28564 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations

ENVIRONMENTAL PROTECTION reference of certain publications listed D. Executive Order 12875 AGENCY in the regulations is approved by the E. Executive Order 13084 Director of the Federal Register as of F. Paperwork Reduction Act 40 CFR Parts 72 and 75 June 25, 1999. G. Regulatory Flexibility H. Submission to Congress and the General ADDRESSES: Docket. Supporting [FRL±6320±8] Accounting Office information used in developing the RIN 2060±AG46 I. Executive Order 13045 regulations is contained in Docket No. J. National Technology Transfer and A–97–35. This docket is available for Acid Rain Program; Continuous Advancement Act public inspection and photocopying Emission Monitoring Rule Revisions between 8:00 a.m. and 5:30 p.m. I. Regulated Entities AGENCY: Monday through Friday, excluding Environmental Protection Entities regulated by this action are government holidays and is located at: Agency (EPA). fossil fuel-fired boilers and turbines that EPA Air Docket (MC 6102) , Room M– ACTION: Final rule. serve generators producing electricity, 1500, Waterside Mall, 401 M Street, SW, generate steam, or cogenerate electricity SUMMARY: Title IV of the Clean Air Act Washington, DC 20460. A reasonable fee and steam. While part 75 primarily (CAA or the Act), as amended by the may be charged for photocopying. regulates the electric utility industry, Clean Air Act Amendments of 1990, FOR FURTHER INFORMATION CONTACT: authorizes the Environmental Protection the recent promulgation of 40 CFR part Monika Chandra, Acid Rain Division 96 and certain revisions to part 75 (see Agency (EPA or Agency) to establish the (6204J), U.S. Environmental Protection Acid Rain Program. The Acid Rain 63 FR 57356, October 27, 1998) means Agency, 401 M Street, SW, Washington, that part 75 could potentially affect Program and the provisions in this final DC 20460, (202) 564–9781. rule benefit the environment by other industries. The recent adoption of SUPPLEMENTARY INFORMATION: The part 96, together with revisions to part ensuring that the sulfur dioxide (SO2), contents of the preamble are listed in 75, include nitrogen oxides (NOX) mass nitrogen oxides (NOX) and carbon the following outline: provisions for the purpose of serving as dioxide (CO2) air pollution emissions to be measured and tracked pursuant to I. Regulated Entities a model which could be adopted by a the provisions of 40 CFR part 75 are II. Background and Summary of Final Rule state, tribal, or federal NOX mass accurately monitored and reported. III. Summary of Major Comments and reduction program covering the electric Responses These provisions also benefit the utility and other industries. Regulated A. Certification/Recertification Procedural categories and entities include: regulated entities by providing Changes additional flexibility and improved cost B. Quality Assurance Requirements for Examples of regu- effectiveness to the monitoring and Quantifying Stack Gas Moisture Content Category lated entities reporting options available to part 75 C. Percent Monitor Availability subject sources. On January 11, 1993, D. Span and Range Requirements Industry ...... Electric service pro- the Agency promulgated final rules, E. Flow-to-Load Ratio Test Requirements viders, boilers, tur- including the final continuous emission F. RATA and Bias Test Requirements bines and other monitoring (CEM) rule, under title IV. 1. RATA Load Levels process sources 2. Single Point Reference Method Sampling where emissions On May 17, 1995 and November 20, G. Data Validation 1996, the Agency revised the CEM rule exhaust through a 1. Data Validation During Monitor stack. to make the implementation simpler. On Certification and Recertification May 21, 1998, the Agency proposed 2. Data Validation for RATAs and Linearity additional revisions to the CEM rule, to Checks This table is not intended to be make implementation easier and more H. Appendix D—Sulfur Dioxide Emissions exhaustive, but rather provides a guide efficient for both EPA and the facilities from the Combustion of Gaseous Fuels for readers regarding entities likely to be affected by the rule, to improve quality 1. Summary of EPA Analysis of Appendix regulated by this action. This table lists assurance requirements, and to create D Gaseous Fuel SO2 and Heat Input the types of entities which EPA is now Methodologies new alternative monitoring options. aware could potentially be regulated by 2. Changes to the Definitions of ‘‘Pipeline this action. Other types of entities not EPA promulgated final rule revisions Natural Gas’’ and ‘‘Natural Gas’’ addressing some of these additional 3. Changes to the Methodology for listed in the table could also be regulated. To determine whether your proposed revisions, based on comments Calculating SO2 Emissions Under received, when EPA promulgated a Appendix D facility, company, business, Finding of Significant Contribution and 4. Changes to the Applicability of organization, etc., is regulated by this Rulemaking for Certain States in the Appendix D action, you should carefully examine Ozone Transport Assessment Group 5. Changes to the Method of Determining the applicability provisions in §§ 72.6, Region for Purposes of Reducing the Sulfur Content Sampling Frequency 72.7, 72.8, and part 96 of title 40 of the for Gaseous Fuels Regional Transport of Ozone (NOX SIP Code of Federal Regulations. If you have 6. Changes to the Method of Determining questions regarding the applicability of call). the GCV Sampling Frequency for In this action, EPA is issuing final Gaseous Fuels this action to a particular entity, consult rule revisions addressing the remaining I. Electronic Transfer of Quarterly Reports the person listed in the preceding FOR May 21, 1998 proposed revisions to the J. Bias, Relative Accuracy and Availability FURTHER INFORMATION CONTACT section of CEM rule, with certain changes to the Determinations this preamble. proposal based on the public comments K. Appendix I—Proposed Optional Stack Flow Monitoring Methodology II. Background and Summary of Final received. Some of these revisions will Rule be relevant for sources that become L. Subpart H—Clarifications to NOX Mass subject to part 75 requirements in Monitoring Requirements IV. Administrative Requirements Title IV of the Act requires EPA to response to the NOX SIP call. A. Public Docket establish an Acid Rain Program to DATES: The effective date of this rule is B. Executive Order 12866 reduce the adverse effects of acidic June 25, 1999. The incorporation by C. Unfunded Mandates Reform Act deposition. On January 11, 1993, the

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Agency promulgated final rules on experience gained in the early years 1997 were disapproved’’ (63 FR 28045, implementing the program, including of the program, facilities have citing Docket A–97–35, Item II–A–4). As the CEM rule (58 FR 3590). Notices of developed a number of suggestions that experience with the program increases, direct final rulemaking and of interim will simplify and streamline the the number of disapprovals is expected final rulemaking further amending the monitoring process without sacrificing to decrease even further. In addition, regulations were published on May 17, data quality. The Agency has also EPA’s position is that the owners or 1995 (60 FR 26510 and 60 FR 26560). amended quality assurance operators of affected facilities are Subsequently, on November 20, 1996, a requirements based on gaps identified responsible for initiating, conducting, final rule was published in response to by EPA during evaluation of the initial evaluating and certifying the results of public comments received on the direct implementation of part 75. Finally, the required testing prior to submission final and interim rules (61 FR 59142). several minor technical changes have to the appropriate regulatory Agencies. On May 21, 1998, the Agency published been made in order to maintain The Agencies’ role is to ‘‘certify’’ or proposed revisions to the part 75 CEM uniformity within the rule itself and to verify the results. Thus, there is no regulations (62 FR 28032). As noted clarify various provisions. reason to expect that the additional time above, EPA recently promulgated final provided to meet the administrative revisions to part 75 addressing some of III. Summary of Major Comments and needs of the program will result in any the May 21, 1998, proposed revisions in Responses significant compliance risk to the conjunction with the promulgation of a A. Certification/Recertification regulated sources, except in instances Model NOX Trading Rule in part 96 and Procedural Changes where insufficient care is taken to the NOX SIP call (see 63 FR 57356). ensure proper conduct of the testing. Today’s action adopts final part 75 Background: EPA proposed to revise Two commenters stated that the revisions to address the remaining May the recertification application review owner or operator would be in violation 21, 1998, proposed revisions and to period in § 75.20(b)(5) from 60 days to of the requirements of proposed make minor technical corrections to the 120 days, which is the same review § 75.33(d) and § 75.10(a) if a part 75 provisions promulgated in period as for the initial certification recertification application were application. The Agency believes that conjunction with part 96 and the NOX disapproved after 120 days (see Docket SIP Call. The final revisions involve the this will reduce confusion, simplify A–97–35, Items IV–D17 and IV–D–23) following matters: (1) revised certification/recertification application because the percent monitor availability definitions of gas-fired, oil-fired, and tracking, and will result in the more would be below 80%. These proposed peaking unit to allow for changes in unit efficient allocation of resources by local, penalties have been withdrawn from the fuel usage and/or operation; (2) a minor state, and federal agencies. Therefore, final rule in response to comments wording correction to the applicability EPA has adopted this change in the final received. Today’s final rule does not provisions in part 72; (3) new quality rule with certain modifications in treat a percent monitor data availability assurance/quality control (QA/QC) response to issues raised by of less than 80% as a violation. Instead, requirements for quantifying stack gas commenters. the final rule provides that if percent moisture content; (4) clarifying changes Discussion: Two states responded monitor data availability is less than to the certification and recertification positively to the proposed change. One 80%, then the appropriate maximum process; (5) substitute data requirements state commented that the increased value (e.g., maximum potential for carbon dioxide (CO2), heat input and review time ‘‘will allow more effective concentration) or, in some cases, the moisture; (6) clarifying revisions to the use of staff resources and provide ample appropriate minimum potential value petition provisions for alternatives to time for a thorough review of the data will be used to provide substitute data part 75 requirements; (7) clarifying submitted in the application’’ (see (see Section C of this preamble for a changes to span and range requirements; Docket A–97–35, Item IV–D–6). Another further discussion of these provisions). (8) clarifying revisions to general QA/ state commenter remarked that Several commenters suggested that QC requirements; (9) calibration error extending the review period ‘‘adds since the review of the initial test requirements; (10) linearity test uniformity and consistency to the certification applications for the Acid requirements; (11) a new flow-to-load certification and recertification process. Rain Phase I and Phase II units has been QA test for flow monitors; (12) This change is positive, and it allows completed, the burden on the states and reductions in and/or clarifications to the the state agencies the time to resolve EPA has been removed . Therefore, it relative accuracy test audit (RATA) and minor deficiencies which may should not take EPA 120 days to review bias test requirements; (13) clarifying otherwise serve as grounds to recertification applications (see Docket revisions to the procedures for CEM recommend disapproval. Based on A–97–35, Items IV–D–14, IV–D–20, and data validation; (14) clarifying revisions experience, the 120 day period is IV–D–24). This argument would be to the sulfur dioxide (SO2) emissions absolutely essential for the review of more compelling if the Acid Rain data protocol for gas-fired and oil-fired certification/recertification Program were the only program that the units (Appendix D); (15) determination applications’’ (see Docket A–97–35, various regulatory agencies are required of CO2 emissions under Appendix G; Item IV–D–9). to implement. However, EPA and the (16) recordkeeping and reporting Several commenters suggested that if States are currently responsible for changes to reflect the proposed EPA disapproved a recertification implementing several other programs revisions; (17) a revised traceability application after the 120 day period, that require comprehensive protocol for calibration gases (Appendix data recorded during the entire 120 day administrative review of various types H); and (18) NOX mass emission period would become invalid and the of applications and petitions (e.g., recordkeeping and reporting provisions, use of substitute data would be required Compliance Assurance Monitoring and minor revisions to NOX mass (see Docket A–97–35, Items IV–D–17, (CAM), the OTC NOX Budget Program, monitoring requirements. IV–D–20 and IV–D–24). However, as the PSD program and Title V Many of these changes are minor EPA stated in the preamble to the permitting). EPA also anticipates that technical revisions based on comments proposal, ‘‘less than 2 percent of all the NOX SIP call will further increase received from facilities following the monitoring system applications the number of certification and initial implementation of part 75. Based submitted between 1992 and September recertification applications and

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It is also measurements directly affects the moisture monitoring systems consisting sometimes difficult to distinguish a accuracy of the reported SO2 mass of wet-and dry-basis O2 analyzers, the recertification application package from emission rates, CO2 mass emission rates, proposed span values and performance an initial certification application NOX emission rates and heat input specifications for calibration error, package, which can complicate tracking values. An error of 1.0 percent H2O in linearity, and cycle time would be the the two types of applications if they measured moisture content causes a 1.0 same as the current specifications for O2 have different review periods. The percent error in the reported emission monitors. For moisture sensors, a recertification process usually requires rate or heat input value. Failure to calibration error specification of 3.0% of that a state or local program perform the quality assure the moisture data can span was proposed. The proposed initial review and forward the results to therefore result in significant under- relative accuracy (RA) specification for the EPA regional office which will then reporting of SO2, CO2, and NOX all moisture monitoring systems would make a recommendation to EPA emissions and heat input. be 10.0 percent. An alternative RA headquarters on whether to approve or In the May 21, 1998 proposed rule, specification was also proposed, i.e., the disapprove the application. This EPA set forth quality assurance RA test results would be considered requires a significant amount of time procedures that would apply to acceptable if the mean difference of the and does not allow much time to moisture monitoring systems because reference method measurements and the coordinate with the source to get moisture monitoring system the Agency believes that when moisture ± additional information, when needed. corrections must be applied, measurements is within 1.0 percent There is more likelihood of a continuous, quality assured, direct H2O. disapproval being issued under a short measurement of the stack gas moisture On-going QA requirements for time frame. Finally, EPA notes that it content or continuous measurement of moisture monitoring systems were also does not have control over the number surrogate parameters for moisture, such proposed. Appendix B would be revised of recertification applications that are as wet-and dry-basis oxygen to require daily calibrations of moisture submitted. Individual utility choices, monitoring systems, quarterly linearity concentrations, is the best way to ensure changes in rules, market conditions, and checks of wet-and dry-basis oxygen the accuracy of the reported emission technology all influence the number of analyzer(s), and semiannual RATAs of data. The proposed rule specified that a recertifications. Therefore, EPA has moisture monitoring systems. Any moisture monitoring system could concluded that extending the moisture monitoring system achieving a consist of either: (1) a continuous application review period from 60 to relative accuracy of ≤7.5 percent or a moisture sensor; (2) an oxygen (O2) 120 days is both necessary and mean difference between the CEMS and analyzer (or analyzers) capable of appropriate. reference method values within ± 0.7 measuring O2 on both a wet basis and percent H2O, would qualify for an B. Quality Assurance Requirements for on a dry basis; or (3) a system consisting annual, rather than semiannual RATA Quantifying Stack Gas Moisture Content of a temperature sensor and a certified frequency. Background: Section 75.11(b) of the data acquisition and handling system Missing data procedures for moisture January 11, 1993 Acid Rain rule requires (DAHS) component capable of were included in the proposed rule in the owner or operator to continuously determining moisture from a lookup a new section, § 75.37. Provided that the (or on an hourly basis) account for the table, i.e., a psychometric chart (this moisture data availability is high (≥90.0 moisture content of the stack gas when third option would apply only to percent), the average of the ‘‘hour SO2 concentration is measured on a dry saturated gas streams following wet before’’ and ‘‘hour after’’ moisture basis. The moisture content is needed to scrubbers). values would be used for each hour of correct the measured hourly stack gas The proposed rule included the missing data period. When the volumetric flow rates to a dry basis requirements for the initial certification percent data availability drops below when calculating SO2 mass emission of moisture monitoring systems. For 90.0 percent, 0.0 percent moisture rates in lb/hr. Section 75.13(a) of the continuous moisture sensors, a 7-day would be substituted for each hour of rule, as amended on May 17, 1995, calibration error test and a relative the missing data period. contains provisions for CO2 monitoring accuracy test audit (RATA) would be Finally, the proposed rule specified paralleling the provisions of § 75.11(b); required. For moisture monitoring that records must be kept for the that is, when CO2 concentration is systems consisting of one or more wet- moisture monitoring systems, including measured on a dry basis, a correction for and dry-basis oxygen analyzers, the hourly average moisture readings, stack gas moisture content is needed to proposed requirements included a 7-day percent data availability, and records of accurately determine the CO2 mass calibration error test, a linearity test and all calibration error tests, linearity tests emissions. The stack gas moisture a cycle time test of each O2 analyzer, and relative accuracy test audits. content is also needed when a dry-basis and a RATA of the moisture Today’s final rule provides a number O2 monitor is used to account for CO2 measurement system. For the lookup of options by which owners or operators emissions and, in some instances, when table option (saturated streams, only), of affected sources may account for the accounting for unit heat input or when the certification requirement would stack gas moisture content on an hourly determining NOX emission rate in lb/ consist of a DAHS verification. The basis. The rule also includes quality mmBtu. proposed rule specified that owners or assurance provisions for moisture As presently codified, part 75 does operators would have to complete all monitoring systems. Today’s rule differs not specify any quality assurance moisture monitoring system from the proposed rule as follows: (1) requirements for moisture measurement certification tests no later than January the alternate specification in terms of devices. Approximately 5 to 10 percent 1, 2000. the mean difference has been increased

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from ± 1.0 to ± 1.5% H2O, but the pollutant and diluent component monitoring system readings agree with principal relative accuracy specification monitors are not determined). the reference method. In this case, for moisture monitoring systems has Several commenters indicated that subtracting 3% moisture from the been promulgated as proposed, at 10.0 they do not believe that a moisture average moisture monitoring system percent; (2) the daily calibration monitoring system can meet the values for each run caused the relative requirement for continuous moisture proposed relative accuracy (RA) accuracy to drop from 16.5% to 2.4%, sensors has been withdrawn; (3) the use specifications of 10.0% for a semiannual which is well below the proposed of the lookup table option has been RATA frequency or 7.5% for an annual 10.0% semiannual and 7.5% annual RA expanded to include any demonstrably RATA frequency. One commenter specifications. For the alternate RA saturated gas stream, rather than expressed the opinion that the RA for a specification, after applying the 3% limiting it to gas streams following wet moisture monitoring system should be moisture correction, the mean difference scrubbers; (4) a site-specific coefficient 15.0% (see Docket A–97–35, Item IV–G– was essentially zero, which is also well or constant (‘‘K’’ factor), determined at 04). Another commenter suggested that below the value of 1.0% moisture the principal RA specification should be the time of the RATA, may be used to proposed for a semiannual RATA 10%

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00005 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28568 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations especially in view of the proposed specific default values for moisture in maximum potential moisture percentage moisture QA/QC specifications. After today’s rule (for coal and wood, only), must be used. careful consideration, the Agency agrees which may be reported for each unit Discussion: EPA received one with the commenter and, in response, operating hour, as an alternative to comment that supported making a the final rule adopts the missing data operating and maintaining a continuous percent monitor availability of less than procedures in § 75.37 that are less moisture monitoring system. The 80% a violation (see Docket A–97–35, conservative than the procedures in the default values are found in Item IV–D–11) and another commenter proposed rule and that more closely §§ 75.11(b)(1) and 75.12(b) of today’s favored the provision that if percent resemble the standard missing data rule. Note that two sets of default values monitor availability is below 80% due procedures for SO2, NOX, and flow, as appear in the rule to address the to ‘‘unforseen events beyond our recommended by the commenters. The variability in format among the control,’’ this would be taken into moisture missing data algorithm is equations used for determining consideration (see Docket A–97–35, modeled after the standard SO2 missing pollutant emissions and heat input (as Item IV–G–9). EPA also received data algorithm in § 75.33(b). This is discussed in the previous paragraph). comments objecting to making a percent consistent with the provisions in The lower default values in § 75.11(b)(1) monitor data availability of less than §§ 75.35 and 75.36 of today’s rule, apply to Equations F–2, F–14b, F–16, F– 80% a violation and suggesting that EPA which adopt this algorithm for CO2 and 17 and F–18 in Appendix F of part 75 should modify the standard missing heat input missing data. However, in and to Equations 19–5 and 19–9 in EPA data algorithms for SO2, NOX and flow finalizing the moisture missing data Method 19 in Appendix A of 40 CFR 60. rate to require the use of a maximum provisions, it became evident that a The higher default values in § 75.12(b) substitute data value when monitor single mathematical algorithm is not apply when Equation 19–3, 19–4 or 19– availability drops below 80 percent (see adequate to cover all of the part 75 8 in EPA Method 19 in Appendix A of Docket A–97–35, Items IV–D–17, IV–D– emission rate and heat input equations 40 CFR 60 is used to determine the NOX 19, IV–D–23, IV–D–24). In response to that require moisture corrections. In emission rate. The default values were the comments, the final rule does not most of the equations, the lower determined as follows. The moisture make percent monitor availability of moisture values are more conservative, percentage values (which included both less than 80% a violation and instead provides that if percent monitor data and an ‘‘inverted’’ SO2 missing data ultimate moisture and free moisture) for algorithm is appropriate (for further each fuel type were taken from the availability at a source is less than 80%, discussion of the ‘‘inverted’’ algorithm, appropriate tables in Docket Item IV–A– then the owner or operator of the source see section C of this preamble, below). 2, cited above. The moisture values will have to substitute the appropriate However, there are certain emission rate were then ranked from the lowest maximum value (i.e., MPC for SO2 and equations for which the opposite is true percentage value to the highest CO2, MER for NOX emission rate and (i.e., the higher moisture values are percentage value, and the 10th maximum potential flow rate for flow) as suggested by the commenters. Note more conservative and the regular SO2 percentile value was selected for the missing data algorithm is appropriate). ‘‘low’’ default value and the 90th that for O2 and, in most cases, for The specific equations for which the percentile value was selected for the moisture, minimum potential values will be substituted rather than regular SO2 algorithm applies are ‘‘high’’ default value. Each default Equations F–3, F–4 and F–8 in Method moisture percentage was rounded to the maximum values, since the lower values of these parameters are more 19 in Appendix A of 40 CFR 60. nearest whole number. conservative. However, if Equation 19– Provided that all of the moisture- C. Percent Monitor Availability 3, 19–4 or 19–8 in EPA Method 19 in corrected emission and heat input Appendix A of 40 CFR 60 is used to equations used by an affected facility Background: EPA proposed that if the determine NOX emission rate, higher employ the same moisture missing data annual monitor data availability moisture values are more conservative algorithm (regular or inverted), it is a dropped below 80% for SO2, NOX, flow and the maximum potential moisture simple matter to substitute for missing rate or CO2, this would violate the percentage will be used to provide moisture data. However, when two or primary measurement requirement of substitute data. more equations require different § 75.10(a). In response to comments, The missing data approach set forth in moisture algorithms, an alternative way today’s final rule does not treat a today’s rule to address low monitor data of addressing missing moisture data is percent monitor data availability of less availability retains the basic design of needed. EPA believes that this situation than 80% as a violation. Instead, the the part 75 program and appropriately will rarely be encountered (at present, final rule provides that if percent addresses the need for accountability the Agency’s records indicate that there monitor data availability is less than from sources that are inadequately are only two such affected units in the 80%, then the appropriate maximum maintaining their monitoring systems. Acid Rain Program). Therefore, value (i.e., maximum potential The Agency maintains that this provides § 75.37(d) of today’s rule requires the concentration (MPC) for SO2 and CO2, a strong incentive to achieve at least owner or operator of such units to maximum potential emission rate (MER) 80% monitor availability. Unlike the petition the Administrator under for NOX and maximum potential flow proposed approach of considering § 75.66(l), for an alternative moisture rate for flow) will have to be used as sources to be in violation, the substitute missing data procedure. substitute data for any hour for which data approach adopted today creates Finally, several commenters requested valid data is not available. For O2, the this incentive while rendering that EPA allow the use of a default minimum potential concentration will unnecessary the task of determining and moisture value in lieu of the required be used to provide substitute data. For evaluating the reason(s) for low monitor moisture monitoring (see Docket A–97– moisture, consistent with the discussion data availability. 35, Items IV–D–11, IV–D–02 and IV–D– in section B of this preamble, the 23). The Agency has performed a minimum potential moisture percentage D. Span and Range Requirements moisture data analysis for various fuels will be used in most instances to Background: The span of a CEMS (see Docket A–97–35, Item IV–A–2) and, provide substitute data; however, for provides an estimate of the highest based on the results, has provided fuel- certain emission rate equations, the expected value for the parameter being

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

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

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200% of the MPC (for the default high commenter. For units with SO2 combinations of boilers. Despite this, if range value) have been retained in the scrubbers, the vast majority of the data the diluent gas concentration is properly final rule. EPA maintains that these is collected on the low range. Therefore, taken into account, the flow-to-load values must be conservative, based on a the SO2 RATA should be performed on characteristics of common stacks often ‘‘worst case’’ analysis to ensure that that range. If the scrubber malfunctions become more normalized. The flow-to- emissions will not be under-reported. at the time of a scheduled SO2 RATA, load ratio, or a normalized ratio, such as The Agency believes that if spans and the RATA should either be rescheduled the gross heat rate (GHR) can thus serve ranges are properly set, full-scale later in the quarter or should be done as a quantitative indicator of flow exceedances will be relatively rare. during the 720 unit operating hour grace monitor accuracy from quarter to Also, EPA anticipates that the majority period allowed under revised section quarter until the next RATA is of the units for which owners or 2.3.3 of Appendix B. performed. operators will elect to use the default The proposed rule provided a E. Flow-to-Load Ratio Test high range option have reliable emission calculation methodology for the Requirements controls and the default value will quarterly flow-to-load or GHR rarely, if ever, have to be used. Background: The quality assurance evaluation. A ‘‘reference’’ flow-to-load One commenter objected to the requirements for flow rate monitoring ratio or GHR would be established at the proposed changes to the method of systems in Appendices A and B of part time of each normal-load flow RATA, calculating MPC and MEC values, 75 include daily calibration error tests, using data from the flow rate reference expressing concern that the revisions daily interference checks, quarterly leak method. Then, in subsequent quarters, might require his existing span and checks (for differential pressure type hourly data from the flow monitor range values to be re-calculated (see monitors only), and semiannual or would be compared to the reference Docket A–97–35, Item IV–G–02). annual RATAs. Of these required QA ratio or GHR, and an absolute average Another commenter (mistakenly) tests, only the RATA provides a true percentage difference between the interpreted the proposed definition of evaluation of a flow monitor’s hourly data and the reference ratio the MPC for CO2 in section 2.3.1 of measurement accuracy by direct would be calculated. If the percentage Appendix A to mean that his existing comparison against an independent difference exceeded certain limits, the CO2 span values would have to be re- reference method. The daily calibration utility would be required to investigate determined (see Docket A–97–35, Item error test checks the system’s internal to try to establish the cause of the test IV–D–04). A third commenter asked electronic components by means of failure. If the investigation indicated a EPA to ‘‘grandfather’’ existing span and reference signals. The calibration error problem with the flow monitor, the range values (see Docket A–97–35, Item test is useful in that it can diagnose utility could perform corrective actions, IV–D–20). It is not, and never has been certain types of monitor problems, but followed by an abbreviated flow-to-load EPA’s intent to require utilities to it does not evaluate the system’s ability diagnostic test, to demonstrate that the change their existing spans and ranges, to measure an actual stack gas flow rate. corrective actions were effective. provided that they meet the guideline of Because of this limitation, EPA believes However, if the investigation could not section 2.1 of Appendix A ( for the that a more substantive, periodic QA establish the cause of the flow-to-load majority of the readings to be between test is needed to ensure that the test failure, a normal load flow RATA 20 and 80% of full-scale, with certain accuracy of the reported flow rate data would be required. allowable exceptions). The Agency does is maintained in the interval between Today’s final rule adopts the flow-to- not believe that ‘‘grandfathering’’ of any successive RATAs. The Agency is load ratio test provisions. The final rule existing part 75 span and range values particularly concerned about the is essentially the same as the proposal is necessary. The final rule simply adds potential for poor data quality from flow except for a few minor changes in flexibility to the procedures for monitors that are not properly response to comments received. determining spans and ranges. Affected maintained. Discussion: EPA received comments units with previously-determined span In view of this, EPA proposed to add on the proposed quarterly flow-to-load and range values that meet the guideline a new flow monitor quality assurance ratio test from seven utilities, two state of section 2.1 of Appendix A do not test, the ‘‘flow-to-load ratio test,’’ to part agencies, one utility regulatory response have to change their current span or 75 in section 7.7 of Appendix A and group and one flow monitor vendor. range values. To further alleviate undue section 2.2.5 of Appendix B. A similar One state agency was supportive of the concern about this, the Agency has test was first suggested to the Agency by test, because it can serve as a withdrawn the proposed changes to the a flow monitor manufacturer (see quantitative indicator of flow monitor method of determining whether a dual Docket A–97–35, Item II–D–69). The performance from quarter to quarter (see span is required. Rather than comparing flow-to-load ratio test, which would be Docket A–97–35, Item IV–D–9). The the MEC value(s) to the MPC value(s) (as performed quarterly, would be required flow monitor vendor also favored the proposed), today’s rule specifies that the beginning in the second quarter of the test, because it will help to ensure that MEC value should be compared to the year 2000. The basic premise of the all flow monitoring technologies high range value. This is essentially the flow-to-load ratio test is that a perform in a reliable manner (see Docket same as the requirement in the current meaningful correlation exists between A–97–35, Item IV–D–12). Several utility rule. the stack gas volumetric flow rate and commenters objected to the proposed Finally, one commenter objected to unit load. In general, for a single unit test, believing it would be burdensome, the proposed requirement to perform discharging to a single stack, as the load time-consuming, expensive to the RATA at the low range of the increases, the flow rate increases implement (requiring significant DAHS monitor on units that have scrubbers. proportionally, and the flow rate at a software modifications), and difficult to The commenter urged EPA to revert to given load should remain relatively pass (see Docket A–97–35, Items IV–D– the original rule and allow the RATA to constant if the same type of fuel is 16, IV–G–5, IV–G–9, IV–G–2). One be performed at whatever range the burned. Common stacks are somewhat commenter suggested that the test be CEMS is operating on at the time of the less predictable, because the same used as a warning to take corrective RATA (see Docket A–97–35, Item IV–G– combined unit load can be produced in action rather than using it to directly 3). EPA does not agree with the a number of ways by using different validate or invalidate flow rate data (see

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Docket A–97–35, Item IV–D–11). demonstrate to the satisfaction of the results of the flow-to-load and GHR data Another commenter recommended that Administrator that the flow rate through analyses were nearly the same. Only one for common stacks, additional hours be the complex stack configuration cannot failure of the quarterly flow-to-load test exempted from the data analysis, be reasonably correlated to unit load. was observed in each analysis (i.e., the specifically hours in which the Second, for a unit with a multiple stack failure rate was <5.0 percent). The value combination of boilers and loads does discharge configuration consisting of a of Ef (the average percentage difference not match the combination used during main stack and a bypass stack (e.g., for between the hourly ratios and the the last normal load flow RATA (see a unit with a wet SO2 scrubber), the reference ratio) was 6.1 percent for the Docket A–97–35, Item IV–D–17). Two flow-to-load test is to be performed on analysis of the flow-to-load ratios and commenters recommended increasing an individual stack basis and hours in 6.4 percent for the simulated GHR the threshold to qualify for a less which emissions are discharged analysis (with diluent gas corrections). stringent flow-to-load specification from simultaneously through both stacks may However, as noted by one of the 50 MW to 60 or 70 MW (see Docket A– be excluded from the quarterly flow-to- commenters, the Agency acknowledges 97–35, Items IV–D–11, IV–D–2). Two load analysis. Third, the threshold to that these data analyses were performed commenters recommended reducing the qualify for a less stringent flow-to-load using the calculation method described frequency of flow RATAs based on good specification has been raised from 50 in the May, 1997 pre-proposal draft of performance in the flow-to-load test; MW to 60 MW. Fourth, when a flow-to- the rule revisions, i.e., using the specifically, one commenter advocated load or GHR test is failed, two weeks, arithmetic percentage difference performing flow RATAs every other rather than one, are allowed after the between each hourly flow-to-load ratio year and the other commenter end of the quarter to investigate the and the reference ratio, rather than the recommended performing a flow RATA cause of the test failure before triggering absolute percentage difference once every five years (see Docket A–97– a RATA requirement. prescribed in the proposed rule. To 35, Items IV–D–22, IV–G–2). One EPA does not agree with the address the commenter’s concern, EPA commenter stated that the proposed commenters who characterized the has re-analyzed the data using the flow-to-load methodology does not proposed flow-to-load test as time- absolute percentage difference. The adequately address multiple stack consuming, burdensome, and difficult results of the data analysis using the configurations where one of the stacks to implement (requiring extensive absolute percentage difference were is a bypass stack, and also software revision). The Agency believes nearly the same as the results using the recommended that EPA make it clear that implementation of the flow-to-load arithmetic percentage difference. The that the flow-to-load data analysis only test will not require any special failure rate was the same (<5%) and the modification of existing part 75 DAHS applies to reported data and not to value of Ef was 7.3 percent for the redundant backup monitor data which systems or software. All of the analysis of the flow-to-load ratios and are not reported (see Docket A–97–35, information needed to perform the 8.0 percent for the simulated GHR Item IV–G–2). Finally, the utility quarterly flow-to-load or GHR analysis analysis (with diluent gas corrections), regulatory response group found the is currently reported in the electronic which is still well below the 15.0 proposal to be an improvement over the quarterly report required under § 75.64. percent tolerance limit (see Docket A– pre-proposal draft that was circulated in Rather, a PC-based computer program 97–35, Item IV–A–3). Thus, it appears to May, 1997, but took issue with the will be needed, which can extract the make very little difference, in terms of following: (1) The method of calculating essential information from the quarterly ease of passing, whether the absolute report and analyze it. Once such a the test results, using the absolute value percentage difference or the arithmetic computer program is written, analysis of of, rather than the arithmetic, percentage difference is used in the the quarterly flow rate and load data percentage of differences between the flow-to-load and GHR calculations. should become a routine operation hourly flow-to-load ratios and the Therefore, the flow-to-load and GHR which will be neither burdensome nor reference ratio; (2) failure of the calculation methodology has been time-consuming. proposal to address units with bypass The Agency also disagrees with those finalized as proposed using the absolute stacks or other complex stack commenters who contended that the percentage difference. configurations; and (3) allowing only flow-to-load test will be difficult to pass. Two commenters suggested that the one week after the end of the quarter to On the contrary, the flow-to-load test flow RATA frequency should be investigate and troubleshoot the flow should be relatively easy to pass, reduced based on good performance on monitor when a flow-to-load test failure provided that the flow monitor is the quarterly flow-to-load test (see occurs, before a RATA requirement is properly operated and well-maintained. Docket A–97–35, Items IV–D–22 and triggered (see Docket A–97–35, Item IV– Prior to issuing the proposed rule, EPA IV–G–02). The Agency agrees with the D–20). analyzed quarterly flow rate and load commenters that with the addition of Today’s rule includes flow-to-load data from the third quarter of 1996 for the new QA tests it is reasonable to test provisions in section 7.7 of 21 units and stacks, including 9 single lessen the frequency of the annual three Appendix A and section 2.2.5 of units, 11 common stacks, and 1 load flow RATA. Therefore, EPA is also Appendix B. The final rule is essentially multiple-stack unit. The units chosen adopting the following three provisions the same as the proposal, except for the for this analysis were selected as a reducing the flow RATA requirements: following changes, which have been representative sample of units that (1) Routine flow RATAs are changed incorporated in response to the would be affected by this QA test from three-load tests to two-load tests; comments received. First, a new section requirement and included various (2) a single-load annual flow RATA is 7.8 has been added to Appendix A, operational circumstances (e.g., base allowed if the unit operates at one load which allows owners or operators of loaded and peaking units, single fuel level for ≥85 percent of the time since units with complex stack configurations units, and units that burn multiple the last annual flow RATA; and (3) a to petition for an exemption from fuels). The flow-to-load and GHR test three-load flow RATA is required only quarterly flow-to-load testing. Any such methodologies were applied to each once every five years and whenever the petition would have to provide unit or stack, excluding none of the instrument is re-linearized. EPA has information and data which normal load data from the analysis. The adopted these reduced flow RATA

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00010 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28573 requirements principally because of the quarterly report under § 75.64. The most results of the load frequency data reasonable assurance of data quality that frequently used load level would then analysis electronically, stating that will be provided in between RATAs by be designated as the ‘‘normal’’ load. The requiring electronic reporting of the the new flow-to-load test. Note, second most frequently used load could, results provides no advantage over however, that the flow-to-load ratio test, at the discretion of the owner or keeping the data analysis on-site and which analyzes a limited amount of operator, be designated as a second that such reporting would require DAHS flow rate data at a single load level, does normal load level. Gas monitor RATAs software changes (see Docket A–97–35, not serve as a replacement for annual would be required at the normal load Item IV–G–2). RATA testing. Rather, the flow-to-load level. Routine quality assurance RATAs Today’s rule finalizes the proposed ratio test helps to ensure that the flow for flow monitors would be done at the definitions of the ‘‘range of operation,’’ monitor remains accurate in between two most frequently used load levels. and the ‘‘low,’’ ‘‘mid,’’ and ‘‘high’’ load successive semiannual or annual Today’s rule adopts the proposed levels in section 6.5.2.1 of Appendix A RATAs. changes with certain modifications in and the associated requirement to report response to comments. the upper and lower boundaries of the F. RATA and Bias Test Requirements Discussion: The Agency received range of operation, with one minor 1. RATA Load Levels comments on the proposed method of revision. A provision has been added for frequently-operated (e.g., base-loaded) Background: The previous provisions determining RATA load levels from units that share a common stack, which of part 75 were neither sufficiently three individual utilities and from two allows the ‘‘minimum safe, stable load’’ standardized nor clear in defining the utility regulatory response groups. Only to be determined in a different manner. two comments were received on the appropriate load levels for RATAs. For For such units, the owner or operator proposed definitions of ‘‘range of example, the previous rule required gas may use the sum of the minimum safe, operation,’’ ‘‘low,’’ ‘‘mid,’’ and ‘‘high’’ monitor RATAs to be conducted at stable loads for the individual units as load levels. One commenter supported normal load and required gas and flow the minimum safe stable load for the the effort to establish load level rate monitor bias adjustment factors to common stack (rather than using the definitions, but found the proposal to be be determined at normal load, but no lowest of the minimum safe, stable load too inflexible and complicated and definition of normal load was provided. values for the individual units). The suggested that EPA should permit In addition, section 6.5.2 of Appendix A Agency believes that this adequately specified that the ‘‘low’’ load audit overlapping load ranges (see Docket A– addresses the commenter’s concern that point for a 3-level flow RATA can be 97–35, Item IV–D–20). The other one or more units might have to be shut located anywhere from the minimum commenter requested that EPA modify down in order to attain the ‘‘low’’ load safe, stable load to 50.0 percent of the the proposed definition of the level during a 3-load flow RATA. maximum load, and no minimum ‘‘minimum safe, stable load’’ for Section 6.5.2.1 of Appendix A of separation is required between the audit common stacks. The commenter today’s rule also finalizes the proposed points at adjacent load levels. If adjacent expressed concern that for base-loaded methodology for determining normal audit points are too close together, a units which share a common stack, the load and for selecting the appropriate multiple load flow evaluation loses its proposed definition might require a unit load levels for the annual 2-load flow significance. to be shut down to attain the low load RATAs, with revisions based on EPA proposed revisions to Appendix level in a 3-load flow RATA (see Docket comments received. In the final rule, a A of part 75, which would more clearly A–97–35, Item IV–D–24). Four determination of the normal load define the load levels at which RATAs commenters opposed the proposed level(s) and the appropriate flow RATA are done in order to achieve greater requirement to develop a historical load load levels is still required, but it has consistency in the way that RATAs are frequency distribution to establish the been made a one-time requirement, performed. The proposed methodology, normal load level(s) for the unit or rather than an annual requirement. The which would become effective as of stack, stating that the load frequency is requirement becomes effective on April April 1, 2000, would require the utility too variable (being dependent on unit 1, 2000, but owners or operators may to define the ‘‘range of operation’’ for availability, operation, and dispatch) comply with it prior to that date. The each affected unit or common stack and that the new requirement would owner or operator must review (except for peaking units). The range of add another level of unnecessary data historical load data for the unit or stack, operation would extend from the collection and manipulation (see Docket for a minimum of four representative minimum safe, stable load to the A–97–35, Items IV–D–20, IV–D–24, IV– operating quarters. From these data, the maximum achievable load. The ‘‘low’’ D–19, and IV–D–23). Another percentage of unit operating time at load level would then be defined as 0– commenter suggested that RATA load each load level (‘‘low,’’ ‘‘mid’’ or 30% of the range of operation, the ranges should be based on the typical ‘‘high’’) will be determined. The ‘‘mid’’ load level would be 30–60% of load requirements for the quarter in historical load data may be analyzed by the range and the ‘‘high’’ load level which the RATA is done, particularly if any suitable means; construction of a would be 60–100% of the range. The the historical data are no longer histogram, per se, is not required. The proposed methodology would require a representative. The commenters further load level used the most frequently will load frequency distribution (histogram) recommended that EPA should: (1) be designated normal, and the second to be developed, prior to each annual eliminate the requirement to use four most frequently used load level may, at RATA, to determine the percentage of operating quarters of data; (2) allow the discretion of the owner or operator, time the unit or stack has operated at extenuating data to be excluded; (3) be designated as a second normal load. each load level in the previous four ‘‘QA allow recent changes to be considered The two most frequently used load operating quarters.’’ A summary of the when selecting load ranges; and (4) levels are the load levels at which the data used for the load frequency allow utilities to consider forecasted annual 2-load flow RATA will be determination would be maintained on- usage of a unit when selecting load performed. The results of the historical site in a format suitable for inspection, ranges (see Docket A–97–35, Item IV–D– load data analysis will be reported in and the results of the determination 20). Finally, one commenter objected to the electronic quarterly report as part of would be included in the electronic the proposed requirement to report the the electronic monitoring plan. EPA

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28574 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations believes that reporting one additional traverse point selection. Proposed stratification is present in the stack. monitoring plan record will not prove to section 6.5.6 would allow single-point Another State agency commenter be burdensome. A summary of the data reference method sampling to be used in viewed the proposal to allow single- used for the load determinations and the two specific instances: (1) for all point reference method sampling as calculated results must be kept on-site, moisture determinations, a single unfavorable, expressing concern that in a format suitable for inspection. reference method point, located at least single-point sampling may not yield EPA continues to believe that a 1.0 meter from the stack wall, could be valid results, particularly if the review of historical operating load data used; and (2) for flue gas sampling, a sampling point is too near the stack is a reasonable way to standardize the single reference method measurement wall, where air in-leakage can occur (see determination of the normal load point, located no less than 1.0 meter Docket A–97–35, Item IV–D–9). The level(s) and the appropriate flow RATA from the stack wall, could be used at third State agency commenter appeared load levels for a unit or stack. In order any test location if a stratification test is to take issue with the use of a 3-point to maintain national consistency and to performed prior to each RATA at the abbreviated stratification test, stating ensure that a ‘‘level playing field’’ is location and certain acceptance criteria that for the large-diameter stacks in the maintained among affected utilities, the are met. Acid Rain Program, a three point test is Agency believes that a standardized In order to implement the second not adequate to demonstrate the absence procedure is necessary. Although option (single-point gas sampling), a 12- of stratification. several commenters took issue with the point stratification test, as described in In response to the comments received, specifics of the proposed methodology, proposed section 6.5.6.1, would have to the single-point reference method none of them provided a sufficiently be passed one time at the sampling provisions in section 6.5.6 of Appendix detailed alternative procedure for location, meeting the acceptance criteria A of today’s rule are more restrictive serious consideration by the Agency. for single-point sampling given in than the provisions in the proposal. Requests to ‘‘allow exclusion of proposed section 6.5.6.3 of Appendix A. After careful consideration, EPA has extenuating data’’ and ‘‘permit The location would qualify for single- decided to allow single-point reference consideration of recent changes when point gas sampling if the concentration method sampling, but to place selecting load ranges’’ do not provide a at each individual traverse point ± additional restrictions on its use. The sufficient basis for the development of differed by no more than 5.0 percent Agency believes that some of the state appropriate regulatory language. from the arithmetic average agency commenters’ concerns about the Further, since the standardized concentration for all traverse points. proposed single-point sampling procedure is based on data for four The results would also be acceptable if methodology are valid. Accordingly, operating quarters, any unrepresentative the concentration at each individual today’s final rule addresses these data is likely to have minimal effect. traverse point differed by no more than concerns. Therefore, EPA did not incorporate most ± 3.0 ppm or 0.3 percent CO2 (or O2) Today’s rule allows the unrestricted of the commenters’ suggestions. from the arithmetic average use of single-point moisture sampling However, to address the concern of concentration for all traverse points. several commenters about possible Once a 12-point stratification test was only in applications where the moisture variability in unit load and manner of passed at the candidate sampling data are used to determine the stack gas unit operation, a provision has been location, either the 12-point test or an molecular weight. For all other moisture added to section 6.5.2.1 of Appendix A abbreviated 3-point or 6-point measurement applications, i.e., for which requires the historical load stratification test, as described in moisture monitoring system RATAs or analysis to be repeated if the way in proposed section 6.5.6.2, would have to when moisture data are used to correct which a unit operates changes be passed prior to subsequent RATAs at emission data from a dry basis to a wet significantly and the previously- the location. basis (or vice-versa), single-point determined normal load level(s) and the Today’s rule finalizes the provisions moisture sampling is only permitted if two most frequently used load levels for single-point moisture and gas a 12-point pollutant or diluent gas change. The new provision requires a reference method sampling, with certain stratification test is performed and minimum of two representative modifications in response to comments passed (at the 5.0 percent specification operating quarters of historical load data received. The criteria in today’s rule to in section 6.5.6.3 of Appendix A) prior to document that a change in the qualify for single-point sampling are to the RATA. Similarly, for flue gas manner of unit operation has actually more stringent than the criteria in the sampling, today’s rule allows the use of occurred. proposed rule. single-point reference method sampling Discussion: EPA received comments only if a 12-point gas stratification test 2. Single-Point Reference Method from two utilities and three State air is performed and passed at the 5.0 Sampling regulatory agencies on the proposal to percent specification prior to the RATA. Background: Section 6.5.6 of allow single-point reference method Use of an abbreviated (3- or 6-point) Appendix A to part 75 gives the traverse sampling. One of the utility commenters stratification test as a means of point location requirements for favored allowing single-point sampling, qualifying for single-point sampling is reference method sampling during viewing it as an excellent step to not allowed. relative accuracy test audits (RATAs) of improve the overall efficiency of RATA Finally, when a test location qualifies gas monitoring systems. The reference testing (see Docket A–97–35, Item IV– for single-point reference method method sampling points are to be D–21). The other utility commenter also sampling, today’s rule specifies that the located along a line, in accordance with favored the proposal, believing that it measurement point must be located at section 3.2 of Performance Specification would reduce the manpower least 1.0 meter from the stack wall and No. 2 in Appendix B to 40 CFR part 60. requirements for gas RATA testing (see must be situated along one of the Performance Specification No. 2 Docket A–97–35, Item IV–D–22). One measurement lines used in the 12-point requires three reference method State agency commenter opposed the stratification test. EPA believes that sampling points for each RATA test run. unrestricted use of single-point moisture these modifications to the proposed EPA proposed changes to section 6.5.6 sampling, stating that the moisture single-point reference method sampling of Appendix A, pertaining to RATA results could be biased if gas methodology are necessary to ensure

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00012 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28575 that representative samples will Appendix B) and provided that the option). Second, proposed paragraph continue to be obtained. recertification tests and required daily (b)(3)(x) of § 75.20 has been merged with calibration error tests continued to be proposed paragraph (b)(3)(i), for greater G. Data Validation passed. If all of the required clarity; both paragraphs deal with 1. Data Validation During Monitor recertification tests and calibration error missing data substitution prior to the Certification and Recertification tests were passed hands-off, with no recertification test period. Third, the Background: The previous version of failures and within the required time definition of a ‘‘hands-off’’ part 75 specified that for any period, then all of the conditionally recertification test in § 75.20(b)(3)(v) has replacement, change, or modification to valid emission data recorded by the been revised to make it clear that once a monitoring system requiring CEMS during the recertification test a recertification test has begun, only recertification of the CEMS, all data period would be considered quality routine calibration adjustments from the CEMS are invalid from the assured and suitable for part 75 following daily calibration error tests reporting. However, if any required test hour of that replacement, change, or are permitted until the test is was failed, the conditionally valid data modification until the hour of completed. Fourth, language has been would, in most cases, be invalidated completion of all required added to § 75.20(b)(3) to address the and a new recertification test period recertification tests. The proposed rule case in which a multi-load flow RATA would have to be initiated, following would have revised § 75.20(b)(3) to is passed at one or more load levels and corrective actions. conditionally allow emission data then failed at a subsequent load level. Today’s rule finalizes the CEMS Regarding the fourth revision to generated by the CEMS during a validation procedures for certifications recertification test period to be used for § 75.20(b)(3) described in the previous and recertifications, with certain paragraph, 2.3.2(e) of Appendix B of part 75 reporting, provided that the modifications in response to comments required tests are successfully today’s rule states that in such cases, received. only the RATA at the failed load level completed in a timely manner and that Discussion: EPA received strongly needs to be repeated (unless re- certain data validation rules are supportive comments on the proposed linearization of the monitor is followed during the recertification test revisions to § 75.20(b)(3) from five necessary, in which case a 3-load RATA period. Proposed sections 6.2, 6.3.1, and utilities, one state air regulatory agency is required). Because of this new 6.5 of Appendix A would have allowed and two utility regulatory response Appendix B provision, the following these new data validation procedures to groups. However, two utilities asked the corresponding data validation also be applied to the initial Agency to modify the proposal to allow provisions have been added to certification of monitoring systems. The trial gas injections and preliminary §§ 75.20(b)(3)(vii)(A) and intended purpose of the proposed RATA runs to be done during the revisions is to minimize the number of recertification test period, rather than 75.20(b)(3)(vii)(B): (1) upon failure of hours of substitute data or maximum prior to it. One commenter stated that the RATA at the particular load level, potential values that must be reported preliminary gas injections and RATA the length of the new recertification test during a monitor certification or runs, which are considered to be a period is not 720 unit operating hours, recertification period. valuable maintenance tool, should be but is equal to the number of hours In proposed § 75.20(b)(3), specific allowed following the probationary remaining in the original recertification rules were provided for data validation calibration error test, and, provided that test period at the time of test failure; and during the recertification test period. the results of the trial runs are (2) data invalidation is prospective, The recertification test period would acceptable, the recertification should be beginning with the hour of failure of the begin with the first successful allowed to proceed (see Docket A–97– RATA at the particular load level; calibration error test (known as a 35, Item IV–G–3). Another commenter therefore, conditionally valid data ‘‘probationary calibration error test’’) requested that the proposal be revised to recorded prior to the test failure at the after making the change to the CEMS allow a single challenge with each of the particular load level are not invalidated. and completing all necessary post- three gases prior to a linearity test and Finally, in response to the comments change adjustments (e.g., to allow up to five preliminary trial runs received, a new paragraph, (b)(3)(vii)(E), reprogramming or linearization) of the prior to a RATA (see Docket A–97–35, has been added to § 75.20 to address the CEMS. The post-change activities could Item IV–G–5). issue of trial RATA runs and pre-test gas include preliminary tests such as trial Today’s rule finalizes the proposed injections. Section 75.20(b)(3)(vii)(E) RATA runs or a challenge of the data validation procedures in allows pre-test trial gas injections and monitor with calibration gases. Data § 75.20(b)(3) for monitor certification pre-RATA runs to be done during the from the CEMS would be considered and recertification, with the following recertification period, for the purpose of invalid from the hour in which the modifications in response to the optimizing the performance of the replacement, modification, or change to comments. First, an introductory monitoring system. A trial run or the system is commenced until the hour statement of applicability has been injection will not affect the status of of completion of the probationary added at the beginning of § 75.20(b)(3), previously-recorded conditionally valid calibration error test, at which point the clearly indicating that the provisions of data, provided that: (1) the results of the data status would become the section apply both to recertifications trial run are within the Appendix A ‘‘conditionally valid.’’ and to initial certifications. The specifications for a passed linearity test The conditionally valid status of the statement of applicability also allows or RATA (i.e., for a trial gas injection, CEMS data would continue throughout the data validation procedures to be within ±5% or 5 ppm of the reference the recertification test period, provided applied, at the discretion of the owner gas or, for a trial RATA run, if the that the required recertification tests or operator, to the routine quality average reference method and the were done ‘‘hands-off’’ (i.e., with no assurance linearity tests and RATAs average CEMS readings differ by no adjustments, such as reprogramming or required under Appendix B of part 75 more than ±10% of the reference linearization of the CEMS, other than (see the section on ‘‘Data Validation for method value, or ±15 ppm, or ±0.02 the calibration adjustments allowed RATAs and Linearity Checks’’ in this lb/mmBtu, or ±1.5% H2O, as under proposed section 2.1.3 of preamble, for a further discussion of this applicable); (2) no adjustments are made

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00013 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28576 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations to the calibration of the CEMS following section 2.1.3 of Appendix B would have proposed sections 2.2.3 and 2.3.2 of the trial run, other than the adjustments to be reported. However, tests which are Appendix B which allow ‘‘non-routine’’ allowed under section 2.1.3 of aborted or invalidated due to problems adjustments to be made prior to Appendix B; and (3) the CEMS is not with the calibration gases or reference linearity tests and RATAs. The repaired, re-linearized, or method or due to operational problems commenter especially objected to the reprogrammed after the trial run. As with the affected unit(s) would not need idea of allowing adjustments in a long as these conditions continue to be to be reported, because such runs do not direction away from the reference gas met, the CEMS can be further optimized affect the validation status of emission tag value, believing that this without data loss. However, if, for any data recorded by the CEMS. In addition, compromises the integrity of the audit trial run or injection the conditions are aborted RATA attempts which are part and sets an ‘‘unfortunate precedent’’ not met, the trial run or injection is of the process of optimizing a (see Docket A–97–35, Item IV–D–11). treated as a failed or aborted linearity monitoring system’s performance would Today’s rule finalizes the data check or RATA and the applicable not have to be reported, provided that validation provisions for linearity provisions in §§ 75.20(b)(3)(vii)(A) and in the period from the end of the checks and RATAs in sections 2.2.3 and 75.20(b)(3)(vii)(B) pertaining to aborted aborted test to the commencement of the 2.3.2 of Appendix B. Based on the or failed recertification tests must be next RATA attempt: (1) no corrective comments received, EPA has made followed. maintenance or re-linearization of the substantive revisions to the proposed CEMS was performed, and (2) no rule in an attempt to clarify the 2. Data Validation for RATAs and adjustments other than the calibration allowable pre-test adjustments and the Linearity Checks adjustments allowed under proposed rules for validating the CEMS data. Background: EPA proposed rules for section 2.1.3 of Appendix B were made. Today’s rule specifies that when a CEMS data validation prior to and However, such aborted RATA runs linearity check or RATA is due, the during the periodic linearity tests and would still have to be documented and owner or operator has three options. RATAs required by part 75. These new kept on-site as part of the official test First, the test may be done ‘‘cold,’’ with provisions were found in proposed log. no pre-test adjustments of any kind. sections 2.2.3 and 2.3.2 of Appendix B. Today’s rule finalizes the CEMS data Second, the test may be done after According to these provisions, a validation requirements for RATAs and making only the routine or non-routine linearity test or RATA could not be linearity checks. The final rule has been calibration adjustments allowed under started if the CEMS were operating ‘‘out- modified from the proposal, based on section 2.1.3 of Appendix B. Under this of-control’’ with respect to any of its comments received. second option, trial gas injections and other daily, semiannual, or annual Discussion: EPA received comments preliminary RATA runs are allowed, quality assurance tests. Prior to the test, on the proposed data validation followed by additional adjustments (if both routine and non-routine calibration procedures for RATAs and linearity necessary) within the limits of section adjustments, as defined in proposed checks from one state air regulatory 2.1.3 of Appendix B, to optimize the section 2.1.3 of Appendix B, would be agency, two utilities and one utility monitor’s performance. The trial runs or permitted. During the linearity or RATA regulatory response group. Two of the injections need not be reported, test period, however, no adjustment of commenters found the proposed rule provided that they meet the acceptance the monitor would be permitted except language defining the allowable pre-test criteria for trial RATA runs and gas for routine daily calibration adjustments adjustments to be inconsistent with the injections in § 75.20(b)(3)(vii)(E) (see the following successful daily calibration preamble language found at 63 FR section of this preamble entitled ‘‘Data error tests. For 2-level and 3-level flow 28075. The commenters noted an Validation During Monitor Certification RATAs, no linearization of the monitor apparent contradiction between the and Recertification’’ for further would be permitted between load levels. preamble statement that there is ‘‘no discussion of these acceptance criteria). If a linearity check or RATA was failed significant risk in allowing pre-RATA If the acceptance criteria are not met, or aborted due to a problem with the adjustments provided that the monitor’s the trial run is counted as a failed or monitor, the monitor would be declared accuracy between successive RATAs aborted test. Third, the CEMS may be out-of-control as of the hour in which can be reasonably established’’ and the repaired, re-linearized or reprogrammed the test is failed or aborted. Data from rule language in section 6.5(a)(1) of prior to the quality assurance test. In the monitor would remain invalid until Appendix A that ‘‘no adjustments, this case, the CEMS may either be the hour of completion of a subsequent linearizations or reprogramming of the considered out-of-control from the hour successful test of the same type. CEMS other than the calibration of commencement of the corrective The proposed rule also attempted to adjustments described in section 2.1.3 maintenance, re-linearization or clarify the way in which linearity and of Appendix B to this part, are reprogramming until completion of the RATA test results are to be reported to permitted prior to and during the RATA required quality assurance test or the EPA in the electronic quarterly report test period.’’ Both commenters owner or operator may follow the data required under § 75.64. Proposed expressed concern that this proposed validation procedures in § 75.20(b)(3) sections 2.2.3 and 2.3.2 of Appendix B rule language appeared to exclude upon completion of the necessary specified that only the results of important activities such as re- corrective maintenance, re-linearization, completed and partial tests which affect linearization of a flow monitor (see or reprogramming. data validation would have to be Docket A–97–35, Items IV–D–20, IV–G– EPA believes that the revisions to reported. That is, all completed passed 2). Another commenter also objected to sections 2.2.3 and 2.3.2 of Appendix B tests, all completed failed tests, and all the proposed language in section address the commenters’ concerns about tests aborted due to a problem with the 6.5(a)(1) of Appendix A, stating that pre-test adjustments. For example, if, at CEMS would have to be included in the technicians need to be able to perform the time of a scheduled flow RATA, the quarterly report. Therefore, aborted test evaluations and adjustments of flow and owner or operator decides to re-linearize attempts followed by corrective gas measurement systems prior to the primary flow monitor to optimize its maintenance, re-linearization of the conducting a RATA (see Docket A–97– performance, this would be permissible monitor, or any other adjustments other 35, Item IV–G–3). Another commenter under the third option above. However, than those allowed under proposed took issue with the provisions in re-linearization of a flow monitor

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00014 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28577 triggers a requirement to perform a 3- compromises the integrity of the audits the Agency stated, ‘‘the definition of load RATA. Therefore, if the monitor is or sets a bad precedent. On the contrary, ‘‘natural gas’’ does not, therefore, declared out-of-control from the hour of it demonstrates that the monitor include landfill gas, digester gas, the re-linearization until the hour of continues to perform in a comparable biomass, or gasified coal’’ (58 FR 3590 completion of the 3-load RATA (as manner to its performance at the time of and 3596). The Agency further stated in would be required by the proposed initial certification. When the monitor is the preamble that, ‘‘essentially sulfur- rule), this could result in significant held to the calibration error free fuels such as natural gas, landfill data loss, since a 3-load RATA can take specification required for initial methane, or synthetic propane’’ should days (or even weeks) to complete, certification, the monitor is shown to be qualify for the use of Appendix D depending on electrical demand. For capable of passing a linearity test or methodologies. The intent of the Agency this reason, today’s rule allows the RATA. in that rulemaking was to allow the use of a default emission rate for SO2 mass owner or operator to use the H. Appendix D—Sulfur Dioxide emissions calculations for natural gas recertification data validation Emissions From the Combustion of and other fuels which have a similar procedures in § 75.20(b)(3) to Gaseous Fuels supplement the quality assurance low sulfur content, but not for fuels provisions in Appendix B. In this Background: EPA proposed several which have higher sulfur content than example, if the owner or operator opts revisions to the procedures in Appendix natural gas. Appendix D did not to use the data validation procedures in D of part 75 for determining sulfur effectively address how to determine § 75.20(b)(3), data from the flow monitor dioxide emissions from gas-fired and SO2 mass emissions for gaseous fuels would be considered conditionally valid oil-fired units. Most of the proposed other than natural gas. upon completion of a ‘‘probationary revisions would provide affected On May 17, 1995 the Agency revised calibration error test,’’ following the re- utilities with additional flexibility and the core Acid Rain rules to add a new linearization of the monitor. The sampling options. These changes were definition for ‘‘pipeline natural gas,’’ procedures in § 75.20(b)(3)(vii)(E) allow generally supported by the comments and revised the definitions of ‘‘natural for trial runs and further optimization of received and have either been finalized gas’’ and ‘‘gas-fired.’’ The most the monitor prior to the RATA. If the 3- as proposed or with minor revisions and significant change in the definition of level flow RATA is then passed in clarifications. However, for gaseous ‘‘natural gas’’ was the addition of the accordance with the procedures of fuels, EPA received a number of requirement that ‘‘natural gas’’ must significant comments concerning the § 75.20(b)(3) and within the allotted contain ‘‘one grain or less hydrogen proposed changes to the definition of time frame (indicating that the re- sulfide per 100 standard cubic feet and the term ‘‘pipeline natural gas’’ under linearization was successful), the 20 grains or less total sulfur per 100 § 72.2 and received other comments conditionally valid data will become standard cubic feet.’’ The intent of this which have prompted the Agency to re- quality assured and may be used for additional language was to clarify which evaluate the applicability and use of reporting. gaseous fuels qualified as ‘‘natural gas.’’ Appendix D. In response to the The criteria used (1 grain hydrogen For the following reasons, EPA does significant comments received, the sulfide (H2S) and 20 grains total sulfur) not agree with the commenter who Agency is adopting the following final were based on contracts and tariff sheets opposed allowing ‘‘non-routine’’ revisions to Appendix D and to § 72.2: for pipeline natural gas regulated by the calibration adjustments prior to a (1) Revised definitions of ‘‘pipeline Federal Energy Regulatory Commission quality assurance test. The ‘‘non- natural gas,’’ ‘‘natural gas’’ and ‘‘gas- (FERC). Consistent with this approach, routine’’ adjustments described in fired’’ have been promulgated in § 72.2; the Agency defined ‘‘pipeline natural section 2.1.3 of Appendix B allow (2) The applicability of Appendix D gas’’ as natural gas provided by a adjustments only within the has been expanded to include gaseous supplier through a pipeline. In addition, performance specifications of the fuels with any sulfur content the Agency modified the definition of instrument. When a monitor is initially (previously, Appendix D had been ‘‘gas-fired’’ to make it clear that the use certified, it must pass several quality limited to gaseous fuels with a sulfur of Appendix D was limited to units assurance tests, one of which is a 7-day content of 20 grains per 100 scf, or less); combusting ‘‘fuel oil,’’ ‘‘natural gas,’’ calibration error test. The monitor must and and ‘‘gaseous fuels containing no more demonstrate, for 7 consecutive operating (3) The methodology for determining sulfur than natural gas.’’ The default days, that it is capable of meeting a the frequency of fuel gross calorific SO2 emission rate of 0.0006 lb/mmBtu ± calibration error specification of 2.5 value (GCV) under section 2.3 of could only be used for the combustion percent of the instrument span (±3.0 Appendix D has been modified. of either natural gas or a fuel with a percent for flow monitors). Once a In order to put today’s revisions in sulfur content no greater than natural monitor has been certified, the ‘‘control context, it is necessary to review how gas. To use the default SO2 emission limits’’ for daily calibration error tests of the Agency addressed these issues in rate, the owner or operator was required the monitor are twice the performance previous rulemakings. Section 2.4 of to demonstrate that the fuel being specification value, i.e., ±5.0 percent of Appendix D of the core rules of the Acid combusted qualified as natural gas, span for gas monitors and ±6.0 percent Rain Program issued on January 11, based on contract or tariff values which for flow monitors. Thus, when the ‘‘non- 1993, allowed units combusting indicate that the gas meets the criteria routine’’ adjustments described under ‘‘natural gas’’ (as defined in § 72.2) to for natural gas H2S content and total section 2.1.3 of Appendix B are made calculate SO2 mass emissions through sulfur content. prior to a linearity test or RATA, the either: (1) fuel sulfur sampling and As noted in the preamble of the monitor is actually being held to a measurement of the fuel flow rate by a proposed rule, the May 12, 1995 tighter specification than is used for certified fuel flowmeter; or (2) the use revisions apparently did not eliminate daily operation. The Agency therefore of a default SO2 emission rate of 0.0006 confusion concerning the use of the does not agree that keeping the lb/mmBtu and heat input determined default SO2 emission rate. The SO2 instrument’s calibration within the using a certified fuel flowmeter and default emission rate of 0.0006 lb/ performance specification ‘‘band’’ at the monthly analysis for fuel GCV. In the mmBtu is equivalent to approximately time of linearity tests or RATAs preamble to the January 11, 1993 rule, 0.2 grains hydrogen sulfide per 100

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00015 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28578 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations standard cubic feet (scf) of gas, when part 75 to ensure consistency within the affected units reporting gas as the hydrogen sulfide is the sole source of rule. primary fuel. The data analysis (which total sulfur in the gas (as is the case for Two commenters were opposed to the was limited to 1997 emission data) refined natural gas), or 0.2 grains total change to the definition of pipeline indicates the following: (1) there are 582 sulfur per 100 scf of gas. The Agency natural gas (see Docket A–97–35, Items units that list gas as the primary fuel did not intend that fuels with average IV–D–23 and IV–D–24). Both (representing about 30% of the units in sulfur content much higher than 0.2 commenters suggested that the the program); (2) these 582 units grains per 100 scf should be allowed to requirement to document that a gaseous accounted for approximately 10% of the ≤ use the default value. In this context, fuel has 0.3 gr/100 scf of H2S, as total heat input reported for all Acid the current definition of ‘‘natural gas’’ opposed to the previous requirement to Rain-affected units; (3) the total amount ≤ under § 72.2, which includes the term document an H2S content 1.0 gr/100 of SO2 emitted by these 582 units was ‘‘20 grains of total sulfur,’’ is somewhat scf, would either disqualify some 14,728 tons in 1997 or 0.1% of the total confusing. Further, use of the 0.0006 lb/ sources currently using the default SO2 mass emissions in the program; and mmBtu default emission rate for emission rate of 0.0006 lb/mmBtu or (4) of the 14,728 tons of SO2 emitted by ‘‘natural gas’’ with one grain of H2S per force those sources to use means other the 582 units, 12,844 tons were from 100 scf would result in an than the contract or tariff provisions to only 17 units and the remaining 1,884 approximately five-fold underestimation demonstrate that the hydrogen sulfide tons were from the remaining 565 units of SO2 emissions. Therefore, in the content of the gas is less than 0.3 gr./100 (see Docket A–97–35, Item IV–A–4). proposed rule, the Agency modified the scf. Under the proposed Appendix D Thus it appears that gas-fired units definition of pipeline natural gas to revisions, any sources disqualified from account for a significant portion of the include only natural gas with a the use of the default SO2 emission rate total heat input and electrical generation hydrogen sulfide content less than or would either be required to begin daily under the Acid Rain Program, but equal to 0.3 grains hydrogen sulfide per gas sampling of the fuel sulfur content contribute only a fraction of one percent or would have to install an SO2 CEMS. 100 scf, thereby clarifying that the of the total SO2 emissions. Note, default emission rate of 0.0006 lb/ Two other commenters suggested that however, that even though emissions mmBtu could only be used for natural the use of two sulfur content criteria in from the individual gas-fired units are gas with an appropriately low hydrogen the natural gas definition (the dual very small, the cumulative emissions sulfide content. criteria of 1 grain H2S and 20 grains from all 582 units are roughly total sulfur per 100 scf) was confusing The proposed rule required equivalent to the typical SO2 emissions and could lead to misinterpretation of documentation of the hydrogen sulfide from a coal-fired unit. For this reason, which fuels could be classified as either content of the natural gas either through the method of calculating the SO2 ‘‘pipeline natural gas’’ or ‘‘natural gas’’ emissions from the gas-fired units must quality characteristics specified by a under § 72.2 (see Docket A–97–35, Items be sufficiently accurate to prevent purchase contract or pipeline IV–G–3 and IV–G–10). One of these significant underestimation of transportation contract, through commenters suggested that the emissions. The methodology in the certification of the gas vendor, based on definition of natural gas should be current rule allows the default SO routine vendor sampling and analysis, changed to incorporate only the 2 emission rate of 0.0006 lb/mmBtu to be or through at least one year’s worth of requirement of 20 grains or less of total used for all types of natural gas. As analytical data on the fuel hydrogen sulfur per 100 scf. If this suggestion previously noted, the default emission sulfide content from samples taken at were followed, a source with 20 grains least monthly, demonstrating that all rate corresponds to 0.2 grains of H2S per total sulfur per 100 scf could use an SO2 100 scf, but the definition of natural gas samples contain 0.3 grains or less of emission rate of 0.0006 lb/mmBtu, hydrogen sulfide per 100 standard cubic allows fuels with up to 1.0 grain of H2S thereby underestimating SO2 emissions and 20 grains of total sulfur to be feet. For a fuel to be classified as 100-fold. This would clearly be classified as ‘‘natural gas.’’ In view of ‘‘pipeline natural gas’’ the fuel would, of unacceptable and contrary to the this, it is possible that the reported course, first have to meet the current Agency’s intent since the initial cumulative SO2 emissions reported in definition of ‘‘natural gas’’ in § 72.2, adoption of Appendix D. which states, ‘‘Natural gas means a One commenter suggested that the 1997 for the 582 gas-fired units may be naturally occurring fluid mixture of requirement to determine the fuel GCV inaccurate by several orders of hydrocarbons (e.g., methane, ethane, or on the same frequency as sulfur magnitude. This level of uncertainty in propane) containing 1 grain or less sampling be removed from Appendix D reported emissions is unacceptable in hydrogen sulfide per 100 standard cubic and that monthly GCV sampling be an allowance trading program such as feet, and 20 grains or less total sulfur allowed in all cases (see Docket A–97– the Acid Rain Program. Consequently, a per 100 standard cubic feet), produced 35, Item IV–D–20). The commenter more representative method is needed in geological formations beneath the claimed that the variability of fuel GCV to characterize the actual sulfur content Earth’s surface, and maintaining a is not necessarily the same as the of the gaseous fuels combusted by Acid gaseous state at standard atmospheric variability of the sulfur content of a fuel. Rain-affected units. temperature and pressure under The Agency also performed an ordinary conditions.’’ 1. Summary of EPA Analysis of analysis of all available gaseous fuel Discussion: Several comments were Appendix D Gaseous Fuel SO2 and Heat GCV sampling data from all Acid Rain received on the proposed changes to the Input Methodologies sources reporting such data in 1997. definition of ‘‘pipeline natural gas,’’ and In responding to the comments Gaseous fuels were analyzed in two comments were also received on the received, the Agency first attempted to categories, pipeline natural gas and current definition of ‘‘natural gas.’’ In quantify the SO2 emissions from the ‘‘other’’ gas. Only 14 Acid Rain sources responding to the comments, the combustion of gaseous fuels under the reported sampling and analysis of Agency is revising both the definition of current Acid Rain rules. A data analysis ‘‘other’’ gases in 1997. The data analysis ‘‘pipeline natural gas’’ and ‘‘natural was performed, assuming that the vast showed that for 275,669 pipeline gas,’’ as well as making various majority of SO2 emissions from the natural gas analyses, the average fuel corresponding changes to wording in combustion of gaseous fuel are from GCV was 1023 Btu/ft3 and the 95th

