mass emissions units using the optional long term fuel 
    flow methodology under Sec. 75.19(c), for each quarter report the long 
    term fuel flow for each fuel according to Sec. 75.59.
        (11) For units using the optional fuel flow to load procedure in 
    section 2.1.7 of appendix D to this part, report both the fuel flow-to-
    load baseline data and
    
    [[Page 28623]]
    
    the results of the fuel flow-to-load test each quarter.
        (b) The designated representative shall affirm that the component/
    system identification codes and formulas in the quarterly electronic 
    reports, submitted to the Administrator pursuant to Sec. 75.53, 
    represent current operating conditions.
        (c) Compliance certification. The designated representative shall 
    submit a 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 indicate 
    whether the monitoring data submitted were recorded in accordance with 
    the applicable requirements of this part including the quality control 
    and quality assurance procedures and specifications of this part and 
    its appendices, and any such requirements, procedures and 
    specifications of an applicable excepted or approved alternative 
    monitoring method. For a unit with add-on emission controls, the 
    designated representative shall also include a certification, for all 
    hours where data are substituted following the provisions of 
    Sec. 75.34(a)(1), that the add-on emission controls were operating 
    within the range of parameters listed in the monitoring plan and that 
    the substitute values recorded during the quarter do not systematically 
    underestimate SO2 or NOX emissions, pursuant to 
    Sec. 75.34.
        (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 2001, 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.
        48. 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.
        49. Section 75.66 is amended by revising paragraph (a) and the 
    first sentence of paragraph (e) introductory text; by redesignating 
    paragraph (i) as paragraph (l) and revising it; and by adding 
    paragraphs (i) through (k) 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 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 to this part. 
    The designated representative shall include the following information 
    in the petition:
        (1) Identification of the affected plant and 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) 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 to 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 to 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) Any other petitions to the Administrator under this part. 
    Except for petitions addressed in paragraphs (b) through (k) 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 plant and 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.
    
    [[Page 28624]]
    
    Subpart H--NOX Mass Emissions Provisions
    
        50. Section 75.70 is amended by revising paragraphs (e), (f) 
    introductory text and (f)(1)(iv), and by adding new paragraph (g)(6) to 
    read as follows:
    
    
    Sec. 75.70  NOX mass emissions provisions.
    
    * * * * *
        (e) Quality assurance and quality control requirements. For units 
    that use continuous emission monitoring systems to account for 
    NOX mass emissions, the owner or operator shall meet the 
    applicable quality assurance and quality control requirements in 
    Sec. 75.21, appendix B to this part, and Sec. 75.74(c) for the 
    NOX-diluent continuous emission monitoring systems, flow 
    monitoring systems, NOX concentration monitoring systems, 
    and diluent monitors required under Sec. 75.71. A NOX 
    concentration monitoring system for determining NOX mass 
    emissions in accordance with Sec. 75.71 shall meet the same 
    certification testing requirements, quality assurance requirements, and 
    bias test requirements as are specified in this part for an 
    SO2 pollutant concentration monitor, except as otherwise 
    provided in Sec. 75.74(c). Units using excepted methods under 
    Sec. 75.19 shall meet the applicable quality assurance requirements of 
    that section, and, except as otherwise provided in Sec. 75.74(c), units 
    using excepted monitoring methods under appendices D and E to this part 
    shall meet the applicable quality assurance requirements of those 
    appendices.
        (f) Missing data procedures. Except as provided in Sec. 75.34, 
    paragraph (g) of this section, and Sec. 75.74, the owner or operator 
    shall provide substitute data from monitoring systems required under 
    Sec. 75.71 for each affected unit as follows:
        (1) * * *
        (iv) A valid, quality-assured hour of NOX concentration 
    data (in ppm) has not been measured and recorded by a certified 
    NOX concentration monitoring system, or by an approved 
    alternative monitoring method under subpart E of this part, where the 
    owner or operator chooses to use a NOX concentration 
    monitoring system with a volumetric flow monitor, and without a diluent 
    monitor to calculate NOX mass emissions. The initial missing 
    data procedures for determining monitor data availability and the 
    standard missing data procedures for a NOX concentration 
    monitoring system shall be the same as the procedures specified for a 
    NOX-diluent continuous emission monitoring system under 
    Secs. 75.31, 75.32 and 75.33.
    * * * * *
        (g) * * *
        (6) For any unit using continuous emissions monitors, the 
    procedures in Sec. 75.20(b)(3).
    * * * * *
        51. Section 75.71 is amended by revising paragraphs (b) and (d)(2) 
    to read as follows:
    
    
    Sec. 75.71  Specific provisions for monitoring NOX emission 
    rate and heat input for the purpose of calculating NOX mass 
    emissions.
    
    * * * * *
        (b) Moisture correction. (1) 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 in a NOX-diluent monitoring system 
    measures on a different moisture basis from the diluent monitor), the 
    owner or operator of an affected unit shall account for the moisture 
    content of the flue gas on a continuous basis in accordance with 
    Sec. 75.12(b).
        (2) If a correction for the stack gas moisture content is needed to 
    properly calculate NOX mass emissions in tons, in the case 
    where a NOX concentration monitoring system which measures 
    on a dry basis is used with a flow rate monitor to determine 
    NOX mass emissions, the owner or operator of an affected 
    unit shall account for the moisture content of the flue gas on a 
    continuous basis in accordance with Sec. 75.11(b) except that the term 
    ``SO2'' shall be replaced by the term ``NOX.''
        (3) If a correction for the stack gas moisture content is needed to 
    properly calculate NOX mass emissions, in the case where a 
    diluent monitor that measures on a dry basis is used with a flow rate 
    monitor to determine heat input, which is then multiplied by the 
    NOX emission rate, the owner or operator shall install, 
    operate, maintain and quality assure a continuous moisture monitoring 
    system, as described in Sec. 75.11(b).
    * * * * *
        (d) * * *
        (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, the operation 
    of a unit that reports emissions on an annual basis under Sec. 75.74(a) 
    of this part exceeds a capacity factor of 20.0 percent in any calendar 
    year or exceeds an annual capacity factor of 10.0 percent averaged over 
    three years, or the operation of a unit that reports emissions on an 
    ozone season basis under Sec. 75.74(b) of this part exceeds a capacity 
    factor of 20.0 percent in any ozone season or exceeds an ozone season 
    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 calendar year.
    * * * * *
        52. Text is added to reserved section 75.73 to read as follows:
    
    
    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)(2) or (b)(3) (for 
    units with add-on NOX emission controls), as applicable, (d) 
    (as applicable for units using Appendix E to this part), and (f) (as 
    applicable for units using the low mass emissions unit provisions of 
    Sec. 75.19).
        (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
    
    [[Page 28625]]
    
    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 mass flow rate of oil, while the unit combusts 
    oil (in lb/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) For units using volumetric flowmeters, volumetric flow rate of 
    oil combusted each hour (in gal/hr, lb/hr, m3/hr, or bbl/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 of oil used to determine heat input (in 
    Btu/lb);
        (G) Hourly heat input rate during combustion of 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:
        (A) Measured gross calorific value and, if measuring with 
    volumetric oil flowmeters, density from each fuel sample; and
        (B) Assumed gross calorific value and, if measuring with volumetric 
    oil flowmeters, 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 of gaseous fuel used to determine heat 
    input rate (in Btu/100 scf) (flag value if derived from missing data 
    procedures);
        (E) 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
        (F) Monitoring system identification code.
        (iv) For each oil sample or sample of diesel fuel:
        (A) Date of sampling;
        (B) Gross calorific value (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 (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 Secs. 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 recordkeeping 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 Secs. 75.53(f)(1)(i), (f)(2)(i), (f)(4), and (f)(5)(i) for units 
    using the low mass emitter methodology in electronic format and the 
    information in Secs. 75.53(f)(1)(ii), (f)(2)(ii), and (f)(5)(ii) in 
    hardcopy format. The monitoring plan also shall identify, in electronic 
    format, the reporting schedule for the affected unit (ozone season or 
    quarterly), the beginning and end dates for the reporting schedule, and 
    whether year-round reporting for the unit is required by a state or 
    local agency.
        (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):
    
    [[Page 28626]]
    
        (i) Initial certification and recertification 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(h).
        (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)(9) 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 plan reporting.--(1) Electronic submission. 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)(2) 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:
        (i) To the permitting authority, no later than 45 days prior to the 
    initial certification test and at the time of recertification 
    application submission; and
        (ii) To the Administrator, no later than 45 days prior to the 
    initial certification test, at the time of submission of a 
    recertification application, and in each electronic quarterly report.
        (2) Hardcopy submission. The designated representative of an 
    affected unit shall 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 as 
    follows: 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).
        (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 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 (f)(1)(ii) through (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) Electronic data reporting format version used for the report.
        (B) Location of facility, including:
        (1) Plant name and facility identification code;
        (2) EPA AIRS facility system identification code;
        (3) State facility identification code;
        (4) Source category/type;
        (5) Primary SIC code;
        (6) State postal abbreviation;
        (7) FIPS 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 
    or transducer accuracy tests;
        (I) Stratification test results required as part of the RATA 
    supplementary records under 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) Supplementary RATA information required under 
    Sec. 75.59(a)(7)(i) through Sec. 75.59(a)(7)(v), except that: the data 
    under Sec. 75.59(a)(7)(ii)(A) through (T) and the data under 
    Sec. 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported 
    for flow RATAs in which angular compensation (measurement of pitch and/
    or yaw angles) is used and for flow RATAs in which a site-specific wall 
    effects adjustment factor is determined by direct measurement; and the 
    data under Sec. 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs 
    in which a default wall effects adjustment factor is applied.
        (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 calendar quarters, cumulative tons of NOX emitted 
    during the ozone season.
        (v) During the second and third calendar quarters, cumulative heat 
    input for the ozone season.
        (vi) Unit or stack or common pipe header operating hours for 
    quarter, cumulative unit, stack or common pipe header operating hours 
    for calendar year, and, during the second and third calendar quarters, 
    cumulative operating hours during the ozone season.
        (2) The designated representative shall certify that the component 
    and 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
    
    [[Page 28627]]
    
    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).
        53. Section 75.74 is amended by:
        a. Revising paragraphs (b)(2), (c)(1) and (c)(2);
        b. Redesignating paragraphs (c)(3), (c)(4), (c)(5), (c)(6), (c)(7), 
    (c)(8), (c)(9) and (c)(10), as paragraphs (c)(4), (c)(5), (c)(6), 
    (c)(7), (c)(8), (c)(9), (c)(10) and (c)(11), respectively;
        c. Adding a new paragraph (c)(3); and
        d. Revising newly redesignated paragraphs (c)(4), (c)(5), (c)(6) 
    and (c)(7), to read as follows:
    
    
    Sec. 75.74  Annual and ozone season monitoring and reporting 
    requirements.
    
    * * * * *
        (b) * * *
        (2) Meet the requirements of this subpart during the ozone season, 
    except as specified in paragraph (c) of this section.
        (c) * * *
        (1) The owner or operator of a unit that uses continuous emissions 
    monitoring systems or a fuel flowmeter to meet any of the requirements 
    of this subpart shall quality assure the hourly ozone season emission 
    data required by this subpart. To achieve this, the owner or operator 
    shall operate, maintain and calibrate each required CEMS and shall 
    perform diagnostic testing and quality assurance testing of each 
    required CEMS or fuel flowmeter according to the applicable provisions 
    of paragraphs (c)(2) through (c)(5) of this section. Except where 
    otherwise noted, the provisions of paragraphs (c)(2) and (c)(3) of this 
    section apply instead of the quality assurance provisions in sections 
    2.1 through 2.3 of appendix B to this part, and shall be used in lieu 
    of those appendix B provisions.
        (2) Quality assurance requirements prior to the ozone season. The 
    provisions of this paragraph apply to each ozone season. In the time 
    period prior to the start of the current ozone season (i.e., in the 
    period extending from October 1 of the previous calendar year through 
    April 30 of the current calendar year), the owner or operator shall, at 
    a minimum, perform the following diagnostic testing and quality 
    assurance assessments, and shall maintain the following records, to 
    ensure that the hourly emission data recorded at the beginning of the 
    current ozone season are suitable for reporting as quality-assured 
    data:
        (i) For each required gas monitor (i.e., for each NOX 
    pollutant concentration monitor and each diluent gas (CO2 or 
    O2) monitor, including CO2 and O2 
    monitors used exclusively for heat input determination and 
    O2 monitors used for moisture determination), a linearity 
    check shall be performed and passed.
        (A) Conduct each linearity check in accordance with the general 
    procedures in section 6.2 of appendix A to this part, except that the 
    data validation procedures in sections 6.2(a) through (f) of appendix A 
    do not apply.
        (B) Each linearity check shall be done ``hands-off,'' as described 
    in section 2.2.3(c) of appendix B to this part.
        (C) In the time period extending from the date and hour in which 
    the linearity check is passed through April 30 of the current calendar 
    year, the owner or operator shall operate and maintain the CEMS and 
    shall perform daily calibration error tests of the CEMS in accordance 
    with section 2.1 of appendix B to this part. When a calibration error 
    test is failed, as described in section 2.1.4 of appendix B to this 
    part, corrective actions shall be taken. The additional calibration 
    error test provisions of section 2.1.3 of appendix B to this part shall 
    be followed. Records of the required daily calibration error tests 
    shall be kept in a format suitable for inspection on a year-round 
    basis.
        (D) Exceptions. (1) If the monitor passed a linearity check on or 
    after January 1 of the previous year and the unit or stack on which the 
    monitor is located operated for less than 336 hours in the previous 
    ozone season, the owner or operator may have a grace period of up to 
    168 hours to perform a linearity check. In addition, if the unit or 
    stack operates for 168 hours or less in the current ozone season the 
    owner or operator is exempt from the linearity check requirement for 
    that ozone season and the owner or operator may submit quality assured 
    data from that monitor as long as all other required quality assurance 
    tests are passed. If the unit or stack operates for more than 168 hours 
    in the current ozone season, the owner or operator of the unit shall 
    report substitute data using the missing data procedures under 
    paragraph (c)(7) of this section starting with the 169th unit or stack 
    operating hour of the ozone season and continuing until the successful 
    completion of a linearity check.
        (2) If a monitor does not qualify for an exception under paragraph 
    (c)(2)(i)(D)(1) and if a required linearity check has not been 
    completed prior to the start of the current ozone season, follow the 
    applicable procedures in paragraph (c)(3)(vi) of this section.
        (ii) For each required CEMS (i.e., for each NOX 
    concentration monitoring system, each NOX-diluent monitoring 
    system, each flow rate monitoring system, each moisture monitoring 
    system and each diluent gas CEMS used exclusively for heat input 
    determination), a relative accuracy test audit (RATA) shall be 
    performed and passed.
        (A) Conduct each RATA in accordance with the applicable procedures 
    in sections 6.5 through 6.5.10 of appendix A to this part, except that 
    the data validation procedures in sections 6.5(f)(1) through (f)(6) do 
    not apply, and, for flow rate monitoring systems, the required RATA 
    load level(s) shall be as specified in this paragraph.
        (B) Each RATA shall be done ``hands-off,'' as described in section 
    2.3.2 (c) of appendix B to this part. The provisions in section 2.3.1.4 
    of appendix B to this part, pertaining to the number of allowable RATA 
    attempts, shall apply.
        (C) For flow rate monitoring systems installed on peaking units or 
    bypass stacks, a single-load RATA is required. For all other flow rate 
    monitoring systems, a 2-load RATA is required at the two most 
    frequently-used load levels (as defined under section 6.5.2.1 of 
    appendix A to this part), with the following exceptions. A 3-load flow 
    RATA is required at least once in every period of five consecutive 
    calendar years. A 3-load RATA is also required if the flow monitor 
    polynomial coefficients or K factor(s) are changed prior to conducting 
    the flow RATA required under this paragraph.
        (D) A bias test of each required NOX concentration 
    monitoring system, each NOX-diluent monitoring system and 
    each flow rate monitoring system shall be performed in accordance with 
    section 7.6 of appendix A to this part. If the bias test is failed, a 
    bias adjustment factor (BAF) shall be calculated for the monitoring 
    system, as described in section 7.6.5 of appendix A to this part and 
    shall be applied to the subsequent data recorded by the CEMS.
    
    [[Page 28628]]
    
        (E) In the time period extending from the hour of completion of the 
    required RATA through April 30 of the current calendar year, the owner 
    or operator shall operate and maintain the CEMS by performing, at a 
    minimum, the following activities:
        (1) The owner or operator shall perform daily calibration error 
    tests and (if applicable) daily flow monitor interference checks, 
    according to section 2.1 of appendix B to this part. When a daily 
    calibration error test or interference check is failed, as described in 
    section 2.1.4 of appendix B to this part, corrective actions shall be 
    taken. The additional calibration error test provisions in section 
    2.1.3 of appendix B to this part shall be followed. Records of the 
    required daily calibration error tests and interference checks shall be 
    kept in a format suitable for inspection on a year-round basis.
        (2) If the owner or operator makes a replacement, modification, or 
    change in a certified monitoring system that significantly affects the 
    ability of the system to accurately measure or record NOX 
    mass emissions or heat input or to meet the requirements of Sec. 75.21 
    or appendix B to this part, the owner or operator shall recertify the 
    monitoring system according to Sec. 75.20(b).
        (F) If the results of a RATA performed according to the provisions 
    of this paragraph indicate that the CEMS qualifies for an annual RATA 
    frequency (see Figure 2 in appendix B to this part), the RATA may be 
    used to quality assure data for the entire current ozone season.
        (G) If the results of a RATA performed according to the provisions 
    of this paragraph indicate that the CEMS qualifies for a semiannual 
    RATA frequency rather than an annual frequency, provided that the RATA 
    was completed on or after January 1 of the current calendar year, the 
    RATA may be used to quality assure data for the entire current ozone 
    season. However, if the RATA was performed in the fourth calendar 
    quarter of the previous year, the RATA may only be used to quality 
    assure data for a part of the current ozone season, from May 1 through 
    June 30. An additional RATA is then required by June 30 of the current 
    calendar year to quality assure the remainder of the data (from June 30 
    through September 30) for the current ozone season. If such an 
    additional RATA is required but is not completed by June 30 of the 
    current calendar year, data from the CEMS shall be considered invalid 
    as of the first unit or stack operating hour subsequent to June 30 of 
    the current calendar year and shall remain invalid until the required 
    RATA is performed and passed.
        (H) Exceptions. (1) If the monitoring system passed a RATA on or 
    after January 1 of the previous year and the unit or stack on which the 
    monitor is located operated for less than 336 hours in the previous 
    ozone season, the owner or operator may have a grace period of up to 
    720 hours to perform a RATA. If the unit or stack operates for 720 
    hours or less in the current ozone season, the owner or operator of the 
    unit is exempt from the requirement to perform a RATA for that ozone 
    season and the owner or operator may submit quality assured data from 
    that monitor as long as all other required quality assurance tests are 
    passed. If the unit or stack operates for more than 720 hours in the 
    current ozone season, the owner or operator of the unit or stack shall 
    report substitute data using the missing data procedures under 
    paragraph (c)(7) of this section, starting with the 721st unit 
    operating hour and continuing until the successful completion of the 
    RATA.
        (2) If a monitor does not qualify for a grace period under 
    paragraph (c)(2)(ii)(H)(1) of this section and if a required RATA has 
    not been completed prior to the start of the current ozone season, 
    follow the applicable procedures in paragraph (c)(3)(vi) of this 
    section.
        (3) Quality assurance requirements within the ozone season. The 
    provisions of this paragraph apply to each ozone season. The owner or 
    operator shall, at a minimum, perform the following quality assurance 
    testing during the ozone season, i.e. in the time period extending from 
    May 1 through September 30 of each calendar year:
        (i) Daily calibration error tests and (if applicable) interference 
    checks of each CEMS required by this subpart shall be performed in 
    accordance with sections 2.1.1 and 2.1.2 of appendix B to this part. 
    The applicable provisions in sections 2.1.3, 2.1.4 and 2.1.5 of 
    appendix B to this part, pertaining, respectively, to additional 
    calibration error tests and calibration adjustments, data validation, 
    and quality assurance of data with respect to daily assessments, shall 
    also apply.
        (ii) For each gas monitor required by this subpart, linearity 
    checks shall be performed in the second and third calendar quarters, in 
    accordance with section 2.2.1 of appendix B to this part (see also 
    paragraph (c)(3)(vii) of this section). For the second calendar quarter 
    of the year, only unit or stack operating hours in the months of May 
    and June shall be included when determining whether the second calendar 
    quarter is a ``QA operating quarter'' (as defined in Sec. 72.2 of this 
    chapter). Data validation for these linearity checks shall be done in 
    accordance with sections 2.2.3(a) through (e) of appendix B to this 
    part. The grace period provision in section 2.2.4 of appendix B to this 
    part does not apply to these linearity checks. If the required 
    linearity check has not been completed by the end of the calendar 
    quarter, unless the conditional data validation provisions of 
    Sec. 75.20(b)(3) are applied, data from the CEMS are considered to be 
    invalid, beginning with the first unit or stack operating hour after 
    the end of the quarter and shall remain invalid until a linearity check 
    of the CEMS is performed and passed.
        (iii) For each flow monitoring system required by this subpart, 
    flow-to-load ratio tests are required in the second and third calendar 
    quarters, in accordance with section 2.2.5 of appendix B to this part. 
    If the flow-to-load ratio test for the second calendar quarter is 
    failed, the owner or operator shall declare the flow monitor out-of-
    control as of the first unit or stack operating hour following the 
    second calendar quarter and shall either implement Option 1 in section 
    2.2.5.1 of appendix B to this part or Option 2 in section 2.2.5.2 of 
    appendix B to this part. If the flow-to-load ratio test for the third 
    calendar quarter is failed, data from the flow monitor shall be 
    considered invalid at the beginning of the next ozone season unless, 
    prior to May 1 of the next calendar year, the owner or operator has 
    either successfully implemented Option 1 in section 2.2.5.1 of appendix 
    B to this part or Option 2 in section 2.2.5.2 of appendix B to this 
    part, or unless a flow RATA has been performed and passed in accordance 
    with paragraph (c)(2)(ii) of this section.
        (iv) For each differential pressure-type flow monitor used to meet 
    the requirements of this subpart, quarterly leak checks are required in 
    the second and third calendar quarters, in accordance with section 
    2.2.2 of appendix B to this part. For the second calendar quarter of 
    the year, only unit or stack operating hours in the months of May and 
    June shall be included when determining whether the second calendar 
    quarter is a QA operating quarter (as defined in Sec. 72.2 of this 
    chapter). Data validation for quarterly flow monitor leak checks shall 
    be done in accordance with section 2.2.3(g) of appendix B to this part. 
    If the leak check for the third calendar quarter is failed and a 
    subsequent leak check is not passed by the end of the ozone season, 
    then data from the flow monitor shall be considered invalid at the 
    beginning of the next ozone season unless a leak
    