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28579 percentile value was 1051 Btu/ft3, a monitoring criteria for all types of general, any ‘‘natural gas’’ with ≤1.0 difference of only 2.6%. For the ‘‘other’’ gaseous fuels under Appendix D. Clear, grain of H2S/100 scf will also meet the gaseous fuels, the average GCV from flexible and reasonable requirements for requirement that hydrogen sulfide must 14,282 analyses was 819 Btu/ft3 and the gaseous fuel GCV sampling and analysis account for ≥50% of the total sulfur in 95th percentile value was 1118 Btu/ft3, are needed. the fuel. However, the Agency reserves a difference of approximately 26%. This Based on the comments received and the right to request that the owner or demonstrates the consistency of the the data analyses described above, the operator provide data to demonstrate GCV of pipeline natural gas and the Agency has concluded that: compliance with this latter requirement. Finally, EPA is adding a requirement to high variability of the few ‘‘other’’ • The use of the default SO2 emission rate gaseous fuels for which Appendix D is of 0.0006 lb/mmBtu is only appropriate for the ‘‘natural gas’’ definition that the gas currently being used (see Docket A–97– natural gas with a documented contractual or must have either a methane content of 35, Item IV–-A–1). tariff limit of 0.3 grains hydrogen sulfide per at least 70% or the same GCV as In finalizing today’s rule, the Agency hundred standard cubic feet or for fuels methane (950 to 1100 Btu/scf). This which are demonstrated to have a similar low requirement ensures that the gas will also considered the potential impact of total sulfur content. the revisions to Appendix D on the new • have a stable GCV, consistent with the For natural gas with a contract or tariff Appendix D provisions which allow Subpart H of part 75 (which establishes hydrogen sulfide limit up to 1.0 grain of monthly GCV sampling for either the requirements for monitoring of NOX hydrogen sulfide per 100 standard cubic feet, mass emissions). Currently, the or for fuels which are demonstrated to have pipeline natural gas or natural gas. In provisions of Subpart H are being used a similar low total sulfur content, a site- today’s rule, the requirements for by the Ozone Transport Commission specific default SO2 emission rate should be documenting that a fuel qualifies as allowed, which more closely represents the ‘‘pipeline natural gas’’ or ‘‘natural gas’’ (OTC) NOX Budget Program and, in the potential SO2 emission rate for that fuel. are essentially the same as the proposed future, Subpart H may be adopted as • The applicability of Appendix D should part of an implementation plan as a rule. The three principal ways of be expanded to include any gaseous fuel providing the necessary documentation means of complying with the NOX SIP (rather than limiting it to fuels with a total are: (1) gas quality characteristics Call (see 63 FR 57356). Subpart H of sulfur content ≤ 20 grains per 100 scf. For part 75 allows heat input determined by gaseous fuels with highly variable sulfur specified in a purchase contract or pipeline transportation contract; (2) the procedures of Appendix D to be content, hourly sampling using advanced monitoring such as on-line gas certification by the gas vendor, based on used in determining NOX mass routine sampling and analysis for at emissions from gas-fired units. In the chromatography should be required. The frequency of determination of the GCV of a least one year; and (3) at least one year process of implementing part 75 and the gaseous fuel should be independent of the of analytical data on the fuel OTC NOX Budget Program, the Agency requirements for sulfur sampling and should characteristics, derived from monthly has encountered an increasing number be based solely on the variability of the GCV. (or more frequent) samples. In addition, of sources that combust gaseous fuels sections 2.3.5 and 2.3.6 of Appendix D which neither qualify as ‘‘pipeline 2. Changes to the Definitions of of today’s rule allow the owner or natural gas’’ or ‘‘natural gas.’’ These ‘‘Pipeline Natural Gas’’ and ‘‘Natural Gas’’ operator to conduct a 720 hour fuels include refinery gas, landfill gas, demonstration of the fuel’s sulfur and digester gas, coke oven gas, process gas, As previously stated, the Agency is GCV characteristics (see Items 5 and 6 propane liquified gas, liquified revising the definitions of ‘‘pipeline in this section, below). petroleum gas, blast furnace gas and natural gas’’ and ‘‘natural gas’’ in § 72.2. EPA believes that the revised coal-derived gas. Under the previous Since the definition of ‘‘pipeline natural definitions of ‘‘pipeline natural gas’’ and version of part 75 units combusting gas’’ necessarily includes the definition ‘‘natural gas’’ will: (1) apply to the low these fuels would either be required to of ‘‘natural gas’’, and the definitions sulfur fuel combusted by the vast install SO2 and stack flow monitoring therefore involve similar issues, EPA is majority of the sources in the Acid Rain systems or would have to petition the addressing both definitions in today’s Program; (2) be documentable, in most Agency to use Appendix D. It is likely final rule. In particular, ‘‘pipeline cases, based on contract or tariff that under the OTC NOX Budget natural gas’’ is defined in such a way provisions without other types of Program and under the SIP call, the that only fuels with the appropriate demonstrations; and (3) allow most number of sources combusting these sulfur content can meet the definition sources currently using 0.0006 lb/ ‘‘other’’ gaseous fuels and required to and can use the default emission rate of mmBtu as a default to continue using monitor heat input using part 75 0.0006 lb/mmBtu. Under the revised that default value or to use an methods will increase significantly. The definition, pipeline natural gas must alternative, site-specific default value Agency anticipates that the owners or contain less than 0.3 grains of hydrogen that will not underestimate SO2 operators of the majority of these sulfide per 100 scf. Consistent with this emissions. sources would petition to use the approach, the definition of ‘‘natural gas’’ procedures of Appendix D to determine is revised so that only the requirement 3. Changes to the Methodology for Calculating SO2 Emissions Under heat input used for NOX mass for the hydrogen sulfide content to be calculations, in lieu of installing CEMS. less than one grain per 100 scf remains, Appendix D However, the current Appendix D does and the requirement for the total sulfur Today’s rule adopts a two-tiered not address how to determine hourly content to be ≤20 grains per 100 scf is approach to the use of default SO2 heat input for gaseous fuels with deleted. Further, EPA is adding to both emission rates, depending on whether a variable GCV. The Agency also notes definitions a requirement that hydrogen fuel qualifies as ‘‘pipeline natural gas’’ that any error in hourly heat input sulfide content must account for at least or as ‘‘natural gas.’’ First, if the owner determined under Appendix D would 50% (by weight) of the total sulfur in or operator can demonstrate that the result in a corresponding and equal the fuel. This ensures that a fuel with a fuel combusted at a unit has ≤0.3 grains error in the reported NOX mass high total sulfur content, but a relatively of hydrogen sulfide per 100 scf, the emissions. It is therefore particularly small hydrogen sulfide content, cannot default SO2 emission rate of 0.0006 lb/ important to establish consistent and qualify to use a default SO2 emission mmBtu may be used. Second, the rule easily implementable heat input rate. The Agency believes that in allows units combusting gaseous fuels

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28580 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations with >0.3 grains, but ≤1.0 grain of hourly hydrogen sulfide concentration fuel gas combustion units) the 720 hour hydrogen sulfide per 100 scf to calculate recorded during the 720 hour demonstration period must also include a site-specific default SO2 emission rate, demonstration. After a fuel qualifies as data which characterizes the variability as suggested by two of the commenters ‘‘natural gas,’’ the owner or operator is of the fuel during the seasonal or (see Docket A–97–35, Items IV–D–23 required to sample the H2S content at process changes. The results of the 720 and IV–D–24). The method of least once monthly for a year following hour demonstration will be used to calculating the default value is based on the 720 hour demonstration. The default determine the average heat content of the actual conversion of hydrogen emission rate for the demonstration may the fuel and the standard deviation. As sulfide in natural gas to SO2 and utilizes continue to be used, provided that none explained in section 2.3.5 of Appendix a realistic fuel GCV value of 1023 Btu/ of the samples taken during the year D in today’s rule, depending on the scf (from the previously-discussed data exceeds 1.0 grain/100 scf of H2S. All results of the demonstration, the owner analysis, above). The result is a simple ‘‘other’’ gaseous fuels would require or operator will perform either daily or equation which converts hydrogen either daily or hourly sampling of the hourly sampling of the fuel GCV. sulfide in natural gas to an SO2 emission total sulfur content, depending on the I. Electronic Transfer of Quarterly rate in lb/mmBtu. fuel sulfur variability. Reports 4. Changes to the Applicability of 6. Changes to the Method of Background: For the reasons Appendix D Determining the GCV Sampling discussed in the preamble to the In the process of considering Frequency for Gaseous Fuels proposed rule revisions (63 FR 57356, comment on the definitions of ‘‘pipeline Accurate determinations of heat input May 21, 1998), EPA proposed changes natural gas’’ and ‘‘natural gas’’ the are important for the calculation of SO2, to § 75.64(f) concerning the method of Agency also re-evaluated the NOX and CO2 mass emissions under submitting quarterly reports. The appropriateness of limiting the Appendices D, E, G and Subpart H of proposal provided that all quarterly applicability of Appendix D to gaseous part 75. EPA has found that fuels such reports would have to be submitted to fuels with ≤20 grains of total sulfur per as refinery gas, digester gas, landfill gas, EPA by direct computer-to-computer 100 scf. While EPA does not believe that coke oven gas, process gas, propane electronic transfer via modem and EPA- a gaseous fuel with 20 or more grains of liquified gas, liquified petroleum gas, provided software, unless otherwise total sulfur per 100 scf should be blast furnace gas, and coal derived gas approved by the Administrator. This allowed to use a default SO2 emission can have highly variable GCV (see requirement was to begin with the rate, neither does the Agency believe Docket A–97–35, Item IV–A–4). For quarterly report for the first quarter of that units combusting such fuel should these fuels a standardized test for the year 2000. be excluded from using Appendix D. determining the appropriate GCV Discussion: EPA received one Currently, technologies such as on-line sampling and analysis frequency is comment (see Docket A–97–35, Item IV– gas chromatography allow accurate fuel essential. One commenter on the D–20) which opposed the proposed sulfur analysis to be performed over proposed rule noted that in many cases requirement based on difficulty in intervals as short as one hour. This the GCV of a fuel is relatively stable receiving electronic transfer of quarterly ability to perform hourly sampling is over a period of time, and sampling reports due to technical difficulties with comparable to a CEMS in accuracy, each month for fuel heat content is EPA computers which may arise due to precision and timeliness. Therefore, adequate (see Docket A–97–35, Item IV– year 2000 conversion difficulties or today’s rule removes the 20 grains of D–20). The Agency agrees that this is other technical problems relative to sulfur per 100 scf restriction on the use true in many cases (e.g., for natural gas), electronic transfer of quarterly reports at of Appendix D for gaseous fuels. but not often for the fuels listed above. times when EPA computers may not be The Agency also notes that the 5. Changes to the Method of accessible. Concern was expressed emissions data determined under Determining the Sulfur Content regarding the requirement for utilities to Appendix D must be as reliable, precise, Sampling Frequency for Gaseous Fuels provide proof that they attempted to timely and accessible as data from a transfer their reports on time but were Section 2.3.6 of Appendix D of CEMS. unsuccessful due to the inability to gain today’s rule also includes a general In view of this, the Agency is revising access to the EPA computer system. procedure for determining the the criteria for determining the Based on the comment received, EPA appropriate frequency of sulfur content frequency of GCV sampling for gaseous has decided to change the electronic sampling for any gaseous fuel which is fuels. For any fuel which meets the reporting requirement in § 75.64(f) so transmitted by a pipeline. The revised definition of either ‘‘pipeline that beginning with the quarterly report procedure consists of a 720 hour natural gas’’ or ‘‘natural gas,’’ this for the first quarter of the year 2001, all demonstration, similar to the one in ensures that the fuel will have a stable quarterly reports must be submitted to section 2.3.3.4 of Appendix D in the heat content and therefore monthly EPA by direct computer-to-computer proposed rule. The results of the 720 sampling is appropriate. For fuels which electronic transfer via modem and EPA- hour demonstration may first be used to do not qualify as either pipeline natural provided software, unless otherwise determine first if a fuel qualifies as gas or natural gas and for which ‘‘as- approved by the Administrator. This either ‘‘pipeline natural gas’’ or ‘‘natural delivered’’ fuel sampling and analysis is will ensure adequate time for all parties gas’’ or as ‘‘other’’ gaseous fuel, and not performed, the same 720 hour to address the year 2000 concerns. EPA then to determine the appropriate total demonstration described in item 5 in notes that its system has already sulfur sampling frequency for the fuel. this section, above, for fuel sulfur undergone testing and changes to If a fuel qualifies as pipeline natural gas, sampling will also be used to determine accommodate year 2000 concerns. the default SO2 emission rate of 0.0006 the appropriate GCV sampling and lb/mmBtu could be used in lieu of fuel analysis frequency. The heat content of J. Bias, Relative Accuracy and sampling. If the fuel qualifies as the fuel will be determined for each Availability Determinations ‘‘natural gas’’ (but not pipeline natural hour in the 720 hour period. For units Background: The preamble to the gas), a site-specific default SO2 emission that switch fuels seasonally or when proposed rule described the findings of rate may be used, based on the highest process changes occur (such as refinery studies performed to evaluate the

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00018 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28581 provisions for the bias test, relative and/or fuel oil. For these units, EPA basis. In such a petition, the designated accuracy, and monitor availability believes that the proposed method representative can reference the trigger conditions as required by §§ 75.7 would provide acceptably accurate information used to support the and 75.8. Issues concerning the bias measurements of volumetric flow. proposed Appendix I procedure (see 63 relative accuracy, and monitor However, adoption of the proposed FR 28113–28115, May 21, 1998, for availability provisions in the core Acid method would require the Agency to further details on the information used Rain rules had been raised in litigation develop regulations imposing additional to develop proposed Appendix I). The (Environmental Defense Fund v. Carol reporting and recordkeeping Agency will evaluate the petition on the M. Browner, No. 93–120; et al. D.C. Cir., requirements for those units that used merits at that time. 1993). The purpose of these studies was this option. This would also place a L. Subpart H—Clarifications to NO to address these issues (see 63 FR burden on software vendors to develop X Mass Monitoring Requirements 28197). The preamble of the proposed software to allow for electronic data rule explained how these findings led to reporting of the required data elements. Background: By notice of proposed the Agency’s proposed determinations Discussion: A few commenters stated rulemaking (NPR, proposal, or to retain the current rule provisions generally that they supported the ‘‘proposed SIP call’’) (62 FR 60318, concerning these matters. There were no Appendix I option, while two other November 7, 1997) and by supplemental comments objecting to the substance of commenters stated generally that the notice (SNPR or supplemental proposal) the proposed determinations. Therefore, method should be allowed for other (63 FR 25902, May 11, 1998), EPA for the reasons set forth in the preamble types of units or simplified (see Docket proposed to find that NOX emissions to the proposed rule, EPA is adopting A–97–56, Items IV–D–9, 23, and 24, and from sources in 22 states and the the proposed rule revisions as final, IV–G–2 and –8). However, utilities have District of Columbia, will significantly with the result that §§ 75.7 and 75.8 are submitted late comments that suggest contribute to nonattainment of the 1- removed and reserved. Moreover, since that the utilities (including those hour and 8-hour ozone National none of the issues raised concerning the originally interested in an F-factor/fuel Ambient Air Quality Standards bias, relative accuracy, and monitor flow method) are in fact unlikely to use (NAAQS), or will interfere with availability provisions in the core Acid the Appendix I option at this time (see maintenance of the 8-hour NAAQS, in Rain rules were raised in any comments Docket A–97–56, Item IV–G–13). Based one or more downwind states on the studies, EPA maintains that those on a review of Acid Rain program throughout the eastern United States. litigation issues have been resolved. databases, only about 150 units affected In October, 1998 (63 FR 57356, Discussion: Two comments were by the Acid Rain Program could October 27, 1998), EPA finalized the received. One (see Docket A–97–56, potentially take advantage of this proposed SIP call rulemaking. The final Item IV–D–01) supported the proposed option. In contrast, there are a rule specified dates by which: (1) the determinations. The second comment significant number of units that affected states must submit State (see Docket A–97–56, Item IV–D–02) implement the other generally available Implementation Plan revisions to reduce expressed concern that the bias test excepted methods under Appendices D NOX emissions to eliminate the amounts studies performed in response to § 75.7 and E to Part 75 (currently, of NOX emissions that contribute did not evaluate overestimation in flow approximately 540 different units report significantly to nonattainment, or that measurements. The commenter urged using one or both of these methods). interfere with maintenance, downwind; EPA to complete its ongoing work as As discussed above there would be and (2) the affected sources must quickly as possible on a separate substantial effort involved for EPA, implement the measures chosen by the rulemaking to resolve the commenter’s utilities and software vendors to states to achieve the required NOX flow overestimation concerns. The implement a new generally available emission reductions. Agency is pursuing the separate option such as proposed Appendix I. As The provisions of the October 27, rulemaking recommended by the discussed in the preamble to the 1998 final rule allow each state to commenter. proposed rule, the annual savings on a determine the best way to achieve the per unit basis for Appendix I units are necessary NOX emission reductions. K. Appendix I—Proposed Optional at most $10–15,000 over the Consistent with the Ozone Transport Stack Flow Monitoring Methodology measurement of volumetric flow Assessment Group’s recommendation to Background: EPA proposed to add an directly with a flow monitor. The actual achieve NOX emissions decreases F-factor/fuel flow method in Appendix cost savings would be less because other primarily from large stationary sources I to part 75 as an excepted method to provisions of today’s rule revise flow in a trading program, EPA promulgated measure volumetric flow directly with a monitor quality assurance requirements a model rule for the implementation of flow monitor. The Agency proposed this and significantly reduce the costs of such a trading program as 40 CFR part method based on information provided using a flow monitor. Given the 96 (‘‘Part 96’’) in the October 27, 1998 by affected utilities, and based on the relatively small amount of savings on a rulemaking. assumption that the new excepted per unit basis, the indication that no If the states should choose to create a method would be used by a significant units would use the option at this time, NOX mass trading program and to adopt number of units as a cost-effective and the significant burden on all the provisions of the Part 96 model rule, option to a volumetric flow monitor. interested parties in implementing a § 96.70 requires the monitoring and This method would allow fuel flow generally available option in Appendix reporting of NOX mass emissions to be measurement with a gas or oil I, the Agency has determined not to done in accordance with either: (1) flowmeter, fuel sampling data, CO2 (or adopt Appendix I. Subpart H of 40 CFR part 75, the Acid O2) CEMS data, and F-factors to However, if the owner or operator of Rain CEM Rule (‘‘Part 75’’); or (2) for determine the flow rate of the stack gas a unit decides at some time in the future qualifying low mass-emission units, rather than a volumetric flow monitor. to use this type of procedure for § 75.19 of Part 75. However, even if a The F-factor/fuel flow method would be measuring flow, the designated state should choose not to participate in available for use by oil-fired and gas- representative of the unit may petition such a trading program, the October 27, fired units, as defined under § 72.2, the Agency under § 75.66 to use this 1998 rule still requires the monitoring provided that they only burn natural gas type of procedure on a case-by-case provisions of Subpart H to be used by

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28582 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations a core group of sources (large industrial affect §§ 75.70(f)(1)(iv), 75.71(b) and must specify which QA tests are to be boilers and turbines, and large boilers 75.71(d)(2). The new paragraph is found performed. Section 75.74(c) therefore and turbines used for the generation of at § 75.70(g)(6). In addition to these lists the specific quality assurance tests electricity for sale) if the NOX mass minor corrections, EPA has found that that are required prior to the ozone emission reduction program for that certain provisions in § 75.74(c), season. For all CEM systems, a relative state includes requirements to control pertaining to sources that monitor and accuracy test audit (RATA) is required such sources. To support these NOX report data only in the ozone season, are and for all gas monitors, a linearity mass emission reduction programs and substantially inconsistent with sections check is also required. After a required rulemakings, EPA promulgated both of today’s final rule (particularly the linearity check or RATA is passed, Subpart H of Part 75 and the low mass new CEM data validation provisions). § 75.74(c) requires that daily calibration emission unit provisions in § 75.19 of The Agency has also found an instance error tests and (if applicable) flow Part 75 as part of the October 27, 1998 in which the text of § 75.74(c) is monitor interference checks begin to be rulemaking. internally inconsistent and a second performed. These daily assessments In the November 7, 1997 proposed SIP instance in which a statement in the must then continue to be performed Call rule, EPA would have required the October 27, 1998 preamble does not until the end of the ozone season. affected units in a Federal or state NOX agree with the regulatory language in Section 75.74(c)(5) of Subpart H, as mass emission reduction program to § 75.74(c). In view of these promulgated on October 27, 1998, report NOX emissions on a year-round considerations, today’s rulemaking requires both the recording and basis and also to quality assure the NOX revises § 75.74(c), in order to make reporting of hourly emission data prior emission data in accordance with the Subpart H more consistent with the rest to the current ozone season in the time provisions of Part 75 on a year-round of Part 75 and to resolve the apparent interval from the date and hour that basis. However, in response to discrepancies and inconsistencies in the ‘‘recertification’’ testing of the CEM comments on the proposed rule, EPA text of § 75.74(c). systems is completed through the end of modified Subpart H of Part 75 so that Discussion of Changes: As previously the ozone season. EPA believes that states could choose to allow sources that stated, Subpart H requires owners or most sources that choose this option were not subject to the requirements of operators of sources that monitor and would do the testing as close to the Title IV of the Clean Air Act (the Acid report only during the ozone season to ozone season as possible. However, Rain Program) to monitor and report recertify their CEM systems prior to there may be some instances in which either on a year round basis or on an ozone season only basis. Therefore, the each ozone season. EPA put this it would be difficult for a source to October 27, 1998 final rule provides for requirement in Subpart H because the perform all of the testing in the second Agency believes that for sources which quarter before the beginning of the the monitoring and reporting of NOX mass emissions either on an annual are not required to monitor and report ozone season. This means that some basis or during the ozone season, when on a year-round basis, substantial sources for which the NOX emission this is allowed by the governing state or quality assurance testing of the CEMS data count for compliance only during Federal rule. prior to the ozone season is essential to the ozone season would be required to validate the emission data at the submit additional electronic quarterly If a state or Federal NOX mass emission reduction program were to beginning of the ozone season. reports outside the ozone season, if they allow ‘‘ozone season only’’ monitoring However, in the light of today’s completed the pre-ozone season testing and reporting, there would be an issue rulemaking, the use of the word in the first or fourth calendar quarter. In related to data quality at the start of ‘‘recertification’’ in § 75.74(c) of Subpart view of this, EPA has reconsidered the each ozone season. To address this H is regarded as inaccurate and implications of this extra reporting issue, in the October 27, 1998 final rule, inappropriate and does not properly requirement and has concluded that it EPA included a provision in § 75.74(c) communicate the Agency’s intent. In will complicate program of Subpart H, which requires the § 75.20(b) of today’s final rule, the term implementation. The Agency believes continuous emission monitoring ‘‘recertification’’ has been carefully that this complication is unnecessary. systems used to provide the NOX mass defined, so that it is limited to major Therefore, in § 75.74(c)(6) of today’s emission data to be recertified prior to changes to a CEMS which may affect its final rule, the Subpart H reporting the start of each ozone season. ability to accurately measure emissions. provision for these sources has been Although Subpart H was proposed on Since in most instances sources will be revised, so that only reporting of May 21, 1998 as part of the Acid Rain testing existing CEMS that have not emission data in the ozone season, from CEM Rule revisions, it was finalized undergone major changes, EPA believes May 1 through September 30, is several months ahead of today’s that this is more consistent with either required. This means that in the time rulemaking, in order to support the SIP diagnostic testing or on-going quality period from the date and hour of call. In the preamble to the October 27, assurance testing rather than completion of the required pre-ozone 1998 final rule (63 FR 57467), EPA recertification. Therefore, in today’s season quality assurance testing of the explained its intention to, where final rule, all of the references in § 75.74 CEM systems through April 30 of the possible, make the provisions of Subpart to ‘‘recertification testing’’ of CEMS current year, the owner or operator is H consistent with any other changes prior to the ozone season have been only required to record and keep that EPA promulgated as a result of the replaced with terms such as ‘‘diagnostic records of the hourly emission data on- May 21, 1998 proposed revisions to Part testing’’ or ‘‘quality assurance testing,’’ site. The only pre-ozone season data 75. EPA has re-examined the provisions which properly convey the Agency’s that must be reported are the results of of Subpart H within the context of intent and de-couple this testing from daily calibration error checks and flow today’s final rulemaking. The Agency the formal administrative process monitor interference checks performed has found that a few minor clarifications associated with recertification events. in the time period from April 1 through of the regulatory language in Subpart H Since the required pre-ozone season April 30 and the results of any linearity and the addition of one new paragraph testing is considered to be quality checks, RATAs, fuel flow meter tests are needed for consistency with today’s assurance (QA) or diagnostic testing and fuel sampling performed outside of final rule. The textual clarifications rather than a recertification, the Agency the ozone season for purposes of

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28583 compliance with Subpart H. This will procedures in § 75.20 could be clarified season and which provisions are provide the regulatory agencies with to make the requirements easier to inapplicable. The Agency has replaced added assurance that the CEMS data are understand, particularly for sources that the general references in Subpart H to quality-assured at the start of the ozone report data only during the ozone the quality assurance provisions of season and will enable the agencies to season. There are several reasons for § 75.21 and appendix B and the have a limited pre-ozone season this. references to the provisions of § 75.20 electronic auditing capability. The First, sections 2.2.4 and 2.3.3 in with specific language that delineates requirement to report the results of the appendix B of today’s final rule provide the exact QA tests required during each daily assessments for the month of April ‘‘grace periods’’ in which late or missed ozone season. Section 75.74(c)(3) of is not considered burdensome because QA tests can be completed. For linearity today’s rule also contains specific data April is in the second calendar quarter, checks, the grace period is 168 unit validation provisions for sources that which is one of the two reporting operating hours after the end of the report only during the ozone season. To quarters for the affected sources. In fact, quarter in which the test is due. For the extent possible, these QA and data some affected sources may prefer to RATAs, the grace period is 720 unit validation provisions have been made report data for April, because it may be operating hours after the end of the the same as or similar to the easier to generate an electronic quarterly quarter in which the RATA is due. requirements for sources that report data report for the entire second calendar Because the grace periods in Part 75 are on a year-round basis. However, as quarter, rather than just for the months in terms of unit operating hours, they necessary, special provisions have been of May and June. Therefore, § 75.74(c)(6) can sometimes extend for more than one added to § 75.74(c) to address the of today’s final rule gives the owner or calendar quarter beyond the quarter in differences between year-round operator the option to report unit which the QA test was due (particularly reporters and sources that report only operating data and emission data for the for infrequently-operated or seasonally- during the ozone season. EPA believes month of April. operated units). Consequently, the Part that these revisions to Subpart H will In reviewing the missing data 75 grace period provisions in appendix help to achieve consistency in the provisions of Subpart H, EPA found a B are considered to be inappropriate for implementation of state and Federal discrepancy between the Agency’s sources that report emissions data only NOX mass emission reduction programs stated intent in the preamble to the during the ozone season. Without a and will help to ensure the quality of October 27, 1998 final rule and the complete record of unit operation for the reported data. regulatory language in § 75.74(c)(6)(i). each year, the regulatory agency will be The preamble states that ‘‘[h]istorical unable to determine whether the IV. Administrative Requirements lookback periods for missing data only required QA tests have been completed A. Public Docket need to include data from the ozone within the allotted grace period. season’’ (63 FR 57483, October 27, Second, § 75.20(b)(3) of today’s final EPA has established Docket A–97–35 1998). However, the rule language in rule provides ‘‘conditional’’ data for the regulations. The docket is an § 75.74(c)(6)(i) does not state this validation procedures for CEMS organized and complete file of all the explicitly, and could be misinterpreted. recertifications. These provisions allow information submitted to, or otherwise The rule language states that all ‘‘quality a probationary period following a considered by, EPA in the development assured data, in accordance with recertification event, during which data of today’s final rule. The principal paragraph (c)(2) or (c)(3) of this section’’ from a CEMS are assigned a purposes of the docket are: (1) to allow are to be used for missing data purposes. ‘‘conditionally valid’’ status. Provided interested parties a means to identify This could be interpreted as meaning that all recertification tests are passed and locate documents so that they can that the data recorded outside the ozone within the probationary period, with no effectively participate in the rulemaking season, in the time period between test failures, § 75.20(b)(3) allows the process; and (2) to serve as the record completion of the pre-ozone season conditionally valid data to be reported in case of judicial review. The docket is quality assurance testing of the CEM as quality-assured. Today’s rule also available for public inspection at EPA’s systems and May 1, are to be included allows these data validation procedures Air Docket, which is listed under the in the missing data lookback periods. to be used for routine linearity checks ADDRESSES section of this notice. This is not what EPA intends; rather, and RATAs, in cases where significant the statement cited above from the repair, adjustment or reprogramming of B. Executive Order 12866 October 27, 1998 preamble accurately the CEMS is done prior to the QA test. Under Executive Order 12866 (58 FR reflects the Agency’s position. The maximum allowable length of the 51735, October 4, 1993), the Therefore, § 75.74(c)(7) of today’s rule probationary period is 168 unit Administrator must determine whether operating hours for a linearity check and clearly states that for purposes of the regulatory action is ‘‘significant’’ 720 unit operating hours for a RATA. missing data substitution, only data and therefore subject to Office of Once again, because these probationary recorded during the ozone season will Management and Budget (OMB) review periods are in terms of unit operating be used for the historical missing data and the requirements of the Executive hours, they can extend outside the lookback periods. Order. The Order defines ‘‘significant Finally, EPA has examined the quality current calendar quarter, into the next regulatory action’’ as one that is likely assurance provisions of Subpart H in quarter and possibly beyond the next to result in a rule that may: view of the many substantial changes to quarter. Therefore, for sources that the quality assurance and data report only during the ozone season, (1) Have an annual effect on the economy validation provisions of Part 75 in some restrictions must be placed on the of $100 million or more or adversely affect today’s rulemaking. The Agency has use of the conditional data validation in a material way the economy, a sector of concluded that, in light of the many the economy, productivity, competition, jobs, procedures in § 75.20(b)(3). the environment, public health or safety, or changes that have been made to Part 75, In view of the above considerations, State, local or tribal governments or the general references in Subpart H to EPA has revised Subpart H to make it communities; the quality assurance provisions in clear which of the Part 75 QA and data (2) Create a serious inconsistency or § 75.21 and appendix B to Part 75 and validation provisions are applicable to otherwise interfere with an action taken or references to the data validation sources that report only in the ozone planned by another agency;

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(3) Materially alter the budgetary impact of the development of EPA regulatory governments in complying with the entitlements, grants, user fees, or loan proposals with significant Federal mandate. In developing this rule, EPA programs or the rights and obligations of intergovernmental mandates, and consulted with local and tribal recipients thereof; or informing, educating, and advising governments to enable them to provide (4) Raise novel legal or policy issues arising out of legal mandates, the President’s small governments on compliance with meaningful and timely input in the priorities, or the principles set forth in the the regulatory requirements. development of this rule. Only local or Executive Order. This rule is not expected to result in tribal governments that own sources expenditures of more than $100 million affected by Acid Rain would be affected This rule is not expected to have an in any one year and therefore is not by this rulemaking. The governments annual effect on the economy of $100 subject to section 202 of the UMRA. that own an Acid Rain affected source million or more. Although the rule is not expected to Pursuant to the terms of Executive were contacted when the proposed rule significantly or uniquely affect small was signed and informed of their right Order 12866, it has been determined governments, the Agency notified all that this rule is a ‘‘significant regulatory to comment on the proposal. EPA potentially affected small governments received a few comment letters from action’’ due to its policy implications. that own or operate units potentially Therefore, the rule was submitted to municipal utilities; these letters affected by the rule in order to assure contained support for many elements of OMB for review. Any written comments that they had the opportunity to have from OMB and any EPA response to the rule, as well as concerns with meaningful and timely input on the certain provisions. The Agency has those comments are included in the rule. EPA will continue to use its public docket for this proposal. The attempted to include changes to the outreach efforts related to part 75 proposed rule revisions based on these docket is available for public inspection implementation, including a policy at EPA’s Air Docket Section, which is and other comments wherever possible manual that is generally updated on a consistent with the purpose and intent listed in the ADDRESSES portion of this quarterly basis, to inform, educate, and preamble. of the rule revisions, and to the extent advise all potentially impacted small justified by the commenters. See section C. Unfunded Mandates Reform Act governments about compliance with III of this preamble and the response to part 75. comments document included in the Title II of the Unfunded Mandates EPA is not directly establishing any Reform Act of 1995 (UMRA), Pub. L. docket for this rulemaking for the regulatory requirements that may Agency’s responses to the specific 104–4, establishes requirements for significantly or uniquely affect small Federal agencies to assess the effects of comments raised. EPA also notes governments, including tribal generally that these sources already their regulatory actions on state, local, governments. Thus, EPA is not obligated and tribal governments and the private have to comply with part 75. Today’s to develop under section 203 of the rule adds more compliance flexibility sector. Under section 202 of the UMRA, UMRA a small government agency plan. EPA generally must prepare a written and may reduce the compliance costs statement, including a cost-benefit D. Executive Order 12875 for some of the sources owned by local analysis, for proposed and final rules Under Executive Order 12875, EPA and tribal governments. with ‘‘Federal mandates’’ that may may not issue a regulation that is not E. Executive Order 13084 result in expenditures to state, local, required by statute and that creates a and tribal governments, in the aggregate, mandate upon a State, local or tribal Under Executive Order 13084, EPA or to the private sector, of $100 million government, unless the Federal may not issue a regulation that is not or more in any one year. Section 205 of government provides the funds required by statute, that significantly or the UMRA generally requires that, necessary to pay the direct compliance uniquely affects the communities of before promulgating rules for which a costs incurred by those governments, or Indian tribal governments, and that written statement is needed, EPA must EPA consults with those governments. If imposes substantial direct compliance identify and consider a reasonable EPA complies by consulting, Executive costs on those communities, unless the number of regulatory alternatives and Order 12875 requires EPA to provide to Federal government provides the funds adopt the least costly, most cost- the Office of Management and Budget a necessary to pay the direct compliance effective, or least burdensome description of the extent of EPA’s prior costs incurred by the tribal alternative that achieves the objectives consultation with representatives of governments, or EPA consults with of the rule. The provisions of section affected State, local and tribal those governments. If EPA complies by 205 do not apply when they are governments, the nature of their consulting, Executive Order 13084 inconsistent with applicable law. concerns, copies of any written requires EPA to provide the Office of Moreover, section 205 allows EPA to communications from the governments, Management and Budget, in a separately adopt an alternative other than the least and a statement supporting the need to identified section of the preamble to the costly, most cost-effective, or least issue the regulation. In addition, rule, a description of the extent of EPA’s burdensome alternative if the Executive Order 12875 requires EPA to prior consultation with representatives Administrator publishes with the final develop an effective process permitting of affected tribal governments, a rule an explanation why that alternative elected officials and other summary of the nature of their concerns, was not adopted. Before EPA establishes representatives of State, local and tribal and a statement supporting the need to any regulatory requirements that may governments ‘‘to provide meaningful issue the regulation. In addition, significantly or uniquely affect small and timely input in the development of Executive Order 13084 requires EPA to governments, including tribal regulatory proposals containing develop an effective process permitting governments, it must have developed significant unfunded mandates.’’ elected officials and other under section 203 of the UMRA a small EPA has concluded that this rule will representatives of Indian tribal government agency plan. The plan must create a mandate on local and tribal governments ‘‘to provide meaningful provide for notifying potentially governments and that the Federal and timely input in the development of affected small governments, enabling government will not provide the funds regulatory policies on matters that officials of affected small governments necessary to pay the direct costs significantly or uniquely affect their to have meaningful and timely input in incurred by the local and tribal communities.’’

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Today’s rule does not significantly or The average annual projected hour fired units, many of which are owned or uniquely affect the communities of burden is 1,225,633, which is based on operated by small entities. Indian tribal governments. Only tribal an estimated average burden of Accordingly, considering all of the governments that own sources affected approximately 421 hours per response, above information, EPA concludes that by the Acid Rain Program are affected quarterly reporting frequency, and an this rule will not have a significant by this rulemaking. As noted above in estimated 728 likely respondents (on a economic impact on a substantial section IV.D. of this preamble, today’s per facility basis). The projected annual number of small entities. rule adds compliance flexibility and cost burden resulting from the H. Submission to Congress and the may reduce compliance costs for any collection of information is General Accounting Office tribal governments that own or operate $192,483,642, which includes a total affected sources. Accordingly, the projected capital and start-up average The Congressional Review Act, 5 requirements of section 3(b) of annualized cost of $92,131,857 (for U.S.C. 801 et seq., as added by the Small Executive Order 13084 do not apply to monitoring equipment/software), total Business Regulatory Enforcement this rule. projected fuel sampling and analysis Fairness Act of 1996, generally provides average annual cost of $581,100, and a that before a rule may take effect, the F. Paperwork Reduction Act total projected operation and Agency promulgating the rule must The information collection maintenance average annual cost (which submit a rule report, which includes a requirements in this rule have been includes purchase of testing contractor copy of the rule, to each House of submitted for approval to the OMB services) of $41,398,000. Burden means Congress and to the Comptroller General under the Paperwork Reduction Act, 44 the total time, effort, or financial of the United States. EPA will submit a U.S.C. 3501, et seq. An Information resources expended by persons to report containing this rule and other Collection Request (ICR) document has generate, maintain, retain, disclose, or required information to the U.S. Senate, been prepared by EPA (ICR No. provide information to or for a Federal the U.S. House of Representatives, and 1633.12), and a copy may be obtained agency. This includes the time needed the Comptroller General of the General from Sandy Farmer, OPPE Regulatory to review instructions; develop, acquire, Accounting Office prior to publication Information Division; U.S. install, and utilize technology and of the rule in today’s Federal Register. Environmental Protection Agency systems for purposes of collecting, This rule is not a ‘‘major rule’’ as (2137); 401 M Street, SW, Washington, validating, and verifying information, defined by U.S.C. 804(2). DC 20460, by calling (202) 260–2740, or processing and maintaining I. Executive Order 13045 via the Internet at www.epa.gov/icr. The information, and disclosing and information requirements are not providing information; adjust the This final rule is not subject to effective until OMB approves them. existing ways to comply with any Executive Order 13045, entitled Currently, all affected facilities are previously applicable instructions and ‘‘Protection of Children from required to keep records and submit requirements; train personnel to be able Environmental Health Risks and Safety electronic quarterly reports under the to respond to a collection of Risks’’ (62 FR 19885, April 23, 1997), provisions of part 75. The revisions to information; search data sources; because it does not involve decisions on the rule include several new options for complete and review the collection of environmental health risks or safety compliance with part 75 which have information; and transmit or otherwise risks that may disproportionately affect been requested by owners or operators disclose the information. children. of affected facilities. To implement An agency may not conduct or these options, EPA will have to modify J. National Technology Transfer and sponsor and a person is not required to Advancement Act the existing recordkeeping and reporting respond to a collection of information, requirements. In some circumstances, unless it displays a currently valid OMB Section 12(d) of National Technology these changes will result in significant control number. The OMB control Transfer and Advancement Act of 1995 reductions in the reporting and numbers for EPA’s regulations are listed (‘‘NTTAA’’), Pub L. 104–113, section recordkeeping burdens or costs for some in 40 CFR part 9 and 48 CFR chapter 15. 12(d) (15 U.S.C. 272 note), directs EPA units (such as low mass emissions to use voluntary consensus standards in units). However, these changes will G. Regulatory Flexibility its regulatory activities unless to do so require modifications to the software The Regulatory Flexibility Act (RFA), would be inconsistent with applicable used to generate electronic reports. In 5 U.S.C. 601, et seq., generally requires law or otherwise impractical. Voluntary addition, there will be some increased an agency to conduct a regulatory consensus standards are technical burden or costs for certain units to flexibility analysis of any rule subject to standards (e.g., materials specifications, fulfill the new quality assurance notice and comment rulemaking test methods, sampling procedures, procedures contained in this rule. requirements unless the agency certifies business practices, etc.) that are Finally, several other technical revisions that the rule will not have a significant developed or adopted by voluntary to the existing reporting and economic impact on a substantial consensus standards bodies. The recordkeeping requirements have been number of small entities. Small entities NTTAA requires EPA to provide adopted to clarify existing provisions or include small businesses, small not-for- Congress, through OMB, explanations to facilitate reporting for other profit enterprises, and governmental when the Agency decides not to use regulatory programs in the context of jurisdictions. This rule will not have a available and applicable voluntary Acid Rain Program reporting. Although significant impact on a substantial consensus standards. these one-time software changes will number of small entities. Part 75 already incorporates a number increase the short-term burdens on Today’s revisions to part 75 result in of voluntary consensus standards. In sources under the Acid Rain Program, a net cost reduction to facilities affected addition, today’s rule includes the changes should reduce a source’s by the Acid Rain Program, including incorporation on two voluntary overall long-term burden by small entities. Most importantly, the consensus standards, in response to streamlining the source’s reporting changes to Appendix D will comments submitted on the proposed obligations under both the Acid Rain significantly reduce the cost of part 75 rulemaking. First, ASTM Program and other parts of the Act. complying with part 75 for oil-and gas- D5373–93 ‘‘Standard Methods for

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Instrumental Determination of Carbon, calibration error test,’’ ‘‘QA operating Oils,’’ grades 1–GT or 2–GT, as defined Hydrogen and Nitrogen in laboratory quarter,’’ ‘‘research gas mixture’’ ‘‘stack by ASTM D2880–90a, ‘‘Standard samples of Coal and Coke.’’ This operating hour,’’ ‘‘standard reference Specification for Gas Turbine Fuel standard is incorporated by reference for material-equivalent compressed gas Oils,’’ or grades 1 or 2, as defined by use under section 2.1 of Appendix G to primary reference material (SRM- ASTM D396–90a, ‘‘Standard part 75. Second, API Sections 2, 3 and equivalent PRM),’’ and ‘‘very low sulfur Specification for Fuel Oils’’ 5 from Chapter 4 of the Manual of fuel;’’ by revising paragraphs (1) (incorporated by reference in § 72.13). Petroleum Standards, October 1988 introductory text, (1)(ii) and (2) of the * * * * * edition. This standard is incorporated definition of ‘‘oil-fired’’ and paragraph EPA protocol gas means a calibration by reference for use under section (2) of the definition of ‘‘peaking unit;’’ gas mixture prepared and analyzed 2.1.5.1 of Appendix D to part 75. by adding a paragraph (3) to the according to section 2 of the ‘‘EPA Consistent with the Agency’s definition of ‘‘peaking unit;’’ and by Traceability Protocol for Assay and Performance Based Measurement removing the definition of ‘‘protocol 1 Certification of Gaseous Calibration System, part 75 sets forth performance gas’’ and to read as follows: Standards,’’ September 1997, EPA–600/ criteria that allow the use of alternative § 72.2 Definitions. R–97/121 or such revised procedure as methods to the ones set forth in part 75. approved by the Administrator. The PBMS approach is intended to be * * * * * more flexible and cost effective for the Calibration gas means: * * * * * regulated community; it is also intended (1) A standard reference material; Fuel flowmeter QA operating quarter (2) A standard reference material- to encourage innovation in analytical means a unit operating quarter in which equivalent compressed gas primary technology and improved data quality. the unit combusts the fuel measured by reference material; the fuel flowmeter for at least 168 unit The EPA is not precluding the use of (3) A NIST traceable reference any method, whether it constitutes a operating hours (as defined in this material; section) or more. voluntary consensus standard or not, as (4) NIST/EPA-approved certified long as it meets the performance criteria reference materials; * * * * * specified, however any alternative (5) A gas manufacturer’s intermediate Gas-fired means: methods must be approved in advance standard; (1) For all purposes under the Acid before they may be used under part 75. (6) An EPA protocol gas; Rain Program, except for part 75 of this (7) Zero air material; or chapter, the combustion of: List of Subjects (8) A research gas mixture. (i) Natural gas or other gaseous fuel 40 CFR Part 72 * * * * * (including coal-derived gaseous fuel), Coal-fired means the combustion of Environmental protection, Acid rain, for at least 90.0 percent of the unit’s fuel consisting of coal or any coal- Air pollution control, Electric utilities, average annual heat input during the derived fuel (except a coal-derived Nitrogen oxides, Sulfur oxides. previous three calendar years and for at gaseous fuel that meets the definition of least 85.0 percent of the annual heat 40 CFR Part 75 ‘‘very low sulfur fuel’’ in this section), input in each of those calendar years; Environmental protection, Air alone or in combination with any other and fuel, where: pollution control, Carbon dioxide, (ii) Any fuel, except coal or solid or Continuous emission monitoring, * * * * * liquid coal-derived fuel, for the Electric utilities, Incorporation by Conditionally valid data means data remaining heat input, if any. from a continuous monitoring system reference, Nitrogen oxides, Reporting (2) For purposes of part 75 of this that are not quality assured, but which and recordkeeping, Sulfur dioxide. chapter, the combustion of: may become quality assured if certain Dated: April 1, 1999. conditions are met. Examples of data (i) Natural gas or other gaseous fuel Carol M. Browner, that may qualify as conditionally valid (including coal-derived gaseous fuel) for Administrator. are: data recorded by an uncertified at least 90.0 percent of the unit’s average annual heat input during the previous For the reasons set out in the monitoring system prior to its initial three calendar years and for at least 85.0 preamble, title 40 chapter I of the Code certification; or data recorded by a percent of the annual heat input in each of Federal Regulations is amended as certified monitoring system following a of those calendar years; and follows: significant change to the system that may affect its ability to accurately (ii) Fuel oil, for the remaining heat PART 72ÐPERMITS REGULATION measure and record emissions. A input, if any. monitoring system must pass a (3) For purposes of part 75 of this 1. The authority for part 72 continues chapter, a unit may initially qualify as to read as follows: probationary calibration error test, in accordance with section 2.1.1 of gas-fired if the designated representative Authority: 42 U.S.C. 7601 and 7651, et seq. appendix B to part 75 of this chapter, to demonstrates to the satisfaction of the 2. Section 72.2 is amended by initiate the conditionally valid data Administrator that the requirements of correcting the definition of ‘‘diesel status. In order for conditionally valid paragraph (2) of this definition are met, fuel;’’ by revising the definitions of emission data to become quality or will in the future be met, through one ‘‘calibration gas,’’ ‘‘coal-fired’’ assured, one or more quality assurance of the following submissions: (introductory text only), ‘‘gas-fired,’’ tests or diagnostic tests must be passed (i) For a unit for which a monitoring ‘‘natural gas,’’ ‘‘pipeline natural gas,’’ within a specified time period in plan has not been submitted under ‘‘span,’’ ‘‘stationary gas turbine,’’ and accordance with § 75.20(b)(3). § 75.62 of this chapter, the designated ‘‘zero air material;’’ by adding, in * * * * * representative submits either: alphabetical order, new definitions for Diesel fuel means a low sulfur fuel oil (A) Fuel usage data for the unit for the ‘‘conditionally valid data,’’ ‘‘EPA of grades 1–D or 2–D, as defined by the three calendar years immediately protocol gas,’’ ‘‘fuel flowmeter QA American Society for Testing and preceding the date of initial submission operating quarter,’’ ‘‘gas manufacturer’s Materials standard ASTM D975–91, of the monitoring plan for the unit intermediate standard,’’ ‘‘probationary ‘‘Standard Specification for Diesel Fuel under § 75.62; or

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(B) If a unit does not have fuel usage as a gas-fired unit for a subsequent year requirements of paragraph (1) of this data for one or more of the three only if the designated representative definition are met, or will in the future calendar years immediately preceding submits the data specified in paragraph be met, through one of the following the date of initial submission of the (3)(ii)(A) of this definition. submissions: monitoring plan for the unit under * * * * * (i) For a unit for which a monitoring § 75.62, the unit’s designated fuel usage; Gas manufacturer’s intermediate plan has not been submitted under all available fuel usage data (including standard (GMIS) means a compressed § 75.62, the designated representative the percentage of the unit’s heat input gas calibration standard that has been submits either: derived from the combustion of gaseous assayed and certified by direct (A) Capacity factor data for the unit fuels), beginning with the date on which comparison to a standard reference for the three calendar years immediately the unit commenced commercial material (SRM), an SRM-equivalent preceding the date of initial submission operation; and the unit’s projected fuel PRM, a NIST/EPA-approved certified of the monitoring plan for the unit usage. reference material (CRM), or a NIST under § 75.62; or (ii) For a unit for which a monitoring traceable reference material (NTRM), in (B) If a unit does not have capacity factor data for one or more of the three plan has already been submitted under accordance with section 2.1.2.1 of the calendar years immediately preceding § 75.62, that has not qualified as gas- ‘‘EPA Traceability Protocol for Assay the date of initial submission of the fired under paragraph (3)(i) of this and Certification of Gaseous Calibration monitoring plan for the unit under definition, and whose fuel usage Standards,’’ September 1997, EPA–600/ § 75.62, all available capacity factor changes, the designated representative R–97/121. submits either: data, beginning with the date on which (A) Three calendar years of data * * * * * the unit commenced commercial Natural gas means a naturally following the change in the unit’s fuel operation; and projected capacity factor usage, showing that no less than 90.0 occurring fluid mixture of hydrocarbons data. percent of the unit’s average annual heat (e.g., methane, ethane, or propane) (ii) For a unit for which a monitoring input during the previous three calendar produced in geological formations plan has already been submitted under years, and no less than 85.0 percent of beneath the Earth’s surface that § 75.62, that has not qualified as a the unit’s annual heat input during any maintains a gaseous state at standard peaking unit under paragraph (2)(i) of one of the previous three calendar years, atmospheric temperature and pressure this definition, and where capacity is from the combustion of gaseous fuels under ordinary conditions. Natural gas factor changes, the designated and the remaining heat input is from the contains 1.0 grain or less of hydrogen representative submits either: combustion of fuel oil; or sulfide per 100 standard cubic feet and (A) Three calendar years of data (B) A minimum of 720 hours of unit the hydrogen sulfide constitutes more following the change in the unit’s operating data following the change in than 50% (by weight) of the total sulfur capacity factor showing an average the unit’s fuel usage, showing that no in the gas fuel. Additionally, natural gas capacity factor of no more than 10.0 less than 90.0 percent of the unit’s heat must meet either be composed of at least percent during the three previous input is from the combustion of gaseous 70% methane by volume or have a gross calendar years and a capacity factor of fuels and the remaining heat input is calorific value between 950 and 1100 no more than 20.0 percent in each of from the combustion of fuel oil, and a Btu per standard cubic foot. Natural gas those calendar years; or statement that this changed pattern of does not include the following gaseous (B) One calendar year of data fuel usage is considered permanent and fuels: landfill gas, digester gas, refinery following the change in the unit’s is projected to continue for the gas, sour gas, blast furnace gas, coal- capacity factor showing a capacity factor foreseeable future. derived gas, producer gas, coke oven of no more than 10.0 percent and a (iii) If a unit qualifies as gas-fired gas, or any gaseous fuel produced in a statement that this changed pattern of under paragraph (3)(i) or (ii) of this process which might result in highly operation resulting in a capacity factor definition, the unit is classified as gas- variable sulfur content or heating value. less than 10.0 percent is considered fired as of the date of the submission * * * * * permanent and is projected to continue under such paragraph. Oil-fired means: for the foreseeable future. (4) For purposes of part 75 of this (1) For all purposes under the Acid (3) For purposes of part 75 of this chapter, a unit that initially qualifies as Rain Program, except part 75 of this chapter, a unit that initially qualifies as gas-fired under paragraph (3)(i) or (ii) of chapter, the combustion of: a peaking unit must meet the criteria in this definition must meet the criteria in (i) * * * paragraph (1) of this definition each paragraph (2) of this definition each (ii) Any solid, liquid or gaseous fuel year in order to continue to qualify as year in order to continue to qualify as (including coal-derived gaseous fuel), a peaking unit. If such a unit fails to gas-fired. If such a unit combusts only other than coal or any other coal- meet such criteria for a given year, the gaseous fuel and fuel oil but fails to derived solid or liquid fuel, for the unit no longer qualifies as a peaking meet such criteria for a given year, the remaining heat input, if any. unit starting January 1 of the year after unit no longer qualifies as gas-fired (2) For purposes of part 75 of this the year for which the criteria are not starting January 1 of the year after the chapter, combustion of only fuel oil and met. If a unit failing to meet the criteria first year for which the criteria are not gaseous fuels, provided that the unit in paragraph (1) of this definition met. If such a unit combusts fuel other involved does not meet the definition of initially qualified as a peaking unit than gaseous fuel or fuel oil and fails to gas-fired. under paragraph (2) of this definition, meet such criteria in a given year, the * * * * * the unit may qualify as a peaking unit unit no longer qualifies as gas-fired Peaking unit means: for a subsequent year only if the starting the day after the first day for * * * * * designated representative submits the which the criteria are not met. If a unit (2) For purposes of part 75 of this data specified in paragraph (2)(ii)(A) of failing to meet the criteria in paragraph chapter, a unit may initially qualify as this definition. (2) of this definition initially qualified a peaking unit if the designated * * * * * as a gas-fired unit under paragraph (3) representative demonstrates to the Pipeline natural gas means natural of this definition, the unit may qualify satisfaction of the Administrator that the gas, as defined in this section, that is

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28588 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations provided by a supplier through a (1) A fuel with a total sulfur content § 72.90 Annual compliance certification pipeline and that contains 0.3 grains or no greater than 0.05 percent sulfur by report. less of hydrogen sulfide per 100 weight; * * * * * standard cubic feet and the hydrogen (2) Natural gas or pipeline natural gas, (c) * * * sulfide in content of the gas constitutes as defined in this section; or (3) Whether all the emissions from the at least 50% (by weight) of the total (3) Any gaseous fuel with a total unit, or a group of units (including the sulfur in the fuel; sulfur content no greater than 20 grains unit) using a common stack, were * * * * * of sulfur per 100 standard cubic feet. monitored or accounted for through the Probationary calibration error test * * * * * missing data procedures and reported in Zero air material means either: means an on-line calibration error test the quarterly monitoring reports, (1) A calibration gas certified by the performed in accordance with section including whether conditionally valid gas vendor not to contain concentrations 2.1.1 of appendix B to part 75 of this data, as defined in § 72.2, were reported of SO2, NOX, or total hydrocarbons chapter that is used to initiate a in the quarterly report. If conditionally above 0.1 parts per million (ppm), a conditionally valid data period. valid data were reported, the owner or concentration of CO above 1 ppm, or a operator shall indicate whether the * * * * * concentration of CO2 above 400 ppm; status of all conditionally valid data has QA operating quarter means a (2) Ambient air conditioned and been resolved and all necessary calendar quarter in which there are at purified by a CEMS for which the CEMS quarterly report resubmissions have least 168 unit operating hours (as manufacturer or vendor certifies that the been made. defined in this section) or, for a particular CEMS model produces * * * * * common stack or bypass stack, a conditioned gas that does not contain calendar quarter in which there are at concentrations of SO2, NOX, or total PART 75ÐCONTINUOUS EMISSION least 168 stack operating hours (as hydrocarbons above 0.1 ppm, a MONITORING defined in this section). concentration of CO above 1 ppm, or a * * * * * concentration of CO2 above 400 ppm; 6. The authority citation for part 75 is (3) For dilution-type CEMS, revised to read as follows: Research gas mixture (RGM) means a conditioned and purified ambient air calibration gas mixture developed by Authority: 42 U.S.C. 7601, 7651k, and provided by a conditioning system agreement of a requestor and NIST that 7651k note. concurrently supplying dilution air to NIST analyzes and certifies as ‘‘NIST the CEMS; or Subpart AÐGeneral traceable.’’ RGMs may have (4) A multicomponent mixture concentrations different from those of certified by the supplier of the mixture 7. Section 75.4 is amended by revising standard reference materials. that the concentration of the component the last sentence of paragraph (a) * * * * * being zeroed is less than or equal to the introductory text, revising the first Span means the highest pollutant or applicable concentration specified in sentence of paragraph (d) introductory diluent concentration or flow rate that a paragraph (1) of this definition, and that text, revising paragraph (d)(1), adding a monitor component is required to be the mixture’s other components do not new sentence to the beginning of capable of measuring under part 75 of interfere with the CEM readings. paragraph (g) introductory text, and this chapter. 3. Section 72.3 is amended by adding, adding a new paragraph (i) to read as follows: * * * * * in alphabetical order, new acronyms for CEMS, kacfm, kscfh, NIST and RATA to Stack operating hour means any hour § 75.4 Compliance dates. read as follows: (or fraction of an hour) during which (a) * * * In accordance with § 75.20, flue gases flow through a common stack § 72.3 Measurements, abbreviations, and the owner or operator of each existing or bypass stack. acronyms. affected unit shall ensure that all * * * * * * * * * * monitoring systems required by this part Standard reference material- CEMS—continuous emission for monitoring SO2, NOX, CO2, opacity, equivalent compressed gas primary monitoring system. moisture and volumetric flow are reference material (SRM-equivalent * * * * * installed and that all certification tests PRM) means those gas mixtures listed in kacfm—thousands of cubic feet per are completed no later than the a declaration of equivalence in minute at actual conditions. following dates (except as provided in accordance with section 2.1.2 of the kscfh—thousands of cubic feet per paragraphs (d) through (i) of this ‘‘EPA Traceability Protocol for Assay hour at standard conditions. section): and Certification of Gaseous Calibration * * * * * * * * * * Standards,’’ September 1997, EPA–600/ NIST—National Institute of Standards (d) In accordance with § 75.20, the R–97/121. and Technology. owner or operator of an existing unit * * * * * * * * * * that is shutdown and is not yet operating by the applicable dates listed Stationary gas turbine means a RATA—relative accuracy test audit. * * * * * in paragraph (a) of this section, or an turbine that is not self-propelled and existing unit which has been placed in that combusts natural gas, other gaseous § 72.6 [Amended] long-term cold storage after having fuel with a total sulfur content no 4. Section 72.6 is amended by previously reported emissions data in greater than the total sulfur content of removing from paragraph (b)(1) the accordance with this part, shall ensure natural gas, or fuel oil in order to heat word ‘‘operation’’ and adding, in its that all monitoring systems required inlet combustion air and thereby turn a place, the words ‘‘commercial under this part for monitoring of SO2, turbine in addition to or instead of operation.’’ NOX, CO2, opacity, and volumetric flow producing steam or heating water. 5. Section 72.90 is amended by are installed and all certification tests * * * * * revising paragraph (c)(3) to read as are completed no later than the earlier Very low sulfur fuel means either: follows: of 45 unit operating days or 180

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Conduits Using Transit-Time Ultrasonic potential NOX emission rate, as defined * * * * * Flowmeters, for appendix D of this part. in section 2.1.2.1 of appendix A to this (f) * * * (4) ASME MFC–6M–1987 with June part, the maximum potential flow rate, (2) The owner or operator is 1987 Errata, Measurement of Fluid Flow as defined in section 2.1.4.1 of appendix monitoring emissions from the unit with in Pipes Using Vortex Flow Meters, for A to this part, or the maximum potential another certified monitoring system or appendix D of this part. CO2 concentration, as defined in section an excepted methodology approved by (5) ASME MFC–7M–1987 (Reaffirmed 2.1.3.1 of appendix A to this part; the Administrator for use at that unit 1992), Measurement of Gas Flow by * * * * * that provides emissions data for the Means of Critical Flow Venturi Nozzles, (g) The provisions of this paragraph same pollutant or parameter as the for appendix D of this part. shall apply unless an owner or operator retired or discontinued monitoring (6) ASME MFC–9M–1988 with is exempt from certifying a fuel system; or December 1989 Errata, Measurement of flowmeter for use during combustion of * * * * * Liquid Flow in Closed Conduits by emergency fuel under section 2.1.4.3 of 9. Section 75.6 is amended by revising Weighing Method, for appendix D of appendix D to this part, in which paragraphs (a)(13), (a)(31), (a)(38), this part. circumstance the provisions of section (a)(39), (b), (c), (e)(1) and (e)(2); by (c) The following materials are 2.1.4.3 of appendix D shall apply. redesignating paragraph (a)(40) as available for purchase from the *** paragraph (a)(41); and by adding new American National Standards Institute * * * * * paragraphs (a)(40) and (f)(3) to read as (ANSI), 11 W. 42nd Street, New York (i) In accordance with § 75.20, the follows: NY 10036: ISO 8316: 1987(E) owner or operator of each affected unit Measurement of Liquid Flow in Closed § 75.6 Incorporation by reference. at which SO2 concentration is measured Conduits-Method by Collection of the on a dry basis or at which moisture * * * * * Liquid in a Volumetric Tank, for corrections are required to account for (a) * * * appendices D and E of this part. (13) ASTM D1826–88, Standard Test CO2 emissions, NOX emission rate in lb/ * * * * * Method for Calorific (Heating) Value of mmBtu, heat input, or NOX mass (e) * * * emissions for units in a NOX mass Gases in Natural Gas Range by (1) American Gas Association Report reduction program, shall ensure that the Continuous Recording Calorimeter, for No. 3: Orifice Metering of Natural Gas continuous moisture monitoring system appendices D and F to this part. and Other Related Hydrocarbon Fluids, required by this part is installed and * * * * * Part 1: General Equations and that all applicable initial certification (31) ASTM D3588–91, Standard Uncertainty Guidelines (October 1990 tests required under § 75.20(c)(5), (c)(6), Practice for Calculating Heat Value, Edition), Part 2: Specification and or (c)(7) for the continuous moisture Compressibility Factor, and Relative Installation Requirements (February monitoring system are completed no Density (Specific Gravity) of Gaseous 1991 Edition) and Part 3: Natural Gas later than the following dates: Fuels, for appendices D and F to this Applications (August 1992 Edition), for (1) April 1, 2000, for a unit that is part. appendices D and E of this part. existing and has commenced * * * * * (2) American Gas Association commercial operation by January 2, (38) ASTM D4891–89, Standard Test Transmission Measurement Committee 2000; or Method for Heating Value of Gases in Report No. 7: Measurement of Gas by (2) For a new affected unit which has Natural Gas Range by Stoichiometric Turbine Meters (Second Revision, April, not commenced commercial operation Combustion, for appendices D and F to 1996), for appendix D to this part. by January 2, 2000, no later than 90 days this part. (f) * * * after the date the unit commences (39) ASTM D5291–92, Standard Test (3) American Petroleum Institute commercial operation; or Methods for Instrumental Determination (API) Section 2, ‘‘Conventional Pipe (3) For an existing unit that is of Carbon, Hydrogen, and Nitrogen in Provers,’’ Section 3, ‘‘Small Volume shutdown and is not yet operating by Petroleum Products and Lubricants, for Provers,’’ and Section 5, ‘‘Master-Meter April 1, 2000, no later than the earlier appendices F and G to this part. Provers,’’ from Chapter 4 of the Manual of 45 unit operating days or 180 (40) ASTM D5373–93, ‘‘Standard of Petroleum Measurement Standards, calendar days after the date that the unit Methods for Instrumental Determination October 1988 (Reaffirmed 1993), for recommences commercial operation. of Carbon, Hydrogen, and Nitrogen in appendix D to this part. 8. Section 75.5 is amended by revising Laboratory Samples of Coal and Coke,’’ 10. Section 75.7 is removed and paragraphs (b), (d), and (f)(2) to read as for appendix G to this part. reserved. follows: (41) * * * (b) The following materials are § 75.7 [Removed and Reserved] § 75.5 Prohibitions. available for purchase from the 11. Section 75.8 is removed and * * * * * American Society of Mechanical reserved. (b) No owner or operator of an Engineers (ASME), 22 Law Drive, Box affected unit shall operate the unit 2350, Fairfield, NJ 07007–2350. § 75.8 [Removed and Reserved] without complying with the (1) ASME MFC–3M–1989 with Subpart B ÐMonitoring Provisions requirements of §§ 75.2 through 75.75 September 1990 Errata, Measurement of and appendices A through G to this Fluid Flow in Pipes Using Orifice, 12. Section 75.10 is amended by part. Nozzle, and Venturi, for appendix D of revising paragraphs (d)(3) and (f) to read * * * * * this part. as follows:

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§ 75.10 General operating requirements. only gaseous fuel is combusted in the (e) Units with SO2 continuous * * * * * unit, the owner or operator shall comply emission monitoring systems during the (d) * * * with the applicable provisions of combustion of gaseous fuel. The owner (3) Failure of an SO2, CO2, or O2 paragraph (e)(1), (e)(2), or (e)(3) of this or operator of an affected unit with an pollutant concentration monitor, flow section. SO2 continuous emission monitoring monitor, or NOX continuous emission (b) Moisture correction. Where SO2 system shall, during any hour in which monitoring system to acquire the concentration is measured on a dry the unit combusts only gaseous fuel, minimum number of data points for basis, the owner or operator shall either: determine SO2 emissions in accordance calculation of an hourly average in (1) Report the appropriate fuel- with paragraph (e)(1), (e)(2) or (e)(3) of paragraph (d)(1) of this section shall specific default moisture value for each this section, as applicable. (1) If the gaseous fuel meets the result in the failure to obtain a valid unit operating hour, selected from definition of ‘‘pipeline natural gas’’ or hour of data and the loss of such among the following: 3.0%, for ‘‘natural gas’’ in § 72.2 of this chapter, component data for the entire hour. An anthracite coal; 6.0% for bituminous the owner or operator may, in lieu of hourly average NOX or SO2 emission coal; 8.0% for sub-bituminous coal; operating and recording data from the rate in lb/mmBtu is valid only if the 11.0% for lignite coal; 13.0% for wood; SO2 monitoring system, determine SO2 minimum number of data points is or acquired by both the pollutant emissions by using Equation F–23 in (2) Install, operate, maintain, and appendix F to this part. Substitute into concentration monitor (NOX or SO2) and quality assure a continuous moisture Equation F–23 the hourly heat input, the diluent monitor (O2 or CO2). For a monitoring system for measuring and calculated using a certified flow moisture monitoring system consisting recording the moisture content of the of one or more oxygen analyzers capable monitoring system and a certified flue gases, in order to correct the diluent monitor, in conjunction with the of measuring O2 on a wet-basis and a measured hourly volumetric flow rates dry-basis, an hourly average percent appropriate default SO2 emission rate for moisture when calculating SO2 mass moisture value is valid only if the from section 2.3.1.1 or 2.3.2.1.1 of emissions (in lb/hr) using the appendix D to this part, and Equation minimum number of data points is procedures in appendix F to this part. acquired for both the wet-and dry-basis D–5 in appendix D to this part. When The following continuous moisture this option is chosen, the owner or measurements. Except for SO2 emission monitoring systems are acceptable: a rate data in lb/mmBtu, if a valid hour of operator shall perform the necessary continuous moisture sensor; an oxygen data acquisition and handling system data is not obtained, the owner or analyzer (or analyzers) capable of tests under § 75.20(c), and shall meet all operator shall estimate and record measuring O2 both on a wet basis and quality control and quality assurance emissions, moisture, or flow data for the on a dry basis; or a stack temperature requirements in appendix B to this part missing hour by means of the automated sensor and a moisture look-up table, i.e., for the flow monitor and the diluent data acquisition and handling system, in a psychometric chart (for saturated gas monitor. accordance with the applicable streams following wet scrubbers or other (2) The owner or operator may, in lieu procedure for missing data substitution demonstrably saturated gas streams, of operating and recording data from the in subpart D of this part. only). The moisture monitoring system SO2 monitoring system, determine SO2 * * * * * shall include as a component the emissions by certifying an excepted (f) Minimum measurement capability automated data acquisition and monitoring system in accordance with requirement. The owner or operator handling system (DAHS) for recording § 75.20 and appendix D to this part, shall ensure that each continuous and reporting both the raw data (e.g., following the applicable fuel sampling emission monitoring system and hourly average wet-and dry-basis O2 and analysis procedures in section 2.3 component thereof is capable of values) and the hourly average values of of appendix D to this part, meeting the accurately measuring, recording, and the stack gas moisture content derived recordkeeping requirements of § 75.55 reporting data, and shall not incur an from those data. When a moisture look- or § 75.58, as applicable, and meeting all exceedance of the full scale range, up table is used, the moisture quality control and quality assurance except as provided in sections 2.1.1.5, monitoring system shall be represented requirements for fuel flowmeters in 2.1.2.5, and 2.1.4.3 of appendix A to this as a single component, the certified appendix D to this part. If this part. DAHS, in the monitoring plan for the compliance option is selected, the * * * * * unit or common stack. hourly unit heat input reported under 13. Section 75.11 is amended by * * * * * § 75.54(b)(5) or § 75.57(b)(5), as revising paragraphs (a), (b), (d)(1), (d)(2), (d) * * * applicable, shall be determined using a certified flow monitoring system and a (e) introductory text, (e)(1), (e)(2), (e)(3) (1) By meeting the general operating introductory text, (e)(3)(ii), (e)(3)(iv), certified diluent monitor, in accordance requirements in § 75.10 for an SO2 with the procedures in section 5.2 of and by removing paragraph (e)(4) to continuous emission monitoring system read as follows: appendix F to this part. The flow and flow monitoring system. If this monitor and diluent monitor shall meet § 75.11 Specific provisions for monitoring option is selected, the owner or operator all of the applicable quality control and SO2 emissions (SO2 and flow monitors). shall comply with the applicable quality assurance requirements of (a) Coal-fired units. The owner or provisions in paragraph (e)(1), (e)(2), or appendix B to this part. operator shall meet the general (e)(3) of this section during hours in (3) The owner or operator may which the unit combusts only gaseous operating requirements in § 75.10 for an determine SO2 mass emissions by using fuel; SO2 continuous emission monitoring a certified SO2 continuous monitoring system and a flow monitoring system for (2) By providing other information system, in conjunction with a certified each affected coal-fired unit while the satisfactory to the Administrator using flow rate monitoring system. However, unit is combusting coal and/or any other the applicable procedures specified in if the unit burns any gaseous fuel that fuel, except as provided in paragraph (e) appendix D to this part for estimating is very low sulfur fuel (as defined in of this section, in § 75.16, and in subpart hourly SO2 mass emissions; or § 72.2 of this chapter), then on and after E of this part. During hours in which * * * * * April 1, 2000, the SO2 monitoring

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Prior operator shall either report a fuel- O2 concentration monitor; fuel F and Fc to April 1, 2000, the owner or operator specific default moisture value for each factors; and, where O2 concentration is may comply with these provisions. unit operating hour, as provided in measured on a dry basis, a continuous * * * * * § 75.11(b)(1), or shall install, operate, moisture monitoring system, as (ii) EPA recommends that the maintain, and quality assure a specified in § 75.11(b)(2), or a fuel- calibration response of the SO2 continuous moisture monitoring system, specific default moisture percentage (if monitoring system be adjusted, either as defined in § 75.11(b)(2). applicable), as defined in § 75.11(b)(1), automatically or manually, in Notwithstanding this requirement, if and by using the methods and accordance with the procedures for Equation 19–3, 19–4 or 19–8 in Method procedures specified in appendix F to routine calibration adjustments in 19 in appendix A to part 60 of this this part. For units using a common section 2.1.3 of appendix B to this part, chapter is used to measure NOX stack, multiple stack, or bypass stack, whenever the zero-level calibration emission rate, the following fuel- the owner or operator may use the response during a required daily specific default moisture percentages provisions of § 75.16, except that the calibration error test exceeds the shall be used in lieu of the default phrase ‘‘CO2 continuous emission applicable performance specification of values specified in § 75.11(b)(1): 5.0%, monitoring system’’ shall apply rather the instrument in section 3.1 of for anthracite coal; 8.0% for bituminous than ‘‘SO2 continuous emission appendix A to this part (i.e., ±2.5 coal; 12.0% for sub-bituminous coal; monitoring system,’’ the term percent of the span value or ±5 ppm, 13.0% for lignite coal; and 15.0% for ‘‘maximum potential concentration of wood. whichever is less restrictive). CO2’’ shall apply rather than ‘‘maximum (c) Determination of NOX emission * * * * * potential concentration of SO2,’’ and the rate. The owner or operator shall phrase ‘‘CO2 mass emissions’’ shall (iv) In accordance with the calculate hourly, quarterly, and annual requirements of section 2.1.1.2 of apply rather than ‘‘SO2 mass NOX emission rates (in lb/mmBtu) by emissions.’’ appendix A to this part, for units that combining the NOX concentration (in * * * * * sometimes burn gaseous fuel that is very ppm), diluent concentration (in percent low sulfur fuel (as defined in § 72.2 of 16. Section 75.16 is amended by: O2 or CO2), and percent moisture (if a. Revising paragraphs (b)(2)(ii)(B), this chapter) and at other times burn applicable) measurements according to higher sulfur fuel(s) such as coal or oil, (b)(2)(ii)(D), (d)(2), and (e)(1); the procedures in appendix F to this b. Removing paragraphs (e)(2) and a second low-scale SO2 measurement part. range is not required when the very low (e)(3); * * * * * c. Redesignating existing paragraphs sulfur gaseous fuel is combusted. For 15. Section 75.13 is amended by (e)(4) and (e)(5) as paragraphs (e)(2) and units that burn only gaseous fuel that is revising paragraphs (a) and (c) to read as (e)(3), respectively; very low sulfur fuel and burn no other follows: d. Adding a new sentence to the end type(s) of fuel(s), the owner or operator of the newly designated paragraph shall set the span of the SO2 monitoring § 75.13 Specific provisions for monitoring CO emissions. (e)(3); and system to a value no greater than 200 2 e. Adding a new paragraph (e)(4), to (a) CO2 continuous emission ppm. read as follows: * * * * * monitoring system. If the owner or 14. Section 75.12 is amended by operator chooses to use the continuous § 75.16 Special provisions for monitoring revising the first sentence in paragraph emission monitoring method, then the emissions from common, bypass, and (a); by redesignating existing paragraphs owner or operator shall meet the general multiple stacks for SO2 emissions and heat input determinations. (b), (c), (d) and (e) as paragraphs (c), (d), operating requirements in § 75.10 for a (e) and (f), respectively; by adding new CO2 continuous emission monitoring * * * * * paragraph (b); and by revising the newly system and flow monitoring system for (b) * * * (2) * * * designated paragraph (c) to read as each affected unit. The owner or (ii) * * * follows: operator shall comply with the applicable provisions specified in (B) Install, certify, operate, and § 75.12 Specific provisions for monitoring §§ 75.11(a) through (e) or § 75.16, except maintain an SO2 continuous emission NOX emission rate (NOX and diluent gas that the phrase ‘‘CO2 continuous monitoring system and flow monitoring monitors). emission monitoring system’’ shall system in the duct from each (a) Coal-fired units, gas-fired apply rather than ‘‘SO2 continuous nonaffected unit; determine SO2 mass nonpeaking units or oil-fired emission monitoring system,’’ the emissions from the affected units as the nonpeaking units. The owner or phrase ‘‘CO2 concentration’’ shall apply difference between SO2 mass emissions operator shall meet the general rather than ‘‘SO2 concentration,’’ the measured in the common stack and SO2 operating requirements in § 75.10 of this term ‘‘maximum potential concentration mass emissions measured in the ducts part for a NOX continuous emission of CO2’’ shall apply rather than of the nonaffected units, not to be monitoring system for each affected ‘‘maximum potential concentration of reported as an hourly average value less coal-fired unit, gas-fired nonpeaking SO2,’’ and the phrase ‘‘CO2 mass than zero; combine emissions for the unit, or oil-fired nonpeaking unit, emissions’’ shall apply rather than ‘‘SO2 Phase I and Phase II affected units for except as provided in paragraph (d) of mass emissions.’’ recordkeeping and compliance this section, § 75.17, and subpart E of * * * * * purposes; and calculate and report SO2 this part. * * * (c) Determination of CO2 mass mass emissions from the Phase I and (b) Moisture correction. If a correction emissions using an O2 monitor Phase II affected units, pursuant to an for the stack gas moisture content is according to appendix F to this part. If approach approved by the needed to properly calculate the NOX the owner or operator chooses to use the Administrator, such that these emission rate in lb/mmBtu, e.g., if the appendix F method, then the owner or emissions are not underestimated; or NOX pollutant concentration monitor operator may determine hourly CO2 * * * * *

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(D) Petition through the designated (a)(1)(ii), (a)(2)(ii), (b)(1)(ii), and (b)(2)(ii) § 75.19 Optional SO2, NOX, and CO2 representative and provide information of this section, the owner or operator of emissions calculation for low mass satisfactory to the Administrator on an affected unit with a diluent monitor emissions units. methods for apportioning SO2 mass and a flow monitor installed on a * * * * * emissions measured in the common common stack to determine the (c) * * * stack to each of the units using the combined heat input at the common (3) * * * common stack and on reporting the SO2 stack shall also determine and report (ii) * * * mass emissions. The Administrator may heat input to each individual unit. (D) * * * approve such demonstrated substitute * * * * * (2) Using the appropriate default methods for apportioning and reporting (3) * * * If using either of these specific gravity value in Table LM–6 of SO2 mass emissions measured in a apportionment methods, the owner or this section. common stack whenever the operator shall apportion according to * * * * * demonstration ensures that there is a section 5.6 of appendix F to this part. (4) * * * complete and accurate accounting of all (4) Notwithstanding paragraph (e)(1) (ii) * * * emissions regulated under this part and, of this section, any affected unit that is in particular, that the emissions from (A) * * * using the procedures in this part to meet Where: any affected unit are not the monitoring and reporting * * * * * underestimated. requirements of a State or federal NOX * * * * * mass emission reduction program must EFNNOX = Either the NOX emission (d) * * * also meet the requirements for factor from Table LM–2 of this section (2) Install, certify, operate, and monitoring heat input in §§ 75.71, 75.72 or the fuel- and unit-specific NOX maintain an SO2 continuous emission and 75.75. emission rate determined under monitoring system and flow monitoring 17. Section 75.17 is amended by paragraph (c)(1)(iv) of this section (lb/ system in each stack. Determine SO2 revising paragraph (a)(2)(i)(C) to read as mmBtu). mass emissions from each affected unit follows: * * * * * as the sum of the SO2 mass emissions recorded for each stack. § 75.17 Specific provisions for monitoring TABLE LM±5.ÐDEFAULT GROSS CAL- emissions from common, by-pass, and Notwithstanding the prior sentence, if ORIFIC VALUES (GCVS) FOR VAR- multiple stacks for NOX emission rate. another unit also exhausts flue gases to IOUS FUELS one or more of the stacks, the owner or * * * * * (a) * * * operator shall also comply with the Fuel GCV for use in equa- applicable common stack requirements (2) * * * tion LM±2 or LM±3 of this section to determine and record (i) * * * (C) Each unit’s compliance with the Pipeline Natural Gas 1050 Btu/scf. SO2 mass emissions from the units Natural Gas ...... 1100 Btu/scf. using that stack and shall calculate and applicable NOX emission limit will be determined by a method satisfactory to Residual Oil ...... 19,700 Btu/lb or report SO2 mass emissions from the 167,500 Btu/gallon. affected units and stacks, pursuant to an the Administrator for apportioning to Diesel Fuel ...... 20,500 Btu/lb or approach approved by the each of the units the combined NOX 151,700 Btu/gallon. Administrator, such that these emission rate (in lb/mmBtu) measured emissions are not underestimated. in the common stack and for reporting * * * * * (e) * * * the NOX emission rate, as provided in (1) The owner or operator of an a petition submitted by the designated Subpart CÐOperation and affected unit using a common stack, representative. The Administrator may Maintenance Requirements bypass stack, or multiple stack with a approve such demonstrated substitute 19. Section 75.20 is amended by: diluent monitor and a flow monitor on methods for apportioning and reporting a. Revising the title of the section; each stack may choose to install NOX emission rate measured in a monitors to determine the heat input for common stack whenever the b. Revising the titles of paragraphs (c), the affected unit, wherever flow and demonstration ensures that there is a (d) and (g); diluent monitor measurements are used complete and accurate estimation of all c. Revising the introductory text of to determine the heat input, using the emissions regulated under this part and, paragraphs (a), (c) and (g); procedures specified in paragraphs (a) in particular, that the emissions from d. Revising paragraphs (a)(1), (a)(3), through (d) of this section, except that any unit with a NOX emission limitation (a)(4) introductory text, (a)(4)(i), the term ‘‘heat input’’ shall apply rather are not underestimated. (a)(4)(ii), (a)(4)(iii), (a)(5)(i), (b), (c)(1), than ‘‘SO2 mass emissions’’ or * * * * * (c)(1)(i), (c)(1)(ii), (c)(1)(iii), (d)(1), (d)(2), ‘‘emissions’’ and the phrase ‘‘a diluent 18. Section 75.19 is amended by: (g)(1), (g)(1)(i), (g)(2), (g)(4), (g)(5) and monitor and a flow monitor’’ shall apply a. Redesignating Tables 1, 2, 3, 4, 5 (h)(2); rather than ‘‘SO2 continuous emission and 6 as LM–1, LM–2, LM–3, LM–4, e. Removing existing paragraph (c)(3); monitoring system and flow monitoring LM–5 and LM–6, respectively; f. Redesignating existing paragraphs system.’’ The applicable equation in b. Revising all references to Tables 1, (c)(4), (c)(5), (c)(6), (c)(7), and (c)(8) as appendix F to this part shall be used to 2, 3, 4, 5 and 6 in § 75.19 to LM–1, LM– paragraphs (c)(3), (c)(4), (c)(8), (c)(9), calculate the heat input from the hourly 2, LM–3, LM–4, LM–5, and LM–6, and (c)(10), respectively; flow rate, diluentmonitor respectively; g. Revising newly redesignated measurements, and (if the equation in c. Revising newly designated Table paragraphs (c)(3), (c)(4) introductory appendix F requires a correction for the LM–5; text, (c)(8) introductory text, (c)(8)(i), stack gas moisture content) hourly d. Correcting paragraph (c)(3)(ii)(D)(2) and (c)(10) introductory text; and moisture measurements. and the term ‘‘EFNOX’’ that follows Eq. h. Adding new paragraphs (c)(5), Notwithstanding the options for LM–10 in paragraph (c)(4)(ii)(A) to read (c)(6), (c)(7), (g)(6) and (g)(7), to read as combining heat input in paragraphs as follows: follows:

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§ 75.20 Initial certification and recertification) by issuing a notice of (iii) Disapproval notice. If the recertification procedures. disapproval within 120 days of receipt certification (or recertification) (a) Initial certification approval by the Administrator of the complete application shows that any continuous process. The owner or operator shall certification (or recertification) emission or opacity monitoring system ensure that each continuous emission or application. Note that when the data or component thereof does not meet the opacity monitoring system required by validation procedures of paragraph performance requirements of this part, this part, which includes the automated (b)(3) of this section are used for the or if the certification (or recertification) data acquisition and handling system, initial certification (or recertification) of application is incomplete and the and, where applicable, the CO2 a continuous emissions monitoring requirement for disapproval under continuous emission monitoring system, system, the date and time of provisional paragraph (a)(4)(ii) of this section has meets the initial certification certification (or recertification) of the been met, the Administrator shall issue requirements of this section and shall CEMS may be earlier than the date and a written notice of disapproval of the ensure that all applicable initial time of completion of the required certification (or recertification) certification tests under paragraph (c) of certification (or recertification) tests. application within 120 days of receipt. this section are completed by the (4) Certification (or recertification) By issuing the notice of disapproval, the deadlines specified in § 75.4 and prior application formal approval process. provisional certification (or to use in the Acid Rain Program. In The Administrator will issue a notice of recertification) is invalidated by the addition, whenever the owner or approval or disapproval of the Administrator, and the data measured operator installs a continuous emission certification (or recertification) and recorded by each uncertified or opacity monitoring system in order to application to the owner or operator continuous emission or opacity meet the requirements of §§ 75.11 within 120 days of receipt of the monitoring system or component through 75.18, where no continuous complete certification (or recertification) thereof shall not be considered valid emission or opacity monitoring system application. In the event the quality-assured data as follows: from the was previously installed, initial Administrator does not issue such a hour of the probationary calibration certification is required. notice within 120 days of receipt, each error test that began the initial (1) Notification of initial certification continuous emission or opacity certification (or recertification) test test dates. The owner or operator or monitoring system which meets the period (if the data validation procedures designated representative shall submit a performance requirements of this part of paragraph (b)(3) of this section were written notice of the dates of initial and is included in the certification (or used to retrospectively validate data); or certification testing at the unit as recertification) application will be from the date and time of completion of specified in § 75.61(a)(1). deemed certified (or recertified) for use the invalid certification or * * * * * under the Acid Rain Program. recertification tests (if the data (3) Provisional approval of (i) Approval notice. If the certification validation procedures of paragraph certification (or recertification) (or recertification) application is (b)(3) of this section were not used), applications. Upon the successful complete and shows that each until the date and time that the owner completion of the required certification continuous emission or opacity or operator completes subsequently (or recertification) procedures of this monitoring system meets the approved initial certification or section for each continuous emission or performance requirements of this part, recertification tests. The owner or opacity monitoring system or then the Administrator will issue a operator shall follow the procedures for component thereof, continuous notice of approval of the certification (or loss of initial certification in paragraph emission or opacity monitoring system recertification) application within 120 (a)(5) of this section for each continuous or component thereof shall be deemed days of receipt. emission or opacity monitoring system provisionally certified (or recertified) for (ii) Incomplete application notice. A or component thereof which is use under the Acid Rain Program for a certification (or recertification) disapproved for initial certification. For period not to exceed 120 days following application will be considered complete each disapproved recertification, the receipt by the Administrator of the when all of the applicable information owner or operator shall follow the complete certification (or recertification) required to be submitted in § 75.63 has procedures of paragraph (b)(5) of this application under paragraph (a)(4) of been received by the Administrator, the section. this section. Notwithstanding this EPA Regional Office, and the * * * * * paragraph, no continuous emission or appropriate State and/or local air (5) * * * opacity monitor systems for a pollution control agency. If the (i) Until such time, date, and hour as combustion source seeking to enter the certification (or recertification) the continuous emission monitoring Opt-in Program in accordance with part application is not complete, then the system or component thereof can be 74 of this chapter shall be deemed Administrator will issue a notice of adjusted, repaired, or replaced and provisionally certified (or recertified) for incompleteness that provides a certification tests successfully use under the Acid Rain Program. Data reasonable timeframe for the designated completed, the owner or operator shall measured and recorded by a representative to submit the additional substitute the following values, as provisionally certified (or recertified) information required to complete the applicable, for each hour of unit continuous emission or opacity certification (or recertification) operation during the period of invalid monitoring system or component application. If the designated data specified in paragraph (a)(4)(iii) of thereof, operated in accordance with the representative has not complied with this section or in § 75.21: the maximum requirements of appendix B to this part, the notice of incompleteness by a potential concentration of SO2, as will be considered valid quality-assured specified due date, then the defined in section 2.1.1.1 of appendix A data (retroactive to the date and time of Administrator may issue a notice of to this part, to report SO2 concentration; provisional certification or disapproval specified under paragraph the maximum potential NOX emission recertification), provided that the (a)(4)(iii) of this section. The 120-day rate, as defined in § 72.2 of this chapter, Administrator does not invalidate the review period shall not begin prior to to report NOX emissions in lb/mmBtu; provisional certification (or receipt of a complete application. the maximum potential concentration of

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NOX, as defined in section 2.1.2.1 of recertification event; however, records initial certifications (see sections 6.2(a), appendix A to this part, to report NOX of the polynomial coefficients or K 6.3.1(a), 6.3.2(a), 6.4(a) and 6.5(f) of emissions in ppm (when a NOX factor (s) currently in use shall be appendix A to this part) and may be concentration monitoring system is used maintained on-site in a format suitable used to supplement the linearity check to determine NOX mass emissions, as for inspection. Changing the coefficient and RATA data validation procedures in defined under § 75.71(a)(2)); the or K factor(s) of a moisture monitoring sections 2.2.3(b) and 2.3.2(b) of maximum potential flow rate, as defined system shall require a RATA, but is not appendix B to this part. in section 2.1.4.1 of appendix A to this considered to be a recertification event; (i) In the period extending from the part, to report volumetric flow; the however, records of the coefficient or K hour of the replacement, modification or maximum potential concentration of factor (s) currently in use by the change made to a monitoring system CO2, as defined in section 2.1.3.1 of moisture monitoring system shall be that triggers the need to perform appendix A to this part, to report CO2 maintained on-site in a format suitable recertification test(s) of the CEMS to the concentration data; and either the for inspection. In such cases, any other hour of successful completion of a minimum potential moisture tests that are necessary to ensure probationary calibration error test percentage, as defined in section 2.1.5 of continued proper operation of the (according to paragraph (b)(3)(ii) of this appendix A to this part or, if Equation monitoring system (e.g., 3-load flow section) following the replacement, 19–3, 19–4 or 19–8 in Method 19 in RATAs following changes to flow modification, or change to the CEMS, appendix A to part 60 of this chapter is monitor polynomial coefficients, the owner or operator shall either used to determine NOX emission rate, linearity checks, calibration error tests, substitute for missing data, according to the maximum potential moisture DAHS verifications, etc.) shall be the standard missing data procedures in percentage, as defined in section 2.1.6 of performed as diagnostic tests, rather §§ 75.33 through 75.37, or report appendix A to this part; and than as recertification tests. The data emission data using a reference method or another monitoring system that has * * * * * validation procedures in paragraph been certified or approved for use under (b) Recertification approval process. (b)(3) of this section shall be applied to this part. Notwithstanding this Whenever the owner or operator makes RATAs associated with changes to flow or moisture monitor coefficients, and to requirement, if the replacement, a replacement, modification, or change linearity checks, 7-day calibration error modification, or change requiring in a certified continuous emission tests, and cycle time tests, when these recertification of the CEMS is such that monitoring system or continuous are required as diagnostic tests. When the historical data stream is no longer opacity monitoring system that may the data validation procedures of representative (e.g., where the SO2 significantly affect the ability of the paragraph (b)(3) of this section are concentration and stack flow rate system to accurately measure or record applied in this manner, replace the change significantly after installation of the SO2 or CO2 concentration, stack gas word ‘‘recertification’’ with the word a wet scrubber), the owner or operator volumetric flow rate, NOX emission rate, ‘‘diagnostic.’’ shall substitute for missing data as percent moisture, or opacity, or to meet (1) Tests required. For all follows, in the period extending from the requirements of § 75.21 or appendix recertification testing, the owner or the hour of commencement of the B to this part, the owner or operator operator shall complete all initial replacement, modification, or change shall recertify the continuous emission certification tests in paragraph (c) of this requiring recertification of the CEMS to monitoring system or continuous section that are applicable to the the hour of commencement of the opacity monitoring system, according to monitoring system, except as otherwise recertification test period: For a change the procedures in this paragraph. approved by the Administrator. For that results in a significantly higher Furthermore, whenever the owner or diagnostic testing after changing the concentration or flow rate, substitute operator makes a replacement, flow rate monitor polynomial maximum potential values according to modification, or change to the flue gas coefficients, the owner or operator shall the procedures in paragraph (a)(5) of handling system or the unit operation complete a 3-level RATA. For diagnostic this section; or for a change that results that may significantly change the flow testing after changing the K factor or in a significantly lower concentration or or concentration profile, the owner or mathematical algorithm of a moisture flow rate, substitute data using the operator shall recertify the monitoring monitoring system, the owner or standard missing data procedures. The system according to the procedures in operator shall complete a RATA. owner or operator shall then use the this paragraph. Examples of changes (2) Notification of recertification test initial missing data procedures in which require recertification include: dates. The owner, operator, or § 75.31, beginning with the first hour of replacement of the analyzer; change in designated representative shall submit quality assured data obtained with the location or orientation of the sampling notice of testing dates for recertification recertified monitoring system, unless probe or site; and complete replacement under this paragraph as specified in otherwise provided by § 75.34 for units of an existing continuous emission § 75.61(a)(1)(ii), unless all of the tests in with add-on emission controls. The first monitoring system or continuous paragraph (c) of this section are not hour of quality-assured data for the opacity monitoring system. The owner required for recertification, in which recertified monitoring system shall be or operator shall recertify a continuous case the owner or operator shall provide determined in accordance with opacity monitoring system whenever notice in accordance with the notice paragraphs (b)(3)(ii) through (b)(3)(ix) of the monitor path length changes or as provisions for initial certification testing this section. required by an applicable State or local in § 75.61(a)(1)(i). (ii) Once the modification or change regulation or permit. Any change to a (3) Recertification test period to the CEMS has been completed and all flow monitor or gas monitoring system requirements and data validation. The of the associated repairs, component for which a RATA is not necessary shall data validation provisions in paragraphs replacements, adjustments, not be considered a recertification (b)(3)(i) through (b)(3)(ix) of this section linearization, and reprogramming of the event. In addition, changing the shall apply to all CEMS recertifications CEMS have been completed, a polynomial coefficients or K factor(s) of and diagnostic testing. The provisions probationary calibration error test is a flow monitor shall require a 3-load in paragraphs (b)(3)(ii) through (b)(3)(ix) required to establish the beginning point RATA, but is not considered to be a of this section may also be applied to of the recertification test period. In this

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The period, data validation shall be done as again; probationary calibration error test must follows: (C) If a 7-day calibration error test is be passed before any of the required (A) If any required recertification test failed within the recertification test recertification tests are commenced. is failed, it shall be repeated. If any period, previously-recorded (iii) Beginning with the hour of recertification test other than a 7-day conditionally valid emission data from commencement of a recertification test calibration error test is failed or aborted the CEMS are not invalidated. The period, emission data recorded by the due to a problem with the CEMS, the conditionally valid data status is CEMS are considered to be original recertification test period is unaffected, unless the calibration error conditionally valid, contingent upon the ended, and a new recertification test on the day of the failed 7-day calibration results of the subsequent recertification period must be commenced with a error test exceeds twice the performance tests. probationary calibration error test. The specification in section 3 of appendix A (iv) Each required recertification test tests that are required in the new to this part, as described in paragraph shall be completed no later than the recertification test period will include (b)(3)(vii)(D) of this section; and following number of unit operating any tests that were required for the (D) If a daily calibration error test is hours (or unit operating days) after the initial recertification event which were failed during a recertification test period probationary calibration error test that not successfully completed and any (i.e., the results of the test exceed twice initiates the test period: recertification or diagnostic tests that the performance specification in section are required as a result of changes made 3 of appendix A to this part), the CEMS (A) For a linearity check and/or cycle to the monitoring system to correct the is out-of-control as of the hour in which time test, 168 consecutive unit operating problems that caused the failure of the the calibration error test is failed. hours, as defined in § 72.2 of this recertification test. For a 2- or 3-load Emission data from the CEMS shall be chapter or, for CEMS installed on flow RATA, if the relative accuracy test invalidated prospectively from the hour common stacks or bypass stacks, 168 is passed at one or more load levels, but of the failed calibration error test until consecutive stack operating hours, as is failed at a subsequent load level, the hour of completion of a subsequent defined in § 72.2 of this chapter; provided that the problem that caused successful calibration error test (B) For a RATA (whether normal-load the RATA failure is corrected without following corrective action, at which or multiple-load), 720 consecutive unit re-linearizing the instrument, the length time the conditionally valid status of operating hours, as defined in § 72.2 of of the new recertification test period data from the monitoring system this chapter or, for CEMS installed on shall be equal to the number of unit resumes. Failure to perform a required common stacks or bypass stacks, 720 operating hours remaining in the daily calibration error test during a consecutive stack operating hours, as original recertification test period, as of recertification test period shall also defined in § 72.2 of this chapter; and the hour of failure of the RATA. cause data from the CEMS to be (C) For a 7-day calibration error test, However, if re-linearization of the flow invalidated prospectively, from the hour 21 consecutive unit operating days, as monitor is required after a flow RATA in which the calibration error test was defined in § 72.2 of this chapter. is failed at a particular load level, then due until the hour of completion of a (v) All recertification tests shall be a subsequent 3-load RATA is required, subsequent successful calibration error performed hands-off. No adjustments to and the new recertification test period test. Whenever a calibration error test is the calibration of the CEMS, other than shall be 720 consecutive unit (or stack) failed or missed during a recertification the routine calibration adjustments operating hours. The new recertification test period, no further recertification following daily calibration error tests as test sequence shall not be commenced tests shall be performed until the described in section 2.1.3 of appendix B until all necessary maintenance required subsequent calibration error to this part, are permitted during the activities, adjustments, linearizations, test has been passed, re-establishing the recertification test period. Routine daily and reprogramming of the CEMS have conditionally valid status of data from calibration error tests shall be performed been completed; the monitoring system. If a calibration throughout the recertification test (B) If a linearity check, RATA, or error test failure occurs while a linearity period, in accordance with section 2.1.1 cycle time test is failed or aborted due check or RATA is still in progress, the of appendix B to this part. The to a problem with the CEMS, all linearity check or RATA must be re- additional calibration error test conditionally valid emission data started. requirements in section 2.1.3 of recorded by the CEMS are invalidated, (E) Trial gas injections and trial RATA appendix B to this part shall also apply from the hour of commencement of the runs are permissible during the during the recertification test period. recertification test period to the hour in recertification test period, prior to (vi) If all of the required which the test is failed or aborted, commencing a linearity check or RATA, recertification tests and required daily except for the case in which a multiple- for the purpose of optimizing the calibration error tests are successfully load flow RATA is passed at one or performance of the CEMS. The results of completed in succession with no more load levels, failed at a subsequent such gas injections and trial runs shall failures, and if each recertification test load level, and the problem that caused not affect the status of previously- is completed within the time period the RATA failure is corrected without recorded conditionally valid data or specified in paragraph (b)(3)(iv)(A), (B), re-linearizing the instrument. In that result in termination of the or (C) of this section, then all of the case, data invalidation shall be recertification test period, provided that conditionally valid emission data prospective, from the hour of failure of the following specifications and recorded by the CEMS shall be the RATA until the commencement of conditions are met: considered quality assured, from the the new recertification test period. Data (1) For gas injections, the stable, hour of commencement of the from the CEMS remain invalid until the ending monitor response is within ±5

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The procedures for reference method value or ±15 ppm, or completed in a subsequent quarter, the provisional certification in paragraph ±1.5% H2O, or ±0.02 lb/mmBtu from the owner or operator shall indicate this by (a)(3) of this section shall apply to average reference method value, as means of a suitable conditionally valid recertification applications. The applicable; data flag in the electronic quarterly Administrator will issue a notice of (3) No adjustments to the calibration report for that quarter. The owner or approval, disapproval, or of the CEMS are made following the operator shall resubmit the report for incompleteness according to the trial injection(s) or run(s), other than the that quarter if the required procedures in paragraph (a)(4) of this adjustments permitted under section recertification test is subsequently section. In the event that a 2.1.3 of appendix B to this part; and failed. In the resubmitted report, the recertification application is (4) The CEMS is not repaired, re- owner or operator shall use the disapproved, data from the monitoring linearized or reprogrammed (e.g., appropriate missing data routine in system are invalidated and the changing flow monitor polynomial § 75.31 or § 75.33 to replace with applicable missing data procedures in coefficients, linearity constants, or K- substitute data each hour of § 75.31 or § 75.33 shall be used from the factors) after the trial injection(s) or conditionally valid data that was date and hour of receipt of the run(s). invalidated by the failed recertification disapproval notice back to the hour of (F) If the results of any trial gas test. Alternatively, if any required the probationary calibration error test that began the recertification test period. injection(s) or RATA run(s) are outside recertification test is not completed by Data from the monitoring system remain the limits in paragraphs (b)(3)(vii)(E)(1) the end of a particular calendar quarter invalid until a subsequent probationary or (2) of this section or if the CEMS is but is completed no later than 30 days calibration error test is passed, repaired, re-linearized or reprogrammed after the end of that quarter (i.e., prior beginning a new recertification test after the trial injection(s) or run(s), the to the deadline for submitting the period. The owner or operator shall trial injection(s) or run(s) shall be quarterly report under § 75.64), the test repeat all recertification tests or other counted as a failed linearity check or data and results may be submitted with requirements, as indicated in the RATA attempt. If this occurs, follow the the earlier quarterly report even though Administrator’s notice of disapproval, procedures pertaining to failed and the test date(s) are from the next calendar quarter. In such instances, if no later than 30 unit operating days aborted recertification tests in after the date of issuance of the notice paragraphs (b)(3)(vii)(A) and the recertification test(s) are passed in accordance with the provisions of of disapproval. The designated (b)(3)(vii)(B) of this section. representative shall submit a (viii) If any required recertification paragraph (b)(3) of this section, conditionally valid data may be notification of the recertification retest test is not completed within its allotted dates, as specified in § 75.61(a)(1)(ii), time period, data validation shall be reported as quality-assured, in lieu of reporting a conditional data flag. If the and shall submit a new recertification done as follows. For a late linearity test, application according to the procedures recertification test(s) is failed and if RATA, or cycle time test that is passed in paragraph (b)(4) of this section. conditionally valid data are replaced, as on the first attempt, data from the (c) Initial certification and monitoring system shall be invalidated appropriate, with substitute data, then recertification procedures. Prior to the from the hour of expiration of the neither the reporting of a conditional deadline in § 75.4, the owner or operator recertification test period until the hour data flag nor resubmission is required. shall conduct initial certification tests of completion of the late test. For a late In addition, if the owner or operator and in accordance with § 75.63, the 7-day calibration error test, whether or uses a conditionally valid data flag in designated representative shall submit not it is passed on the first attempt, data any of the four quarterly reports for a an application to demonstrate that the from the monitoring system shall also be given year, the owner or operator shall continuous emission or opacity invalidated from the hour of expiration indicate the final status of the monitoring system and components of the recertification test period until conditionally valid data (i.e., resolved or thereof meet the specifications in the hour of completion of the late test. unresolved) in the annual compliance appendix A to this part. The owner or For a late linearity test, RATA, or cycle certification report required under operator shall compare reference time test that is failed on the first § 72.90 of this chapter for that year. The method values with output from the attempt or aborted on the first attempt Administrator may invalidate any automated data acquisition and due to a problem with the monitor, all conditionally valid data that remains handling system that is part of the conditionally valid data from the unresolved at the end of a particular continuous emission monitoring system monitoring system shall be considered calendar year and may require the being tested. Except as specified in invalid back to the hour of the first owner or operator to resubmit one or paragraphs (b)(1), (d), and (e) of this probationary calibration error test which more of the quarterly reports for that section, the owner or operator shall initiated the recertification test period. calendar year, replacing the unresolved perform the following tests for initial Data from the monitoring system shall conditionally valid data with substitute certification or recertification of remain invalid until the hour of data values determined in accordance continuous emission or opacity successful completion of the late with § 75.31 or § 75.33, as appropriate. monitoring systems or components recertification test and any additional (4) Recertification application. The according to the requirements of recertification or diagnostic tests that designated representative shall apply for appendix A to this part: are required as a result of changes made recertification of each continuous (1) For each SO2 pollutant to the monitoring system to correct emission or opacity monitoring system concentration monitor, each NOX problems that caused failure of the late used under the Acid Rain Program. The concentration monitoring system used recertification test. owner or operator shall submit the to determine NOX mass emissions, as

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At a minimum, the the tests in paragraph (c) of this section emission monitoring system, the test is demonstration shall be made at three are required for initial certification of performed separately on the NOX different temperatures covering the the system, except for the 7-day pollutant concentration monitor and the normal range of stack temperatures from calibration error test. diluent gas monitor; low to high. (ii) For a like-kind replacement non- (ii) A linearity check, where, for the (ii) [Reserved] redundant backup analyzer (i.e., a non- NOX-diluent continuous emission (8) The owner or operator shall ensure redundant backup analyzer that uses the monitoring system, the test is performed that initial certification or recertification same probe and sample interface as a separately on the NOX pollutant of a continuous opacity monitor for use primary monitoring system), no initial concentration monitor and the diluent under the Acid Rain Program is certification of the analyzer is required. gas monitor; conducted according to one of the A non-redundant backup analyzer, (iii) A relative accuracy test audit. For following procedures: connected to the same probe and the NOX-diluent continuous emission (i) Performance of the tests for initial interface as a primary CEMS in order to monitoring system, the RATA shall be certification or recertification, according satisfy the dual span requirements of done on a system basis, in units of lb/ to the requirements of Performance section 2.1.1.4 or 2.1.2.4 of appendix A mmBtu. For the NOX concentration Specification 1 in appendix B to part 60 to this part, shall be treated in the same monitoring system, the RATA shall be of this chapter; or manner as a like-kind replacement done on a ppm basis. * * * * * analyzer. (iii) Each non-redundant backup * * * * * (10) The owner or operator shall CEMS or like-kind replacement analyzer (3) The initial certification test data provide adequate facilities for initial shall comply with the daily and from an O2 or a CO2 diluent gas monitor certification or recertification testing quarterly quality assurance and quality certified for use in a NOX continuous that include: control requirements in appendix B to emission monitoring system may be * * * * * this part for each day and quarter that submitted to meet the requirements of (d) Initial certification and the non-redundant backup CEMS or paragraph (c)(4) of this section. Also, for recertification and quality assurance like-kind replacement analyzer is used a diluent monitor that is used both as a procedures for optional backup to report data, and shall meet the CO2 monitoring system and to continuous emission monitoring additional linearity and calibration error determine heat input, only one set of systems. (1) Redundant backups. The test requirements specified in this diluent monitor certification data need owner or operator of an optional paragraph. The owner or operator shall be submitted (under the component and redundant backup CEMS shall comply ensure that each non-redundant backup system identification numbers of the with all the requirements for initial CEMS or like-kind replacement analyzer CO2 monitoring system). certification and recertification passes a linearity check (for pollutant (4) For each CO2 pollutant according to the procedures specified in concentration and diluent gas monitors) concentration monitor, each O2 monitor paragraphs (a), (b), and (c) of this or a calibration error test (for flow which is part of a CO2 continuous section. The owner or operator shall monitors) prior to each use for recording emission monitoring system, each operate the redundant backup CEMS and reporting emissions. For a primary diluent monitor used to monitor heat during all periods of unit operation, NOX-diluent or SO2-diluent CEMS input and each SO2-diluent continuous except for periods of calibration, quality consisting of the primary pollutant emission monitoring system: assurance, maintenance, or repair. The analyzer and a like-kind replacement * * * * * owner or operator shall perform upon diluent analyzer (or vice-versa), (5) For each continuous moisture the redundant backup CEMS all quality provided that the primary pollutant or monitoring system consisting of wet- assurance and quality control diluent analyzer (as applicable) is and dry-basis O2 analyzers: procedures specified in appendix B to operating and is not out-of-control with (i) A 7-day calibration error test of this part, except that the daily respect to any of its quality assurance each O2 analyzer; assessments in section 2.1 of appendix requirements, only the like-kind (ii) A cycle time test of each O2 B to this part are optional for days on replacement analyzer must pass a analyzer; which the redundant backup CEMS is linearity check before the system is used (iii) A linearity test of each O2 not used to report emission data under for data reporting. When a non- analyzer; and this part. For any day on which a redundant backup CEMS or like-kind (iv) A RATA, directly comparing the redundant backup CEMS is used to replacement analyzer is brought into percent moisture measured by the report emission data, the system must service, prior to conducting the linearity monitoring system to a reference meet all of the applicable daily test, a probationary calibration error test method. assessment criteria in appendix B to this (as described in paragraph (b)(3)(ii) of (6) For each continuous moisture part. this section), which will begin a period sensor: A RATA, directly comparing the (2) Non-redundant backups. The of conditionally valid data, may be percent moisture measured by the owner or operator of an optional non- performed in order to allow the monitor sensor to a reference method. redundant backup CEMS or like-kind validation of data retrospectively, as (7) For a continuous moisture replacement analyzer shall comply with follows. Conditionally valid data from monitoring system consisting of a all of the following requirements for the CEMS or like-kind replacement temperature sensor and a data initial certification, quality assurance, analyzer are validated back to the hour acquisition and handling system recertification, and data reporting: of completion of the probationary (DAHS) software component (i) Except as provided in paragraph calibration error test if the following programmed with a moisture lookup (d)(2)(v) of this section, for a regular conditions are met: if no adjustments table: non-redundant backup CEMS (i.e., a are made to the CEMS or like-kind

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00035 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28598 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations replacement analyzer other than the to report data from that unit or stack (1) Initial certification and allowable calibration adjustments until the hour of completion of a recertification testing. The owner or specified in section 2.1.3 of appendix B passing RATA at that location. operator shall use the following to this part between the probationary (vii) Each regular non-redundant procedures for initial certification and calibration error test and the successful backup CEMS shall be represented in recertification of an excepted completion of the linearity test; and if the monitoring plan required under monitoring system under appendix D or the linearity test is passed within 168 § 75.53 as a separate monitoring system, E to this part. unit (or stack) operating hours of the with unique system and component (i) When the optional SO2 mass probationary calibration error test. identification numbers. When like-kind emissions estimation procedure in However, if the linearity test is either replacement non-redundant backup appendix D to this part or the optional failed, aborted due to a problem with analyzers are used, the owner or NOX emissions estimation protocol in the CEMS or like-kind replacement operator shall represent each like-kind appendix E to this part is used, the analyzer, or is not completed as replacement analyzer used during a owner or operator shall provide data required, then all of the conditionally particular calendar quarter in the from a flowmeter accuracy test (or shall valid data are invalidated back to the monitoring plan required under § 75.53 provide a statement of calibration if the hour of the probationary calibration as a component of a primary monitoring flowmeter meets the accuracy standard error test, and data from the non- system. The owner or operator shall also by design) for each fuel flowmeter, redundant backup CEMS or from the assign a unique component according to section 2.1.5.1 of appendix primary monitoring system of which the identification number to each like-kind D to this part. like-kind replacement analyzer is a part replacement analyzer and specify the * * * * * remain invalid until the hour of manufacturer, model and serial number (2) Initial certification and completion of a successful linearity test. of the like-kind replacement analyzer. recertification testing notification. The (iv) When data are reported from a designated representative shall provide non-redundant backup CEMS or like- This information may be added, deleted or updated as necessary, from quarter to initial certification testing notification kind replacement analyzer, the and routine periodic retesting appropriate bias adjustment factor shall quarter. The owner or operator shall also report data from the like-kind notification for an excepted monitoring be determined as follows: system under appendix E to this part as (A) For a regular non-redundant replacement analyzer using the system specified in § 75.61. The designated backup CEMS, as described in identification number of the primary representative shall also submit paragraph (d)(2)(i) of this section, apply monitoring system and the assigned recertification testing notification, as the bias adjustment factor from the most component identification number of the specified in § 75.61, for quality recent RATA of the non-redundant like-kind replacement analyzer. For the backup system (even if that RATA was purposes of the electronic quarterly assurance related NOX emission rate re- done more than 12 months previously); report required under § 75.64, the owner testing under section 2.3 of appendix E or or operator may manually enter the to this part for an excepted monitoring (B) When a like-kind replacement appropriate component identification system under appendix E to this part. non-redundant backup analyzer is used number(s) of any like-kind replacement Initial certification testing notification as a component of a primary CEMS (as analyzer(s) used for data reporting or periodic retesting notification is not described in paragraph (d)(2)(ii) of this during the quarter. required for testing of a fuel flowmeter or for testing of an excepted monitoring section), apply the primary monitoring (viii) When reporting data from a system under appendix D to this part. system bias adjustment factor. certified regular non-redundant backup (v) For each parameter monitored (i.e., CEMS, use a method of determination * * * * * SO2, CO2, NOX or flow rate) at each unit (MODC) code of ‘‘02.’’ When reporting (4) Initial certification or or stack, a regular non-redundant data from a like-kind replacement non- recertification application. The backup CEMS may not be used to report redundant backup analyzer, use a designated representative shall submit data at that affected unit or common MODC of ‘‘17’’ (see Table 4a under an initial certification or recertification stack for more than 720 hours in any § 75.57). For the purposes of the application in accordance with §§ 75.60 one calendar year, unless the CEMS electronic quarterly report required and 75.63. passes a RATA at that unit or stack. For under § 75.64, the owner or operator (5) Provisional approval of initial each parameter monitored (SO2, CO2 or may manually enter the required MODC certification and recertification NOX) at each unit or stack, the use of a of ‘‘17’’ for a like-kind replacement applications. Upon the successful like-kind replacement non-redundant analyzer. completion of the required initial backup analyzer (or analyzers) is certification or recertification restricted to 720 cumulative hours per * * * * * procedures for each excepted calendar year, unless the owner or (g) Initial certification and monitoring system under appendix D or operator redesignates the like-kind recertification procedures for excepted E to this part, each excepted monitoring replacement analyzer(s) as monitoring systems under appendices D system under appendix D or E to this component(s) of regular non-redundant and E. The owner or operator of a gas- part shall be deemed provisionally backup CEMS and each redesignated fired unit, oil-fired unit, or diesel-fired certified for use under the Acid Rain CEMS passes a RATA at that unit or unit using the optional protocol under Program during the period for the stack. appendix D or E to this part shall ensure Administrator’s review. The provisions (vi) For each regular non-redundant that an excepted monitoring system for the initial certification or backup CEMS, no more than eight under appendix D or E to this part meets recertification application formal successive calendar quarters shall the applicable general operating approval process in paragraph (a)(4) of elapse following the quarter in which requirements of § 75.10, the applicable this section shall apply, except that the the last RATA of the CEMS was done at requirements of appendices D and E to term ‘‘excepted monitoring system’’ a particular unit or stack, without this part, and the initial certification or shall apply rather than ‘‘continuous performing a subsequent RATA. recertification requirements of this emission or opacity monitoring system’’ Otherwise, the CEMS may not be used paragraph. and except that the procedures for loss

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Revising paragraphs (a)(2), (a)(4), certifies that a particular unit with an E to this part will be considered quality (a)(5), (a)(6), and (e); SO2 monitoring system combusts assured data from the date and time of b. Redesignating existing paragraphs primarily fuel(s) that are very low sulfur completion of the last initial (a)(7) and (a)(8) as paragraphs (a)(9) and fuel(s) (as defined in § 72.2 of this certification or recertification test, (a)(10), respectively; and revising newly chapter), and combusts higher sulfur provided that the Administrator does designated paragraphs (a)(9) and (a)(10); fuel (s) only as emergency backup not revoke the provisional certification and fuel(s) or for short-term testing, the SO2 or recertification by issuing a notice of c. Adding new paragraphs (a)(7) and monitoring system shall be exempted disapproval in accordance with the (a)(8) to read as follows: from the RATA requirements of provisions in paragraph (a)(4) or (b)(5) appendices A and B to this part in any § 75.21 Quality assurance and quality calendar year that the unit combusts the of this section. control requirements. (6) Recertification requirements. higher-sulfur fuel(s) for no more than Recertification of an excepted (a) * * * 480 hours. If, in a particular calendar (2) The owner or operator shall ensure monitoring system under appendix D or year, the higher-sulfur fuel usage that each non-redundant backup CEMS E to this part is required for any exceeds 480 hours, the owner or meets the quality assurance modification to the system or change in operator shall perform a RATA of the requirements of § 75.20(d) for each day operation that could significantly affect SO2 monitor (while combusting the the ability of the system to accurately and quarter that the system is used to higher-sulfur fuel) either by the end of account for emissions and for which the report data. the calendar quarter in which the Administrator determines that an * * * * * exceedance occurs or by the end of a accuracy test of the fuel flowmeter or a (4) The owner or operator of a unit 720 unit (or stack) operating hour grace retest under appendix E to this part to with an SO2 continuous emission period (under section 2.3.3 of appendix re-establish the NOX correlation curve is monitoring system is not required to B to this part) following the quarter in required. Examples of such changes or perform the daily or quarterly which the exceedance occurs. modifications include fuel flowmeter assessments of the SO2 monitoring (8) On and after April 1, 2000, the replacement, changes in unit system under appendix B to this part on quality assurance provisions of configuration, or exceedance of any day or in any calendar quarter in §§ 75.11(e)(3)(i) through 75.11(e)(3)(iv) operating parameters. which only gaseous fuel is combusted in shall apply to all units with SO2 (7) Procedures for loss of certification the unit if, during those days and monitoring systems during hours in or recertification for excepted calendar quarters, SO2 emissions are which only very low sulfur fuel (as monitoring systems under appendices D determined in accordance with defined in § 72.2 of this chapter) is and E to this part. In the event that a § 75.11(e)(1) or (e)(2). However, such combusted in the unit. certification or recertification assessments are permissible, and if any (9) Provided that a unit with an SO2 application is disapproved for an daily calibration error test or linearity monitoring system is not exempted excepted monitoring system, data from test of the SO2 monitoring system is under paragraphs (a)(6) or (a)(7) of this the monitoring system are invalidated, failed while the unit is combusting only section from the SO2 RATA and the applicable missing data gaseous fuel, the SO2 monitoring system requirements of this part, any calendar procedures in section 2.4 of appendix D shall be considered out-of-control. The quarter during which a unit combusts or section 2.5 of appendix E to this part length of the out-of-control period shall only very low sulfur fuel (as defined in shall be used from the date and hour of be determined in accordance with the § 72.2 of this chapter) shall be excluded receipt of such notice back to the hour applicable procedures in section 2.1.4 or in determining the quarter in which the of the provisional certification. Data 2.2.3 of appendix B to this part. next relative accuracy test audit must be from the excepted monitoring system (5) For a unit with an SO2 continuous performed for the SO2 monitoring remain invalid until all required tests monitoring system, in which gaseous system. However, no more than eight are repeated and the excepted fuel that is very low sulfur fuel (as successive calendar quarters shall monitoring system is again defined in § 72.2 of this chapter) is elapse after a relative accuracy test audit provisionally certified. The owner or sometimes burned as a primary or of an SO2 monitoring system, without a operator shall repeat all certification or backup fuel and in which higher-sulfur subsequent relative accuracy test audit recertification tests or other fuel(s) such as oil or coal are, at other having been performed. The owner or requirements, as indicated in the times, burned as primary or backup operator shall ensure that a relative Administrator’s notice of disapproval, fuel(s), the owner shall perform the accuracy test audit is performed, in no later than 30 unit operating days relative accuracy test audits of the SO2 accordance with paragraph (a)(5) of this after the date of issuance of the notice monitoring system (as required by section, either by the end of the eighth of disapproval. The designated section 6.5 of appendix A to this part successive elapsed calendar quarter representative shall submit a and section 2.3.1 of appendix B to this since the last RATA or by the end of a notification of the certification or part) only when the higher-sulfur fuel is 720 unit (or stack) operating hour grace recertification retest dates if required combusted in the unit and shall not period, as provided in section 2.3.3 of under paragraph (g)(2) of this section perform SO2 relative accuracy test appendix B to this part. and shall submit a new certification or audits when the very low sulfur gaseous (10) The owner or operator who, in recertification application according to fuel is the only fuel being combusted. accordance with § 75.11(e)(1), uses a the procedures in paragraph (g)(4) of (6) If the designated representative certified flow monitor and a certified this section. certifies that a unit with an SO2 diluent monitor and Equation F–23 in (h) * * * monitoring system burns only very low appendix F to this part to calculate SO2

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Section 75.22 is amended by system or a NOX concentration * * * * * adding a sentence to the end of the monitoring system used to determine (e) Consequences of audits. The introductory text of paragraph (a) and by NOX mass emissions, as defined in owner or operator shall invalidate data revising paragraphs (a)(2), (a)(4), (b)(4) § 75.71(a)(2), is biased low (i.e., the from a continuous emission monitoring and the introductory text of paragraph arithmetic mean of the differences system or continuous opacity (c)(1) to read as follows: between the reference method value and the monitor or monitoring system monitoring system upon failure of an § 75.22 Reference test methods. audit under appendix B to this part or measurements in a relative accuracy test (a) * * * Unless otherwise specified any other audit, beginning with the unit audit exceed the bias statistic in section in this part, use only codified versions operating hour of completion of a failed 7 of appendix A to this part), the owner of Methods 3A, 4, 6C and 7E revised as audit as determined by the or operator shall adjust the monitor or of July 1, 1995 or July 1, 1996 or July Administrator. The owner or operator continuous emission monitoring system 1, 1997. shall not use invalidated data for to eliminate the cause of bias such that reporting either emissions or heat input, * * * * * it passes the bias test or calculate and nor for calculating monitor data (2) Method 2 or its allowable use the bias adjustment factor as availability. alternatives, as provided in appendix A specified in section 2.3.4 of appendix B (1) Audit decertification. Whenever to part 60 of this chapter, except for to this part. both an audit of a continuous emission Methods 2B and 2E, are the reference * * * * * or opacity monitoring system (or methods for determination of component thereof, including the data volumetric flow. Subpart DÐMissing Data Substitution acquisition and handling system), of any * * * * * Procedures (4) Method 4 (either the standard excepted monitoring system under 23. Section 75.30 is amended by procedure described in section 2 of the appendix D or E to this part, or of any revising paragraphs (a)(3) and (a)(4), method or the moisture approximation alternative monitoring system under adding new paragraphs (a)(5) and (a)(6), procedure described in section 3 of the subpart E of this part, and a review of revising the first sentence of paragraph method) shall be used to correct the initial certification application or of (b) and revising paragraph (d) to read as pollutant concentrations from a dry a recertification application, reveal that follows: any system or component should not basis to a wet basis (or from a wet basis have been certified or recertified to a dry basis) and shall be used when § 75.30 General provisions. because it did not meet a particular relative accuracy test audits of (a) * * * performance specification or other continuous moisture monitoring (3) A valid, quality-assured hour of requirement of this part, both at the time systems are conducted. For the purpose NOX emission rate data (in lb/mmBtu) of the initial certification or of determining the stack gas molecular has not been measured or recorded for recertification application submission weight, however, the alternative an affected unit, either by a certified and at the time of the audit, the techniques for approximating the stack NOX-diluent continuous emission Administrator will issue a notice of gas moisture content described in monitoring system or by an approved disapproval of the certification status of section 1.2 of Method 4 may be used in alternative monitoring system under such system or component. For the lieu of the procedures in sections 2 and subpart E of this part; or purposes of this paragraph, an audit 3 of the method. (4) A valid, quality-assured hour of shall be either a field audit of the * * * * * CO2 concentration data (in percent CO2, facility or an audit of any information (b) * * * or percent O2 converted to percent CO2 submitted to EPA or the State agency (4) Method 2, or its allowable using the procedures in appendix F to regarding the facility. By issuing the alternatives, as provided in appendix A this part) has not been measured and notice of disapproval, the certification to part 60 of this chapter, except for recorded for an affected unit, either by status is revoked prospectively by the Methods 2B and 2E, for determining a certified CO2 continuous emission Administrator. The data measured and volumetric flow. The sample point(s) for monitoring system or by an approved recorded by each system shall not be reference methods shall be located alternative monitoring method under considered valid quality-assured data according to the provisions of section subpart E of this part; or from the date of issuance of the 6.5.5 of appendix A to this part. (5) A valid, quality-assured hour of notification of the revoked certification (c)(1) Instrumental EPA Reference NOX concentration data (in ppm) has status until the date and time that the Methods 3A, 6C, 7E, and 20 shall be not been measured or recorded for an owner or operator completes conducted using calibration gases as affected unit, either by a certified NOX subsequently approved initial defined in section 5 of appendix A to concentration monitoring system used certification or recertification tests. The this part. Otherwise, performance tests to determine NOX mass emissions, as owner or operator shall follow the shall be conducted and data reduced in defined in § 75.71(a)(2), or by an procedures in § 75.20(a)(5) for initial accordance with the test methods and approved alternative monitoring system certification or § 75.20(b)(5) for procedures of this part unless the under subpart E of this part; or recertification to replace, prospectively, Administrator: (6) A valid, quality-assured hour of all of the invalid, non-quality-assured * * * * * CO2 or O2 concentration data (in percent data for each disapproved system. 22. Section 75.24 is amended by CO2, or percent O2) used for the (2) Out-of-control period. Whenever a revising the section title and by revising determination of heat input has not continuous emission monitoring system paragraph (d) to read as follows: been measured and recorded for an

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affected unit, either by a certified CO2 § 75.33, for hours when SO2 emissions (1) Whenever prior quality-assured or O2 diluent monitor, or by an are determined in accordance with data exist, the owner or operator shall approved alternative monitoring method § 75.11(e)(1) or (e)(2). For the purpose of substitute, by means of the data under subpart E of this part. the missing data and availability acquisition and handling system, for (b) However, the owner or operator procedures for SO2 pollutant each hour of missing data, the average shall have no need to provide substitute concentration monitors in §§ 75.31 and of the hourly SO2, CO2 or O2 data according to the missing data 75.33 only, all hours during which the concentrations or moisture percentages procedures in this subpart if the owner unit combusts only gaseous fuel shall be recorded by a certified monitor for the or operator uses SO2, CO2, NOX, or O2 excluded from the definition of unit operating hour immediately before concentration, flow rate, or NOX ‘‘monitor operating hour,’’ ‘‘quality and the unit operating hour emission rate data recorded from either assured monitor operating hour,’’ ‘‘unit immediately after the missing data a certified redundant or regular non- operating hour,’’ and ‘‘unit operating period. redundant backup CEMS, a like-kind day,’’ when SO2 emissions are (2) Whenever no prior quality assured replacement non-redundant backup determined in accordance with SO2, CO2 or O2 concentration data or analyzer, or a backup reference method § 75.11(e)(1) or (e)(2). moisture data exist, the owner or monitoring system when the certified (4) During all hours in which a unit operator shall substitute, as applicable, primary monitor is not operating or is with an SO2 continuous emission for each hour of missing data, the out-of-control. * ** monitoring system combusts only maximum potential SO2 concentration * * * * * gaseous fuel and the owner or operator or the maximum potential CO2 (d) The owner or operator shall uses the SO2 monitoring system to concentration or the minimum potential comply with the applicable provisions determine SO2 mass emissions pursuant O2 concentration or (unless Equation of this paragraph during hours in which to § 75.11(e)(3), the owner or operator 19–3, 19–4 or 19–8 in Method 19 in a unit with an SO2 continuous emission shall determine the percent monitor appendix A to part 60 of this chapter is monitoring system combusts only data availability for SO2 in accordance used to determine NOX emission rate) gaseous fuel. with § 75.32 and shall use the standard the minimum potential moisture (1) Whenever a unit with an SO2 SO2 missing data procedures of § 75.33. percentage, as specified, respectively, in CEMS combusts only natural gas or 24. Section 75.31 is revised to read as sections 2.1.1.1, 2.1.3.1, 2.1.3.2 and pipeline natural gas (as defined in § 72.2 follows: 2.1.5 of appendix A to this part. If of this chapter) and the owner or Equation 19–3, 19–4 or 19–8 in Method operator is using the procedures in § 75.31 Initial missing data procedures. 19 in appendix A to part 60 of this section 7 of appendix F to this part to (a) During the first 720 quality- chapter is used to determine NOX determine SO2 mass emissions pursuant assured monitor operating hours emission rate, substitute the maximum to § 75.11(e)(1), the owner or operator following initial certification (i.e., the potential moisture percentage, as shall, for purposes of reporting heat date and time at which quality assured specified in section 2.1.6 of appendix A input data under § 75.54(b)(5) or data begins to be recorded by the CEMS) to this part. § 75.57(b)(5), as applicable, and for the of an SO2 pollutant concentration (c) Volumetric flow and NOX emission calculation of SO2 mass emissions using monitor, or a CO2 pollutant rate or NOX concentration data. For Equation F–23 in section 7 of appendix concentration monitor (or an O2 monitor each hour of missing volumetric flow F to this part, substitute for missing data used to determine CO2 concentration in rate data, NOX emission rate data or from a flow monitoring system, CO2 accordance with appendix F to this NOX concentration data used to diluent monitor or O2 diluent monitor part), or an O2 or CO2 diluent monitor determine NOX mass emissions: using the missing data substitution used to calculate heat input or a (1) Whenever prior quality-assured procedures in § 75.36. moisture monitoring system, and during data exist in the load range (2) Whenever a unit with an SO2 the first 2,160 quality-assured monitor corresponding to the operating load at CEMS combusts gaseous fuel and the operating hours following initial the time the missing data period owner or operator uses the gas sampling certification of a flow monitor, or a occurred, the owner or operator shall and analysis and fuel flow procedures NOX-diluent monitoring system, or a substitute, by means of the automated in appendix D to this part to determine NOX concentration monitoring system data acquisition and handling system, SO2 mass emissions pursuant to used to determine NOX mass emissions, for each hour of missing data, the § 75.11(e)(2), the owner or operator shall the owner or operator shall provide average hourly flow rate or NOX substitute for missing total sulfur substitute data required under this emission rate or NOX concentration content, gross calorific value, and fuel subpart according to the procedures in recorded by a certified monitoring flowmeter data using the missing data paragraphs (b) and (c) of this section. system. The average flow rate (or NOX procedures in appendix D to this part The owner or operator of a unit shall emission rate or NOX concentration) and shall also, for purposes of reporting use these procedures for no longer than shall be the arithmetic average of all heat input data under § 75.54(b)(5) or three years (26,280 clock hours) data in the corresponding load range as § 75.57(b)(5), as applicable, substitute following initial certification. determined using the procedure in for missing data from a flow monitoring (b) SO2, CO2, or O2 concentration data appendix C to this part. system, CO2 diluent monitor, or O2 and moisture data. For each hour of (2) Whenever no prior quality-assured diluent monitor using the missing data missing SO2 or CO2 pollutant flow or NOX emission rate or NOX substitution procedures in § 75.36. concentration data (including CO2 data concentration data exist for the (3) The owner or operator of a unit converted from O2 data using the corresponding load range, the owner or with an SO2 monitoring system shall not procedures in appendix F of this part), operator shall substitute, for each hour include hours when the unit combusts or missing O2 or CO2 diluent of missing data, the average hourly flow only gaseous fuel in the SO2 data concentration data used to calculate rate or the average hourly NOX emission availability calculations in § 75.32 or in heat input, or missing moisture data, the rate or NOX concentration at the next the calculations of substitute SO2 data owner or operator shall calculate the higher level load range for which using the procedures of either § 75.31 or substitute data as follows: quality-assured data are available.

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(3) Whenever no prior quality assured calculate heat input or a moisture 26. Section 75.33 is amended by flow rate or NOX emission rate or NOX monitoring system; or the first 2,160 revising the title of the section, by concentration data exist for the quality-assured monitor operating hours revising paragraphs (a), (b)(3) and (c), corresponding load range, or any higher of a flow monitor or a NOX-diluent and adding a new paragraph (b)(4) to load range, the owner or operator shall, monitoring system or a NOX read as follows: as applicable, substitute, for each hour concentration monitoring system, the of missing data, the maximum potential § 75.33 Standard missing data procedures owner or operator shall calculate and for SO2, NOX and flow rate. flow rate as specified in section 2.1.4.1 record, by means of the automated data of appendix A to this part or shall (a) Following initial certification (i.e., acquisition and handling system, the the date and time at which quality substitute the maximum potential NOX percent monitor data availability for the emission rate or the maximum potential assured data begins to be recorded by SO2 pollutant concentration monitor, the CEMS) and upon completion of the NOX concentration, as specified in the CO2 pollutant concentration section 2.1.2.1 of appendix A to this first 720 quality-assured monitor monitor, the O2 or CO2 diluent monitor part. operating hours of the SO2 pollutant used to calculate heat input, the concentration monitor or the first 2,160 25. Section 75.32 is amended by moisture monitoring system, the flow revising paragraph (a) introductory text quality assured monitor operating hours monitor, the NOX-diluent monitoring and revising the last sentence in of the flow monitor, NOX-diluent system and the NOX concentration paragraph (a)(3) to read as follows: monitoring system or NOX monitoring system as follows: concentration monitoring system used § 75.32 Determination of monitor data * * * * * to determine NOX mass emissions, the availability for standard missing data (3) * * * The owner or operator of a owner or operator shall provide procedures. substitute data required under this unit with an SO2 monitoring system (a) Following initial certification (i.e., subpart according to the procedures in shall, when SO2 emissions are the date and time at which quality paragraphs (b) and (c) of this section determined in accordance with assured data begins to be recorded by and depicted in Table 1 (SO2) and Table § 75.11(e)(1) or (e)(2), exclude hours in the CEMS), upon completion of: the first 2 of this sectioin (NOX, flow). The 720 quality-assured monitor operating which a unit combusts only gaseous fuel owner or operator of a unit shall from calculations of percent monitor hours of an SO2 pollutant concentration substitute for missing data using only data availability for SO2 pollutant monitor, or a CO2 pollutant quality-assured monitor operating hours concentration monitors, as provided in concentration monitor (or O2 monitor of data from the three years (26,280 used to determine CO2 concentration), § 75.30(d). clock hours) prior to the date and time or an O2 or CO2 diluent monitor used to * * * * * of the missing data period.

TABLE 1.ÐMISSING 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 Method Lookback (percent) outage (hours) 2 period

95 or more ...... N ≤ 24 Average ...... HB/HA. N > 24 For SO2, CO2 and H2O**, the greater of: Average ...... HB/HA. 90th percentile ...... 720 hours.* X For O2, and H2O , the lesser of: Average ...... HB/HA. 10th percentile ...... 720 hours.* 90 or more, but below 95 ...... N ≤ 8 Average ...... HB/HA. N > 8 For SO2, CO2 and H2O**, the greater of: Average ...... HB/HA. 95th percentile ...... 720 hours.* X For O2, and H2O , the lesser of: Average ...... HB/HA. 5th percentile ...... 720 hours.* 80 or more, but below 90 ...... N > 0 For SO2, CO2 and H2O**, ...... Maximum value 1 ...... 720 hours.* X For O2, and H2O : Minimum value1 ...... 720 hours.* Below 80 ...... N > 0 Maximum potential concentration or % (for SO2, CO2 and H2O**) or X Minimum potential concentration or % (for O2, and H2O ) ..... None. 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 § 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.

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TABLE 2.ÐMISSING DATA PROCEDURE FOR NOX-Diluent CEMS, NOX CONCENTRATION CEMS AND FLOW RATE CEMS

Trigger conditions Calculation routines

Monitor data availability Duration (N) of CEMS Load (percent) outage Method Lookback period ranges (hours) 2

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 maximum None ...... No. potential NOX concentration; or max- imum 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 § 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) * * * (ii) For a missing data period greater quality-assured monitor operating hours (3) Whenever the monitor data than 24 hours, substitute, as applicable, at the corresponding unit load range, as availability is at least 80.0 percent but for each missing hour, the greater of: determined using the procedure in less than 90.0 percent, the owner or (A) The 90th percentile hourly flow appendix C to this part; or operator shall substitute for each rate or the 90th percentile NOX emission (B) The average of the hourly flow missing data period the maximum rate or the 90th percentile NOX rates, NOX emission rates or NOX hourly SO2 concentration recorded by concentration recorded by a monitoring concentrations recorded by a monitoring an SO2 pollutant concentration monitor system during the previous 2,160 system for the hour before and the hour during the previous 720 quality-assured quality-assured monitor operating hours after the missing data period. monitor operating hours. at the corresponding unit load range, as (3) Whenever the monitor data (4) Whenever the monitor data determined using the procedure in availability is at least 80.0 percent but availability is less than 80.0 percent, the appendix C to this part; or less than 90.0 percent, the owner or owner or operator shall substitute for (B) The average of the recorded hourly operator shall, by means of the each missing data period the maximum flow rates, NOX emission rates or NOX automated data acquisition and concentrations recorded by a monitoring handling system, substitute, as potential SO2 concentration, as defined in section 2.1.1.1 of appendix A to this system for the hour before and the hour applicable, for each hour of each part. after the missing data period. missing data period, the maximum (2) Whenever the monitor or hourly flow rate or the maximum hourly (c) Volumetric flow rate, NOX continuous emission monitoring system NOX emission rate or the maximum emission rate and NOX concentration data availability is at least 90.0 percent hourly NOX concentration recorded data. For each hour of missing but less than 95.0 percent, the owner or during the previous 2,160 quality- volumetric flow rate data, NOX emission operator shall calculate substitute data assured monitor operating hours at the rate data, or NOX concentration data by means of the automated data corresponding unit load range, as used to determine NOX mass emissions: acquisition and handling system for determined using the procedure in (1) Whenever the monitor or each hour of each missing data period section 2 of appendix C to this part. continuous emission monitoring system according to the following procedures: (4) Whenever the monitor data data availability is equal to or greater (i) For a missing data period of less availability is less than 80.0 percent, the than 95.0 percent, the owner or operator than or equal to 8 hours, substitute, as owner or operator shall substitute, as shall calculate substitute data by means applicable, the arithmetic average applicable, for each hour of each of the automated data acquisition and hourly flow rate or NOX emission rate missing data period, the maximum handling system for each hour of each or NOX concentration recorded by a potential flow rate, as defined in section missing data period according to the monitoring system during the previous 2.1.4.1 of appendix A to this part, or the following procedures: 2,160 quality-assured monitor operating maximum NOX emission rate, as (i) For a missing data period less than hours at the corresponding unit load defined in section 2.1.2.1 of appendix A or equal to 24 hours, substitute, as range, as determined using the to this part, or the maximum potential applicable, for each missing hour, the procedure in appendix C to this part. NOX concentration, as defined in arithmetic average of the flow rates or (ii) For a missing data period greater section 2.1.2.1 of appendix A to this NOX emission rates or NOX than 8 hours, substitute, as applicable, part. concentrations recorded by a monitoring for each missing hour, the greater of: (5) Whenever no prior quality-assured system during the previous 2,160 (A) The 95th percentile hourly flow flow rate data, NOX concentration data quality assured monitor operating hours rate or the 95th percentile NOX emission or NOX emission rate data exist for the at the corresponding unit load range, as rate or the 95th percentile NOX corresponding load range, the owner or determined using the procedure in concentration recorded by a monitoring operator shall substitute, as applicable, appendix C to this part. system during the previous 2,160 for each hour of missing data, the

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Substitute CO2 data for heat in section 2.1.4.1 of appendix A to this (d) Upon completion of 720 quality input determinations shall be provided part. assured monitor operating hours using according to § 75.35(d). Substitute O2 27–28. Section 75.34 is amended by the initial missing data procedures of data for the heat input determinations revising paragraph (a)(3) to read as § 75.31(b), the owner or operator shall shall be provided in accordance with follows: provide substitute data for CO2 the procedures in § 75.33(b), except that concentration data or substitute CO2 the term ‘‘O2 concentration’’ shall apply § 75.34 Units with add-on emission data for heat input determination, as rather than the term ‘‘SO2 controls. applicable, in accordance with the concentration’’ and the term ‘‘O2 diluent (a) * * * procedures in § 75.33(b), except that the monitor’’ shall apply rather than the (3) The designated representative may term ‘‘CO2 concentration’’ shall apply term ‘‘SO2 pollutant concentration petition the Administrator under § 75.66 rather than ‘‘SO2 concentration’’ and the monitor.’’ In addition, the term for approval of site-specific parametric term ‘‘CO2 pollutant concentration ‘‘substitute the lesser of’’ shall apply monitoring procedure(s) for calculating monitor’’ or ‘‘CO2 diluent monitor’’ rather than ‘‘substitute the greater of;’’ substitute data for missing SO2 pollutant shall apply rather than ‘‘SO2 pollutant the terms ‘‘minimum hourly O2 concentration, NOX pollutant concentration monitor.’’ concentration’’ and ‘‘minimum potential concentration, and NOX emission rate 30. Section 75.36 is amended by O2 concentration, as determined under data in accordance with the revising the section heading and section 2.1.3.2 of appendix A to this requirements of paragraphs (b) and (c) of paragraphs (a), (b) and (d) to read as part’’ shall apply rather than, this section and appendix C to this part. follows: respectively, the terms ‘‘maximum The owner or operator shall record the hourly SO2 concentration’’ and data required in appendix C to this part, § 75.36 Missing data procedures for heat input determinations. ‘‘maximum potential SO2 concentration, pursuant to § 75.55(b) or § 75.58(b), as as determined under section 2.1.1.1 of (a) When hourly heat input is applicable. appendix A to this part;’’ and the terms determined using a flow monitoring * * * * * ‘‘10th percentile’’ and ‘‘5th percentile’’ system and a diluent gas (O2 or CO2) 29. Section 75.35 is amended by shall apply rather than, respectively, the monitor, substitute data must be revising paragraphs (a) and (b) and by terms ‘‘90th percentile’’ and ‘‘95th provided to calculate the heat input adding paragraph (d) to read as follows: percentile’’ (see Table 1 of § 75.33). whenever quality assured data are 31. Section 75.37 is added to subpart § 75.35 Missing data procedures for CO 2 unavailable from the flow monitor, the D to read as follows: data. diluent gas monitor, or both. When flow (a) On and after April 1, 2000, the rate data are unavailable, substitute flow § 75.37 Missing data procedures for owner or operator of a unit with a CO2 rate data for the heat input calculation moisture. continuous emission monitoring system shall be provided according to § 75.31 or (a) On and after April 1, 2000, the for determining CO2 mass emissions in § 75.33, as applicable. On and after owner or operator of a unit with a accordance with § 75.10 (or an O2 April 1, 2000, when diluent gas data are continuous moisture monitoring system monitor that is used to determine CO2 unavailable, the owner or operator shall shall substitute for missing moisture concentration in accordance with provide substitute O2 or CO2 data for the data using the procedures of this appendix F to this part) shall substitute heat input calculations in accordance section. Prior to April 1, 2000, the for missing CO2 pollutant concentration with paragraphs (b) and (d) of this owner or operator may substitute for data using the procedures of paragraphs section. Prior to April 1, 2000, the missing moisture data using the (b) and (d) of this section. The owner or operator shall substitute for procedures of this section. procedures of paragraphs (b) and (d) of missing CO2 or O2 concentration data in (b) Where no prior quality assured this section shall also be used on and accordance with either paragraphs (c) moisture data exist, substitute the after April 1, 2000 to provide substitute and (d) or paragraphs (b) and (d) of this minimum potential moisture CO2 data for heat input determination. section. percentage, from section 2.1.5 of Prior to April 1, 2000, the owner or (b) During the first 720 quality appendix A to this part, except when operator shall substitute for missing CO2 assured monitor operating hours Equation 19–3, 19–4 or 19–8 in Method data using either the procedures of following initial certification (i.e., the 19 in appendix A to part 60 of this paragraphs (b) and (c), or paragraphs (b) date and time at which quality assured chapter is used to determine NOX and (d) of this section. data begins to be recorded by the emission rate. If Equation 19–3, 19–4 or (b) During the first 720 quality CEMS), or (for a previously certified 19–8 in Method 19 in appendix A to assured monitor operating hours CO2 or O2 monitor) during the 720 part 60 of this chapter is used to

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determine NOX emission rate, substitute 60 of this chapter, the owner or operator correcting paragraph (c)(1), and adding the maximum potential moisture shall petition the Administrator under paragraphs (e) and (f) to read as follows: percentage, as specified in section 2.1.6 § 75.66(l) for permission to use an (a) General provisions. (1) The of appendix A to this part. alternative moisture missing data provisions of paragraphs (c) and (d) of (c) During the first 720 quality assured procedure. this section shall remain in effect prior monitor operating hours following to April 1, 2000. The owner or operator initial certification (i.e., the date and Subpart EÐAlternative Monitoring shall meet the requirements of either time at which quality assured data Systems paragraphs (a) through (d) or paragraphs begins to be recorded by the moisture 32. Section 75.48 is amended by (a), (b), (e) and (f) of this section prior monitoring system), the owner or revising paragraphs (a)(3)(ii) and (a) to April 1, 2000. On and after April 1, operator shall provide substitute data (3)(iii), and correcting paragraphs 2000, the owner or operator shall meet for moisture according to § 75.31(b). the requirements of paragraphs (a), (b), (d) Upon completion of the first 720 (a)(3)(iv), (a)(3)(viii), (a)(3)(ix), and (a)(3)(xi) to read as follows: (e) and (f) of this section only. In quality-assured monitor operating hours addition, the provisions in paragraphs following initial certification of the § 75.48 Petition for an alternative (e) and (f) of this section that support a moisture monitoring system, the owner monitoring system. regulatory option provided in another or operator shall provide substitute data (a) * * * section of this part must be followed if for moisture as follows: (3) * * * the regulatory option is used prior to (1) Unless Equation 19–3, 19–4 or 19– (ii) Hourly test data for the alternative April 1, 2000. 8 in Method 19 in appendix A to part monitoring system at each required (2) The owner or operator of an 60 of this chapter is used to determine operating level and fuel type. The fuel affected unit shall prepare and maintain NOX emission rate, follow the missing type, operating level and gross unit load a monitoring plan. Except as provided data procedures in § 75.33(b), except shall be recorded. in paragraphs (d) or (f) of this section (as that the term ‘‘moisture percentage’’ (iii) Hourly test data for the applicable), a monitoring plan shall shall apply rather than ‘‘SO2 continuous emissions monitoring contain sufficient information on the concentration;’’ the term ‘‘moisture system at each required operating level continuous emission or opacity monitoring system’’ shall apply rather and fuel type. The fuel type, operating monitoring systems, excepted than the term ‘‘SO2 pollutant level and gross unit load shall be methodology under § 75.19, or excepted concentration monitor;’’ the term recorded. monitoring systems under appendix D ‘‘substitute the lesser of’’ shall apply (iv) Arithmetic mean of the alternative or E to this part and the use of data rather than ‘‘substitute the greater of;’’ monitoring system measurement values, derived from these systems to the terms ‘‘minimum hourly moisture as specified in Equation 25 in § 75.41(c) demonstrate that all unit SO2 emissions, percentage’’ and ‘‘minimum potential of this part, of the continuous emission NOX emissions, CO2 emissions, and moisture percentage, as determined monitoring system values, as specified under section 2.1.5 of appendix A to opacity are monitored and reported. in Equation 26 in § 75.41(c) of this part, (b) Whenever the owner or operator this part’’ shall apply rather than, and of their differences. respectively, the terms ‘‘maximum makes a replacement, modification, or * * * * * change in the certified CEMS, hourly SO2 concentration’’ and (viii) Variance of the measured values continuous opacity monitoring system, ‘‘maximum potential SO2 concentration, as determined under section 2.1.1.1 of for the alternative monitoring system excepted methodology under § 75.19, appendix A to this part;’’ and the terms and of the measured values for the excepted monitoring system under ‘‘10th percentile’’ and ‘‘5th percentile’’ continuous emission monitoring system, appendix D or E to this part, or shall apply rather than, respectively, the as specified in Equation 23 in § 75.41(c) alternative monitoring system under terms ‘‘90th percentile’’ and ‘‘95th of this part. subpart E of this part, including a (ix) F-statistic, as specified in percentile’’ (see Table 1 of § 75.33). change in the automated data (2) When Equation 19–3, 19–4 or 19– Equation 24 in § 75.41(c) of this part. acquisition and handling system or in 8 in Method 19 in appendix A to part * * * * * the flue gas handling system, that affects 60 of this chapter is used to determine (xi) Coefficient of correlation, r, as information reported in the monitoring plan (e.g., a change to a serial number NOX emission rate: specified in Equation 27 in § 75.41(c) of (i) Provided that none of the following this part. for a component of a monitoring system), then the owner or operator equations is used to determine SO2 * * * * * emissions, CO2 emissions or heat input: shall update the monitoring plan. Equation F–2, F–14b, F–16, F–17, or F– Subpart FÐRecordkeeping (c) * * * 18 in appendix F to this part, or Requirements (1) Precertification information, including, as applicable, the Equation 19–5 or 19–9 in Method 19 in § 75.50 [Removed and Reserved] appendix A to part 60 of this chapter, identification of the test strategy, use the missing data procedures in 33. Section 75.50 is removed and protocol for the relative accuracy test § 75.33(b), except that the term reserved. audit, other relevant test information, span calculations, and apportionment ‘‘moisture percentage’’ shall apply § 75.51 [Removed and Reserved] rather than ‘‘SO2 concentration’’ and the strategies under §§ 75.10 through 75.18 34. Section 75.51 is removed and of this part. term ‘‘moisture monitoring system’’ reserved. shall apply rather than ‘‘SO2 pollutant * * * * * concentration monitor;’’ or § 75.52 [Removed and Reserved] (e) Contents of the monitoring plan. (ii) If any of the following equations 35. Section 75.52 is removed and Each monitoring plan shall contain the is used to determine SO2 emissions, CO2 reserved. information in paragraph (e)(1) of this emissions or heat input: Equation F–2, section in electronic format and the F–14b, F–16, F–17, or F–18 in appendix § 75.53 Monitoring plan. information in paragraph (e)(2) of this F to this part, or Equation 19–5 or 19– 36. Section 75.53 is amended by section in hardcopy format. Electronic 9 in Method 19 in appendix A to part revising paragraphs (a) and (b), storage of all monitoring plan