    [[Page 28629]]
    
    check is passed prior to May 1 of the next calendar year.
        (v) A fuel flow-to-load ratio test in section 2.1.7 of appendix D 
    to this part shall be performed in the second and third calendar 
    quarters if, for a unit using a fuel flowmeter to determine heat input 
    under this subpart, the owner or operator has elected to use the fuel 
    flow-to-load ratio test to extend the deadline for the next fuel 
    flowmeter accuracy test. If a fuel flow-to-load ratio test is failed, 
    follow the applicable procedures and data validation provisions in 
    section 2.1.7.4 of appendix D to this part. If the fuel flow-to-load 
    ratio test for the third calendar quarter is failed, data from the fuel 
    flowmeter shall be considered invalid at the beginning of the next 
    ozone season unless the requirements of section 2.1.7.4 of appendix D 
    to this part have been fully met prior to May 1 of the next calendar 
    year.
        (vi) If, at the start of the current ozone season (i.e., as of May 
    1 of the current calendar year), the linearity check or RATA required 
    under paragraph (c)(2)(i) or (c)(2)(ii) of this section has not been 
    performed for a particular monitor or monitoring system, and if, during 
    the previous ozone season, the unit or stack on which the monitoring 
    system is installed operated for 336 hours or more the owner or 
    operator shall invalidate all data from the CEMS until either:
        (A) The required linearity check or RATA of the CEMS has been 
    performed and passed; or
        (B) A ``probationary calibration error test'' of the CEMS is passed 
    in accordance with Sec. 75.20(b)(3). Note that a calibration error test 
    passed on April 30 may be used as the probationary calibration error 
    test, to ensure that emission data recorded by the CEMS at the 
    beginning of the ozone season will have a conditionally valid status. 
    Once the probationary calibration error test has been passed, the owner 
    or operator shall perform the required linearity check or RATA in 
    accordance with the conditional data validation provisions and within 
    the associated timelines in Sec. 75.20(b)(3), with the term 
    ``diagnostic'' applying instead of the term ``recertification''. 
    However, in lieu of the provisions in Sec. 75.20(b)(3)(ix), the owner 
    or operator shall follow the applicable provisions in paragraphs 
    (c)(3)(xi) and (c)(3)(xii) of this section.
        (vii) A RATA which is performed and passed during the second or 
    third quarter of the current calendar year may be used to quality 
    assure data in the next ozone season, provided that:
        (A) The results of the RATA indicate that the CEMS qualifies for an 
    annual RATA frequency (see Figure 2 in appendix B to this part); and
        (B) The CEMS is continuously operated and maintained, and daily 
    calibration error tests and (if applicable) interference checks of the 
    CEMS are performed in the time period extending from the end of the 
    current ozone season (October 1 of the current calendar year) through 
    April 30 of the next calendar year; and
        (C) For a gas monitoring system, the linearity check requirement of 
    paragraph (c)(2)(i) of this section is met prior to May 1 of the next 
    calendar year.
        (D) If conditions in paragraphs (c)(3)(vii)(A), (B) and, if 
    applicable, (c)(3)(vii)(C) of this section are met, then a RATA 
    completed and passed in the second or third calendar quarter of the 
    current year may be used to quality assure data for the next ozone 
    season, as follows:
        (1) If the RATA is completed and passed in the second calendar 
    quarter of the current year, the RATA may be used to quality assure 
    data from the CEMS through June 30 of the next calendar year.
        (2) If the RATA is completed and passed in the third calendar 
    quarter of the current year, the RATA may be used to quality assure 
    data from the CEMS through September 30 of the next calendar year.
        (viii) If a linearity check performed to meet the requirement of 
    paragraph (c)(2)(i) of this section is completed and passed in the 
    second calendar quarter of the current year, provided that the date and 
    hour of completion of the test is within the first 168 unit or stack 
    operating hours of the current ozone season, the linearity check may be 
    used to satisfy both the requirement of paragraph (c)(2)(i) of this 
    section and to meet the second quarter linearity check requirement of 
    paragraph (c)(3)(ii) of this section.
        (ix) If, for any required CEMS, diagnostic linearity checks or 
    RATAs other than those required by this section are performed during 
    the ozone season, use the applicable data validation procedures in 
    section 2.2.3 (for linearity checks) or 2.3.2 (for RATAs) of appendix B 
    to this part.
        (x) If any required CEMS is recertified within the ozone season, 
    use the data validation provisions in Sec. 75.20(b)(3) and paragraphs 
    (c)(3)(xi) and (c)(3)(xii) of this section.
        (xi) If, at the end of the second quarter of any calendar year, a 
    required quality assurance, diagnostic or recertification test of a 
    monitoring system has not been completed, and if data contained in the 
    quarterly report are conditionally valid pending the results of test(s) 
    to be completed in a subsequent quarter, the owner or operator shall 
    indicate this by means of a suitable conditionally valid data flag in 
    the electronic quarterly report for the second calendar quarter. The 
    owner or operator shall resubmit the report for the second quarter if 
    the required quality assurance, diagnostic or 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 quality assurance, 
    diagnostic or recertification test. Alternatively, if any required 
    quality assurance, diagnostic or recertification test is not completed 
    by the end of the second 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. 75.73), the test data 
    and results may be submitted with the second quarter report even though 
    the test date(s) are from the third calendar quarter. In such 
    instances, if the quality assurance, diagnostic or recertification 
    test(s) are passed in accordance with the provisions of 
    Sec. 75.20(b)(3), conditionally valid data may be reported as quality-
    assured, in lieu of reporting a conditional data flag. If the tests are 
    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.
        (xii) If, at the end of the third quarter of any calendar year, a 
    required quality assurance, diagnostic or recertification test of a 
    monitoring system has not been completed, and if data contained in the 
    quarterly report are conditionally valid pending the results of test(s) 
    to be completed, the owner or operator shall do one of the following:
        (A) If the results of the required tests are not available within 
    30 days of the end of the third calendar quarter and cannot be 
    submitted with the quarterly report for the third calendar quarter, 
    then the test results are considered to be missing and 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 in the third quarter report. In addition, if 
    the data in the second quarterly report were flagged as conditionally 
    valid at the end of the quarter, pending the results of the same 
    missing tests, the owner or operator shall resubmit the report for the 
    second quarter and shall use the appropriate missing data routine in 
    Sec. 75.31 or Sec. 75.33 to replace with substitute data
    
    [[Page 28630]]
    
    each hour of conditionally valid data associated with the missing 
    quality assurance, diagnostic or recertification tests; or
        (B) If the required quality assurance, diagnostic or 
    recertification tests are completed no later than 30 days after the end 
    of the third calendar quarter, the test data and results may be 
    submitted with the third quarter report even though the test date(s) 
    are from the fourth calendar quarter. In this instance, if the required 
    tests are passed in accordance with the provisions of Sec. 75.20(b)(3), 
    all conditionally valid data associated with the tests shall be 
    reported as quality assured. If the tests are failed, 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 associated with the failed test(s). In 
    addition, if the data in the second quarterly report were flagged as 
    conditionally valid at the end of the quarter, pending the results of 
    the same failed test(s), the owner or operator shall resubmit the 
    report for the second quarter and 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 associated with the failed 
    test(s).
        (4) The owner or operator of a unit using the procedures in 
    appendix D of this part to determine heat input is required to maintain 
    fuel flowmeters only during the ozone season, except that for purposes 
    of determining the deadline for the next periodic quality assurance 
    test on the fuel flowmeter, the owner or operator shall include all 
    fuel flowmeter QA operating quarters (as defined in Sec. 72.2) for the 
    entire calendar year, not just fuel flowmeter QA operating quarters in 
    the ozone season. For each calendar year, the owner or operator shall 
    record, for each fuel flowmeter, the number of fuel flowmeter QA 
    operating quarters.
        (5) The owner or operator of a unit using the procedures in 
    appendix D of this part to determine heat input is only required to 
    sample fuel for the purposes of determining density and GCV during the 
    ozone season, except that:
        (i) The owner or operator of a unit that performs sampling from the 
    fuel storage tank upon delivery must sample the tank between the date 
    and hour of the most recent delivery before the first date and hour 
    that the unit operates in the ozone season and the first date and hour 
    that the unit operates in the ozone season.
        (ii) The owner or operator of a unit that performs sampling upon 
    delivery from the delivery vehicle must ensure that all shipments 
    received during the calendar year are sampled.
        (iii) The owner or operator of a unit that performs sampling on 
    each day the unit combusts fuel or that performs fuel sampling 
    continuously must sample the fuel starting on the first day the unit 
    operates during the ozone season. The owner or operator then shall use 
    that sampled value for all hours of combustion during the first day of 
    unit operation, continuing until the date and hour of the next sample.
        (6) The owner or operator shall, in accordance with Sec. 75.73, 
    record and report the hourly data required by this subpart and shall 
    record and report the results of all required quality assurance tests, 
    as follows:
        (i) All hourly emission data for the period of time from May 1 
    through September 30 of each calendar year shall be recorded and 
    reported. For missing data purposes, only the data recorded in the time 
    period from May 1 through September 30 shall be considered quality-
    assured;
        (ii) The results of all daily calibration error tests and flow 
    monitor interference checks performed in the time period from May 1 
    through September 30 shall be recorded and reported;
        (iii) For the time periods described in paragraphs (c)(2)(i)(C) and 
    (c)(2)(ii)(E) of this section, hourly emission data and the results of 
    all daily calibration error tests and flow monitor interference checks 
    shall be recorded. The results of all daily calibration error tests and 
    flow monitor interference checks performed in the time period from 
    April 1 through April 30 shall be reported. The owner or operator may 
    also report the hourly emission data and unit operating data recorded 
    in the time period from April 1 through April 30. However, only the 
    emission data recorded in the time period from May 1 through September 
    30 shall be used for NOX mass compliance determination;
        (iv) The results of all required quality assurance tests (RATAs, 
    linearity checks, flow-to-load ratio tests and leak checks) performed 
    during the ozone season shall be reported in the appropriate ozone 
    season quarterly report; and
        (v) The results of RATAs (and any other quality assurance test(s) 
    required under paragraph (c)(2) or (c)(3) of this section) which affect 
    data validation for the current ozone season, but which were performed 
    outside the ozone season (i.e., between October 1 of the previous 
    calendar year and April 30 of the current calendar year), shall be 
    reported in the quarterly report for the second quarter of the current 
    calendar year.
        (7) The owner or operator shall use only quality-assured data from 
    within ozone seasons in the substitute data procedures under subpart D 
    of this part and section 2.4.2 of appendix D to this part.
        (i) The lookback periods (e.g., 2160 quality-assured monitor 
    operating hours for a NOX-diluent continuous emission 
    monitoring system, a NOX concentration monitoring system, or 
    a flow monitoring system) used to calculate missing data must include 
    only quality-assured data from periods within ozone seasons.
        (ii) The missing data procedures of Secs. 75.31 through 75.33 shall 
    be used, with two exceptions. First, when the NOX emission 
    rate or NOX concentration of the unit was consistently lower 
    in the previous ozone season because the unit combusted a fuel that 
    produces less NOX than the fuel currently being combusted; 
    and second, when the unit's add-on emission controls are not working 
    properly, as shown by the parametric data recorded under paragraph 
    (c)(8) of this section. In those two cases, the owner or operator shall 
    substitute the maximum potential NOX emission rate, as 
    defined in Sec. 72.2 of this chapter, from a NOX-diluent 
    continuous emission monitoring system, or the maximum potential 
    concentration of NOX, as defined in section 2.1.2.1 of 
    appendix A to this part, from a NOX concentration monitoring 
    system. The maximum potential value used shall be for the fuel 
    currently being combusted. The length of time for which the owner or 
    operator shall substitute these maximum potential values for each hour 
    of missing NOX operator shall substitute these maximum 
    potential value for each hour of missing NOX data, shall be 
    as follows:
        (A) For a unit that changed fuels, substitute the maximum potential 
    values until the first hour when the unit combusts a fuel that produces 
    the same or less NOX than the fuel combusted in the previous 
    ozone season; and
        (B) For a unit with add-on emission controls that are not working 
    properly, substitute the maximum potential values until the first hour 
    in which the add-on emission controls are documented to be operating 
    properly, according to paragraph (c)(8) of this section.
    * * * * *
        54. Appendix A to part 75 is amended by--
        a. Revising sections 2 through 2.1.1.4;
        b. Adding section 2.1.1.5;
        c. Revising sections 2.1.2 through 2.1.2.4;
        d. Adding section 2.1.2.5;
    
    [[Page 28631]]
    
        e. Revising section 2.1.3;
        f. Adding sections 2.1.3.1 through 2.1.3.3;
        g. Revising section 2.1.4;
        h. Adding sections 2.1.4.1 through 2.1.6;
        i. Removing and reserving section 2.2 and removing sections 2.2.1 
    through 2.2.2.2 to read as follows:
    
    Appendix A to Part 75--Specifications and Test Procedures
    
    * * * * *
    
    2. Equipment Specifications
    
    2.1  Instrument Span and Range
    
        In implementing sections 2.1.1 through 2.1.6 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, select the range 
    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. These guidelines do not apply 
    to: (1) SO2 readings obtained during the combustion of 
    very low sulfur fuel (as defined in Sec. 72.2 of this chapter); (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 in this section 2, 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 
    fuels that are very low sulfur fuels (as defined in Sec. 72.2 of 
    this chapter), 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
    
        (a) 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 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 values. 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.
        (b) 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.
        (c) 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] TR26MY99.000
    
        or
    [GRAPHIC] [TIFF OMITTED] TR26MY99.001
    
    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 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 percent 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
    
        (a) 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 that are very 
    low sulfur fuels (as defined in Sec. 72.2 of this chapter); or (3) 
    fuels or blends that are used only for unit startup.
        (b) For each MEC determination, substitute into Equation A-1a or 
    A-1b the highest sulfur content and minimum GCV value for
    
    [[Page 28632]]
    
    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).
        (c) 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] TR26MY99.002
    
    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 
    (%).
    
    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 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 and range 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 high full-scale 
    range value from section 2.1.1.3 of this appendix. If the MEC is 
    20.0 percent of the high range value, 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="" high="" range="" value,="" then="" 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="">2 controls, 
    compare the high range value from section 2.1.1.3 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 high range value, 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="" high="" range="" value,="" then="" a="" second="" (low)="" span="" value="" must="" be="" used="" when="" that="" fuel="" or="" blend="" is="" combusted.="" (c)="" when="" two="">2 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 in the monitoring plan under Sec. 75.53 as follows: 
    designate the low and high monitor ranges as separate SO2 
    components of a single, primary SO2 monitoring system; or 
    designate the low and high monitor ranges as the SO2 
    components of two separate, primary SO2 monitoring 
    systems; or designate the normal monitor range as a primary 
    monitoring system and the other monitor range as a non-redundant 
    backup monitoring system; or, when a single, dual-range 
    SO2 analyzer is used, designate the low and high ranges 
    as a single SO2 component of a primary SO2 
    monitoring system (if this option is selected, use a special dual-
    range component type code, as specified by the Administrator, to 
    satisfy the requirements of Sec. 75.53(e)(1)(iv)(D)); or, for units 
    with SO2 controls, if the default high range value is 
    used, designate the low range analyzer as the SO2 
    component of a primary SO2 monitoring system. Do not 
    designate the default high range as a monitoring system or 
    component. Other component and system designations are subject to 
    approval by the Administrator. Note that the component and system 
    designations for redundant backup monitoring systems shall be the 
    same as for primary monitoring systems.
        (e) Each monitoring system designated as primary or redundant 
    backup shall meet the initial certification and quality assurance 
    requirements for primary monitoring systems in Sec. 75.20(c) or 
    Sec. 75.20(d)(1), as applicable, 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)(2).
        (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 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 high full-
    scale range value (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 high full-scale range value, 
    i.e., when the MEC of the fuel or blend being combusted is less than 
    20.0 percent of the high full-scale range value. 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 periodic evaluation of the MPC, MEC, span, and range 
    values for each SO2 monitor (at a minimum, an annual 
    evaluation is required) and shall make any necessary span and range 
    adjustments, with corresponding monitoring plan updates, as 
    described in paragraphs (a) and (b) of this section. Span and range
    
    [[Page 28633]]
    
    adjustments may be required, for example, as a result of changes in 
    the fuel supply, changes in the manner of operation of the unit, or 
    installation or removal of emission controls. In implementing the 
    provisions in paragraphs (a) and (b) of this section, 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 consideration. The owner or operator 
    shall keep the results of the most recent span and range evaluation 
    on-site, in a format suitable for inspection. 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) 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. A ``significant'' 
    change in the MPC or MEC means that the guidelines in section 2.1 of 
    this appendix can no longer be met, as determined by either a 
    periodic evaluation by the owner or operator or from the results of 
    an audit by the Administrator. 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.
        (b) 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 each hour of the full-scale exceedance and make 
    appropriate 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 (b)(1) of this section).
        (c) Whenever changes are made to the MPC, MEC, full-scale range, 
    or span value of the SO2 monitor, as described in 
    paragraphs (a) or (b) 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 in section 2.1.2.1, 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
    
        (a) 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 as follows:
        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.
        (b) 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 expected 
    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.
        (c) 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.
        (d) For units with add-on NOX controls (whether or 
    not the unit is equipped with low-NOX burner technology), 
    NOX emission testing may only be used to determine the 
    MPC if testing can be performed either upstream of the add-on 
    controls or during a time or season when the add-on controls are not 
    in operation. 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 from all test runs as the MPC for NOX.
        (e) If historical CEM data are used to determine the MPC, the 
    data must, for uncontrolled units or units equipped with low-
    NOX burner technology and no other NOX 
    controls, 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 a 
    unit with add-on NOX controls (whether or not the unit is 
    equipped with low-NOX burner technology), historical CEM 
    data may only be used to determine the MPC if the 720 quality 
    assured monitor operating hours of CEM data are collected upstream 
    of the add-on controls or if the 720 hours of data include periods 
    when the add-on controls are not in operation. The highest hourly 
    NOX concentration in ppm shall be the MPC.
    
    [[Page 28634]]
    
    
    
      Table 2-1.--Maximum Potential Concentration for NOX--Coal-Fired Units
    ------------------------------------------------------------------------
                                                                  Maximum
                                                                 potential
                            Unit type                          concentration
                                                               for NOX (ppm)
    ------------------------------------------------------------------------
    Tangentially-fired dry bottom and fluidized bed.........             460
    Wall-fired dry bottom, turbo-fired dry bottom, stokers..             675
    Roof-fired (vertically-fired) dry bottom, cell burners,              975
     arch-fired.............................................
    Cyclone, wall-fired wet bottom, wet bottom turbo-fired..            1200
    Others..................................................           (\1\)
    ------------------------------------------------------------------------
    \1\ As approved by the Administrator.
    