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00043 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28606 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations information, including the hardcopy (F) State or local regulatory agency basis from the backup system). The portions, is permissible provided that a code. formulas must contain all constants and paper copy of the information can be (iv) Identification and description of factors required to derive mass furnished upon request for audit each monitoring component (including emissions or emission rates from purposes. each monitor and its identifiable component/system code observations (1) Electronic. (i) ORISPL numbers components, such as analyzer and/or and an indication of whether the developed by the Department of Energy probe) in the CEMS (e.g., SO2 pollutant formula is being added, corrected, and used in the National Allowance concentration monitor, flow monitor, deleted, or is unchanged. Each Data Base, for all affected units involved moisture monitor; NOX pollutant emissions formula is identified with a in the monitoring plan, with the concentration monitor and diluent gas unique three digit code. The owner or following information for each unit: monitor), the continuous opacity operator of a low mass emissions unit (A) Short name; monitoring system, or the excepted for which the owner or operator is using (B) Classification of the unit as one of monitoring system (e.g., fuel flowmeter, the optional low mass emissions the following: Phase I (including data acquisition and handling system), excepted methodology in § 75.19(c) is substitution or compensating units), including: not required to report such formulas. Phase II, new, or nonaffected; (A) Manufacturer, model number and (vii) Inside cross-sectional area (ft2) at (C) Type of boiler (or boilers for a serial number; flue exit (for all units) and at flow group of units using a common stack); (B) Component/system identification monitoring location (for units with flow (D) Type of fuel(s) fired by boiler, fuel code assigned by the utility to each monitors, only). type start and end dates, primary/ identifiable monitoring component (viii) Stack height (ft) above ground secondary fuel indicator, and, if more (such as the analyzer and/or probe). level and stack base elevation above sea than one fuel, the fuel classification of Each code shall use a three-digit format, level. the boiler; unique to each monitoring component (ix) Part 75 monitoring location (E) Type(s) of emission controls for and unique to each monitoring system; identification, facility identification SO2, NOX, and particulates installed or (C) Designation of the component type code as assigned by the Administrator to be installed, including specifications and method of sample acquisition or for use under the Acid Rain Program or of whether such controls are pre- operation, (e.g., in situ pollutant this part, and the following information, combustion, post-combustion, or concentration monitor or thermal flow as reported to the Energy Information integral to the combustion process; monitor); Administration (EIA): facility control equipment code, installation (D) Designation of the system as a identification number, flue date, and optimization date; control primary, redundant backup, non- identification number, boiler equipment retirement date (if redundant backup, data backup, or identification number, reporting year, applicable); and an indicator for reference method backup system, as and 767 reporting indicator. whether the controls are an original provided in § 75.10(e); (x) For each parameter monitored: installation; (E) First and last dates the system scale, maximum potential concentration (F) Maximum hourly heat input reported data; (and method of calculation), maximum capacity; (F) Status of the monitoring expected concentration (if applicable) (G) Date of first commercial operation; component; and (and method of calculation), maximum (H) Unit retirement date (if (G) Parameter monitored. potential flow rate (and method of (v) Identification and description of applicable); calculation), maximum potential NOX (I) Maximum hourly gross load (in all major hardware and software emission rate, span value, full-scale MW, rounded to the nearest MW, or components of the automated data range, daily calibration units of steam load in 1000 lb/hr, rounded to the acquisition and handling system, measure, span effective date/hour, span nearest 100 lb/hr); including: inactivation date/hour, indication of (J) Identification of all units using a (A) Hardware components that whether dual spans are required, default common stack; perform emission calculations or store high range value, flow rate span, and (K) Activation date for the stack/pipe; data for quarterly reporting purposes flow rate span value and full scale value (L) Retirement date of the stack/pipe (provide the manufacturer and model (in scfh) for each unit or stack using number); and (if applicable); and SO2, NOX, CO2, O2, or flow component (B) Software components (provide the (M) Indicator of whether the stack is monitors. a bypass stack. identification of the provider and (xi) If the monitoring system or (ii) For each unit and parameter model/version number). excepted methodology provides for the (vi) Explicit formulas for each required to be monitored, identification use of a constant, assumed, or default measured emission parameter, using of monitoring methodology information, value for a parameter under specific component/system identification codes consisting of monitoring methodology, circumstances, then include the for the primary system used to measure type of fuel associated with the following information for each such the parameter that links CEMS or methodology, primary/secondary value for each parameter: methodology indicator, missing data excepted monitoring system (A) Identification of the parameter; approach for the methodology, observations with reported (B) Default, maximum, minimum, or methodology start date, and concentrations, mass emissions, or constant value, and units of measure for methodology end date (if applicable). emission rates, according to the the value; (iii) The following information: conversions listed in appendix D or E to (C) Purpose of the value; (A) Program(s) for which the EDR is this part. Formulas for backup (D) Indicator of use during controlled/ submitted; monitoring systems are required only if uncontrolled hours; (B) Unit classification; different formulas for the same (E) Type of fuel; (C) Reporting frequency; parameter are used for the primary and (F) Source of the value; (D) Program participation date; backup monitoring systems (e.g., if the (G) Value effective date and hour; (E) State regulation code (if primary system measures pollutant (H) Date and hour value is no longer applicable); and concentration on a different moisture effective (if applicable); and

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(I) For units using the excepted from output signals of CEMS (ii) Hardcopy. (A) A schematic methodology under § 75.19, the components to final reports. diagram identifying the relationship applicable SO2 emission factor. (iv) For units monitored by a between the unit, all fuel supply lines, (xii) For each unit or common stack continuous emission or opacity the fuel flowmeter(s), and the stack(s). (except for peaking units) on which monitoring system, a schematic diagram The schematic diagram must depict the hardware CEMS are installed: identifying entire gas handling system installation location of each fuel (A) The upper and lower boundaries from boiler to stack for all affected units, flowmeter and the fuel sampling of the range of operation (as defined in using identification numbers for units, location(s). Comprehensive and/or section 6.5.2.1 of appendix A to this monitor components, and stacks separate schematic diagrams shall be part), expressed in megawatts or corresponding to the identification used to describe groups of units using thousands of lb/hr of steam; numbers provided in paragraphs a common pipe; (B) The load level(s) designated as (e)(1)(i), (e)(1)(iv), (e)(1)(vi), and (B) For units using the optional normal in section 6.5.2.1 of appendix A (e)(1)(ix) of this section. The schematic default SO2 emission rate for ‘‘pipeline to this part, expressed in megawatts or diagram must depict stack height and natural gas’’ or ‘‘natural gas’’ in thousands of lb/hr of steam; the height of any monitor locations. appendix D to this part, the information (C) The two load levels (i.e., low, mid, Comprehensive and/or separate on the sulfur content of the gaseous fuel or high) identified in section 6.5.2.1 of schematic diagrams shall be used to used to demonstrate compliance with appendix A to this part as the most describe groups of units using a either section 2.3.1.4 or 2.3.2.4 of frequently used; common stack. appendix D to this part; (D) The date of the load analysis used (v) For units monitored by a (C) For units using the 720 hour test to determine the normal load level(s) continuous emission or opacity under 2.3.6 of Appendix D of this part and the two most frequently-used load monitoring system, stack and duct to determine the required sulfur levels; and engineering diagrams showing the sampling requirements, report the (E) Activation and deactivation dates, dimensions and location of fans, turning procedures and results of the test; and when the normal load level(s) or two vanes, air preheaters, monitor (D) For units using the 720 hour test most frequently-used load levels change components, probes, reference method under 2.3.5 of Appendix D of this part and are updated. sampling ports, and other equipment to determine the appropriate fuel GCV (xiii) For each unit for which the that affects the monitoring system sampling frequency, report the optional fuel flow-to-load test in section location, performance, or quality control procedures used and the results of the 2.1.7 of appendix D to this part is used: checks. test; (A) The upper and lower boundaries (f) Contents of monitoring plan for (2) For each gas-fired peaking unit of the range of operation (as defined in specific situations. The following and oil-fired peaking unit for which the section 6.5.2.1 of appendix A to this additional information shall be included owner or operator uses the optional part), expressed in megawatts or in the monitoring plan for the specific procedures in appendix E to this part for thousands of lb/hr of steam; situations described: estimating NOX emission rate, the (1) For each gas-fired unit or oil-fired (B) The load level designated as designated representative shall include unit for which the owner or operator normal, pursuant to section 6.5.2.1 of in the monitoring plan: uses the optional protocol in appendix appendix A to this part, expressed in (i) Electronic. Unit operating and D to this part for estimating heat input megawatts or thousands of lb/hr of capacity factor information and/or SO2 mass emissions, or for each steam; and demonstrating that the unit qualifies as gas-fired or oil-fired peaking unit for (C) The date of the load analysis used a peaking unit or gas-fired unit, as which the owner/operator uses the to determine the normal load level. defined in § 72.2 of this chapter, and optional protocol in appendix E to this (2) Hardcopy. (i) Information, NOX correlation test information, part for estimating NOX emission rate including (as applicable): identification including: (using a fuel flowmeter), the designated (A) Test date; of the test strategy; protocol for the representative shall include the (B) Test number; relative accuracy test audit; other following additional information in the (C) Operating level; relevant test information; calibration gas monitoring plan: (D) Segment ID of the NOX correlation levels (percent of span) for the (i) Electronic. curve; calibration error test and linearity (A) Parameter monitored; (E) NOX monitoring system check; calculations for determining (B) Type of fuel measured, maximum identification; maximum potential concentration, fuel flow rate, units of measure, and (F) Low and high heat input values maximum expected concentration (if basis of maximum fuel flow rate (i.e., and corresponding NOX rates; applicable), maximum potential flow upper range value or unit maximum) for (G) Type of fuel; and rate, maximum potential NOX emission each fuel flowmeter; (H) To document the unit qualifies as rate, and span; and apportionment (C) Test method used to check the a peaking unit, current calendar year, strategies under §§ 75.10 through 75.18. accuracy of each fuel flowmeter; capacity factor data as specified in the (ii) Description of site locations for (D) Submission status of the data; definition of peaking unit in § 72.2 of each monitoring component in the (E) Monitoring system identification this part, and an indication of whether continuous emission or opacity code; and the data are actual or projected data. monitoring systems, including (F) For gaseous fuels fired by the unit, (ii) Hardcopy. (A) A protocol schematic diagrams and engineering the method used to verify that the fuel containing methods used to perform the drawings specified in paragraphs meets the definition in § 72.2 of pipeline baseline or periodic NOX emission test; (e)(2)(iv) and (e)(2)(v) of this section and natural gas or natural gas, if applicable, and any other documentation that and the demonstration methods used for (B) Unit operating parameters related demonstrates each monitor location other gaseous fuels, if applicable, to to NOX formation by the unit. meets the appropriate siting criteria. determine the appropriate frequency for (3) For each gas-fired unit and diesel- (iii) A data flow diagram denoting the sampling for GCV or sulfur content of fired unit or unit with a wet flue gas complete information handling path the fuel. pollution control system for which the

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(b) * * * demonstrating that the unit qualifies for (6) For each gas-fired unit the (1) * * * the exemption. designated representative shall include (i) The information required in (4) For each monitoring system in the monitoring plan, in electronic § 75.54(c) for SO2 concentration and recertification, maintenance, or other format, the following: current calendar volumetric flow if either one of these event, the designated representative year, fuel usage data as specified in the monitors is still operating: shall include the following additional definition of gas-fired in § 72.2 of this * * * * * information in electronic format in the part, and an indication of whether the (xi) Method of determination of SO2 monitoring plan: data are actual or projected data. concentration and volumetric flow, (i) Component/system identification 37. Section 75.54 is amended by using Codes 1–15 in Table 4 of § 75.54; code; revising paragraph (a) introductory text and (ii) Event code or code for required and paragraph (a)(1), and adding a new * * * * * test; paragraph (g) to read as follows: (2) * * * (vii) Method of determination of NO (iii) Event begin date and hour; § 75.54 General recordkeeping provisions. X (iv) Conditionally valid data period emission rate using Codes 1–15 in Table (a) Recordkeeping requirements for begin date and hour (if applicable); 4 of § 75.54; and affected sources. On and after January 1, (v) Date and hour that last test is 1996, and before April 1, 2000, the * * * * * successfully completed; and (e) Specific SO2 emission record owner or operator shall meet the provisions during the combustion of (vi) Indicator of whether conditionally requirements of either this section or valid data were reported at the end of gaseous fuel. (1) If SO2 emissions are § 75.57. On and after April 1, 2000, the determined in accordance with the the quarter. owner or operator shall meet the (5) For each unit using the low mass provisions in § 75.11(e)(2) during hours requirements of § 75.57. The owner or in which only gaseous fuel is combusted emission excepted methodology under operator of any affected source subject § 75.19 the designated representative in a unit with an SO2 CEMS, the owner to the requirements of this part shall or operator shall record the information shall include the following additional maintain for each affected unit a file of information in the monitoring plan: in paragraph (c)(3) of this section in lieu all measurements, data, reports, and of the information in §§ 75.54(c)(1) and (i) Electronic. For each low mass other information required by this part emissions unit, report the results of the (c)(3) or §§ 75.57(c)(1) and (c)(4), for at the source in a form suitable for those hours. analysis performed to qualify as a low inspection for at least three (3) years mass emissions unit under § 75.19(c). (2) The provisions of this paragraph from the date of each record. Unless apply to a unit which, in accordance This report will include either the otherwise provided, throughout this previous three years actual or projected with the provisions of § 75.11(e)(3), uses subpart the phrase ‘‘for each affected an SO2 CEMS to determine SO2 emissions and the emissions calculated unit’’ also applies to each group of using the methodology which will be emissions during hours in which only affected or nonaffected units utilizing a gaseous fuel is combusted in the unit. If used by the unit to estimate future common stack and common monitoring emissions. the unit sometimes burns only gaseous systems, pursuant to §§ 75.16 through fuel that is very low sulfur fuel (as (ii) Hardcopy. (A) A schematic 75.18, or utilizing a common pipe diagram identifying the relationship defined in § 72.2 of this chapter) as a header and common fuel flowmeter, primary and/or backup fuel and at other between the unit, all fuel supply lines pursuant to section 2.1.2 of appendix D and tanks, any fuel flowmeter(s), and times combusts higher-sulfur fuels, such to this part. The file shall contain the as coal or oil, as primary and/or backup the stack(s). Comprehensive and/or following information: separate schematic diagrams shall be fuel(s), then the owner or operator shall (1) The data and information required keep records on-site, suitable for used to describe groups of units using in paragraphs (b) through (g) of this a common pipe; inspection, of the type(s) of fuel(s) section, beginning with the earlier of the burned during each period of missing (B) For units which use the long term date of provisional certification, or the SO2 data and the number of hours that fuel flow methodology under deadline in § 75.4(a), (b) or (c); each type of fuel was combusted in the § 75.19(c)(3), the designated * * * * * unit during each missing data period. representative must provide a diagram (g) Missing data records. The owner or This recordkeeping requirement does of the fuel flow to each affected unit or operator shall record the causes of any not apply to an affected unit that burns group of units and describe in detail the missing data periods and the actions very low sulfur fuel exclusively, nor procedures used to determine the long taken by the owner or operator to cure does it apply to a unit that burns such term fuel flow for a unit or group of such causes. gaseous fuel(s) only during unit startup. units for each fuel combusted by the 38. Section 75.55 is amended by 39. Section 75.56 is amended by unit or group of units; adding introductory text prior to adding introductory text prior to (C) A statement that the unit burns paragraph (a), by correcting paragraphs paragraph (a) adding new paragraphs only natural gas or fuel oil and a list of (b)(1)(i), (b)(1)(xi), (b)(2)(vii), by revising (a)(5)(vii) through (a)(5)(ix) and the fuels that are burned or a statement paragraph (e), and by removing removing paragraph (d) to read as that the unit is projected to burn only paragraph (f) to read as follows: follows: natural gas or fuel oil and a list of the fuels that are projected to be burned; § 75.55 General recordkeeping provisions § 75.56 Certification, quality assurance, (D) A statement that the unit meets for specific situations. and quality control record provisions. the applicability requirements in Before April 1, 2000, the owner or Before April 1, 2000, the owner or §§ 75.19(a) and (b); and operator shall meet the requirements of operator shall meet the requirements of

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(3) The data and information required except as provided under § 75.11(e) or (a) * * * in § 75.55 or § 75.58 for specific for a gas-fired or oil-fired unit for which (5) * * * situations, as applicable, beginning with the owner or operator is using the (vii) For flow monitors, the equation the earlier of the date of provisional optional protocol in appendix D to this used to linearize the flow monitor and certification or the deadline in § 75.4(a), part or for a low mass emissions unit for the numerical values of the polynomial (b), or (c); which the owner or operator is using the coefficients or K factor(s) of that (4) The certification test data and optional low mass emissions equation. information required in § 75.56 or methodology in § 75.19(c) for estimating (viii) The raw data and calculated § 75.59 for tests required under § 75.20, SO2 mass emissions: results for any stratification tests beginning with the date of the first (1) For SO2 concentration during unit performed in accordance with sections certification test performed, the quality operation, as measured and reported 6.5.6.1 through 6.5.6.3 in appendix A to assurance and quality control data and from each certified primary monitor, this part. information required in § 75.56 or certified back-up monitor, or other (ix) For moisture monitoring systems, § 75.59 for tests, and the quality approved method of emissions the coefficient or ‘‘K’’ factor or other assurance/quality control plan required determination: mathematical algorithm used to adjust under § 75.21 and appendix B to this (i) Component-system identification the monitoring system with respect to part, beginning with the date of code, as provided in § 75.53; the reference method. provisional certification; (ii) Date and hour; * * * * * (5) The current monitoring plan as (iii) Hourly average SO2 concentration 40. Section 75.57 is added to subpart specified in § 75.53, beginning with the (ppm, rounded to the nearest tenth); F to read as follows: initial submission required by § 75.62; (iv) Hourly average SO2 concentration and (ppm, rounded to the nearest tenth), § 75.57 General recordkeeping provisions. (6) The quality control plan as adjusted for bias if bias adjustment Before April 1, 2000, the owner or described in section 1 of appendix B to factor is required, as provided in operator shall meet the requirements of this part, beginning with the date of § 75.24(d); either this section or § 75.54. However, provisional certification. (v) Percent monitor data availability the provisions of this section which (b) Operating parameter record (recorded to the nearest tenth of a support a regulatory option provided in provisions. The owner or operator shall percent), calculated pursuant to § 75.32; another section of this part must be record for each hour the following and followed if that regulatory option is information on unit operating time, heat (vi) Method of determination for used prior to April 1, 2000. On or after input rate, and load, separately for each hourly average SO2 concentration using April 1, 2000, the owner or operator affected unit and also for each group of Codes 1–55 in Table 4a of this section. shall meet the requirements of this units utilizing a common stack and a (2) For flow rate during unit section. common monitoring system or utilizing operation, as measured and reported (a) Recordkeeping requirements for a common pipe header and common from each certified primary monitor, affected sources. The owner or operator fuel flowmeter: certified back-up monitor, or other of any affected source subject to the (1) Date and hour; approved method of emissions requirements of this part shall maintain (2) Unit operating time (rounded up to determination: for each affected unit a file of all the nearest fraction of an hour (in equal (i) Component-system identification measurements, data, reports, and other increments that can range from one code, as provided in § 75.53; information required by this part at the hundredth to one quarter of an hour, at (ii) Date and hour; source in a form suitable for inspection the option of the owner or operator)); (iii) Hourly average volumetric flow for at least three (3) years from the date (3) Hourly gross unit load (rounded to rate (in scfh, rounded to the nearest of each record. Unless otherwise nearest MWge) (or steam load in 1000 thousand); provided, throughout this subpart the lb/hr at stated temperature and pressure, (iv) Hourly average volumetric flow phrase ‘‘for each affected unit’’ also rounded to the nearest 1000 lb/hr, if rate (in scfh, rounded to the nearest applies to each group of affected or elected in the monitoring plan); thousand), adjusted for bias if bias nonaffected units utilizing a common (4) Operating load range adjustment factor required, as provided stack and common monitoring systems, corresponding to hourly gross load of 1 in § 75.24(d); pursuant to §§ 75.16 through 75.18, or to 10, except for units using a common (v) Percent monitor data availability utilizing a common pipe header and stack or common pipe header, which (recorded to the nearest tenth of a common fuel flowmeter, pursuant to may use up to 20 load ranges for stack percent) for the flow monitor, calculated section 2.1.2 of appendix D to this part. or fuel flow, as specified in the pursuant to § 75.32; and The file shall contain the following monitoring plan; (vi) Method of determination for information: (5) Hourly heat input rate (mmBtu/hr, hourly average flow rate using Codes 1– (1) The data and information required rounded to the nearest tenth); 55 in Table 4a of this section. in paragraphs (b) through (h) of this (6) Identification code for formula (3) For flue gas moisture content section, beginning with the earlier of the used for heat input, as provided in during unit operation (where SO2 date of provisional certification or the § 75.53; and concentration is measured on a dry deadline in § 75.4(a), (b), or (c); (7) For CEMS units only, F-factor for basis), as measured and reported from (2) The supporting data and heat input calculation and indication of each certified primary monitor, certified information used to calculate values whether the diluent cap was used for back-up monitor, or other approved required in paragraphs (b) through (g) of heat input calculations for the hour. method of emissions determination: this section, excluding the subhourly (c) SO2 emission record provisions. (i) Component-system identification data points used to compute hourly The owner or operator shall record for code, as provided in § 75.53; averages under § 75.10(d), beginning each hour the information required by (ii) Date and hour;

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

TABLE 4A.ÐCODES FOR METHOD OF EMISSIONS AND FLOW DETERMINATION

Code Hourly emissions/flow measurement or 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 po- tential 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 § 72.2 of this chapter, is com- busted. 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 dil- uent 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. peaking unit or oil-fired peaking unit for methodology in § 75.19(c) for estimating The owner or operator shall record the which the owner or operator is using the NOX emission rate. For each NOX applicable information required by this optional protocol in appendix E to this emission rate (in lb/mmBtu) measured paragraph for each affected unit for each part or a low mass emissions unit for by a NOX-diluent monitoring system, or, hour or partial hour during which the which the owner or operator is using the if applicable, for each NOX unit operates, except for a gas-fired optional low mass emissions excepted concentration (in ppm) measured by a

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NOX concentration monitoring system percentage, using Codes 1–55 in Table CO2 mass emission rate, as provided in used to calculate NOX mass emissions 4a of this section; and § 75.53; and under § 75.71(a)(2), record the following (10) Identification codes for emissions (x) Indication of whether the diluent data as measured and reported from the formulas used to derive hourly average cap was used for CO2 calculation for the certified primary monitor, certified NOX emission rate and total NOX mass hour. back-up monitor, or other approved emissions, as provided in § 75.53, and (2) As an alternative to paragraph method of emissions determination: (if applicable) the F-factor used to (e)(1) of this section, the owner or (1) Component-system identification convert NOX concentrations into operator may use the procedures in code, as provided in § 75.53 (including emission rates. § 75.13 and in appendix G to this part, identification code for the moisture (e) CO2 emission record provisions. and shall record daily the following monitoring system, if applicable); Except for a low mass emissions unit for information for CO2 mass emissions: (2) Date and hour; which the owner or operator is using the (i) Date; (ii) Daily combustion-formed CO2 (3) Hourly average NOX concentration optional low mass emissions excepted (ppm, rounded to the nearest tenth) and methodology in § 75.19(c) for estimating mass emissions (tons/day, rounded to the nearest tenth); hourly average NOX concentration CO2 mass emissions, the owner or (ppm, rounded to the nearest tenth) operator shall record or calculate CO2 (iii) For coal-fired units, flag adjusted for bias if bias adjustment emissions for each affected unit using indicating whether optional procedure factor required, as provided in one of the following methods specified to adjust combustion-formed CO2 mass § 75.24(d); in this section: emissions for carbon retained in flyash (4) Hourly average diluent gas (1) If the owner or operator chooses to has been used and, if so, the adjustment; use a CO2 CEMS (including an O2 (iv) For a unit with a wet flue gas concentration (for NOX-diluent desulfurization system or other controls monitoring systems, only, in units of monitor and flow monitor, as specified in appendix F to this part), then the generating CO2, daily sorbent-related percent O2 or percent CO2, rounded to CO2 mass emissions (tons/day, rounded the nearest tenth); owner or operator shall record for each hour or partial hour during which the to the nearest tenth); and (5) If applicable, the hourly average (v) For a unit with a wet flue gas moisture content of the stack gas unit operates the following information for CO2 mass emissions, as measured desulfurization system or other controls (percent H2O, rounded to the nearest and reported from the certified primary generating CO2, total daily CO2 mass tenth). If the continuous moisture emissions (tons/day, rounded to the monitoring system consists of wet- and monitor, certified back-up monitor, or other approved method of emissions nearest tenth) as the sum of combustion- dry-basis oxygen analyzers, also record formed emissions and sorbent-related both the hourly wet- and dry-basis determination: (i) Component-system identification emissions. oxygen readings (in percent O2, rounded (f) Opacity records. The owner or to the nearest tenth); code, as provided in § 75.53 (including identification code for the moisture operator shall record opacity data as (6) Hourly average NOX emission rate monitoring system, if applicable); specified by the State or local air (for NOX-diluent monitoring systems (ii) Date and hour; pollution control agency. If the State or only, in units of lb/mmBtu, rounded (iii) Hourly average CO2 concentration local air pollution control agency does either to the nearest hundredth or (in percent, rounded to the nearest not specify recordkeeping requirements thousandth prior to April 1, 2000 and tenth); for opacity, then record the information rounded to the nearest thousandth on (iv) Hourly average volumetric flow required by paragraphs (f) (1) through and after April 1, 2000); rate (scfh, rounded to the nearest (5) of this section for each affected unit, (7) Hourly average NOX emission rate thousand scfh); except as provided in §§ 75.14(b), (c), (for NOX-diluent monitoring systems (v) Hourly average moisture content of and (d). The owner or operator shall only, in units of lb/mmBtu, rounded flue gas (percent, rounded to the nearest also keep records of all incidents of either to the nearest hundredth or tenth), where CO2 concentration is opacity monitor downtime during unit thousandth prior to April 1, 2000 and measured on a dry basis. If the operation, including reason(s) for the rounded to the nearest thousandth on continuous moisture monitoring system monitor outage(s) and any corrective and after April 1, 2000), adjusted for consists of wet- and dry-basis oxygen action(s) taken for opacity, as measured bias if bias adjustment factor is required, analyzers, also record both the hourly and reported by the continuous opacity as provided in § 75.24(d). The wet- and dry-basis oxygen readings (in monitoring system: requirement to report hourly NOX percent O2, rounded to the nearest (1) Component/system identification emission rates to the nearest thousandth tenth); code; shall not affect NOX compliance (vi) Hourly average CO2 mass (2) Date, hour, and minute; determinations under part 76 of this emission rate (tons/hr, rounded to the (3) Average opacity of emissions for chapter; compliance with each nearest tenth); each six minute averaging period (in applicable emission limit under part 76 (vii) Percent monitor data availability percent opacity); shall be determined to the nearest for both the CO2 monitoring system and, (4) If the average opacity of emissions hundredth pound per million Btu; if applicable, the moisture monitoring exceeds the applicable standard, then a (8) Percent monitoring system data system (recorded to the nearest tenth of code indicating such an exceedance has availability (recorded to the nearest a percent), calculated pursuant to occurred; and (5) Percent monitor data tenth of a percent), for the NOX-diluent § 75.32; availability (recorded to the nearest or NOX concentration monitoring (viii) Method of determination for tenth of a percent), calculated according system, and, if applicable, for the hourly average CO2 mass emission rate to the requirements of the procedure moisture monitoring system, calculated and hourly average CO2 concentration, recommended for State Implementation pursuant to § 75.32; and, if applicable, for the hourly average Plans in appendix M to part 51 of this (9) Method of determination for moisture percentage, using Codes 1–55 chapter. hourly average NOX emission rate or in Table 4a of this section; (g) Diluent record provisions. The NOX concentration and (if applicable) (ix) Identification code for emissions owner or operator of a unit using a flow for the hourly average moisture formula used to derive hourly average monitor and an O2 diluent monitor to

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The parametric diluent monitor: (v) Pressure differential across each data shall be maintained on site and (1) Component-system identification operating scrubber module (inches of shall be submitted, upon request, to the code, as provided in § 75.53; water column); Administrator, EPA Regional office, (2) Date and hour; (vi) For a unit with a wet flue gas (3) Hourly average diluent gas (O2 or State, or local agency; desulfurization system, an in-line CO2) concentration (in percent, rounded (ii) A flag indicating either that the measure of absorber pH for each to the nearest tenth); add-on emission controls are operating operating scrubber module; (4) Percent monitor data availability (vii) For a unit with a dry flue gas properly, as evidenced by all parameters for the diluent monitor (recorded to the desulfurization system, the inlet and being within the ranges specified in the nearest tenth of a percent), calculated outlet temperatures across each quality assurance/quality control pursuant to § 75.32; and operating scrubber module; program, or that the add-on emission (5) Method of determination code for (viii) For a unit with a wet flue gas controls are not operating properly; diluent gas (O2 or CO2) concentration desulfurization system, the percent (iii) For units substituting a data using Codes 1–55, in Table 4a of solids in slurry for each scrubber representative SO this section. 2 concentration during module; missing data periods under § 75.34(a)(2), (h) Missing data records. The owner (ix) For a unit with a dry flue gas or operator shall record the causes of any available inlet and outlet SO2 desulfurization system, the slurry feed concentration values recorded by an any missing data periods and the rate (gal/min) to the atomizer nozzle; SO2 continuous emission monitoring actions taken by the owner or operator (x) For a unit with SO2 add-on to correct such causes. emission controls other than wet or dry system; and 41. Section 75.58 is added to subpart limestone, corresponding parameters (iv) For units substituting a F to read as follows: approved by the Administrator; representative NOX emission rate during (xi) Method of determination of SO2 missing data periods under § 75.34(a)(2), § 75.58 General recordkeeping provisions concentration and volumetric flow for specific situations. any available inlet and outlet NOX using Codes 1–15 in Table 4 of § 75.54 emission rate values recorded by a Before April 1, 2000, the owner or or Codes 1–55 in Table 4a of § 75.57; continuous emission monitoring system. operator shall meet the requirements of and (c) Specific SO2 emission record either this section or § 75.55. However, (xii) Inlet and outlet SO2 the provisions of this section which concentration values, recorded by an provisions for gas-fired or oil-fired units using optional protocol in appendix D support a regulatory option provided in SO2 continuous emission monitoring another section of this part must be system, and the removal efficiency of to this part. In lieu of recording the followed if that regulatory option is the add-on emission controls. information in § 75.54(c) or § 75.57(c), exercised prior to April 1, 2000. On or (2) For units with add-on NOX the owner or operator shall record the after April 1, 2000, the owner or emission controls using the optional applicable information in this paragraph operator shall meet the requirements of parametric monitoring procedures in for each affected gas-fired or oil-fired this section. appendix C to this part, for each hour unit for which the owner or operator is (a) [Reserved] of missing NOX emission rate data: using the optional protocol in appendix (b) Specific parametric data record (i) Date and hour; D to this part for estimating SO2 mass provisions for calculating substitute (ii) Inlet air flow rate (scfh, rounded emissions: to the nearest thousand); emissions data for units with add-on (1) For each hour when the unit is (iii) Excess O2 concentration of flue emission controls. In accordance with combusting oil: § 75.34, the owner or operator of an gas at stack outlet (percent, rounded to affected unit with add-on emission the nearest tenth of a percent); (i) Date and hour; controls shall either record the (iv) Carbon monoxide concentration (ii) Hourly average volumetric flow applicable information in paragraph of flue gas at stack outlet (ppm, rounded rate of oil, while the unit combusts oil, (b)(3) of this section for each hour of to the nearest tenth); with the units in which oil flow is (v) Temperature of flue gas at furnace 3 missing SO2 concentration data or NOX recorded (gal/hr, scf/hr, m /hr, or bbl/ exit or economizer outlet duct (°F); emission rate (in addition to other hr, rounded to the nearest tenth) (flag (vi) Other parameters specific to NOX information), or shall record the emission controls (e.g., average hourly value if derived from missing data information in paragraph (b)(1) of this reagent feedrate); procedures); section for SO2 or paragraph (b)(2) of (vii) Method of determination of NOX (iii) Sulfur content of oil sample used this section for NOX through an emission rate using Codes 1–15 in Table to determine SO2 mass emission rate automated data acquisition and 4 of § 75.54 or Codes 1–55 in Table 4a (rounded to nearest hundredth for diesel handling system, as appropriate to the of § 75.57; and fuel or to the nearest tenth of a percent type of add-on emission controls: (viii) Inlet and outlet NOX emission for other fuel oil) (flag value if derived (1) For units with add-on SO2 rate values recorded by a NOX from missing data procedures); emission controls using the optional continuous emission monitoring system parametric monitoring procedures in and the removal efficiency of the add- (iv) [Reserved]; appendix C to this part, for each hour on emission controls. (v) Mass flow rate of oil combusted of missing SO2 concentration or (3) For units with add-on SO2 or NOX each hour and method of determination volumetric flow data: emission controls following the (lb/hr, rounded to the nearest tenth)

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(flag value if derived from missing data (B) Default SO2 emission rate of estimating NOX emission rate. The procedures); 0.0006 lb/mmBtu for pipeline natural owner or operator shall meet the (vi) SO2 mass emission rate from oil gas, or calculated SO2 emission rate for requirements of this section, except that (lb/hr, rounded to the nearest tenth); natural gas from section 2.3.2.1.1 of the requirements under paragraphs (vii) For units using volumetric oil appendix D to this part. (d)(1)(vii) and (d)(2)(vii) of this section flowmeters, density of oil with the units (iv) Hourly flow rate of gaseous fuel, shall become applicable on the date on in which oil density is recorded and while the unit combusts gas (100 scfh) which the owner or operator is required method of determination (flag value if and source of data code for gas flow to monitor, record, and report NOX mass derived from missing data procedures); rate. emissions under an applicable State or (viii) Gross calorific value of oil used (v) Gross calorific value of gaseous federal NOX mass emission reduction to determine heat input and method of fuel used to determine heat input rate program, if the provisions of subpart H determination (Btu/lb) (flag value if (Btu/100 scf) (flag value if derived from of this part are adopted as requirements derived from missing data procedures); missing data procedures). under such a program. (ix) Hourly heat input rate from oil, (vi) SO2 mass emission rate due to the (1) For each hour when the unit is according to procedures in appendix D combustion of gaseous fuels (lb/hr). combusting oil: to this part (mmBtu/hr, to the nearest (vii) Fuel usage time for combustion (i) Date and hour; tenth); of gaseous fuel during the hour (ii) Hourly average mass flow rate of (x) Fuel usage time for combustion of (rounded up to the nearest fraction of an oil while the unit combusts oil with the oil during the hour (rounded up to the hour (in equal increments that can range units in which oil flow is recorded (lb/ nearest fraction of an hour (in equal from one hundredth to one quarter of an hr); increments that can range from one hour, at the option of the owner or (iii) Gross calorific value of oil used hundredth to one quarter of an hour, at operator)) (flag to indicate multiple/ to determine heat input (Btu/lb); the option of the owner or operator)) single fuel types combusted). (iv) Hourly average NOX emission rate (flag to indicate multiple/single fuel (viii) Monitoring system identification from combustion of oil (lb/mmBtu, types combusted); code. rounded to the nearest hundredth); (xi) Monitoring system identification (ix) Operating load range (v) Heat input rate of oil (mmBtu/hr, code; corresponding to gross unit load (01– rounded to the nearest tenth); (xii) Operating load range (vi) Fuel usage time for combustion of 20). corresponding to gross unit load (01– oil during the hour (rounded up to the (x) Type of gas combusted. 20); and (5) For each oil sample or sample of nearest fraction of an hour, in equal (xiii) Type of oil combusted. increments that can range from one (2) For gas-fired units or oil-fired diesel fuel: (i) Date of sampling; hundredth to one quarter of an hour, at units using the optional protocol in the option of the owner or operator); appendix D to this part for daily manual (ii) Sulfur content (percent, rounded to the nearest hundredth for diesel fuel (vii) NOX mass emissions, calculated oil sampling, when the unit is in accordance with section 8.1 of combusting oil, the highest sulfur and to the nearest tenth for other fuel oil); appendix F to this part; content recorded from the most recent (viii) NOX monitoring system 30 daily oil samples (rounded to the (iii) Gross calorific value (Btu/lb); and (iv) Density or specific gravity, if identification code; nearest tenth of a percent). (ix) Fuel flow monitoring system required to convert volume to mass. (3) For gas-fired units or oil-fired identification code; and units using the optional protocol in (6) For each sample of gaseous fuel for (x) Segment identification of the appendix D to this part, when either an sulfur content: correlation curve. assumed oil sulfur content or density (i) Date of sampling; and (2) For each hour when the unit is (ii) Sulfur content (grains/100 scf, value is used, or when as-delivered oil combusting gaseous fuel: sampling is performed: rounded to the nearest tenth). (i) Date and hour; (i) Record the measured sulfur (7) For each sample of gaseous fuel for (ii) Hourly average fuel flow rate of content, gross calorific value, and, if gross calorific value: gaseous fuel, while the unit combusts applicable, density from each fuel (i) Date of sampling; and gas (100 scfh); sample; and (ii) Gross calorific value (Btu/100 scf) (iii) Gross calorific value of gaseous (ii) Record and report the assumed (8) For each oil sample or sample of fuel used to determine heat input (Btu/ sulfur content, gross calorific value, gaseous fuel: 100 scf) (flag value if derived from and, if applicable, density used to (i) Type of oil or gas; and missing data procedures); (ii) Type of sulfur sampling (using calculate SO2 mass emission rate or heat (iv) Hourly average NOX emission rate input rate. codes in tables D–4 and D–5 of from combustion of gaseous fuel (lb/ (4) For each hour when the unit is appendix D to this part) and value used mmBtu, rounded to nearest hundredth); combusting gaseous fuel: in calculations, and type of GCV or (v) Heat input rate from gaseous fuel, (i) Date and hour. density sampling (using codes in tables while the unit combusts gas (mmBtu/hr, (ii) Hourly heat input rate from D–4 and D–5 of appendix D to this part). rounded to the nearest tenth); gaseous fuel, according to procedures in (d) Specific NOX emission record (vi) Fuel usage time for combustion of appendix F to this part (mmBtu/hr, provisions for gas-fired peaking units or gaseous fuel during the hour (rounded rounded to the nearest tenth). oil-fired peaking units using optional up to the nearest fraction of an hour, in (iii) Sulfur content or SO2 emission protocol in appendix E to this part. In equal increments that can range from rate, in one of the following formats, in lieu of recording the information in one hundredth to one quarter of an accordance with the appropriate paragraph § 75.54(d) or § 75.57(d), the hour, at the option of the owner or procedure from appendix D to this part: owner or operator shall record the operator); (A) Sulfur content of gas sample and applicable information in this paragraph (vii) NOX mass emissions, calculated method of determination (rounded to for each affected gas-fired peaking unit in accordance with section 8.1 of the nearest 0.1 grains/100 scf) (flag or oil-fired peaking unit for which the appendix F to this part; value if derived from missing data owner or operator is using the optional (viii) NOX monitoring system procedures); or protocol in appendix E to this part for identification code;

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(ix) Fuel flow monitoring system not apply to an affected unit that burns (viii) Method of determining fuel GCV identification code; and very low sulfur fuel exclusively, nor used; (x) Segment identification of the does it apply to a unit that burns such (ix) Method of determining fuel flow correlation curve. gaseous fuel(s) only during unit startup. over period; (3) For each hour when the unit (f) Specific SO2, NOX, and CO2 record (x) Component-system identification combusts multiple fuels: provisions for gas-fired or oil-fired units code; (i) Date and hour; using the optional low mass emissions (xi) Quarter and year; (ii) Hourly average heat input rate excepted methodology in § 75.19. In lieu (xii) Total heat input (mmBtu); and from all fuels (mmBtu/hr, rounded to of recording the information in (xiii) Operating hours in period. 42. Section 75.59 is added to subpart the nearest tenth); and §§ 75.54(b) through (e) or §§ 75.57(b) F to read as follows: (iii) Hourly average NOX emission rate through (e), the owner or operator shall for the unit for all fuels (lb/mmBtu, record the following information for § 75.59 Certification, quality assurance, rounded to the nearest hundredth). each affected low mass emissions unit and quality control record provisions. (4) For each hour when the unit for which the owner or operator is using Before April 1, 2000, the owner or combusts any fuel(s): the optional low mass emissions operator shall meet the requirements of (i) For stationary gas turbines and excepted methodology in § 75.19(c): this section or § 75.56. However, the diesel or dual-fuel reciprocating (1) All low mass emission units shall provisions of this section which support engines, hourly averages of operating report for each hour: a regulatory option provided in another parameters under section 2.3 of (i) Date and hour; section of this part must be followed if appendix E to this part (flag if value is (ii) Unit operating time (units using that regulatory option is exercised prior outside of manufacturer’s recommended the long term fuel flow methodology to April 1, 2000. On or after April 1, range); and report operating time to be 1); 2000, the owner or operator shall meet (ii) For boilers, hourly average boiler (iii) Fuel type (pipeline natural gas, the requirements of this section. O2 reading (percent, rounded to the natural gas, residual oil, or diesel fuel) (a) Continuous emission or opacity nearest tenth) (flag if value exceeds by (note: if more than one type of fuel is monitoring systems. The owner or more than 2 percentage points the O2 combusted in the hour, indicate the fuel operator shall record the applicable level recorded at the same heat input type which results in the highest information in this section for each during the previous NOX emission rate emission factors for NOX); certified monitor or certified monitoring test). (iv) Average hourly NOX emission rate system (including certified backup (5) For each fuel sample: (lb/mmBtu, rounded to the nearest monitors) measuring and recording (i) Date of sampling; thousandth); (ii) Gross calorific value (Btu/lb for emissions or flow from an affected unit. (v) Hourly NOX mass emissions (lbs, (1) For each SO2 or NOX pollutant oil, Btu/100 scf for gaseous fuel); and rounded to the nearest tenth); (iii) Density or specific gravity, if concentration monitor, flow monitor, (vi) Hourly SO2 mass emissions (lbs, CO2 pollutant concentration monitor required to convert volume to mass. rounded to the nearest tenth); (6) Flag to indicate multiple or single (including O2 monitors used to (vii) Hourly CO2 mass emissions fuels combusted. determine CO2 emissions), or diluent (tons, rounded to the nearest tenth); gas monitor (including wet- and dry- (e) Specific SO2 emission record (viii) Hourly calculated unit heat provisions during the combustion of basis O2 monitors used to determine input in mmBtu; percent moisture), the owner or operator gaseous fuel. (1) If SO2 emissions are (ix) Hourly unit output in gross load determined in accordance with the shall record the following for all daily or steam load; and 7-day calibration error tests and all provisions in § 75.11(e)(2) during hours (x) The method of determining hourly in which only gaseous fuel is combusted off-line calibration demonstrations, heat input: unit maximum rated heat including any follow-up tests after in a unit with an SO2 CEMS, the owner input, unit long term fuel flow or group or operator shall record the information corrective action: long term fuel flow; (i) Component-system identification in paragraph (c)(3) of this section in lieu (xi) The method of determining NOX of the information in §§ 75.54(c)(1) and code; emission rate used for the hour: default (ii) Instrument span and span scale; (c)(3) or §§ 75.57(c)(1), (c)(3), and (c)(4), based on fuel combusted, unit specific (iii) Date and hour; for those hours. default based on testing or historical (iv) Reference value (i.e., calibration (2) The provisions of this paragraph data, group default based on gas concentration or reference signal apply to a unit which, in accordance representative testing of identical units, value, in ppm or other appropriate with the provisions of § 75.11(e)(3), uses unit specific based on testing of a unit units); an SO2 CEMS to determine SO2 with NOX controls operating, or missing (v) Observed value (monitor response emissions during hours in which only data value; and during calibration, in ppm or other gaseous fuel is combusted in the unit. If (xii) Control status of the unit. appropriate units); the unit sometimes burns only gaseous (2) Low mass emission units using the (vi) Percent calibration error (rounded fuel that is very low sulfur fuel (as optional long term fuel flow to the nearest tenth of a percent) (flag if defined in § 72.2 of this chapter) as a methodology to determine unit heat using alternative performance primary and/or backup fuel and at other input shall report for each quarter: specification for low emitters or times combusts higher sulfur fuels, such (i) Type of fuel; differential pressure flow monitors); as coal or oil, as primary and/or backup (ii) Beginning date and hour of long (vii) Calibration gas level; fuel(s), then the owner or operator shall term fuel flow measurement period; (viii) Test number and reason for test; keep records on-site, in a form suitable (iii) End date and hour of long term (ix) For 7-day calibration tests for for inspection, of the type(s) of fuel(s) fuel flow period; certification or recertification, a burned during each period of missing (iv) Quantity of fuel measured; certification from the cylinder gas SO2 data and the number of hours that (v) Units of measure; vendor or CEMS vendor that calibration each type of fuel was combusted in the (vi) Fuel GCV value used to calculate gas, as defined in § 72.2 of this chapter unit during each missing data period. heat input; and appendix A to this part, was used This recordkeeping requirement does (vii) Units of GCV; to conduct calibration error testing;

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(x) Description of any adjustments, paragraphs (a)(4) (vi) and (vii) for all (K) Average gross unit load; and corrective actions, or maintenance prior flow-to-load ratio and gross heat rate (L) Operating load level. to a passed test or following a failed test; tests: (5) For each SO2 pollutant and (i) Component-system identification concentration monitor, flow monitor, (xi) For the qualifying test for off-line code. each CO2 pollutant concentration calibration, the owner or operator shall (ii) Date and hour. monitor (including any O2 indicate whether the unit is off-line or (iii) Reason for test. concentration monitor used to on-line. (iv) Code indicating whether monitor determine CO2 mass emissions or heat (2) For each flow monitor, the owner passes or fails the quarterly leak check. input), each NOX-diluent continuous or operator shall record the following (v) Description of any adjustments, emission monitoring system, each SO2- for all daily interference checks, corrective actions, or maintenance prior diluent continuous emission monitoring including any follow-up tests after to a passed test or following a failed test. system, each NOX concentration corrective action. (vi) Test data from the flow-to-load monitoring system, each diluent gas (O2 (i) Component-system identification ratio or gross heat rate (GHR) evaluation, or CO2) monitor used to determine heat code; including: input, each moisture monitoring system, (ii) Date and hour; (A) Monitoring system identification and each approved alternative (iii) Code indicating whether monitor code; monitoring system, the owner or passes or fails the interference check; (B) Calendar year and quarter; operator shall record the following and (C) Indication of whether the test is a information for the initial and all (iv) Description of any adjustments, flow-to-load ratio or gross heat rate subsequent relative accuracy test audits: corrective actions, or maintenance prior evaluation; (i) Reference method(s) used. to a passed test or following a failed test. (D) Indication of whether bias (ii) Individual test run data from the adjusted flow rates were used; (3) For each SO2 or NOX pollutant relative accuracy test audit for the SO2 (E) Average absolute percent concentration monitor, CO2 pollutant concentration monitor, flow monitor, difference between reference ratio (or concentration monitor (including O2 CO2 pollutant concentration monitor, GHR) and hourly ratios (or GHR values); monitors used to determine CO2 NOX-diluent continuous emission emissions), or diluent gas monitor (F) Test result; (G) Number of hours used in final monitoring system, SO2-diluent (including wet- and dry-basis O2 continuous emission monitoring system, monitors used to determine percent quarterly average; (H) Number of hours exempted for use diluent gas (O2 or CO2) monitor used to moisture), the owner or operator shall of a different fuel type; determine heat input, NOX record the following for the initial and (I) Number of hours exempted for load concentration monitoring system, all subsequent linearity check(s), ramping up or down; moisture monitoring system, or including any follow-up tests after (J) Number of hours exempted for approved alternative monitoring system, corrective action. scrubber bypass; including: (i) Component-system identification (K) Number of hours exempted for (A) Date, hour, and minute of code; hours preceding a normal-load flow beginning of test run; (ii) Instrument span and span scale; RATA; (B) Date, hour, and minute of end of (iii) Calibration gas level; (L) Number of hours exempted for test run; (iv) Date and time (hour and minute) hours preceding a successful diagnostic (C) Monitoring system identification of each gas injection at each calibration test, following a documented monitor code; gas level; repair or major component replacement; (D) Test number and reason for test; (v) Reference value (i.e., reference gas and (E) Operating load level (low, mid, concentration for each gas injection at (M) Number of hours excluded for high, or normal, as appropriate) and each calibration gas level, in ppm or flue gases discharging simultaneously number of load levels comprising test; other appropriate units); thorough a main stack and a bypass (F) Normal load indicator for flow (vi) Observed value (monitor response stack. RATAs (except for peaking units); to each reference gas injection at each (vii) Reference data for the flow-to- (G) Units of measure; calibration gas level, in ppm or other load ratio or gross heat rate evaluation, (H) Run number; appropriate units); including (as applicable): (I) Run value from CEMS being tested, (vii) Mean of reference values and (A) Reference flow RATA end date in the appropriate units of measure; mean of measured values at each and time; (J) Run value from reference method, calibration gas level; (B) Test number of the reference in the appropriate units of measure; (viii) Linearity error at each of the RATA; (K) Flag value (0, 1, or 9, as reference gas concentrations (rounded to (C) Reference RATA load and load appropriate) indicating whether run has nearest tenth of a percent) (flag if using level; been used in calculating relative alternative performance specification); (D) Average reference method flow accuracy and bias values or whether the (ix) Test number and reason for test rate during reference flow RATA; test was aborted prior to completion; (flag if aborted test); and (E) Reference flow/load ratio; (L) Average gross unit load, expressed (x) Description of any adjustments, (F) Average reference method diluent as a total gross unit load, rounded to the corrective action, or maintenance prior gas concentration during flow RATA nearest MWe, or as steam load, rounded to a passed test or following a failed test. and diluent gas units of measure; to the nearest thousand lb/hr); and (4) For each differential pressure type (G) Fuel specific Fd -or Fc-factor (M) Flag to indicate whether an flow monitor, the owner or operator during flow RATA and F-factor units of alternative performance specification shall record items in paragraphs (a)(4) measure; has been used. (i) through (v) of this section, for all (H) Reference gross heat rate value; (iii) Calculations and tabulated quarterly leak checks, including any (I) Monitoring system identification results, as follows: follow-up tests after corrective action. code; (A) Arithmetic mean of the For each flow monitor, the owner or (J) Average hourly heat input rate monitoring system measurement values, operator shall record items in during RATA; of the reference method values, and of

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For multi-level flow compliance with all applicable sections during the run, and, if different, the wall monitor tests the relative accuracy test and appendices in this part. Unless effects adjustment factor used in the results shall be recorded at each load otherwise specified in this part or in an calculations; and level tested. Each load level shall be applicable test method, the information (T) Default wall effects adjustment expressed as a total gross unit load, in paragraphs (a)(7)(i) through (a)(7)(vi) factor used. rounded to the nearest MWe, or as may be recorded either in hard copy (iii) For each traverse point of each steam load, rounded to the nearest format, electronic format or a run of each RATA using Reference thousand lb/hr; combination of the two, and the owner Method 2 (or its allowable alternatives (F) Bias test results as specified in or operator shall maintain this in appendix A to part 60 of this chapter) section 7.6.4 in appendix A to this part; information in a format suitable for to determine volumetric flow rate, and inspection and audit purposes. This record the following data elements (as (G) Bias adjustment factor from RATA supporting information shall applicable to the measurement method Equation A–12 in appendix A to this include, but shall not be limited to, the used): part for any monitoring system that following data elements: (A) Reference method probe type; failed the bias test (except as otherwise (i) For each RATA using Reference (B) Pressure measurement device provided in section 7.6.5 of appendix A Method 2 (or its allowable alternatives) type; to this part) and 1.000 for any in appendix A to part 60 of this chapter (C) Traverse point ID; monitoring system that passed the bias to determine volumetric flow rate: (D) Probe or pitot tube calibration test. (A) Information indicating whether or coefficient; (iv) Description of any adjustment, not the location meets requirements of (E) Date of latest probe or pitot tube corrective action, or maintenance prior Method 1 in appendix A to part 60 of calibration; to a passed test or following a failed or this chapter; and (F) Velocity differential pressure at aborted test. (B) Information indicating whether or traverse point (inches of H2O); (v) F-factor value(s) used to convert not the equipment passed the required (G) TS, stack temperature at the ° NOX pollutant concentration and leak checks. traverse point ( F); diluent gas (O2 or CO2) concentration (ii) For each run of each RATA using (H) Composite (wall effects) traverse measurements into NOX emission rates Reference Method 2 (or its allowable point identifier; (in lb/mmBtu), heat input or CO2 alternatives in appendix A to part 60 of (I) Number of points included in emissions. this chapter) to determine volumetric composite traverse point; (vi) For flow monitors, the equation flow rate, record the following data (J) Yaw angle of flow at traverse point used to linearize the flow monitor and elements (as applicable to the (degrees); the numerical values of the polynomial measurement method used): (K) Pitch angle of flow at traverse coefficients or K factor(s) of that (A) Operating load level (low, mid, point (degrees); equation. high, or normal, as appropriate); (L) Calculated velocity at traverse (vii) For moisture monitoring systems, (B) Number of reference method point both accounting and not the coefficient or ‘‘K’’ factor or other traverse points; accounting for wall effects (ft/sec); and mathematical algorithm used to adjust (C) Average stack gas temperature (M) Probe identification number. the monitoring system with respect to (°F); (iv) For each RATA using Method 6C, the reference method. (D) Barometric pressure at test port 7E, or 3A in appendix A to part 60 of (6) For each SO2, NOX, or CO2 (inches of mercury); this chapter to determine SO2, NOX, pollutant concentration monitor, NOX- (E) Stack static pressure (inches of CO2, or O2 concentration: diluent continuous emission monitoring H2O); (A) Pollutant or diluent gas being system, SO2-diluent continuous (F) Absolute stack gas pressure measured; emission monitoring system, NOX (inches of mercury); (B) Span of reference method concentration monitoring system, or (G) Percent CO2 and O2 in the stack analyzer; diluent gas (O2 or CO2) monitor used to gas, dry basis; (C) Type of reference method system determine heat input, the owner or (H) CO2 and O2 reference method (e.g., extractive or dilution type); operator shall record the following used; (D) Reference method dilution factor information for the cycle time test: (I) Moisture content of stack gas (dilution type systems, only); (i) Component-system identification (percent H2O); (E) Reference gas concentrations (zero, code; (J) Molecular weight of stack gas, dry mid, and high gas levels) used for the 3- (ii) Date; basis (lb/lb-mole); point pre-test analyzer calibration error (iii) Start and end times; (K) Molecular weight of stack gas, wet test (or, for dilution type reference (iv) Upscale and downscale cycle basis (lb/lb-mole); method systems, for the 3-point pre-test times for each component; (L) Stack diameter (or equivalent system calibration error test) and for any (v) Stable start monitor value; diameter) at the test port (ft); subsequent recalibrations;

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(F) Analyzer responses to the zero-, cylinder gas vendor, cylinder number, (iii) For pollutant concentration mid-, and high-level calibration gases expiration date, pollutant(s) in the monitor or diluent monitor relative during the 3-point pre-test analyzer (or cylinder, and certified gas accuracy tests at normal operating load: system) calibration error test and during concentration(s). (A) The raw reference method data any subsequent recalibration(s); (v) For each test run of each moisture from each run, i.e., the data under (G) Analyzer calibration error at each determination using Method 4 in paragraph (a)(7)(iv)(Q) of this section gas level (zero, mid, and high) for the 3- appendix A to part 60 of this chapter (or (usually in the form of a computerized point pre-test analyzer (or system) its allowable alternatives), whether the printout, showing a series of one-minute calibration error test and for any determination is made to support a gas readings and the run average); subsequent recalibration(s) (percent of RATA, to support a flow RATA, or to (B) The raw data and results for all span value); quality assure the data from a required pre-test, post-test, pre-run and (H) Upscale gas concentration (mid or continuous moisture monitoring system, post-run quality assurance checks (i.e., high gas level) used for each pre-run or record the following data elements (as calibration gas injections) of the post-run system bias check or (for applicable to the moisture measurement reference method analyzers, i.e., the dilution type reference method systems) method used): data under paragraphs (a)(7)(iv)(E) for each pre-run or post-run system (A) Test number; through (a)(7)(iv)(N) of this section; calibration error check; (B) Run number; (C) The raw data and results for any (I) Analyzer response to the (C) The beginning date, hour, and moisture measurements made during calibration gas for each pre-run or post- minute of the run; the relative accuracy testing, i.e., the run system bias (or system calibration (D) The ending date, hour, and minute data under paragraphs (a)(7)(v)(A) error) check; of the run; through (a)(7)(v)(O) of this section; and (J) The arithmetic average of the (E) Unit operating level (low, mid, (D) Tabulated, final, corrected analyzer responses to the zero-level gas, high, or normal, as appropriate); reference method run data (i.e., the (F) Moisture measurement method; for each pair of pre- and post-run system actual values used in the relative (G) Volume of H2O collected in the accuracy calculations), along with the bias (or system calibration error) checks; impingers (ml); (K) The arithmetic average of the equations used to convert the raw data (H) Mass of H2O collected in the silica to the final values and example analyzer responses to the upscale gel (g); calibration gas, for each pair of pre- and (I) Dry gas meter calibration factor; calculations to demonstrate how the test post-run system bias (or system (J) Average dry gas meter temperature data were reduced. calibration error) checks; (°F); (iv) For relative accuracy tests for flow (L) The results of each pre-run and (K) Barometric pressure (inches of monitors: each post-run system bias (or system mercury); (A) The raw flow rate reference calibration error) check using the zero- (L) Differential pressure across the method data, from Reference Method 2 (or its allowable alternatives) under level gas (percentage of span value); orifice meter (inches of H2O); (M) The results of each pre-run and (M) Initial and final dry gas meter appendix A to part 60 of this chapter, each post-run system bias (or system readings (ft3); including auxiliary moisture data (often calibration error) check using the (N) Total sample gas volume, in the form of handwritten data sheets), upscale calibration gas (percentage of corrected to standard conditions (dscf); i.e., the data under paragraphs span value); and (a)(7)(ii)(A) through (a)(7)(ii)(T), (N) Calibration drift and zero drift of (O) Percentage of moisture in the paragraphs (a)(7)(iii)(A) through analyzer during each RATA run stack gas (percent H2O). (a)(7)(iii)(M), and, if applicable, (percentage of span value); (vi) The raw data and calculated paragraphs (a)(7)(v)(A) through (O) Moisture basis of the reference results for any stratification tests (a)(7)(v)(O) of this section; and method analysis; performed in accordance with sections (B) The tabulated, final volumetric (P) Moisture content of stack gas, in 6.5.6.1 through 6.5.6.3 of appendix A to flow rate values used in the relative percent, during each test run (if needed this part. accuracy calculations (determined from to convert to moisture basis of CEMS (8) For each certified continuous the flow rate reference method data and being tested); emission monitoring system, continuous other necessary measurements, such as (Q) Unadjusted (raw) average opacity monitoring system, or moisture, stack temperature and pollutant or diluent gas concentration alternative monitoring system, the date pressure), along with the equations used for each run; and description of each event which to convert the raw data to the final (R) Average pollutant or diluent gas requires recertification of the system values and example calculations to concentration for each run, corrected for and the date and type of each test demonstrate how the test data were calibration bias (or calibration error) performed to recertify the system in reduced. and, if applicable, corrected for accordance with § 75.20(b). (v) Calibration gas certificates for the moisture; (9) When hardcopy relative accuracy gases used in the linearity, calibration (S) The F-factor used to convert test reports, certification reports, error, and cycle time tests and for the reference method data to units of lb/ recertification reports, or semiannual or calibration gases used to quality assure mmBtu (if applicable); annual reports for gas or flow rate CEMS the gas monitor reference method data (T) Date(s) of the latest analyzer are required or requested under during the relative accuracy test audit. interference test(s); § 75.60(b)(6) or § 75.63, the reports shall (vi) Laboratory calibrations of the (U) Results of the latest analyzer include, at a minimum, the following source sampling equipment. interference test(s); elements (as applicable to the type(s) of (vii) A copy of the test protocol used (V) Date of the latest NO2 to NO test(s) performed): for the CEMS certifications or conversion test (Method 7E only); (i) Summarized test results. recertifications, including narrative that (W) Results of the latest NO2 to NO (ii) DAHS printouts of the CEMS data explains any testing abnormalities, conversion test (Method 7E only); and generated during the calibration error, problematic sampling, and analytical (X) For each calibration gas cylinder linearity, cycle time, and relative conditions that required a change to the used during each RATA, record the accuracy tests. test protocol, and/or solutions to

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The the owner or operator shall record the (v) For a single-load flow RATA discussion shall also confirm that following (as applicable): claim: sample points satisfy applicable (i) Component/system identification (A) Monitoring system identification acceptance criteria. code; code; (ix) Names of key personnel involved (ii) Parameter; (B) Ending date of last annual flow RATA; in the test program, including test team (iii) Test or activity completion date (C) The relative frequency members, plant contacts, agency and hour; (percentage) of unit or stack operation at representatives and test observers on (iv) Test or activity description; (v) Test result; each load level (low, mid, and high) site. since the previous annual flow RATA, (10) Whenever reference methods are (vi) Reason for test; and to the nearest 0.1 percent. used as backup monitoring systems (vii) Test code. (12) For each request for a quality (D) End date of the historical load pursuant to § 75.20(d)(3), the owner or data collection period; and operator shall record the following assurance test extension or exemption, for any loss of exempt status, and for (E) Indication of the load level (low, information: mid or high) claimed for the single-load (i) For each test run using Reference each single-load flow RATA claim pursuant to section 2.3.1.3(c)(3) of flow RATA. Method 2 (or its allowable alternatives (13) An indication that data have been appendix B to this part, the owner or in appendix A to part 60 of this chapter) excluded from a periodic span and to determine volumetric flow rate, operator shall record the following (as range evaluation of an SO2 or NOX applicable): record the following data elements (as monitor under section 2.1.1.5 or 2.1.2.5 applicable to the measurement method (i) For a RATA deadline extension or exemption request: of appendix A to this part and the used): reason(s) for excluding the data. For (A) Unit or stack identification (A) Monitoring system identification code; purposes of reporting under number; § 75.64(a)(2), this information shall be (B) Reference method system and (B) Date of last RATA; reported with the quarterly report as component identification numbers; (C) RATA expiration date without (C) Run date and hour; extension; descriptive text consistent with (D) The data in paragraph (a)(7)(ii) of (D) RATA expiration date with § 75.64(g). this section, except for paragraphs extension; (b) Excepted monitoring systems for (a)(7)(ii)(A), (F), (H), (L) and (Q) through (E) Type of RATA extension of gas-fired and oil-fired units. The owner (T); and exemption claimed or lost; or operator shall record the applicable (E) The data in paragraph (F) Year to date hours of usage of fuel information in this section for each (a)(7)(iii)(A), except on a run basis. other than very low sulfur fuel; excepted monitoring system following (ii) For each reference method test run (G) Year to date hours of non- the requirements of appendix D to this using Method 6C, 7E, or 3A in appendix redundant back-up CEMS usage at the part or appendix E to this part for A to part 60 of this chapter to determine unit/stack; and determining and recording emissions SO2, NOX, CO2, or O2 concentration: (H) Quarter and year. from an affected unit. (A) Unit or stack identification (ii) For a linearity test or flow-to-load (1) For certification and quality number; ratio test quarterly exemption: assurance testing of fuel flowmeters (B) The reference method system and (A) Component-system identification tested against a reference fuel flow rate component identification numbers; code; (i.e., flow rate from another fuel (C) Run number; (B) Type of test; flowmeter under section 2.1.5.2 of (D) Run start date and hour; (C) Basis for exemption; appendix D to this part or flow rate from (E) Run end date and hour; (D) Quarter and year; and a procedure according to a standard (F) The data in paragraphs (a)(7)(iv)(B) (E) Span scale. incorporated by reference under section through (I) and (L) through (O); and (G) (iii) For a quality assurance test 2.1.5.1 of appendix D to this part): Stack gas density adjustment factor (if extension claim based on a grace period: (i) Unit or common pipe header applicable). (A) Component-system identification identification code; (iii) For each hour of each reference code; (ii) Component and system method test run using Method 6C, 7E, (B) Type of test; identification codes of the fuel or 3A in appendix A to part 60 of this (C) Beginning of grace period; flowmeter being tested; chapter to determine SO2, NOX, CO2, or (D) Date and hour of completion of (iii) Date and hour of test completion, O2 concentration: required quality assurance test; for a test performed in-line at the unit; (A) Unit or stack identification (E) Number of unit or stack operating (iv) Date and hour of flowmeter number; hours from the beginning of the grace reinstallation, for laboratory tests; (B) The reference method system and period to the completion of the quality (v) Test number; component identification numbers; assurance test or the maximum (vi) Upper range value of the fuel (C) Run number; allowable grace period; and flowmeter; (D) Run date and hour; (F) Date and hour of end of grace (vii) Flowmeter measurements during (E) Pollutant or diluent gas being period. accuracy test (and mean of values), measured; (iv) For a fuel flowmeter accuracy test including units of measure; (F) Unadjusted (raw) average extension: (viii) Reference flow rates during pollutant or diluent gas concentration (A) Component-system identification accuracy test (and mean of values), for the hour; and code; including units of measure;

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(ix) Level of fuel flowrate test during (4) For fuel flowmeters that are tested (A) Unit or common pipe runs (low, mid or high); using the optional fuel flow-to-load ratio identification code; (x) Average flowmeter accuracy for procedures of section 2.1.7 of appendix (B) Monitoring system identification low and high fuel flowrates and highest D to this part: code for appendix E system; flowmeter accuracy of any level (i) Test data for the fuel flowmeter (C) Run start date and time; designated as mid, expressed as a flow-to-load ratio or gross heat rate (D) Run end date and time; percent of upper range value; check, including: (E) Total heat input during the run (xi) Indicator of whether test method (A) Component/system identification (mmBtu); was a lab comparison to reference meter code; (F) NOX emission rate (lb/mmBtu) or an in-line comparison against a (B) Calendar year and quarter; from reference method; master meter; (C) Indication of whether the test is (G) Response time of the O2 and NOX (xii) Test result (aborted, pass, or fail); for fuel flow-to-load ratio or gross heat reference method analyzers; and rate; (H) Type of fuel(s) combusted during (xiii) Description of fuel flowmeter (D) Quarterly average absolute percent the run; calibration specification or procedure difference between baseline for fuel (I) Heat input rate (mmBtu/hr) during (in the certification application, or flow-to-load ratio (or baseline gross heat the run; periodically if a different method is rate and hourly quarterly fuel flow-to- (J) Test number; used for annual quality assurance load ratios (or gross heat rate value); (K) Run number; testing). (E) Test result; (L) Operating level during the run; (2) For each transmitter or transducer (F) Number of hours used in the (M) NOX concentration recorded by accuracy test for an orifice-, nozzle-, or analysis; the reference method during the run; venturi-type flowmeter used under (G) Number of hours excluded due to (N) Diluent concentration recorded by section 2.1.6 of appendix D to this part: co-firing; the reference method during the run; (i) Component and system (H) Number of hours excluded due to and identification codes of the fuel ramping; and (O) Moisture measurement for the run (I) Number of hours excluded in lower flowmeter being tested; (if applicable). (ii) Completion date and hour of test; 25.0 percent range of operation. (ii) For each run during which oil or (iii) For each transmitter or (ii) Reference data for the fuel mixed fuels are combusted record the transducer: transmitter or transducer flowmeter flow-to-load ratio or gross following data: type (differential pressure, static heat rate evaluation, including: (A) Unit or common pipe pressure, or temperature); the full-scale (A) Completion date and hour of most identification code; value of the transmitter or transducer, recent primary element inspection; (B) Monitoring system identification transmitter input (pre-calibration) prior (B) Completion date and hour of most code for oil monitoring system; to accuracy test, including units of recent flowmeter or transmitter accuracy (C) Run start date and time; measure; and expected transmitter test; (D) Run end date and time; output during accuracy test (reference (C) Beginning date and hour of (E) Mass flow or volumetric flow of value from NIST-traceable equipment), baseline period; oil, in the units of measure for the type including units of measure; (D) Completion date and hour of (iv) For each transmitter or transducer baseline period; of fuel flowmeter; tested: output during accuracy test, (E) Average fuel flow rate, in 100 scfh (F) Gross calorific value of oil in the including units of measure; transmitter for gas and lb/hr for oil; appropriate units of measure; (G) Density of fuel oil in the or transducer accuracy as a percent of (F) Average load, in megawatts or appropriate units of measure (if density the full-scale value; and transmitter 1000 lb/hr of steam; is used to convert oil volume to mass); output level as a percent of the full-scale (G) Baseline fuel flow-to-load ratio, in (H) Hourly heat input (mmBtu) during value; the appropriate units of measure (if (v) Average flowmeter accuracy at low using fuel flow-to-load ratio); run from oil; and high fuel flowrates and highest (H) Baseline gross heat rate if using (I) Test number; flowmeter accuracy of any level gross heat rate, in the appropriate units (J) Run number; and (K) Operating level during the run. designated as mid fuel flowrate, of measure (if using gross heat rate (iii) For each run during which gas or expressed as a percent of upper range check); mixed fuels are combusted record the value; (I) Number of hours excluded from (vi) Test result (pass, fail, or aborted); baseline data due to ramping; following data: (vii) Test number; and (J) Number of hours excluded from (A) Unit or common pipe (viii) Accuracy determination baseline data in lower 25.0 percent of identification code; methodology. range of operation; (B) Monitoring system identification (3) For each visual inspection of the (K) Average hourly heat input rate; code for gas monitoring system; primary element or transmitter or and (C) Run start date and time; transducer accuracy test for an (L) Flag indicating baseline data (D) Run end date and time; orifice-, nozzle-, or venturi-type collection is in progress and that fewer (E) Volumetric flow of gas (100 scf); flowmeter under sections 2.1.6.1 than four calendar quarters have elapsed (F) Gross calorific value of gas (Btu/ through 2.1.6.4 of appendix D to this since the quarter of the last flowmeter 100 scf); part: QA test. (G) Hourly heat input (mmBtu) during (i) Date of inspection/test; (5) For gas-fired peaking units or oil- run from gas; (ii) Hour of completion of inspection/ fired peaking units using the optional (H) Test number; test; procedures of appendix E to this part, (I) Run number; and (iii) Component and system for each initial performance, periodic, or (J) Operating level during the run. identification codes of the fuel quality assurance/quality control-related (iv) For each operating level at which flowmeter being inspected/tested; and test: runs were performed: (iv) Results of inspection/test (pass or (i) For each run of emission data, (A) Completion date and time of last fail). record the following data: run for operating level;

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(B) Type of fuel(s) combusted during (xiv) The default NOX emission rate (b) * * * test; (highest NOX emission rate value during (1) Initial certifications. The (C) Average heat input rate at that the test multiplied by 1.15); designated representative shall submit operating level (mmBtu/hr); (xv) An indicator that control initial certification applications (D) Arithmetic mean of NOX emission equipment was operating or not according to § 75.63. rates from reference method run at this operating during each run of the test; (2) Recertifications. The designated level; and representative shall submit (E) F-factor used in calculations of (xvi) Parameter data indicating the recertification applications according to NOX emission rate at that operating use and efficacy of control equipment § 75.63. level; during the test. (3) Monitoring plans. The designated (F) Unit operating parametric data (2) For each unit in a group of representative shall submit monitoring related to NOX formation for that unit identical units qualifying for reduced plans according to § 75.62. type (e.g., excess O2 level, water/fuel testing under § 75.19(c)(1)(iv)(B), record (4) Electronic quarterly reports. The ratio); the following data: designated representative shall submit (G) Test number; and (i) The unique group identification electronic quarterly reports according to (H) Operating level for runs. code assigned to the group. This code § 75.64. (5) Other petitions and (c) For units with add-on SO2 or NOX must include the ORIS code of one of emission controls following the the units in the group; communications. The designated provisions of § 75.34(a)(1) or (a)(2), the (ii) The ORIS code or facility representative shall submit petitions, owner or operator shall keep the identification code for the unit; correspondence, application forms, following records on-site in the quality (iii) The plant name of the facility at designated representative signature, and assurance/quality control plan required which the unit is located, consistent petition-related test results in hardcopy by section 1 of appendix B to this part: with the facility’s monitoring plan; to the Administrator. Additional (1) A list of operating parameters for (iv) The identification code for the petition requirements are specified in the add-on emission controls, including unit, consistent with the facility’s §§ 75.66 and 75.67. (6) Semiannual or annual RATA parameters in § 75.55(b) or § 75.58(b), monitoring plan; reports. If requested by the applicable appropriate to the particular installation (v) A record of whether or not the unit EPA Regional Office, appropriate State, of add-on emission controls; and underwent fuel and unit-specific testing and/or appropriate local air pollution (2) The range of each operating for purposes of establishing a fuel and parameter in the list that indicates the control agency, the designated unit-specific NOX emission rate for representative shall submit a hardcopy add-on emission controls are properly purposes of § 75.19; RATA report within 45 days after operating. (vi) The completion date of the fuel completing a required semiannual or (d) Excepted monitoring for low mass and unit-specific test performed for annual RATA according to section 2.3.1 emissions units under § 75.19(c)(1)(iv). purposes of establishing a fuel and unit- For oil-and gas-fired units using the of appendix B to this part, or within 15 specific NOX emission rate for purposes days of receiving the request, whichever optional SO2, NOX and CO2 emissions of § 75.19; is later. The designated representative calculations for low mass emission units (vii) The fuel and unit-specific NO X shall report the hardcopy information under § 75.19, the owner or operator default rate established for the group of required by § 75.59(a)(9) to the shall record the following information identical units under § 75.19; applicable EPA Regional Office, for tests performed to determine a fuel (viii) The type of fuel combusted for appropriate State, and/or appropriate and unit-specific default as provided in the units during testing and represented § 75.19(c)(1)(iv): local air pollution control agency that by the resulting default NOX emission requested the RATA report. (1) For each run of each test rate; performed under section 2.1 of (ix) The control status for the units * * * * * appendix E to this part, record the during testing and represented by the 44. Section 75.61 is amended by following data: revising paragraphs (a) introductory resulting default NOX emission rate; (i) Unit or common pipe identification (x) Documentation supporting the text, (a)(1) introductory text, and (b), by code; qualification of all units in the group for adding a new sentence to the end of (ii) Run start date and time; reduced testing based on the criteria paragraph (a)(6)(ii), and by adding a (iii) Run end date and time; established in §§ 75.19(c)(1)(iv)(B)(1) new paragraph (a)(1)(iv) to read as (iv) NOX emission rate (lb/mmBtu) and (3); and follows: from reference method; (xi) Purpose of group tests. § 75.61 Notifications. (v) Response time of the O2 and NOX (a) Submission. The designated reference method analyzers; Subpart GÐReporting Requirements (vi) Type of fuel(s) combusted during representative for an affected unit (or the run; 43. Section 75.60 is amended by owner or operator, as specified) shall (vii) Test number; revising paragraphs (a), (b)(1), and (b)(2) submit notice to the Administrator, to (viii) Run number; and by adding new paragraphs (b)(3), the appropriate EPA Regional Office, (ix) Operating level during the run; (b)(4), (b)(5) and (b)(6) to read as and to the applicable State and local air (x) NOX concentration recorded by the follows: pollution control agencies for the reference method during the run; following purposes, as required by this (xi) Diluent concentration recorded by § 75.60 General provisions. part. the reference method during the run; (a) The designated representative for (1) Initial certification and (xii) Moisture measurement for the any affected unit subject to the recertification test notifications. The run (if applicable); requirements of this part shall comply owner or operator or designated (xiii) An indicator that the resulting with all reporting requirements in this representative for an affected unit shall NOX emission rate is the highest NOX section and with the signatory submit written notification of initial emission rate record during any run of requirements of § 72.21 of this chapter certification tests, recertification tests, the test (if appropriate); for all submissions. and revised test dates as specified in

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§ 75.20 for continuous emission Office and the appropriate State and/or (B) To the applicable EPA Regional monitoring systems, for alternative local air pollution control agency prior Office and appropriate State and/or monitoring systems under subpart E of to initial certification. Thereafter, the local air pollution control agency, the this part, or for excepted monitoring designated representative shall submit hardcopy information required by systems under appendix E to this part, hardcopy information only if that paragraphs (b)(2)(i), (iii), and (iv). except as provided in paragraphs portion of the monitoring plan is (2) Recertifications. (i) Within 45 days (a)(1)(iii), (a)(1)(iv) and (a)(4) of this revised. The designated representative after completing all recertification tests, section and except for testing only of the shall submit the required hardcopy submit to the Administrator the data acquisition and handling system. information as follows: no later than 45 electronic information required by * * * * * days prior to the initial certification test; paragraph (b)(1) and a hardcopy (iv) Waiver from notification with any recertification application, if a certification application form (EPA form requirements. The Administrator, the hardcopy monitoring plan change is 7610–14). Except for subpart E appropriate EPA Regional Office, or the associated with the recertification event; applications for alternative monitoring applicable State or local air pollution and within 30 days of any other event systems or unless specifically requested control agency may issue a waiver from with which a hardcopy monitoring plan by the Administrator, do not submit a the notification requirement of change is associated, pursuant to hardcopy of the test data and results to paragraph (a)(1) of this section, for a § 75.53(b). Electronic submittal of all the Administrator. (ii) Within 45 days after completing unit or a group of units, for one or more monitoring plan information, including all recertification tests, submit the recertification tests. The Administrator, hardcopy portions, is permissible hardcopy information required by the appropriate EPA Regional Office, or provided that a paper copy of the paragraph (b)(2) to the applicable EPA the applicable State or local air hardcopy portions can be furnished Regional Office and the appropriate pollution control agency may also upon request. State and/or local air pollution control discontinue the waiver and reinstate the * * * * * agency. The applicable EPA Regional notification requirement of paragraph (c) Format. The designated Office or appropriate State or local air (a)(1) of this section for future representative shall submit each pollution control agency may waive the recertification tests of a unit or a group monitoring plan in a format specified by requirement for submission to it of a of units. the Administrator. hardcopy recertification. The applicable * * * * * 46. Section 75.63 is revised to read as EPA Regional Office or the appropriate (6) * * * follows: State or local air pollution control (ii) * * * The reporting requirements agency may also discontinue the waiver of this paragraph (a)(6)(ii) also shall § 75.63 Initial certification or recertification application submittals. and reinstate the requirement of this apply if the designated representative of (a) Submission. The designated paragraph to provide a hardcopy report a unit is exempt from certifying a fuel of the recertification test data and flowmeter for use during the representative for an affected unit or a combustion source shall submit results. combustion of emergency fuel under (iii) Notwithstanding the applications and reports as follows: section 2.1.4.3 of appendix D to this requirements of paragraphs (a)(2)(i) and part. (1) Initial certifications. (i) Within 45 (a)(2)(ii) of this section, for an event for (b) The owner or operator or days after completing all initial which the Administrator determines designated representative shall submit certification tests, submit to the that only diagnostic tests (see § 75.20(b)) notification of certification tests and Administrator the electronic are required, no hardcopy submittal is recertification tests for continuous information required by paragraph (b)(1) required; however, the results of all opacity monitoring systems as specified of this section and a hardcopy diagnostic test(s) shall be submitted in in § 75.20(c)(8) to the State or local air certification application form (EPA form the electronic quarterly report required pollution control agency. 7610–14). Except for subpart E under § 75.64. For DAHS (missing data * * * * * applications for alternative monitoring and formula) verifications, neither a 45. Section 75.62 is amended by systems or unless specifically requested hardcopy nor an electronic submittal of revising the title of the section and by the Administrator, do not submit a any kind is required; the owner or revising paragraphs (a) and (c) to read as hardcopy of the test data and results to operator shall keep these test results on- follows: the Administrator. site in a format suitable for inspection. (ii) Within 45 days after completing (b) Contents. Each application for § 75.62 Monitoring plan submittals. all initial certification tests, submit the initial certification or recertification (a) Submission.—(1) Electronic. Using hardcopy information required by shall contain the following information, the format specified in paragraph (c) of paragraph (b)(2) to the applicable EPA as applicable: this section, the designated Regional Office and the appropriate (1) Electronic. (i) A complete, up-to- representative for an affected unit shall State and/or local air pollution control date version of the electronic portion of submit a complete, electronic, up-to- agency. the monitoring plan, according to date monitoring plan file (except for (iii) For units for which the owner or §§ 75.53(c) and (d), or §§ 75.53(e) and hardcopy portions identified in operator is applying for certification (f), as applicable, in the format specified paragraph (a)(2) of this section) to the approval of the optional excepted in § 75.62(c). Administrator as follows: no later than methodology under § 75.19 for low mass (ii) The results of the test(s) required 45 days prior to the initial certification emissions units, submit: by § 75.20, including the type of test test; at the time of recertification (A) To the Administrator, the conducted, testing date, information application submission; and in each electronic information required by required by § 75.56 or § 75.59, as electronic quarterly report. paragraph (b)(1)(i), the hardcopy applicable, and the results of any failed (2) Hardcopy. The designated information required by paragraph tests that affect data validation. representative shall submit all of the (b)(2), and a hardcopy certification (2) Hardcopy. (i) Any changed hardcopy information required under application form (EPA form 7610–14); portions of the hardcopy monitoring § 75.53 to the appropriate EPA Regional and plan information required under

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§§ 75.53(c) and (d), or §§ 75.53(e) and (a)(2) through (a)(11) of this section, and problems with the reference method or (f), as applicable. Electronic submittal of shall also include for each affected unit operational problems with the unit and all monitoring plan information, (or group of units using a common data and results of linearity checks that including the hardcopy portions, is stack): are aborted or invalidated due to permissible, provided that a paper copy (1) Facility information: problems unrelated to monitor can be furnished upon request. (i) Identification, including: performance; and (ii) The results of the test(s) required (A) Facility/ORISPL number; (xiv) Supplementary RATA by § 75.20, including the type of test (B) Calendar quarter and year for the information required under conducted, testing date, information data contained in the report; and § 75.59(a)(7)(i) through § 75.59(a)(7)(v), required by § 75.59(a)(9), and the results (C) Version of the electronic data except that: the data under of any failed tests that affect data reporting format used for the report. § 75.59(a)(7)(ii)(A) through (T) and the validation. (ii) Location, including: data under § 75.59(a)(7)(iii)(A) through (iii) Certification or recertification (A) Plant name and facility ID; (M) shall, as applicable, be reported for (B) EPA AIRS facility system ID; application form (EPA form 7610–14). flow RATAs in which angular (C) State facility ID; (iv) Designated representative compensation (measurement of pitch signature. (D) Source category/type; (E) Primary SIC code; and/or yaw angles) is used and for flow (c) Format. The electronic portion of RATAs in which a site-specific wall each certification or recertification (F) State postal abbreviation; (G) County code; and effects adjustment factor is determined application shall be submitted in a (H) Latitude and longitude. by direct measurement; and the data format to be specified by the (2) The information and hourly data under § 75.59(a)(7)(ii)(T) shall be Administrator. The hardcopy test results required in §§ 75.53 through 75.59, reported for all flow RATAs in which a shall be submitted in a format suitable excluding the following: default wall effects adjustment factor is for review and shall include the (i) Descriptions of adjustments, applied. information in § 75.59(a)(9). corrective action, and maintenance; (3) Tons (rounded to the nearest 47. Section 75.64 is revised to read as (ii) Information which is incompatible tenth) of SO2 emitted during the quarter follows: with electronic reporting (e.g., field data and cumulative SO2 emissions for the § 75.64 Quarterly reports. sheets, lab analyses, quality control calendar year. (a) Electronic submission. The plan); (4) Average NOX emission rate (lb/ (iii) Opacity data listed in § 75.54(f) or designated representative for an affected mmBtu, rounded to the nearest § 75.57(f), and in § 75.59(a)(8); unit shall electronically report the data hundredth prior to April 1, 2000 and to (iv) For units with SO2 or NOX add- and information in paragraphs (a), (b), the nearest thousandth on and after on emission controls that do not elect to and (c) of this section to the April 1, 2000) during the quarter and use the approved site-specific Administrator quarterly, beginning with cumulative NOX emission rate for the parametric monitoring procedures for the data from the later of: the last calendar year. calculation of substitute data, the (5) Tons of CO2 emitted during (partial) calendar quarter of 1993 (where information in § 75.55(b)(3) or quarter and cumulative CO2 emissions the calendar quarter data begins at § 75.58(b)(3); for calendar year. November 15, 1993); or the calendar (v) The information recorded under (6) Total heat input (mmBtu) for quarter corresponding to the date of § 75.56(a)(7) for the period prior to April quarter and cumulative heat input for provisional certification; or the calendar 1, 2000; calendar year. quarter corresponding to the relevant (vi) Information required by § 75.54(g) (7) Unit or stack or common pipe deadline for initial certification in or § 75.57(h) concerning the causes of header operating hours for quarter and § 75.4(a), (b), or (c), whichever quarter is any missing data periods and the cumulative unit or stack or common earlier. The initial quarterly report shall actions taken to cure such causes; pipe header operating hours for contain hourly data beginning with the (vii) Hardcopy monitoring plan calendar year. hour of provisional certification or the information required by § 75.53 and (8) If the affected unit is using a hour corresponding to the relevant hardcopy test data and results required qualifying Phase I technology, then the certification deadline, whichever is by § 75.56 or § 75.59; quarterly report shall include the earlier. For an affected unit subject to (viii) Records of flow monitor and information required in paragraph (e) of § 75.4(d) that is shutdown on the moisture monitoring system polynomial this section. relevant compliance date in § 75.4(a), equations, coefficients or ‘‘K’’ factors (9) For low mass emissions units for the owner or operator shall submit required by § 75.56(a)(5)(vii), which the owner or operator is using the quarterly reports for the unit beginning § 75.56(a)(5)(ix), § 75.59(a)(5)(vi) or optional low mass emissions with the data from the quarter in which § 75.59(a)(5)(vii); methodology in § 75.19(c) to calculate the unit recommences commercial (ix) Daily fuel sampling information NOX mass emissions, the designated operation (where the initial quarterly required by § 75.58(c)(3)(i) for units representative must also report tons report contains hourly data beginning using assumed values under appendix (rounded to the nearest tenth) of NOX with the first hour of recommenced D; emitted during the quarter and commercial operation of the unit). For (x) Information required by cumulative NOX mass emissions for the any provisionally-certified monitoring §§ 75.59(b)(1)(vi), (vii), (viii), (ix), and calendar year. system, § 75.20(a)(3) shall apply for (xiii), and (b)(2)(iii) and (iv) concerning (10) For low mass emissions units initial certifications, and § 75.20(b)(5) fuel flowmeter accuracy tests and using the optional long term fuel flow shall apply for recertifications. Each transmitter/transducer accuracy tests; methodology under § 75.19(c), for each electronic report must be submitted to (xi) Stratification test results required quarter report the long term fuel flow for the Administrator within 30 days as part of the RATA supplementary each fuel according to § 75.59. following the end of each calendar records under §§ 75.56(a)(7) or (11) For units using the optional fuel quarter. Each electronic report shall 75.59(a)(7); flow to load procedure in section 2.1.7 include the date of report generation for (xii) Data and results of RATAs that of appendix D to this part, report both the information provided in paragraphs are aborted or invalidated due to the fuel flow-to-load baseline data and

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The to the Administrator pursuant to either be submitted in hardcopy to the designated representative for an affected § 75.53, represent current operating Agency or be provided in electronic unit may submit a petition to the conditions. format compatible with the other data Administrator to use an alternative to (c) Compliance certification. The required to be reported under this the procedures in § 75.4(d)(3), (e)(3), designated representative shall submit a section. (f)(3) or (g)(3) to account for emissions certification in support of each quarterly 48. Section 75.65 is revised to read as during the period between the emissions monitoring report based on follows: compliance date for a unit and the reasonable inquiry of those persons with completion of certification testing for primary responsibility for ensuring that § 75.65 Opacity reports. that unit. The designated representative all of the unit’s emissions are correctly The owner or operator or designated shall include: and fully monitored. The certification representative shall report excess (1) Identification of the affected shall indicate whether the monitoring emissions of opacity recorded under unit(s); data submitted were recorded in § 75.54(f) or § 75.57(f), as applicable, to (2) A detailed explanation of the accordance with the applicable the applicable State or local air alternative method to account for requirements of this part including the pollution control agency. emissions of the following parameters, quality control and quality assurance 49. Section 75.66 is amended by as applicable: SO2 mass emissions (in procedures and specifications of this revising paragraph (a) and the first lbs), NOX emission rate (in lbs/mmBtu), part and its appendices, and any such sentence of paragraph (e) introductory CO2 mass emissions (in lbs) and, if the requirements, procedures and text; by redesignating paragraph (i) as unit is subject to the requirements of specifications of an applicable excepted paragraph (l) and revising it; and by subpart H of this part, NOX mass or approved alternative monitoring adding paragraphs (i) through (k) to read emissions (in lbs); and method. For a unit with add-on as follows: (3) A demonstration that the proposed emission controls, the designated alternative does not underestimate representative shall also include a § 75.66 Petitions to the Administrator. emissions. certification, for all hours where data (a) General. The designated (k) Petition for an alternative to the are substituted following the provisions representative for an affected unit stabilization criteria for the cycle time of § 75.34(a)(1), that the add-on subject to the requirements of this part test in section 6.4 of appendix A to this emission controls were operating within may submit a petition to the part. The designated representative for the range of parameters listed in the Administrator requesting that the an affected unit may submit a petition monitoring plan and that the substitute Administrator exercise his or her to the Administrator to use an values recorded during the quarter do discretion to approve an alternative to alternative stabilization criteria for the not systematically underestimate SO2 or any requirement prescribed in this part cycle time test in section 6.4 of NOX emissions, pursuant to § 75.34. or incorporated by reference in this part. appendix A to this part, if the installed (d) Electronic format. Each quarterly Any such petition shall be submitted in monitoring system does not record data report shall be submitted in a format to accordance with the requirements of in 1-minute or 3-minute intervals. The be specified by the Administrator, this section. The designated designated representative shall provide including both electronic submission of representative shall comply with the a description of the alternative criteria. data and electronic or hardcopy signatory requirements of § 72.21 of this (l) Any other petitions to the submission of compliance certifications. chapter for each submission. Administrator under this part. Except (e) Phase I qualifying technology * * * * * for petitions addressed in paragraphs (b) reports. In addition to reporting the through (k) of this section, any petition information in paragraphs (a), (b), and (e) Parametric monitoring procedure petitions. The designated representative submitted under this paragraph shall (c) of this section, the designated include sufficient information for the representative for an affected unit on for an affected unit may submit a petition to the Administrator, where evaluation of the petition, including, at which SO2 emission controls have been each petition shall contain the a minimum, the following information: installed and operated for the purpose (1) Identification of the affected plant information specified in § 75.55(b) or of meeting qualifying Phase I technology and unit(s); § 75.58(b), as applicable, for the use of requirements pursuant to § 72.42 of this (2) A detailed explanation of why the a parametric monitoring method. * ** chapter shall also submit reports proposed alternative is being suggested documenting the measured percent SO2 * * * * * in lieu of the requirement; emissions removal to the Administrator (i) Emergency fuel petition. The (3) A description and diagram of any on a quarterly basis, beginning the first designated representative for an affected equipment and procedures used in the quarter of 1997 and continuing through unit may submit a petition to the proposed alternative, if applicable; the fourth quarter of 1999. Each report Administrator to use the emergency fuel (4) A demonstration that the proposed shall include all measurements and provisions in section 2.1.4 of appendix alternative is consistent with the calculations necessary to substantiate E to this part. The designated purposes of the requirement for which that the qualifying technology achieves representative shall include the the alternative is proposed and is the required percent reduction in SO2 following information in the petition: consistent with the purposes of this part emissions. (1) Identification of the affected plant and of section 412 of the Act and that (f) Method of submission. Beginning and unit(s); any adverse effect of approving such with the quarterly report for the first (2) A procedure for determining the alternative will be de minimis; and quarter of the year 2001, all quarterly NOX emission rate for the unit when the (5) Any other relevant information reports shall be submitted to EPA by emergency fuel is combusted; and that the Administrator may require.

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Subpart HÐNOX Mass Emissions (g) * * * annual capacity factor of 10.0 percent Provisions (6) For any unit using continuous averaged over three years, or the emissions monitors, the procedures in operation of a unit that reports 50. Section 75.70 is amended by § 75.20(b)(3). emissions on an ozone season basis revising paragraphs (e), (f) introductory * * * * * under § 75.74(b) of this part exceeds a text and (f)(1)(iv), and by adding new 51. Section 75.71 is amended by capacity factor of 20.0 percent in any paragraph (g)(6) to read as follows: revising paragraphs (b) and (d)(2) to ozone season or exceeds an ozone

§ 75.70 NOX mass emissions provisions. read as follows: season capacity factor of 10.0 percent * * * * * averaged over three years, the owner or § 75.71 Specific provisions for monitoring operator shall meet the requirements of (e) Quality assurance and quality NO emission rate and heat input for the X paragraph (c) of this section or, if control requirements. For units that use purpose of calculating NOX mass continuous emission monitoring emissions. applicable, paragraph (e) of this section by no later than December 31 of the systems to account for NOX mass * * * * * following calendar year. emissions, the owner or operator shall (b) Moisture correction. (1) If a meet the applicable quality assurance correction for the stack gas moisture * * * * * and quality control requirements in content is needed to properly calculate 52. Text is added to reserved section 75.73 to read as follows: § 75.21, appendix B to this part, and the NOX emission rate in lb/mmBtu (i.e., § 75.74(c) for the NOX-diluent if the NOX pollutant concentration § 75.73 Recordkeeping and reporting. continuous emission monitoring monitor in a NOX-diluent monitoring (a) General recordkeeping provisions. systems, flow monitoring systems, NOX system measures on a different moisture The owner or operator of any affected concentration monitoring systems, and basis from the diluent monitor), the unit shall maintain for each affected diluent monitors required under § 75.71. owner or operator of an affected unit unit and each non-affected unit under A NOX concentration monitoring system shall account for the moisture content of § 75.72(b)(2)(ii) a file of all for determining NOX mass emissions in the flue gas on a continuous basis in measurements, data, reports, and other accordance with § 75.71 shall meet the accordance with § 75.12(b). information required by this part at the same certification testing requirements, (2) If a correction for the stack gas source in a form suitable for inspection quality assurance requirements, and moisture content is needed to properly for at least three (3) years from the date bias test requirements as are specified in calculate NOX mass emissions in tons, of each record. Except for the this part for an SO2 pollutant in the case where a NOX concentration certification data required in concentration monitor, except as monitoring system which measures on a § 75.57(a)(4) and the initial submission otherwise provided in § 75.74(c). Units dry basis is used with a flow rate of the monitoring plan required in using excepted methods under § 75.19 monitor to determine NOX mass § 75.57(a)(5), the data shall be collected shall meet the applicable quality emissions, the owner or operator of an beginning with the earlier of the date of assurance requirements of that section, affected unit shall account for the provisional certification or the deadline and, except as otherwise provided in moisture content of the flue gas on a in § 75.70. The certification data § 75.74(c), units using excepted continuous basis in accordance with required in § 75.57(a)(4) shall be monitoring methods under appendices § 75.11(b) except that the term ‘‘SO2’’ collected beginning with the date of the D and E to this part shall meet the shall be replaced by the term ‘‘NOX.’’ first certification test performed. The (3) If a correction for the stack gas applicable quality assurance file shall contain the following moisture content is needed to properly requirements of those appendices. information: (f) Missing data procedures. Except as calculate NOX mass emissions, in the (1) The information required in provided in § 75.34, paragraph (g) of this case where a diluent monitor that §§ 75.57(a)(2), (a)(4), (a)(5), (a)(6), (b), section, and § 75.74, the owner or measures on a dry basis is used with a (c)(2), (d), (g), and (h). operator shall provide substitute data flow rate monitor to determine heat (2) The information required in from monitoring systems required under input, which is then multiplied by the §§ 75.58(b)(2) or (b)(3) (for units with § 75.71 for each affected unit as follows: NOX emission rate, the owner or add-on NOX emission controls), as (1) * * * operator shall install, operate, maintain applicable, (d) (as applicable for units (iv) A valid, quality-assured hour of and quality assure a continuous using Appendix E to this part), and (f) NOX concentration data (in ppm) has moisture monitoring system, as (as applicable for units using the low not been measured and recorded by a described in § 75.11(b). mass emissions unit provisions of certified NOX concentration monitoring * * * * * § 75.19). system, or by an approved alternative (d) * * * (3) For each hour when the unit is monitoring method under subpart E of (2) Use the procedures in appendix D operating, NOX mass emissions, this part, where the owner or operator to this part for determining hourly heat calculated in accordance with section chooses to use a NOX concentration input and the procedure specified in 8.1 of appendix F to this part. monitoring system with a volumetric appendix E to this part for estimating (4) During the second and third flow monitor, and without a diluent hourly NOX emission rate. However, the calendar quarters, cumulative ozone monitor to calculate NOX mass heat input apportionment provisions in season heat input and cumulative ozone emissions. The initial missing data section 2.1.2 of appendix D to this part season operating hours. procedures for determining monitor shall not be used to meet the NOX mass (5) Heat input and NOX data availability and the standard reporting provisions of this subpart. In methodologies for the hour. missing data procedures for a NOX addition, if after certification of an (6) Specific heat input record concentration monitoring system shall excepted monitoring system under provisions for gas-fired or oil-fired units be the same as the procedures specified appendix E to this part, the operation of using the procedures in appendix D to for a NOX-diluent continuous emission a unit that reports emissions on an this part. In lieu of the information monitoring system under §§ 75.31, 75.32 annual basis under § 75.74(a) of this part required in § 75.57(c)(2), the owner or and 75.33. exceeds a capacity factor of 20.0 percent operator shall record the following * * * * * in any calendar year or exceeds an information in this paragraph for each

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Except as provided in procedures in appendix D to this part up to the nearest fraction of an hour, in paragraph (d) or (f) of this section, a for estimating heat input: equal increments that can range from monitoring plan shall contain sufficient (i) For each hour when the unit is one hundredth to one quarter of an information on the continuous emission combusting oil: hour, at the option of the owner or monitoring systems, excepted (A) Date and hour; operator) (flag to indicate multiple/ methodology under § 75.19, or excepted (B) Hourly average mass flow rate of single fuel types combusted); and monitoring systems under appendix D oil, while the unit combusts oil (in lb/ (F) Monitoring system identification or E to this part and the use of data hr, rounded to the nearest tenth) (flag code. derived from these systems to value if derived from missing data (iv) For each oil sample or sample of demonstrate that all the unit’s NOX procedures); diesel fuel: emissions are monitored and reported. (C) Method of oil sampling (flow (A) Date of sampling; (2) Whenever the owner or operator proportional, continuous drip, as (B) Gross calorific value (in Btu/lb) makes a replacement, modification, or delivered, manual from storage tank, or (flag value if derived from missing data change in the certified continuous daily manual); procedures); and emission monitoring system, excepted (D) For units using volumetric (C) Density or specific gravity, if methodology under § 75.19, excepted flowmeters, volumetric flow rate of oil required to convert volume to mass (flag monitoring system under appendix D or combusted each hour (in gal/hr, lb/hr, value if derived from missing data E to this part, or alternative monitoring 3 m /hr, or bbl/hr, rounded to the nearest procedures). system under subpart E of this part, tenth) (flag value if derived from (v) For each sample of gaseous fuel: including a change in the automated missing data procedures); (A) Date of sampling; and data acquisition and handling system or (E) For units using volumetric oil (B) Gross calorific value (in Btu/100 in the flue gas handling system, that flowmeters, density of oil (flag value if scf) (flag value if derived from missing affects information reported in the derived from missing data procedures); data procedures). monitoring plan (e.g., a change to a (vi) For each oil sample or sample of (F) Gross calorific value of oil used to serial number for a component of a gaseous fuel: determine heat input (in Btu/lb); monitoring system), then the owner or (G) Hourly heat input rate during (A) Type of oil or gas; and (B) Percent carbon or F-factor of fuel. operator shall update the monitoring combustion of oil, according to plan. procedures in appendix F to this part (in (7) Specific NOX record provisions for (3) Contents of the monitoring plan mmBtu/hr, to the nearest tenth); gas-fired or oil-fired units using the for units not subject to an Acid Rain (H) Fuel usage time for combustion of optional low mass emissions excepted emissions limitation. Each monitoring oil during the hour (rounded up to the methodology in § 75.19. In lieu of plan shall contain the information in nearest fraction of an hour, in equal recording the information in §§ 75.57(b), § 75.53(e)(1) in electronic format and the increments that can range from one (c)(2), (d), and (g), the owner or operator information in § 75.53(e)(2) in hardcopy hundredth to one quarter of an hour, at shall record, for each hour when the format. In addition, to the extent the option of the owner or operator) unit is operating for any portion of the applicable, each monitoring plan shall (flag to indicate multiple/single fuel hour, the following information for each contain the information in types combusted); and affected low mass emissions unit for (I) Monitoring system identification which the owner or operator is using the §§ 75.53(f)(1)(i), (f)(2)(i), (f)(4), and code. low mass emissions excepted (f)(5)(i) for units using the low mass (ii) For gas-fired units or oil-fired methodology in § 75.19(c): emitter methodology in electronic units, using the procedures in appendix (i) Date and hour; format and the information in D to this part with an assumed density (ii) If one type of fuel is combusted in §§ 75.53(f)(1)(ii), (f)(2)(ii), and (f)(5)(ii) or for as-delivered fuel sampled from the hour, fuel type (pipeline natural gas, in hardcopy format. The monitoring each delivery: natural gas, residual oil, or diesel fuel) plan also shall identify, in electronic (A) Measured gross calorific value or, if more than one type of fuel is format, the reporting schedule for the and, if measuring with volumetric oil combusted in the hour, the fuel type affected unit (ozone season or flowmeters, density from each fuel which results in the highest emission quarterly), the beginning and end dates for the reporting schedule, and whether sample; and factors for NOX; (B) Assumed gross calorific value and, (iii) Average hourly NOX emission year-round reporting for the unit is if measuring with volumetric oil rate (in lb/mmBtu, rounded to the required by a state or local agency. flowmeters, density used to calculate nearest thousandth); and (d) General reporting provisions. (1) heat input rate. (iv) Hourly NOX mass emissions (in The designated representative for an (iii) For each hour when the unit is lbs, rounded to the nearest tenth). affected unit shall comply with all combusting gaseous fuel: (b) Certification, quality assurance reporting requirements in this section (A) Date and hour; and quality control record provisions. and with any additional requirements (B) Hourly heat input rate from The owner or operator of any affected set forth in an applicable State or federal gaseous fuel, according to procedures in unit shall record the applicable NOX mass emission reduction program appendix F to this part (in mmBtu/hr, information in § 75.59 for each affected that adopts the requirements of this rounded to the nearest tenth); unit or group of units monitored at a subpart. (C) Hourly flow rate of gaseous fuel, common stack and each non-affected (2) The designated representative for while the unit combusts gas (in 100 unit under § 75.72(b)(2)(ii). an affected unit shall submit the scfh) (flag value if derived from missing (c) Monitoring plan recordkeeping following for each affected unit or group data procedures); provisions—(1) General provisions. The of units monitored at a common stack (D) Gross calorific value of gaseous owner or operator of an affected unit and each non-affected unit under fuel used to determine heat input rate shall prepare and maintain a monitoring § 75.72(b)(2)(ii):

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(i) Initial certification and hardcopy information only if that hardcopy test data and results required recertification applications in portion of the monitoring plan is by § 75.59; accordance with § 75.70(d); revised. The designated representative (F) Records of flow polynomial (ii) Monitoring plans in accordance shall submit the required hardcopy equations and numerical values with paragraph (e) of this section; and information as follows: no later than 45 required by § 75.59(a)(5)(vi); (iii) Quarterly reports in accordance days prior to the initial certification test; (G) Daily fuel sampling information with paragraph (f) of this section. with any recertification application, if a required by § 75.58(c)(3)(i) for units (3) Other petitions and hardcopy monitoring plan change is using assumed values under appendix communications. The designated associated with the recertification event; D; representative for an affected unit shall and within 30 days of any other event (H) Information required by submit petitions, correspondence, with which a hardcopy monitoring plan § 75.59(b)(2) concerning transmitter or application forms, and petition-related change is associated, pursuant to transducer accuracy tests; test results in accordance with the § 75.53(b). (I) Stratification test results required provisions in § 75.70(h). (f) Quarterly reports.—(1) Electronic as part of the RATA supplementary (4) Quality assurance RATA reports. If submission. The designated records under § 75.59(a)(7); requested by the permitting authority, representative for an affected unit shall (J) Data and results of RATAs that are the designated representative of an electronically report the data and aborted or invalidated due to problems affected unit shall submit the quality information in this paragraph (f)(1) and with the reference method or assurance RATA report for each affected in paragraphs (f)(2) and (3) of this operational problems with the unit and unit or group of units monitored at a section to the Administrator quarterly. data and results of linearity checks that common stack and each non-affected Each electronic report must be are aborted or invalidated due to unit under § 75.72(b)(2)(ii) by the later submitted to the Administrator within operational problems with the unit; and of 45 days after completing a quality 30 days following the end of each (K) Supplementary RATA information assurance RATA according to section calendar quarter. Each electronic report required under § 75.59(a)(7)(i) through 2.3 of appendix B to this part or 15 days shall include the date of report § 75.59(a)(7)(v), except that: the data of receiving the request. The designated generation, for the information provided under § 75.59(a)(7)(ii)(A) through (T) representative shall report the hardcopy in paragraphs (f)(1)(ii) through (1)(vi) of and the data under § 75.59(a)(7)(iii)(A) information required by § 75.59(a)(9) to this section, and shall also include for through (M) shall, as applicable, be the permitting authority. each affected unit or group of units reported for flow RATAs in which (5) Notifications. The designated monitored at a common stack: angular compensation (measurement of representative for an affected unit shall (i) Facility information: pitch and/or yaw angles) is used and for submit written notice to the permitting (A) Identification, including: flow RATAs in which a site-specific authority according to the provisions in (1) Facility/ORISPL number; wall effects adjustment factor is § 75.61 for each affected unit or group (2) Calendar quarter and year data determined by direct measurement; and of units monitored at a common stack contained in the report; and the data under § 75.59(a)(7)(ii)(T) shall and each non-affected unit under (3) Electronic data reporting format be reported for all flow RATAs in which § 75.72(b)(2)(ii). version used for the report. a default wall effects adjustment factor (e) Monitoring plan reporting.—(1) (B) Location of facility, including: is applied. Electronic submission. The designated (1) Plant name and facility (iii) Average NOX emission rate (lb/ representative for an affected unit shall identification code; mmBtu, rounded to the nearest submit a complete, electronic, up-to- (2) EPA AIRS facility system thousandth) during the quarter and date monitoring plan file (except for identification code; cumulative NOX emission rate for the hardcopy portions identified in (3) State facility identification code; calendar year. paragraph (e)(2) of this section) for each (4) Source category/type; (iv) Tons of NOX emitted during affected unit or group of units (5) Primary SIC code; quarter, cumulative tons of NOX emitted monitored at a common stack and each (6) State postal abbreviation; during the year, and, during the second non-affected unit under § 75.72(b)(2)(ii) (7) FIPS county code; and and third calendar quarters, cumulative as follows: (8) Latitude and longitude. tons of NOX emitted during the ozone (i) To the permitting authority, no (ii) The information and hourly data season. later than 45 days prior to the initial required in paragraph (a) of this section, (v) During the second and third certification test and at the time of except for: calendar quarters, cumulative heat input recertification application submission; (A) Descriptions of adjustments, for the ozone season. and corrective action, and maintenance; (vi) Unit or stack or common pipe (ii) To the Administrator, no later (B) Information which is incompatible header operating hours for quarter, than 45 days prior to the initial with electronic reporting (e.g., field data cumulative unit, stack or common pipe certification test, at the time of sheets, lab analyses, quality control header operating hours for calendar submission of a recertification plan); year, and, during the second and third application, and in each electronic (C) For units with NOX add-on calendar quarters, cumulative operating quarterly report. emission controls that do not elect to hours during the ozone season. (2) Hardcopy submission. The use the approved site-specific (2) The designated representative designated representative of an affected parametric monitoring procedures for shall certify that the component and unit shall submit all of the hardcopy calculation of substitute data, the system identification codes and information required under § 75.53, for information in § 75.58(b)(3); formulas in the quarterly electronic each affected unit or group of units (D) Information required by § 75.57(h) reports submitted to the Administrator monitored at a common stack and each concerning the causes of any missing pursuant to paragraph (e) of this section non-affected unit under § 75.72(b)(2)(ii), data periods and the actions taken to represent current operating conditions. to the permitting authority prior to cure such causes; (3) Compliance certification. The initial certification. Thereafter, the (E) Hardcopy monitoring plan designated representative shall submit designated representative shall submit information required by § 75.53 and and sign a compliance certification in

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The certification shall state year through April 30 of the current season and continuing until the that: calendar year), the owner or operator successful completion of a linearity (i) The monitoring data submitted shall, at a minimum, perform the check. were recorded in accordance with the following diagnostic testing and quality (2) If a monitor does not qualify for an applicable requirements of this part, assurance assessments, and shall exception under paragraph (c)(2)(i)(D)(1) including the quality assurance maintain the following records, to and if a required linearity check has not procedures and specifications; and ensure that the hourly emission data been completed prior to the start of the (ii) With regard to a unit with add-on recorded at the beginning of the current current ozone season, follow the emission controls and for all hours ozone season are suitable for reporting applicable procedures in paragraph where data are substituted in as quality-assured data: (c)(3)(vi) of this section. accordance with § 75.34(a)(1), the add- (i) For each required gas monitor (i.e., (ii) For each required CEMS (i.e., for on emission controls were operating for each NOX pollutant concentration each NOX concentration monitoring within the range of parameters listed in monitor and each diluent gas (CO2 or system, each NOX-diluent monitoring the monitoring plan and the substitute O2) monitor, including CO2 and O2 system, each flow rate monitoring values do not systematically monitors used exclusively for heat input system, each moisture monitoring underestimate NOX emissions. determination and O2 monitors used for system and each diluent gas CEMS used (4) The designated representative moisture determination), a linearity exclusively for heat input shall comply with all of the quarterly check shall be performed and passed. determination), a relative accuracy test reporting requirements in §§ 75.64(d), (A) Conduct each linearity check in audit (RATA) shall be performed and (f), and (g). accordance with the general procedures passed. 53. Section 75.74 is amended by: in section 6.2 of appendix A to this part, (A) Conduct each RATA in a. Revising paragraphs (b)(2), (c)(1) except that the data validation accordance with the applicable and (c)(2); procedures in sections 6.2(a) through (f) procedures in sections 6.5 through b. Redesignating paragraphs (c)(3), of appendix A do not apply. 6.5.10 of appendix A to this part, except (c)(4), (c)(5), (c)(6), (c)(7), (c)(8), (c)(9) (B) Each linearity check shall be done that the data validation procedures in and (c)(10), as paragraphs (c)(4), (c)(5), ‘‘hands-off,’’ as described in section sections 6.5(f)(1) through (f)(6) do not (c)(6), (c)(7), (c)(8), (c)(9), (c)(10) and 2.2.3(c) of appendix B to this part. apply, and, for flow rate monitoring (c)(11), respectively; (C) In the time period extending from systems, the required RATA load c. Adding a new paragraph (c)(3); and the date and hour in which the linearity level(s) shall be as specified in this d. Revising newly redesignated check is passed through April 30 of the paragraph. paragraphs (c)(4), (c)(5), (c)(6) and (c)(7), current calendar year, the owner or (B) Each RATA shall be done ‘‘hands- to read as follows: operator shall operate and maintain the off,’’ as described in section 2.3.2 (c) of § 75.74 Annual and ozone season CEMS and shall perform daily appendix B to this part. The provisions monitoring and reporting requirements. calibration error tests of the CEMS in in section 2.3.1.4 of appendix B to this * * * * * accordance with section 2.1 of appendix part, pertaining to the number of (b) * * * B to this part. When a calibration error allowable RATA attempts, shall apply. (2) Meet the requirements of this test is failed, as described in section (C) For flow rate monitoring systems subpart during the ozone season, except 2.1.4 of appendix B to this part, installed on peaking units or bypass as specified in paragraph (c) of this corrective actions shall be taken. The stacks, a single-load RATA is required. section. additional calibration error test For all other flow rate monitoring (c) * * * provisions of section 2.1.3 of appendix systems, a 2-load RATA is required at (1) The owner or operator of a unit B to this part shall be followed. Records the two most frequently-used load levels that uses continuous emissions of the required daily calibration error (as defined under section 6.5.2.1 of monitoring systems or a fuel flowmeter tests shall be kept in a format suitable appendix A to this part), with the to meet any of the requirements of this for inspection on a year-round basis. following exceptions. A 3-load flow subpart shall quality assure the hourly (D) Exceptions. (1) If the monitor RATA is required at least once in every ozone season emission data required by passed a linearity check on or after period of five consecutive calendar this subpart. To achieve this, the owner January 1 of the previous year and the years. A 3-load RATA is also required or operator shall operate, maintain and unit or stack on which the monitor is if the flow monitor polynomial calibrate each required CEMS and shall located operated for less than 336 hours coefficients or K factor(s) are changed perform diagnostic testing and quality in the previous ozone season, the owner prior to conducting the flow RATA assurance testing of each required CEMS or operator may have a grace period of required under this paragraph. or fuel flowmeter according to the up to 168 hours to perform a linearity (D) A bias test of each required NOX applicable provisions of paragraphs check. In addition, if the unit or stack concentration monitoring system, each (c)(2) through (c)(5) of this section. operates for 168 hours or less in the NOX-diluent monitoring system and Except where otherwise noted, the current ozone season the owner or each flow rate monitoring system shall provisions of paragraphs (c)(2) and (c)(3) operator is exempt from the linearity be performed in accordance with of this section apply instead of the check requirement for that ozone season section 7.6 of appendix A to this part. quality assurance provisions in sections and the owner or operator may submit If the bias test is failed, a bias 2.1 through 2.3 of appendix B to this quality assured data from that monitor adjustment factor (BAF) shall be part, and shall be used in lieu of those as long as all other required quality calculated for the monitoring system, as appendix B provisions. assurance tests are passed. If the unit or described in section 7.6.5 of appendix A (2) Quality assurance requirements stack operates for more than 168 hours to this part and shall be applied to the prior to the ozone season. The in the current ozone season, the owner subsequent data recorded by the CEMS.

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(E) In the time period extending from (H) Exceptions. (1) If the monitoring linearity checks shall be done in the hour of completion of the required system passed a RATA on or after accordance with sections 2.2.3(a) RATA through April 30 of the current January 1 of the previous year and the through (e) of appendix B to this part. calendar year, the owner or operator unit or stack on which the monitor is The grace period provision in section shall operate and maintain the CEMS by located operated for less than 336 hours 2.2.4 of appendix B to this part does not performing, at a minimum, the in the previous ozone season, the owner apply to these linearity checks. If the following activities: or operator may have a grace period of required linearity check has not been (1) The owner or operator shall up to 720 hours to perform a RATA. If completed by the end of the calendar perform daily calibration error tests and the unit or stack operates for 720 hours quarter, unless the conditional data (if applicable) daily flow monitor or less in the current ozone season, the validation provisions of § 75.20(b)(3) are interference checks, according to section owner or operator of the unit is exempt applied, data from the CEMS are 2.1 of appendix B to this part. When a from the requirement to perform a considered to be invalid, beginning with daily calibration error test or RATA for that ozone season and the the first unit or stack operating hour interference check is failed, as described owner or operator may submit quality after the end of the quarter and shall in section 2.1.4 of appendix B to this assured data from that monitor as long remain invalid until a linearity check of part, corrective actions shall be taken. as all other required quality assurance the CEMS is performed and passed. The additional calibration error test tests are passed. If the unit or stack (iii) For each flow monitoring system provisions in section 2.1.3 of appendix operates for more than 720 hours in the required by this subpart, flow-to-load B to this part shall be followed. Records current ozone season, the owner or ratio tests are required in the second of the required daily calibration error operator of the unit or stack shall report and third calendar quarters, in tests and interference checks shall be substitute data using the missing data accordance with section 2.2.5 of kept in a format suitable for inspection procedures under paragraph (c)(7) of appendix B to this part. If the flow-to- on a year-round basis. this section, starting with the 721st unit load ratio test for the second calendar (2) If the owner or operator makes a operating hour and continuing until the quarter is failed, the owner or operator replacement, modification, or change in successful completion of the RATA. shall declare the flow monitor out-of- a certified monitoring system that (2) If a monitor does not qualify for a control as of the first unit or stack significantly affects the ability of the grace period under paragraph operating hour following the second system to accurately measure or record (c)(2)(ii)(H)(1) of this section and if a calendar quarter and shall either NOX mass emissions or heat input or to required RATA has not been completed implement Option 1 in section 2.2.5.1 of meet the requirements of § 75.21 or prior to the start of the current ozone appendix B to this part or Option 2 in appendix B to this part, the owner or season, follow the applicable section 2.2.5.2 of appendix B to this operator shall recertify the monitoring procedures in paragraph (c)(3)(vi) of this part. If the flow-to-load ratio test for the system according to § 75.20(b). section. (F) If the results of a RATA performed (3) Quality assurance requirements third calendar quarter is failed, data according to the provisions of this within the ozone season. The provisions from the flow monitor shall be paragraph indicate that the CEMS of this paragraph apply to each ozone considered invalid at the beginning of qualifies for an annual RATA frequency season. The owner or operator shall, at the next ozone season unless, prior to (see Figure 2 in appendix B to this part), a minimum, perform the following May 1 of the next calendar year, the the RATA may be used to quality assure quality assurance testing during the owner or operator has either data for the entire current ozone season. ozone season, i.e. in the time period successfully implemented Option 1 in (G) If the results of a RATA performed extending from May 1 through section 2.2.5.1 of appendix B to this part according to the provisions of this September 30 of each calendar year: or Option 2 in section 2.2.5.2 of paragraph indicate that the CEMS (i) Daily calibration error tests and (if appendix B to this part, or unless a flow qualifies for a semiannual RATA applicable) interference checks of each RATA has been performed and passed frequency rather than an annual CEMS required by this subpart shall be in accordance with paragraph (c)(2)(ii) frequency, provided that the RATA was performed in accordance with sections of this section. completed on or after January 1 of the 2.1.1 and 2.1.2 of appendix B to this (iv) For each differential pressure-type current calendar year, the RATA may be part. The applicable provisions in flow monitor used to meet the used to quality assure data for the entire sections 2.1.3, 2.1.4 and 2.1.5 of requirements of this subpart, quarterly current ozone season. However, if the appendix B to this part, pertaining, leak checks are required in the second RATA was performed in the fourth respectively, to additional calibration and third calendar quarters, in calendar quarter of the previous year, error tests and calibration adjustments, accordance with section 2.2.2 of the RATA may only be used to quality data validation, and quality assurance of appendix B to this part. For the second assure data for a part of the current data with respect to daily assessments, calendar quarter of the year, only unit ozone season, from May 1 through June shall also apply. or stack operating hours in the months 30. An additional RATA is then (ii) For each gas monitor required by of May and June shall be included when required by June 30 of the current this subpart, linearity checks shall be determining whether the second calendar year to quality assure the performed in the second and third calendar quarter is a QA operating remainder of the data (from June 30 calendar quarters, in accordance with quarter (as defined in § 72.2 of this through September 30) for the current section 2.2.1 of appendix B to this part chapter). Data validation for quarterly ozone season. If such an additional (see also paragraph (c)(3)(vii) of this flow monitor leak checks shall be done RATA is required but is not completed section). For the second calendar in accordance with section 2.2.3(g) of by June 30 of the current calendar year, quarter of the year, only unit or stack appendix B to this part. If the leak check data from the CEMS shall be considered operating hours in the months of May for the third calendar quarter is failed invalid as of the first unit or stack and June shall be included when and a subsequent leak check is not operating hour subsequent to June 30 of determining whether the second passed by the end of the ozone season, the current calendar year and shall calendar quarter is a ‘‘QA operating then data from the flow monitor shall be remain invalid until the required RATA quarter’’ (as defined in § 72.2 of this considered invalid at the beginning of is performed and passed. chapter). Data validation for these the next ozone season unless a leak

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In the resubmitted report, the for the next fuel flowmeter accuracy next calendar year; and owner or operator shall use the test. If a fuel flow-to-load ratio test is (C) For a gas monitoring system, the appropriate missing data routine in failed, follow the applicable procedures linearity check requirement of § 75.31 or § 75.33 to replace with and data validation provisions in paragraph (c)(2)(i) of this section is met substitute data each hour of section 2.1.7.4 of appendix D to this prior to May 1 of the next calendar year. conditionally valid data that was part. If the fuel flow-to-load ratio test for (D) If conditions in paragraphs invalidated by the failed quality the third calendar quarter is failed, data (c)(3)(vii)(A), (B) and, if applicable, assurance, diagnostic or recertification from the fuel flowmeter shall be (c)(3)(vii)(C) of this section are met, then test. Alternatively, if any required considered invalid at the beginning of a RATA completed and passed in the quality assurance, diagnostic or the next ozone season unless the second or third calendar quarter of the recertification test is not completed by requirements of section 2.1.7.4 of current year may be used to quality the end of the second calendar quarter appendix D to this part have been fully assure data for the next ozone season, as but is completed no later than 30 days met prior to May 1 of the next calendar follows: after the end of that quarter (i.e., prior year. (1) If the RATA is completed and to the deadline for submitting the passed in the second calendar quarter of (vi) If, at the start of the current ozone quarterly report under § 75.73), the test the current year, the RATA may be used season (i.e., as of May 1 of the current data and results may be submitted with to quality assure data from the CEMS calendar year), the linearity check or the second quarter report even though through June 30 of the next calendar RATA required under paragraph (c)(2)(i) the test date(s) are from the third year. calendar quarter. In such instances, if or (c)(2)(ii) of this section has not been (2) If the RATA is completed and performed for a particular monitor or the quality assurance, diagnostic or passed in the third calendar quarter of recertification test(s) are passed in monitoring system, and if, during the the current year, the RATA may be used previous ozone season, the unit or stack accordance with the provisions of to quality assure data from the CEMS § 75.20(b)(3), conditionally valid data on which the monitoring system is through September 30 of the next installed operated for 336 hours or more may be reported as quality-assured, in calendar year. lieu of reporting a conditional data flag. the owner or operator shall invalidate (viii) If a linearity check performed to all data from the CEMS until either: If the tests are failed and if conditionally meet the requirement of paragraph valid data are replaced, as appropriate, (A) The required linearity check or (c)(2)(i) of this section is completed and with substitute data, then neither the RATA of the CEMS has been performed passed in the second calendar quarter of reporting of a conditional data flag nor and passed; or the current year, provided that the date resubmission is required. (B) A ‘‘probationary calibration error and hour of completion of the test is (xii) If, at the end of the third quarter test’’ of the CEMS is passed in within the first 168 unit or stack of any calendar year, a required quality accordance with § 75.20(b)(3). Note that operating hours of the current ozone assurance, diagnostic or recertification a calibration error test passed on April season, the linearity check may be used test of a monitoring system has not been 30 may be used as the probationary to satisfy both the requirement of completed, and if data contained in the calibration error test, to ensure that paragraph (c)(2)(i) of this section and to quarterly report are conditionally valid emission data recorded by the CEMS at meet the second quarter linearity check pending the results of test(s) to be the beginning of the ozone season will requirement of paragraph (c)(3)(ii) of completed, the owner or operator shall have a conditionally valid status. Once this section. do one of the following: the probationary calibration error test (ix) If, for any required CEMS, (A) If the results of the required tests has been passed, the owner or operator diagnostic linearity checks or RATAs are not available within 30 days of the shall perform the required linearity other than those required by this section end of the third calendar quarter and check or RATA in accordance with the are performed during the ozone season, cannot be submitted with the quarterly conditional data validation provisions use the applicable data validation report for the third calendar quarter, and within the associated timelines in procedures in section 2.2.3 (for linearity then the test results are considered to be § 75.20(b)(3), with the term ‘‘diagnostic’’ checks) or 2.3.2 (for RATAs) of missing and the owner or operator shall applying instead of the term appendix B to this part. use the appropriate missing data routine ‘‘recertification’’. However, in lieu of the (x) If any required CEMS is recertified in § 75.31 or § 75.33 to replace with provisions in § 75.20(b)(3)(ix), the within the ozone season, use the data substitute data each hour of owner or operator shall follow the validation provisions in § 75.20(b)(3) conditionally valid data in the third applicable provisions in paragraphs and paragraphs (c)(3)(xi) and (c)(3)(xii) quarter report. In addition, if the data in (c)(3)(xi) and (c)(3)(xii) of this section. of this section. the second quarterly report were flagged (vii) A RATA which is performed and (xi) If, at the end of the second quarter as conditionally valid at the end of the passed during the second or third of any calendar year, a required quality quarter, pending the results of the same quarter of the current calendar year may assurance, diagnostic or recertification missing tests, the owner or operator be used to quality assure data in the test of a monitoring system has not been shall resubmit the report for the second next ozone season, provided that: completed, and if data contained in the quarter and shall use the appropriate (A) The results of the RATA indicate quarterly report are conditionally valid missing data routine in § 75.31 or that the CEMS qualifies for an annual pending the results of test(s) to be § 75.33 to replace with substitute data

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The quality-assured monitor operating hours test data and results may be submitted owner or operator then shall use that for a NOX-diluent continuous emission with the third quarter report even sampled value for all hours of monitoring system, a NOX concentration though the test date(s) are from the combustion during the first day of unit monitoring system, or a flow monitoring fourth calendar quarter. In this instance, operation, continuing until the date and system) used to calculate missing data if the required tests are passed in hour of the next sample. must include only quality-assured data accordance with the provisions of (6) The owner or operator shall, in from periods within ozone seasons. § 75.20(b)(3), all conditionally valid data accordance with § 75.73, record and (ii) The missing data procedures of associated with the tests shall be report the hourly data required by this §§ 75.31 through 75.33 shall be used, reported as quality assured. If the tests subpart and shall record and report the with two exceptions. First, when the results of all required quality assurance are failed, the owner or operator shall NOX emission rate or NOX use the appropriate missing data routine tests, as follows: concentration of the unit was in § 75.31 or § 75.33 to replace with (i) All hourly emission data for the consistently lower in the previous ozone substitute data each hour of period of time from May 1 through season because the unit combusted a September 30 of each calendar year conditionally valid data associated with fuel that produces less NOX than the the failed test(s). In addition, if the data shall be recorded and reported. For fuel currently being combusted; and in the second quarterly report were missing data purposes, only the data second, when the unit’s add-on recorded in the time period from May 1 flagged as conditionally valid at the end emission controls are not working through September 30 shall be of the quarter, pending the results of the properly, as shown by the parametric considered quality-assured; same failed test(s), the owner or data recorded under paragraph (c)(8) of operator shall resubmit the report for (ii) The results of all daily calibration error tests and flow monitor interference this section. In those two cases, the the second quarter and shall use the owner or operator shall substitute the appropriate missing data routine in checks performed in the time period from May 1 through September 30 shall maximum potential NOX emission rate, § 75.31 or § 75.33 to replace with as defined in § 72.2 of this chapter, from substitute data each hour of be recorded and reported; (iii) For the time periods described in a NOX-diluent continuous emission conditionally valid data associated with monitoring system, or the maximum the failed test(s). paragraphs (c)(2)(i)(C) and (c)(2)(ii)(E) of potential concentration of NOX, as (4) The owner or operator of a unit this section, hourly emission data and defined in section 2.1.2.1 of appendix A using the procedures in appendix D of the results of all daily calibration error to this part, from a NOX concentration this part to determine heat input is tests and flow monitor interference monitoring system. The maximum required to maintain fuel flowmeters checks shall be recorded. The results of potential value used shall be for the fuel only during the ozone season, except all daily calibration error tests and flow currently being combusted. The length that for purposes of determining the monitor interference checks performed of time for which the owner or operator deadline for the next periodic quality in the time period from April 1 through shall substitute these maximum assurance test on the fuel flowmeter, the April 30 shall be reported. The owner or owner or operator shall include all fuel operator may also report the hourly potential values for each hour of flowmeter QA operating quarters (as emission data and unit operating data missing NOX operator shall substitute defined in § 72.2) for the entire calendar recorded in the time period from April these maximum potential value for each year, not just fuel flowmeter QA 1 through April 30. However, only the hour of missing NOX data, shall be as operating quarters in the ozone season. emission data recorded in the time follows: For each calendar year, the owner or period from May 1 through September (A) For a unit that changed fuels, substitute the maximum potential operator shall record, for each fuel 30 shall be used for NOX mass flowmeter, the number of fuel flowmeter compliance determination; values until the first hour when the unit QA operating quarters. (iv) The results of all required quality combusts a fuel that produces the same (5) The owner or operator of a unit assurance tests (RATAs, linearity or less NOX than the fuel combusted in using the procedures in appendix D of checks, flow-to-load ratio tests and leak the previous ozone season; and this part to determine heat input is only checks) performed during the ozone (B) For a unit with add-on emission required to sample fuel for the purposes season shall be reported in the controls that are not working properly, of determining density and GCV during appropriate ozone season quarterly substitute the maximum potential the ozone season, except that: report; and values until the first hour in which the (i) The owner or operator of a unit (v) The results of RATAs (and any add-on emission controls are that performs sampling from the fuel other quality assurance test(s) required documented to be operating properly, storage tank upon delivery must sample under paragraph (c)(2) or (c)(3) of this according to paragraph (c)(8) of this the tank between the date and hour of section) which affect data validation for section. the most recent delivery before the first the current ozone season, but which * * * * * date and hour that the unit operates in were performed outside the ozone 54. Appendix A to part 75 is amended the ozone season and the first date and season (i.e., between October 1 of the by— hour that the unit operates in the ozone previous calendar year and April 30 of a. Revising sections 2 through 2.1.1.4; season. the current calendar year), shall be b. Adding section 2.1.1.5; (ii) The owner or operator of a unit reported in the quarterly report for the c. Revising sections 2.1.2 through that performs sampling upon delivery second quarter of the current calendar 2.1.2.4; from the delivery vehicle must ensure year. d. Adding section 2.1.2.5;

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e. Revising section 2.1.3; potential and expected concentrations can be chosen, the MPC shall be the maximum SO2 f. Adding sections 2.1.3.1 through accurately measured and recorded. Note that concentration observed during the previous 2.1.3.3; if a unit exclusively combusts fuels that are 720 (or more) quality assured monitor g. Revising section 2.1.4; very low sulfur fuels (as defined in § 72.2 of operating hours when combusting the h. Adding sections 2.1.4.1 through this chapter), the SO2 monitor span highest-sulfur fuel (or highest-sulfur blend if requirements in § 75.11(e)(3)(iv) apply in lieu fuels are always blended or co-fired) that is 2.1.6; of the requirements of this section. i. Removing and reserving section 2.2 to be combusted in the unit or units and removing sections 2.2.1 through 2.1.1.1 Maximum Potential Concentration monitored by the SO2 monitor. For units with 2.2.2.2 to read as follows: (a) Make an initial determination of the SO2 emission controls, the certified SO2 maximum potential concentration (MPC) of monitor used to determine the MPC must be Appendix A to Part 75—Specifications and SO2 by using Equation A–1a or A–1b. Base located at or before the control device inlet. Test Procedures the MPC calculation on the maximum Report the MPC and the method of * * * * * percent sulfur and the minimum gross determination in the monitoring plan calorific value (GCV) for the highest-sulfur required under § 75.53. 2. Equipment Specifications fuel to be burned. The maximum sulfur (c) When performing fuel sampling to 2.1 Instrument Span and Range content and minimum GCV shall be determine the MPC, use ASTM Methods: In implementing sections 2.1.1 through determined from all available fuel sampling ASTM D3177–89, ‘‘Standard Test Methods and analysis data for that fuel from the 2.1.6 of this appendix, set the measurement for Total Sulfur in the Analysis Sample of previous 12 months (minimum), excluding range for each parameter (SO2, NOX, CO2, O2, clearly anomalous fuel sampling values. If Coal and Coke’’; ASTM D4239–85, ‘‘Standard or flow rate) high enough to prevent full- Test Methods for Sulfur in the Analysis scale exceedances from occurring, yet low the designated representative certifies that the highest-sulfur fuel is never burned alone Sample of Coal and Coke Using High enough to ensure good measurement Temperature Tube Furnace Combustion accuracy and to maintain a high signal-to- in the unit during normal operation but is Methods’’; ASTM D4294–90, ‘‘Standard Test noise ratio. To meet these objectives, select always blended or co-fired with other fuel(s), Method for Sulfur in Petroleum Products by the range such that the readings obtained the MPC may be calculated using a best during typical unit operation are kept, to the estimate of the highest sulfur content and Energy-Dispersive X-Ray Fluorescence extent practicable, between 20.0 and 80.0 lowest gross calorific value expected for the Spectroscopy’’; ASTM D1552–90, ‘‘Standard percent of full-scale range of the instrument. blend or fuel mixture and inserting these Test Method for Sulfur in Petroleum values into Equation A–1a or A–1b. Derive These guidelines do not apply to: (1) SO2 Products (High Temperature Method)’’; readings obtained during the combustion of the best estimate of the highest percent sulfur ASTM D129–91, ‘‘Standard Test Method for very low sulfur fuel (as defined in § 72.2 of and lowest GCV for a blend or fuel mixture Sulfur in Petroleum Products (General Bomb from weighted-average values based upon the this chapter); (2) SO2 or NOX readings Method)’’; ASTM D2622–92, ‘‘Standard Test recorded on the high measurement range, for historical composition of the blend or Method for Sulfur in Petroleum Products by mixture in the previous 12 (or more) months. units with SO2 or NOX emission controls and X-Ray Spectrometry’’ for sulfur content of If insufficient representative fuel sampling two span values; or (3) SO2 or NOX readings solid or liquid fuels; ASTM D3176–89, data are available to determine the maximum less than 20.0 percent of full-scale on the low ‘‘Standard Practice for Ultimate Analysis of measurement range for a dual span unit with sulfur content and minimum GCV, use values from contract(s) for the fuel(s) that will be Coal and Coke’’; ASTM D240–87 SO2 or NOX emission controls, provided that combusted by the unit in the MPC (Reapproved 1991), ‘‘Standard Test Method the readings occur during periods of high for Heat of Combustion of Liquid control device efficiency. calculation. (b) Alternatively, if a certified SO2 CEMS Hydrocarbon Fuels by Bomb Calorimeter’’; or 2.1.1 SO2 Pollutant Concentration Monitors is already installed, the owner or operator ASTM D2015–91, ‘‘Standard Test Method for Determine, as indicated in this section 2, may make the initial MPC determination Gross Calorific Value of Coal and Coke by the the span value(s) and range(s) for an SO2 based upon quality assured historical data Adiabatic Bomb Calorimeter’’ for GCV pollutant concentration monitor so that all recorded by the CEMS. If this option is (incorporated by reference under § 75.6).

 %S   20.% 9 − O  MPC (or MEC) = 11.32 ×106 2w ()Eq. A-1 a  GCV  20. 9  or

 %S   %CO  MPC (or MEC) = 66.93 ×106 2w ()Eq. A -1 b  GCV  100 

Where, %CO2w = Maximum carbon dioxide sulfur and low-sulfur fuel blends are MPC = Maximum potential concentration concentration, percent wet basis, under combusted as primary or backup fuels in a (ppm, wet basis). (To convert to dry typical operating conditions. unit without SO2 emission controls. For units × 6 basis, divide the MPC by 0.9.) 11.32 10 = Oxygen-based conversion factor with SO2 emission controls, use Equation A– 2 to make the initial MEC determination. MEC = Maximum expected concentration in Btu/lb (ppm)/%. × 6 When high-sulfur and low-sulfur fuels or (ppm, wet basis). (To convert to dry 66.93 10 = Carbon dioxide-based blends are burned as primary or backup fuels basis, divide the MEC by 0.9). conversion factor in Btu/lb (ppm)/%. in a unit without SO2 controls, use Equation %S = Maximum sulfur content of fuel to be Note: All percent values to be inserted in the equations of this section are to be A–1a or A–1b to calculate the initial MEC fired, wet basis, weight percent, as value for each fuel or blend, except for: (1) determined by ASTM D3177–89, ASTM expressed as a percentage, not a fractional value (e.g., 3, not .03). the highest-sulfur fuel or blend (for which D4239–85, ASTM D4294–90, ASTM the MPC was previously calculated in section D1552–90, ASTM D129–91, or ASTM 2.1.1.2 Maximum Expected Concentration 2.1.1.1 of this appendix); (2) fuels or blends D2622–92 for solid or liquid fuels (a) Make an initial determination of the that are very low sulfur fuels (as defined in (incorporated by reference under § 75.6). maximum expected concentration (MEC) of § 72.2 of this chapter); or (3) fuels or blends %O2w = Minimum oxygen concentration, SO2 whenever: (a) SO2 emission controls are that are used only for unit startup. percent wet basis, under typical used; or (b) both high-sulfur and low-sulfur (b) For each MEC determination, substitute operating conditions. fuels (e.g., high-sulfur coal and low-sulfur into Equation A–1a or A–1b the highest coal or different grades of fuel oil) or high- sulfur content and minimum GCV value for

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For most units, the high span value based (c) Alternatively, if a certified SO2 CEMS Other component and system designations on the MPC, as determined under section is already installed, the owner or operator are subject to approval by the Administrator. 2.1.1.3 of this appendix will suffice to may make the initial MEC determination(s) Note that the component and system measure and record SO2 concentrations based upon historical monitoring data. If this designations for redundant backup (unless span and/or range adjustments option is chosen for a unit with SO2 emission monitoring systems shall be the same as for become necessary in accordance with section controls, the MEC shall be the maximum SO2 primary monitoring systems. 2.1.1.5 of this appendix). In some instances, concentration measured downstream of the (e) Each monitoring system designated as however, a second (low) span value based on control device outlet by the CEMS over the primary or redundant backup shall meet the the MEC may be required to ensure accurate previous 720 (or more) quality assured initial certification and quality assurance measurement of all possible or expected SO2 monitor operating hours with the unit and requirements for primary monitoring systems concentrations. To determine whether two the control device both operating normally. in § 75.20(c) or § 75.20(d)(1), as applicable, SO2 span values are required, proceed as and appendices A and B to this part, with For units that burn high- and low-sulfur fuels follows: or blends as primary and backup fuels and one exception: relative accuracy test audits (a) For units with SO2 emission controls, (RATAs) are required only on the normal have no SO2 emission controls, the MEC for compare the MEC from section 2.1.1.2 of this each fuel shall be the maximum SO2 range (for units with SO2 emission controls, appendix to the high full-scale range value the low range is considered normal). Each concentration measured by the CEMS over from section 2.1.1.3 of this appendix. If the the previous 720 (or more) quality assured ≥ monitoring system designated as a non- MEC is 20.0 percent of the high range value, redundant backup shall meet the applicable monitor operating hours in which that fuel or then the high span value and range blend was the only fuel being burned in the quality assurance requirements in determined under section 2.1.1.3 of this § 75.20(d)(2). unit. appendix are sufficient. If the MEC is <20.0 (f) For dual span units with SO2 emission percent of the high range value, then a 100 − RE controls, the owner or operator may, as an MEC= MPC ()Eq. A-2 second (low) span value is required. alternative to maintaining and quality  100  (b) For units that combust high- and low- assuring a high monitor range, use a default sulfur primary and backup fuels (or blends) Where: high range value. If this option is chosen, the and have no SO2 controls, compare the high owner or operator shall report a default SO2 MEC = Maximum expected concentration range value from section 2.1.1.3 of this concentration of 200 percent of the MPC for (ppm). appendix (for the highest-sulfur fuel or each unit operating hour in which the full- MPC = Maximum potential concentration blend) to the MEC value for each of the other scale of the low range SO2 analyzer is (ppm), as determined by Eq. A–1a or A– fuels or blends, as determined under section exceeded. 1b. 2.1.1.2 of this appendix. If all of the MEC ≥ (g) The high span value and range shall be RE = Expected average design removal values are 20.0 percent of the high range determined in accordance with section efficiency of control equipment (%). value, the high span and range determined 2.1.1.3 of this appendix. The low span value 2.1.1.3 Span Value(s) and Range(s) under section 2.1.1.3 of this appendix are shall be obtained by multiplying the MEC by sufficient, regardless of which fuel or blend Determine the high span value and the a factor no less than 1.00 and no greater than is burned in the unit. If any MEC value is 1.25, and rounding the result upward to the high full-scale range of the SO2 monitor as <20.0 percent of the high range value, then follows. (Note: For purposes of this part, the next highest multiple of 10 ppm (or 100 ppm, a second (low) span value must be used as appropriate). For units that burn high- and high span and range refer, respectively, either when that fuel or blend is combusted. to the span and range of a single span unit low-sulfur primary and backup fuels or (c) When two SO2 spans are required, the blends and have no SO2 emission controls, or to the high span and range of a dual span owner or operator may either use a single unit.) The high span value shall be obtained select, as the basis for calculating the SO2 analyzer with a dual range (i.e., low- and by multiplying the MPC by a factor no less appropriate low span value and range, the high-scales) or two separate SO2 analyzers fuel-specific MEC value closest to 20.0 than 1.00 and no greater than 1.25. Round the connected to a common sample probe and span value upward to the next highest percent of the high full-scale range value sample interface. For units with SO2 (from paragraph (b) of this section). The low multiple of 100 ppm. If the SO2 span emission controls, the owner or operator may ≤ range must be greater than or equal to the low concentration is 500 ppm, the span value use a low range analyzer and a default high may be rounded upward to the next highest span value, and the required calibration gases range value, as described in paragraph (f) of must be selected based on the low span multiple of 10 ppm, instead of the nearest this section, in lieu of maintaining and value. For units with two SO2 spans, use the 100 ppm. The high span value shall be used quality assuring a high-scale range. Other to determine concentrations of the calibration low range whenever the SO2 concentrations monitor configurations are subject to the are expected to be consistently below 20.0 gases required for daily calibration error approval of the Administrator. percent of the high full-scale range value, i.e., checks and linearity tests. Select the full- (d) The owner or operator shall designate when the MEC of the fuel or blend being scale range of the instrument to be consistent the monitoring systems and components in combusted is less than 20.0 percent of the with section 2.1 of this appendix and to be the monitoring plan under § 75.53 as follows: high full-scale range value. When the full- greater than or equal to the span value. designate the low and high monitor ranges as scale of the low range is exceeded, the high Report the full-scale range setting and separate SO2 components of a single, primary range shall be used to measure and record the calculations of the MPC and span in the SO2 monitoring system; or designate the low SO2 concentrations; or, if applicable, the monitoring plan for the unit. Note that for and high monitor ranges as the SO2 default high range value in paragraph (f) of certain applications, a second (low) SO2 span components of two separate, primary SO2 this section shall be reported for each hour and range may be required (see section monitoring systems; or designate the normal of the full-scale exceedance. 2.1.1.4 of this appendix). If an existing state, monitor range as a primary monitoring local, or federal requirement for span of an system and the other monitor range as a non- 2.1.1.5 Adjustment of Span and Range SO2 pollutant concentration monitor requires redundant backup monitoring system; or, For each affected unit or common stack, a span lower than that required by this when a single, dual-range SO2 analyzer is the owner or operator shall make a periodic section or by section 2.1.1.4 of this appendix, used, designate the low and high ranges as evaluation of the MPC, MEC, span, and range the state, local, or federal span value may be a single SO2 component of a primary SO2 values for each SO2 monitor (at a minimum, used if a satisfactory explanation is included monitoring system (if this option is selected, an annual evaluation is required) and shall in the monitoring plan, unless span and/or use a special dual-range component type make any necessary span and range range adjustments become necessary in code, as specified by the Administrator, to adjustments, with corresponding monitoring accordance with section 2.1.1.5 of this satisfy the requirements of plan updates, as described in paragraphs (a) appendix. Span values higher than those § 75.53(e)(1)(iv)(D)); or, for units with SO2 and (b) of this section. Span and range

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In implementing the provisions in assured data (unless the reason that the high- owner or operator shall also calculate the paragraphs (a) and (b) of this section, SO2 scale range is not able to provide quality maximum potential NOX emission rate data recorded during short-term, non- assured data is because the high-scale range (MER), in lb/mmBtu, by substituting the MPC representative process operating conditions has been exceeded; if the high-scale range is for NOX in conjunction with the minimum (e.g., a trial burn of a different type of fuel) exceeded follow the procedures in paragraph expected CO2 or maximum O2 concentration (b)(1) of this section). shall be excluded from consideration. The (under all unit operating conditions except owner or operator shall keep the results of (c) Whenever changes are made to the for unit startup, shutdown, and upsets) and the most recent span and range evaluation MPC, MEC, full-scale range, or span value of the appropriate F-factor into the applicable on-site, in a format suitable for inspection. the SO2 monitor, as described in paragraphs equation in appendix F to this part. The Make each required span or range adjustment (a) or (b) of this section, record and report (as diluent cap value of 5.0 percent CO2 (or 14.0 no later than 45 days after the end of the applicable) the new full-scale range setting, quarter in which the need to adjust the span the new MPC or MEC and calculations of the percent O2) for boilers or 1.0 percent CO2 (or or range is identified, except that up to 90 adjusted span value in an updated 19.0 percent O2) for combustion turbines may days after the end of that quarter may be monitoring plan. The monitoring plan update be used in the NOX MER calculation. taken to implement a span adjustment if the shall be made in the quarter in which the (c) Report the method of determining the calibration gases currently being used for changes become effective. In addition, record initial MPC and the calculation of the daily calibration error tests and linearity and report the adjusted span as part of the maximum potential NOX emission rate in the checks are unsuitable for use with the new records for the daily calibration error test and monitoring plan for the unit. span value. linearity check specified by appendix B to (d) For units with add-on NOX controls (a) If the fuel supply, the composition of this part. Whenever the span value is (whether or not the unit is equipped with adjusted, use calibration gas concentrations the fuel blend(s), the emission controls, or low-NOX burner technology), NOX emission the manner of operation change such that the that meet the requirements of section 5.1 of testing may only be used to determine the maximum expected or potential this appendix, based on the adjusted span MPC if testing can be performed either concentration changes significantly, adjust value. When a span adjustment is so upstream of the add-on controls or during a significant that the calibration gases currently the span and range setting to assure the time or season when the add-on controls are being used for daily calibration error tests continued accuracy of the monitoring system. not in operation. If NOX emission testing is and linearity checks are unsuitable for use A ‘‘significant’’ change in the MPC or MEC with the new span value, then a diagnostic performed, use the following guidelines. Use means that the guidelines in section 2.1 of linearity test using the new calibration gases Method 7E from appendix A to part 60 of this this appendix can no longer be met, as must be performed and passed. Data from the chapter to measure total NOX concentration. determined by either a periodic evaluation by monitor are considered invalid from the hour (Note: Method 20 from appendix A to part 60 the owner or operator or from the results of in which the span is adjusted until the may be used for gas turbines, instead of an audit by the Administrator. The owner or required linearity check is passed in Method 7E.) Operate the unit, or group of operator should evaluate whether any accordance with section 6.2 of this appendix. units sharing a common stack, at the planned changes in operation of the unit may minimum safe and stable load, the normal affect the concentration of emissions being 2.1.2 NOX Pollutant Concentration Monitors load, and the maximum load. If the normal emitted from the unit or stack and should load and maximum load are identical, an Determine, as indicated in section 2.1.2.1, plan any necessary span and range changes intermediate level need not be tested. needed to account for these changes, so that the span and range value(s) for the NOX Operate at the highest excess O2 level they are made in as timely a manner as pollutant concentration monitor so that all expected under normal operating conditions. practicable to coordinate with the operational expected NOX concentrations can be Make at least three runs of 20 minutes changes. Determine the adjusted span(s) determined and recorded accurately. (minimum) duration with three traverse using the procedures in sections 2.1.1.3 and 2.1.2.1 Maximum Potential Concentration points per run at each operating condition. 2.1.1.4 of this appendix (as applicable). (a) The maximum potential concentration Select the highest point NOX concentration Select the full-scale range(s) of the (MPC) of NOX for each affected unit shall be from all test runs as the MPC for NOX. instrument to be greater than or equal to the based upon whichever fuel or blend (e) If historical CEM data are used to new span value(s) and to be consistent with combusted in the unit produces the highest the guidelines of section 2.1 of this appendix. determine the MPC, the data must, for level of NOX emissions. Make an initial uncontrolled units or units equipped with (b) Whenever a full-scale range is exceeded determination of the MPC using the low-NOX burner technology and no other during a quarter and the exceedance is not appropriate option as follows: caused by a monitor out-of-control period, NOX controls, represent a minimum of 720 Option 1: Use 800 ppm for coal-fired and quality assured monitor operating hours, proceed as follows: 400 ppm for oil- or gas-fired units as the obtained under various operating conditions (1) For exceedances of the high range, maximum potential concentration of NOX (if including the minimum safe and stable load, report 200.0 percent of the current full-scale an MPC of 1600 ppm for coal-fired units or normal load (including periods of high range as the hourly SO2 concentration for 480 ppm for oil- or gas-fired units was each hour of the full-scale exceedance and previously selected under this part, that excess air at normal load), and maximum make appropriate adjustments to the MPC, value may still be used, provided that the load. For a unit with add-on NOX controls span, and range to prevent future full-scale guidelines of section 2.1 of this appendix are (whether or not the unit is equipped with exceedances. met); low-NOX burner technology), historical CEM (2) For units with two SO2 spans and Option 2: Use the specific values based on data may only be used to determine the MPC ranges, if the low range is exceeded, no boiler type and fuel combusted, listed in if the 720 quality assured monitor operating further action is required, provided that the Table 2–1 or Table 2–2; hours of CEM data are collected upstream of high range is available and is not out-of- Option 3: Use NOX emission test results; or the add-on controls or if the 720 hours of control or out-of-service for any reason. Option 4: Use historical CEM data over the data include periods when the add-on However, if the high range is not able to previous 720 (or more) unit operating hours controls are not in operation. The highest provide quality assured data at the time of when combusting the fuel or blend with the hourly NOX concentration in ppm shall be the low range exceedance or at any time highest NOX emission rate. the MPC.