    
     Table 2-2.--Maximum Potential Concentration for NOX--Gas-and Oil-Fired
                                      Units
    ------------------------------------------------------------------------
                                                                  Maximum
                                                                 potential
                            Unit type                          concentration
                                                               for NOX (ppm)
    ------------------------------------------------------------------------
    Tangentially-fired dry bottom...........................             380
    Wall-fired dry bottom...................................             600
    Roof-fired (vertically-fired) dry bottom, arch-fired....             550
    Existing combustion turbine or combined cycle turbine...             200
    New stationary gas turbine/combustion turbine...........              50
    Others..................................................           (\1\)
    ------------------------------------------------------------------------
    \1\ As approved by the Administrator
    
    2.1.2.2  Maximum Expected Concentration
    
        (a) 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 
    (e.g., 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.
        (b) 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 three 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.
        (c)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 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)
    
        (a) 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 and range 
    may be required (see section 2.1.2.4 of this appendix).
        (b) If an existing State, local, or federal requirement for span 
    of a 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.
        (c) 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 high full-scale range value determined in 
    section 2.1.2.3 of this appendix. If the MEC values for all fuels 
    (or blends) are 20.0 percent of the high range value, 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="" high="" range="" value,="" two="" spans="" (low="" and="" high)="" are="" required,="" one="" based="" on="" the="" mpc="" and="" the="" other="" based="" on="" the="" mec.="" (b)="" when="" two="">X 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
    
    [[Page 28635]]
    
    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 in the monitoring plan under Sec. 75.53 as follows: 
    designate the low and high ranges as separate NOX 
    components of a single, primary NOX monitoring system; or 
    designate the low and high ranges as the NOX components 
    of two separate, primary NOX monitoring systems; or 
    designate the normal range as a primary monitoring system and the 
    other range as a non-redundant backup monitoring system; or, when a 
    single, dual-range NOX analyzer is used, designate the 
    low and high ranges as a single NOX component of a 
    primary NOX monitoring system (if this option is 
    selected, use a special dual-range component type code, as specified 
    by the Administrator, to satisfy the requirements of 
    Sec. 75.53(e)(1)(iv)(D)); or, for units with add-on NOX 
    controls, if the default high range value is used, designate the low 
    range analyzer as the NOX component of the primary 
    NOX monitoring system. Do not designate the default high 
    range as a monitoring system or component. Other component and 
    system designations are subject to approval by the Administrator. 
    Note that the component and system designations for redundant backup 
    monitoring systems shall be the same as for primary monitoring 
    systems.
        (d) Each monitoring system designated as primary or redundant 
    backup shall meet the initial certification and quality assurance 
    requirements in Sec. 75.20(c) (for primary monitoring systems), in 
    Sec. 75.20(d)(1) (for redundant backup monitoring systems) 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)(2).
        (e) For dual span units with add-on NOX emission 
    controls (e.g., 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="" high="" full-scale="" range="" value,="" the="" low="" span="" value="" shall="" be="" based="" upon="" whichever="" mec="" value="" is="" closest="" to="" 20.0="" percent="" of="" the="" high="" range="" value.="" 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="">X spans, use the low range whenever 
    NOX concentrations are expected to be consistently <20.0 percent="" of="" the="" high="" range="" value,="" i.e.,="" when="" the="" mec="" of="" the="" fuel="" being="" combusted="" is=""><20.0 percent="" of="" the="" high="" range="" value.="" when="" the="" full-scale="" of="" the="" low="" range="" is="" exceeded,="" the="" high="" range="" shall="" be="" used="" to="" measure="" and="" record="" the="">X 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 periodic evaluation of the MPC, MEC, span, and range 
    values for each NOX monitor (at a minimum, an annual 
    evaluation is required) and shall make any necessary span and range 
    adjustments, with corresponding monitoring plan updates, as 
    described in paragraphs (a) and (b) of this section. Span and range 
    adjustments may be required, for example, as a result of changes in 
    the fuel supply, changes in the manner of operation of the unit, or 
    installation or removal of emission controls. In implementing the 
    provisions in paragraphs (a) and (b) of this section, 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 consideration. The owner or operator 
    shall keep the results of the most recent span and range evaluation 
    on-site, in a format suitable for inspection. 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) 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. A ``significant'' change in the MPC or MEC means 
    that the guidelines in section 2.1 of this appendix can no longer be 
    met, as determined by either a periodic evaluation by the owner or 
    operator or from the results of an audit by the Administrator. 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 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. An example of a change that may 
    require a span and range adjustment is the installation of low-
    NOX burner technology on a previously uncontrolled unit. 
    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.
        (b) 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 NOX 
    concentration for each hour of the full-scale exceedance and make 
    appropriate 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 (b)(1) of this section).
        (c) Whenever changes are made to the MPC, MEC, full-scale range, 
    or span value of the NOX monitor as described in 
    paragraphs (a) and (b) 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 (e.g., O2 
    concentrations above a certain level create an unsafe operating 
    condition).
    
    [[Page 28636]]
    
    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). Note that 
    the MPC for CO2 monitors shall only be used for the 
    purpose of providing substitute data under this part. The 
    CO2 monitor span and range shall be determined according 
    to section 2.1.3 of this appendix.
    
    2.1.3.2  Minimum Potential Concentration of O2
    
        The owner or operator of a unit that uses a flow monitor and an 
    O2 diluent monitor to determine heat input in accordance 
    with Equation F-17 or F-18 in appendix F to this part shall, for the 
    purposes of providing substitute data under Sec. 75.36, determine 
    the minimum potential O2 concentration. The minimum 
    potential O2 concentration shall be based upon 720 hours 
    or more of quality-assured CEM data, representing the full operating 
    load range of the unit(s). The minimum potential O2 
    concentration shall be the lowest quality-assured hourly average 
    O2 concentration recorded in the 720 (or more) hours of 
    data used for the determination.
    
    2.1.3.3  Adjustment of Span and Range
    
        Adjust the span value and range of a CO2 or 
    O2 monitor in accordance with section 2.1.1.5 of this 
    appendix (insofar as those provisions are applicable), with the term 
    ``CO2 or O2'' applying instead of the term 
    ``SO2''. Set the new span and range in accordance with 
    section 2.1.3 of this appendix and report 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
    
        For this purpose, determine the span value of the flow monitor 
    using the following procedure. Calculate 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.
    [GRAPHIC] [TIFF OMITTED] TR26MY99.003
    
        or
    [GRAPHIC] [TIFF OMITTED] TR26MY99.004
    
    Where:
    
    MPV = maximum potential velocity (fpm, standard wet basis).
    Fd = dry-basis F factor (dscf/mmBtu) from Table 1, 
    Appendix F to this part.
    Fc = carbon-based F factor (scf CO2/mmBtu) 
    from Table 1, Appendix F to 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.
    
    2.1.4.2  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 measurement 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 two 
    significant figures. For calibration span values in inches of water, 
    retain at least two 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 scfh and, 
    if different, in the measurement units of calibration).
    
    2.1.4.3  Adjustment of Span and Range
    
        For each affected unit or common stack, the owner or operator 
    shall make a periodic evaluation of the MPV, MPF, span, and range 
    values for each flow rate monitor (at a minimum, an annual 
    evaluation is required) and shall make any necessary span and range 
    adjustments with corresponding monitoring plan updates, as described 
    in paragraphs (a) through (c) of this section 2.1.4.3. Span and 
    range adjustments may be required, for example, 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, or 
    installation or removal of emission controls. In implementing the 
    provisions in paragraphs (a) and (b) of this section 2.1.4.3, 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 consideration. The owner or operator 
    shall keep the results of the most recent span and range evaluation 
    on-site, in a format suitable for inspection. 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) 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. A 
    ``significant'' change in the MPV or MPF means that the guidelines 
    of section 2.1 of this appendix can no longer be met, as
    
    [[Page 28637]]
    
    determined by either a periodic evaluation by the owner or operator 
    or from the results of an audit by the Administrator. 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.
        (b) 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 appropriate 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.
        (c) Whenever changes are made to the MPV, MPF, full-scale range, 
    or span value of the flow monitor, as described in paragraphs (a) 
    and (b) 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  Minimum Potential Moisture Percentage
    
        Except as provided in section 2.1.6 of this appendix, the owner 
    or operator of a unit that uses a continuous moisture monitoring 
    system to correct emission rates and heat inputs from a dry basis to 
    a wet basis (or vice-versa) shall, for the purpose of providing 
    substitute data under Sec. 75.37, use a default value of 3.0 percent 
    H2O as the minimum potential moisture percentage. 
    Alternatively, the minimum potential moisture percentage may be 
    based upon 720 hours or more of quality-assured CEM data, 
    representing the full operating load range of the unit(s). If this 
    option is chosen, the minimum potential moisture percentage shall be 
    the lowest quality-assured hourly average H2O 
    concentration recorded in the 720 (or more) hours of data used for 
    the determination.
    
    2.1.6  Maximum Potential Moisture Percentage
    
        When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to 
    part 60 of this chapter is used to determine NOX emission 
    rate, the owner or operator of a unit that uses a continuous 
    moisture monitoring system shall, for the purpose of providing 
    substitute data under Sec. 75.37, determine the maximum potential 
    moisture percentage. The maximum potential moisture percentage shall 
    be based upon 720 hours or more of quality-assured CEM data, 
    representing the full operating load range of the unit(s). The 
    maximum potential moisture percentage shall be the highest quality-
    assured hourly average H2O concentration recorded in the 
    720 (or more) hours of data used for the determination.
        55. Appendix A to part 75 is amended by revising section 3.1, 
    the last sentence in the first paragraph of section 3.2, and section 
    3.3.2; by adding section 3.3.6; and by revising sections 3.3.7, 
    3.4.1 and 3.5 to read as follows:
    
    3. Performance Specifications
    
    3.1  Calibration Error
    
        (a) The calibration error performance specifications in this 
    section apply only to 7-day calibration error tests under sections 
    6.3.1 and 6.3.2 of this appendix and to the offline calibration 
    demonstration described in section 2.1.1.2 of appendix B to this 
    part. The calibration error limits for daily operation of the 
    continuous monitoring systems required under this part are found in 
    section 2.1.4(a) of appendix B to this part.
        (b) The 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.
    
    3.2  Linearity Check
    
        * * * For CO2 or O2 monitors (including 
    O2 monitors used to measure CO2 emissions or 
    percent moisture):
    * * * * *
        3.3 * * *
    
    3.3.2  Relative Accuracy for NOX-Diluent Continuous Emission 
    Monitoring Systems
    
        (a) The relative accuracy for NOX-diluent continuous 
    emission monitoring systems shall not exceed 10.0 percent.
        (b) For affected units where the average of the monitoring 
    system measurements of NOX emission rate during the 
    relative accuracy test audit is less than or equal to 0.200 lb/
    mmBtu, the mean value of the continuous emission monitoring system 
    measurements shall not exceed 0.020 lb/mmBtu of the 
    reference method mean value whenever the relative accuracy 
    specification of 10.0 percent is not achieved.
    * * * * *
    
    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), 
    calculated using Equation A-7 of this appendix, are within 
    1.5 percent H2O.
    
    3.3.7  Relative Accuracy for NOX Concentration Monitoring 
    Systems
    
        (a) The following requirement applies only to NOX 
    concentration monitoring systems (i.e., NOX pollutant 
    concentration monitors) that are used to determine NOX 
    mass emissions, where the owner or operator elects to monitor and 
    report NOX mass emissions using a NOX 
    concentration monitoring system and a flow monitoring system.
        (b) The relative accuracy for NOX concentration 
    monitoring systems shall not exceed 10.0 percent. Alternatively, for 
    affected units where the average of the monitoring system 
    measurements of NOX concentration during the relative 
    accuracy test audit is less than or equal to 250.0 ppm, the mean 
    value of the continuous emission monitoring system measurements 
    shall not exceed 15.0 ppm of the reference method mean 
    value.
        3.4 * * *
    
    3.4.1  SO2 Pollutant Concentration Monitors, NOX 
    Concentration Monitoring Systems and NOX-Diluent Continuous 
    Emission Monitoring Systems
    
        SO2 pollutant concentration monitors, NOX-
    diluent continuous emission monitoring systems and NOX 
    concentration monitoring systems used to determine NOX 
    mass emissions, as defined in Sec. 75.71(a)(2), shall not be biased 
    low as determined by the test procedure in section 7.6 of this 
    appendix. The bias specification applies to all SO2 
    pollutant concentration monitors and to all NOX 
    concentration monitoring systems, including those measuring an 
    average SO2 or NOX concentration of 250.0 ppm 
    or less, and to all NOX-diluent continuous emission 
    monitoring systems, including those measuring an average 
    NOX emission rate of 0.200 lb/mmBtu or less.
    * * * * *
    
    [[Page 28638]]
    
    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.
        56. Appendix A to part 75 is amended by revising the first 
    sentence of the first paragraph of section 4 and paragraph (6) to 
    read as follows:
    
    4. Data Acquisition and Handling Systems
    
        Automated data acquisition and handling systems shall read and 
    record the full range of pollutant concentrations and volumetric 
    flow from zero through span and 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.
        57. Appendix A to part 75 is amended by revising sections 5 
    through 5.1.6, adding sections 5.1.7 through 5.1.8, and revising 
    sections 5.2 through 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 address 
    in section 5.1.1, 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 address 
    in section 5.1.1, for a list of vendors and cylinder gases.
    
    5.1.4  EPA Protocol Gases
    
        (a) 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.
        (b) 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.
    
    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  Concentrations
    
        Four concentration levels are required as follows.
    
    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.
        58. Appendix A to part 75 is amended by revising sections 6.2, 
    6.3.1, 6.3.2, 6.4, 6.5, 6.5.1, 6.5.2, 6.5.6, 6.5.7, 6.5.9 and 
    6.5.10, and adding sections 6.5.2.1, 6.5.2.2, 6.5.6.1, 6.5.6.2, and 
    6.5.6.3 to read as follows:
    
    6. Certification Tests and Procedures
    
    * * * * *
    
    6.2  Linearity Check (General Procedures)
    
        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. 
    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 checks, using the procedures in this 
    section, on the range(s) and at the frequency specified in section 
    2.2.1 of appendix B to 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. 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. 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, the 
    words ``initial certification'' apply instead of 
    ``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 28639]]
    
        (f) For all other linearity checks, use the data validation 
    procedures in section 2.2.3 of appendix B to this part.
    
    6.3 * * *
    
    6.3.1  Gas Monitor 7-day Calibration Error Test
    
        Measure the calibration error of each SO2 monitor, 
    each NOX monitor and each CO2 or O2 
    monitor while the unit is combusting fuel (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 calibration error test procedures in this 
    section and in section 6.3.2 of this appendix 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 high-level concentration, as 
    specified in section 5.2 of this appendix. Alternatively, a mid-
    level concentration gas (50.0 to 60.0 percent of the span value) may 
    be used in lieu of the high-level gas, provided that the mid-level 
    gas is more representative of the actual stack gas concentrations. 
    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. The results of a 
    7-day calibration error test are acceptable for monitor or 
    monitoring system certification, recertification or diagnostic 
    testing 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 gas monitor prior to and 
    during a 7-day calibration error test period shall be determined as 
    follows:
        (a) For initial certification, data from the monitor 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, the words ``initial 
    certification'' apply instead of ``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).
    
    6.3.2  Flow Monitor 7-day Calibration Error Test
    
        Perform the 7-day calibration error test of a flow monitor, when 
    required for certification, recertification or diagnostic testing, 
    according to the following procedures. Introduce the reference 
    signal corresponding to the values specified in section 2.2.2.1 of 
    this appendix to the probe tip (or equivalent), or to the 
    transducer. During the 7-day certification test period, conduct the 
    calibration error test while the unit is operating once each unit 
    operating day (as close to 24-hour intervals as practicable). In the 
    event that extended unit outages occur after the commencement of the 
    test, the 7 consecutive operating days need not be 7 consecutive 
    calendar days. Record the flow monitor responses by means of the 
    data acquisition and handling system. Calculate the calibration 
    error using Equation A-6 of this appendix. Do not perform any 
    corrective maintenance, repair, or replacement upon the flow monitor 
    during the 7-day test period other than that required in the quality 
    assurance/quality control plan required by appendix B to this part. 
    Do not make adjustments between the zero and high reference level 
    measurements on any day during the 7-day test. If the flow monitor 
    operates within the calibration error performance specification 
    (i.e., less than or equal to 3.0 percent error each day and 
    requiring no corrective maintenance, repair, or replacement during 
    the 7-day test period), the flow monitor passes the calibration 
    error test. Record all maintenance activities and the magnitude of 
    any adjustments. Record output readings from the data acquisition 
    and handling system before and after all adjustments. Record and 
    report all calibration error test results using the unadjusted flow 
    rate measured in the calibration error test prior to resetting the 
    calibration. Record all adjustments made during the 7-day period at 
    the time the adjustment is made, and report them in the 
    certification or recertification application. The status of 
    emissions data from a flow monitor prior to and during a 7-day 
    calibration error test period shall be determined as follows:
        (a) For initial certification, data from the monitor 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, the words ``initial 
    certification'' apply instead of ``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).
    
    6.4  Cycle Time Test
    
        Perform cycle time tests for each pollutant concentration 
    monitor and continuous emission monitoring system while the unit is 
    operating, according to the following procedures (see also Figure 6 
    at the end of this appendix). Use a zero-level and a high-level 
    calibration gas (as defined in section 5.2 of this appendix) 
    alternately. To determine the upscale elapsed time, inject a zero-
    level concentration calibration gas into the probe tip (or injection 
    port leading to the calibration cell, for in situ systems with no 
    probe). Record the stable starting gas value and start time, using 
    the data acquisition and handling system (DAHS). Next, allow the 
    monitor to measure the concentration of flue gas emissions until the 
    response stabilizes. Record the stable ending stack emissions value 
    and the end time of the test using the DAHS. Determine the upscale 
    elapsed time as the time it takes for 95.0 percent of the step 
    change to be achieved between the stable starting gas value and the 
    stable ending stack emissions value. Then repeat the procedure, 
    starting by injecting the high-level gas concentration to determine 
    the downscale elapsed time, which is the time it takes for 95.0 
    percent of the step change to be achieved between the stable 
    starting gas value and the stable ending stack emissions value. End 
    the downscale test by measuring the stable concentration of flue gas 
    emissions. Record the stable starting and ending monitor values, the 
    start and end times, and the downscale elapsed time for the monitor 
    using the DAHS. A stable value is equivalent to a reading with a 
    change of less than 2.0 percent of the span value for 2 minutes, or 
    a reading with a change of less than 6.0 percent from the measured 
    average concentration over 6 minutes. (Owners or operators of 
    systems which do not record data in 1-minute or 3-minute intervals 
    may petition the Administrator under Sec. 75.66 for alternative 
    stabilization criteria). For monitors or monitoring systems that 
    perform a series of operations (such as purge, sample, and analyze), 
    time the injections of the calibration gases so they will produce 
    the
    
    [[Page 28640]]
    
    longest possible cycle time. Report the slower of the two elapsed 
    times (upscale or downscale) as the cycle time for the analyzer. 
    (See Figure 5 at the end of this appendix.) For the NOx-diluent 
    continuous emission monitoring system test and SO2-
    diluent continuous emission monitoring system test, record and 
    report the longer cycle time of the two component analyzers as the 
    system cycle time. For time-shared systems, this procedure must be 
    done at all probe locations that will be polled within the same 15-
    minute period during monitoring system operations. To determine the 
    cycle time for time-shared systems, add together the longest cycle 
    time obtained at each of the probe locations. Report the sum of the 
    longest cycle time at each of the probe locations plus the sum of 
    the time required for all purge cycles (as determined by the 
    continuous emission monitoring system manufacturer) at each of the 
    probe locations as the cycle time for each of the time-shared 
    systems. For monitors with dual ranges, report the test results from 
    on the range giving the longer cycle time. Cycle time test results 
    are acceptable for monitor or monitoring system certification, 
    recertification or diagnostic testing if none of the cycle times 
    exceed 15 minutes. The status of emissions data from a monitor prior 
    to and during a cycle time test period shall be determined as 
    follows:
        (a) For initial certification, data from the monitor are 
    considered invalid until all certification tests, including the 
    cycle time 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, the words ``initial 
    certification'' apply instead of ``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 cycle time 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 (General Procedures)
    
        Perform the required relative accuracy test audits (RATAs) as 
    follows for each CO2 pollutant concentration monitor 
    (including O2 monitors used to determine CO2 
    pollutant concentration), each SO2 pollutant 
    concentration monitor, each NOX concentration monitoring 
    system used to determine NOX mass emissions, each flow 
    monitor, each NOX-diluent continuous emission monitoring 
    system, each O2 or CO2 diluent monitor used to 
    calculate heat input, each moisture monitoring system and each 
    SO2-diluent continuous emission monitoring system. For 
    NOX concentration monitoring systems used to determine 
    NOX mass emissions, as defined in Sec. 75.71(a)(2), use 
    the same general RATA procedures as for SO2 pollutant 
    concentration monitors; however, use the reference methods for 
    NOX concentration specified in section 6.5.10 of this 
    appendix:
        (a) 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.
        (b) 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.
        (c) 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 use fuel switching or for which the emission controls are 
    operated seasonally), 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.
        (d) Record monitor or monitoring system output from the data 
    acquisition and handling system.
        (e) Complete each single-load relative accuracy test audit 
    within a period of 168 consecutive unit operating hours, as defined 
    in Sec. 72.2 of this chapter (or, for CEMS installed on common 
    stacks or bypass stacks, 168 consecutive stack operating hours, as 
    defined in Sec. 72.2 of this chapter). 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 (or 
    stack) operating hours; however, if this is not possible, up to 720 
    consecutive unit (or stack) operating hours may be taken to complete 
    a multiple-load flow RATA.
        (f) 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, the words ``initial 
    certification'' apply instead of ``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.
        (6) For all other RATAs, use the data validation procedures in 
    section 2.3.2 of appendix B to this part.
        (g) For each SO2 or CO2 pollutant 
    concentration monitor, each flow monitor, each CO2 or 
    O2 diluent monitor used to determine heat input, each 
    NOX concentration monitoring system used to determine 
    NOX mass emissions, as defined in Sec. 75.71(a)(2), each 
    moisture monitoring system and each NOX-diluent 
    continuous emission monitoring system, calculate the relative 
    accuracy, in accordance with section 7.3 or 7.4 of this appendix, as 
    applicable. In addition (except for CO2, O2, 
    SO2-diluent or moisture 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) Perform the required relative accuracy test audits for each 
    SO2 or CO2 pollutant concentration monitor, 
    each CO2 or O2 diluent monitor used to determine heat 
    input, each NOX-diluent continuous emission monitoring 
    system, each NOX concentration monitoring system used to 
    determine NOX mass emissions, as defined in 
    Sec. 75.71(a)(2), and each SO2-diluent continuous 
    emission monitoring system, 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.
    
    [[Page 28641]]
    
        (c) Flow monitor recertification RATAs shall be done at three 
    load level(s), unless otherwise specified in paragraph (b) of this 
    section or unless otherwise specified or approved by the 
    Administrator.
        (d) 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 to this 
    part.
    