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TABLE 2±1.ÐMAXIMUM POTENTIAL CONCENTRATION FOR NOXÐCOAL-FIRED UNITS

Maximum po- tential con- Unit type centration 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, arch-fired ...... 975 Cyclone, wall-fired wet bottom, wet bottom turbo-fired ...... 1200 Others ...... (1) 1 As approved by the Administrator.

TABLE 2±2.ÐMAXIMUM POTENTIAL CONCENTRATION FOR NOXÐGAS-AND OIL-FIRED UNITS

Maximum po- tential con- Unit type centration 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 more) hours of quality assured data appendix must be approved by the (a) Make an initial determination of the representing the entire load range under Administrator. maximum expected concentration (MEC) of stable operating conditions. The data base for (c) Select the full-scale range of the instrument to be consistent with section 2.1 NOX during normal operation for affected the MEC shall not include any CEM data of this appendix and to be greater than or units with add-on NOX controls of any kind recorded during unit startup, shutdown, or (e.g., steam injection, water injection, SCR, or malfunction or during any NOX control equal to the high span value. Include the full- SNCR). Determine a separate MEC value for device malfunctions or outages. All NOX scale range setting and calculations of the each type of fuel (or blend) combusted in the control devices and methods used to reduce MPC and span in the monitoring plan for the unit, except for fuels that are only used for NOX emissions must be operating properly unit. unit startup and/or flame stabilization. during each hour. The CEM data shall be 2.1.2.4 Dual Span and Range Requirements Calculate the MEC of NOX using Equation A– collected downstream of all NOX controls. For most units, the high span value based 2, if applicable, inserting the maximum For each type of fuel, the highest of the 720 on the MPC, as determined under section potential concentration, as determined using (or more) quality assured hourly average NOX 2.1.2.3 of this appendix will suffice to the procedures in section 2.1.2.1 of this concentrations recorded by the CEMS shall measure and record NOX concentrations appendix. Where Equation A–2 is not be the MEC. (unless span and/or range adjustments must applicable, set the MEC either by: (1) 2.1.2.3 Span Value(s) and Range(s) be made in accordance with section 2.1.2.5 measuring the NOX concentration using the (a) Determine the high span value of the of this appendix). In some instances, testing procedures in this section; or (2) using however, a second (low) span value based on historical CEM data over the previous 720 (or NOX monitor as follows. The high span value shall be obtained by multiplying the MPC by the MEC may be required to ensure accurate more) quality assured monitor operating measurement of all expected and potential a factor no less than 1.00 and no greater than hours. Include in the monitoring plan for the NOX concentrations. To determine whether 1.25. Round the span value upward to the unit each MEC value and the method by two NOX spans are required, proceed as next highest multiple of 100 ppm. If the NOX which the MEC was determined. follows: span concentration is ≤ 500 ppm, the span (b) If NOX emission testing is used to (a) Compare the MEC value(s) determined determine the MEC value(s), the MEC for value may be rounded upward to the next in section 2.1.2.2 of this appendix to the high each type of fuel (or blend) shall be based highest multiple of 10 ppm, rather than 100 full-scale range value determined in section upon testing at minimum load, normal load, ppm. The high span value shall be used to 2.1.2.3 of this appendix. If the MEC values and maximum load. At least three tests of 20 determine the concentrations of the for all fuels (or blends) are ≥20.0 percent of minutes (minimum) duration, using at least calibration gases required for daily the high range value, the high span and range three traverse points, shall be performed at calibration error checks and linearity tests. values determined under section 2.1.2.3 of each load, using Method 7E from appendix Note that for certain applications, a second this appendix are sufficient, irrespective of A to part 60 of this chapter (Note: Method 20 (low) NOX span and range may be required which fuel or blend is combusted in the unit. from appendix A to part 60 may be used for (see section 2.1.2.4 of this appendix). If any of the MEC values is <20.0 percent of gas turbines instead of Method 7E). The test (b) If an existing State, local, or federal the high range value, two spans (low and must be performed at a time when all NOX requirement for span of a NOX pollutant high) are required, one based on the MPC and control devices and methods used to reduce concentration monitor requires a span lower the other based on the MEC. NOX emissions are operating properly. The than that required by this section or by (b) When two NOX spans are required, the testing shall be conducted downstream of all section 2.1.2.4 of this appendix, the State, owner or operator may either use a single NOX controls. The highest point NOX local, or federal span value may be used, NOX analyzer with a dual range (low-and concentration (e.g., the highest one-minute where a satisfactory explanation is included high-scales) or two separate NOX analyzers average) recorded during any of the test runs in the monitoring plan, unless span and/or connected to a common sample probe and shall be the MEC. range adjustments become necessary in sample interface. For units with add-on NOX (c)If historical CEM data are used to accordance with section 2.1.2.5 of this emission controls (i.e., steam injection, water determine the MEC value(s), the MEC for appendix. Span values higher than required injection, SCR, or SNCR), the owner or each type of fuel shall be based upon 720 (or by this section or by section 2.1.2.4 of this operator may use a low range analyzer and

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a ‘‘default high range value,’’ as described in the low span value. For units with two NOX than or equal to the adjusted span value(s) paragraph 2.1.2.4(e) of this section, in lieu of spans, use the low range whenever NOX and to be consistent with the guidelines of maintaining and quality assuring a high-scale concentrations are expected to be section 2.1 of this appendix. range. Other monitor configurations are consistently <20.0 percent of the high range (b) Whenever a full-scale range is exceeded subject to the approval of the Administrator. value, i.e., when the MEC of the fuel being during a quarter and the exceedance is not (c) The owner or operator shall designate combusted is <20.0 percent of the high range caused by a monitor out-of-control period, the monitoring systems and components in value. When the full-scale of the low range proceed as follows: the monitoring plan under § 75.53 as follows: is exceeded, the high range shall be used to (1) For exceedances of the high range, designate the low and high ranges as separate measure and record the NOX concentrations; report 200.0 percent of the current full-scale NOX components of a single, primary NOX or, if applicable, the default high range value range as the hourly NOX concentration for monitoring system; or designate the low and in paragraph (e) of this section shall be each hour of the full-scale exceedance and high ranges as the NOX components of two reported for each hour of the full-scale make appropriate adjustments to the MPC, separate, primary NOX monitoring systems; exceedance. span, and range to prevent future full-scale or designate the normal range as a primary 2.1.2.5 Adjustment of Span and Range exceedances. monitoring system and the other range as a (2) For units with two NOX spans and non-redundant backup monitoring system; For each affected unit or common stack, ranges, if the low range is exceeded, no the owner or operator shall make a periodic or, when a single, dual-range NOX analyzer further action is required, provided that the is used, designate the low and high ranges as evaluation of the MPC, MEC, span, and range high range is available and is not out-of- values for each NOX monitor (at a minimum, a single NOX component of a primary NOX control or out-of-service for any reason. monitoring system (if this option is selected, an annual evaluation is required) and shall However, if the high range is not able to use a special dual-range component type make any necessary span and range provide quality assured data at the time of code, as specified by the Administrator, to adjustments, with corresponding monitoring the low range exceedance or at any time satisfy the requirements of plan updates, as described in paragraphs (a) during the continuation of the exceedance, and (b) of this section. Span and range § 75.53(e)(1)(iv)(D)); or, for units with add-on report the MPC as the NOX concentration adjustments may be required, for example, as NOX controls, if the default high range value until the readings return to the low range or is used, designate the low range analyzer as a result of changes in the fuel supply, until the high range is able to provide quality changes in the manner of operation of the the NOX component of the primary NOX assured data (unless the reason that the high- unit, or installation or removal of emission monitoring system. Do not designate the scale range is not able to provide quality controls. In implementing the provisions in default high range as a monitoring system or assured data is because the high-scale range paragraphs (a) and (b) of this section, note component. Other component and system has been exceeded; if the high-scale range is that NOX data recorded during short-term, designations are subject to approval by the exceeded, follow the procedures in paragraph non-representative operating conditions (e.g., Administrator. Note that the component and (b)(1) of this section). a trial burn of a different type of fuel) shall system designations for redundant backup (c) Whenever changes are made to the be excluded from consideration. The owner monitoring systems shall be the same as for MPC, MEC, full-scale range, or span value of or operator shall keep the results of the most primary monitoring systems. the NOX monitor as described in paragraphs recent span and range evaluation on-site, in (a) and (b) of this section, record and report (d) Each monitoring system designated as a format suitable for inspection. Make each primary or redundant backup shall meet the (as applicable) the new full-scale range required span or range adjustment no later setting, the new MPC or MEC, maximum initial certification and quality assurance than 45 days after the end of the quarter in potential NOX emission rate, and the requirements in § 75.20(c) (for primary which the need to adjust the span or range monitoring systems), in § 75.20(d)(1) (for adjusted span value in an updated is identified, except that up to 90 days after monitoring plan for the unit. The monitoring redundant backup monitoring systems) and the end of that quarter may be taken to appendices A and B to this part, with one plan update shall be made in the quarter in implement a span adjustment if the which the changes become effective. In exception: relative accuracy test audits calibration gases currently being used for (RATAs) are required only on the normal addition, record and report the adjusted span daily calibration error tests and linearity as part of the records for the daily calibration range (for dual span units with add-on NOX checks are unsuitable for use with the new emission controls, the low range is error test and linearity check required by span value. appendix B to this part. Whenever the span considered normal). Each monitoring system (a) If the fuel supply, emission controls, or designated as non-redundant backup shall value is adjusted, use calibration gas other process parameters change such that concentrations that meet the requirements of meet the applicable quality assurance the maximum expected concentration or the requirements in § 75.20(d)(2). section 5.1 of this appendix, based on the maximum potential concentration changes adjusted span value. When a span adjustment (e) For dual span units with add-on NOX significantly, adjust the NOX pollutant is significant enough that the calibration emission controls (e.g., steam injection, water concentration span(s) and (if necessary) injection, SCR, or SNCR), the owner or gases currently being used for daily monitor range(s) to assure the continued calibration error tests and linearity checks are operator may, as an alternative to accuracy of the monitoring system. A maintaining and quality assuring a high unsuitable for use with the new span value, ‘‘significant’’ change in the MPC or MEC a linearity test using the new calibration monitor range, use a default high range value. means that the guidelines in section 2.1 of gases must be performed and passed. Data If this option is chosen, the owner or operator this appendix can no longer be met, as from the monitor are considered invalid from shall report a default value of 200.0 percent determined by either a periodic evaluation by the hour in which the span is adjusted until of the MPC for each unit operating hour in the owner or operator or from the results of the required linearity check is passed in which the full-scale of the low range NOX an audit by the Administrator. The owner or accordance with section 6.2 of this appendix. analyzer is exceeded. operator should evaluate whether any (f) The high span and range shall be planned changes in operation of the unit or 2.1.3 CO2 and O2 Monitors determined in accordance with section stack may affect the concentration of For an O2 monitor (including O2 monitors 2.1.2.3 of this appendix. The low span value emissions being emitted from the unit and used to measure CO2 emissions or percentage shall be 100.0 to 125.0 percent of the MEC, should plan any necessary span and range moisture), select a span value between 15.0 rounded up to the next highest multiple of changes needed to account for these changes, and 25.0 percent O2. For a CO2 monitor 10 ppm (or 100 ppm, if appropriate). If more so that they are made in as timely a manner installed on a boiler, select a span value than one MEC value (as determined in as practicable to coordinate with the between 14.0 and 20.0 percent CO2. For a section 2.1.2.2 of this appendix) is <20.0 operational changes. An example of a change CO2 monitor installed on a combustion percent of the high full-scale range value, the that may require a span and range adjustment turbine, an alternative span value between low span value shall be based upon is the installation of low-NOX burner 6.0 and 14.0 percent CO2 may be used. An whichever MEC value is closest to 20.0 technology on a previously uncontrolled alternative O2 span value below 15.0 percent percent of the high range value. The low unit. Determine the adjusted span(s) using O2 may be used if an appropriate technical range must be greater than or equal to the low the procedures in section 2.1.2.3 or 2.1.2.4 of justification is included in the monitoring span value, and the required calibration gases this appendix (as applicable). Select the full- plan (e.g., O2 concentrations above a certain for the low range must be selected based on scale range(s) of the instrument to be greater level create an unsafe operating condition).

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Select the full-scale range of the instrument 2.1.3.2 Minimum Potential Concentration of 2.1 of this appendix and can accurately to be consistent with section 2.1 of this O2 measure all potential volumetric flow rates at appendix and to be greater than or equal to The owner or operator of a unit that uses the flow monitor installation site. the span value. Select the calibration gas a flow monitor and an O2 diluent monitor to 2.1.4.1 Maximum Potential Velocity and concentrations for the daily calibration error determine heat input in accordance with Flow Rate tests and linearity checks in accordance with Equation F–17 or F–18 in appendix F to this For this purpose, determine the span value section 5.1 of this appendix, as percentages part shall, for the purposes of providing substitute data under § 75.36, determine the of the flow monitor using the following of the span value. For O2 monitors with span minimum potential O2 concentration. The procedure. Calculate the maximum potential values ≥21.0 percent O2, purified instrument minimum potential O2 concentration shall be velocity (MPV) using Equation A–3a or A–3b air containing 20.9 percent O2 may be used based upon 720 hours or more of quality- or determine the MPV (wet basis) from as the high-level calibration material. assured CEM data, representing the full velocity traverse testing using Reference operating load range of the unit(s). The 2.1.3.1 Maximum Potential Concentration Method 2 (or its allowable alternatives) in minimum potential O2 concentration shall be of CO2 appendix A to part 60 of this chapter. If using the lowest quality-assured hourly average O2 For CO2 pollutant concentration monitors, concentration recorded in the 720 (or more) test values, use the highest average velocity the maximum potential concentration shall hours of data used for the determination. (determined from the Method 2 traverses) be 14.0 percent CO2 for boilers and 6.0 2.1.3.3 Adjustment of Span and Range measured at or near the maximum unit percent CO2 for combustion turbines. operating load. Express the MPV in units of Adjust the span value and range of a CO2 Alternatively, the owner or operator may wet standard feet per minute (fpm). For the or O2 monitor in accordance with section determine the MPC based on a minimum of 2.1.1.5 of this appendix (insofar as those purpose of providing substitute data during 720 hours of quality assured historical CEM provisions are applicable), with the term periods of missing flow rate data in data representing the full operating load ‘‘CO2 or O2’’ applying instead of the term accordance with §§ 75.31 and 75.33 and as range of the unit(s). Note that the MPC for ‘‘SO2’’. Set the new span and range in required elsewhere in this part, calculate the CO2 monitors shall only be used for the accordance with section 2.1.3 of this maximum potential stack gas flow rate (MPF) purpose of providing substitute data under appendix and report the new span value in in units of standard cubic feet per hour the monitoring plan. this part. The CO2 monitor span and range (scfh), as the product of the MPV (in units of shall be determined according to section 2.1.4 Flow Monitors wet, standard fpm) times 60, times the cross- 2.1.3 of this appendix. Select the full-scale range of the flow sectional area of the stack or duct (in ft2) at monitor so that it is consistent with section the flow monitor location.

 FH   20. 9   100  MPV = d f   ()Eq. A-3a    −  − AOO 20. 9 %2d  100 %H 2  or

 FH   100  100  MPV = c f   ()Eq. A-3b     − A % CO2d  100 %H 2 O

Where: multiplying the MPV (converted to and shall make any necessary span and range MPV = maximum potential velocity (fpm, equivalent daily calibration error units) by a adjustments with corresponding monitoring standard wet basis). factor no less than 1.00 and no greater than plan updates, as described in paragraphs (a) Fd = dry-basis F factor (dscf/mmBtu) from 1.25, and rounding up the result to at least through (c) of this section 2.1.4.3. Span and Table 1, Appendix F to this part. two significant figures. For calibration span range adjustments may be required, for Fc = carbon-based F factor (scf CO2/mmBtu) values in inches of water, retain at least two example, as a result of changes in the fuel from Table 1, Appendix F to this part. decimal places. Select appropriate reference supply, changes in the stack or ductwork Hf = maximum heat input (mmBtu/minute) signals for the daily calibration error tests as configuration, changes in the manner of for all units, combined, exhausting to the percentages of the calibration span value. operation of the unit, or installation or stack or duct where the flow monitor is Finally, calculate the ‘‘flow rate span value’’ removal of emission controls. In located. (in scfh) as the product of the MPF, as implementing the provisions in paragraphs A = inside cross sectional area (ft2) of the flue determined in section 2.1.4.1 of this (a) and (b) of this section 2.1.4.3, note that at the flow monitor location. appendix, times the same factor (between flow rate data recorded during short-term, non-representative operating conditions (e.g., %O2d = maximum oxygen concentration, 1.00 and 1.25) that was used to calculate the percent dry basis, under normal calibration span value. Round off the flow a trial burn of a different type of fuel) shall operating conditions. rate span value to the nearest 1000 scfh. be excluded from consideration. The owner or operator shall keep the results of the most %CO2d = minimum carbon dioxide Select the full-scale range of the flow monitor concentration, percent dry basis, under so that it is greater than or equal to the span recent span and range evaluation on-site, in normal operating conditions. value and is consistent with section 2.1 of a format suitable for inspection. Make each required span or range adjustment no later %H2O = maximum percent flue gas moisture this appendix. Include in the monitoring content under normal operating plan for the unit: calculations of the MPV, than 45 days after the end of the quarter in conditions. MPF, calibration span value, flow rate span which the need to adjust the span or range is identified. 2.1.4.2 Span Values and Range value, and full-scale range (expressed both in scfh and, if different, in the measurement (a) If the fuel supply, stack or ductwork Determine the span and range of the flow units of calibration). configuration, operating parameters, or other monitor as follows. Convert the MPV, as conditions change such that the maximum determined in section 2.1.4.1 of this 2.1.4.3 Adjustment of Span and Range potential flow rate changes significantly, appendix, to the same measurement units of For each affected unit or common stack, adjust the span and range to assure the flow rate that are used for daily calibration the owner or operator shall make a periodic continued accuracy of the flow monitor. A error tests (e.g., scfh, kscfh, kacfm, or evaluation of the MPV, MPF, span, and range ‘‘significant’’ change in the MPV or MPF differential pressure (inches of water)). Next, values for each flow rate monitor (at a means that the guidelines of section 2.1 of determine the ‘‘calibration span value’’ by minimum, an annual evaluation is required) this appendix can no longer be met, as

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determined by either a periodic evaluation by 2.1.6 Maximum Potential Moisture 3.3.2 Relative Accuracy for NOX-Diluent the owner or operator or from the results of Percentage Continuous Emission Monitoring Systems an audit by the Administrator. The owner or When Equation 19–3, 19–4 or 19–8 in (a) The relative accuracy for NOX-diluent operator should evaluate whether any Method 19 in appendix A to part 60 of this continuous emission monitoring systems planned changes in operation of the unit may chapter is used to determine NOX emission shall not exceed 10.0 percent. affect the flow of the unit or stack and should rate, the owner or operator of a unit that uses (b) For affected units where the average of plan any necessary span and range changes a continuous moisture monitoring system the monitoring system measurements of NOX needed to account for these changes, so that shall, for the purpose of providing substitute emission rate during the relative accuracy they are made in as timely a manner as data under § 75.37, determine the maximum test audit is less than or equal to 0.200 lb/ practicable to coordinate with the operational potential moisture percentage. The maximum mmBtu, the mean value of the continuous changes. Calculate the adjusted calibration potential moisture percentage shall be based emission monitoring system measurements span and flow rate span values using the upon 720 hours or more of quality-assured shall not exceed ±0.020 lb/mmBtu of the procedures in section 2.1.4.2 of this CEM data, representing the full operating reference method mean value whenever the appendix. load range of the unit(s). The maximum relative accuracy specification of 10.0 (b) Whenever the full-scale range is potential moisture percentage shall be the percent is not achieved. exceeded during a quarter, provided that the highest quality-assured hourly average H2O exceedance is not caused by a monitor out- * * * * * concentration recorded in the 720 (or more) of-control period, report 200.0 percent of the hours of data used for the determination. 3.3.6 Relative Accuracy for Moisture current full-scale range as the hourly flow 55. Appendix A to part 75 is amended by Monitoring Systems rate for each hour of the full-scale revising section 3.1, the last sentence in the The relative accuracy of a moisture exceedance. If the range is exceeded, make first paragraph of section 3.2, and section monitoring system shall not exceed 10.0 appropriate adjustments to the MPF, flow 3.3.2; by adding section 3.3.6; and by revising percent. The relative accuracy test results are rate span, and range to prevent future full- sections 3.3.7, 3.4.1 and 3.5 to read as also acceptable if the mean difference of the scale exceedances. Calculate the new follows: reference method measurements (in percent calibration span value by converting the new H2O) and the corresponding moisture flow rate span value from units of scfh to 3. Performance Specifications monitoring system measurements (in percent units of daily calibration. A calibration error 3.1 Calibration Error H2O), calculated using Equation A–7 of this test must be performed and passed to appendix, are within ±1.5 percent H2O. validate data on the new range. (a) The calibration error performance (c) Whenever changes are made to the specifications in this section apply only to 7- 3.3.7 Relative Accuracy for NOX MPV, MPF, full-scale range, or span value of day calibration error tests under sections Concentration Monitoring Systems the flow monitor, as described in paragraphs 6.3.1 and 6.3.2 of this appendix and to the (a) The following requirement applies only offline calibration demonstration described (a) and (b) of this section, record and report to NOX concentration monitoring systems in section 2.1.1.2 of appendix B to this part. (as applicable) the new full-scale range (i.e., NOX pollutant concentration monitors) The calibration error limits for daily setting, calculations of the flow rate span that are used to determine NOX mass value, calibration span value, MPV, and MPF operation of the continuous monitoring emissions, where the owner or operator in an updated monitoring plan for the unit. systems required under this part are found in elects to monitor and report NOX mass The monitoring plan update shall be made in section 2.1.4(a) of appendix B to this part. emissions using a NOX concentration the quarter in which the changes become (b) The calibration error of SO2 and NOX monitoring system and a flow monitoring effective. Record and report the adjusted pollutant concentration monitors shall not system. calibration span and reference values as parts deviate from the reference value of either the (b) The relative accuracy for NOX of the records for the calibration error test zero or upscale calibration gas by more than concentration monitoring systems shall not required by appendix B to this part. 2.5 percent of the span of the instrument, as exceed 10.0 percent. Alternatively, for Whenever the calibration span value is calculated using Equation A–5 of this affected units where the average of the adjusted, use reference values for the appendix. Alternatively, where the span monitoring system measurements of NOX calibration error test that meet the value is less than 200 ppm, calibration error concentration during the relative accuracy requirements of section 2.2.2.1 of this test results are also acceptable if the absolute test audit is less than or equal to 250.0 ppm, appendix, based on the most recent adjusted value of the difference between the monitor the mean value of the continuous emission calibration span value. Perform a calibration | response value and the reference value, R– monitoring system measurements shall not error test according to section 2.1.1 of A¥ in Equation A–5 of this appendix, is exceed ±15.0 ppm of the reference method appendix B to this part whenever making a ≤ 5 ppm. The calibration error of CO2 or O2 mean value. change to the flow monitor span or range, monitors (including O2 monitors used to 3.4 * * * unless the range change also triggers a measure CO2 emissions or percent moisture) 3.4.1 SO2 Pollutant Concentration Monitors, recertification under § 75.20(b). shall not deviate from the reference value of NOX Concentration Monitoring Systems and 2.1.5 Minimum Potential Moisture the zero or upscale calibration gas by >0.5 NOX-Diluent Continuous Emission Percentage percent O2 or CO2, as calculated using the | Monitoring Systems Except as provided in section 2.1.6 of this term ¥R–A in the numerator of Equation A– SO2 pollutant concentration monitors, appendix, the owner or operator of a unit that 5 of this appendix. The calibration error of NOX-diluent continuous emission monitoring uses a continuous moisture monitoring flow monitors shall not exceed 3.0 percent of systems and NOX concentration monitoring system to correct emission rates and heat the calibration span value of the instrument, systems used to determine NOX mass inputs from a dry basis to a wet basis (or as calculated using Equation A–6 of this emissions, as defined in § 75.71(a)(2), shall vice-versa) shall, for the purpose of providing appendix. For differential pressure-type flow not be biased low as determined by the test substitute data under § 75.37, use a default monitors, the calibration error test results are | | procedure in section 7.6 of this appendix. value of 3.0 percent H2O as the minimum also acceptable if R–A , the absolute value of potential moisture percentage. Alternatively, the difference between the monitor response The bias specification applies to all SO2 the minimum potential moisture percentage and the reference value in Equation A–6, pollutant concentration monitors and to all may be based upon 720 hours or more of does not exceed 0.01 inches of water. NOX concentration monitoring systems, including those measuring an average SO2 or quality-assured CEM data, representing the 3.2 Linearity Check full operating load range of the unit(s). If this NOX concentration of 250.0 ppm or less, and option is chosen, the minimum potential * * * For CO2 or O2 monitors (including to all NOX-diluent continuous emission moisture percentage shall be the lowest O2 monitors used to measure CO2 emissions monitoring systems, including those or percent moisture): measuring an average NOX emission rate of quality-assured hourly average H2O concentration recorded in the 720 (or more) * * * * * 0.200 lb/mmBtu or less. hours of data used for the determination. 3.3 * * * * * * * *

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3.5 Cycle Time Office of Research and Development, (MD– exempted from the linearity test The cycle time for pollutant concentration 77B), U.S. Environmental Protection Agency, requirements of this part. For units using monitors, oxygen monitors used to determine Research Triangle Park, NC 27711. emission controls and other units using both percent moisture, and any other continuous 5.1.5 Research Gas Mixtures a high and a low span, perform a linearity check on both the low- and high-scales for emission monitoring system(s) required to Research gas mixtures must be vendor- initial certification. For on-going quality perform a cycle time test shall not exceed 15 certified to be within 2.0 percent of the assurance of the CEMS, perform linearity minutes. concentration specified on the cylinder label 56. Appendix A to part 75 is amended by (tag value), using the uncertainty calculation checks, using the procedures in this section, revising the first sentence of the first procedure in section 2.1.8 of the ‘‘EPA on the range(s) and at the frequency specified paragraph of section 4 and paragraph (6) to Traceability Protocol for Assay and in section 2.2.1 of appendix B to this part. read as follows: Certification of Gaseous Calibration Challenge each monitor with calibration gas, as defined in section 5.1 of this appendix, at 4. Data Acquisition and Handling Systems Standards,’’ September 1997, EPA–600/R–97/ 121. Inquiries about the RGM program the low-, mid-, and high-range concentrations Automated data acquisition and handling should be directed to: National Institute of specified in section 5.2 of this appendix. systems shall read and record the full range Standards and Technology, Analytical Introduce the calibration gas at the gas of pollutant concentrations and volumetric Chemistry Division, Chemical Science and injection port, as specified in section 2.2.1 of flow from zero through span and provide a Technology Laboratory, B–324 Chemistry, this appendix. Operate each monitor at its continuous, permanent record of all Gaithersburg, MD 20899. normal operating temperature and measurements and required information as 5.1.6 Zero Air Material conditions. For extractive and dilution type an ASCII flat file capable of transmission monitors, pass the calibration gas through all both by direct computer-to-computer Zero air material is defined in § 72.2 of this filters, scrubbers, conditioners, and other electronic transfer via modem and EPA- chapter. monitor components used during normal provided software and by an IBM-compatible 5.1.7 NIST/EPA-Approved Certified sampling and through as much of the personal computer diskette. Reference Materials sampling probe as is practical. For in-situ * * * * * Existing certified reference materials type monitors, perform calibration checking (6) Provide a continuous, permanent record (CRMs) that are still within their certification all active electronic and optical components, of all measurements and required period may be used as calibration gas. including the transmitter, receiver, and information as an ASCII flat file capable of analyzer. Challenge the monitor three times 5.1.8 Gas Manufacturer’s Intermediate transmission both by direct computer-to- with each reference gas (see example data Standards computer electronic transfer via modem and sheet in Figure 1). Do not use the same gas EPA-provided software and by an IBM- Gas manufacturer’s intermediate standards twice in succession. To the extent compatible personal computer diskette. is defined in § 72.2 of this chapter. practicable, the duration of each linearity 57. Appendix A to part 75 is amended by 5.2 Concentrations test, from the hour of the first injection to the revising sections 5 through 5.1.6, adding hour of the last injection, shall not exceed 24 sections 5.1.7 through 5.1.8, and revising Four concentration levels are required as follows. unit operating hours. Record the monitor sections 5.2 through 5.2.4 to read as follows: response from the data acquisition and 5. Calibration Gas 5.2.1 Zero-level Concentration handling system. For each concentration, use 0.0 to 20.0 percent of span, including span the average of the responses to determine the 5.1 Reference Gases for high-scale or both low- and high-scale for error in linearity using Equation A–4 in this For the purposes of part 75, calibration SO2, NOX, CO2, and O2 monitors, as appendix. Linearity checks are acceptable for gases include the following: appropriate. monitor or monitoring system certification, 5.1.1 Standard Reference Materials (SRM) 5.2.2 Low-level Concentration recertification, or quality assurance if none of the test results exceed the applicable These calibration gases may be obtained 20.0 to 30.0 percent of span, including performance specifications in section 3.2 of from the National Institute of Standards and span for high-scale or both low- and high- this appendix. The status of emission data Technology (NIST) at the following address: scale for SO2, NOX, CO2, and O2 monitors, as from a CEMS prior to and during a linearity Quince Orchard and Cloppers Road, appropriate. Gaithersburg, MD 20899–0001. test period shall be determined as follows: 5.2.3 Mid-level Concentration (a) For the initial certification of a CEMS, 5.1.2 SRM-Equivalent Compressed Gas 50.0 to 60.0 percent of span, including data from the monitoring system are Primary Reference Material (PRM) span for high-scale or both low- and high- considered invalid until all certification tests, Contact the Gas Metrology Team, scale for SO2, NOX, CO2, and O2 monitors, as including the linearity test, have been Analytical Chemistry Division, Chemical appropriate. successfully completed, unless the data Science and Technology Laboratory of NIST, 5.2.4 High-level Concentration validation procedures in § 75.20(b)(3) are at the address in section 5.1.1, for a list of used. When the procedures in § 75.20(b)(3) vendors and cylinder gases. 80.0 to 100.0 percent of span, including are followed, the words ‘‘initial certification’’ span for high-scale or both low-and high- 5.1.3 NIST Traceable Reference Materials apply instead of ‘‘recertification,’’ and scale for SO2, NOX, CO2, and O2 monitors, as complete all of the initial certification tests Contact the Gas Metrology Team, appropriate. by the applicable deadline in § 75.4, rather Analytical Chemistry Division, Chemical 58. Appendix A to part 75 is amended by than within the time periods specified in Science and Technology Laboratory of NIST, revising sections 6.2, 6.3.1, 6.3.2, 6.4, 6.5, § 75.20(b)(3)(iv) for the individual tests. at the address in section 5.1.1, for a list of 6.5.1, 6.5.2, 6.5.6, 6.5.7, 6.5.9 and 6.5.10, and (b) For the routine quality assurance vendors and cylinder gases. adding sections 6.5.2.1, 6.5.2.2, 6.5.6.1, linearity checks required by section 2.2.1 of 5.1.4 EPA Protocol Gases 6.5.6.2, and 6.5.6.3 to read as follows: appendix B to this part, use the data (a) EPA Protocol gases must be vendor- 6. Certification Tests and Procedures validation procedures in section 2.2.3 of certified to be within 2.0 percent of the * * * * * appendix B to this part. concentration specified on the cylinder label (c) When a linearity test is required as a (tag value), using the uncertainty calculation 6.2 Linearity Check (General Procedures) diagnostic test or for recertification, use the procedure in section 2.1.8 of the ‘‘EPA Check the linearity of each SO2, NOX, CO2, data validation procedures in § 75.20(b)(3). Traceability Protocol for Assay and and O2 monitor while the unit, or group of (d) For linearity tests of non-redundant Certification of Gaseous Calibration units for a common stack, is combusting fuel backup monitoring systems, use the data Standards,’’ September 1997, EPA–600/R–97/ at conditions of typical stack temperature validation procedures in § 75.20(d)(2)(iii). 121. and pressure; it is not necessary for the unit (e) For linearity tests performed during a (b) A copy of EPA–600/R–97/121 is to be generating electricity during this test. grace period and after the expiration of a available from the National Technical Notwithstanding these requirements, if the grace period, use the data validation Information Service, 5285 Port Royal Road, SO2 or NOX span value for a particular procedures in sections 2.2.3 and 2.2.4, Springfield, VA, 703–487–4650 and from the monitor range is ≤30 ppm, that range is respectively, of appendix B to this part.

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(f) For all other linearity checks, use the each day (at approximately 24-hour intervals) adjustment is made, and report them in the data validation procedures in section 2.2.3 of for 7 consecutive days according to the certification or recertification application. appendix B to this part. procedures given in this section. The results The status of emissions data from a flow 6.3 * * * of a 7-day calibration error test are acceptable monitor prior to and during a 7-day for monitor or monitoring system calibration error test period shall be 6.3.1 Gas Monitor 7-day Calibration Error certification, recertification or diagnostic determined as follows: Test testing if none of these daily calibration error (a) For initial certification, data from the test results exceed the applicable Measure the calibration error of each SO2 monitor are considered invalid until all performance specifications in section 3.1 of monitor, each NOX monitor and each CO2 or certification tests, including the 7-day this appendix.The status of emission data O2 monitor while the unit is combusting fuel calibration error test, have been successfully from a gas monitor prior to and during a 7- (but not necessarily generating electricity) completed, unless the data validation day calibration error test period shall be once each day for 7 consecutive operating procedures in § 75.20(b)(3) are used. When days according to the following procedures. determined as follows: (a) For initial certification, data from the the procedures in § 75.20(b)(3) are followed, (In the event that extended unit outages the words ‘‘initial certification’’ apply occur after the commencement of the test, the monitor are considered invalid until all certification tests, including the 7-day instead of ‘‘recertification,’’ and complete all 7 consecutive unit operating days need not of the initial certification tests by the be 7 consecutive calendar days.) Units using calibration error test, have been successfully applicable deadline in § 75.4, rather than dual span monitors must perform the completed, unless the data validation within the time periods specified in calibration error test on both high- and low- procedures in § 75.20(b)(3) are used. When scales of the pollutant concentration monitor. the procedures in § 75.20(b)(3) are followed, § 75.20(b)(3)(iv) for the individual tests. The calibration error test procedures in this the words ‘‘initial certification’’ apply (b) When a 7-day calibration error test is section and in section 6.3.2 of this appendix instead of ‘‘recertification,’’ and complete all required as a diagnostic test or for shall also be used to perform the daily of the initial certification tests by the recertification, use the data validation assessments and additional calibration error applicable deadline in § 75.4, rather than procedures in § 75.20(b)(3). tests required under sections 2.1.1 and 2.1.3 within the time periods specified in 6.4 Cycle Time Test of appendix B to this part. Do not make § 75.20(b)(3)(iv) for the individual tests. Perform cycle time tests for each pollutant manual or automatic adjustments to the (b) When a 7-day calibration error test is monitor settings until after taking required as a diagnostic test or for concentration monitor and continuous measurements at both zero and high recertification, use the data validation emission monitoring system while the unit is concentration levels for that day during the procedures in § 75.20(b)(3). operating, according to the following 7-day test. If automatic adjustments are made 6.3.2 Flow Monitor 7-day Calibration Error procedures (see also Figure 6 at the end of following both injections, conduct the Test this appendix). Use a zero-level and a high- level calibration gas (as defined in section 5.2 calibration error test such that the magnitude Perform the 7-day calibration error test of of this appendix) alternately. To determine of the adjustments can be determined and a flow monitor, when required for the upscale elapsed time, inject a zero-level recorded. Record and report test results for certification, recertification or diagnostic concentration calibration gas into the probe each day using the unadjusted concentration testing, according to the following measured in the calibration error test prior to procedures. Introduce the reference signal tip (or injection port leading to the making any manual or automatic adjustments corresponding to the values specified in calibration cell, for in situ systems with no (i.e., resetting the calibration). The section 2.2.2.1 of this appendix to the probe probe). Record the stable starting gas value calibration error tests should be tip (or equivalent), or to the transducer. and start time, using the data acquisition and approximately 24 hours apart, (unless the 7- During the 7-day certification test period, handling system (DAHS). Next, allow the day test is performed over non-consecutive conduct the calibration error test while the monitor to measure the concentration of flue days). Perform calibration error tests at both unit is operating once each unit operating gas emissions until the response stabilizes. the zero-level concentration and high-level day (as close to 24-hour intervals as Record the stable ending stack emissions concentration, as specified in section 5.2 of practicable). In the event that extended unit value and the end time of the test using the this appendix. Alternatively, a mid-level outages occur after the commencement of the DAHS. Determine the upscale elapsed time concentration gas (50.0 to 60.0 percent of the test, the 7 consecutive operating days need as the time it takes for 95.0 percent of the span value) may be used in lieu of the high- not be 7 consecutive calendar days. Record step change to be achieved between the level gas, provided that the mid-level gas is the flow monitor responses by means of the stable starting gas value and the stable ending more representative of the actual stack gas data acquisition and handling system. stack emissions value. Then repeat the concentrations. In addition, repeat the Calculate the calibration error using Equation procedure, starting by injecting the high-level procedure for SO2 and NOX pollutant A–6 of this appendix. Do not perform any gas concentration to determine the concentration monitors using the low-scale corrective maintenance, repair, or downscale elapsed time, which is the time it for units equipped with emission controls or replacement upon the flow monitor during takes for 95.0 percent of the step change to other units with dual span monitors. Use the 7-day test period other than that required only calibration gas, as specified in section be achieved between the stable starting gas in the quality assurance/quality control plan value and the stable ending stack emissions 5.1 of this appendix. Introduce the required by appendix B to this part. Do not calibration gas at the gas injection port, as value. End the downscale test by measuring make adjustments between the zero and high the stable concentration of flue gas specified in section 2.2.1 of this appendix. reference level measurements on any day emissions. Record the stable starting and Operate each monitor in its normal sampling during the 7-day test. If the flow monitor ending monitor values, the start and end mode. For extractive and dilution type operates within the calibration error times, and the downscale elapsed time for monitors, pass the calibration gas through all performance specification (i.e., less than or filters, scrubbers, conditioners, and other equal to 3.0 percent error each day and the monitor using the DAHS. A stable value monitor components used during normal requiring no corrective maintenance, repair, is equivalent to a reading with a change of sampling and through as much of the or replacement during the 7-day test period), less than 2.0 percent of the span value for 2 sampling probe as is practical. For in-situ the flow monitor passes the calibration error minutes, or a reading with a change of less type monitors, perform calibration, checking test. Record all maintenance activities and than 6.0 percent from the measured average all active electronic and optical components, the magnitude of any adjustments. Record concentration over 6 minutes. (Owners or including the transmitter, receiver, and output readings from the data acquisition and operators of systems which do not record analyzer. Challenge the pollutant handling system before and after all data in 1-minute or 3-minute intervals may concentration monitors and CO2 or O2 adjustments. Record and report all petition the Administrator under § 75.66 for monitors once with each calibration gas. calibration error test results using the alternative stabilization criteria). For Record the monitor response from the data unadjusted flow rate measured in the monitors or monitoring systems that perform acquisition and handling system. Using calibration error test prior to resetting the a series of operations (such as purge, sample, Equation A–5 of this appendix, determine the calibration. Record all adjustments made and analyze), time the injections of the calibration error at each concentration once during the 7-day period at the time the calibration gases so they will produce the

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When relative accuracy test audits are (6) For all other RATAs, use the data (See Figure 5 at the end of this appendix.) performed on continuous emission validation procedures in section 2.3.2 of For the NOx-diluent continuous emission monitoring systems or component(s) on appendix B to this part. monitoring system test and SO2-diluent bypass stacks/ducts, use the fuel normally (g) For each SO2 or CO2 pollutant continuous emission monitoring system test, combusted by the unit (or units, if more than concentration monitor, each flow monitor, record and report the longer cycle time of the one unit exhausts into the flue) when each CO2 or O2 diluent monitor used to two component analyzers as the system cycle emissions exhaust through the bypass stack/ determine heat input, each NOX time. For time-shared systems, this procedure ducts. concentration monitoring system used to must be done at all probe locations that will (b) Perform each RATA at the load level(s) determine NOX mass emissions, as defined in be polled within the same 15-minute period specified in section 6.5.1 or 6.5.2 of this § 75.71(a)(2), each moisture monitoring during monitoring system operations. To appendix or in section 2.3.1.3 of appendix B system and each NOX-diluent continuous determine the cycle time for time-shared to this part, as applicable. emission monitoring system, calculate the systems, add together the longest cycle time (c) For monitoring systems with dual relative accuracy, in accordance with section obtained at each of the probe locations. ranges, perform the relative accuracy test on 7.3 or 7.4 of this appendix, as applicable. In Report the sum of the longest cycle time at the range normally used for measuring addition (except for CO2, O2, SO2-diluent or each of the probe locations plus the sum of emissions. For units with add-on SO2 or NOx moisture monitors), test for bias and the time required for all purge cycles (as controls or for units that need a dual range determine the appropriate bias adjustment determined by the continuous emission to record high concentration ‘‘spikes’’ during factor, in accordance with sections 7.6.4 and monitoring system manufacturer) at each of startup conditions, the low range is 7.6.5 of this appendix, using the data from the probe locations as the cycle time for each considered normal. However, for some dual the relative accuracy test audits. of the time-shared systems. For monitors span units (e.g., for units that use fuel 6.5.1 Gas Monitoring System RATAs with dual ranges, report the test results from switching or for which the emission controls (Special Considerations) on the range giving the longer cycle time. are operated seasonally), either of the two Cycle time test results are acceptable for measurement ranges may be considered (a) Perform the required relative accuracy monitor or monitoring system certification, normal; in such cases, perform the RATA on test audits for each SO2 or CO2 pollutant recertification or diagnostic testing if none of the range that is in use at the time of the concentration monitor, each CO2 or O2 the cycle times exceed 15 minutes. The status scheduled test. diluent monitor used to determine heat of emissions data from a monitor prior to and (d) Record monitor or monitoring system input, each NOX-diluent continuous during a cycle time test period shall be output from the data acquisition and emission monitoring system, each NOX determined as follows: handling system. concentration monitoring system used to determine NOX mass emissions, as defined in (a) For initial certification, data from the (e) Complete each single-load relative § 75.71(a)(2), and each SO2-diluent monitor are considered invalid until all accuracy test audit within a period of 168 continuous emission monitoring system, at certification tests, including the cycle time consecutive unit operating hours, as defined the normal load level for the unit (or test, have been successfully completed, in § 72.2 of this chapter (or, for CEMS combined units, if common stack), as defined unless the data validation procedures in installed on common stacks or bypass stacks, in section 6.5.2.1 of this appendix. If two § 75.20(b)(3) are used. When the procedures 168 consecutive stack operating hours, as load levels have been designated as normal, in § 75.20(b)(3) are followed, the words defined in § 72.2 of this chapter). For 2-level the RATAs may be done at either load level. ‘‘initial certification’’ apply instead of and 3-level flow monitor RATAs, complete (b) For the initial certification of a gas ‘‘recertification,’’ and complete all of the all of the RATAs at all levels, to the extent monitoring system and for recertifications in initial certification tests by the applicable practicable, within a period of 168 deadline in § 75.4, rather than within the which, in addition to a RATA, one or more consecutive unit (or stack) operating hours; other tests are required (i.e., a linearity test, time periods specified in § 75.20(b)(3)(iv) for however, if this is not possible, up to 720 the individual tests. cycle time test, or 7-day calibration error consecutive unit (or stack) operating hours test), EPA recommends that the RATA not be (b) When a cycle time test is required as may be taken to complete a multiple-load a diagnostic test or for recertification, use the commenced until the other required tests of flow RATA. the CEMS have been passed. data validation procedures in § 75.20(b)(3). (f) The status of emission data from the 6.5 Relative Accuracy and Bias Tests CEMS prior to and during the RATA test 6.5.2 Flow Monitor RATAs (Special (General Procedures) period shall be determined as follows: Considerations) Perform the required relative accuracy test (1) For the initial certification of a CEMS, (a) Except for flow monitors on bypass audits (RATAs) as follows for each CO2 data from the monitoring system are stacks/ducts and peaking units, perform pollutant concentration monitor (including considered invalid until all certification tests, relative accuracy test audits for the initial O2 monitors used to determine CO2 pollutant including the RATA, have been successfully certification of each flow monitor at three concentration), each SO2 pollutant completed, unless the data validation different exhaust gas velocities (low, mid, concentration monitor, each NOX procedures in § 75.20(b)(3) are used. When and high), corresponding to three different concentration monitoring system used to the procedures in § 75.20(b)(3) are followed, load levels within the range of operation, as determine NOX mass emissions, each flow the words ‘‘initial certification’’ apply defined in section 6.5.2.1 of this appendix. monitor, each NOX-diluent continuous instead of ‘‘recertification,’’ and complete all For a common stack/duct, the three different emission monitoring system, each O2 or CO2 of the initial certification tests by the exhaust gas velocities may be obtained from diluent monitor used to calculate heat input, applicable deadline in § 75.4, rather than frequently used unit/load combinations for each moisture monitoring system and each within the time periods specified in the units exhausting to the common stack. SO2-diluent continuous emission monitoring § 75.20(b)(3)(iv) for the individual tests. Select the three exhaust gas velocities such system. For NOX concentration monitoring (2) For the routine quality assurance that the audit points at adjacent load levels systems used to determine NOX mass RATAs required by section 2.3.1 of appendix (i.e., low and mid or mid and high), in emissions, as defined in § 75.71(a)(2), use the B to this part, use the data validation megawatts (or in thousands of lb/hr of steam same general RATA procedures as for SO2 procedures in section 2.3.2 of appendix B to production), are separated by no less than pollutant concentration monitors; however, this part. 25.0 percent of the range of operation, as use the reference methods for NOX (3) For recertification RATAs, use the data defined in section 6.5.2.1 of this appendix. concentration specified in section 6.5.10 of validation procedures in § 75.20(b)(3). (b) For flow monitors on bypass stacks/ this appendix: (4) For quality assurance RATAs of non- ducts and peaking units, the flow monitor (a) Except as provided in § 75.21(a)(5), redundant backup monitoring systems, use relative accuracy test audits for initial perform each RATA while the unit (or units, the data validation procedures in certification and recertification shall be if more than one unit exhausts into the flue) §§ 75.20(d)(2)(v) and (vi). single-load tests, performed at the normal is combusting the fuel that is normal for that (5) For RATAs performed during and after load, as defined in section 6.5.2.1 of this unit (for some units, more than one type of the expiration of a grace period, use the data appendix.

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(c) Flow monitor recertification RATAs level(s), the owner or operator shall, at a (for SO2, NOX, and moisture monitoring shall be done at three load level(s), unless minimum, determine the relative number of system RATAs), Performance Specification 3 otherwise specified in paragraph (b) of this operating hours at each of the three load in appendix B to part 60 of this chapter (for section or unless otherwise specified or levels, low, mid and high over the past four O2 and CO2 monitor RATAs), Method 1 (or approved by the Administrator. representative operating quarters. The owner 1A) (for volumetric flow rate monitor (d) The semiannual and annual quality or operator shall determine, to the nearest 0.1 RATAs), Method 3 (for molecular weight), assurance flow monitor RATAs required percent, the percentage of the time that each and Method 4 (for moisture determination) in under appendix B to this part shall be done load level (low, mid, high) has been used appendix A to part 60 of this chapter. Unless at the load level(s) specified in section 2.3.1.3 during that time period. A summary of the otherwise specified, use only codified of appendix B to this part. data used for this determination and the versions of PS No. 2 revised as of July 1, 6.5.2.1 Range of Operation and Normal calculated results shall be kept on-site in a 1995, July 1, 1996 or July 1, 1997. The Load Level(s) format suitable for inspection. following alternative reference method (d) Based on the analysis of the historical traverse point locations are permitted for (a) The owner or operator shall determine load data the owner or operator shall moisture and gas monitor RATAs: the upper and lower boundaries of the ‘‘range designate the most frequently used load level (a) For moisture determinations where the of operation’’ for each unit (or combination as the normal load level for the unit (or moisture data are used only to determine of units, for common stack configurations) combination of units, for common stacks). stack gas molecular weight, a single reference that uses CEMS to account for its emissions The owner or operator may also designate the method point, located at least 1.0 meter from and for each unit that uses the optional fuel second most frequently used load level as an the stack wall, may be used. For moisture flow-to-load quality assurance test in section additional normal load level for the unit or monitoring system RATAs and for gas 2.1.7 of appendix D to this part. The lower stack. For peaking units, normal load monitor RATAs in which moisture data are boundary of the range of operation of a unit designations are unnecessary; the entire used to correct pollutant or diluent shall be the minimum safe, stable load. For operating load range shall be considered concentrations from a dry basis to a wet basis common stacks, the minimum safe, stable normal. If the manner of operation of the unit (or vice-versa), single-point moisture load shall be the lowest of the minimum safe, changes significantly, such that the sampling may only be used if the 12-point stable loads for any of the units discharging designated normal load(s) or the two most stratification test described in section 6.5.6.1 through the stack. Alternatively, for a group frequently used load levels change, the of this appendix is performed prior to the of frequently-operated units that serve a owner or operator shall repeat the historical RATA for at least one pollutant or diluent common stack, the sum of the minimum safe, load analysis and shall redesignate the gas, and if the test is passed according to the stable loads for the individual units may be normal load(s) and the two most frequently acceptance criteria in section 6.5.6.3(b) of used as the lower boundary of the range of used load levels, as appropriate. A minimum this appendix. operation. The upper boundary of the range of two representative quarters of historical (b) For gas monitoring system RATAs, the of operation of a unit shall be the maximum load data are required to document that a owner or operator may use any of the sustainable load. The ‘‘maximum sustainable change in the manner of unit operation has following options: load’’ is the higher of either: the nameplate occurred. (1) At any location (including locations or rated capacity of the unit, less any (e) Beginning on April 1, 2000, the owner where stratification is expected), use a physical or regulatory limitations or other or operator shall report the upper and lower deratings; or the highest sustainable unit minimum of six traverse points along a boundaries of the range of operation for each diameter, in the direction of any expected load, based on at least four quarters of unit (or combination of units, for common representative historical operating data. For stratification. The points shall be located in stacks), in units of megawatts or thousands accordance with Method 1 in appendix A to common stacks, the maximum sustainable of lb/hr of steam production, in the electronic load is the sum of all of the maximum part 60 of this chapter. quarterly report required under § 75.64. (2) At locations where section 3.2 of PS No. sustainable loads of the individual units Except for peaking units, the owner or discharging through the stack, unless this 2 allows the use of a short reference method operator shall indicate, in the electronic measurement line (with three points located load is unattainable in practice, in which quarterly report (as part of the electronic case use the highest sustainable combined at 0.4, 1.0, and 2.0 meters from the stack monitoring plan) the load level (or levels) wall), the owner or operator may use an load for the units that discharge through the designated as normal under this section and stack, based on at least four quarters of alternative 3-point measurement line, shall also indicate the two most frequently locating the three points at 4.4, 14.6, and 29.6 representative historical operating data. The used load levels.. load values for the unit(s) shall be expressed percent of the way across the stack, in either in units of megawatts or thousands of 6.5.2.2 Multi-Load Flow RATA Results accordance with Method 1 in appendix A to lb/hr of steam load. For each multi-load flow RATA, calculate part 60 of this chapter. (b) The operating levels for relative the flow monitor relative accuracy at each (3) At locations where stratification is accuracy test audits shall, except for peaking operating level. If a flow monitor relative likely to occur (e.g., following a wet scrubber units, be defined as follows: the ‘‘low’’ accuracy test is failed or aborted due to a or when dissimilar gas streams are operating level shall be the first 30.0 percent problem with the monitor on any level of a combined), the short measurement line from of the range of operation; the ‘‘mid’’ 2-level (or 3-level) relative accuracy test section 3.2 of PS No. 2 (or the alternative line operating level shall be the middle portion audit, the RATA must be repeated at that described in paragraph (b)(2) of this section) (30.0 to 60.0 percent) of the range of load level. However, the entire 2-level (or 3- may be used in lieu of the prescribed ‘‘long’’ operation; and the ‘‘high’’ operating level level) relative accuracy test audit does not measurement line in section 3.2 of PS No. 2, shall be the upper end (60.0 to 100.0 percent) have to be repeated unless the flow monitor provided that the 12-point stratification test of the range of operation. For example, if the polynomial coefficients or K-factor(s) are described in section 6.5.6.1 of this appendix upper and lower boundaries of the range of changed, in which case a 3-level RATA is is performed and passed one time at the operation are 100 and 1100 megawatts, required. location (according to the acceptance criteria respectively, then the low, mid, and high * * * * * of section 6.5.6.3(a) of this appendix) and operating levels would be 100 to 400 provided that either the 12-point megawatts, 400 to 700 megawatts, and 700 to 6.5.6 Reference Method Traverse Point stratification test or the alternative 1100 megawatts, respectively. Selection (abbreviated) stratification test in section (c) The owner or operator shall identify, for Select traverse points that ensure 6.5.6.2 of this appendix is performed and each affected unit or common stack (except acquisition of representative samples of passed prior to each subsequent RATA at the for peaking units), the ‘‘normal’’ load level or pollutant and diluent concentrations, location (according to the acceptance criteria levels (low, mid or high), based on the moisture content, temperature, and flue gas of section 6.5.6.3(a) of this appendix). operating history of the unit(s). This flow rate over the flue cross section. To (4) A single reference method measurement requirement becomes effective on April 1, achieve this, the reference method traverse point, located no less than 1.0 meter from the 2000; however, the owner or operator may points shall meet the requirements of section stack wall and situated along one of the choose to comply with this requirement prior 3.2 of Performance Specification 2 (‘‘PS No. measurement lines used for the stratification to April 1, 2000. To identify the normal load 2’’) in appendix B to part 60 of this chapter test, may be used at any sampling location if

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the 12-point stratification test described in (e) Calculate the average NOX, SO2, and moved from traverse point to traverse point section 6.5.6.1 of this appendix is performed CO2 (or O2) concentrations at each of the either manually or automatically. If, during a and passed prior to each RATA at the individual traverse points. Then, calculate flow RATA, significant pulsations in the location (according to the acceptance criteria the arithmetic average NOX, SO2, and CO2 (or reference method readings are observed, be of section 6.5.6.3(b) of this appendix). O2) concentrations for all traverse points. sure to allow enough measurement time at 6.5.6.1 Stratification Test 6.5.6.3 Stratification Test Results and each traverse point to obtain an accurate Acceptance Criteria average reading when a manual readout (a) With the unit(s) operating under steady- method is used (e.g., a ‘‘sight-weighted’’ state conditions at normal load, as defined in (a) For each pollutant or diluent gas, the average from a manometer). A minimum of section 6.5.2.1 of this appendix, use a short reference method measurement line one set of auxiliary measurements for stack traversing gas sampling probe to measure the described in section 3.2 of PS No. 2 may be gas molecular weight determination (i.e., pollutant (SO2 or NOX) and diluent (CO2 or used in lieu of the long measurement line diluent gas data and moisture data) is O2) concentrations at a minimum of twelve prescribed in section 3.2 of PS No. 2 if the required for every clock hour of a flow RATA (12) points, located according to Method 1 in results of a stratification test, conducted in or for every three test runs (whichever is less appendix A to part 60 of this chapter. accordance with section 6.5.6.1 or 6.5.6.2 of restrictive). Successive flow RATA runs may (b) Use Methods 6C, 7E, and 3A in this appendix (as appropriate; see section be performed without waiting in-between appendix A to part 60 of this chapter to make 6.5.6(b)(3) of this appendix), show that the runs. If an O2-diluent monitor is used as a the measurements. Data from the reference concentration at each individual traverse CO2 continuous emission monitoring system, method analyzers must be quality assured by point differs by no more than ±10.0 percent perform a CO2 system RATA (i.e., measure performing analyzer calibration error and from the arithmetic average concentration for CO2, rather than O2, with the reference system bias checks before the series of all traverse points. The results are also method). For moisture monitoring systems, measurements and by conducting system bias acceptable if the concentration at each an appropriate coefficient, ‘‘K’’ factor or other and calibration drift checks after the individual traverse point differs by no more suitable mathematical algorithm may be measurements, in accordance with the than ± 5ppm or ±0.5 percent CO2 (or O2) from developed prior to the RATA, to adjust the procedures of Methods 6C, 7E, and 3A. the arithmetic average concentration for all monitoring system readings with respect to (c) Measure for a minimum of 2 minutes traverse points. the reference method. If such a coefficient, K- at each traverse point. To the extent (b) For each pollutant or diluent gas, a factor or algorithm is developed, it shall be practicable, complete the traverse within a 2- single reference method measurement point, applied to the CEMS readings during the hour period. located at least 1.0 meter from the stack wall RATA and (if the RATA is passed), to the (d) If the load has remained constant (±3.0 and situated along one of the measurement subsequent CEMS data, by means of the percent) during the traverse and if the lines used for the stratification test, may be automated data acquisition and handling reference method analyzers have passed all used for that pollutant or diluent gas if the of the required quality assurance checks, results of a stratification test, conducted in system. The owner or operator shall keep proceed with the data analysis. accordance with section 6.5.6.1 of this records of the current coefficient, K factor or algorithm, as specified in §§ 75.56(a)(5)(ix) (e) Calculate the average NOX, SO2, and appendix, show that the concentration at and 75.59(a)(5)(vii). Whenever the CO2 (or O2) concentrations at each of the each individual traverse point differs by no individual traverse points. Then, calculate more than ±5.0 percent from the arithmetic coefficient, K factor or algorithm is changed, a RATA of the moisture monitoring system the arithmetic average NOX, SO2, and CO2 (or average concentration for all traverse points. is required. O2) concentrations for all traverse points. The results are also acceptable if the (b) To properly correlate individual SO2 or 6.5.6.2 Alternative (Abbreviated) concentration at each individual traverse point differs by no more than ±3 ppm or ±0.3 NOX continuous emission monitoring system Stratification Test data (in lb/mmBtu) and volumetric flow rate percent CO2 (or O2) from the arithmetic (a) With the unit(s) operating under steady- average concentration for all traverse points. data with the reference method data, state conditions at normal load, as defined in (c) The owner or operator shall keep the annotate the beginning and end of each section 6.5.2.1 of this appendix, use a results of all stratification tests on-site, in a reference method test run (including the traversing gas sampling probe to measure the format suitable for inspection, as part of the exact time of day) on the individual chart pollutant (SO2 or NOX) and diluent (CO2 or supplementary RATA records required under recorder(s) or other permanent recording O2) concentrations at three points. The points § 75.56(a)(7) or § 75.59(a)(7), as applicable. device(s). shall be located according to the * * * * * specifications for the long measurement line 6.5.7 Sampling Strategy in section 3.2 of PS No. 2 (i.e., locate the (a) Conduct the reference method tests so 6.5.9 Number of Reference Method Tests points 16.7 percent, 50.0 percent, and 83.3 they will yield results representative of the Perform a minimum of nine sets of paired percent of the way across the stack). pollutant concentration, emission rate, monitor (or monitoring system) and reference Alternatively, the concentration moisture, temperature, and flue gas flow rate method test data for every required (i.e., measurements may be made at six traverse from the unit and can be correlated with the certification, recertification, diagnostic, points along a diameter. The six points shall pollutant concentration monitor, CO2 or O2 semiannual, or annual) relative accuracy test be located in accordance with Method 1 in monitor, flow monitor, and SO2 or NOX audit. For 2-level and 3-level relative appendix A to part 60 of this chapter. continuous emission monitoring system accuracy test audits of flow monitors, (b) Use Methods 6C, 7E, and 3A in measurements. The minimum acceptable perform a minimum of nine sets at each of appendix A to part 60 of this chapter to make time for a gas monitoring system RATA run the operating levels. the measurements. Data from the reference or for a moisture monitoring system RATA Note: The tester may choose to perform method analyzers must be quality assured by run is 21 minutes. For each run of a gas more than nine sets of reference method performing analyzer calibration error and monitoring system RATA, all necessary tests. If this option is chosen, the tester may system bias checks before the series of pollutant concentration measurements, reject a maximum of three sets of the test measurements and by conducting system bias diluent concentration measurements, and results, as long as the total number of test and calibration drift checks after the moisture measurements (if applicable) must, results used to determine the relative measurements, in accordance with the to the extent practicable, be made within a accuracy or bias is greater than or equal to procedures of Methods 6C, 7E, and 3A. 60-minute period. For NOX-diluent or SO2- nine. Report all data, including the rejected (c) Measure for a minimum of 2 minutes diluent monitoring system RATAs, the CEMS data and corresponding reference at each traverse point. To the extent pollutant and diluent concentration method test results. practicable, complete the traverse within a 1- measurements must be made simultaneously. hour period. For flow monitor RATAs, the minimum time 6.5.10 Reference Methods (d) If the load has remained constant (±3.0 per run shall be 5 minutes. Flow rate The following methods from appendix A to percent) during the traverse and if the reference method measurements may be part 60 of this chapter or their approved reference method analyzers have passed all made either sequentially from port to port or alternatives are the reference methods for of the required quality assurance checks, simultaneously at two or more sample ports. performing relative accuracy test audits: proceed with the data analysis. The velocity measurement probe may be Method 1 or 1A for siting; Method 2 or its

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00080 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28643 allowable alternatives in appendix A to part R = Reference value of zero or upscale (high- concentration monitoring systems used to 60 of this chapter (except for Methods 2B and level or mid-level, as applicable) determine NOX mass emissions, as defined in 2E) for stack gas velocity and volumetric flow calibration gas introduced into the § 75.71(a)(2); and NOX-diluent continuous rate; Methods 3, 3A, or 3B for O2 or CO2; monitoring system. emission monitoring systems, using the Method 4 for moisture; Methods 6, 6A, or 6C A = Actual monitoring system response to procedures outlined in section 7.6.1 through for SO2; Methods 7, 7A, 7C, 7D or 7E for the calibration gas. 7.6.5 of this appendix. For multiple-load flow NOX, excluding the exception in section 5.1.2 S = Span of the instrument, as specified in of Method 7E. When using Method 7E for RATAs, perform a bias test at each load level section 2 of this appendix. designated as normal under section 6.5.2.1 of measuring NOX concentration, total NOX, 7.2.2 Flow Monitor Calibration Error both NO and NO2, must be measured. this appendix. 59. Appendix A to part 75 is amended by * * * * * * * * * * revising in sections 7.2.1, and 7.2.2, the text Where: 7.6.4 Bias Test following each section’s equation, beginning CE = Calibration error as a percentage of with the word ‘‘where’’; by revising sections span. If, for the relative accuracy test audit data ¯ 7.6, 7.6.4, and 7.6.5 and by adding new R = Low or high level reference value set being tested, the mean difference, d, is sections 7.7 and 7.8 (without revising the specified in section 2.2.2.1 of this less than or equal to the absolute value of the Figures for Appendix A that appear at the appendix. confidence coefficient, | cc |, the monitor or end of section 7 to Appendix A) to read as A = Actual flow monitor response to the monitoring system has passed the bias test. follows: reference value. If the mean difference, d¯ , is greater than the 7. Calculations S = Flow monitor calibration span value as absolute value of the confidence coefficient, * * * * * determined under section 2.1.4.2 of this | cc |, the monitor or monitoring system has appendix. failed to meet the bias test requirement. 7.2.1 Pollutant Concentration and Diluent Monitors * * * * * 7.6.5 Bias Adjustment * * * * * 7.6 Bias Test and Adjustment Factor (a) If the monitor or monitoring system Where: Test the following relative accuracy test fails to meet the bias test requirement, adjust CE = Calibration error as a percentage of the audit data sets for bias: SO2 pollutant the value obtained from the monitor using span of the instrument. concentration monitors; flow monitors; NOX the following equation:

Adjusted =Monitor × CEMi CEMi BAF() Eq. A-11

Where: Equation A–12, or a default BAF of 1.111 the first clock hour following the hour in Monitor CEMi = Data (measurement) provided may be used. which the RATA was completed. For a 2-load by the monitor at time i. (c) For 2-load or 3-load flow RATAs, when flow RATA, the ‘‘hour in which the RATA Adjusted CEMi = Data value, adjusted for bias, only one load level (low, mid or high) has was completed’’ refers to the hour in which at time i. been designated as normal under section the testing at both loads was completed; for BAF = Bias adjustment factor, defined by: 6.5.2.1 of this appendix and the bias test is a 3-load RATA, it refers to the hour in which passed at the normal load level, apply a BAF the testing at all three loads was completed. of 1.000 to the subsequent flow rate data. If (f) Use the bias-adjusted values in the bias test is failed at the normal load level, computing substitution values in the missing d use Equation A–12 to calculate the normal data procedure, as specified in subpart D of BAF =1 + (.)Eq A- 12 load BAF and then perform an additional this part, and in reporting the concentration CEMavg bias test at the second most frequently-used of SO2, the flow rate, the average NOX Where: load level, as determined under section emission rate, the unit heat input, and the 6.5.2.1 of this appendix. If the bias test is calculated mass emissions of SO2 and CO2 BAF = Bias adjustment factor, calculated to passed at this second load level, apply the during the quarter and calendar year, as the nearest thousandth. normal load BAF to the subsequent flow rate specified in subpart G of this part. In d¯ = Arithmetic mean of the difference data. If the bias test is failed at this second addition, when using a NOX concentration obtained during the failed bias test using load level, use Equation A–12 to calculate the monitoring system and a flow monitor to Equation A–7. BAF at the second load level and apply the calculate NOX mass emissions under subpart CEMavg = Mean of the data values provided higher of the two BAFs (either from the H of this part, use bias-adjusted values for by the monitor during the failed bias test. normal load level or from the second load NOX concentration and flow rate in the mass (b) For single-load RATAs of SO2 pollutant level) to the subsequent flow rate data. emission calculations and use bias-adjusted concentration monitors, NOX concentration (d) For 2-load or 3-load flow RATAs, when NOX concentrations to compute the monitoring systems, and NOX-diluent two load levels have been designated as appropriate substitution values for NOX monitoring systems and for the single-load normal under section 6.5.2.1 of this appendix concentration in the missing data routines flow RATAs required or allowed under and the bias test is passed at both normal under subpart D of this part. section 6.5.2 of this appendix and sections load levels, apply a BAF of 1.000 to the * * * * * 2.3.1.3(b) and 2.3.1.3(c) of appendix B to this subsequent flow rate data. If the bias test is part, the appropriate BAF is determined failed at one of the normal load levels but not 7.7 Reference Flow-to-Load Ratio or Gross directly from the RATA results at normal at the other, use Equation A–12 to calculate Heat Rate load, using Equation A–12. Notwithstanding, the BAF for the normal load level at which (a) Except as provided in section 7.8 of this when a NOX concentration CEMS or an SO2 the bias test was failed and apply that BAF appendix, the owner or operator shall CEMS or a NOX-diluent CEMS installed on to the subsequent flow rate data. If the bias determine Rref, the reference value of the ratio a low-emitting affected unit (i.e., average SO2 test is failed at both designated normal load of flow rate to unit load, each time that a or NOX concentration during the RATA ± 250 levels, use Equation A–12 to calculate the passing flow RATA is performed at a load ppm or average NOX emission rate ± 0.200 lb/ BAF at each normal load level and apply the level designated as normal in section 6.5.2.1 mmBtu) meets the normal 10.0 percent higher of the two BAFs to the subsequent of this appendix. The owner or operator shall relative accuracy specification (as calculated flow rate data. report the current value of Rref in the using Equation A–10) or the alternate relative (e) Each time a RATA is passed and the electronic quarterly report required under accuracy specification in section 3.3 of this appropriate bias adjustment factor has been § 75.64 and shall also report the completion appendix for low-emitters, but fails the bias determined, apply the BAF prospectively to date of the associated RATA. If two load test, the BAF may either be determined using all monitoring system data, beginning with levels have been designated as normal under

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section 6.5.2.1 of this appendix, the owner or Qref = Average stack gas volumetric flow rate consisting of a main stack and a bypass stack operator shall determine a separate Rref value measured by the reference method (e.g., a unit with a wet SO2 scrubber), for each of the normal load levels. The during the normal-load RATA, scfh. determine Qref separately for each stack at the requirements of this section shall become Lavg = Average unit load during the normal- time of the normal load flow RATA. Round effective as of April 1, 2000. The reference load flow RATA, megawatts or 1000 lb/ off the value of Rref to two decimal places. flow-to-load ratio shall be calculated as hr of steam. follows: (c) In addition to determining Rref or as an (b) In Equation A–13, for a common stack, alternative to determining Rref, a reference Lavg shall be the sum of the operating loads value of the gross heat rate (GHR) may be Q ref −5 R = ×10(.)Eq A- 13 of all units that discharge through the stack. determined. In order to use this option, ref For a unit that discharges its emissions Lavg quality assured diluent gas (CO2 or O2) must through multiple stacks (except for a Where: discharge configuration consisting of a main be available for each hour of the most recent normal-load flow RATA. The reference value Rref = Reference value of the flow-to-load stack and a bypass stack), Qref will be the sum ratio, from the most recent normal-load of the total volumetric flow rates that of the GHR shall be determined as follows: flow RATA, scfh/megawatts or scfh/1000 discharge through all of the stacks. For a unit lb/hr of steam. with a multiple stack discharge configuration

()Heat Input =avg × ()GHR ref 1000(.)Eq A- 13 a Lavg

Where: systems, excepted monitoring systems moisture monitoring system polynomial

(GHR)ref = Reference value of the gross heat approved under appendix D or E to this part, coefficients, K factors or mathematical rate at the time of the most recent and alternative monitoring systems under algorithms, changing of temperature and normal-load flow RATA, Btu/kwh or subpart E of this part, and their components. pressure coefficients and dilution ratio Btu/lb steam load. At a minimum, include in each QA/QC settings), and a written explanation of the (Heat Input)avg = Average hourly heat input program a written plan that describes in procedures used to make the adjustment(s) during the normal-load flow RATA, as detail (or that refers to separate documents shall be kept. determined using the applicable containing) complete, step-by-step 1.2 Specific Requirements for Continuous equation in appendix F to this part, procedures and operations for each of the Emissions Monitoring Systems mmBtu/hr. following activities. Upon request from 1.2.1 Calibration Error Test and Linearity Lavg = Average unit load during the normal- regulatory authorities, the source shall make load flow RATA, megawatts or 1000 lb/ all procedures, maintenance records, and Check Procedures hr of steam. ancillary supporting documentation from the Keep a written record of the procedures manufacturer (e.g., software coefficients and used for daily calibration error tests and (d) In the calculation of (Heat Input)avg, use troubleshooting diagrams) available for linearity checks (e.g., how gases are to be Qref, the average volumetric flow rate review during an audit. measured by the reference method during the injected, adjustments of flow rates and RATA, and use the average diluent gas 1.1 Requirements for All Monitoring pressure, introduction of reference values, concentration measured during the flow Systems length of time for injection of calibration RATA. gases, steps for obtaining calibration error or 1.1.1 Preventive Maintenance error in linearity, determination of 7.8 Flow-to-Load Test Exemptions Keep a written record of procedures interferences, and when calibration The requirements of this section apply needed to maintain the monitoring system in adjustments should be made). Identify any beginning on April 1, 2000. For complex proper operating condition and a schedule calibration error test and linearity check stack configurations (e.g., when the effluent for those procedures. This shall, at a procedures specific to the continuous from a unit is divided and discharges through minimum, include procedures specified by emission monitoring system that vary from multiple stacks in such a manner that the the manufacturers of the equipment and, if the procedures in appendix A to this part. flow rate in the individual stacks cannot be applicable, additional or alternate procedures 1.2.2 Calibration and Linearity Adjustments correlated with unit load), the owner or developed for the equipment. operator may petition the Administrator Explain how each component of the under § 75.66 for an exemption from the 1.1.2 Recordkeeping and Reporting continuous emission monitoring system will requirements of section 7.7 of this appendix. Keep a written record describing be adjusted to provide correct responses to The petition must include sufficient procedures that will be used to implement calibration gases, reference values, and/or information and data to demonstrate that a the recordkeeping and reporting indications of interference both initially and flow-to-load or gross heat rate evaluation is requirements in subparts E, F, and G and after repairs or corrective action. Identify infeasible for the complex stack appendices D and E to this part, as equations, conversion factors and other configuration. applicable. factors affecting calibration of each continuous emission monitoring system. 1.1.3 Maintenance Records Appendix B to Part 75—Quality Assurance 1.2.3 Relative Accuracy Test Audit and Quality Control Procedures Keep a record of all testing, maintenance, Procedures or repair activities performed on any 60. Appendix B to part 75 is amended by Keep a written record of procedures and monitoring system or component in a revising sections 1 and 1.1; adding sections details peculiar to the installed continuous location and format suitable for inspection. A 1.1.1 through 1.1.3; revising section 1.2; emission monitoring systems that are to be maintenance log may be used for this adding sections 1.2.1 through 1.2.4; revising used for relative accuracy test audits, such as purpose. The following records should be section 1.3; adding sections 1.3.1 through sampling and analysis methods. 1.3.6; revising section 1.4; adding sections maintained: date, time, and description of 1.4.1 through 1.4.3; and removing sections any testing, adjustment, repair, replacement, 1.2.4 Parametric Monitoring for Units With 1.5 and 1.6 to read as follows: or preventive maintenance action performed Add-on Emission Controls on any monitoring system and records of any The owner or operator shall keep a written 1. Quality Assurance/Quality Control corrective actions associated with a monitor’s (or electronic) record including a list of Program outage period. Additionally, any adjustment operating parameters for the add-on SO2 or Develop and implement a quality that recharacterizes a system’s ability to NOX emission controls, including parameters assurance/quality control (QA/QC) program record and report emissions data must be in § 75.55(b) or § 75.58(b), as applicable, and for the continuous emission monitoring recorded (e.g., changing of flow monitor or the range of each operating parameter that