    6.5.2.1  Range of Operation and Normal Load Level(s)
    
        (a) 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 and for each unit that uses the 
    optional fuel flow-to-load quality assurance test in section 2.1.7 
    of appendix D to this part. The lower boundary of the range of 
    operation of a unit shall be the minimum safe, stable load. For 
    common stacks, the minimum safe, stable load shall be the lowest of 
    the minimum safe, stable loads for any of the units discharging 
    through the stack. Alternatively, for a group of frequently-operated 
    units that serve a common stack, the sum of the minimum safe, stable 
    loads for the individual units may be used as the lower boundary of 
    the range of operation. 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 either: the nameplate or rated 
    capacity of the unit, less any physical or regulatory limitations or 
    other deratings; or 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.
        (b) The operating levels for relative accuracy test audits 
    shall, except for peaking units, be defined as follows: the ``low'' 
    operating level shall be the first 30.0 percent of the range of 
    operation; the ``mid'' operating level shall be the middle portion 
    (30.0 to 60.0 percent) of the range of operation; and 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.
        (c) The owner or operator shall identify, for each affected unit 
    or common stack (except for peaking units), the ``normal'' load 
    level or levels (low, mid or high), based on the operating history 
    of the unit(s). This requirement becomes effective on April 1, 2000; 
    however, the owner or operator may choose to comply with this 
    requirement prior to April 1, 2000. To identify the normal load 
    level(s), the owner or operator shall, at a minimum, determine the 
    relative number of operating hours at each of the three load levels, 
    low, mid and high over the past four representative operating 
    quarters. The owner or operator shall determine, to the nearest 0.1 
    percent, the percentage of the time that each load level (low, mid, 
    high) has been used during that time period. A summary of the data 
    used for this determination and the calculated results shall be kept 
    on-site in a format suitable for inspection.
        (d) Based on the analysis of the historical load data the owner 
    or operator shall designate the most frequently used load level as 
    the normal load level for the unit (or combination of units, for 
    common stacks). The owner or operator may also designate the second 
    most frequently used load level as an additional normal load level 
    for the unit or stack. For peaking units, normal load designations 
    are unnecessary; the entire operating load range shall be considered 
    normal. If the manner of operation of the unit changes 
    significantly, such that the designated normal load(s) or the two 
    most frequently used load levels change, the owner or operator shall 
    repeat the historical load analysis and shall redesignate the normal 
    load(s) and the two most frequently used load levels, as 
    appropriate. A minimum of two representative quarters of historical 
    load data are required to document that a change in the manner of 
    unit operation has occurred.
        (e) Beginning on April 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 indicate, in the 
    electronic quarterly report (as part of the electronic monitoring 
    plan) the load level (or levels) designated as normal under this 
    section and shall also indicate the two most frequently used load 
    levels..
    
    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 or K-factor(s) 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. Unless otherwise specified, use only 
    codified versions of PS No. 2 revised as of July 1, 1995, July 1, 
    1996 or July 1, 1997. The following alternative reference method 
    traverse point locations are permitted for moisture and gas monitor 
    RATAs:
        (a) For moisture determinations where the moisture data are used 
    only to determine stack gas molecular weight, a single reference 
    method point, located at least 1.0 meter from the stack wall, may be 
    used. For moisture monitoring system RATAs and for gas monitor RATAs 
    in which moisture data are used to correct pollutant or diluent 
    concentrations from a dry basis to a wet basis (or vice-versa), 
    single-point moisture sampling may only be used if the 12-point 
    stratification test described in section 6.5.6.1 of this appendix is 
    performed prior to the RATA for at least one pollutant or diluent 
    gas, and if the test is passed according to the acceptance criteria 
    in section 6.5.6.3(b) of this appendix.
        (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 accordance with Method 1 in appendix A to part 60 of 
    this chapter.
        (3) At locations where stratification is likely to occur (e.g., 
    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 (b)(2) 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 and situated along one of the 
    measurement lines used for the stratification test, may be used at 
    any sampling location if
    
    [[Page 28642]]
    
    the 12-point stratification test described in section 6.5.6.1 of 
    this appendix is performed and passed prior to each 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  5ppm 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 
    and situated along one of the measurement lines used for the 
    stratification test, 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 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, in a format 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
    
        (a) 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 when a manual readout 
    method is used (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). For moisture 
    monitoring systems, an appropriate coefficient, ``K'' factor or 
    other suitable mathematical algorithm may be developed prior to the 
    RATA, to adjust the monitoring system readings with respect to the 
    reference method. If such a coefficient, K-factor or algorithm is 
    developed, it shall be applied to the CEMS readings during the RATA 
    and (if the RATA is passed), to the subsequent CEMS data, by means 
    of the automated data acquisition and handling system. The owner or 
    operator shall keep records of the current coefficient, K factor or 
    algorithm, as specified in Secs. 75.56(a)(5)(ix) and 
    75.59(a)(5)(vii). Whenever the coefficient, K factor or algorithm is 
    changed, a RATA of the moisture monitoring system is required.
        (b) 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, diagnostic, 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 results used to determine the relative accuracy 
    or bias is greater than or equal to nine. Report all data, including 
    the rejected CEMS data and corresponding reference method test 
    results.
    
    6.5.10  Reference Methods
    
        The following methods from appendix A to part 60 of this chapter 
    or their approved alternatives are the reference methods for 
    performing relative accuracy test audits: Method 1 or 1A for siting; 
    Method 2 or its
    
    [[Page 28643]]
    
    allowable alternatives in appendix A to part 60 of this chapter 
    (except for Methods 2B and 2E) for stack gas velocity and volumetric 
    flow rate; Methods 3, 3A, or 3B for O2 or CO2; 
    Method 4 for moisture; Methods 6, 6A, or 6C for SO2; 
    Methods 7, 7A, 7C, 7D or 7E for NOX, excluding the 
    exception in section 5.1.2 of Method 7E. When using Method 7E for 
    measuring NOX concentration, total NOX, both 
    NO and NO2, must be measured.
        59. Appendix A to part 75 is amended by revising in sections 
    7.2.1, and 7.2.2, the text following each section's equation, 
    beginning with the word ``where''; by revising sections 7.6, 7.6.4, 
    and 7.6.5 and by adding new sections 7.7 and 7.8 (without revising 
    the Figures for Appendix A that appear at the end of section 7 to 
    Appendix A) to read as follows:
    
    7. Calculations
    
    * * * * *
    
    7.2.1  Pollutant Concentration and Diluent Monitors
    
    * * * * *
    Where:
    
    CE = Calibration error as a percentage of the span of the 
    instrument.
    R = Reference value of zero or upscale (high-level or mid-level, as 
    applicable) calibration gas introduced into the monitoring system.
    A = Actual monitoring system response to the calibration gas.
    S = Span of the instrument, as specified in section 2 of this 
    appendix.
    
    7.2.2  Flow Monitor Calibration Error
    
    * * * * *
    Where:
    
    CE = Calibration error as a percentage of span.
    R = Low or high level reference value specified in section 2.2.2.1 
    of this appendix.
    A = Actual flow monitor response to the reference value.
    S = Flow monitor calibration span value as determined under section 
    2.1.4.2 of this appendix.
    * * * * *
    
    7.6  Bias Test and Adjustment Factor
    
        Test the following relative accuracy test audit data sets for 
    bias: SO2 pollutant concentration monitors; flow 
    monitors; NOX concentration monitoring systems used to 
    determine NOX mass emissions, as defined in 
    Sec. 75.71(a)(2); and NOX-diluent continuous emission 
    monitoring systems, using the procedures outlined in section 7.6.1 
    through 7.6.5 of this appendix. For multiple-load flow RATAs, 
    perform a bias test at each load level designated as normal under 
    section 6.5.2.1 of this appendix.
    * * * * *
    
    7.6.4  Bias Test
    
        If, for the relative accuracy test audit data set being tested, 
    the mean difference, d, is less than or equal to the absolute value 
    of the confidence coefficient, | cc |, the monitor or monitoring 
    system has passed the bias test. 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.
    
    7.6.5  Bias Adjustment
    
        (a) If the monitor or monitoring system fails to meet the bias 
    test requirement, adjust the value obtained from the monitor using 
    the following equation:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.005
    
    Where:
    
    CEMi Monitor = Data (measurement) provided by 
    the monitor at time i.
    CEMi Adjusted = Data value, adjusted for bias, 
    at time i.
    BAF = Bias adjustment factor, defined by:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.006
    
    Where:
    
    BAF = Bias adjustment factor, calculated to the nearest thousandth.
    d = Arithmetic mean of the difference obtained during the failed 
    bias test using Equation A-7.
    CEMavg = Mean of the data values provided by the monitor 
    during the failed bias test.
    
        (b) For single-load RATAs of SO2 pollutant 
    concentration monitors, NOX concentration monitoring 
    systems, and NOX-diluent monitoring systems and for the 
    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 concentration CEMS or an SO2 CEMS 
    or a NOX-diluent CEMS installed on a low-emitting 
    affected unit (i.e., average SO2 or NOX 
    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 either be determined using Equation 
    A-12, or a default BAF of 1.111 may be used.
        (c) For 2-load or 3-load flow RATAs, when only one load level 
    (low, mid or high) has been designated as normal under section 
    6.5.2.1 of this appendix and the bias test is passed at the normal 
    load level, apply a BAF of 1.000 to the subsequent flow rate data. 
    If the bias test is failed at the normal load level, use Equation A-
    12 to calculate the normal load BAF and then perform an additional 
    bias test at the second most frequently-used load level, as 
    determined under section 6.5.2.1 of this appendix. If the bias test 
    is passed at this second load level, apply the normal load BAF to 
    the subsequent flow rate data. If the bias test is failed at this 
    second load level, use Equation A-12 to calculate the BAF at the 
    second load level and apply the higher of the two BAFs (either from 
    the normal load level or from the second load level) to the 
    subsequent flow rate data.
        (d) For 2-load or 3-load flow RATAs, when two load levels have 
    been designated as normal under section 6.5.2.1 of this appendix and 
    the bias test is passed at both normal load levels, apply a BAF of 
    1.000 to the subsequent flow rate data. If the bias test is failed 
    at one of the normal load levels but not at the other, use Equation 
    A-12 to calculate the BAF for the normal load level at which the 
    bias test was failed and apply that BAF to the subsequent flow rate 
    data. If the bias test is failed at both designated normal load 
    levels, use Equation A-12 to calculate the BAF at each normal load 
    level and apply the higher of the two BAFs to the subsequent flow 
    rate data.
        (e) Each time a RATA is passed 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.
        (f) 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, 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. In addition, when using a NOX 
    concentration monitoring system and a flow monitor to calculate 
    NOX mass emissions under subpart H of this part, use 
    bias-adjusted values for NOX concentration and flow rate 
    in the mass emission calculations and use bias-adjusted 
    NOX concentrations to compute the appropriate 
    substitution values for NOX concentration in the missing 
    data routines under subpart D of this part.
    * * * * *
    
    7.7  Reference Flow-to-Load Ratio or Gross Heat Rate
    
        (a) Except as provided in section 7.8 of this appendix, the 
    owner or operator shall determine Rref, the reference 
    value of the ratio of flow rate to unit load, each time that a 
    passing 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
    
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    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 April 1, 2000. The reference flow-to-load ratio shall be 
    calculated as follows:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.007
    
    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.
    
        (b) 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 (except for a discharge configuration consisting of 
    a main stack and a bypass stack), Qref will be the sum of 
    the total volumetric flow rates that discharge through all of the 
    stacks. For a unit with a multiple stack discharge configuration 
    consisting of a main stack and a bypass stack (e.g., a unit with a 
    wet SO2 scrubber), determine Qref separately 
    for each stack at the time of the normal load flow RATA. Round off 
    the value of Rref to two decimal places.
        (c) 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] TR26MY99.008
    
    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.
    
        (d) 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.
    
    7.8  Flow-to-Load Test Exemptions
    
        The requirements of this section apply beginning on April 1, 
    2000. For complex stack configurations (e.g., when the effluent from 
    a unit is divided and discharges through multiple stacks in such a 
    manner that the flow rate in the individual stacks cannot be 
    correlated with unit load), the owner or operator may petition the 
    Administrator under Sec. 75.66 for an exemption from the 
    requirements of section 7.7 of this appendix. The petition must 
    include sufficient information and data to demonstrate that a flow-
    to-load or gross heat rate evaluation is infeasible for the complex 
    stack configuration.
    
    Appendix B to Part 75--Quality Assurance and Quality Control Procedures
    
        60. Appendix B to part 75 is amended by revising sections 1 and 
    1.1; adding sections 1.1.1 through 1.1.3; revising section 1.2; 
    adding sections 1.2.1 through 1.2.4; revising section 1.3; adding 
    sections 1.3.1 through 1.3.6; revising section 1.4; adding sections 
    1.4.1 through 1.4.3; and removing sections 1.5 and 1.6 to read as 
    follows:
    
    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 or E 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.
    
    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 and E to 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 of flow monitor or moisture 
    monitoring system polynomial coefficients, K factors or mathematical 
    algorithms, changing of 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 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
    
    [[Page 28645]]
    
    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 SOX or 
    NO2 missing data period.
    
    1.3  Specific Requirements for Excepted Systems Approved Under 
    Appendices D and E
    
    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 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., baroscope), 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 maintaining 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.
    
    1.4  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.
        61. Appendix B to part 75 is amended by:
        a. Revising the first paragraph of section 2.1.1, revising 
    sections 2.1.3 and 2.1.4; revising paragraph (1) of section 2.1.5.1; 
    revising sections 2.2 through 2.2.3; adding sections 2.2.4 through 
    2.2.5.3; revising sections 2.3 and 2.3.1; adding sections 2.3.1.1 
    through 2.3.1.4; revising sections 2.3.2 and 2.3.3; and adding 
    section 2.3.4;
        b. Redesignating existing section 2.4 as section 2.5;
        c. Adding new section 2.4; and
        d. Revising Figures 1 and 2 at the end of appendix B to read as 
    follows:
    
    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.
    * * * * *
    
    2.1.3  Additional Calibration Error Tests and Calibration Adjustments
    
        (a) In addition to the daily calibration error tests required 
    under section 2.1.1 of this appendix, a calibration error test of a 
    monitor shall be performed in accordance with section 2.1.1 of this 
    appendix, as follows: whenever a daily calibration error test is 
    failed; 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; 
    or after making certain calibration adjustments, as described in 
    this section. Except in the case of the routine calibration 
    adjustments described in this section, data from the monitor are 
    considered invalid until the required additional calibration error 
    test has been successfully completed.
        (b) 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.
        (c) Additional (non-routine) calibration adjustments of a 
    monitor are permitted prior to (but not during) linearity checks and 
    RATAs and at other times, 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 at both the zero and upscale calibration 
    levels.
    
    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="">2 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
    
    [[Page 28646]]
    
    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 
    upon failure of the calibration error test and ends upon completion 
    of a successful calibration error test. Note, that if a 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 two 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 monitor or monitoring 
    system, perform the following quarterly assessments. This 
    requirement is applies 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, as 
    defined in Sec. 72.2 of this chapter. 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(e) 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 linearity check shall not be commenced if the monitoring 
    system is operating out-of-control with respect to any of the daily 
    or semiannual quality assurance assessments required by sections 2.1 
    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) Each required linearity check shall be done according to 
    paragraph (b)(1), (b)(2) or (b)(3) of this section:
        (1) The linearity check may be done ``cold,'' i.e., with no 
    corrective maintenance, repair, calibration adjustments, re-
    linearization or reprogramming of the monitor prior to the test.
        (2) The linearity check may be done after performing only the 
    routine or non-routine calibration adjustments described in section 
    2.1.3 of this appendix at the various calibration gas levels (zero, 
    low, mid or high), but no other corrective maintenance, repair, re-
    linearization or reprogramming of the monitor. Trial gas injection 
    runs may be performed after the calibration adjustments and 
    additional adjustments within the allowable limits in section 2.1.3 
    of this appendix may be made prior to the linearity check, as 
    necessary, to optimize the performance of the monitor. The trial gas 
    injections need not be reported, provided that they meet the 
    specification for trial gas injections in 
    Sec. 75.20(b)(3)(vii)(E)(1). However, if, for any trial injection, 
    the specification in Sec. 75.20(b)(3)(vii)(E)(1) is not met, the 
    trial injection shall be counted as an aborted linearity check.
        (3) The linearity check may be done after repair, corrective 
    maintenance or reprogramming of the monitor. In this case, the 
    monitor shall be considered out-of-control from the hour in which 
    the repair, corrective maintenance or reprogramming is commenced 
    until the linearity check has been passed. Alternatively, the data 
    validation procedures and associated timelines in 
    Secs. 75.20(b)(3)(ii) through (ix) may be followed upon completion 
    of the necessary repair, corrective maintenance, or reprogramming. 
    If the procedures in Sec. 75.20(b)(3) are used, the words ``quality 
    assurance'' apply instead of the word ``recertification''.
        (c) Once a linearity check has been commenced, the test shall be 
    done hands-off. That is, no adjustments of the monitor are permitted 
    during the linearity test period, other than the routine calibration 
    adjustments following daily calibration error tests, as described in 
    section 2.1.3 of this appendix.
        (d) If a daily calibration error test is failed during a 
    linearity test period, prior to completing the test, the linearity 
    test 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 commenced until the 
    monitor has successfully completed a calibration error test.
        (e) 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 section 
    3.2 of appendix A to this part) or when a linearity test is aborted 
    due to a problem with the monitor or monitoring system. 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, unless the option in paragraph (b)(3) of this 
    section to use the data validation procedures and associated 
    timelines in Sec. 75.20(b)(3)(ii) through (ix) has been selected, in 
    which case the beginning and end of the out-of-control period shall 
    be determined in accordance with Secs. 75.20(b)(3)(vii)(A) and (B). 
    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).
        (f) No more than four successive calendar quarters shall elapse 
    after the quarter in which a linearity check of a monitor or 
    monitoring system (or range of a monitor or monitoring system) 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 or 
    stack 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.
        (g) 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.
        (h) 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, including trial gas injections counted as failed 
    test attempts under paragraph (b)(2) of this section or
    
    [[Page 28647]]
    
    under Sec. 75.20(b)(3)(vii)(F)), 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. A record of all linearity 
    tests, trial gas injections and test 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
    
        (a) 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 monitor or monitoring 
    system, four successive calendar quarters have elapsed after the 
    quarter in which a linearity check of a monitor or monitoring system 
    (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, as defined in Sec. 72.2 of this 
    chapter (or, for monitors installed on common stacks or bypass 
    stacks, 168 consecutive stack operating hours, as defined in 
    Sec. 72.2 of this chapter) in which to perform a linearity test or 
    leak check of that monitor or monitoring system (or range). The 
    grace period begins with the first unit or stack 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.
        (b) If, at the end of the 168 unit (or stack) 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 monitor or monitoring 
    system (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 
    missed linearity test or leak check is completed.
    
    2.2.5  Flow-to-Load Ratio or Gross Heat Rate Evaluation
    
        (a) Applicability and methodology. The provisions of this 
    section apply beginning on April 1, 2000. Unless exempted by an 
    approved petition in accordance with section 7.8 of appendix A to 
    this part, the owner or operator shall, for each flow rate 
    monitoring system installed on each unit, common stack or multiple 
    stack, evaluate the flow-to-load ratio quarterly, i.e., for each QA 
    operating quarter (as defined in Sec. 72.2 of this chapter). At the 
    end of each QA operating quarter, the owner or operator shall use 
    Equation B-1 to calculate the flow-to-load ratio for every hour 
    during the quarter in which: 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 a quality assured hourly average flow rate was 
    obtained with a certified flow rate monitor.
    [GRAPHIC] [TIFF OMITTED] TR26MY99.009
    
    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.
    
        (1) 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 (except when one of the stacks 
    is a bypass stack) or that monitors its emissions in multiple 
    breechings, Qh will be the combined hourly volumetric 
    flow rate for all of the stacks or ducts. For a unit with a multiple 
    stack discharge configuration consisting of a main stack and a 
    bypass stack, each of which has a certified flow monitor (e.g., a 
    unit with a wet SO2 scrubber), calculate the hourly flow-
    to-load ratios separately for each stack. Round off each value of 
    Rh to two decimal places.
        (2) 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 monitor or monitoring system or reference method. If this 
    option is selected, calculate each hourly GHR value as follows:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.010
    
    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.
    
        (3) 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.
        (4) 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 recorded 
    hourly average flow rates. 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.
        (5) 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.
    
    [[Page 28648]]
    
    [GRAPHIC] [TIFF OMITTED] TR26MY99.011
    
    
    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.
    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.
    
        (6) 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.
        (b) Acceptable results. 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: (1) 15.0 percent, if Lavg for the most 
    recent normal-load flow RATA is 60 megawatts (or 
    500 klb/hr of steam) and if unadjusted flow rates were 
    used in the calculations; or (2) 10.0 percent, if Lavg 
    for the most recent normal-load flow RATA is 60 megawatts 
    (or 500 klb/hr of steam) and if bias-adjusted flow rates 
    were used in the calculations; or (3) 20.0 percent, if 
    Lavg for the most recent normal-load flow RATA is <60 megawatts="" (or=""><500 klb/hr="" of="" steam)="" and="" if="" unadjusted="" flow="" rates="" were="" used="" in="" the="" calculations;="" or="" (4)="" 15.0="" percent,="" if="">avg for the most recent normal-load flow RATA is <60 megawatts="" (or=""><500 klb/hr="" of="" steam)="" and="" if="" bias-adjusted="" flow="" rates="" were="" used="" in="" the="" calculations.="" if="">f is above these 
    limits, the owner or operator shall either: implement Option 1 in 
    section 2.2.5.1 of this appendix; or perform a RATA in accordance 
    with Option 2 in section 2.2.5.2 of this appendix; or 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.
        (c) Recalculation of Ef. 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) For a unit that is equipped with an SO2 scrubber 
    and which always discharges its flue gases to the atmosphere through 
    a single stack, any hour in which the 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) For a unit with a multiple stack discharge configuration 
    consisting of a main stack and a bypass stack, any hour in which the 
    flue gases were discharged through both stacks;
        (5) If a normal-load flow RATA was performed and passed during 
    the quarter being analyzed, any hour prior to completion of that 
    RATA; and
        (6) 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.
        (7) After identifying and excluding all non-representative 
    hourly data in accordance with paragraphs (c)(1) through (6) of this 
    section, 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.
        (8) If, after re-analyzing the data, Ef meets the 
    applicable limit in paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of 
    this section, 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 two weeks of the end of the calendar quarter for which 
    the Ef value is above the applicable limit, investigate 
    and troubleshoot the applicable flow monitor(s). 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 or K factor(s)), 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 then either may complete the abbreviated flow-to-load 
    test in section 2.2.5.3 of this appendix, or, if the corrective 
    action taken has required relinearization of the flow monitor, shall 
    perform a 3-level RATA.
    
    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 passed.
    
    2.2.5.3  Abbreviated Flow-to-Load Test
    
        (a) 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 or K factor(s)) 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.
        (b) 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 six 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 three 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-
    
    [[Page 28649]]
    
    to-load ratio (or GHR), using Equation B-2 of this appendix and then 
    calculate Ef, the arithmetic average of the Eh 
    values.
        (c) 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 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.
    
    2.3  Semiannual and Annual Assessments
    
        For each primary and redundant backup monitoring system, perform 
    relative accuracy assessments either semiannually or annually, as 
    specified in section 2.3.1.1 or 2.3.1.2 of this appendix, for the 
    type of test and the performance achieved. This requirement applies 
    as of the calendar quarter following the calendar quarter in which 
    the 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
    
        (a) 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 (as defined in Sec. 72.2 of this chapter) for 
    each primary and redundant backup SO2 pollutant 
    concentration monitor, flow monitor, CO2 pollutant 
    concentration monitor (including O2 monitors used to 
    determine CO2 emissions), CO2 or O2 
    diluent monitor used to determine heat input, moisture monitoring 
    system, NOX concentration monitoring system, 
    NOX-diluent continuous emission monitoring system, or 
    SO2-diluent continuous emission monitoring system. 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 (or stack) 
    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.
        (b) The relative accuracy test audit frequency of a CEMS may be 
    reduced, as specified in section 2.3.1.2 of this appendix, 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 sections 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), CO2 or 
    O2 diluent monitors used to determine heat input, 
    moisture monitoring systems, NOX concentration monitoring 
    systems, flow monitors, NOX-diluent monitoring systems 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:
        (a) 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 CO2 
    or O2 diluent monitor used to determine heat input, or of 
    a NOX concentration monitoring system, or of a 
    NOX-diluent monitoring system, or of an SO2-
    diluent continuous emissions monitoring system is  7.5 
    percent;
        (b) Prior to January 1, 2000, the relative accuracy during the 
    audit of a flow monitor is  10.0 percent at each 
    operating level tested;
        (c) 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;
        (d) For low flow ( 10.0 fps) stacks/ducts, when the 
    flow monitor fails to achieve a relative accuracy  7.5 
    percent (10.0 percent if prior to January 1, 2000) during the audit, 
    but the monitor mean value, calculated using Equation A-7 in 
    appendix A to this part and converted back to an equivalent velocity 
    in standard feet per second (fps), is within  1.5 fps of 
    the reference method mean value, converted to an equivalent velocity 
    in fps;
        (e) For low SO2 or NOX emitting units 
    (average SO2 or NOX concentrations  
    250 ppm, when an SO2 pollutant concentration monitor or 
    NOX concentration monitoring system fails to achieve a 
    relative accuracy  7.5 percent during the audit, but the 
    monitor mean value from the RATA is within  12 ppm of 
    the reference method mean value;
        (f) For units with low NOX emission rates (average 
    NOX emission rate  0.200 lb/mmBtu), when a 
    NOX-diluent continuous emission monitoring system fails 
    to achieve a relative accuracy  7.5 percent, but 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;
        (g) For units with low SO2 emission rates (average 
    SO2 emission rate  0.500 lb/mmBtu), when an 
    SO2-diluent continuous emission monitoring system fails 
    to achieve a relative accuracy  7.5 percent, but the 
    monitoring system mean value from the RATA, calculated using 
    Equation A-7 in appendix A to this part, is within  
    0.025 lb/mmBtu of the reference method mean value;
        (h) 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
        (i) 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  1.0 
    percent H2O.
    2.3.1.3  RATA Load Levels and Additional RATA Requirements
        (a) For SO2 pollutant concentration monitors, 
    CO2 pollutant concentration monitors (including 
    O2 monitors used to determine CO2 emissions), 
    CO2 or O2 diluent monitors used to determine 
    heat input, NOX concentration monitoring systems, 
    moisture monitoring systems, SO2-diluent monitoring 
    systems and NOX-diluent monitoring systems, the required 
    semiannual or annual 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 semiannual or annual 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:
        (1) An annual 2-load flow 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.
        (2) If the flow monitor is on a semiannual RATA frequency, 2-
    load flow RATAs and single-load flow RATAs at normal load may be 
    performed alternately.
        (3) A single-load annual flow RATA, at the most frequently used 
    load level, may be performed in lieu of the 2-load RATA if the 
    results of an historical load data analysis show that in the time 
    period extending from the ending date of the last annual flow RATA 
    to a date that is no more than 7 days prior to the date of the 
    current annual flow RATA, the unit has operated at a single load 
    level (low, mid or high) for  85.0 percent of the time. * 
    * *
        (4) 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.
        (5) A 3-load RATA is required whenever a flow monitor is re-
    linearized, i.e., when its polynomial coefficients or K factor(s) 
    are changed.
        (6) 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.
    
    [[Page 28650]]
    
        (d) A RATA of a moisture monitoring system shall be performed 
    whenever the coefficient, K factor or mathematical algorithm 
    determined under section 6.5.7 of appendix A to this part is 
    changed.
    
    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 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) Each required RATA shall be done according to paragraphs 
    (b)(1), (b)(2) or (b)(3) of this section:
        (1) The RATA may be done ``cold,'' i.e., with no corrective 
    maintenance, repair, calibration adjustments, re-linearization or 
    reprogramming of the monitoring system prior to the test.
        (2) The RATA may be done after performing only the routine or 
    non-routine calibration adjustments described in section 2.1.3 of 
    this appendix at the zero and/or upscale calibration gas levels, but 
    no other corrective maintenance, repair, re-linearization or 
    reprogramming of the monitoring system. Trial RATA runs may be 
    performed after the calibration adjustments and additional 
    adjustments within the allowable limits in section 2.1.3 of this 
    appendix may be made prior to the RATA, as necessary, to optimize 
    the performance of the CEMS. The trial RATA runs need not be 
    reported, provided that they meet the specification for trial RATA 
    runs in Sec. 75.20(b)(3)(vii)(E)(2). However, if, for any trial run, 
    the specification in Sec. 75.20(b)(3)(vii)(E)(2) is not met, the 
    trial run shall be counted as an aborted RATA attempt.
        (3) The RATA may be done after repair, corrective maintenance, 
    re-linearization or reprogramming of the monitoring system. In this 
    case, the monitoring system shall be considered out-of-control from 
    the hour in which the repair, corrective maintenance, re-
    linearization or reprogramming is commenced until the RATA has been 
    passed. Alternatively, the data validation procedures and associated 
    timelines in Secs. 75.20(b)(3)(ii) through (ix) may be followed upon 
    completion of the necessary repair, corrective maintenance, re-
    linearization or reprogramming. If the procedures in 
    Sec. 75.20(b)(3) are used, the words ``quality assurance'' apply 
    instead of the word ``recertification.''
        (c) Once a RATA is commenced, the test must be done hands-off. 
    No adjustment of the monitor's calibration is permitted during the 
    RATA test period, other than the routine calibration adjustments 
    following daily calibration error tests, as described in section 
    2.1.3 of this appendix. For 2-level and 3-level flow monitor audits, 
    no linearization or reprogramming of the monitor is permitted in 
    between load levels.
        (d) For single-load RATAs, if a daily calibration error test is 
    failed during a RATA test period, prior to completing the test, the 
    RATA 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 subsequent RATA shall not be 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 must be 
    repeated; the results of any previously-passed RATA(s) at the other 
    load level(s) are unaffected, unless re-linearization of the monitor 
    is required to correct the problem that caused the calibration 
    failure, in which case a subsequent 3-load RATA is required).
        (e) If a RATA is failed (that is, if the relative accuracy 
    exceeds the applicable 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 the CEMS is out-of-control and 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, unless the option in paragraph (b)(3) of this section 
    to use the data validation procedures and associated timelines in 
    Secs. 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which 
    case the beginning and end of the out-of-control period shall be 
    determined in accordance with Sec. 75.20(b)(3)(vii)(A) and (B). 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 (h) of this section).
        (f) 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 flow monitor, 
    the RATA at that load level must be repeated. The flow monitor is 
    considered out-of-control and data from the monitor are invalidated 
    from the hour in which the test is failed or aborted and remain 
    invalid until the passing of a RATA at the failed load level, unless 
    the option in paragraph (b)(3) of this section to use the data 
    validation procedures and associated timelines in 
    Sec. 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which 
    case the beginning and end of the out-of-control period shall be 
    determined in accordance with Sec. 75.20(b)(3)(vii)(A) and (B). Flow 
    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 flow monitor 
    is re-linearized, a subsequent 3-load RATA is required.
        (g) 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, beginning with the hour of completion of 
    the failed CO2 (or O2) monitor RATA, and 
    continuing 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, unless the option in paragraph (b)(3) of 
    this section to use the data validation procedures and associated 
    timelines in Secs. 75.20(b)(3)(ii) through (b)(3)(ix) has been 
    selected, in which case the beginning and end of the out-of-control 
    period shall be determined in accordance with Secs. 75.20(b)(3)(vii) 
    (A) and (B).
        (h) 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 RATAs; and all RATAs 
    aborted due to a problem with the CEMS, including trial RATA runs 
    counted as failed test attempts under paragraph (b)(2) of this 
    section or under Sec. 75.20(b)(3)(vii)(F)) 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. However, a record of all RATAs, trial RATA 
    runs and RATA attempts (whether reported or not) must be kept on-
    site as part of the official test log for each monitoring system.
        (i) Each time that a hands-off RATA of an SO2 
    pollutant concentration monitor, a NOX-diluent monitoring 
    system, a NOX concentration monitoring system or a flow 
    monitor is passed, 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.
        (j) Failure of the bias test does not result in the monitoring 
    system being out-of-control.
    
    2.3.3 RATA Grace Period
    
        (a) The owner or operator has a grace period of 720 consecutive 
    unit operating hours, as defined in Sec. 72.2 of this chapter (or, 
    for CEMS installed on common stacks or bypass stacks, 720 
    consecutive stack operating hours, as defined in Sec. 72.2 of this 
    chapter), in which to complete the required RATA for a particular 
    CEMS whenever: a required RATA has not been performed by the end of 
    the QA operating quarter in which it is due; or five consecutive 
    calendar years have elapsed without a required 3-load flow RATA 
    having been conducted; or for a unit which is conditionally exempted 
    under Sec. 75.21(a)(7) from the SO2 RATA requirements of 
    this part, an SO2 RATA has not been completed by the end 
    of the calendar quarter in which the annual usage of fuel(s) with a 
    sulfur content higher than very low sulfur fuel(as defined in 
    Sec. 72.2 of this chapter) exceeds 480 hours; or eight
    
    [[Page 28651]]
    
    successive calendar quarters have elapsed, following the quarter in 
    which a RATA was last performed, without a subsequent RATA having 
    been done, due either to infrequent operation of the unit(s) or 
    frequent combustion of very low sulfur fuel, as defined in Sec. 72.2 
    of this chapter (SO2 monitors, only), or a combination of 
    these factors.
        (b) Except for SO2 monitoring system RATAs, the grace 
    period shall begin with the first unit (or stack) 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 (or stack) operating hour in which fuel with a total 
    sulfur content higher than that of very low sulfur fuel (as defined 
    in Sec. 72.2 of this chapter) 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.
        (c) If, at the end of the 720 unit (or stack) 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, 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 RATA is actually 
    completed. However, if a RATA deadline determined in this manner is 
    less than two QA operating quarters from the quarter in which the 
    missed RATA is completed , the RATA deadline shall be re-set at two 
    QA operating quarters from the quarter in which the missed RATA is 
    completed .
    
    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, NOX continuous emission monitoring system, 
    or NOX concentration monitoring system used to calculate 
    NOX mass emissions 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, RATA Frequency and Bias 
    Adjustment Factors (Special Considerations)
    
        (a) 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 all recertifications, a RATA will be one of the 
    required tests; for some recertifications, other tests will also be 
    required. A 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 check 
    is successful, then, unless another such recertification event 
    occurs in that same QA operating quarter, it would not be necessary 
    to perform an additional linearity test of the CEMS in that quarter 
    to meet the quality assurance requirement of section 2.2.1 of this 
    appendix. 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.
        (b) Except as provided in section 2.3.3 of this appendix, 
    whenever a passing RATA of a gas monitor or a passing 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 
    RATA frequency (semi-annual or annual) 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 RATA frequency. The results of a single-load flow RATA 
    may be used to establish the RATA frequency when 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 when the single-load RATA is allowed under section 
    2.3.1.3(c) of this appendix for a unit that has operated at the most 
    frequently used load level for 85.0 percent of the time 
    since the last annual flow RATA. No other single-load flow RATA may 
    be used to establish an annual RATA frequency; however, a 2-load or 
    3-load flow RATA may be performed at any time or in place of any 
    required single-load RATA, in order to establish an annual RATA 
    frequency.
    
    2.5  Other Audits
    
    * * * * *
    
                         Figure 1 to Appendix B of Part 75--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, 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 annual RATAs at the two load levels used most frequently since the last
      annual RATA. 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, since the last annual flow RATA, 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 flitor is re-linearized.
    
    
                 Figure 2 to Appendix B of Part 75--Relative Accuracy Test Frequency Incentive System .
    ----------------------------------------------------------------------------------------------------------------
                RATA                       Semiannual 1 (percent)                           Annual 1
    ----------------------------------------------------------------------------------------------------------------
    SO2 or NOX3.................  7.5%  10.0% or  7.5% or  12.0
                                   minus> 15.0 ppm2.                         ppm2
    SO2-diluent.................  7.5% < ra=""> 10.0% or  7.5% or 
                                   minus> 0.030.                             0.025.
                                  lb/mmBtu 2..............................  lb/mmBtu 2
    NOX-diluent.................  7.5% < ra=""> 10.0% or  7.5% or 
                                   minus> 0.020.                             0.015.
    
    [[Page 28652]]
    
     
                                  lb/mmBtu 2..............................  lb/mmBtu 2.
    Flow (Phase I)..............  10.0% < ra=""> 15.0% or  10.0%.
                                   minus> 1.5 fps 2.
    Flow (Phase II).............  7.5% < ra=""> 10.0% or  7.5%.
                                   minus> 1.5 fps 2.
    CO2 or O2...................  7.5% < ra=""> 10.0% or  7.5% or  0.7%
                                   minus> 1.0% CO2/O22.                      CO2/O22.
    Moisture....................  7.5% < ra=""> 10.0% or  7.5% or  1.0%
                                   minus> 1.5% H2O2.                         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 with
      fewer than 168 unit operating hours (or, for common stacks and bypass stacks, exclude quarters with fewer than
      168 stack operating hours) in determining the RATA deadline. For SO2 monitors, QA operating quarters in which
      only very low sulfur fuel as defined in Sec.  72.2, 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.
    \3\ A NOX concentration monitoring system used to determine NO2 mass emissions under Sec.  75.71.
    
    Appendix C To Part 75--Missing Data Statistical Estimation Procedures
    
        62.-63. Appendix C to part 75 is amended by revising sections 
    2.1, 2.2.1, 2.2.2, 2.2.3, and 2.2.5, and by revising section 2.2.3.9 
    to read as follows:
    
    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), NOX 
    emission rate (in lb/mmBtu) from NOX-diluent continuous 
    emission monitoring systems, and NOX concentration data 
    (in ppm) from NOx concentration monitoring systems used to determine 
    NOX mass emissions.
        2.2 * * *
        2.2.1  For a single unit, establish ten 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
    ------------------------------------------------------------------------
                                                                 Percent of
                                                                   maximum
                                                                hourly gross
                                                                   load or
                       Operating load range                        maximum
                                                                hourly gross
                                                                 steam load
                                                                  (percent)
    ------------------------------------------------------------------------
    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
    ------------------------------------------------------------------------
    
        2.2.2  Beginning with the first hour of unit operation after 
    installation and certification of the flow monitor or the 
    NOX-diluent continuous emission monitoring system (or a 
    NOX concentration monitoring system used to determine 
    NOX mass emissions, as defined in Sec. 75.71(a)(2)), for 
    each hour of unit operation record a number, 1 through 10, (or 1 
    through 20 for flow at common stacks) that identifies the operating 
    load range corresponding to the integrated hourly gross load of the 
    unit(s) recorded for each unit operating hour.
        2.2.3  Beginning with the first hour of unit operation after 
    installation and certification of the flow monitor or the 
    NOX-diluent continuous emission monitoring system (or a 
    NOX concentration monitoring system used to determine 
    NOX mass emissions, as defined in Sec. 75.71(a)(2)) and 
    continuing thereafter, the data acquisition and handling system must 
    be capable of calculating and recording the following information 
    for each unit operating hour of missing flow or NOX data 
    within each identified load range during the shorter of: (a) the 
    previous 2,160 quality assured monitor operating hours (on a rolling 
    basis), or (b) all previous quality assured monitor operating hours.
    * * * * *
        2.2.3.9  Average of the hourly NOX pollutant 
    concentrations, in ppm, reported by a NOX concentration 
    monitoring system used to determine NOX mass emissions, 
    as defined in Sec. 75.71(a)(2).
    * * * * *
        2.2.5  When a bias adjustment is necessary for the flow monitor 
    and/or the NOX-diluent continuous emission monitoring 
    system (and/or the NOX concentration monitoring system 
    used to determine NOX mass emissions, as defined in 
    Sec. 75.71(a)(2)), apply the adjustment factor to all monitor or 
    continuous emission monitoring system data values placed in the load 
    ranges.
    * * * * *
    
    Appendix D To Part 75--Optional SO2 Emissions Data Protocol 
    for Gas-Fired and Oil-Fired Units
    
        64. Appendix D to part 75 is amended by revising section 1.1 to 
    read as follows:
    
    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 mass emissions and heat 
    input 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. Section 2.1 of this appendix provides procedures for 
    measuring oil or gaseous fuel flow using a fuel flowmeter, section 
    2.2 of this appendix provides procedures for conducting oil sampling 
    and analysis to determine sulfur content and gross calorific value 
    (GCV) of fuel oil, and section 2.3 of this appendix provides 
    procedures for determining the sulfur content and GCV of gaseous 
    fuels.
    * * * * *
        65. Appendix D to part 75 is further amended by:
        a. Revising sections 2.1 and 2.1.1;
        b. Addding sections 2.1.1.1 through 2.1.1.3;
        c. Revising sections 2.1.2 through 2.1.4;
        d. Adding sections 2.1.4.1 through 2.1.4.3;
        e. Revising sections 2.1.5 through 2.1.5.2;
        f. Adding sections 2.1.5.3 through 2.1.5.4;
        g. Revising sections 2.1.6 through 2.1.6.2;
        h. Adding sections 2.1.6.3 through 2.1.7.5;
        i. Revising sections 2.2 and 2.2.1;
        j. Removing sections 2.2.1.1 and 2.2.1.2;
        k. Removing and reserving section 2.2.2;
        l. Revising sections 2.2.3 and 2.2.4;
        m. Adding sections 2.2.4.1 through 2.2.4.3;
    
    [[Page 28653]]
    
        n. Revising the first sentence of section 2.2.6;
        o. Revising sections 2.2.8 and 2.3 through 2.3.2.1;
        p. Adding sections 2.3.2.1.1 and 2.3.2.1.2;
        q. Revising section 2.3.2.2;
        r. Adding sections 2.3.2.3 through 2.3.6;
        s. Revising section 2.4.1;
        t. Removing section 2.4.2, and redesignating sections 2.4.3, 
    2.4.3.1, 2.4.3.2, 2.4.3.3 and 2.4.4 as sections 2.4.2, 2.4.2.1, 
    2.4.2.2, 2.4.2.3 and 2.4.3, respectively; and
        u. Revising newly redesignated sections 2.4.2, 2.4.2.1, and 
    2.4.2.3 to read as follows:
    
    2. Procedure
    
    2.1  Fuel 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 in section 2.1.4 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, on an annual basis, more than 5.0 percent 
    of the fuel 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. However, the additional fuel 
    flowmeter is not required if, on an annual basis, the total amount 
    of fuel diverted away from the unit, expressed as a percentage of 
    the total annual fuel usage by the unit is demonstrated to be less 
    than or equal to 5.0 percent. The owner or operator may make this 
    demonstration in the following manner:
        2.1.1.1  For existing units with fuel usage data from fuel 
    flowmeters, if data are submitted from a previous year demonstrating 
    that the total diverted yearly fuel does not exceed 5% of the total 
    fuel used; or
        2.1.1.2  For new units which do not have historical data, if a 
    letter is submitted signed by the designated representative 
    certifying that, in the future, the diverted fuel will not exceed 
    5.0% of the total annual fuel usage ; or
        2.1.1.3  By using a method approved by the Administrator under 
    Sec. 75.66(d).
        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: the proposed 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 (see section 3.4.3 of this appendix); 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 or Oil Flowmeter Used for Commercial Billing
    
        A gas or oil flowmeter used for commercial billing of natural 
    gas or oil may be used to measure, record, and report hourly fuel 
    flow rate. A gas or oil flowmeter used for commercial billing of 
    natural gas or oil 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:
        (a) The gas or oil flowmeter is used for commercial billing 
    under a contract, provided that the company providing the gas or oil 
    under the contract and each unit combusting the gas or oil do not 
    have any common owners and are not owned by subsidiaries or 
    affiliates of the same company;
        (b) The designated representative reports hourly records of gas 
    or oil flow rate, heat input rate, and emissions due to combustion 
    of natural gas or oil;
        (c) The designated representative also reports hourly records of 
    heat input rate for each unit, if the gas or oil flowmeter is on a 
    common pipe header, consistent with section 2.1.2 of this appendix;
        (d) The designated representative reports hourly records 
    directly from the gas or oil 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
        (e) The designated representative identifies the gas or oil 
    flowmeter in the unit's monitoring plan.
    