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00082 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28645 indicates the add-on emission controls are calorific value, and density, as incorporated 2.1.3 Additional Calibration Error Tests and operating properly. The owner or operator by reference under § 75.6, or other methods Calibration Adjustments shall keep a written (or electronic) record of approved by the Administrator through the (a) In addition to the daily calibration error the parametric monitoring data during each petition process of § 75.66(c). tests required under section 2.1.1 of this SOX or NO2 missing data period. 1.3.6 Appendix E Monitoring System appendix, a calibration error test of a monitor 1.3 Specific Requirements for Excepted Quality Assurance Information shall be performed in accordance with Systems Approved Under Appendices D and section 2.1.1 of this appendix, as follows: E Identify the unit manufacturer’s whenever a daily calibration error test is recommended range of quality assurance- failed; whenever a monitoring system is 1.3.1 Fuel Flowmeter Accuracy Test and quality control-related operating returned to service following repair or Procedures parameters. Keep records of these operating corrective maintenance that could affect the Keep a written record of the specific fuel parameters for each hour of unit operation monitor’s ability to accurately measure and flowmeter accuracy test procedures. These (i.e., fuel combustion). Keep a written record record emissions data; or after making certain may include: standard methods or of the procedures used to perform NOX calibration adjustments, as described in this specifications listed in and section 2.1.5.1 of emission rate testing. Keep a copy of all data section. Except in the case of the routine appendix D to this part and incorporated by and results from the initial and from the most calibration adjustments described in this reference under § 75.6; the procedures of recent NOX emission rate testing, including section, data from the monitor are considered sections 2.1.5.2 or 2.1.7 of appendix D to this the values of quality assurance parameters invalid until the required additional part; or other methods approved by the specified in section 2.3 of appendix E to this calibration error test has been successfully Administrator through the petition process of part. completed. § 75.66(c). (b) Routine calibration adjustments of a 1.4 Requirements for Alternative Systems monitor are permitted after any successful 1.3.2 Transducer or Transmitter Accuracy Approved Under Subpart E Test Procedures calibration error test. These routine 1.4.1 Daily Quality Assurance Tests adjustments shall be made so as to bring the Keep a written record of the procedures for monitor readings as close as practicable to testing the accuracy of transducers or Explain how the daily assessment the known tag values of the calibration gases transmitters of an orifice-, nozzle-, or venturi- procedures specific to the alternative or to the actual value of the flow monitor type fuel flowmeter under section 2.1.6 of monitoring system are to be performed. reference signals. An additional calibration appendix D to this part. These procedures 1.4.2 Daily Quality Assurance Test error test is required following routine should include a description of equipment Adjustments calibration adjustments where the monitor’s used, steps in testing, and frequency of calibration has been physically adjusted (e.g., Explain how each component of the testing. by turning a potentiometer) to verify that the alternative monitoring system will be 1.3.3 Fuel Flowmeter, Transducer, or adjustments have been made properly. An Transmitter Calibration and Maintenance adjusted in response to the results of the additional calibration error test is not Records daily assessments. required, however, if the routine calibration Keep a record of adjustments, 1.4.3 Relative Accuracy Test Audit adjustments are made by means of a maintenance, or repairs performed on the Procedures mathematical algorithm programmed into the fuel flowmeter monitoring system. Keep Keep a written record of procedures and data acquisition and handling system. The records of the data and results for fuel details peculiar to the installed alternative EPA recommends that routine calibration adjustments be made, at a minimum, flowmeter accuracy tests and transducer monitoring system that are to be used for whenever the daily calibration error exceeds accuracy tests, consistent with appendix D to relative accuracy test audits, such as this part. the limits of the applicable performance sampling and analysis methods. specification in appendix A to this part for 1.3.4 Primary Element Inspection 61. Appendix B to part 75 is amended by: the pollutant concentration monitor, CO2 or Procedures a. Revising the first paragraph of section O2 monitor, or flow monitor. Keep a written record of the standard 2.1.1, revising sections 2.1.3 and 2.1.4; (c) Additional (non-routine) calibration operating procedures for inspection of the revising paragraph (1) of section 2.1.5.1; adjustments of a monitor are permitted prior primary element (i.e., orifice, venturi, or revising sections 2.2 through 2.2.3; adding to (but not during) linearity checks and nozzle) of an orifice-, venturi-, or nozzle-type sections 2.2.4 through 2.2.5.3; revising RATAs and at other times, provided that an fuel flowmeter. Examples of the types of sections 2.3 and 2.3.1; adding sections 2.3.1.1 appropriate technical justification is information to be included are: what to through 2.3.1.4; revising sections 2.3.2 and included in the quality control program examine on the primary element; how to 2.3.3; and adding section 2.3.4; required under section 1 of this appendix. identify if there is corrosion sufficient to b. Redesignating existing section 2.4 as The allowable non-routine adjustments are as affect the accuracy of the primary element; section 2.5; follows. The owner or operator may and what inspection tools (e.g., baroscope), if c. Adding new section 2.4; and physically adjust the calibration of a monitor any, are used. d. Revising Figures 1 and 2 at the end of (e.g., by means of a potentiometer), provided 1.3.5 Fuel Sampling Method and Sample appendix B to read as follows: that the post-adjustment zero and upscale Retention responses of the monitor are within the 2. Frequency of Testing performance specifications of the instrument Keep a written record of the standard * * * * * given in section 3.1 of appendix A to this procedures used to perform fuel sampling, 2.1 * * * part. An additional calibration error test is either by utility personnel or by fuel supply required following such adjustments to verify company personnel. These procedures 2.1.1 Calibration Error Test that the monitor is operating within the should specify the portion of the ASTM Except as provided in section 2.1.1.2 of performance specifications at both the zero method used, as incorporated by reference this appendix, perform the daily calibration and upscale calibration levels. under § 75.6, or other methods approved by error test of each gas monitoring system 2.1.4 Data Validation the Administrator through the petition (including moisture monitoring systems process of § 75.66(c). These procedures (a) An out-of-control period occurs when consisting of wet- and dry-basis O2 analyzers) should describe safeguards for ensuring the the calibration error of an SO2 or NOX according to the procedures in section 6.3.1 availability of an oil sample (e.g., procedure pollutant concentration monitor exceeds 5.0 of appendix A to this part, and perform the and location for splitting samples, procedure percent of the span value (or exceeds 10 daily calibration error test of each flow for maintaining sample splits on site, and ppm, for span values <200 ppm), when the monitoring system according to the procedure for transmitting samples to an calibration error of a CO2 or O2 monitor procedure in section 6.3.2 of appendix A to analytical laboratory). These procedures (including O2 monitors used to measure CO2 should identify the ASTM analytical this part. emissions or percent moisture) exceeds 1.0 methods used to analyze sulfur content, gross * * * * * percent O2 or CO2, or when the calibration

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00083 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28646 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations error of a flow monitor or a moisture sensor The data validation procedures in section (d) If a daily calibration error test is failed exceeds 6.0 percent of the span value, which 2.2.3(e) of this appendix shall be followed. during a linearity test period, prior to is twice the applicable specification of 2.2.2 Leak Check completing the test, the linearity test must be appendix A to this part. Notwithstanding, a repeated. Data from the monitor are differential pressure-type flow monitor for For differential pressure flow monitors, invalidated prospectively from the hour of which the calibration error exceeds 6.0 perform a leak check of all sample lines (a the failed calibration error test until the hour percent of the span value shall not be manual check is acceptable) at least once of completion of a subsequent successful considered out-of-control if «R¥A«, the during each QA operating quarter. For this calibration error test. The linearity test shall absolute value of the difference between the test, the unit does not have to be in not be commenced until the monitor has monitor response and the reference value in operation. Conduct the leak checks no less successfully completed a calibration error Equation A–6, is ≤0.02 inches of water. The than 30 days apart, to the extent practicable. test. out-of-control period begins upon failure of If a leak check is failed, follow the applicable (e) An out-of-control period occurs when a the calibration error test and ends upon data validation procedures in section 2.2.3(f) linearity test is failed (i.e., when the error in completion of a successful calibration error of this appendix. linearity at any of the three concentrations in test. Note, that if a failed calibration, 2.2.3 Data Validation the quarterly linearity check (or any of the six corrective action, and successful calibration (a) A linearity check shall not be concentrations, when both ranges of a single error test occur within the same hour, commenced if the monitoring system is analyzer with a dual range are tested) emission data for that hour recorded by the operating out-of-control with respect to any exceeds the applicable specification in monitor after the successful calibration error of the daily or semiannual quality assurance section 3.2 of appendix A to this part) or test may be used for reporting purposes, assessments required by sections 2.1 and 2.3 when a linearity test is aborted due to a provided that two or more valid readings are of this appendix or with respect to the problem with the monitor or monitoring obtained as required by § 75.10. A NOX- additional calibration error test requirements system. For a NOX-diluent or SO2-diluent diluent continuous emission monitoring in section 2.1.3 of this appendix. continuous emission monitoring system, the system is considered out-of-control if the (b) Each required linearity check shall be system is considered out-of-control if either calibration error of either component monitor done according to paragraph (b)(1), (b)(2) or of the component monitors exceeds the exceeds twice the applicable performance (b)(3) of this section: applicable specification in section 3.2 of specification in appendix A to this part. (1) The linearity check may be done appendix A to this part or if the linearity test Emission data shall not be reported from an ‘‘cold,’’ i.e., with no corrective maintenance, of either component is aborted due to a out-of-control monitor. repair, calibration adjustments, re- problem with the monitor. The out-of-control (b) An out-of-control period also occurs linearization or reprogramming of the period begins with the hour of the failed or whenever interference of a flow monitor is monitor prior to the test. aborted linearity check and ends with the identified. The out-of-control period begins (2) The linearity check may be done after hour of completion of a satisfactory linearity with the hour of completion of the failed performing only the routine or non-routine check following corrective action and/or interference check and ends with the hour of calibration adjustments described in section monitor repair, unless the option in completion of an interference check that is 2.1.3 of this appendix at the various paragraph (b)(3) of this section to use the data passed. calibration gas levels (zero, low, mid or high), validation procedures and associated timelines in § 75.20(b)(3)(ii) through (ix) has 2.1.5 * * * but no other corrective maintenance, repair, re-linearization or reprogramming of the been selected, in which case the beginning 2.1.5.1 * * * monitor. Trial gas injection runs may be and end of the out-of-control period shall be (1) Data from a monitoring system are performed after the calibration adjustments determined in accordance with invalid, beginning with the first hour and additional adjustments within the §§ 75.20(b)(3)(vii)(A) and (B). Note that a following the expiration of a 26-hour data allowable limits in section 2.1.3 of this monitor shall not be considered out-of- validation period or beginning with the first appendix may be made prior to the linearity control when a linearity test is aborted for a hour following the expiration of an 8-hour check, as necessary, to optimize the reason unrelated to the monitor’s start-up grace period (as provided under performance of the monitor. The trial gas performance (e.g., a forced unit outage). section 2.1.5.2 of this appendix), if the injections need not be reported, provided (f) No more than four successive calendar required subsequent daily assessment has not that they meet the specification for trial gas quarters shall elapse after the quarter in been conducted. injections in § 75.20(b)(3)(vii)(E)(1). However, which a linearity check of a monitor or if, for any trial injection, the specification in monitoring system (or range of a monitor or * * * * * § 75.20(b)(3)(vii)(E)(1) is not met, the trial monitoring system) was last performed 2.2 Quarterly Assessments injection shall be counted as an aborted without a subsequent linearity test having For each primary and redundant backup linearity check. been conducted. If a linearity test has not monitor or monitoring system, perform the (3) The linearity check may be done after been completed by the end of the fourth following quarterly assessments. This repair, corrective maintenance or calendar quarter since the last linearity test, requirement is applies as of the calendar reprogramming of the monitor. In this case, then the linearity test must be completed quarter following the calendar quarter in the monitor shall be considered out-of- within a 168 unit operating hour or stack which the monitor or continuous emission control from the hour in which the repair, operating hour ‘‘grace period’’ (as provided monitoring system is provisionally certified. corrective maintenance or reprogramming is in section 2.2.4 of this appendix) following commenced until the linearity check has the end of the fourth successive elapsed 2.2.1 Linearity Check been passed. Alternatively, the data calendar quarter, or data from the CEMS (or Perform a linearity check, in accordance validation procedures and associated range) will become invalid. with the procedures in section 6.2 of timelines in §§ 75.20(b)(3)(ii) through (ix) (g) An out-of-control period also occurs appendix A to this part, for each primary and may be followed upon completion of the when a flow monitor sample line leak is redundant backup SO2 and NOX pollutant necessary repair, corrective maintenance, or detected. The out-of-control period begins concentration monitor and each primary and reprogramming. If the procedures in with the hour of the failed leak check and redundant backup CO2 or O2 monitor § 75.20(b)(3) are used, the words ‘‘quality ends with the hour of a satisfactory leak (including O2 monitors used to measure CO2 assurance’’ apply instead of the word check following corrective action. emissions or to continuously monitor ‘‘recertification’’. (h) For each monitoring system, report the moisture) at least once during each QA (c) Once a linearity check has been results of all completed and partial linearity operating quarter, as defined in § 72.2 of this commenced, the test shall be done hands-off. tests that affect data validation (i.e., all chapter. For units using both a low and high That is, no adjustments of the monitor are completed, passed linearity checks; all span value, a linearity check is required only permitted during the linearity test period, completed, failed linearity checks; and all on the range(s) used to record and report other than the routine calibration linearity checks aborted due to a problem emission data during the QA operating adjustments following daily calibration error with the monitor, including trial gas quarter. Conduct the linearity checks no less tests, as described in section 2.1.3 of this injections counted as failed test attempts than 30 days apart, to the extent practicable. appendix. under paragraph (b)(2) of this section or

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00084 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations 28647 under § 75.20(b)(3)(vii)(F)), in the quarterly operating hours, as defined in § 72.2 of this operating quarter, the results of that linearity report required under § 75.64. Note that chapter (or, for monitors installed on test or leak check may only be used to meet linearity attempts which are aborted or common stacks or bypass stacks, 168 the linearity check or leak check requirement invalidated due to problems with the consecutive stack operating hours, as defined of the previous quarter, not the quarter in reference calibration gases or due to in § 72.2 of this chapter) in which to perform which the missed linearity test or leak check operational problems with the affected a linearity test or leak check of that monitor is completed. or monitoring system (or range). The grace unit(s) need not be reported. Such partial 2.2.5 Flow-to-Load Ratio or Gross Heat Rate period begins with the first unit or stack tests do not affect the validation status of Evaluation emission data recorded by the monitor. A operating hour following the calendar quarter record of all linearity tests, trial gas injections in which the linearity test was due. Data (a) Applicability and methodology. The and test attempts (whether reported or not) validation during a linearity or leak check provisions of this section apply beginning on must be kept on-site as part of the official test grace period shall be done in accordance April 1, 2000. Unless exempted by an log for each monitoring system. with the applicable provisions in section approved petition in accordance with section 2.2.3 of this appendix. 7.8 of appendix A to this part, the owner or 2.2.4 Linearity and Leak Check Grace (b) If, at the end of the 168 unit (or stack) operator shall, for each flow rate monitoring Period operating hour grace period, the required system installed on each unit, common stack (a) When a required linearity test or flow linearity test or leak check has not been or multiple stack, evaluate the flow-to-load monitor leak check has not been completed completed, data from the monitoring system ratio quarterly, i.e., for each QA operating by the end of the QA operating quarter in (or range) shall be invalid, beginning with the quarter (as defined in § 72.2 of this chapter). which it is due or if, due to infrequent hour following the expiration of the grace At the end of each QA operating quarter, the operation of a unit or infrequent use of a period. Data from the monitoring system (or owner or operator shall use Equation B–1 to required high range of a monitor or range) remain invalid until the hour of calculate the flow-to-load ratio for every hour monitoring system, four successive calendar completion of a subsequent successful hands- during the quarter in which: the unit (or quarters have elapsed after the quarter in off linearity test or leak check of the monitor combination of units, for a common stack) which a linearity check of a monitor or or monitoring system (or range). Note that operated within ±10.0 percent of Lavg, the monitoring system (or range) was last when a linearity test or a leak check is average load during the most recent normal- performed without a subsequent linearity test conducted within a grace period for the load flow RATA; and a quality assured having been done, the owner or operator has purpose of satisfying the linearity test or leak hourly average flow rate was obtained with a grace period of 168 consecutive unit check requirement from a previous QA a certified flow rate monitor.

=Q h × −5 R h 10(.)Eq B- 1 L h

Where: unadjusted flow rates, provided that all of the (e.g., a unit with a wet SO2 scrubber), ratios are calculated the same way. For a calculate the hourly flow-to-load ratios Rh = Hourly value of the flow-to-load ratio, scfh/megawatts or scfh/1000 lb/hr of common stack, Lh shall be the sum of the separately for each stack. Round off each steam load. hourly operating loads of all units that value of Rh to two decimal places. discharge through the stack. For a unit that (2) Alternatively, the owner or operator Qh = Hourly stack gas volumetric flow rate, as measured by the flow rate monitor, discharges its emissions through multiple may calculate the hourly gross heat rates scfh. stacks (except when one of the stacks is a (GHR) in lieu of the hourly flow-to-load bypass stack) or that monitors its emissions ratios. The hourly GHR shall be determined Lh = Hourly unit load, megawatts or 1000 lb/ hr of steam; must be within ±10.0 in multiple breechings, Qh will be the only for those hours in which quality assured combined hourly volumetric flow rate for all flow rate data and diluent gas (CO2 or O2) percent of Lavg during the most recent normal-load flow RATA. of the stacks or ducts. For a unit with a concentration data are both available from a multiple stack discharge configuration certified monitor or monitoring system or (1) In Equation B–1, the owner or operator consisting of a main stack and a bypass stack, reference method. If this option is selected, may use either bias-adjusted flow rates or each of which has a certified flow monitor calculate each hourly GHR value as follows:

()Heat Input = h × ()(.)GHR h 1000Eq B- 1 a L h where: input values are determined in the same than 168 hourly flow-to-load ratios (or GHR

(GHR)h = Hourly value of the gross heat rate, manner. values) are available at any of the load levels Btu/kwh or Btu/lb steam load. (4) The owner or operator shall evaluate designated as normal, a flow-to-load (or GHR) (Heat Input)h = Hourly heat input, as the calculated hourly flow-to-load ratios (or evaluation is not required for that monitor for determined from the quality assured gross heat rates) as follows. A separate data that calendar quarter. flow rate and diluent data, using the analysis shall be performed for each primary (5) For each flow monitor, use Equation B– and each redundant backup flow rate applicable equation in appendix F to this 2 in this appendix to calculate Eh, the part, mmBtu/hr. monitor used to record and report data absolute percentage difference between each Lh = Hourly unit load, megawatts or 1000 lb/ during the quarter. Each analysis shall be hourly Rh value and Rref, the reference value ± based on a minimum of 168 recorded hourly hr of steam; must be within 10.0 of the flow-to-load ratio, as determined in percent of Lavg during the most recent average flow rates. When two RATA load normal-load flow RATA. levels are designated as normal, the analysis accordance with section 7.7 of appendix A to shall be performed at the higher load level, this part. Note that Rref shall always be based (3) In Equation B–1a, the owner or operator upon the most recent normal-load RATA, may either use bias-adjusted flow rates or unless there are fewer than 168 data points available at that load level, in which case the even if that RATA was performed in the unadjusted flow rates in the calculation of analysis shall be performed at the lower load calendar quarter being evaluated. (Heat Input)h, provided that all of the heat level. If, for a particular flow monitor, fewer

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RR− = ref h × E h 100 (Eq . B-2) R ref where: flue gases to the atmosphere through a single point data from the monitor are conditionally

Eh = Absolute percentage difference between stack, any hour in which the SO2 scrubber valid. The owner or operator then either may the hourly average flow-to-load ratio and was bypassed; complete the abbreviated flow-to-load test in the reference value of the flow-to-load (3) Any hour in which ‘‘ramping’’ section 2.2.5.3 of this appendix, or, if the ratio at normal load. occurred, i.e., the hourly load differed by corrective action taken has required ± Rh = The hourly average flow-to-load ratio, more than 15.0 percent from the load during relinearization of the flow monitor, shall for each flow rate recorded at a load level the preceding hour or the subsequent hour; perform a 3-level RATA. (4) For a unit with a multiple stack within ± 10.0 percent of Lavg. 2.2.5.2 Option 2 Rref = The reference value of the flow-to-load discharge configuration consisting of a main Perform a single-load RATA (at a load ratio from the most recent normal-load stack and a bypass stack, any hour in which designated as normal under section 6.5.2.1 of flow RATA, determined in accordance the flue gases were discharged through both appendix A to this part) of each flow monitor with section 7.7 of appendix A to this stacks; for which Ef is outside of the applicable limit. part. (5) If a normal-load flow RATA was performed and passed during the quarter Data from the monitor remain invalid until (6) Equation B–2 shall be used in a being analyzed, any hour prior to completion the required RATA has been passed. ref and Rh if consistent manner. That is, use R of that RATA; and the flow-to-load ratio is being evaluated, and 2.2.5.3 Abbreviated Flow-to-Load Test (6) If a problem with the accuracy of the use (GHR)ref and (GHR)h if the gross heat rate (a) The following abbreviated flow-to-load flow monitor was discovered during the is being evaluated. Finally, calculate Ef, the test may be performed after any documented quarter and was corrected (as evidenced by arithmetic average of all of the hourly Eh repair, component replacement, or other passing the abbreviated flow-to-load test in values. The owner or operator shall report section 2.2.5.3 of this appendix), any hour corrective maintenance to a flow monitor the results of each quarterly flow-to-load (or prior to completion of the abbreviated flow- (except for changes affecting the linearity of gross heat rate) evaluation, as determined to-load test. the flow monitor, such as adjusting the flow from Equation B–2, in the electronic (7) After identifying and excluding all non- monitor coefficients or K factor(s)) to quarterly report required under § 75.64. representative hourly data in accordance demonstrate that the repair, replacement, or (b) Acceptable results. The results of a with paragraphs (c)(1) through (6) of this other maintenance has not significantly quarterly flow-to-load (or gross heat rate) section, the owner or operator may analyze affected the monitor’s ability to accurately evaluation are acceptable, and no further the remaining data a second time. At least measure the stack gas volumetric flow rate. action is required, if the calculated value of 168 representative hourly ratios or GHR Data from the monitoring system are Ef is less than or equal to: (1) 15.0 percent, values must be available to perform the considered invalid from the hour of if Lavg for the most recent normal-load flow commencement of the repair, replacement, or ≥ ≥ analysis; otherwise, the flow-to-load (or GHR) RATA is 60 megawatts (or 500 klb/hr of analysis is not required for that monitor for maintenance until the hour in which a steam) and if unadjusted flow rates were that calendar quarter. probationary calibration error test is passed used in the calculations; or (2) 10.0 percent, following completion of the repair, (8) If, after re-analyzing the data, Ef meets if Lavg for the most recent normal-load flow replacement, or maintenance and any ≥ ≥ the applicable limit in paragraph (b)(1), RATA is 60 megawatts (or 500 klb/hr of (b)(2), (b)(3), or (b)(4) of this section, no associated adjustments to the monitor. The steam) and if bias-adjusted flow rates were abbreviated flow-to-load test shall be further action is required. If, however, Ef is used in the calculations; or (3) 20.0 percent, still above the applicable limit, the monitor completed within 168 unit operating hours of if Lavg for the most recent normal-load flow shall be declared out-of-control, beginning the probationary calibration error test (or, for RATA is <60 megawatts (or <500 klb/hr of with the first hour of the quarter following peaking units, within 30 unit operating days, steam) and if unadjusted flow rates were if that is less restrictive). Data from the the quarter in which Ef exceeded the used in the calculations; or (4) 15.0 percent, applicable limit. The owner or operator shall monitor are considered to be conditionally if Lavg for the most recent normal-load flow then either implement Option 1 in section valid (as defined in § 72.2 of this chapter), RATA is <60 megawatts (or <500 klb/hr of 2.2.5.1 of this appendix or Option 2 in beginning with the hour of the probationary steam) and if bias-adjusted flow rates were section 2.2.5.2 of this appendix. calibration error test. used in the calculations. If Ef is above these (b) Operate the unit(s) in such a way as to limits, the owner or operator shall either: 2.2.5.1 Option 1 reproduce, as closely as practicable, the exact implement Option 1 in section 2.2.5.1 of this Within two weeks of the end of the conditions at the time of the most recent appendix; or perform a RATA in accordance calendar quarter for which the Ef value is normal-load flow RATA. To achieve this, it with Option 2 in section 2.2.5.2 of this above the applicable limit, investigate and is recommended that the load be held appendix; or re-examine the hourly data used troubleshoot the applicable flow monitor(s). constant to within ±5.0 percent of the average for the flow-to-load or GHR analysis and Evaluate the results of each investigation as load during the RATA and that the diluent recalculate Ef, after excluding all non- follows: gas (CO2 or O2) concentration be maintained representative hourly flow rates. (a) If the investigation fails to uncover a within ±0.5 percent CO2 or O2 of the average (c) Recalculation of Ef. If the owner or problem with the flow monitor, a RATA shall diluent concentration during the RATA. For operator chooses to recalculate Ef, the flow be performed in accordance with Option 2 in common stacks, to the extent practicable, use rates for the following hours are considered section 2.2.5.2 of this appendix. the same combination of units and load non-representative and may be excluded (b) If a problem with the flow monitor is levels that were used during the RATA. from the data analysis: identified through the investigation When the process parameters have been set, (1) Any hour in which the type of fuel (including the need to re-linearize the record a minimum of six and a maximum of combusted was different from the fuel monitor by changing the polynomial 12 consecutive hourly average flow rates, burned during the most recent normal-load coefficients or K factor(s)), corrective actions using the flow monitor(s) for which Ef was RATA. For purposes of this determination, shall be taken. All corrective actions (e.g., outside the applicable limit. For peaking the type of fuel is different if the fuel is in non-routine maintenance, repairs, major units, a minimum of three and a maximum a different state of matter (i.e., solid, liquid, component replacements, re-linearization of of 12 consecutive hourly average flow rates or gas) than is the fuel burned during the the monitor, etc.) shall be documented in the are required. Also record the corresponding RATA or if the fuel is a different operation and maintenance records for the hourly load values and, if applicable, the classification of coal (e.g., bituminous versus monitor. Data from the monitor shall remain hourly diluent gas concentrations. Calculate sub-bituminous); invalid until a probationary calibration error the flow-to-load ratio (or GHR) for each hour (2) For a unit that is equipped with an SO2 test of the monitor is passed following in the test hour period, using Equation B–1 scrubber and which always discharges its completion of all corrective actions, at which or B–1a. Determine Eh for each hourly flow-

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Perform monitoring system mean value from the load test shall be considered acceptable, and RATA, calculated using Equation A–7 in no further action is required if the value of all required RATAs in accordance with appendix A to this part, is within ± 0.025 lb/ Ef does not exceed the applicable limit the applicable procedures and mmBtu of the reference method mean value; specified in section 2.2.5 of this appendix. provisions in sections 6.5 through (h) For a CO2 or O2 monitor, when the All conditionally valid data recorded by the 6.5.2.2 of appendix A to this part and mean difference between the reference flow monitor shall be considered quality sections 2.3.1.3 and 2.3.1.4 of this method values from the RATA and the ± assured, beginning with the hour of the appendix. corresponding monitor values is within 0.7 probationary calibration error test that percent CO2 or O2; and preceded the abbreviated flow-to-load test. 2.3.1.2 Reduced RATA Frequencies (i) When the relative accuracy of a ≤ However, if Ef is outside the applicable limit, Relative accuracy test audits of primary continuous moisture monitoring system is all conditionally valid data recorded by the and redundant backup SO2 pollutant 7.5 percent or when the mean difference flow monitor shall be considered invalid concentration monitors, CO2 pollutant between the reference method values from back to the hour of the probationary concentration monitors (including O2 the RATA and the corresponding monitoring ± calibration error test that preceded the monitors used to determine CO2 emissions), system values is within 1.0 percent H2O. abbreviated flow-to-load test, and a single- CO2 or O2 diluent monitors used to 2.3.1.3 RATA Load Levels and load RATA is required in accordance with determine heat input, moisture monitoring Additional RATA Requirements section 2.2.5.2 of this appendix. If the flow systems, NOX concentration monitoring monitor must be re-linearized, however, a 3- systems, flow monitors, NOX-diluent (a) For SO2 pollutant concentration load RATA is required. monitoring systems or SO2-diluent monitors, CO2 pollutant concentration 2.3 Semiannual and Annual Assessments monitoring systems may be performed monitors (including O2 monitors used to annually (i.e., once every four successive QA determine CO2 emissions), CO2 or O2 diluent For each primary and redundant backup operating quarters, rather than once every monitors used to determine heat input, NOX monitoring system, perform relative accuracy two successive QA operating quarters) if any concentration monitoring systems, moisture assessments either semiannually or annually, of the following conditions are met for the monitoring systems, SO2-diluent monitoring as specified in section 2.3.1.1 or 2.3.1.2 of specific monitoring system involved: systems and NOX-diluent monitoring this appendix, for the type of test and the (a) The relative accuracy during the audit systems, the required semiannual or annual performance achieved. This requirement of an SO2 or CO2 pollutant concentration RATA tests shall be done at the load level applies as of the calendar quarter following monitor (including an O2 pollutant monitor designated as normal under section 6.5.2.1 of the calendar quarter in which the monitoring used to measure CO2 using the procedures in appendix A to this part. If two load levels are system is provisionally certified. A summary appendix F to this part), or of a CO2 or O2 designated as normal, the required RATA(s) chart showing the frequency with which a diluent monitor used to determine heat may be done at either load level. relative accuracy test audit must be input, or of a NOX concentration monitoring (b) For flow monitors installed on peaking performed, depending on the accuracy system, or of a NOX-diluent monitoring units and bypass stacks, all required achieved, is located at the end of this system, or of an SO2-diluent continuous semiannual or annual relative accuracy test appendix in Figure 2. emissions monitoring system is ≤ 7.5 percent; audits shall be single-load audits at the 2.3.1 Relative Accuracy Test Audit (RATA) (b) Prior to January 1, 2000, the relative normal load, as defined in section 6.5.2.1 of accuracy during the audit of a flow monitor appendix A to this part. 2.3.1.1 Standard RATA Frequencies is ≤ 10.0 percent at each operating level (c) For all other flow monitors, the RATAs (a) Except as otherwise specified in tested; shall be performed as follows: § 75.21(a)(6) or (a)(7) or in section 2.3.1.2 of (c) On and after January 1, 2000, the (1) An annual 2-load flow RATA shall be this appendix, perform relative accuracy test relative accuracy during the audit of a flow done at the two most frequently used load audits semiannually, i.e., once every two monitor is ≤ 7.5 percent at each operating levels, as determined under section 6.5.2.1 of successive QA operating quarters (as defined level tested; appendix A to this part. (2) If the flow monitor is on a semiannual in § 72.2 of this chapter) for each primary and (d) For low flow (≤ 10.0 fps) stacks/ducts, RATA frequency, 2-load flow RATAs and redundant backup SO2 pollutant when the flow monitor fails to achieve a single-load flow RATAs at normal load may concentration monitor, flow monitor, CO2 relative accuracy ≤ 7.5 percent (10.0 percent be performed alternately. pollutant concentration monitor (including if prior to January 1, 2000) during the audit, (3) A single-load annual flow RATA, at the O2 monitors used to determine CO2 but the monitor mean value, calculated using most frequently used load level, may be emissions), CO2 or O2 diluent monitor used Equation A–7 in appendix A to this part and to determine heat input, moisture monitoring performed in lieu of the 2-load RATA if the converted back to an equivalent velocity in results of an historical load data analysis system, NOX concentration monitoring ± standard feet per second (fps), is within 1.5 show that in the time period extending from system, NOX-diluent continuous emission fps of the reference method mean value, the ending date of the last annual flow RATA monitoring system, or SO2-diluent converted to an equivalent velocity in fps; to a date that is no more than 7 days prior continuous emission monitoring system. A (e) For low SO2 or NOX emitting units to the date of the current annual flow RATA, ≤ calendar quarter that does not qualify as a (average SO2 or NOX concentrations 250 the unit has operated at a single load level QA operating quarter shall be excluded in ppm, when an SO2 pollutant concentration (low, mid or high) for ≥ 85.0 percent of the determining the deadline for the next RATA. monitor or NOX concentration monitoring time. * * * ≤ No more than eight successive calendar system fails to achieve a relative accuracy (4) A 3-load RATA, at the low-, mid-, and quarters shall elapse after the quarter in 7.5 percent during the audit, but the monitor high-load levels, determined under section which a RATA was last performed without mean value from the RATA is within ± 12 6.5.2.1 of appendix A to this part, shall be a subsequent RATA having been conducted. ppm of the reference method mean value; performed at least once in every period of If a RATA has not been completed by the end (f) For units with low NOX emission rates five consecutive calendar years. of the eighth calendar quarter since the (average NOX emission rate ≤ 0.200 lb/ (5) A 3-load RATA is required whenever a quarter of the last RATA, then the RATA mmBtu), when a NOX-diluent continuous flow monitor is re-linearized, i.e., when its must be completed within a 720 unit (or emission monitoring system fails to achieve polynomial coefficients or K factor(s) are stack) operating hour grace period (as a relative accuracy ≤ 7.5 percent, but the changed. provided in section 2.3.3 of this appendix) monitoring system mean value from the (6) For all multi-level flow audits, the audit following the end of the eighth successive RATA, calculated using Equation A–7 in points at adjacent load levels (e.g., mid and elapsed calendar quarter, or data from the appendix A to this part, is within ± 0.015 lb/ high) shall be separated by no less than 25.0 CEMS will become invalid. mmBtu of the reference method mean value; percent of the ‘‘range of operation,’’ as (b) The relative accuracy test audit (g) For units with low SO2 emission rates defined in section 6.5.2.1 of appendix A to frequency of a CEMS may be reduced, (average SO2 emission rate ≤ 0.500 lb/ this part.

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(d) A RATA of a moisture monitoring flow monitor audits, no linearization or CO2 emissions) which also serves as the system shall be performed whenever the reprogramming of the monitor is permitted in diluent component in a NOX-diluent (or SO2- coefficient, K factor or mathematical between load levels. diluent) monitoring system, if the CO2 (or O2) algorithm determined under section 6.5.7 of (d) For single-load RATAs, if a daily RATA is failed, then both the CO2 (or O2) appendix A to this part is changed. calibration error test is failed during a RATA monitor and the associated NOX-diluent (or 2.3.1.4 Number of RATA Attempts test period, prior to completing the test, the SO2-diluent) system are considered out-of- RATA must be repeated. Data from the control, beginning with the hour of The owner or operator may perform as monitor are invalidated prospectively from completion of the failed CO2 (or O2) monitor many RATA attempts as are necessary to the hour of the failed calibration error test RATA, and continuing until the hour of achieve the desired relative accuracy test until the hour of completion of a subsequent completion of subsequent hands-off RATAs audit frequencies and/or bias adjustment successful calibration error test. The which demonstrate that both systems have factors. However, the data validation subsequent RATA shall not be commenced met the applicable relative accuracy procedures in section 2.3.2 of this appendix until the monitor has successfully passed a specifications in sections 3.3.2 and 3.3.3 of must be followed. calibration error test in accordance with appendix A to this part, unless the option in 2.3.2 Data Validation section 2.1.3 of this appendix. For multiple- paragraph (b)(3) of this section to use the data (a) A RATA shall not commence if the load flow RATAs, each load level is treated validation procedures and associated monitoring system is operating out-of-control as a separate RATA (i.e., when a calibration timelines in §§ 75.20(b)(3)(ii) through with respect to any of the daily and quarterly error test is failed prior to completing the (b)(3)(ix) has been selected, in which case the quality assurance assessments required by RATA at a particular load level, only the beginning and end of the out-of-control sections 2.1 and 2.2 of this appendix or with RATA at that load level must be repeated; the period shall be determined in accordance respect to the additional calibration error test results of any previously-passed RATA(s) at with §§ 75.20(b)(3)(vii) (A) and (B). requirements in section 2.1.3 of this the other load level(s) are unaffected, unless (h) For each monitoring system, report the appendix. re-linearization of the monitor is required to results of all completed and partial RATAs (b) Each required RATA shall be done correct the problem that caused the that affect data validation (i.e., all completed, according to paragraphs (b)(1), (b)(2) or (b)(3) calibration failure, in which case a passed RATAs; all completed, failed RATAs; of this section: subsequent 3-load RATA is required). and all RATAs aborted due to a problem with (1) The RATA may be done ‘‘cold,’’ i.e., (e) If a RATA is failed (that is, if the the CEMS, including trial RATA runs with no corrective maintenance, repair, relative accuracy exceeds the applicable counted as failed test attempts under calibration adjustments, re-linearization or specification in section 3.3 of appendix A to paragraph (b)(2) of this section or under reprogramming of the monitoring system this part) or if the RATA is aborted prior to § 75.20(b)(3)(vii)(F)) in the quarterly report prior to the test. completion due to a problem with the CEMS, required under § 75.64. Note that RATA (2) The RATA may be done after then the CEMS is out-of-control and all attempts that are aborted or invalidated due performing only the routine or non-routine emission data from the CEMS are invalidated to problems with the reference method or calibration adjustments described in section prospectively from the hour in which the due to operational problems with the affected 2.1.3 of this appendix at the zero and/or RATA is failed or aborted. Data from the unit(s) need not be reported. Such runs do upscale calibration gas levels, but no other CEMS remain invalid until the hour of not affect the validation status of emission corrective maintenance, repair, re- completion of a subsequent RATA that meets data recorded by the CEMS. However, a linearization or reprogramming of the the applicable specification in section 3.3 of record of all RATAs, trial RATA runs and monitoring system. Trial RATA runs may be appendix A to this part, unless the option in RATA attempts (whether reported or not) performed after the calibration adjustments paragraph (b)(3) of this section to use the data must be kept on-site as part of the official test and additional adjustments within the validation procedures and associated log for each monitoring system. allowable limits in section 2.1.3 of this timelines in §§ 75.20(b)(3)(ii) through (i) Each time that a hands-off RATA of an appendix may be made prior to the RATA, (b)(3)(ix) has been selected, in which case the SO2 pollutant concentration monitor, a NOX- as necessary, to optimize the performance of beginning and end of the out-of-control diluent monitoring system, a NOX the CEMS. The trial RATA runs need not be period shall be determined in accordance concentration monitoring system or a flow reported, provided that they meet the with § 75.20(b)(3)(vii)(A) and (B). Note that a monitor is passed, perform a bias test in specification for trial RATA runs in monitoring system shall not be considered accordance with section 7.6.4 of appendix A § 75.20(b)(3)(vii)(E)(2). However, if, for any out-of-control when a RATA is aborted for a to this part. Apply the appropriate bias trial run, the specification in reason other than monitoring system adjustment factor to the reported SO2, NOX, § 75.20(b)(3)(vii)(E)(2) is not met, the trial run malfunction (see paragraph (h) of this or flow rate data, in accordance with section shall be counted as an aborted RATA section). 7.6.5 of appendix A to this part. attempt. (f) For a 2-level or 3-level flow RATA, if, (j) Failure of the bias test does not result (3) The RATA may be done after repair, at any load level, a RATA is failed or aborted in the monitoring system being out-of- corrective maintenance, re-linearization or due to a problem with the flow monitor, the control. reprogramming of the monitoring system. In RATA at that load level must be repeated. 2.3.3 RATA Grace Period this case, the monitoring system shall be The flow monitor is considered out-of- (a) The owner or operator has a grace considered out-of-control from the hour in control and data from the monitor are period of 720 consecutive unit operating which the repair, corrective maintenance, re- invalidated from the hour in which the test hours, as defined in § 72.2 of this chapter (or, linearization or reprogramming is is failed or aborted and remain invalid until for CEMS installed on common stacks or commenced until the RATA has been passed. the passing of a RATA at the failed load bypass stacks, 720 consecutive stack Alternatively, the data validation procedures level, unless the option in paragraph (b)(3) of operating hours, as defined in § 72.2 of this and associated timelines in §§ 75.20(b)(3)(ii) this section to use the data validation chapter), in which to complete the required through (ix) may be followed upon procedures and associated timelines in RATA for a particular CEMS whenever: a completion of the necessary repair, corrective § 75.20(b)(3)(ii) through (b)(3)(ix) has been required RATA has not been performed by maintenance, re-linearization or selected, in which case the beginning and the end of the QA operating quarter in which reprogramming. If the procedures in end of the out-of-control period shall be it is due; or five consecutive calendar years § 75.20(b)(3) are used, the words ‘‘quality determined in accordance with have elapsed without a required 3-load flow assurance’’ apply instead of the word § 75.20(b)(3)(vii)(A) and (B). Flow RATA(s) RATA having been conducted; or for a unit ‘‘recertification.’’ that were previously passed at the other load which is conditionally exempted under (c) Once a RATA is commenced, the test level(s) do not have to be repeated unless the § 75.21(a)(7) from the SO2 RATA must be done hands-off. No adjustment of the flow monitor must be re-linearized following requirements of this part, an SO2 RATA has monitor’s calibration is permitted during the the failed or aborted test. If the flow monitor not been completed by the end of the RATA test period, other than the routine is re-linearized, a subsequent 3-load RATA is calendar quarter in which the annual usage calibration adjustments following daily required. of fuel(s) with a sulfur content higher than calibration error tests, as described in section (g) For a CO2 pollutant concentration very low sulfur fuel(as defined in § 72.2 of 2.1.3 of this appendix. For 2-level and 3-level monitor (or an O2 monitor used to measure this chapter) exceeds 480 hours; or eight

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When a quality operation of the unit(s) or frequent assurance test is done for the dual purpose combustion of very low sulfur fuel, as Except as otherwise specified in section of recertification and routine quality 7.6.5 of appendix A to this part, if an SO2 defined in § 72.2 of this chapter (SO2 assurance, the applicable data validation pollutant concentration monitor, flow monitors, only), or a combination of these procedures in § 75.20(b)(3) shall be followed. monitor, NOX continuous emission factors. (b) Except as provided in section 2.3.3 of monitoring system, or NOX concentration (b) Except for SO2 monitoring system this appendix, whenever a passing RATA of RATAs, the grace period shall begin with the monitoring system used to calculate NOX a gas monitor or a passing 2-load or 3-load first unit (or stack) operating hour following mass emissions fails the bias test specified in RATA of a flow monitor is performed the calendar quarter in which the required section 7.6 of appendix A to this part, use the (irrespective of whether the RATA is done to RATA was due. For SO2 monitor RATAs, the bias adjustment factor given in Equations A– grace period shall begin with the first unit (or 11 and A–12 of appendix A to this part to satisfy a recertification requirement or to stack) operating hour in which fuel with a adjust the monitored data. meet the quality assurance requirements of this appendix, or both), the RATA frequency total sulfur content higher than that of very 2.4 Recertification, Quality Assurance, low sulfur fuel (as defined in § 72.2 of this (semi-annual or annual) shall be established RATA Frequency and Bias Adjustment based upon the date and time of completion chapter) is burned in the unit(s), following Factors (Special Considerations) the quarter in which the required RATA is of the RATA and the relative accuracy due. Data validation during a RATA grace (a) When a significant change is made to percentage obtained. For 2-load and 3-load period shall be done in accordance with the a monitoring system such that recertification flow RATAs, use the highest percentage applicable provisions in section 2.3.2 of this of the monitoring system is required in relative accuracy at any of the loads to appendix. accordance with § 75.20(b), a recertification determine the RATA frequency. The results (c) If, at the end of the 720 unit (or stack) test (or tests) must be performed to ensure of a single-load flow RATA may be used to operating hour grace period, the RATA has that the CEMS continues to generate valid establish the RATA frequency when the not been completed, data from the data. In all recertifications, a RATA will be single-load flow RATA is specifically monitoring system shall be invalid, one of the required tests; for some required under section 2.3.1.3(b) of this beginning with the first unit operating hour recertifications, other tests will also be appendix (for flow monitors installed on following the expiration of the grace period. required. A recertification test may be used peaking units and bypass stacks) or when the Data from the CEMS remain invalid until the to satisfy the quality assurance test single-load RATA is allowed under section hour of completion of a subsequent hands-off requirement of this appendix. For example, 2.3.1.3(c) of this appendix for a unit that has RATA. Note that when a RATA (or RATAs, if, for a particular change made to a CEMS, operated at the most frequently used load if more than one attempt is made) is done one of the required recertification tests is a level for ≥85.0 percent of the time since the during a grace period in order to satisfy a linearity check and the linearity check is last annual flow RATA. No other single-load RATA requirement from a previous quarter, successful, then, unless another such flow RATA may be used to establish an the deadline for the next RATA shall be recertification event occurs in that same QA annual RATA frequency; however, a 2-load determined from the quarter in which the operating quarter, it would not be necessary or 3-load flow RATA may be performed at RATA was due, not from the quarter in to perform an additional linearity test of the any time or in place of any required single- which the RATA is actually completed. CEMS in that quarter to meet the quality load RATA, in order to establish an annual However, if a RATA deadline determined in assurance requirement of section 2.2.1 of this RATA frequency. this manner is less than two QA operating appendix. For this reason, EPA recommends quarters from the quarter in which the that owners or operators coordinate 2.5 Other Audits missed RATA is completed , the RATA component replacements, system upgrades, * * * * *

FIGURE 1 TO APPENDIX B OF PART 75ÐQuality 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.) ...... 1 RATA (SO2, NOX, CO2, H2O) ...... RATA (flow)1,2 ...... -For monitors on bypass stack/duct, ``daily'' means bypass operating days, only. ``Quarterly'' means once every QA operating quarter. ``Semi- annual'' 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 test- ing. 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 flow monitor is re-linearized.

FIGURE 2 TO APPENDIX B OF PART 75ÐRELATIVE ACCURACY TEST FREQUENCY INCENTIVE SYSTEM .

RATA Semiannual 1 (percent) Annual 1

3 2 2 SO2 or NOX ...... 7.5%

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FIGURE 2 TO APPENDIX B OF PART 75ÐRELATIVE ACCURACY TEST FREQUENCY INCENTIVE SYSTEM .ÐContinued

RATA Semiannual 1 (percent) Annual 1

lb/mmBtu 2 ...... lb/mmBtu 2. Flow (Phase I) ...... 10.0% < RA ≤ 15.0% or ± 1.5 fps 2 ...... RA ≤ 10.0%. Flow (Phase II) ...... 7.5% < RA ≤ 10.0% or ± 1.5 fps 2 ...... RA ≤ 7.5%. 2 2 CO2 or O2 ...... 7.5% < RA ≤ 10.0% or ± 1.0% CO2/O2 ...... RA ≤ 7.5% or ± 0.7% CO2/O2 . 2 Moisture ...... 7.5% < RA ≤ 10.0% or ± 1.5% H2O2 ...... RA ≤ 7.5% or ± 1.0% H2O . 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 by- pass 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 § 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 per- formed. 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 § 75.71.

Appendix C To Part 75—Missing Data TABLE C±1.ÐDEFINITION OF OPER- 2.2.3.9 Average of the hourly NOX Statistical Estimation Procedures ATING LOAD RANGES FOR LOAD- pollutant concentrations, in ppm, reported by a NOX concentration monitoring system used 62.–63. Appendix C to part 75 is amended BASED UBSTITUTION ATA ROCE S D P - to determine NOX mass emissions, as defined by revising sections 2.1, 2.2.1, 2.2.2, 2.2.3, DURES in § 75.71(a)(2). and 2.2.5, and by revising section 2.2.3.9 to read as follows: * * * * * Percent of 2.2.5 When a bias adjustment is necessary maximum 2. Load-Based Procedure for Missing Flow for the flow monitor and/or the NOX-diluent hourly gross continuous emission monitoring system Rate and NOX Emission Rate Data load or max- Operating load range (and/or the NOX concentration monitoring 2.1 Applicability imum hourly gross steam system used to determine NOX mass This procedure is applicable for data from load (per- emissions, as defined in § 75.71(a)(2)), apply all affected units for use in accordance with cent) the adjustment factor to all monitor or the provisions of this part to provide continuous emission monitoring system data values placed in the load ranges. substitute data for volumetric flow rate (scfh), 1 ...... 0±10 2 ...... >10±20 NOX emission rate (in lb/mmBtu) from NOX- * * * * * 3 ...... >20±30 diluent continuous emission monitoring 4 ...... >30±40 Appendix D To Part 75—Optional SO2 systems, and NOX concentration data (in 5 ...... >40±50 Emissions Data Protocol for Gas-Fired and ppm) from NOx concentration monitoring 6 ...... >50±60 Oil-Fired Units systems used to determine NOX mass 7 ...... >60±70 64. Appendix D to part 75 is amended by emissions. 8 ...... >70±80 revising section 1.1 to read as follows: 2.2 * * * 9 ...... >80±90 1. Applicability 2.2.1 For a single unit, establish ten 10 ...... >90 operating load ranges defined in terms of 1.1 This protocol may be used in lieu of percent of the maximum hourly average gross 2.2.2 Beginning with the first hour of unit continuous SO2 pollutant concentration and flow monitors for the purpose of determining load of the unit, in gross megawatts (MWge), operation after installation and certification hourly SO2 mass emissions and heat input of the flow monitor or the NOX-diluent as shown in Table C–1. (Do not use from: gas-fired units, as defined in § 72.2 of continuous emission monitoring system (or a integrated hourly gross load in MW-hr.) For this chapter, or oil-fired units, as defined in NOX concentration monitoring system used units sharing a common stack monitored § 72.2 of this chapter. Section 2.1 of this to determine NOX mass emissions, as defined with a single flow monitor, the load ranges appendix provides procedures for measuring in § 75.71(a)(2)), for each hour of unit for flow (but not for NOX) may be broken oil or gaseous fuel flow using a fuel operation record a number, 1 through 10, (or down into 20 operating load ranges in flowmeter, section 2.2 of this appendix 1 through 20 for flow at common stacks) that provides procedures for conducting oil increments of 5.0 percent of the combined identifies the operating load range maximum hourly average gross load of all sampling and analysis to determine sulfur corresponding to the integrated hourly gross content and gross calorific value (GCV) of units utilizing the common stack. If this load of the unit(s) recorded for each unit fuel oil, and section 2.3 of this appendix option is selected, the twentieth (uppermost) operating hour. provides procedures for determining the operating load range shall include all values 2.2.3 Beginning with the first hour of unit sulfur content and GCV of gaseous fuels. operation after installation and certification greater than 95.0 percent of the maximum * * * * * of the flow monitor or the NOX-diluent hourly average gross load. For a cogenerating 65. Appendix D to part 75 is further continuous emission monitoring system (or a unit or other unit at which some portion of amended by: NOX concentration monitoring system used the heat input is not used to produce a. Revising sections 2.1 and 2.1.1; to determine NOX mass emissions, as defined electricity or for a unit for which hourly b. Addding sections 2.1.1.1 through 2.1.1.3; in § 75.71(a)(2)) and continuing thereafter, average gross load in MWge is not recorded c. Revising sections 2.1.2 through 2.1.4; the data acquisition and handling system d. Adding sections 2.1.4.1 through 2.1.4.3; separately, use the hourly gross steam load of must be capable of calculating and recording e. Revising sections 2.1.5 through 2.1.5.2; the unit, in pounds of steam per hour at the the following information for each unit ° f. Adding sections 2.1.5.3 through 2.1.5.4; measured temperature ( F) and pressure operating hour of missing flow or NOX data (psia) instead of MWge. Indicate a change in g. Revising sections 2.1.6 through 2.1.6.2; within each identified load range during the h. Adding sections 2.1.6.3 through 2.1.7.5; the number of load ranges or the units of shorter of: (a) the previous 2,160 quality i. Revising sections 2.2 and 2.2.1; loads to be used in the precertification assured monitor operating hours (on a rolling j. Removing sections 2.2.1.1 and 2.2.1.2; section of the monitoring plan. basis), or (b) all previous quality assured k. Removing and reserving section 2.2.2; monitor operating hours. l. Revising sections 2.2.3 and 2.2.4; * * * * * m. Adding sections 2.2.4.1 through 2.2.4.3;

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n. Revising the first sentence of section 2.1.2.1 Measure the fuel flow rate in the subsidiaries or affiliates of the same 2.2.6; common pipe, and combine SO2 mass company; o. Revising sections 2.2.8 and 2.3 through emissions for the affected units for (b) The designated representative reports 2.3.2.1; recordkeeping and compliance purposes; or hourly records of gas or oil flow rate, heat p. Adding sections 2.3.2.1.1 and 2.3.2.1.2; 2.1.2.2 Provide information satisfactory to input rate, and emissions due to combustion q. Revising section 2.3.2.2; the Administrator on methods for of natural gas or oil; r. Adding sections 2.3.2.3 through 2.3.6; apportioning SO2 mass emissions and heat (c) The designated representative also s. Revising section 2.4.1; input to each of the affected units reports hourly records of heat input rate for t. Removing section 2.4.2, and demonstrating that the method ensures each unit, if the gas or oil flowmeter is on redesignating sections 2.4.3, 2.4.3.1, 2.4.3.2, complete and accurate accounting of the a common pipe header, consistent with 2.4.3.3 and 2.4.4 as sections 2.4.2, 2.4.2.1, actual emissions from each of the affected section 2.1.2 of this appendix; 2.4.2.2, 2.4.2.3 and 2.4.3, respectively; and units included in the apportionment and all (d) The designated representative reports u. Revising newly redesignated sections emissions regulated under this part. The hourly records directly from the gas or oil 2.4.2, 2.4.2.1, and 2.4.2.3 to read as follows: information shall be provided to the flowmeter used for commercial billing if 2. Procedure Administrator through a petition submitted these records are the values used, without by the designated representative under adjustment, for commercial billing, or reports 2.1 Fuel Flowmeter Measurements § 75.66. Satisfactory information includes: hourly records using the missing data For each hour when the unit is combusting the proposed apportionment, using fuel flow procedures of section 2.4 of this appendix if fuel, measure and record the flow rate of fuel measurements; the ratio of hourly integrated these records are not the values used, combusted by the unit, except as provided in gross load (in MWe-hr) in each unit to the without adjustment, for commercial billing; section 2.1.4 of this appendix. Measure the total load for all units receiving fuel from the and flow rate of fuel with an in-line fuel common pipe header, or the ratio of hourly (e) The designated representative identifies flowmeter, and automatically record the data steam flow (in 1000 lb) at each unit to the the gas or oil flowmeter in the unit’s with a data acquisition and handling system, total steam flow for all units receiving fuel monitoring plan. except as provided in section 2.1.4 of this from the common pipe header (see section 2.1.4.3 Emergency Fuel appendix. 3.4.3 of this appendix); and documentation The designated representative of a unit that 2.1.1 Measure the flow rate of each fuel that shows the provisions of sections 2.1.5 is restricted by its Federal, State or local entering and being combusted by the unit. If, and 2.1.6 of this appendix have been met for permit to combusting a particular fuel only on an annual basis, more than 5.0 percent of the fuel flowmeter used in the during emergencies where the primary fuel is the fuel from the main pipe is diverted from apportionment. not available is exempt from certifying a fuel the unit without being burned and that 2.1.3 For a gas-fired unit or an oil-fired diversion occurs downstream of the fuel flowmeter for use during combustion of the unit that continuously or frequently emergency fuel. During any hour in which flowmeter, an additional in-line fuel combusts a supplemental fuel for flame flowmeter is required to account for the the emergency fuel is combusted, report the stabilization or safety purposes, measure the hourly heat input to be the maximum rated unburned fuel. In this case, record the flow flow rate of the supplemental fuel with a fuel rate of each fuel combusted by the unit as the heat input of the unit for the fuel. flowmeter meeting the requirements of this Additionally, begin sampling the emergency difference between the flow measured in the appendix. pipe leading to the unit and the flow in the fuel for sulfur content only using the pipe diverting fuel away from the unit. 2.1.4 Situations in Which Certified procedures under section 2.2 (for oil) or 2.3 However, the additional fuel flowmeter is not Flowmeter is Not Required (for gas) of this appendix. The designated representative shall also provide notice required if, on an annual basis, the total 2.1.4.1 Start-up or Ignition Fuel amount of fuel diverted away from the unit, under § 75.61(a)(6)(ii) for each period when expressed as a percentage of the total annual For an oil-fired unit that uses gas solely for the emergency fuel is combusted. fuel usage by the unit is demonstrated to be start-up or burner ignition or a gas-fired unit 2.1.5 Initial Certification Requirement for less than or equal to 5.0 percent. The owner that uses oil solely for start-up or burner all Fuel Flowmeters or operator may make this demonstration in ignition, a flowmeter for the start-up fuel is the following manner: not required. Estimate the volume of oil For the purposes of initial certification, 2.1.1.1 For existing units with fuel usage combusted for each start-up or ignition either each fuel flowmeter used to meet the data from fuel flowmeters, if data are by using a fuel flowmeter or by using the requirements of this protocol shall meet a submitted from a previous year dimensions of the storage container and flowmeter accuracy of 2.0 percent of the demonstrating that the total diverted yearly measuring the depth of the fuel in the storage upper range value (i.e. maximum calibrated fuel does not exceed 5% of the total fuel container before and after each start-up or fuel flow rate) across the range of fuel flow used; or ignition. A fuel flowmeter used solely for rate to be measured at the unit. Flowmeter 2.1.1.2 For new units which do not have start-up or ignition fuel is not subject to the accuracy may be determined under section historical data, if a letter is submitted signed calibration requirements of sections 2.1.5 and 2.1.5.1 of this appendix for initial by the designated representative certifying 2.1.6 of this appendix. Gas combusted solely certification in any of the following ways (as that, in the future, the diverted fuel will not for start-up or burner ignition does not need applicable): by design or by measurement exceed 5.0% of the total annual fuel usage ; to be measured separately. under laboratory conditions; by the or manufacturer; by an independent laboratory; 2.1.4.2 Gas or Oil Flowmeter Used for 2.1.1.3 By using a method approved by or by the owner or operator. Flowmeter Commercial Billing the Administrator under § 75.66(d). accuracy may also be determined under 2.1.2 Install and use fuel flowmeters A gas or oil flowmeter used for commercial section 2.1.5.2 of this appendix by meeting the requirements of this appendix in billing of natural gas or oil may be used to measurement against a NIST traceable a pipe going to each unit, or install and use measure, record, and report hourly fuel flow reference method. a fuel flowmeter in a common pipe header rate. A gas or oil flowmeter used for 2.1.5.1 Use the procedures in the (i.e., a pipe carrying fuel for multiple units). commercial billing of natural gas or oil is not following standards to verify flowmeter However, the use of a fuel flowmeter in a required to meet the certification accuracy or design, as appropriate to the type common pipe header and the provisions of requirements of section 2.1.5 of this of flowmeter: ASME MFC–3M–1989 with sections 2.1.2.1 and 2.1.2.2 of this appendix appendix or the quality assurance September 1990 Errata (‘‘Measurement of are not applicable to any unit that is using requirements of section 2.1.6 of this Fluid Flow in Pipes Using Orifice, Nozzle, the provisions of subpart H of this part to appendix under the following circumstances: and Venturi’’); ASME MFC–4M–1986 monitor, record, and report NOX mass (a) The gas or oil flowmeter is used for (Reaffirmed 1990), ‘‘Measurement of Gas emissions under a state or federal NOX mass commercial billing under a contract, Flow by Turbine Meters;’’ American Gas emission reduction program. For all other provided that the company providing the gas Association Report No. 3, ‘‘Orifice Metering units, if the fuel flowmeter is installed in a or oil under the contract and each unit of Natural Gas and Other Related common pipe header, do one of the combusting the gas or oil do not have any Hydrocarbon Fluids Part 1: General following: common owners and are not owned by Equations and Uncertainty Guidelines’’

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(October 1990 Edition), Part 2: ‘‘Specification 2.1.5.2 (a) Alternatively, determine the A=Average of the three measurements of the and Installation Requirements’’ (February flowmeter accuracy of a fuel flowmeter used flowmeter being tested. 1991 Edition), and Part 3: ‘‘Natural Gas for the purposes of this part by comparing it URV=Upper range value of fuel flowmeter Applications’’ (August 1992 edition) to the measured flow from a reference being tested (i.e. maximum measurable (excluding the modified flow-calculation flowmeter which has been either designed flow). method in part 3); Section 8, Calibration from according to the specifications of American (c) Notwithstanding the requirement for American Gas Association Transmission Gas Association Report No. 3 or ASME MFC– calibration of the reference flowmeter within Measurement Committee Report No. 7: 3M–1989, as cited in section 2.1.5.1 of this 365 days prior to an accuracy test, when an Measurement of Gas by Turbine Meters appendix, or tested for accuracy during the in-place reference meter or prover is used for (Second Revision, April, 1996); ASME MFC– previous 365 days, using a standard listed in quality assurance under section 2.1.6 of this 5M–1985 (‘‘Measurement of Liquid Flow in section 2.1.5.1 of this appendix or other appendix, the reference meter calibration Closed Conduits Using Transit-Time procedure approved by the Administrator requirement may be waived if, during the Ultrasonic Flowmeters’’); ASME MFC–6M– under § 75.66 (all standards incorporated by previous in-place accuracy test with that 1987 with June 1987 Errata (‘‘Measurement of reference under § 75.6). Any secondary reference meter, the reference flowmeter and Fluid Flow in Pipes Using Vortex Flow the flowmeter being tested agreed to within elements, such as pressure and temperature Meters’’); ASME MFC–7M–1987 (Reaffirmed ±1.0 percent of each other at all levels tested. transmitters, must be calibrated immediately 1992), ‘‘Measurement of Gas Flow by Means This exception to calibration and flowmeter prior to the comparison. Perform the of Critical Flow Venturi Nozzles;’’ ISO 8316: accuracy testing requirements for the 1987(E) ‘‘Measurement of Liquid Flow in comparison over a period of no more than reference flowmeter shall apply for periods of Closed Conduits—Method by Collection of seven consecutive unit operating days. no longer than five consecutive years (i.e., 20 the Liquid in a Volumetric Tank;’’ American Compare the average of three fuel flow rate consecutive calendar quarters). Petroleum Institute (API) Section 2, readings over 20 minutes or longer for each 2.1.5.3 If the flowmeter accuracy exceeds ‘‘Conventional Pipe Provers’’, Section 3, meter at each of three different flow rate the specification in section 2.1.5 of this ‘‘Small Volume Provers’’, and Section 5, levels. The three flow rate levels shall appendix, the flowmeter does not qualify for ‘‘Master-Meter Provers’’, from Chapter 4 of correspond to: use for this appendix. Either recalibrate the the Manual of Petroleum Measurement (1) Normal full unit operating load, flowmeter until the flowmeter accuracy is Standards, October 1988 (Reaffirmed 1993); (2) Normal minimum unit operating load, within the performance specification, or or ASME MFC–9M–1988 with December (3) A load point approximately equally replace the flowmeter with another one that 1989 Errata (‘‘Measurement of Liquid Flow in spaced between the full and minimum unit is demonstrated to meet the performance Closed Conduits by Weighing Method’’), for operating loads, and specification. Substitute for fuel flow rate all other flowmeter types (incorporated by (4) Calculate the flowmeter accuracy at using the missing data procedures in section reference under § 75.6). The Administrator each of the three flow levels using the 2.4.2 of this appendix until quality assured may also approve other procedures that use following equation: fuel flow data become available. equipment traceable to National Institute of 2.1.5.4 For purposes of initial Standards and Technology standards. RA− certification, when a flowmeter is tested Document such procedures, the equipment ACC = ×100 (Eq . D-1) against a reference fuel flow rate (i.e., fuel used, and the accuracy of the procedures in URV flow rate from another fuel flowmeter under the monitoring plan for the unit, and submit Where: section 2.1.5.2 of this appendix or flow rate a petition signed by the designated ACC=Flowmeter accuracy at a particular load from a procedure performed according to a representative under § 75.66(c). If the level, as a percentage of the upper range standard incorporated by reference under flowmeter accuracy exceeds 2.0 percent of value. section 2.1.5.1 of this appendix), report the the upper range value, the flowmeter does R=Average of the three flow measurements of results of flowmeter accuracy tests using the not qualify for use under this part. the reference flowmeter. following Table D–1.

TABLE D±1.ÐTABLE OF FLOWMETER ACCURACY RESULTS

Test number:llll Test completion date 1:llllllllll Test completion time 1:llllll Reinstallation date 2 (for testing under 2.1.5.1 only):llllllllll Reinstallation time 2:llllll 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 reading (percent of reading URV)

Low (Minimum) level ...... 1 ...... ll percent 3 of URV ...... 2 ...... 3 ...... Average ...... Mid-level ...... 1 ...... ll percent 3 of URV ...... 2 ...... 3 ...... Average ...... High (Maximum) level ...... 1 ...... ll 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.

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2.1.6 Quality Assurance transmitter accuracy test and primary (c) If each transmitter or transducer meets ± (a) Test the accuracy of each fuel flowmeter element inspection, where applicable. an accuracy of 1.0 percent of its full-scale prior to use under this part and at least once 2.1.6.1 Transmitter or Transducer Accuracy range at each level tested, the fuel flowmeter every four fuel flowmeter QA operating Test for Orifice-, Nozzle-, and Venturi-Type accuracy of 2.0 percent is considered to be quarters, as defined in § 72.2 of this chapter, Flowmeters met at all levels. If, however, one or more of thereafter. Notwithstanding these (a) Calibrate the differential pressure the transmitters or transducers does not meet ± requirements, no more than 20 successive transmitter or transducer, static pressure an accuracy of 1.0 percent of full-scale at calendar quarters shall elapse after the transmitter or transducer, and temperature a particular level, then the owner or operator quarter in which a fuel flowmeter was last transmitter or transducer, as applicable, may demonstrate that the fuel flowmeter tested for accuracy without a subsequent using equipment that has a current certificate meets the total accuracy specification of 2.0 flowmeter accuracy test having been of traceability to NIST standards. Check the percent at that level by using one of the conducted. Test the flowmeter accuracy more calibration of each transmitter or transducer following alternative methods. If, at a frequently if required by manufacturer by comparing its readings to that of the NIST specifications. particular level, the sum of the individual traceable equipment at least once at each of accuracies of the three transducers is less (b) Except for orifice-, nozzle-, and venturi- the following levels: the zero-level and at type flowmeters, perform the required least two other levels (e.g., ‘‘mid’’ and than or equal to 4.0 percent, the fuel flowmeter accuracy testing using the ‘‘high’’), such that the full range of flowmeter accuracy specification of 2.0 procedures in either section 2.1.5.1 or section transmitter or transducer readings percent is considered to be met for that level. 2.1.5.2 of this appendix. Each fuel flowmeter corresponding to normal unit operation is Or, if at a particular level, the total fuel must meet the accuracy specification in represented. flowmeter accuracy is 2.0 percent or less, section 2.1.5 of this appendix. (b) Calculate the accuracy of each when calculated in accordance with Part 1 of (c) For orifice-, nozzle-, and venturi-type transmitter or transducer at each level tested, American Gas Association Report No. 3, flowmeters, either perform the required using the following equation: General Equations and Uncertainty flowmeter accuracy testing using the Guidelines, the flowmeter accuracy procedures in section 2.1.5.1 or 2.1.5.2 of this RT− requirement is considered to be met for that appendix or perform a transmitter accuracy ACC = ×100(Eq . D- 1 a) level. test once every four fuel flowmeter QA FS 2.1.6.2 Recordkeeping and Reporting of operating quarters and a primary element Where: visual inspection once every 12 calendar Transmitter or Transducer Accuracy Results ACC = Accuracy of the transmitter or quarters, according to the procedures in transducer as a percentage of full-scale. (a) Record the accuracy of the orifice, sections 2.1.6.1 through 2.1.6.4 of this nozzle, or venturi meter or its individual appendix for periodic quality assurance. R = Reading of the NIST traceable reference value (in milliamperes, inches of water, transmitters or transducers and keep this (d) Notwithstanding the requirements of information in a file at the site or other this section, if the procedures of section 2.1.7 psi, or degrees). location suitable for inspection. When testing (fuel flow-to-load test) of this appendix are T = Reading of the transmitter or transducer performed during each fuel flowmeter QA being tested (in milliamperes, inches of individual orifice, nozzle, or venturi meter operating quarter, subsequent to a required water, psi, or degrees, consistent with transmitters or transducers for accuracy, flowmeter accuracy test or transmitter the units of measure of the NIST include the information displayed in the accuracy test and primary element traceable reference value). following Table D–2. At a minimum, record inspection, where applicable, those FS = Full-scale range of the transmitter or results for each transmitter or transducer at procedures may be used to meet the transducer being tested (in milliamperes, the zero-level and at least two other levels requirement for periodic quality assurance inches of water, psi, or degrees, across the range of the transmitter or testing for a period of up to 20 calendar consistent with the units of measure of transducer readings that correspond to quarters from the previous accuracy test or the NIST traceable reference value). normal unit operation.

TABLE D±2.ÐTABLE OF FLOWMETER TRANSMITTER OR TRANSDUCER ACCURACY RESULTS

Test number:llll Test completion date: llllllllll Unit or pipe ID: llllll Flowmeter serial number: Component/System ID: Full-scale value: Units of measure: 3 Transducer/Transmitter Type (check one): ll Differential Pressure ll Static Pressure ll Temperature

Expected Run number Transmitter/ transmitter/ Actual Percent ac- Measurement level (percent of full-scale) (if multiple Run time transducer transducer transmitter/ curacy (per- 2 (HHMM) input (pre- transducer cent of full- runs) output (ref- 3 calibration) erence) output scale)

Low (Minimum) level ll percent 1 of full-scale ...... Mid-level ll percent1 of full-scale ...... (If tested at more than 3 levels) 2nd Mid-level ll percent 1 of full-scale ...... (If tested at more than 3 levels) 3rd Mid-level ll percent 1 of full-scale ...... High (Maximum) level ll 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 cor- responding 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 (°), inches of water (in H2O), pounds per square inch (psi), or milliamperes (ma) for both transmitter or transducer readings and reference readings).