    2.1.4.3 Emergency Fuel
    
        The designated representative of a unit that is restricted by 
    its Federal, State or local permit to combusting a particular fuel 
    only during emergencies where the primary fuel is not available is 
    exempt from certifying a fuel flowmeter for use during combustion of 
    the emergency fuel. During any hour in which the emergency fuel is 
    combusted, report the hourly heat input to be the maximum rated heat 
    input of the unit for the fuel. Additionally, begin sampling the 
    emergency fuel for sulfur content only using the procedures under 
    section 2.2 (for oil) or 2.3 (for gas) of this appendix. The 
    designated representative shall also provide notice under 
    Sec. 75.61(a)(6)(ii) for each period when the emergency fuel is 
    combusted.
    
    2.1.5  Initial Certification Requirement for all Fuel Flowmeters
    
        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 in any of the following ways (as applicable): by 
    design or by measurement under laboratory conditions; by the 
    manufacturer; by an independent laboratory; or by the owner or 
    operator. Flowmeter accuracy may also 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''
    
    [[Page 28654]]
    
    (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 (Second Revision, April, 1996); 
    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 the Liquid in a Volumetric Tank;'' American Petroleum 
    Institute (API) Section 2, ``Conventional Pipe Provers'', Section 3, 
    ``Small Volume Provers'', and Section 5, ``Master-Meter Provers'', 
    from Chapter 4 of the Manual of Petroleum Measurement Standards, 
    October 1988 (Reaffirmed 1993); or ASME 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  (a) 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,
        (3) A load point approximately equally spaced between the full 
    and minimum unit operating loads, and
        (4) Calculate the flowmeter accuracy at each of the three flow 
    levels using the following equation:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.012
    
    Where:
    ACC=Flowmeter accuracy at a particular load level, as a percentage 
    of the upper range value.
    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).
        (c) 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 for quality assurance 
    under section 2.1.6 of this appendix, 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 performed according to a standard 
    incorporated by reference under section 2.1.5.1 of this appendix), 
    report the results of flowmeter accuracy tests using the following 
    Table D-1.
    
                 Table D-1.--Table of Flowmeter Accuracy Results
    ------------------------------------------------------------------------
     
    -------------------------------------------------------------------------
    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:
    ------------------------------------------------------------------------
    
    
     
                                                                                                           Percent
                                                                  Time of run   Candidate    Reference     accuracy
     Measurement level (percent of URV)          Run No.             (HHMM)     flowmeter       flow     (percent of
                                                                                 reading      reading        URV)
    ----------------------------------------------------------------------------------------------------------------
    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 and hour that the fuel flowmeter was reinstalled
      following the test.
    \3\ It is required to test at least at three different levels: (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.
    
    
    [[Page 28655]]
    
    2.1.6   Quality Assurance
    
        (a) Test the accuracy of each fuel flowmeter prior to use under 
    this part and at least once every four fuel flowmeter QA operating 
    quarters, as defined in Sec. 72.2 of this chapter, thereafter. 
    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.
        (b) 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 must meet the accuracy specification in section 2.1.5 
    of this appendix.
        (c) For orifice-, nozzle-, and venturi-type flowmeters, either 
    perform the required flowmeter accuracy testing using the procedures 
    in section 2.1.5.1 or 2.1.5.2 of this appendix or perform a 
    transmitter accuracy test once every four fuel 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 2.1.6.4 of this appendix for periodic quality 
    assurance.
        (d) Notwithstanding the requirements of this section, if the 
    procedures of section 2.1.7 (fuel flow-to-load test) 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
    
        (a) 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 (e.g., ``mid'' and ``high''), such that the 
    full range of transmitter or transducer readings corresponding to 
    normal unit operation is represented.
        (b) Calculate the accuracy of each transmitter or transducer at 
    each level tested, using the following equation:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.013
    
    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 
    (in milliamperes, inches of water, psi, or degrees, consistent with 
    the units of measure of the NIST traceable reference value).
    
        (c) If each transmitter or transducer meets an accuracy of 
     1.0 percent of its full-scale range at each level 
    tested, the fuel flowmeter accuracy of 2.0 percent is considered to 
    be met at all levels. If, however, one or more of the transmitters 
    or transducers does not meet an accuracy of  1.0 percent 
    of full-scale at a particular level, then the owner or operator may 
    demonstrate that the fuel flowmeter meets the total accuracy 
    specification of 2.0 percent at that level by using one of the 
    following alternative methods. If, at a particular level, the sum of 
    the individual accuracies of the three transducers is less than or 
    equal to 4.0 percent, the fuel flowmeter accuracy specification of 
    2.0 percent is considered to be met for that level. Or, if at a 
    particular level, the total fuel flowmeter accuracy is 2.0 percent 
    or less, when calculated in accordance with Part 1 of American Gas 
    Association Report No. 3, General Equations and Uncertainty 
    Guidelines, the flowmeter accuracy requirement is considered to be 
    met for that level.
    
    2.1.6.2   Recordkeeping and Reporting of Transmitter or Transducer 
    Accuracy Results
    
        (a) 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 the following Table D-2. 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-2.--Table of Flowmeter Transmitter or Transducer Accuracy
                                     Results
    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
    ------------------------------------------------------------------------
    
    
     
                                                                               Expected
                                      Run number               Transmitter/  transmitter/     Actual       Percent
     Measurement level (percent of       (if        Run time    transducer    transducer   transmitter/    accuracy
              full-scale)              multiple      (HHMM)     input (pre-     output      transducer   (percent of
                                      runs) \2\                calibration)   (reference)   output \3\   full-scale)
    ----------------------------------------------------------------------------------------------------------------
    Low (Minimum) level
        ____ percent \1\ of full-    ...........
         scale
    Mid-level
        ____ percent\1\ of full-     ...........
         scale
    (If tested at more than 3
     levels)
    2nd Mid-level
        ____ percent \1\ of full-    ...........
         scale
    (If tested at more than 3
     levels)
    3rd Mid-level
        ____ percent \1\ of full-    ...........
         scale
    High (Maximum) level
        ____ percent \1\ 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).
    
    
    [[Page 28656]]
    
        (b) When accuracy testing of the orifice, nozzle, or venturi 
    meter is performed according to section 2.1.5.2 of this appendix, 
    record the information displayed in Table D-1 in this section. At a 
    minimum, record the overall flowmeter accuracy results for the fuel 
    flowmeter at the three flow rate levels specified in section 2.1.5.2 
    of this appendix.
        (c) Report the results of all fuel flowmeter accuracy tests, 
    transmitter or transducer accuracy tests, and primary element 
    inspections, as applicable, in the emissions report for the quarter 
    in which the quality assurance tests are performed, using the 
    electronic format specified by the Administrator under Sec. 75.64.
    
    2.1.6.3  Failure of Transducer(s) or Transmitter(s)
    
        If, during a transmitter or transducer accuracy test conducted 
    according to section 2.1.6.1 of this appendix, the flowmeter 
    accuracy specification of 2.0 percent is not met at any of the 
    levels tested, repair or replace transmitter(s) or transducer(s) as 
    necessary until the flowmeter accuracy specification has been 
    achieved at all levels. (Note that only transmitters or transducers 
    which are repaired or replaced need to be re-tested; however, the 
    re-testing is required at all three measurement levels, to ensure 
    that the flowmeter accuracy specification is met at each level). The 
    fuel flowmeter is ``out-of-control'' and data from the flowmeter are 
    considered invalid, beginning with the date and hour of the failed 
    accuracy test and continuing until the date and hour of completion 
    of a successful transmitter or transducer accuracy test at all 
    levels. In addition, if, during normal operation of the fuel 
    flowmeter, one or more transmitters or transducers malfunction, data 
    from the fuel flowmeter shall be considered invalid from the hour of 
    the transmitter or transducer failure until the hour of completion 
    of a successful 3-level transmitter or transducer accuracy test. 
    During fuel flowmeter out-of-control periods, 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 sections 
    2.1.6.1 and 2.1.6.2 of this appendix and Sec. 75.56 or Sec. 75.59, 
    as applicable.
    
    2.1.6.4  Primary Element Inspection
    
        (a) Conduct a visual inspection of the orifice, nozzle, or 
    venturi meter 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 meter to at least once every twenty 
    calendar quarters. The inspection may be performed using a 
    baroscope. If the visual inspection indicates that the orifice, 
    nozzle, or venturi meter 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.
        (b) 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 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 2.1.6.1 of this appendix.
        (c) 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 2.1.6.4 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 section 2.1.7.1 of this appendix 
    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 
    fuel flowmeter QA operating quarter, as defined in Sec. 72.2 of this 
    chapter (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 2.1.6.4 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 2.1.6.4 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
    
        (a) 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 sections 2.1.5.1, 
    2.1.5.2, or 2.1.6.1 and 2.1.6.4 of this appendix. Establish a 
    baseline period of data consisting, at a minimum, of 168 hours of 
    quality assured fuel flowmeter data. Baseline data collection shall 
    begin with the first hour of fuel flowmeter operation following 
    completion of 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 as non-representative 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 may exclude any hour in which the unit load is 
    in the lower 25.0 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 25.0 percent of the range is considered normal for the unit). 
    The baseline data must be obtained no later than the end of the 
    fourth 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-
    
    [[Page 28657]]
    
    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 2.1.6.4 of this appendix, then the 
    baseline data must be obtained after both procedures are completed 
    and no later than the end of the fourth 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] TR26MY99.014
    
    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.
    
        (b) In Equation D-1b, 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.
        (c) 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] TR26MY99.015
    
    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.
    
        (d) 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
    
        (a) Evaluate the fuel flow rate-to-load ratio (or GHR) for each 
    fuel flowmeter QA operating quarter, as defined in Sec. 72.2 of this 
    chapter. At the end of each fuel flowmeter QA operating quarter, use 
    Equation D-1d 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] TR26MY99.016
    
    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.
    
        (b) 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.
        (c) 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] TR26MY99.017
    
    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.
    
        (d) 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 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.
        (e) 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-1f.
    [GRAPHIC] [TIFF OMITTED] TR26MY99.018
    
    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.
    
        (f) Consistently use Rbase and Rh in 
    Equation D-1f if the fuel flow-to-load ratio is being evaluated, and 
    consistently use (GHR)base and (GHR)h in 
    Equation D-1f if the gross heat rate is being evaluated.
        (g) Next, determine the arithmetic average of all of the hourly 
    percent difference (percent Dh) values using Equation D-
    1g, as follows:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.019
    
    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.
    
        (h) 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
    
    [[Page 28658]]
    
    acceptable if the value of Ef is no greater than 15.0 
    percent.
    
    2.1.7.3  Optional Data Exclusions
    
        (a) 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 may be considered non-representative: any 
    hour in which the unit combusted another fuel in addition to the 
    fuel measured by the fuel flowmeter being tested; or 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; or 
    any hour for which the unit load was in the lower 25.0 percent of 
    the range of operation, as defined in section 6.5.2.1 of appendix A 
    to this part (unless operation in the lower 25.0 percent of the 
    range is considered normal for the unit).
        (b) 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-Load Ratio Test
    
        (a) 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 2.1.6.4 of this appendix, and repair or replace 
    the primary element, as necessary.
        (b) 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 (note that for orifice-, nozzle-, or venturi-type fuel 
    flowmeters, establish a new value of Rbase or 
    (GHR)base only 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-1g, in the electronic 
    quarterly report required under Sec. 75.64. Table D-3 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-3.--Baseline Information and Test Results for Fuel Flow-to-Load
                                      Test
    ------------------------------------------------------------------------
     
    -------------------------------------------------------------------------
    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)
    ------------------------------------------------------------------------
    
    
     
                                   Time period
    -------------------------------------------------------------------------
                   Baseline period                          Quarter
    ------------------------------------------------------------------------
    Completion date and time of most recent        Number of hours excluded
     primary element inspection (orifice-, nozzle-  from quarterly average
     , and venturi-type flowmeters only).           due to co-firing
                                                    different fuels:________
                                                    hrs.
        ____/____/____ ____:____
    Completion date and time of the most recent    Number of hours excluded
     flowmeter or transmitter accuracy test.        from quarterly average
                                                    due to ramping load:
                                                    ________ hrs.
        ____/____/____ ____:____
    Beginning date and time of baseline period...  Number of hours in the
                                                    lower 25.0 percent of
                                                    the range of operation
                                                    excluded from quarterly
                                                    average: ________ hrs.
        ____/____/____ ____:____
    End date and time of baseline period.........  Number of hours included
                                                    in quarterly average:
                                                    ________ hrs.
        ____/____/____ ____:____
    Average fuel flow rate____________________     Quarterly percentage
     (100 scfh for gas and lb/hr for oil).          difference between
                                                    hourly ratios and
                                                    baseline ratio: ________
                                                    percent.
    Average load;____________________ (MWe or      Test result: pass, fail.
     1000 lb steam/hr).
    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:________
    Number of hours in the lower 25.0 percent of
     the range of operation excluded from
     baseline ration or GHR: ________ hrs.
    ------------------------------------------------------------------------
    
    2.2 Oil Sampling and Analysis
    
        Perform sampling and analysis of oil to determine the following 
    fuel properties for each type of oil combusted by a unit: percentage 
    of sulfur by weight in the oil; gross calorific value (GCV) of the 
    oil; and, if necessary, the density of the oil. Use the sulfur 
    content, density, and gross calorific value, determined under the 
    provisions of this section, to calculate SO2 mass 
    emission rate and heat input rate for each fuel using the applicable 
    procedures of section 3 of this appendix. The designated 
    representative may petition for reduced GCV and or density sampling 
    under Sec. 75.66 if the fuel combusted
    
    [[Page 28659]]
    
    has a consistent and relatively non-variable GCV or density.
    
           Table D-4.--Oil Sampling Methods and Sulfur, Density and Gross Calorific Value Used in Calculations
    ----------------------------------------------------------------------------------------------------------------
                   Parameter                 Sampling technique/frequency          Value used in calculations
    ----------------------------------------------------------------------------------------------------------------
    Oil Sulfur Content....................  Daily manual sampling.........  1. Highest sulfur content from previous
                                                                             30 daily samples; or
                                                                            2. Actual daily value.
                                            Flow proportional/weekly        Actual measured value.
                                             composite.
                                            In storage tank (after          1. Actual measured value; or
                                             addition of fuel to tank).     2. Highest of all sampled values in
                                                                             previous calendar year; or
                                                                            3. Maximum value allowed by contract.\1\
                                            As delivered (in delivery       1. Highest of all sampled values in
                                             truck or barge).\1\.            previous calendar year; or
                                                                            2. Maximum value allowed by contract.\1\
    Oil Density...........................  Daily manual sampling.........  1. Use the highest density from the
                                                                             previous 30 daily samples; or
                                                                            2. Actual measured value.
                                            Flow proportional/weekly        Actual measured value.
                                             composite.
                                            In storage tank (after          1. Actual measured value; or
                                             addition of fuel to tank).     2. Highest of all sampled values in
                                                                             previous calendar year; or
                                                                            3. Maximum value allowed by contract.\1\
                                            As delivered (in delivery       1. Highest of all sampled values in
                                             truck or barge).\1\.            previous calendar year; or
                                                                            2. Maximum value allowed by contract.\1\
    Oil GCV...............................  Daily manual sampling.........  1. Highest fuel GCV from the previous 30
                                                                             daily samples; or
                                                                            2. Actual measured value.
                                            Flow proportional/weekly        Actual measured value.
                                             composite.
                                            In storage tank (after          1. Actual measured value; or
                                             addition of fuel to tank).     2. Highest of all sampled values in
                                                                             previous calendar year; or
                                                                            3. Maximum value allowed by contract.\1\
                                            As delivered (in delivery       1. Highest of all sampled values in
                                             truck or barge).\1\.            previous calendar year; or
                                                                            2. 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, use one of the following methods to 
    sample the oil (see Table D-4): sample 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; or sample 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; or use the flow 
    proportional sampling methodology in section 2.2.3 of this appendix; 
    or use 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 (e.g., 
    ship load, barge load, group of trucks, discrete purchase of diesel 
    fuel through pipeline, etc.). A storage tank is a container at a 
    plant holding oil that is actually combusted by the unit, such that 
    no 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 hrs). 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). Use either the actual daily sulfur content or the 
    highest fuel sulfur content recorded at that unit from the most 
    recent 30 daily samples for the purpose of calculating 
    SO2 emissions under section 3 of this appendix. Use 
    either the gross calorific value measured from that day's sample or 
    the highest GCV from the previous 30 days' 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. Do not blend additional fuel 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:
        (a) The most recent oil sample taken or
        (b) One of the conservative assumed values described in section 
    2.2.4.3 of this appendix.
    
    2.2.4.3  Sampling From Each Delivery
    
        (a) Alternatively, an oil sample may be taken from--
        (1) The shipment tank or container upon receipt of each lot of 
    fuel oil or
        (2) The supplier's storage container which holds the lot of fuel 
    oil. (Note: a supplier need only sample the storage container once 
    for sulfur content, GCV and, where required, the density so long as 
    the fuel sulfur content and GCV do not change and no fuel is added 
    to the supplier's storage container.)
        (b) 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.) of a 
    single fuel.
        (c) 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, calculate SO2 mass
    
    [[Page 28660]]
    
    emission rate using the sulfur content (and where required, the 
    density) from one of the two following values, 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 
    (this option is allowed for any consistent fuel which comes from a 
    single source whether or not the fuel is supplied under a 
    contractual agreement) or
        (2) The maximum value indicated in the contract with the fuel 
    supplier. Continue to use this assumed contract value unless and 
    until the actual sampled sulfur content, density, or gross calorific 
    value of a delivery exceeds the assumed value.
        (d) 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: it is superseded 
    by a higher value from an oil sample; or it is superseded by a new 
    contract in which case the new contract value becomes the assumed 
    value at the time the fuel specified under the new contract begins 
    to be combusted in the unit; or (if applicable) 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
    
        (a) Account for the hourly SO2 mass emissions due to 
    combustion of gaseous fuels for each hour when gaseous fuels are 
    combusted by the unit using the procedures in this section.
        (b) The procedures in sections 2.3.1 and 2.3.2 of this appendix, 
    respectively, may be used to determine SO2 mass emissions 
    from combustion of pipeline natural gas and natural gas, as defined 
    in Sec. 72.2 of this chapter. The procedures in section 2.3.3 of 
    this appendix may be used to account for SO2 mass 
    emissions from any gaseous fuel combusted by a unit. For each type 
    of gaseous fuel, the appropriate sampling frequency and the sulfur 
    content and GCV values used for calculations of SO2 mass 
    emission rates are summarized in the following Table D-5.
    
     Table D-5.--Gas Sulfur and GCV Values Used in Calculations for Various
                                   Fuel Types
    ------------------------------------------------------------------------
                                      Fuel type and         Value used in
              Parameter            sampling frequency       calculations
    ------------------------------------------------------------------------
                                  Pipeline Natural Gas  0.0006 lb/mmBtu.
                                   with H2S content
                                   less than or equal
                                   to 0.3 grains/
                                   100scf when using
                                   the provisions of
                                   section 2.3.1 to
                                   determine SO2 mass
                                   emissions.
    Gas Sulfur Content..........  Natural Gas with H2S  Default SO2 emission
                                   content less than     rate calculated
                                   or equal to 1.0       from Eq. D-1h,
                                   grain/100scf when     using either the
                                   using the             fuel contract
                                   provisions of         maximum H2S or the
                                   section 2.3.2 to      maximum H2S from
                                   determine SO2 mass    historical sampling
                                   emissions.            data.
                                  Any gaseous fuel      Actual % sulfur from
                                   delivered in          most recent
                                   shipments or lots--   shipment or
                                   Sample each lot or   1. Highest % sulfur
                                   shipment.             from previous
                                                         year's samples \1\;
                                                         or
                                                        2. Maximum % sulfur
                                                         value allowed by
                                                         contract \1\.
                                  Any gaseous fuel      Actual % sulfur from
                                   transmitted by        daily sample; or
                                   pipeline and having   Highest % sulfur
                                   a demonstrated        from previous 30
                                   ``low sulfur          daily samples.
                                   variability'' using
                                   the provisions of
                                   section 2.3.6--
                                   Sample daily.
                                  Any gaseous fuel--    Actual hourly sulfur
                                   Sample hourly.        content of the gas.
    Gas GCV.....................  Pipeline Natural      1. GCV from most
                                   Gas--Sample monthly.  recent monthly
                                                         sample (with  48
                                                         operating hours in
                                                         the month); or
                                                        2. Maximum GCV from
                                                         contract \1\; or
                                                        3. Highest GCV from
                                                         previous year's
                                                         samples.\1\
                                   Natural Gas--Sample  1. GCV from most
                                   monthly.              recent monthly
                                                         sample (with  48
                                                         operating hours in
                                                         the month); or
                                                        2. Maximum GCV from
                                                         contract \1\; or
                                                        3. Highest GCV from
                                                         previous year's
                                                         samples.\1\
                                  Any gaseous fuel      Actual GCV from most
                                   delivered in          recent shipment or
                                   shipments or lots--   lot or
                                   Sample each lot or   1. Highest GCV from
                                   shipment.             previous year's
                                                         samples1; or
                                                        2. Maximum GCV value
                                                         allowed by
                                                         contract.\1\
                                  Any gaseous fuel      1. GCV from most
                                   transmitted by        recent monthly
                                   pipeline and having   sample (with  48
                                   ``low GCV             operating hours in
                                   variability'' using   the month); or
                                   the provisions of    2. Highest GCV from
                                   section 2.3.5--       previous year's
                                   Sample monthly.       samples.\1\
                                  Any other gaseous     Actual daily or
                                   fuel not having a     hourly GCV of the
                                   ``low GCV             gas.
                                   variability''--Samp
                                   le at least daily.
                                   (Note that the use
                                   of an on-line GCV
                                   calorimeter or gas
                                   chromatograph is
                                   allowed).
    ------------------------------------------------------------------------
    \1\ Assumed sulfur content and GCV values (i.e., contract values or
      highest values from previous year) may only continue to be used if the
      sulfur content or GCV of each sample is no greater than the assumed
      value used to calculate SO2 emissions or heat input.
    
    2.3.1  Pipeline Natural Gas Combustion
    
        The owner or operator may determine the SO2 mass 
    emissions from the combustion of a fuel that meets the definition of 
    pipeline natural gas, in Sec. 72.2 of this chapter, using the 
    procedures of this section.
    
    2.3.1.1  SO2 Emission Rate
    
        For a fuel that meets the definition of pipeline natural gas 
    under Sec. 72.2 of this chapter, the owner or operator may determine 
    the SO2 mass emissions using either a default 
    SO2 emission rate of 0.0006 lb/mmBtu and the procedures 
    of this section, the procedures in section 2.3.2 for natural
    
    [[Page 28661]]
    
    gas, or the procedures of section 2.3.3 for any gaseous fuel. For 
    each affected unit using the default rate of 0.0006 lb/mmBtu, the 
    owner or operator must document that the fuel combusted is actually 
    pipeline natural gas, using the procedures in section 2.3.1.4 of 
    this appendix.
    
    2.3.1.2  Hourly Heat Input Rate
    
        Calculate hourly heat input rate, in mmBtu/hr, for a unit 
    combusting pipeline natural gas, using the procedures of section 
    3.4.1 of this appendix. Use the measured fuel flow rate from section 
    2.1 of this appendix and the gross calorific value from section 
    2.3.4.1 of this appendix in the calculations.
    
    2.3.1.3  SO2 Hourly Mass Emission Rate and Hourly Mass 
    Emissions
    
        For pipeline natural gas combustion, calculate the SO2 mass 
    emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this 
    appendix (when the default SO2 emission rate is used). 
    Then, use the calculated SO2 mass emission rate and the 
    unit operating time to determine the hourly SO2 mass 
    emissions from pipeline natural gas combustion, in lb, using 
    Equation D-12 in section 3.5.1 of this appendix.
    
    2.3.1.4  Documentation That a Fuel Is Pipeline Natural Gas
    
        (a) For pipeline natural gas, provide information in the 
    monitoring plan required under Sec. 75.53, demonstrating that the 
    definition of pipeline natural gas in Sec. 72.2 of this chapter has 
    been met. The information must demonstrate that the fuel has a 
    hydrogen sulfide content of less than 0.3 grain/100scf. The 
    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 (minimum of one year of data with samples 
    taken monthly or more frequently);
        (3) At least one year's worth of analytical data on the fuel 
    hydrogen sulfide content from samples taken monthly or more 
    frequently;
        (4) For fuels delivered in shipments or lots, the sulfur content 
    from all shipments or lots received in a one year period; or
        (5) Data from a 720-hour demonstration conducted using the 
    procedures of section 2.3.6 of this appendix.
        (b) When a 720-hour test is used for initial qualification as 
    pipeline natural gas, the owner or operator is required to continue 
    sampling the fuel for hydrogen sulfide at least once per month for 
    one year after the initial qualification period. The use of the 
    default natural gas SO2 emission rate under 2.3.1.1 is 
    not allowed if any sample during the one year period has a hydrogen 
    sulfide content greater than 0.3 gr/100 scf.
    
    2.3.2  Natural Gas Combustion
    
        The owner or operator may determine the SO2 mass 
    emissions from the combustion of a fuel that meets the definition of 
    natural gas, in Sec. 72.2 of this chapter, using the procedures of 
    this section.
    
    2.3.2.1  SO2 Emission Rate
    
        The owner or operator may account for SO2 emissions 
    either by using a default SO2 emission rate, as 
    determined under section 2.3.2.1.1 of this appendix, or by daily 
    sampling of the gas sulfur content using the procedures of section 
    2.3.3 of this appendix. For each affected unit using a default 
    SO2 emission rate, the owner or operator must provide 
    documentation that the fuel combusted is actually natural gas 
    according to the procedures in section 2.3.2.4 of this appendix.
        2.3.2.1.1  In lieu of daily sampling of the sulfur content of 
    the natural gas, an SO2 default emission rate may be 
    determined using Equation D-1h. Round off the calculated 
    SO2 default emission rate to the nearest 0.0001 lb/mmBtu.
    [GRAPHIC] [TIFF OMITTED] TR26MY99.020
    
    Where:
    
    ER = Default SO2 emission rate for natural gas 
    combustion, lb/mmBtu.
    H2S = Hydrogen sulfide content of the natural gas, gr/
    100scf.
    
        2.3.2.1.2  The hydrogen sulfide value used in Equation D-1h may 
    be obtained from one of the following sources of information:
        (a) The highest hydrogen sulfide content specified by a purchase 
    contract or by a pipeline transportation contract;
        (b) The highest hydrogen sulfide content from a certification of 
    the gas vendor, based on routine vendor sampling and analysis 
    (minimum of one year of data with samples taken monthly or more 
    frequently);
        (c) The highest hydrogen sulfide content from at least one 
    year's worth of analytical data on the fuel hydrogen sulfide content 
    from samples taken monthly or more frequently;
        (d) For fuels delivered in shipments or lots, the highest 
    hydrogen sulfide content from all shipments or lots received in a 
    one year period; or (5) the highest hydrogen sulfide content 
    measured during a 720-hour demonstration conducted using the 
    procedures of section 2.3.6 of this appendix.
    
    2.3.2.2  Hourly Heat Input Rate
    
        Calculate hourly heat input rate for natural gas combustion, in 
    mmBtu/hr, using the procedures in section 3.4.1 of this appendix. 
    Use the measured fuel flow rate from section 2.1 of this appendix 
    and the gross calorific value from section 2.3.4.2 of this appendix 
    in the calculations.
    
    2.3.2.3  SO2 Mass Emission Rate and Hourly Mass Emissions
    
        For natural gas combustion, calculate the SO2 mass 
    emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this 
    appendix, when the default SO2 emission rate is used. 
    Then, use the calculated SO2 mass emission rate and the 
    unit operating time to determine the hourly SO2 mass 
    emissions from natural gas combustion, in lb, using Equation D-12 in 
    section 3.5.1 of this appendix.
    
    2.3.2.4  Documentation that a Fuel Is Natural Gas
    
        (a) For natural gas, provide information in the monitoring plan 
    required under Sec. 75.53, demonstrating that the definition of 
    natural gas in Sec. 72.2 of this chapter has been met. The 
    information must demonstrate that the fuel has a hydrogen sulfide 
    content of less than 1.0 grain/100 scf. 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 transportation contract;
        (2) A certification of the gas vendor, based on routine vendor 
    sampling and analysis (minimum of one year of data with samples 
    taken monthly or more frequently);
        (3) At least one year's worth of analytical data on the fuel 
    hydrogen sulfide content from samples taken monthly or more 
    frequently;
        (4) For fuels delivered in shipments or lots, sulfur content 
    from all shipments or lots received in a one year period; or
        (5) Data from a 720-hour demonstration conducted using the 
    procedures of section 2.3.6 of this appendix.
        (b) When a 720-hour test is used for initial qualification as 
    natural gas, the owner or operator shall continue sampling the fuel 
    for hydrogen sulfide at least once per month for one year after the 
    initial qualification period. The use of the default natural gas 
    SO2 emission rate under 2.3.2.1.1 is not allowed if any 
    sample during the one year period has a hydrogen sulfide content 
    greater than 1.0 grain/100 scf.
    
    2.3.3  SO2 Mass Emissions From Any Gaseous Fuel
    
        The owner or operator of a unit may determine SO2 
    mass emissions using this section for any gaseous fuel (including 
    fuels such as refinery gas, landfill gas, digester gas, coke oven 
    gas, blast furnace gas, coal-derived gas, producer gas or any other 
    gas which may have a variable sulfur content).
    
    2.3.3.1  Sulfur Content Determination
    
        2.3.3.1.1  Analyze the total sulfur content of the gaseous fuel 
    in grain/100 scf, at the frequency specified in Table D-5 of this 
    appendix. That is: for fuel delivered in discrete shipments or lots, 
    sample each shipment or lot; for fuel transmitted by pipeline, if a 
    demonstration is provided under section 2.3.6 of this appendix 
    showing that the gaseous fuel has a ``low sulfur variability,'' 
    determine the sulfur content daily using either manual sampling or a 
    gas chromatograph; and for all other gaseous fuels, determine the 
    sulfur content on an hourly basis using a gas chromatograph.
        2.3.3.1.2  Use one of the following methods when using manual 
    sampling (as applicable to the type of gas combusted) to determine 
    the sulfur content of the fuel: ASTM D1072-90, ``Standard Test 
    Method for Total Sulfur in Fuel Gases'', ASTM D4468-85 (Reapproved 
    1989) ``Standard Test Method for Total Sulfur in Gaseous Fuels by 
    Hydrogenolysis and Radiometric Colorimetry,'' ASTM D5504-94 
    ``Standard Test Method for Determination of Sulfur Compounds in 
    Natural Gas and Gaseous Fuels by Gas Chromatography and 
    Chemiluminescence,'' or ASTM D3246-81 (Reapproved 1987) ``Standard 
    Test Method for Sulfur in Petroleum Gas By Oxidative 
    Microcoulometry'' (incorporated by reference under Sec. 75.6).
    
    [[Page 28662]]
    
        2.3.3.1.3  The sampling and analysis of daily manual samples may 
    be performed by the owner or operator, an outside laboratory, or the 
    gas supplier. If hourly sampling with a gas chromatograph is 
    required, or a source chooses to use an online gas chromatograph to 
    determine daily fuel sulfur content, the owner or operator shall 
    develop and implement a program to quality assure the data from the 
    gas chromatograph, in accordance with the manufacturer's recommended 
    procedures. The quality assurance procedures shall be kept on-site, 
    in a form suitable for inspection.
        2.3.3.1.4  Results of all sample analyses must be available no 
    later than thirty calendar days after the sample is taken.
        2.3.3.2  SO2 Mass Emission Rate
        Calculate the SO2 mass emission rate for the gaseous 
    fuel, in lb/hr, using equation D-4 in section 3.3.1 of this 
    appendix. Use the appropriate sulfur content, in equation D-4, as 
    specified in Table D-5 of this appendix. That is, for fuels 
    delivered by pipeline which demonstrate a low sulfur variability 
    (under section 2.3.6 of this appendix) use either the daily value or 
    the highest value in the previous 30 days or for fuels requiring 
    hourly sulfur content sampling with a gas chromatograph use the 
    actual hourly sulfur content).
    
    2.3.3.3  Hourly Heat Input Rate
    
        Calculate the hourly heat input rate for combustion of the 
    gaseous fuel, using the provisions in section 3.4.1 of this 
    appendix. Use the measured fuel flow rate from section 2.1 of this 
    appendix and the gross calorific value from section 2.3.4.3 of this 
    appendix in the calculations.
    
    2.3.4  Gross Calorific Values for Gaseous Fuels
    
        Determine the GCV of each gaseous fuel at the frequency 
    specified in this section, using one of the following methods: 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'' (incorporated by 
    reference under Sec. 75.6 of this part). Use the appropriate GCV 
    value, as specified in section 2.3.4.1, 2.3.4.2 or 2.3.4.3 of this 
    appendix, in the calculation of unit hourly heat input rates.
    
    2.3.4.1  GCV of Pipeline Natural Gas
    
        Determine the GCV of fuel that is pipeline natural gas, as 
    defined in Sec. 72.2 of this chapter, at least once per calendar 
    month. For GCV used in calculations use the specifications in Table 
    D-5: either the value from the most recent monthly sample, the 
    highest value specified in a contract or tariff sheet, or the 
    highest value from the previous year. The fuel GCV value from the 
    most recent monthly sample shall be used for any month in which that 
    value is higher than a contract limit. If a unit combusts pipeline 
    natural gas for less than 48 hours during a calendar month, the 
    sampling and analysis requirement for GCV is waived for that 
    calendar month. The preceding waiver is limited by the condition 
    that at least one analysis for GCV must be performed for each 
    quarter the unit operates for any amount of time.
    
    2.3.4.2  GCV of Natural Gas
    
        Determine the GCV of fuel that is natural gas, as defined in 
    Sec. 72.2 of this chapter, on a monthly basis, in the same manner as 
    described for pipeline natural gas in section 2.3.4.1 of this 
    appendix.
    
    2.3.4.3  GCV of Other Gaseous Fuels
    
        For gaseous fuels other than natural gas or pipeline natural 
    gas, determine the GCV as specified in section 2.3.4.3.1, 2.3.4.3.2 
    or 2.3.4.3.3, as applicable. 2.3.4.3.1 For a gaseous fuel that is 
    delivered in discrete shipments or lots, determine the GCV for each 
    shipment or lot. The determination may be made by sampling each 
    delivery or by sampling the supply tank after each delivery. For 
    sampling of each delivery, use the highest GCV in the previous 
    year's samples. For sampling from the tank after each delivery, use 
    either the most recent GCV sample or the highest GCV in the previous 
    year. 2.3.4.3.2 For any gaseous fuel that does not qualify as 
    pipeline natural gas or natural gas and which is not delivered in 
    shipments or lots which performs the required 720 hour test under 
    section 2.3.5 of this appendix, and the results of the test 
    demonstrate that the gaseous fuel has a low GCV variability, 
    determine the GCV at least monthly. In calculations of hourly heat 
    input for a unit, use either the most recent monthly sample or the 
    highest fuel GCV from the previous year's samples. 2.3.4.3.3 For any 
    other gaseous fuel, determine the GCV at least daily and use the 
    actual fuel GCV in calculations of unit hourly heat input. If an 
    online gas chromatograph or on-line calorimeter is used to determine 
    fuel GCV each day, the owner or operator shall develop and implement 
    a program to quality assure the data from the gas chromatograph or 
    on-line calorimeter, in accordance with the manufacturer's 
    recommended procedures. The quality assurance procedures shall be 
    kept on-site, in a form suitable for inspection.
    
    2.3.5  Demonstration of Fuel GCV Variability
    
        (a) This demonstration is required of any fuel which does not 
    qualify as pipeline natural gas or natural gas, and is not delivered 
    only in shipments or lots. The demonstration data shall be used to 
    determine whether daily or monthly sampling of the GCV of the 
    gaseous fuel or blend is required.
        (b) To make this demonstration, proceed as follows. Provide a 
    minimum of 720 hours of data, indicating the GCV of the gaseous fuel 
    or blend (in Btu/100 scf). The demonstration data shall be obtained 
    using either: hourly sampling and analysis using the methods in 
    section 2.3.4 to determine GCV of the fuel; an on-line gas 
    chromatograph capable of determining fuel GCV on an hourly basis; or 
    an on-line calorimeter. For gaseous fuel produced by a variable 
    process, the data shall be representative of and include all process 
    operating conditions including seasonal and yearly variations in 
    process which may affect fuel GCV.
        (c) The data shall be reduced to hourly averages. The mean GCV 
    value and the standard deviation from the mean shall be calculated 
    from the hourly averages. Specifically, the gaseous fuel is 
    considered to have a low GCV variability, and monthly gas sampling 
    for GCV may be used, if the mean value of the GCV multiplied by 
    1.075 is less than the sum of the mean value and one standard 
    deviation. If the gaseous fuel or blend does not meet this 
    requirement, then daily fuel sampling and analysis for GCV, using 
    manual sampling, a gas chromatograph or an on-line calorimeter is 
    required.
    
    2.3.6  Demonstration of Fuel Sulfur Variability
    
        (a) This demonstration is required for any fuel which does not 
    qualify as pipeline natural gas or natural gas and is not delivered 
    in shipments or lots. The results of the demonstration will be used 
    to determine whether daily or hourly sampling for sulfur in the fuel 
    is required. To make this demonstration, proceed as follows. Provide 
    a minimum of 720 hours of data, indicating the total sulfur content 
    (and hydrogen sulfide content, if needed to define a fuel as either 
    pipeline natural gas or natural gas) of the gaseous fuel or blend 
    (in gr/100 scf). The demonstration data shall be obtained using 
    either manual hourly sampling or an on-line gas chromatograph 
    capable of determining fuel total sulfur content (and, if 
    applicable, H2S content) on an hourly basis. For gaseous 
    fuel produced by a variable process, additional data shall be 
    provided which is representative of all process operating conditions 
    including seasonal or annual variations which may affect fuel sulfur 
    content.
        (b) Reduce the data to hourly averages of the total sulfur 
    content (and hydrogen sulfide content, if applicable) of the fuel. 
    Then, calculate the mean value of the total sulfur content and 
    standard deviation in order to determine whether daily sampling of 
    the sulfur content of the gaseous fuel or blend is sufficient or 
    whether hourly sampling with a gas chromatograph is required. 
    Specifically, daily gas sampling and analysis for total sulfur 
    content, using either manual sampling or an online gas 
    chromatograph, shall be sufficient, provided that the standard 
    deviation of the hourly average values from the mean value does not 
    exceed 5.0 grains per 100 scf. If the gaseous fuel or blend does not 
    meet this requirement, then hourly sampling of the fuel with a gas 
    chromatograph and hourly reporting of the average sulfur content of 
    the fuel is required.
    
    2.4 * * *
    
    2.4.1  Missing Data for Oil and Gas Samples
    
        When fuel sulfur content, gross calorific value or, when 
    necessary, density 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, 2.2.5, 2.2.6, 2.2.7, 2.3.3.1, 2.3.3.1.2, or 2.3.4 
    of this appendix, then substitute the maximum potential sulfur 
    content, density, or gross calorific value of that fuel from Table 
    D-6 of this appendix. Irrespective of which reporting option is 
    selected (i.e., actual value, contract value or highest value from 
    the previous year, the missing data values in Table D-6 shall be 
    reported whenever the
    
    [[Page 28663]]
    
    results of a required sample of sulfur content, GCV or density is 
    missing or invalid in the current calendar year. The substitute data 
    value(s) shall be used until the next valid sample for the missing 
    parameter(s) is obtained. Note that only actual sample results shall 
    be used to determine the ``highest value from the previous year'' 
    when that reporting option is used; missing data values shall not be 
    used in the determination.
    
      Table D-6.--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...........  0.3 gr/100 scf for pipeline natural gas,
                                    or
                                   1.0 gr/100 scf for natural gas, or
                                   Twice the highest total sulfur content
                                    value recorded in the previous 30 days
                                    when sampling gaseous fuel daily or
                                    hourly.
    Gas GCV/Heat Content.........  1100 Btu/scf for pipeline natural gas,
                                    natural gas or landfill gas, or
                                   1500 for butane or refinery gas.
                                   2100 Btu/scf for propane or any 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:
        (a) The maximum fuel flow rate the unit is capable of combusting 
    or (b) 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 * * *
        66. Appendix D to part 75 is further amended by:
        a. Revising sections 3 through 3.2.1 and 3.2.3;
        b. Removing section 3.2.4;
        c. Revising sections 3.3 through 3.3.3;
        d. Redesignating section 3.4 as 3.6 and revising the first 
    sentence; and
        e. Adding new sections 3.4 through 3.4.3 and sections 3.5 
    through 3.5.6 to read as follows:
    
    3. Calculations
    
        Calculate hourly SO2 mass emission rate from 
    combustion of oil fuel using the procedures in section 3.1 of this 
    appendix. Calculate hourly SO2 mass emission rate from 
    combustion of gaseous fuel using the procedures in section 3.3 of 
    this appendix. (Note: the SO2 mass emission rates in 
    sections 3.1 and 3.3 are calculated such that the rate, when 
    multiplied by unit operating time, yields the hourly SO2 
    mass emissions for a particular fuel for the unit.) Calculate hourly 
    heat input rate for both oil and gaseous fuels using the procedures 
    in section 3.4 of this appendix. Calculate total SO2 mass 
    emissions and heat input for each hour, each quarter and the year to 
    date using the procedures under section 3.5 of this appendix. 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.
    
    3.1  SO2 Mass Emission Rate Calculation for Oil
    
        3.1.1  Use Equation D-2 to calculate SO2 mass 
    emission rate per hour (lb/hr):
    [GRAPHIC] [TIFF OMITTED] TR26MY99.021
    
    Where:
    
        SO2rate-oil = Hourly mass emission rate of 
    SO2 emitted from combustion of oil, lb/hr.
        OILrate = Mass rate of oil consumed per hr during 
    combustion, lb/hr.
        %Soil = Percentage of sulfur by weight measured in 
    the sample.
        2.0 = Ratio of lb SO 2/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 Volumetric Oil Flowmeters
    
        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 2.2.6 of this appendix, use Equation D-
    3 to calculate the rate of the mass of oil consumed (in lb/hr):
    [GRAPHIC] [TIFF OMITTED] TR26MY99.022
    
        Where:
        OILrate = Mass rate of oil consumed per hr, lb/hr.
        Voil-rate = Volume rate of oil consumed per hr, 
    measured in scf/hr, gal/hr, barrels/hr, or m \3\/hr.
    Doil = Density of oil, measured in lb/scf, lb/gal, lb/
    barrel, or lb/m3.
    
    3.3  SO2 Mass Emission Rate Calculation for Gaseous Fuels
    
        3.3.1  Use Equation D-4 to calculate the SO2 mass 
    emission rate when using the optional gas sampling and analysis 
    procedures in sections 2.3.1 and 2.3.2 of this appendix, or the 
    required gas sampling and analysis procedures in section 2.3.3 of 
    this appendix. Total sulfur content of a fuel must be determined 
    using the procedures of 2.3.3.1.2 of this appendix:
    
    [[Page 28664]]
    
    [GRAPHIC] [TIFF OMITTED] TR26MY99.023
    
    
    Where:
    
    SO2rate-gas = Hourly mass rate of 
    SO2 emitted due to combustion of gaseous fuel, lb/hr.
    GASrate = Hourly metered flow rate of gaseous fuel 
    combusted, 100 scf/hr.
    Sgas = 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 Equation D-5 to calculate the SO2 mass 
    emission rate when using a default emission rate from section 
    2.3.1.1 or 2.3.2.1.1 of this appendix:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.024
    
    where:
    
    SO2rate = Hourly mass emission rate of 
    SO2 from combustion of a gaseous fuel, lb/hr.
    ER = SO2 emission rate from section 2.3.1.1 or 2.3.2.1.1, 
    of this appendix, lb/mmBtu.
    HIrate = Hourly heat input rate of a gaseous fuel, 
    calculated using procedures in section 3.4.1 of this appendix, in 
    mmBtu/hr.
    
        3.3.3  Record the SO2 mass emission rate for each 
    hour when the unit combusts a gaseous fuel.
    
    3.4  Calculation of Heat Input Rate
    
    3.4.1 Heat Input Rate for Gaseous Fuels
    
        (a) Determine total hourly gas flow or average hourly gas flow 
    rate with a fuel flowmeter in accordance with the requirements of 
    section 2.1 of this appendix and the fuel GCV in accordance with the 
    requirements of section 2.3.4 of this appendix. If necessary perform 
    the 720-hour test under section 2.3.5 to determine the appropriate 
    fuel GCV sampling frequency.
        (b) Then, use Equation D-6 to calculate heat input rate from 
    gaseous fuels for each hour.
    [GRAPHIC] [TIFF OMITTED] TR26MY99.025
    
    Where:
    
    HIrate-gas = Hourly heat input rate from combustion of 
    the gaseous fuel, mmBtu/hr.
    GASrate = Average volumetric flow rate of fuel, for the 
    portion of the hour in which the unit operated, 100 scf/hr.
    GCVgas = Gross calorific value of gaseous fuel, Btu/hr.
    10 \6\ = Conversion of Btu to mmBtu.
    
        (c) Note that when fuel flow is measured on an hourly totalized 
    basis (e.g. a fuel flowmeter reports totalized fuel flow for each 
    hour), before Equation D-6 can be used, the total hourly fuel usage 
    must be converted from units of 100 scf to units of 100 scf/hr using 
    Equation D-7:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.026
    
    Where:
    
    GASrate = Average volumetric flow rate of fuel for the 
    portion of the hour in which the unit operated, 100 scf/hr.
    GASunit = Total fuel combusted during the hour, 100 scf.
    t = 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).
    
    3.4.2  Heat Input Rate From the Combustion of Oil
    
        (a) Determine total hourly oil flow or average hourly oil flow 
    rate with a fuel flowmeter, in accordance with the requirements of 
    section 2.1 of this appendix. Determine oil GCV according to the 
    requirements of section 2.2 of this appendix.
        Then, use Equation D-8 to calculate hourly heat input rate from 
    oil for each hour:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.027
    
    Where:
    
    HIrate-oil = Hourly heat input rate from combustion of 
    oil, mmBtu/hr.
    OILrate = Mass rate of oil consumed per hour, as 
    determined using procedures in section 3.2.3 of this appendix, in 
    lb/hr, tons/hr, or kg/hr.
    GCVoil = Gross calorific value of oil, Btu/lb, Btu/ton, 
    Btu/kg.
    106 = Conversion of Btu to mmBtu.
        (b) Note that when fuel flow is measured on an hourly totalized 
    basis (e.g., a fuel flowmeter reports totalized fuel flow for each 
    hour), before equation D-8 can be used, the total hourly fuel usage 
    must be converted from units of lb to units of lb/hr, using equation 
    D-9:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.028
    
    Where:
    
        OILrate = Average fuel flow rate for the portion of the 
    hour which the unit operated in lb/hr.
        OILunit = Total fuel combusted during the hour, lb.
    t = 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).
    
    3.4.3  Apportioning Heat Input Rate to Multiple Units
    
        (a) Use the procedure in this section to apportion hourly heat 
    input rate to two or more units using a single fuel flowmeter which 
    supplies fuel to the units. (This procedure is not applicable to 
    units calculating NOX mass emissions using the provisions 
    of subpart H of this part.) The designated representative may also 
    petition the Administrator under Sec. 75.66 to use this 
    apportionment procedure to calculate SO2 and 
    CO2 mass emissions.
        (b) Determine total hourly fuel flow or flow rate through the 
    fuel flowmeter supplying gas or oil fuel to the units. Convert fuel 
    flow rates to units of 100 scf for gaseous fuels or to lb for oil, 
    using the procedures of this appendix. Apportion the fuel to each 
    unit separately based on hourly output of the unit in MWe 
    or 1000 lb of steam/hr (klb/hr) using Equation D-10 or D-11, as 
    applicable:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.029
    
    Where:
    
    GASunit = Gas flow apportioned to a unit, 100 scf.
    GASmeter = Total gas flow through the fuel flowmeter, 100 
    scf.
    Uoutput = Total unit output, MW or klb/hr.
    
    [[Page 28665]]
    
    [GRAPHIC] [TIFF OMITTED] TR26MY99.030
    
    
    Where:
    
    OILunit = Oil flow apportioned to a unit, lb.
    OILmeter = Total oil flow through the fuel flowmeter, lb.
    Uoutput = Total unit output in either MWe or 
    klb/hr.
    
        (c) Use the total apportioned fuel flow calculated from Equation 
    D-10 or D-11 to calculate the hourly unit heat input rate, using 
    Equations D-6 and D-7 (for gas) or Equations D-8 and D-9 (for oil).
    
    3.5  Conversion of Hourly Rates to Hourly, Quarterly and Year to Date 
    Totals
    
    3.5.1  Hourly SO2 Mass Emissions From the Combustion of All 
    Fuels
    
        Determine the total mass emissions for each hour from the 
    combustion of all fuels using Equation D-12:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.031
    
    Where:
    
    MSO2-hr = Total mass of SO2 emissions from all 
    fuels combusted during the hour, lb.
    SO2rate-i = SO2 mass emission rate for each 
    type of gas or oil fuel combusted during the hour, lb/hr.
    ti = Time each gas or oil fuel was combusted for the hour 
    (fuel usage time), 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).
    
    3.5.2  Quarterly Total SO2 Mass Emissions
    
        Sum the hourly SO2 mass emissions in lb as determined 
    from Equation D-12 for all hours in a quarter using Equation D-13:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.032
    
    Where:
    
    MSO2-qtr = Total mass of SO2 emissions from 
    all fuels combusted during the quarter, tons.
    MSO2-hr = Hourly SO2 mass emissions determined 
    using Equation D-12, lb.
    2000= Conversion factor from lb to tons.
    
    3.5.3  Year to Date SO2 Mass Emissions
    
        Calculate and record SO2 mass emissions in the year 
    to date using Equation D-14:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.033
    
    Where:
    
    MSO2-YTD = Total SO2 mass emissions for the 
    year to date, tons.
    MSO2-qtr = Total SO2 mass emissions for the 
    quarter, tons.
    
    3.5.4  Hourly Total Heat Input from the Combustion of all Fuels
    
        Determine the total heat input in mmBtu for each hour from the 
    combustion of all fuels using Equation D-15:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.034
    
    Where:
    
    HIhr = Total heat input from all fuels combusted during 
    the hour, mmBtu.
    HIrate-i =Heat input rate for each type of gas or oil 
    combusted during the hour, mmBtu/hr.
    ti = Time each gas or oil fuel was combusted for the hour 
    (fuel usage time), 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).
    
    3.5.5  Quarterly Heat Input
    
        Sum the hourly heat input values determined from equation D-15 
    for all hours in a quarter using Equation D-16:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.035
    
    Where:
    
    HIqtr = Total heat input from all fuels combusted during 
    the quarter, mmBtu.
    HIhr = Hourly heat input determined using Equation D-15, 
    mmBtu.
    
    3.5.6  Year-to-Date Heat Input
    
        Calculate and record the total heat input in the year to date 
    using Equation D-17.
    [GRAPHIC] [TIFF OMITTED] TR26MY99.036
    
    HIYTD = Total heat input for the year to date, mmBtu.
    HIqtr = Total heat input for the quarter, mmBtu.
    
    3.6  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 3.5 of this appendix. * * *
        67. Appendix E to part 75 is amended by revising sections 2.4.2, 
    2.4.3, 2.4.4, 2.5.4 and 2.5.5 to read as follows:
    
    Appendix E to Part 75--Optional NOX Emissions Estimation 
    Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units
    
    * * * * *
    
    2. Procedure
    
    * * * * *
    
    2.4  Procedures for Determining Hourly NOX Emission Rate
    
    * * * * *
        2.4.2 Use the graph of the baseline correlation results 
    (appropriate for the fuel or fuel combination) to determine the 
    NOX emissions rate (lb/mmBtu) corresponding to the heat 
    input rate (mmBtu/hr). Input this correlation into the data 
    acquisition and handling system for the unit. Linearly interpolate 
    to 0.1 mmBtu/hr heat input rate and 0.01 lb/mmBtu NOX 
    (0.001 lb/mmBtu NOX after April 1, 2000). For each type 
    of fuel, calculate NOX emission rate using the baseline 
    correlation results from the most recent test with that fuel, 
    beginning with the date and hour of the completion of the most 
    recent test.
        2.4.3 To determine the NOX emission rate for a unit 
    co-firing fuels that has not been tested for that combination of 
    fuels, interpolate between the NOX emission rate for each 
    fuel as follows. Determine the heat input rate for the hour (in 
    mmBtu/hr) for each fuel and select the corresponding NOX 
    emission rate for each fuel on the appropriate graph. (When a fuel 
    is combusted for a partial
    
    [[Page 28666]]
    
    hour, determine the fuel usage time for each fuel and determine the 
    heat input rate from each fuel as if that fuel were combusted at 
    that rate for the entire hour in order to select the corresponding 
    NOX emission rate.) Calculate the total heat input to the 
    unit in mmBtu for the hour from all fuel combusted using Equation E-
    1. Calculate a Btu-weighted average of the emission rates for all 
    fuels using Equation E-2 of this appendix. For each type of fuel, 
    calculate NOX emission rate using the baseline 
    correlation results from the most recent test with that fuel, 
    beginning with the date and hour of the completion of the most 
    recent test.
        2.4.4 For each hour, record the critical quality assurance 
    parameters, as identified in the monitoring plan, and as required by 
    section 2.3 of this appendix from the date and hour of the 
    completion of the most recent test for each type of fuel.
    
    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.
        68. Appendix E to part 75 is further 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:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.037
    
    Where:
    
    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 April 1, 
    2000, or to the nearest 0.001 lb/mmBtu for tests performed on and 
    after April 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] TR26MY99.038
    
    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.
    
        69. Appendix F to part 75 is amended by revising sections 2, 
    2.1, 2.2, 2.3, and 2.4 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):
    [GRAPHIC] [TIFF OMITTED] TR26MY99.039
    
    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] TR26MY99.040
    
    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] TR26MY99.041
    
    Where:
    Eq = Quarterly total SO2 mass emissions, tons.
    Eh = Hourly SO2 mass emission rate, lb/hr.
    
    [[Page 28667]]
    
    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] TR26MY99.042
    
    Where:
    
    Ea = Annual total SO2 mass emissions, tons.
    Eq = Quarterly 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.
        70. Appendix F to part 75 is further 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="">2 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="">2 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] TR26MY99.043
    
    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] TR26MY99.044
    
    Where:
    
    Ea = Average NOX emission rate for the 
    calendar year, lb/mmBtu.
    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 April 1, 2000, and to the nearest 0.001 lb/mmBtu 
    on and after April 1, 2000.
        71. Appendix F to part 75 is further amended by revising 
    sections 4.1, 4.2, 4.3, 4.4, 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):
    [GRAPHIC] [TIFF OMITTED] TR26MY99.045
    
    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="">2, 
    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="">2, 
    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] TR26MY99.046
    
    Where:
    
    ECO2q = 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.
    
    [GRAPHIC] [TIFF OMITTED] TR26MY99.047
    
    Where:
    
    ECO2a = Annual total CO2 mass emission,
    ECO2q = Quarterly total CO2 mass emissions, 
    tons.
    q = Quarters for which ECO2q are available during 
    calendar year.
    
        4.4 For an affected unit, when the owner or operator is 
    continuously monitoring O2 concentration (in percent by 
    volume) of flue gases using an O2 monitor, use the 
    equations and procedures in section 4.4.1 and 4.4.2 of this appendix 
    to determine hourly CO2 mass emissions (in tons).
        4.4.1 Use appropriate F and Fc factors from section 
    3.3.5 of this appendix in one of the following equations (as 
    applicable) to determine hourly average CO2 concentration 
    of flue gases (in percent by volume):
    [GRAPHIC] [TIFF OMITTED] TR26MY99.048
    
    
    [[Page 28668]]
    
    
    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] TR26MY99.061
    
    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.
    * * * * *
        72. Appendix F to part 75 is amended by revising sections 5 
    through 5.2.4; adding sections 5.3 through 5.3.2; revising sections 
    5.5, 5.5.1 and 5.5.2; and by adding new sections 5.6 through 5.6.2 
    and 5.7 and by removing and revising section 5.4 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 in sections 5.5 through 5.5.7. 
    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 in sections 5.6 through 
    5.6.2 to apportion heat input among each unit using the common stack 
    or common pipe header.
        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] TR26MY99.049
    
    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="">2, 
    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="">2, 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] TR26MY99.051
    
    
    [[Page 28669]]
    
    
    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 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="">2, 
    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="">2, 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] TR26MY99.052
    
    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 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] TR26MY99.053
    
    
    [[Page 28670]]
    
    
    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 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] TR26MY99.054
    
    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] TR26MY99.055
    
    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(a)  When the unit is combusting oil, use the following 
    equation to calculate hourly heat input rate:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.056
    
    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.
    
        (b) 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] TR26MY99.062
    
    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 gas 
    chromatograph, 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] TR26MY99.057
    
    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.
    
    
    [[Page 28671]]
    
    
    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:
    [GRAPHIC] [TIFF OMITTED] TR26MY99.058
    
    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] TR26MY99.059
    
    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).
    
        73. Appendix F is further amended by revising section 7 to read 
    as follows:
    
    7. Procedures for SO2 Mass Emissions at Units With 
    SO2 Continuous Emission Monitoring Systems During the 
    Combustion of Pipeline Natural Gas or Natural Gas
    
        The owner or operator shall use the following equation to 
    calculate hourly SO2 mass emissions as allowed for units 
    with SO2 continuous emission monitoring systems if, 
    during the combustion of gaseous fuel that meets the definition of 
    pipeline natural gas or natural gas in Sec. 72.2 of this chapter, 
    SO2 emissions are determined in accordance with 
    Sec. 75.11(e)(1).
    [GRAPHIC] [TIFF OMITTED] TR26MY99.060
    
    Where:
    
    Eh = Hourly SO2 mass emissions, lb/hr.
    ER = Applicable SO2 default emission rate from section 
    2.3.1.1 or 2.3.2.1.1 of appendix D to this part, lb/mmBtu.
    HI = Hourly heat input, as determined using the procedures of 
    section 5.2 of this appendix.
    
        74. Appendix F is further amended by correcting section 8 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, 8.2, or 8.3, as applicable, to account 
    for hourly NOX mass emissions, and the procedures in 
    section 8.4 to account for quarterly, seasonal, and annual 
    NOX mass emissions to the extent that the provisions of 
    subpart H of this part are adopted as requirements under such a 
    program.
        75. Appendix G to part 75 is amended by revising the paragraph 
    defining the term ``Wc'' that follows Equation G-1 and by 
    revising the paragraph defining the term ``Fc'' that follows 
    Equation G-4 to read as follows:
    
    Appendix G to Part 75--Determination of CO2 Emissions
    
    * * * * *
    
    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 or delivery for oil and diesel fuel, one fuel sample 
    for each delivery for gaseous fuel in lots, one sample per day or 
    per hour (as applicable) for each gaseous fuel that is required to 
    be sampled daily or hourly for gross calorific value under section 
    2.3.5.6 of appendix D to this part, and one sample per month for 
    each gaseous fuel that is required to be sampled monthly for gross 
    calorific value under section 2.3.4.1 or 2.3.4.2 of appendix D to 
    this part. 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.
    * * * * *
        2.3 * * *
    
    (Eq. G-4)
    
    Where:
    * * * * *
    Fc = Carbon based F-factor, 1040 scf/mmBtu for natural 
    gas; 1,240 scf/mmBtu for crude, residual, or distillate oil; and 
    calculated according to the procedures in section 3.3.5 of appendix 
    F to this part for other gaseous fuels.
    * * * * *
    
    [[Page 28672]]
    
        76. Appendix G to part 75 is amended by adding new sections 5 
    through 5.3 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 
    4/1/2000
    
        Prior to April 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 April 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 of 
    this appendix.
    
    5.1.2 [Reserved]
    
    5.2  Missing Carbon Content Data On and After 4/1/2000
    
        Prior to April 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 April 1, 
    2000, use the procedures of this section to substitute for missing 
    carbon content data.
        5.2.1  In all cases (i.e., for weekly coal samples or composite 
    oil samples from continuous sampling, for oil samples taken from the 
    storage tank after transfer of a new delivery of fuel, for as-
    delivered samples of oil, diesel fuel, or gaseous fuel delivered in 
    lots, and for gaseous fuel that is supplied by a pipeline and 
    sampled monthly, daily or hourly for gross calorific value) when 
    carbon content data is missing, report the appropriate default value 
    from Table G-1.
        5.2.2  The missing data values in Table G-1 shall be reported 
    whenever the results of a required sample of fuel carbon content are 
    either missing or invalid. The substitute data value shall be used 
    until the next valid carbon content sample is obtained.
    
       Table G-1.--Missing Data Substitution Procedures for Missing Carbon
                                  Content Data
    ------------------------------------------------------------------------
                                   Sampling technique/
              Parameter                 frequency        Missing data value
    ------------------------------------------------------------------------
    Oil and coal carbon content.  All oil and coal      Most recent,
                                   samples, prior to     previous carbon
                                   April 1, 2000.        content value
                                                         available for that
                                                         grade of oil, or
                                                         default value, in
                                                         this table.
    Gas carbon content..........  All gaseous fuel      Most recent,
                                   samples, prior to     previous carbon
                                   April 1, 2000.        content value
                                                         available for that
                                                         type of gaseous
                                                         fuel, or default
                                                         value, in this
                                                         table.
    Default coal carbon content.  All, on and after     Anthracite: 90.0
                                   April 1, 2000.        percent.
                                                        Bituminous: 85.0
                                                         percent.
                                                        Subbituminous/
                                                         Lignite: 75.0
                                                         percent.
    Default oil carbon content..  All, on and after     90.0 percent.
                                   April 1, 2000.
    Default gas carbon content..  All, on and after     Natural gas: 75.0
                                   April 1, 2000.        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
    
        77. Appendix H to part 75 is removed and reserved.
    
    Appendix J to Part 75--Compliance Dates for Revised Recordkeeping 
    Requirements and Missing Data Procedures
    
        78. Appendix J to part 75 is removed and reserved.
    
    [FR Doc. 99-8939 Filed 5-25-99; 8:45 am]
    BILLING CODE 6560-50-U
    
    
    

Document Information

Effective Date:
6/25/1999
Published:
05/26/1999
Department:
Environmental Protection Agency
Entry Type:
Rule
Action:
Final rule.
Document Number:
99-8939
Dates:
The effective date of this rule is June 25, 1999. The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Federal Register as of June 25, 1999.
Pages:
28564-28672 (109 pages)
Docket Numbers:
FRL-6320-8
RINs:
2060-AG46: Acid Rain Program: Continuous Emission Monitoring (CEM) Rule Revisions
RIN Links:
https://www.federalregister.gov/regulations/2060-AG46/acid-rain-program-continuous-emission-monitoring-cem-rule-revisions
PDF File:
99-8939.pdf
Supporting Documents:
» Legacy Index for Docket A-97-35
» Acid Rain Program; Continuous Emission Monitoring Rule Revisions
» Acid Rain Program; Continuous Emission Monitoring Rule Revisions
» Acid Rain Program; Continuous Emission Monitoring Rule Revisions
CFR: (132)
40 CFR 72.13)
40 CFR 75.33)
40 CFR 75.19)
40 CFR 75.6)
40 CFR 75.71(a)(2)
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