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(b) When accuracy testing of the orifice, Report No. 3 or ASME MFC–3M–1989, as subsequent fuel flowmeter QA operating nozzle, or venturi meter is performed cited in section 2.1.5.1 of this appendix (both quarter, as defined in § 72.2 of this chapter according to section 2.1.5.2 of this appendix, standards incorporated by reference under (excluding the quarter(s) in which the record the information displayed in Table D– § 75.6); baseline data are collected), then these 1 in this section. At a minimum, record the (2) Replace the primary element with procedures may be used to meet the overall flowmeter accuracy results for the another primary element, and demonstrate requirement for periodic quality assurance fuel flowmeter at the three flow rate levels that the overall flowmeter accuracy meets the for a period of up to 20 calendar quarters specified in section 2.1.5.2 of this appendix. accuracy specification in section 2.1.5 of this from the previous periodic quality assurance (c) Report the results of all fuel flowmeter appendix under the procedures of section procedure(s) performed according to sections accuracy tests, transmitter or transducer 2.1.5.2 of this appendix; or 2.1.5.1, 2.1.5.2, or 2.1.6.1 through 2.1.6.4 of accuracy tests, and primary element (3) Restore the damaged or corroded this appendix. The procedures of this section inspections, as applicable, in the emissions primary element to ‘‘as new’’ condition; are not required for any quarter in which a report for the quarter in which the quality determine the overall accuracy of the flowmeter accuracy test or a transmitter assurance tests are performed, using the flowmeter, using either the specifications of accuracy test and a primary element electronic format specified by the American Gas Association Report No. 3 or Administrator under § 75.64. ASME MFC–3M–1989, as cited in section inspection, where applicable, are conducted. 2.1.5.1 of this appendix (both standards Notwithstanding the requirements of 2.1.6.3 Failure of Transducer(s) or § 75.54(a) or § 75.57(a), as applicable, when Transmitter(s) incorporated by reference under § 75.6); and retest the transmitters or transducers prior to using the procedures of this section, keep If, during a transmitter or transducer providing quality assured data from the records of the test data and results from the accuracy test conducted according to section flowmeter. previous flowmeter accuracy test under 2.1.6.1 of this appendix, the flowmeter (b) If the primary element size is changed, section 2.1.5.1 or 2.1.5.2 of this appendix, accuracy specification of 2.0 percent is not calibrate the transmitter or transducers records of the test data and results from the met at any of the levels tested, repair or consistent with the new primary element previous transmitter or transducer accuracy replace transmitter(s) or transducer(s) as size. Data from the fuel flowmeter are test under section 2.1.6.1 of this appendix for necessary until the flowmeter accuracy considered invalid, beginning with the date orifice-, nozzle-, and venturi-type fuel specification has been achieved at all levels. and hour of a failed visual inspection and flowmeters, and records of the previous (Note that only transmitters or transducers continuing until the date and hour when: visual inspection of the primary element which are repaired or replaced need to be re- (1) The damaged or corroded primary required under section 2.1.6.4 of this tested; however, the re-testing is required at element is replaced with another primary all three measurement levels, to ensure that appendix for orifice-, nozzle-, and venturi- element meeting the requirements of type fuel flowmeters until the next flowmeter the flowmeter accuracy specification is met American Gas Association Report No. 3 or at each level). The fuel flowmeter is ‘‘out-of- accuracy test, transmitter accuracy test, or ASME MFC–3M–1989, as cited in section visual inspection is performed, even if the control’’ and data from the flowmeter are 2.1.5.1 of this appendix (both standards considered invalid, beginning with the date previous flowmeter accuracy test, transmitter incorporated by reference under § 75.6); accuracy test, or visual inspection was and hour of the failed accuracy test and (2) The damaged or corroded primary performed more than three years previously. continuing until the date and hour of element is replaced, and the overall accuracy completion of a successful transmitter or of the flowmeter is demonstrated to meet the 2.1.7.1 Baseline Flow Rate-to-Load Ratio or transducer accuracy test at all levels. In accuracy specification in section 2.1.5 of this Heat Input-to-Load Ratio addition, if, during normal operation of the appendix under the procedures of section (a) Determine Rbase, the baseline value of fuel flowmeter, one or more transmitters or 2.1.5.2 of this appendix; or the ratio of fuel flow rate to unit load, transducers malfunction, data from the fuel (3) The restored primary element is flowmeter shall be considered invalid from following each successful periodic quality installed to meet the requirements of assurance procedure performed according to the hour of the transmitter or transducer American Gas Association Report No. 3 or failure until the hour of completion of a sections 2.1.5.1, 2.1.5.2, or 2.1.6.1 and 2.1.6.4 ASME MFC–3M–1989, as cited in section successful 3-level transmitter or transducer of this appendix. Establish a baseline period 2.1.5.1 of this appendix (both standards accuracy test. During fuel flowmeter out-of- of data consisting, at a minimum, of 168 incorporated by reference under § 75.6) and control periods, provide data from another hours of quality assured fuel flowmeter data. its transmitters or transducers are retested to fuel flowmeter that meets the requirements of Baseline data collection shall begin with the meet the accuracy specification in section § 75.20(d) and section 2.1.5 of this appendix, first hour of fuel flowmeter operation 2.1.6.1 of this appendix. or substitute for fuel flow rate using the following completion of the most recent (c) During this period, provide data from missing data procedures in section 2.4.2 of quality assurance procedure(s), during which another fuel flowmeter that meets the this appendix. Record and report test data only the fuel measured by the fuel flowmeter requirements of § 75.20(d) and section 2.1.5 and results, consistent with sections 2.1.6.1 of this appendix, or substitute for fuel flow is combusted (i.e., only gas, only residual oil, and 2.1.6.2 of this appendix and § 75.56 or rate using the missing data procedures in or only diesel fuel is combusted by the unit). § 75.59, as applicable. section 2.4.2 of this appendix. During the baseline data collection period, 2.1.6.4 Primary Element Inspection 2.1.7 Fuel Flow-to-Load Quality the owner or operator may exclude as non- (a) Conduct a visual inspection of the Assurance Testing for Certified Fuel representative any hour in which the unit is orifice, nozzle, or venturi meter at least once Flowmeters ‘‘ramping’’ up or down, (i.e., the load during every twelve calendar quarters. The procedures of this section may be used the hour differs by more than 15.0 percent Notwithstanding this requirement, the as an optional supplement to the quality from the load in the previous or subsequent procedures of section 2.1.7 of this appendix assurance procedures in section 2.1.5.1, hour) and may exclude any hour in which may be used to reduce the inspection 2.1.5.2, 2.1.6.1, or 2.1.6.4 of this appendix the unit load is in the lower 25.0 percent of frequency of the orifice, nozzle, or venturi when conducting periodic quality assurance the range of operation, as defined in section meter to at least once every twenty calendar testing of a certified fuel flowmeter. Note, 6.5.2.1 of appendix A to this part (unless quarters. The inspection may be performed however, that these procedures may not be operation in this lower 25.0 percent of the using a baroscope. If the visual inspection used unless the 168-hour baseline data range is considered normal for the unit). The indicates that the orifice, nozzle, or venturi requirement of section 2.1.7.1 of this baseline data must be obtained no later than meter has become damaged or corroded, appendix has been met. If, following a the end of the fourth calendar quarter then: flowmeter accuracy test or flowmeter following the calendar quarter of the most (1) Replace the primary element with transmitter test and primary element recent quality assurance procedure for that another primary element meeting the inspection, where applicable, the procedures fuel flowmeter. For orifice-, nozzle-, and requirements of American Gas Association of this section are performed during each venturi-type fuel flowmeters, if the fuel flow-

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to-load ratio is to be used as a supplement Lavg = Average unit load during the baseline = Q base both to the transmitter accuracy test under R base (Eq . D-1b) period, megawatts or 1000 lb/hr of section 2.1.6.1 of this appendix and to Lavg steam. primary element inspections under section where: (b) In Equation D–1b, for a common pipe 2.1.6.4 of this appendix, then the baseline header, Lavg is the sum of the operating loads Rbase = Value of the fuel flow rate-to-load data must be obtained after both procedures of all units that receive fuel through the ratio during the baseline period; 100 common pipe header. For a unit that receives are completed and no later than the end of scfh/MWe or 100 scfh/klb per hour its fuel through multiple pipes, Qbase is the the fourth calendar quarter following the steam load for gas-firing; (lb/hr)/MWe or calendar quarter of both the most recent sum of the fuel flow rates for a particular fuel (lb/hr)/klb per hour steam load for oil- (i.e., gas, diesel fuel, or residual oil) from transmitter or transducer test and the most firing. each of the pipes. Round off the value of Rbase recent primary element inspection for that Qbase = Average fuel flow rate measured by to the nearest tenth. fuel flowmeter. From these 168 (or more) the fuel flowmeter during the baseline (c) Alternatively, a baseline value of the hours of baseline data, calculate the baseline period, 100 scfh for gas-firing and lb/hr gross heat rate (GHR) may be determined in fuel flow rate-to-load ratio as follows: for oil-firing. lieu of Rbase. The baseline value of the GHR, GHRbase, shall be determined as follows:

(Heat Input) =avg × ()GHR base 1000 (.Eq D-1c) Lavg

Where: 2.1.7.2 Data Preparation and Analysis Qh = Hourly fuel flow rate, as measured by

(GHR)base = Baseline value of the gross heat (a) Evaluate the fuel flow rate-to-load ratio the fuel flowmeter, 100 scfh for gas-firing rate during the baseline period, Btu/kwh (or GHR) for each fuel flowmeter QA or lb/hr for oil-firing. or Btu/lb steam load. operating quarter, as defined in § 72.2 of this Lh = Hourly unit load, megawatts or 1000 (Heat Input)avg = Average (mean) hourly heat chapter. At the end of each fuel flowmeter lb/hr of steam. QA operating quarter, use Equation D–1d in input rate recorded by the fuel flowmeter (b) For a common pipe header, Lh shall be during the baseline period, as this appendix to calculate Rh, the hourly fuel the sum of the hourly operating loads of all determined using the applicable flow-to-load ratio, for every quality assured hourly average fuel flow rate obtained with units that receive fuel through the common equation in appendix F to this part, a certified fuel flowmeter. pipe header. For a unit that receives its fuel mmBtu/hr. through multiple pipes, Qh will be the sum Lavg = Average (mean) unit load during the Q of the fuel flow rates for a particular fuel (i.e., baseline period, megawatts or 1000 lb/hr = h R h (Eq . D-1d) gas, diesel fuel, or residual oil) from each of of steam. L h the pipes. Round off each value of Rh to the (d) Report the current value of Rbase (or where: nearest tenth. GHRbase) and the completion date of the Rh = Hourly value of the fuel flow rate-to- (c) Alternatively, calculate the hourly gross associated quality assurance procedure in load ratio; 100 scfh/MWe, (lb/hr)/MWe, heat rates (GHR) in lieu of the hourly flow- each electronic quarterly report required 100 scfh/1000 lb/hr of steam load, or to-load ratios. If this option is selected, under § 75.64. (lb/hr)/1000 lb/hr of steam load. calculate each hourly GHR value as follows:

=(Heat Input)h × ()GHR h 1000 (.Eq D-1e) L h

Where: RR− q %D = base h × = h (GHR)h = Hourly value of the gross heat rate, %(.)Dh 100Eq D- 1 f E f ∑ (Eq . D-1 g ) Btu/kwh or Btu/lb steam load. R base h=1 q (Heat Input)h = Hourly heat input rate, as Where: Where: determined using the applicable Ef = Quarterly average percentage difference %Dh = Absolute value of the percentage equation in appendix F to this part, between hourly flow rate-to-load ratios mmBtu/hr. difference between the hourly fuel flow rate-to-load ratio and the baseline value and the baseline value of the fuel flow Lh = Hourly unit load, megawatts or 1000 of the fuel flow rate-to-load ratio (or rate-to-load ratio (or hourly and baseline lb/hr of steam. hourly and baseline GHR). GHR). %Dh = Percentage difference between the (d) Evaluate the calculated flow rate-to- Rh = The hourly fuel flow rate-to-load ratio load ratios (or gross heat rates) as follows. (or GHR). hourly fuel flow rate-to-load ratio and the baseline value of the fuel flow rate- Perform a separate data analysis for each fuel Rbase = The value of the fuel flow rate-to-load to-load ratio (or hourly and baseline flowmeter following the procedures of this ratio (or GHR) from the baseline period, section. Base each analysis on a minimum of GHR). determined in accordance with section q = Number of hours used in fuel flow-to- 168 hours of data. If, for a particular fuel 2.1.7.1 of this appendix. load (or GHR) evaluation. flowmeter, fewer than 168 hourly flow-to- (f) Consistently use Rbase and Rh in load ratios (or GHR values) are available, a (h) When the quarterly average load value Equation D–1f if the fuel flow-to-load ratio is used in the data analysis is greater than 50 flow-to-load (or GHR) evaluation is not being evaluated, and consistently use MWe (or 500 klb steam per hour), the results required for that flowmeter for that calendar (GHR)base and (GHR)h in Equation D–1f if the of a quarterly fuel flow rate-to-load (or GHR) quarter. gross heat rate is being evaluated. evaluation are acceptable and no further (e) For each hourly flow-to-load ratio or (g) Next, determine the arithmetic average action is required if the quarterly average GHR value, calculate the percentage of all of the hourly percent difference percentage difference (Ef) is no greater than difference (percent Dh) from the baseline fuel 10.0 percent. When the arithmetic average of (percent Dh) values using Equation D–1g, as flow-to-load ratio using Equation D–1f. the hourly load values used in the data follows: analysis is ≤50 MWe (or 500 klb steam per hour), the results of the analysis are

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acceptable if the value of Ef is no greater than 2.1.7.4 Consequences of Failed Fuel Flow- this appendix, beginning with the first hour 15.0 percent. to-Load Ratio Test of the calendar quarter following the quarter 2.1.7.3 Optional Data Exclusions (a) If Ef is outside the applicable limit in for which Ef was found to be outside the section 2.1.7.2 of this appendix (after applicable limit and continuing until quality (a) If Ef is outside the limits in section analysis using any optional data exclusions assured fuel flow data become available. 2.1.7.2 of this appendix, the owner or under section 2.1.7.3 of this appendix), Following a failed flow rate-to-load or GHR operator may re-examine the hourly fuel flow perform transmitter accuracy tests according evaluation, data from the flowmeter shall not rate-to-load ratios (or GHRs) that were used to section 2.1.6.1 of this appendix for orifice- be considered quality assured until the hour for the data analysis and identify and exclude , nozzle-, and venturi-type flowmeters, or in which all required flowmeter accuracy fuel flow-to-load ratios or GHR values for any perform a fuel flowmeter accuracy test, in tests, transmitter accuracy tests, visual non-representative fuel flow-to-load ratios or accordance with section 2.1.5.1 or 2.1.5.2 of inspections and diagnostic tests have been GHR values. Specifically, the Rh or (GHR)h this appendix, for each fuel flowmeter for passed. Additionally, a new value of Rbase or values for the following hours may be which Ef is outside of the applicable limit. In (GHR)base shall be established no later than addition, for an orifice-, nozzle-, or venturi- considered non-representative: any hour in two flowmeter QA operating quarters after type fuel flowmeter, repeat the fuel flow-to- which the unit combusted another fuel in the quarter in which the required quality addition to the fuel measured by the fuel load ratio comparison of section 2.1.7.2 of this appendix using six to twelve hours of assurance tests are completed (note that for flowmeter being tested; or any hour for orifice-, nozzle-, or venturi-type fuel which the load differed by more than ±15.0 data following a passed transmitter accuracy flowmeters, establish a new value of Rbase or percent from the load during either the test in order to verify that no significant (GHR)base only if both a transmitter accuracy preceding hour or the subsequent hour; or corrosion has affected the primary element. If, for the abbreviated 6-to-12 hour test, the test and a primary element inspection have any hour for which the unit load was in the orifice-, nozzle-, or venturi-type fuel been performed). lower 25.0 percent of the range of operation, flowmeter is not able to meet the limit in 2.1.7.5 Test Results as defined in section 6.5.2.1 of appendix A section 2.1.7.2 of this appendix, then perform to this part (unless operation in the lower a visual inspection of the primary element Report the results of each quarterly flow 25.0 percent of the range is considered according to section 2.1.6.4 of this appendix, rate-to-load (or GHR) evaluation, as normal for the unit). and repair or replace the primary element, as determined from Equation D–1g, in the (b) After identifying and excluding all non- necessary. electronic quarterly report required under representative hourly fuel flow-to-load ratios (b) Substitute for fuel flow rate, for any § 75.64. Table D–3 is provided as a reference or GHR values, analyze the quarterly fuel hour when that fuel is combusted, using the on the type of information to be recorded flow rate-to-load data a second time. missing data procedures in section 2.4.2 of under § 75.59 and reported under § 75.64.

TABLE D±3.ÐBASELINE INFORMATION AND TEST RESULTS FOR FUEL FLOW-TO-LOAD TEST

Plant name:llllllllllState:lllORIS code:llllllllll Unit/pipe ID #:llllllFuel flowmeter component and system ID #s:llll-llllCalendar quarter (1st, 2nd, 3rd, 4th) and year:llllll Range of operation:llllll to llllll MWe or klb steam/hr (indicate units) Time period Baseline period Quarter

Completion date and time of most recent primary element inspection (orifice-, nozzle-, and ven- Number of hours excluded from quarterly aver- turi-type flowmeters only). age due to co-firing different fuels:llll hrs. ll/ll/ll ll:ll Completion date and time of the most recent flowmeter or transmitter accuracy test ...... Number of hours excluded from quarterly aver- age due to ramping load: llll hrs. ll/ll/ll ll:ll Beginning date and time of baseline period ...... Number of hours in the lower 25.0 percent of the range of operation excluded from quar- terly average: llll hrs. ll/ll/ll ll:ll End date and time of baseline period ...... Number of hours included in quarterly average: llll hrs. ll/ll/ll ll:ll Average fuel flow ratellllllllll (100 scfh for gas and lb/hr for oil) ...... Quarterly percentage difference between hour- ly ratios and baseline ratio: llll per- cent. Average load;llllllllll (MWe or 1000 lb steam/hr) ...... Test result: pass, fail. Baseline fuel flow-to-load ratiollllllllll Units of fuel flow-to-load:llllllllll Baseline GHR: llllllllll Units of fuel flow-to-load:llllllllll Number of hours excluded from baseline ratio or GHR due to ramping load:llll Number of hours in the lower 25.0 percent of the range of operation excluded from baseline ra- tion or GHR: llll hrs.

2.2 Oil Sampling and Analysis gross calorific value (GCV) of the oil; and, if rate and heat input rate for each fuel using Perform sampling and analysis of oil to necessary, the density of the oil. Use the the applicable procedures of section 3 of this determine the following fuel properties for sulfur content, density, and gross calorific appendix. The designated representative may each type of oil combusted by a unit: value, determined under the provisions of petition for reduced GCV and or density percentage of sulfur by weight in the oil; this section, to calculate SO2 mass emission sampling under § 75.66 if the fuel combusted

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TABLE D±4.ÐOIL 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 composite ...... Actual measured value. In storage tank (after addition of fuel to tank) 1. Actual measured value; or 2. Highest of all sampled values in previous calendar year; or 3. Maximum value allowed by contract.1 As delivered (in delivery truck or barge).1 ...... 1. Highest of all sampled values in 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 composite ...... Actual measured value. In storage tank (after addition of fuel to tank) 1. Actual measured value; or 2. Highest of all sampled values in previous calendar year; or 3. Maximum value allowed by contract.1 As delivered (in delivery truck or barge).1 ...... 1. Highest of all sampled values in 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 composite ...... Actual measured value. In storage tank (after addition of fuel to tank) 1. Actual measured value; or 2. Highest of all sampled values in previous calendar year; or 3. Maximum value allowed by contract.1 As delivered (in delivery truck or barge).1 ...... 1. Highest of all sampled values in 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 hrs). Use the actual sulfur content (and where (incorporated by reference under § 75.6). Use following methods to sample the oil (see density data are required, the actual density) the sulfur content (and where required, the Table D–4): sample from the storage tank for from the composite sample to calculate the density) of either the most recent sample or the unit after each addition of oil to the hourly SO2 mass emission rates for each one of the conservative assumed values storage tank, in accordance with section operating day represented by the composite described in section 2.2.4.3 of this appendix 2.2.4.2 of this appendix; or sample from the sample. Calculate the hourly heat input rates to calculate SO2 mass emission rate. fuel lot in the shipment tank or container for each operating day represented by the Calculate heat input rate using the gross upon receipt of each oil delivery or from the composite sample, using the actual gross calorific value from either: fuel lot in the oil supplier’s storage container, calorific value from the composite sample. (a) The most recent oil sample taken or in accordance with section 2.2.4.3 of this 2.2.4 Manual Sampling (b) One of the conservative assumed values appendix; or use the flow proportional described in section 2.2.4.3 of this appendix. 2.2.4.1 Daily Samples sampling methodology in section 2.2.3 of this 2.2.4.3 Sampling From Each Delivery appendix; or use the daily manual sampling Representative oil samples may be taken methodology in section 2.2.4.1 of this from the storage tank or fuel flow line (a) Alternatively, an oil sample may be appendix. For purposes of this appendix, a manually every day that the unit combusts taken from— fuel lot of oil is the mass or volume of oil according to ASTM D4057–88, ‘‘Standard (1) The shipment tank or container upon product oil from one source (supplier or Practice for Manual Sampling of Petroleum receipt of each lot of fuel oil or pretreatment facility), intended as one and Petroleum Products’’ (incorporated by (2) The supplier’s storage container which shipment or delivery (e.g., ship load, barge reference under § 75.6). Use either the actual holds the lot of fuel oil. (Note: a supplier load, group of trucks, discrete purchase of daily sulfur content or the highest fuel sulfur need only sample the storage container once diesel fuel through pipeline, etc.). A storage content recorded at that unit from the most for sulfur content, GCV and, where required, tank is a container at a plant holding oil that recent 30 daily samples for the purpose of the density so long as the fuel sulfur content and GCV do not change and no fuel is added is actually combusted by the unit, such that calculating SO2 emissions under section 3 of no blending of any other fuel with the fuel this appendix. Use either the gross calorific to the supplier’s storage container.) in the storage tank occurs from the time that value measured from that day’s sample or the (b) For the purpose of this section, a lot is the fuel lot is transferred to the storage tank highest GCV from the previous 30 days’ defined as a shipment or delivery (e.g., ship to the time when the fuel is combusted in the samples to calculate heat input. If oil load, barge load, group of trucks, discrete unit. supplies with different sulfur contents are purchase of diesel fuel through a pipeline, 2.2.2 [Reserved] combusted on the same day, sample the etc.) of a single fuel. highest sulfur fuel combusted that day. (c) Oil sampling may be performed either 2.2.3 Flow Proportional Sampling by the owner or operator of an affected unit, Conduct flow proportional oil sampling or 2.2.4.2 Sampling From a Unit’s Storage an outside laboratory, or a fuel supplier, continuous drip oil sampling in accordance Tank provided that samples are representative and with ASTM D4177–82 (Reapproved 1990), Take a manual sample after each addition that sampling is performed according to ‘‘Standard Practice for Automatic Sampling of oil to the storage tank. Do not blend either the single tank composite sampling of Petroleum and Petroleum Products’’ additional fuel with the sampled fuel prior to procedure or the all-levels sampling (incorporated by reference under § 75.6), combustion. Sample according to the single procedure in ASTM D4057–88, ‘‘Standard every day the unit is combusting oil. Extract tank composite sampling procedure or all- Practice for Manual Sampling of Petroleum oil at least once every hour and blend into levels sampling procedure in ASTM D4057– and Petroleum Products’’ (incorporated by a composite sample. The sample compositing 88, ‘‘Standard Practice for Manual Sampling reference under § 75.6). Except as otherwise period may not exceed 7 calendar days (168 of Petroleum and Petroleum Products’’ provided in this section, calculate SO2 mass

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emission rate using the sulfur content (and value to calculate SO2 mass emission rate or after receipt of a request from the where required, the density) from one of the heat input rate unless and until: it is Administrator. two following values, and calculate heat superseded by a higher value from an oil 2.3 SO2 Emissions From Combustion of input using the gross calorific value from one sample; or it is superseded by a new contract Gaseous Fuels of the two following values: in which case the new contract value (1) The highest value sampled during the becomes the assumed value at the time the (a) Account for the hourly SO2 mass previous calendar year (this option is fuel specified under the new contract begins emissions due to combustion of gaseous fuels allowed for any consistent fuel which comes to be combusted in the unit; or (if applicable) for each hour when gaseous fuels are from a single source whether or not the fuel both the calendar year in which the sampled combusted by the unit using the procedures is supplied under a contractual agreement) or value exceeded the assumed value and the in this section. (2) The maximum value indicated in the subsequent calendar year have elapsed. (b) The procedures in sections 2.3.1 and contract with the fuel supplier. Continue to * * * * * 2.3.2 of this appendix, respectively, may be use this assumed contract value unless and 2.2.6 Where the flowmeter records used to determine SO2 mass emissions from until the actual sampled sulfur content, volumetric flow rate rather than mass flow combustion of pipeline natural gas and density, or gross calorific value of a delivery rate, analyze oil samples to determine the natural gas, as defined in § 72.2 of this exceeds the assumed value. chapter. The procedures in section 2.3.3 of (d) If the actual sampled sulfur content, density or specific gravity of the oil. *** gross calorific value, or density of an oil * * * * * this appendix may be used to account for SO2 sample is greater than the assumed value for 2.2.8 Results from the oil sample analysis mass emissions from any gaseous fuel that parameter, then use the actual sampled must be available no later than thirty combusted by a unit. For each type of value for sulfur content, gross calorific value, calendar days after the sample is composited gaseous fuel, the appropriate sampling or density of fuel to calculate SO2 mass or taken. However, during an audit, the frequency and the sulfur content and GCV emission rate or heat input rate as the new Administrator may require that the results of values used for calculations of SO2 mass assumed sulfur content, gross calorific value, the analysis be available as soon as emission rates are summarized in the or density. Continue to use this new assumed practicable, and no later than 5 business days following Table D–5.

TABLE D±5.ÐGAS SULFUR AND GCV VALUES USED IN CALCULATIONS FOR VARIOUS FUEL TYPES

Parameter Fuel type and sampling frequency Value used in calculations

Pipeline Natural Gas with H2S content less than or 0.0006 lb/mmBtu. 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 content less than or equal to 1.0 Default SO2 emission rate calculated from Eq. D±1h, grain/100scf when using the provisions of section using either the fuel contract maximum H2S or the 2.3.2 to determine SO2 mass emissions. maximum H2S from historical sampling data. Any gaseous fuel delivered in shipments or lotsÐSam- Actual % sulfur from most recent shipment or ple each lot or shipment. 1. Highest % sulfur from previous year's samples 1; or 2. Maximum % sulfur value allowed by contract 1. Any gaseous fuel transmitted by pipeline and having a Actual % sulfur from daily sample; or Highest % sulfur demonstrated ``low sulfur variability'' using the provi- from previous 30 daily samples. sions of section 2.3.6ÐSample daily. Any gaseous fuelÐSample hourly ...... Actual hourly sulfur content of the gas. Gas GCV ...... Pipeline Natural GasÐSample monthly ...... 1. GCV from most 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 GasÐSample monthly ...... 1. GCV from most 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 delivered in shipments or lotsÐSam- Actual GCV from most recent shipment or lot or ple each lot or shipment. 1. Highest GCV from previous year's samples1; or 2. Maximum GCV value allowed by contract.1 Any gaseous fuel transmitted by pipeline and having a 1. GCV from most recent monthly sample (with ≥ 48 demonstrated ``low GCV variability'' using the provi- operating hours in the month); or sions of section 2.3.5ÐSample monthly. 2. Highest GCV from previous year's samples.1 Any other gaseous fuel not having a ``low GCV varia- Actual daily or hourly GCV of the gas. bility''ÐSample 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 sul- fur 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 natural gas, in § 72.2 of this chapter, using chapter, the owner or operator may The owner or operator may determine the the procedures of this section. determine the SO2 mass emissions using either a default SO2 emission rate of 0.0006 SO2 mass emissions from the combustion of 2.3.1.1 SO2 Emission Rate lb/mmBtu and the procedures of this section, a fuel that meets the definition of pipeline For a fuel that meets the definition of the procedures in section 2.3.2 for natural pipeline natural gas under § 72.2 of this

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gas, or the procedures of section 2.3.3 for any 2.3.2.1 SO2 Emission Rate demonstrating that the definition of natural gaseous fuel. For each affected unit using the gas in § 72.2 of this chapter has been met. The owner or operator may account for SO2 The information must demonstrate that the default rate of 0.0006 lb/mmBtu, the owner emissions either by using a default SO2 or operator must document that the fuel emission rate, as determined under section fuel has a hydrogen sulfide content of less combusted is actually pipeline natural gas, 2.3.2.1.1 of this appendix, or by daily than 1.0 grain/100 scf. This demonstration using the procedures in section 2.3.1.4 of this sampling of the gas sulfur content using the must be made using one of the following appendix. procedures of section 2.3.3 of this appendix. sources of information: (1) The gas quality characteristics specified 2.3.1.2 Hourly Heat Input Rate For each affected unit using a default SO2 emission rate, the owner or operator must by a purchase contract or by a transportation Calculate hourly heat input rate, in provide documentation that the fuel contract; (2) A certification of the gas vendor, based mmBtu/hr, for a unit combusting pipeline combusted is actually natural gas according on routine vendor sampling and analysis natural gas, using the procedures of section to the procedures in section 2.3.2.4 of this (minimum of one year of data with samples 3.4.1 of this appendix. Use the measured fuel appendix. taken monthly or more frequently); flow rate from section 2.1 of this appendix 2.3.2.1.1 In lieu of daily sampling of the (3) At least one year’s worth of analytical and the gross calorific value from section sulfur content of the natural gas, an SO2 data on the fuel hydrogen sulfide content 2.3.4.1 of this appendix in the calculations. default emission rate may be determined from samples taken monthly or more using Equation D–1h. Round off the 2.3.1.3 SO2 Hourly Mass Emission Rate and frequently; calculated SO2 default emission rate to the Hourly Mass Emissions (4) For fuels delivered in shipments or lots, nearest 0.0001 lb/mmBtu. For pipeline natural gas combustion, sulfur content from all shipments or lots calculate the SO2 mass emission rate, in lb/ ER= H S × 0. 0026 ( Eq . D-1h) received in a one year period; or hr, using Equation D–5 in section 3.3.2 of this 2 (5) Data from a 720-hour demonstration appendix (when the default SO2 emission Where: conducted using the procedures of section rate is used). Then, use the calculated SO2 ER = Default SO2 emission rate for natural 2.3.6 of this appendix. mass emission rate and the unit operating gas combustion, lb/mmBtu. (b) When a 720-hour test is used for initial qualification as natural gas, the owner or time to determine the hourly SO2 mass H2S = Hydrogen sulfide content of the emissions from pipeline natural gas natural gas, gr/100scf. operator shall continue sampling the fuel for hydrogen sulfide at least once per month for combustion, in lb, using Equation D–12 in 2.3.2.1.2 The hydrogen sulfide value used one year after the initial qualification period. section 3.5.1 of this appendix. in Equation D–1h may be obtained from one The use of the default natural gas SO2 2.3.1.4 Documentation That a Fuel Is of the following sources of information: emission rate under 2.3.2.1.1 is not allowed Pipeline Natural Gas (a) The highest hydrogen sulfide content if any sample during the one year period has specified by a purchase contract or by a (a) For pipeline natural gas, provide a hydrogen sulfide content greater than 1.0 pipeline transportation contract; grain/100 scf. information in the monitoring plan required (b) The highest hydrogen sulfide content under § 75.53, demonstrating that the from a certification of the gas vendor, based 2.3.3 SO2 Mass Emissions From Any definition of pipeline natural gas in § 72.2 of on routine vendor sampling and analysis Gaseous Fuel this chapter has been met. The information (minimum of one year of data with samples The owner or operator of a unit may must demonstrate that the fuel has a taken monthly or more frequently); determine SO2 mass emissions using this hydrogen sulfide content of less than 0.3 (c) The highest hydrogen sulfide content section for any gaseous fuel (including fuels grain/100scf. The demonstration must be from at least one year’s worth of analytical such as refinery gas, landfill gas, digester gas, made using one of the following sources of data on the fuel hydrogen sulfide content coke oven gas, blast furnace gas, coal-derived information: from samples taken monthly or more gas, producer gas or any other gas which may (1) The gas quality characteristics specified frequently; have a variable sulfur content). by a purchase contract or by a pipeline (d) For fuels delivered in shipments or lots, 2.3.3.1 Sulfur Content Determination transportation contract; the highest hydrogen sulfide content from all (2) A certification of the gas vendor, based shipments or lots received in a one year 2.3.3.1.1 Analyze the total sulfur content of the gaseous fuel in grain/100 scf, at the on routine vendor sampling and analysis period; or (5) the highest hydrogen sulfide frequency specified in Table D–5 of this (minimum of one year of data with samples content measured during a 720-hour appendix. That is: for fuel delivered in taken monthly or more frequently); demonstration conducted using the discrete shipments or lots, sample each procedures of section 2.3.6 of this appendix. (3) At least one year’s worth of analytical shipment or lot; for fuel transmitted by data on the fuel hydrogen sulfide content 2.3.2.2 Hourly Heat Input Rate pipeline, if a demonstration is provided from samples taken monthly or more Calculate hourly heat input rate for natural under section 2.3.6 of this appendix showing frequently; that the gaseous fuel has a ‘‘low sulfur (4) For fuels delivered in shipments or lots, gas combustion, in mmBtu/hr, using the procedures in section 3.4.1 of this appendix. variability,’’ determine the sulfur content the sulfur content from all shipments or lots Use the measured fuel flow rate from section daily using either manual sampling or a gas received in a one year period; or 2.1 of this appendix and the gross calorific chromatograph; and for all other gaseous (5) Data from a 720-hour demonstration value from section 2.3.4.2 of this appendix in fuels, determine the sulfur content on an conducted using the procedures of section the calculations. hourly basis using a gas chromatograph. 2.3.6 of this appendix. 2.3.3.1.2 Use one of the following (b) When a 720-hour test is used for initial 2.3.2.3 SO2 Mass Emission Rate and Hourly methods when using manual sampling (as qualification as pipeline natural gas, the Mass Emissions applicable to the type of gas combusted) to owner or operator is required to continue For natural gas combustion, calculate the determine the sulfur content of the fuel: sampling the fuel for hydrogen sulfide at SO2 mass emission rate, in lb/hr, using ASTM D1072–90, ‘‘Standard Test Method for least once per month for one year after the Equation D–5 in section 3.3.2 of this Total Sulfur in Fuel Gases’’, ASTM D4468– initial qualification period. The use of the appendix, when the default SO2 emission 85 (Reapproved 1989) ‘‘Standard Test default natural gas SO2 emission rate under rate is used. Then, use the calculated SO2 Method for Total Sulfur in Gaseous Fuels by 2.3.1.1 is not allowed if any sample during mass emission rate and the unit operating Hydrogenolysis and Radiometric the one year period has a hydrogen sulfide time to determine the hourly SO2 mass Colorimetry,’’ ASTM D5504–94 ‘‘Standard content greater than 0.3 gr/100 scf. emissions from natural gas combustion, in lb, Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous 2.3.2 Natural Gas Combustion using Equation D–12 in section 3.5.1 of this appendix. Fuels by Gas Chromatography and The owner or operator may determine the Chemiluminescence,’’ or ASTM D3246–81 2.3.2.4 Documentation that a Fuel Is SO2 mass emissions from the combustion of (Reapproved 1987) ‘‘Standard Test Method a fuel that meets the definition of natural gas, Natural Gas for Sulfur in Petroleum Gas By Oxidative in § 72.2 of this chapter, using the procedures (a) For natural gas, provide information in Microcoulometry’’ (incorporated by reference of this section. the monitoring plan required under § 75.53, under § 75.6).

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2.3.3.1.3 The sampling and analysis of analysis for GCV must be performed for each standard deviation from the mean shall be daily manual samples may be performed by quarter the unit operates for any amount of calculated from the hourly averages. the owner or operator, an outside laboratory, time. Specifically, the gaseous fuel is considered to or the gas supplier. If hourly sampling with 2.3.4.2 GCV of Natural Gas have a low GCV variability, and monthly gas a gas chromatograph is required, or a source sampling for GCV may be used, if the mean chooses to use an online gas chromatograph Determine the GCV of fuel that is natural value of the GCV multiplied by 1.075 is less to determine daily fuel sulfur content, the gas, as defined in § 72.2 of this chapter, on than the sum of the mean value and one owner or operator shall develop and a monthly basis, in the same manner as standard deviation. If the gaseous fuel or implement a program to quality assure the described for pipeline natural gas in section blend does not meet this requirement, then data from the gas chromatograph, in 2.3.4.1 of this appendix. daily fuel sampling and analysis for GCV, accordance with the manufacturer’s 2.3.4.3 GCV of Other Gaseous Fuels using manual sampling, a gas chromatograph recommended procedures. The quality For gaseous fuels other than natural gas or or an on-line calorimeter is required. assurance procedures shall be kept on-site, in pipeline natural gas, determine the GCV as 2.3.6 Demonstration of Fuel Sulfur a form suitable for inspection. specified in section 2.3.4.3.1, 2.3.4.3.2 or Variability 2.3.3.1.4 Results of all sample analyses 2.3.4.3.3, as applicable. 2.3.4.3.1 For a (a) This demonstration is required for any must be available no later than thirty gaseous fuel that is delivered in discrete calendar days after the sample is taken. shipments or lots, determine the GCV for fuel which does not qualify as pipeline natural gas or natural gas and is not delivered 2.3.3.2 SO2 Mass Emission Rate each shipment or lot. The determination may in shipments or lots. The results of the Calculate the SO2 mass emission rate for be made by sampling each delivery or by the gaseous fuel, in lb/hr, using equation D– sampling the supply tank after each delivery. demonstration will be used to determine 4 in section 3.3.1 of this appendix. Use the For sampling of each delivery, use the whether daily or hourly sampling for sulfur appropriate sulfur content, in equation D–4, highest GCV in the previous year’s samples. in the fuel is required. To make this as specified in Table D–5 of this appendix. For sampling from the tank after each demonstration, proceed as follows. Provide a That is, for fuels delivered by pipeline which delivery, use either the most recent GCV minimum of 720 hours of data, indicating the demonstrate a low sulfur variability (under sample or the highest GCV in the previous total sulfur content (and hydrogen sulfide section 2.3.6 of this appendix) use either the year. 2.3.4.3.2 For any gaseous fuel that does content, if needed to define a fuel as either daily value or the highest value in the not qualify as pipeline natural gas or natural pipeline natural gas or natural gas) of the previous 30 days or for fuels requiring hourly gas and which is not delivered in shipments gaseous fuel or blend (in gr/100 scf). The sulfur content sampling with a gas or lots which performs the required 720 hour demonstration data shall be obtained using chromatograph use the actual hourly sulfur test under section 2.3.5 of this appendix, and either manual hourly sampling or an on-line content). the results of the test demonstrate that the gas chromatograph capable of determining fuel total sulfur content (and, if applicable, 2.3.3.3 Hourly Heat Input Rate gaseous fuel has a low GCV variability, determine the GCV at least monthly. In H2S content) on an hourly basis. For gaseous Calculate the hourly heat input rate for calculations of hourly heat input for a unit, fuel produced by a variable process, combustion of the gaseous fuel, using the use either the most recent monthly sample or additional data shall be provided which is provisions in section 3.4.1 of this appendix. the highest fuel GCV from the previous year’s representative of all process operating Use the measured fuel flow rate from section samples. 2.3.4.3.3 For any other gaseous fuel, conditions including seasonal or annual 2.1 of this appendix and the gross calorific determine the GCV at least daily and use the variations which may affect fuel sulfur value from section 2.3.4.3 of this appendix in actual fuel GCV in calculations of unit hourly content. the calculations. heat input. If an online gas chromatograph or (b) Reduce the data to hourly averages of 2.3.4 Gross Calorific Values for Gaseous on-line calorimeter is used to determine fuel the total sulfur content (and hydrogen sulfide Fuels GCV each day, the owner or operator shall content, if applicable) of the fuel. Then, develop and implement a program to quality calculate the mean value of the total sulfur Determine the GCV of each gaseous fuel at assure the data from the gas chromatograph content and standard deviation in order to the frequency specified in this section, using or on-line calorimeter, in accordance with determine whether daily sampling of the one of the following methods: ASTM D1826– the manufacturer’s recommended sulfur content of the gaseous fuel or blend is 88, ASTM D3588–91, ASTM D4891–89, GPA procedures. The quality assurance sufficient or whether hourly sampling with a Standard 2172–86 ‘‘Calculation of Gross procedures shall be kept on-site, in a form gas chromatograph is required. Specifically, Heating Value, Relative Density and suitable for inspection. daily gas sampling and analysis for total Compressibility Factor for Natural Gas sulfur content, using either manual sampling Mixtures from Compositional Analysis,’’ or 2.3.5 Demonstration of Fuel GCV or an online gas chromatograph, shall be GPA Standard 2261–90 ‘‘Analysis for Natural Variability sufficient, provided that the standard Gas and Similar Gaseous Mixtures by Gas (a) This demonstration is required of any deviation of the hourly average values from Chromatography’’ (incorporated by reference fuel which does not qualify as pipeline the mean value does not exceed 5.0 grains under § 75.6 of this part). Use the appropriate natural gas or natural gas, and is not per 100 scf. If the gaseous fuel or blend does GCV value, as specified in section 2.3.4.1, delivered only in shipments or lots. The not meet this requirement, then hourly 2.3.4.2 or 2.3.4.3 of this appendix, in the demonstration data shall be used to sampling of the fuel with a gas calculation of unit hourly heat input rates. determine whether daily or monthly sampling of the GCV of the gaseous fuel or chromatograph and hourly reporting of the 2.3.4.1 GCV of Pipeline Natural Gas blend is required. average sulfur content of the fuel is required. Determine the GCV of fuel that is pipeline (b) To make this demonstration, proceed as 2.4 * * * natural gas, as defined in § 72.2 of this follows. Provide a minimum of 720 hours of 2.4.1 Missing Data for Oil and Gas Samples chapter, at least once per calendar month. data, indicating the GCV of the gaseous fuel For GCV used in calculations use the or blend (in Btu/100 scf). The demonstration When fuel sulfur content, gross calorific specifications in Table D–5: either the value data shall be obtained using either: hourly value or, when necessary, density data are from the most recent monthly sample, the sampling and analysis using the methods in missing or invalid for an oil or gas sample highest value specified in a contract or tariff section 2.3.4 to determine GCV of the fuel; taken according to the procedures in section sheet, or the highest value from the previous an on-line gas chromatograph capable of 2.2.3, 2.2.4.1, 2.2.4.2, 2.2.4.3, 2.2.5, 2.2.6, year. The fuel GCV value from the most determining fuel GCV on an hourly basis; or 2.2.7, 2.3.3.1, 2.3.3.1.2, or 2.3.4 of this recent monthly sample shall be used for any an on-line calorimeter. For gaseous fuel appendix, then substitute the maximum month in which that value is higher than a produced by a variable process, the data shall potential sulfur content, density, or gross contract limit. If a unit combusts pipeline be representative of and include all process calorific value of that fuel from Table D–6 of natural gas for less than 48 hours during a operating conditions including seasonal and this appendix. Irrespective of which calendar month, the sampling and analysis yearly variations in process which may affect reporting option is selected (i.e., actual value, requirement for GCV is waived for that fuel GCV. contract value or highest value from the calendar month. The preceding waiver is (c) The data shall be reduced to hourly previous year, the missing data values in limited by the condition that at least one averages. The mean GCV value and the Table D–6 shall be reported whenever the

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TABLE D±6.ÐMISSING DATA SUBSTITUTION PROCEDURES FOR SULFUR, DENSITY, AND GROSS CALORIFIC VALUE DATA

Parameter Missing data substitution maximum 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 2.4.2.2 * * * 3. Calculations fuel flowmeter that is part of an excepted 2.4.2.3 For hours where two or more fuels Calculate hourly SO2 mass emission rate monitoring system under appendix D or E to are combusted, substitute the maximum from combustion of oil fuel using the this part, where the fuel flowmeter data are hourly fuel flow rate measured and recorded procedures in section 3.1 of this appendix. required to determine the amount of fuel by the flowmeter (or flowmeters, where fuel Calculate hourly SO2 mass emission rate combusted by the unit, use the procedures in is recirculated) for the fuel for which data are from combustion of gaseous fuel using the sections 2.4.2.2 and 2.4.2.3 of this appendix missing at the corresponding load range to account for the flow rate of fuel combusted recorded for each missing hour during the procedures in section 3.3 of this appendix. at the unit for each hour during the missing previous 720 hours when the unit combusted (Note: the SO2 mass emission rates in data period. In addition, a fuel flowmeter that fuel with any other fuel. For hours where sections 3.1 and 3.3 are calculated such that used for measuring fuel combusted by a no previous recorded fuel flow rate data are the rate, when multiplied by unit operating peaking unit may use the simplified fuel flow available for that fuel during the missing data time, yields the hourly SO2 mass emissions missing data procedure in section 2.4.2.1 of period, calculate and substitute the for a particular fuel for the unit.) Calculate this appendix. maximum potential flow rate of that fuel for hourly heat input rate for both oil and 2.4.2.1 Simplified Fuel Flow Missing Data the unit as defined in section 2.4.2.2 of this gaseous fuels using the procedures in section for Peaking Units appendix. 3.4 of this appendix. Calculate total SO2 mass If no fuel flow rate data are available for 2.4.3 * * * emissions and heat input for each hour, each a fuel flowmeter system installed on a 66. Appendix D to part 75 is further quarter and the year to date using the peaking unit (as defined in § 72.2 of this amended by: procedures under section 3.5 of this chapter), then substitute for each hour of a. Revising sections 3 through 3.2.1 and appendix. Where an oil flowmeter records missing data using the maximum potential 3.2.3; volumetric flow rate, use the calculation fuel flow rate. The maximum potential fuel b. Removing section 3.2.4; procedures in section 3.2 of this appendix to flow rate is the lesser of the following: c. Revising sections 3.3 through 3.3.3; calculate the mass flow rate of oil. (a) The maximum fuel flow rate the unit is d. Redesignating section 3.4 as 3.6 and 3.1 SO2 Mass Emission Rate Calculation for capable of combusting or (b) the maximum revising the first sentence; and Oil flow rate that the flowmeter can measure (i.e, e. Adding new sections 3.4 through 3.4.3 upper range value of flowmeter leading to a and sections 3.5 through 3.5.6 to read as 3.1.1 Use Equation D–2 to calculate SO2 unit). follows: mass emission rate per hour (lb/hr):

%S SO2= 2. 0 × OIL × oil (.Eq D-2) rate-oil rate 100. 0

Where: flow rate measurements and the density or Voil-rate = Volume rate of oil consumed per

SO2rate-oil = Hourly mass emission rate of specific gravity of the oil sample. hr, measured in scf/hr, gal/hr, barrels/hr, or 3 SO2 emitted from combustion of oil, lb/hr. * * * * * m /hr. OILrate = Mass rate of oil consumed per hr 3.2.3 Where density of the oil is Doil = Density of oil, measured in lb/scf, lb/ gal, lb/barrel, or lb/m3. during combustion, lb/hr. determined by the applicable ASTM %Soil = Percentage of sulfur by weight procedures from section 2.2.6 of this 3.3 SO2 Mass Emission Rate Calculation for measured in the sample. appendix, use Equation D–3 to calculate the Gaseous Fuels 2.0 = Ratio of lb SO 2/lb S. rate of the mass of oil consumed (in lb/hr): 3.3.1 Use Equation D–4 to calculate the 3.1.2 Record the SO2 mass emission rate SO2 mass emission rate when using the from oil for each hour that oil is combusted. = × OILrate V oil-rate D oil (. Eq D-3) optional gas sampling and analysis 3.2 Mass Flow Rate Calculation for Where: procedures in sections 2.3.1 and 2.3.2 of this Volumetric Oil Flowmeters appendix, or the required gas sampling and OILrate = Mass rate of oil consumed per hr, 3.2.1 Where the oil flowmeter records lb/hr. analysis procedures in section 2.3.3 of this volumetric flow rate rather than mass flow appendix. Total sulfur content of a fuel must rate, calculate and record the oil mass flow be determined using the procedures of rate for each hourly period using hourly oil 2.3.3.1.2 of this appendix:

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 2  SO2 = × GAS × S(. Eq D-4 ) rate-gas  7000 rate gas

= × Where: SO2rate ER HI rate ( Eq . D- 5 ) 3.4 Calculation of Heat Input Rate SO2rate-gas = Hourly mass rate of SO2 emitted where: 3.4.1 Heat Input Rate for Gaseous Fuels due to combustion of gaseous fuel, lb/hr. SO2rate = Hourly mass emission rate of SO2 (a) Determine total hourly gas flow or GASrate = Hourly metered flow rate of gaseous fuel combusted, 100 scf/hr. from combustion of a gaseous fuel, lb/hr. average hourly gas flow rate with a fuel ER = SO2 emission rate from section 2.3.1.1 flowmeter in accordance with the Sgas = Sulfur content of gaseous fuel, in grain/ requirements of section 2.1 of this appendix 100 scf. or 2.3.2.1.1, of this appendix, lb/mmBtu. HIrate = Hourly heat input rate of a gaseous and the fuel GCV in accordance with the 2.0 = Ratio of lb SO2/lb S. fuel, calculated using procedures in requirements of section 2.3.4 of this 7000 = Conversion of grains/100 scf to lb/100 appendix. If necessary perform the 720-hour scf. section 3.4.1 of this appendix, in mmBtu/hr. test under section 2.3.5 to determine the 3.3.2 Use Equation D–5 to calculate the appropriate fuel GCV sampling frequency. 3.3.3 Record the SO2 mass emission rate SO2 mass emission rate when using a default (b) Then, use Equation D–6 to calculate for each hour when the unit combusts a emission rate from section 2.3.1.1 or 2.3.2.1.1 heat input rate from gaseous fuels for each of this appendix: gaseous fuel. hour.

GAS× GCV HI = rate gas (.Eq D-6) rate-gas 106

Where: 3.4.2 Heat Input Rate From the Combustion OILrate = Average fuel flow rate for the of Oil HIrate-gas = Hourly heat input rate from portion of the hour which the unit combustion of the gaseous fuel, mmBtu/ (a) Determine total hourly oil flow or operated in lb/hr. hr. average hourly oil flow rate with a fuel OILunit = Total fuel combusted during GASrate = Average volumetric flow rate of flowmeter, in accordance with the fuel, for the portion of the hour in which requirements of section 2.1 of this appendix. the hour, lb. the unit operated, 100 scf/hr. Determine oil GCV according to the t = Unit operating time, hour or fraction of an hour (in equal increments that can GCVgas = Gross calorific value of gaseous requirements of section 2.2 of this appendix. fuel, Btu/hr. Then, use Equation D–8 to calculate hourly range from one hundredth to one quarter of an hour, at the option of the owner or 10 6 = Conversion of Btu to mmBtu. heat input rate from oil for each hour: operator). (c) Note that when fuel flow is measured GCVoil 3.4.3 Apportioning Heat Input Rate to on an hourly totalized basis (e.g. a fuel HI= OIL (.)Eq D-8 rate-oil rate 6 Multiple Units flowmeter reports totalized fuel flow for each 10 hour), before Equation D–6 can be used, the Where: (a) Use the procedure in this section to total hourly fuel usage must be converted HIrate-oil = Hourly heat input rate from apportion hourly heat input rate to two or from units of 100 scf to units of 100 scf/hr combustion of oil, mmBtu/hr. more units using a single fuel flowmeter using Equation D–7: OILrate = Mass rate of oil consumed per hour, which supplies fuel to the units. (This as determined using procedures in procedure is not applicable to units section 3.2.3 of this appendix, in lb/hr, GASunit calculating NOX mass emissions using the GAS = (Eq . D-7 ) tons/hr, or kg/hr. rate t provisions of subpart H of this part.) The GCVoil = Gross calorific value of oil, Btu/lb, designated representative may also petition Where: Btu/ton, Btu/kg. the Administrator under § 75.66 to use this 106 = Conversion of Btu to mmBtu. GASrate = Average volumetric flow rate of fuel apportionment procedure to calculate SO2 for the portion of the hour in which the (b) Note that when fuel flow is measured and CO2 mass emissions. unit operated, 100 scf/hr. on an hourly totalized basis (e.g., a fuel flowmeter reports totalized fuel flow for each (b) Determine total hourly fuel flow or flow GASunit = Total fuel combusted during the hour), before equation D–8 can be used, the rate through the fuel flowmeter supplying gas hour, 100 scf. total hourly fuel usage must be converted or oil fuel to the units. Convert fuel flow rates t = Unit operating time, hour or fraction of from units of lb to units of lb/hr, using to units of 100 scf for gaseous fuels or to lb an hour (in equal increments that can equation D–9: range from one hundredth to one quarter for oil, using the procedures of this appendix. of an hour, at the option of the owner or Apportion the fuel to each unit separately OIL unit = based on hourly output of the unit in MWe operator). OIL rate (Eq . D-9 ) t or 1000 lb of steam/hr (klb/hr) using Where: Equation D–10 or D–11, as applicable:

  U =  output  GASunit GAS meter   (.Eq D-10)  ∑ Uoutput   all-units 

Where: GASunit = Gas flow apportioned to a unit, 100 GASmeter = Total gas flow through the fuel scf. flowmeter, 100 scf. Uoutput = Total unit output, MW or klb/hr.

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  U =  output  OILunit OIL meter   (.Eq D-11)  ∑ Uoutput   all-units 

Where: 3.5 Conversion of Hourly Rates to Hourly, SO2rate-i = SO2 mass emission rate for each Quarterly and Year to Date Totals type of gas or oil fuel combusted during OILunit = Oil flow apportioned to a unit, lb. the hour, lb/hr. OILmeter = Total oil flow through the fuel 3.5.1 Hourly SO2 Mass Emissions From the flowmeter, lb. Combustion of All Fuels ti = Time each gas or oil fuel was combusted for the hour (fuel usage time), fraction of Uoutput = Total unit output in either MWe or Determine the total mass emissions for klb/hr. an hour (in equal increments that can each hour from the combustion of all fuels range from one hundredth to one quarter (c) Use the total apportioned fuel flow using Equation D–12: of an hour, at the option of the owner or calculated from Equation D–10 or D–11 to operator). calculate the hourly unit heat input rate, M= ∑SO2 t(. Eq D-12) SO2-hr rate-i i 3.5.2 Quarterly Total SO2 Mass Emissions using Equations D–6 and D–7 (for gas) or all-fuels Equations D–8 and D–9 (for oil). Where: Sum the hourly SO2 mass emissions in lb as determined from Equation D–12 for all MSO2-hr = Total mass of SO2 emissions from all fuels combusted during the hour, lb. hours in a quarter using Equation D–13:

= 1 MSO2-qtr∑ M SO 2 -hr (. Eq D-13) 2000 all-hours-in-qtr

Where: MSO2-hr = Hourly SO2 mass emissions 3.5.3 Year to Date SO2 Mass Emissions determined using Equation D–12, lb. MSO2-qtr = Total mass of SO2 emissions from Calculate and record SO2 mass emissions all fuels combusted during the quarter, 2000= Conversion factor from lb to tons. in the year to date using Equation D–14: tons.

current-quarter = MSO2-YTD∑ M SO2-qtr (. Eq D-14) q=1

Where: = 1 Appendix E to Part 75—Optional NOX HIqtr∑ HI hr (. Eq D-16) Emissions Estimation Protocol for Gas-Fired MSO2-YTD = Total SO2 mass emissions for the 2000 year to date, tons. all-hours-in-qtr Peaking Units and Oil-Fired Peaking Units MSO2-qtr = Total SO2 mass emissions for the Where: * * * * * quarter, tons. HIqtr = Total heat input from all fuels 2. Procedure 3.5.4 Hourly Total Heat Input from the combusted during the quarter, mmBtu. * * * * * Combustion of all Fuels HIhr = Hourly heat input determined using Equation D–15, mmBtu. 2.4 Procedures for Determining Hourly NOX Determine the total heat input in mmBtu Emission Rate 3.5.6 Year-to-Date Heat Input for each hour from the combustion of all * * * * * fuels using Equation D–15: Calculate and record the total heat input in 2.4.2 Use the graph of the baseline = the year to date using Equation D–17. correlation results (appropriate for the fuel or HIhr∑ HI rate-i t i (. Eq D-15) fuel combination) to determine the NOX all-fuels current-quarter emissions rate (lb/mmBtu) corresponding to = Where: HIYTD∑ HI qtr (. Eq D-17) the heat input rate (mmBtu/hr). Input this q=1 correlation into the data acquisition and HIhr = Total heat input from all fuels handling system for the unit. Linearly combusted during the hour, mmBtu. HIYTD = Total heat input for the year to date, interpolate to 0.1 mmBtu/hr heat input rate HIrate-i =Heat input rate for each type of gas mmBtu. and 0.01 lb/mmBtu NOX (0.001 lb/mmBtu or oil combusted during the hour, qtr HI = Total heat input for the quarter, NOX after April 1, 2000). For each type of mmBtu/hr. mmBtu. fuel, calculate NOX emission rate using the ti = Time each gas or oil fuel was combusted 3.6 Records and Reports baseline correlation results from the most for the hour (fuel usage time), fraction of recent test with that fuel, beginning with the Calculate and record quarterly and an hour (in equal increments that can date and hour of the completion of the most range from one hundredth to one quarter cumulative SO2 mass emissions and heat recent test. of an hour, at the option of the owner or input for each calendar quarter using the 2.4.3 To determine the NOX emission rate operator). procedures and equations of section 3.5 of for a unit co-firing fuels that has not been 3.5.5 Quarterly Heat Input this appendix. * * * tested for that combination of fuels, 67. Appendix E to part 75 is amended by interpolate between the NOX emission rate Sum the hourly heat input values revising sections 2.4.2, 2.4.3, 2.4.4, 2.5.4 and for each fuel as follows. Determine the heat determined from equation D–15 for all hours 2.5.5 to read as follows: input rate for the hour (in mmBtu/hr) for in a quarter using Equation D–16: each fuel and select the corresponding NOX emission rate for each fuel on the appropriate graph. (When a fuel is combusted for a partial

VerDate 06-MAY-99 23:17 May 25, 1999 Jkt 183247 PO 00000 Frm 00103 Fmt 4701 Sfmt 4700 E:\FR\FM\26MYR2.XXX pfrm07 PsN: 26MYR2 28666 Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules and Regulations hour, determine the fuel usage time for each beginning with the date and hour of the 2.5.5 Substitute missing data for gross fuel and determine the heat input rate from completion of the most recent test. calorific value of fuel using the procedures in each fuel as if that fuel were combusted at 2.4.4 For each hour, record the critical sections 2.4.1 of appendix D to this part. that rate for the entire hour in order to select quality assurance parameters, as identified in 68. Appendix E to part 75 is further the corresponding NOX emission rate.) the monitoring plan, and as required by amended by revising sections 3.1, 3.3.1, and Calculate the total heat input to the unit in section 2.3 of this appendix from the date 3.3.4 to read as follows: mmBtu for the hour from all fuel combusted and hour of the completion of the most recent test for each type of fuel. 3. Calculations using Equation E–1. Calculate a Btu-weighted average of the emission rates for all fuels 2.5 Missing Data Procedures 3.1 Heat Input using Equation E–2 of this appendix. For * * * * * Calculate the total heat input by summing each type of fuel, calculate NOX emission 2.5.4 Substitute missing data from a fuel the product of heat input rate and fuel usage rate using the baseline correlation results flowmeter using the procedures in section time of each fuel, as in the following from the most recent test with that fuel, 2.4.2 of appendix D to this part. equation:

= + + + + HT HI fuel1 t 1 HI fuel 2 t 2 HI fuel 3 t 3 ... HI lastfuel t last ( Eq . E-1)

Where: Where: technologies. When computing hourly SO2

HT = Total heat input of fuel flow or a Eh = NOX emission rate for the unit for the emission rate in lb/mmBtu, a minimum combination of fuel flows to a unit, hour, lb/mmBtu. concentration of 5.0 percent CO2 and a mmBtu. Ef = NOX emission rate for the unit for a maximum concentration of 14.0 percent O2 HIfuel 1,2,3,...last = Heat input rate from each given fuel at heat input rate HIf, lb/ may be substituted for measured diluent gas fuel, in mmBtu/hr as determined using mmBtu. concentration values at boilers during hours Equation F–19 or F–20 in section 5.5 of HIf = Heat input rate for the hour for a given when the hourly average concentration of appendix F to this part, mmBtu/hr. fuel, during the fuel usage time, as CO2 is less than 5.0 percent CO2 or the hourly t1,2,3....last = Fuel usage time for each fuel determined using Equation F–19 or F–20 average concentration of O2 is greater than (rounded up to the nearest fraction of an in section 5.5 of appendix F to this part, 14.0 percent O2. hour (in equal increments that can range mmBtu/hr. 2.1 When measurements of SO2 from one hundredth to one quarter of an HT = Total heat input for all fuels for the hour hour, at the option of the owner or from Equation E–1. concentration and flow rate are on a wet operator)). tf = Fuel usage time for each fuel (rounded basis, use the following equation to compute * * * * * up to the nearest fraction of an hour (in hourly SO2 mass emission rate (in lb/hr): 3.3 * * * equal increments that can range from one hundredth to one quarter of an hour, at E= KC Q( Eq . F-1) 3.3.1 Conversion from Concentration to h h h the option of the owner or operator)). Emission Rate Where: Note: For hours where a fuel is combusted Convert the NOX concentrations (ppm) and Eh = Hourly SO2 mass emission rate during for only part of the hour, use the fuel flow O2 concentrations to NOX emission rates (to unit operation, lb/hr. rate or mass flow rate during the fuel usage ±7 the nearest 0.01 lb/mmBtu for tests K = 1.660 × 10 for SO2, (lb/scf)/ppm. time, instead of the total fuel flow or mass performed prior to April 1, 2000, or to the Ch = Hourly average SO2 concentration nearest 0.001 lb/mmBtu for tests performed flow during the hour, when calculating heat input rate using Equation F–19 or F–20. during unit operation, stack moisture on and after April 1, 2000), according to the basis, ppm. appropriate one of the following equations: 69. Appendix F to part 75 is amended by Qh = Hourly average volumetric flow rate F–5 in appendix F to this part for dry basis revising sections 2, 2.1, 2.2, 2.3, and 2.4 to during unit operation, stack moisture concentration measurements or 19–3 in read as follows: basis, scfh. Method 19 of appendix A to part 60 of this Appendix F to Part 75—Conversion 2.2 When measurements by the SO2 pollutant chapter for wet basis concentration Procedures measurements. concentration monitor are on a dry basis and * * * * * the flow rate monitor measurements are on * * * * * a wet basis, use the following equation to 2. Procedures for SO2 Emissions 3.3.4 Average NOX Emission Rate During compute hourly SO2 mass emission rate (in Co-firing of Fuels Use the following procedures to compute lb/hr): hourly SO2 mass emission rate (in lb/hr) and all fuels quarterly and annual SO2 total mass × ∑()E f HIf t f emissions (in tons). Use the procedures in Method 19 in appendix A to part 60 of this E = f=1 (.Eq E-2) h H chapter to compute hourly SO2 emission T rates (in lb/mmBtu) for qualifying Phase I

()100 − %HO E= K C Q 2 (Eq . F-2) h hp hs 100

where: %H2O = Hourly average stack moisture n Eh = Hourly SO2 mass emission rate during content during unit operation, percent by ∑ Eh t h unit operation, lb/hr. volume. = h= i ±7 E q (Eq . F-3) K = 1.660 x 10 for SO2, (lb/scf)/ppm. 2.3 Use the following equations to 2000 Chp = Hourly average SO2 concentration calculate total SO2 mass emissions for each Where: during unit operation, ppm (dry). calendar quarter (Equation F–3) and for each Eq = Quarterly total SO2 mass emissions, Qhs = Hourly average volumetric flow rate calendar year (Equation F–4), in tons: during unit operation, scfh as measured tons. (wet). Eh = Hourly SO2 mass emission rate, lb/hr.

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th = Unit operating time, hour or fraction of Where: 4.2 When CO2 concentration is measured an hour (in equal increments that can Eq = Quarterly average NOX emission rate, lb/ on a dry basis, use Equation F–2 to calculate range from one hundredth to one quarter mmBtu. the hourly CO2 mass emission rate (in tons/ of an hour, at the option of the owner or Ei = Hourly average NOX emission rate hr) with a K-value of 5.7 x 10±7 (tons/scf) operator). during unit operation, lb/mmBtu. percent CO2, where Eh = hourly CO2 mass n = Number of hourly SO2 emissions values n = Number of hourly rates during calendar during calendar quarter. emission rate, tons/hr and Chp = hourly quarter. 2000 = Conversion of 2000 lb per ton. average CO2 concentration in flue, dry basis, percent CO2. m 4.3 Use the following equations to 4 E = i calculate total CO2 mass emissions for each = Ea ∑ (Eq . F-10 ) Ea∑ E q ( Eq . F-4 ) calendar quarter (Equation F–12) and for i=1 m q=1 each calendar year (Equation F–13): Where: Where: Ea = Average NOX emission rate for the HR Ea = Annual total SO2 mass emissions, tons. calendar year, lb/mmBtu. E= ∑ E t( Eq . F-12) Eq = Quarterly SO2 mass emissions, tons. CO2 q h h Ei = Hourly average NOX emission rate h=1 q = Quarters for which Eq are available during unit operation, lb/mmBtu. during calendar year. Where: m = Number of hourly rates for which Ei is 2.4 Round all SO2 mass emission rates and available in the calendar year. ECO2q = Quarterly total CO2 mass emissions, totals to the nearest tenth. tons. 3.5 Round all NOX emission rates to the 70. Appendix F to part 75 is further nearest 0.01 lb/mmBtu prior to April 1, 2000, Eh = Hourly CO2 mass emission rate, tons/hr. amended by revising sections 3.3.2, 3.3.3, th=Unit operating time, in hours or fraction 3.3.4, 3.4, and 3.5 to read as follows: and to the nearest 0.001 lb/mmBtu on and after April 1, 2000. of an hour (in equal increments that can range from one hundredth to one quarter 3. Procedures for NOX Emission Rate 71. Appendix F to part 75 is further of an hour, at the option of the owner or amended by revising sections 4.1, 4.2, 4.3, * * * * * operator). 3.3 * * * 4.4, and 4.4.1 to read as follows: HR = Number of hourly CO2 mass emission 3.3.2 E = Pollutant emissions during unit 4. Procedures for CO2 Mass Emissions rates available during calendar quarter. operation, lb/mmBtu. * * * * * 3.3.3 Ch = Hourly average pollutant concentration during unit operation, 4.1 When CO2 concentration is measured on a wet basis, use the following equation to 4 ppm. E= ∑ E( Eq . F-13) 3.3.4 %O2, %CO2 = Oxygen or carbon calculate hourly CO2 mass emissions rates (in CO2a CO 2 q dioxide volume during unit operation tons/hr): q=1 (expressed as percent O2 or CO2). A = Where: minimum concentration of 5.0 percent Eh KC h Q h ( Eq . F-11) ECO2a = Annual total CO2 mass emission, CO2 and a maximum concentration of Where: 14.0 percent O2 may be substituted for ECO2q = Quarterly total CO2 mass emissions, measured diluent gas concentration Eh = Hourly CO2 mass emission rate during tons. unit operation, tons/hr. values at boilers during hours when the q = Quarters for which ECO2q are available ±7 hourly average concentration of CO2 is K = 5.7 X 10 for CO2, (tons/scf) /%CO2. during calendar year. Ch = Hourly average CO2 concentration < 5.0 percent CO2 or the hourly average 4.4 For an affected unit, when the owner concentration of O2 is > 14.0 percent O2. during unit operation, wet basis, percent or operator is continuously monitoring O2 A minimum concentration of 1.0 percent CO2. For boilers, a minimum concentration (in percent by volume) of flue CO2 and a maximum concentration of concentration of 5.0 percent CO2 may be gases using an O2 monitor, use the equations 19.0 percent O2 may be substituted for substituted for the measured measured diluent gas concentration concentration when the hourly average and procedures in section 4.4.1 and 4.4.2 of values at stationary gas turbines during concentration of CO2 is < 5.0 percent this appendix to determine hourly CO2 mass hours when the hourly average CO2, provided that this minimum emissions (in tons). concentration of 5.0 percent CO2 is also concentration of CO2 is < 1.0 percent 4.4.1 Use appropriate F and Fc factors from used in the calculation of heat input for CO2 or the hourly average concentration section 3.3.5 of this appendix in one of the of O2 is > 19.0 percent O2. that hour. For stationary gas turbines, a minimum concentration of 1.0 percent following equations (as applicable) to * * * * * CO2 may be substituted for measured determine hourly average CO2 concentration 3.4 Use the following equations to diluent gas concentration values during of flue gases (in percent by volume): calculate the average NOX emission rate for hours when the hourly average each calendar quarter (Equation F–9) and the concentration of CO2 is < 1.0 percent average emission rate for the calendar year CO2, provided that this minimum (Equation F–10), in lb/mmBtu: concentration of 1.0 percent CO2 is also used in the calculation of heat input for n E that hour. E = ∑ i (Eq . F-9 ) q n Qh = Hourly average volumetric flow rate i=1 during unit operation, wet basis, scfh.

F 20.9 − O CO = 100 c 2 d (.Eq F-14a) 2d F 20. 9

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CO2d = Hourly average CO2 concentration O2d = Hourly average O2 concentration during unit operation, percent by during unit operation, percent by volume, dry basis. volume, dry basis. For boilers, a F, Fc = F-factor or carbon-based Fc-factor from maximum concentration of 14.0 percent section 3.3.5 of this appendix. O2 may be substituted for the measured 20.9 = Percentage of O2 in ambient air. 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.

100 F  100 − %HO  CO = c 20. 9 2 − O (. Eq F-14b) 2w20. 9 F   100  2 w 

Where: 5.5, 5.5.1 and 5.5.2; and by adding new 1 %CO HI= Q 2w (.Eq F-15) CO2w = Hourly average CO2 concentration sections 5.6 through 5.6.2 and 5.7 and by w F 100 during unit operation, percent by removing and revising section 5.4 to read as c volume, wet basis. follows: Where: O2w = Hourly average O2 concentration HI = Hourly heat input rate during unit during unit operation, percent by 5. Procedures for Heat Input operation, mmBtu/hr. volume, wet basis. For boilers, a Use the following procedures to compute Qw = Hourly average volumetric flow rate maximum concentration of 14.0 percent heat input rate to an affected unit (in mmBtu/ during unit operation, wet basis, scfh. O2 may be substituted for the measured hr or mmBtu/day): Fc = Carbon-based F-factor, listed in concentration when the hourly average section 3.3.5 of this appendix for each fuel, 5.1 Calculate and record heat input rate to concentration of O2 is > 14.0 percent O2, scf/mmBtu. an affected unit on an hourly basis, except as provided that this maximum %CO2w = Hourly concentration of CO2 during provided in sections 5.5 through 5.5.7. The concentration of 14.0 percent O2 is also unit operation, percent CO2 wet basis. used in the calculation of heat input for owner or operator may choose to use the For boilers, a minimum concentration of that hour. For stationary gas turbines, a provisions specified in § 75.16(e) or in 5.0 percent CO2 may be substituted for maximum concentration of 19.0 percent section 2.1.2 of appendix D to this part in the measured concentration when the O2 may be substituted for measured conjunction with the procedures provided in hourly average concentration of CO2 is < diluent gas concentration values during 5.0 percent CO2, provided that this hours when the hourly average sections 5.6 through 5.6.2 to apportion heat input among each unit using the common minimum concentration of 5.0 percent concentration of O2 is > 19.0 percent O2, CO2 is also used in the calculation of stack or common pipe header. provided that this maximum CO2 mass emissions for that hour. For concentration of 19.0 percent O2 is also 5.2 For an affected unit that has a flow stationary gas turbines, a minimum used in the calculation of heat input for monitor (or approved alternate monitoring concentration of 1.0 percent CO2 may be that hour. system under subpart E of this part for substituted for measured diluent gas F, Fc = F-factor or carbon-based Fc-factor from measuring volumetric flow rate) and a concentration values during hours when section 3.3.5 of this appendix. diluent gas (O2 or CO2) monitor, use the the hourly average concentration of CO2 20.9 = Percentage of O2 in ambient air. recorded data from these monitors and one is < 1.0 percent CO2, provided that this %H2O = Moisture content of gas in the stack, minimum concentration of 1.0 percent of the following equations to calculate hourly percent. CO2 is also used in the calculation of heat input rate (in mmBtu/hr). * * * * * CO2 mass emissions for that hour. 5.2.1 When measurements of CO2 72. Appendix F to part 75 is amended by 5.2.2 When measurements of CO2 revising sections 5 through 5.2.4; adding concentration are on a wet basis, use the concentration are on a dry basis, use the sections 5.3 through 5.3.2; revising sections following equation: following equation:

()100 − %HO  %CO  =  2  2d  HI Q h   (Eq . F-16)  100Fc  100

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Where: %CO2d = Hourly concentration of CO2 during %H2O = Moisture content of gas in the stack, HI = Hourly heat input rate during unit unit operation, percent CO2 dry basis. percent. For boilers, a minimum concentration of operation, mmBtu/hr. 5.2.3 When measurements of O2 5.0 percent CO2 may be substituted for Qh = Hourly average volumetric flow rate concentration are on a wet basis, use the the measured concentration when the during unit operation, wet basis, scfh. following equation: hourly average concentration of CO2 is < Fc = Carbon-based F-Factor, listed in section 5.0 percent CO2, provided that this 3.3.5 of this appendix for each fuel, scf/ minimum concentration of 5.0 percent mmBtu. CO2 is also used in the calculation of CO2 mass emissions for that hour. For stationary gas turbines, a minimum concentration of 1.0 percent CO2 may be substituted for measured diluent gas concentration values during hours when the hourly average concentration of CO2 is < 1.0 percent CO2, provided that this minimum concentration of 1.0 percent CO2 is also used in the calculation of CO2 mass emissions for that hour.

() − − 1 []20./%% 9 100() 100 HOO2 2w HI= Q (.Eq F-17) w F 20. 9

Where: HI = Hourly heat input rate during 5.2.4 When measurements of O2 unit operation, mmBtu/hr. concentration are on a dry basis, use the Qw = Hourly average volumetric flow rate following equation: 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.

()100 − %HO  ()20.% 9 − O  HI= Q  2   2d  (.Eq F-18) w  100 F   20. 9 

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Where: 5.3.2 Calculate total cumulative heat data procedures in § 75.36, oil samples for HI = Hourly heat input rate during input for a unit or common stack using a flow measuring GCV may be taken weekly, and monitor and diluent monitor to calculate heat unit operation, mmBtu/hr. the procedures specified in appendix D to input, using the following equation: this part for determining the mass rate of oil Qw = Hourly average volumetric flow during unit operation, wet basis, scfh. the current quarter consumed per hour are optional. HI= ∑ HI(. Eq F-18b) 5.5.2 When the unit is combusting F = Dry basis F-factor, listed in c q gaseous fuels, use the following equation to q=1 section 3.3.5 of this appendix for each calculate heat input rate from gaseous fuels fuel, dscf/mmBtu. Where: for each hour: %H2O = Moisture content of the stack gas, HIc = Total heat input for the year to date, percent. mmBtu. ()× %O2d = Hourly concentration of O2 during Qg GCV g HIq = Total heat input for the quarter, HI = (Eq . F-20) unit operation, percent O2 dry basis. For mmBtu. g 6 boilers, a maximum concentration of 10 5.4 [Reserved] 14.0 percent O2 may be substituted for Where: the measured concentration when the 5.5 For a gas-fired or oil-fired unit that HIg = Hourly heat input rate from gaseous hourly average concentration of O2 is > does not have a flow monitor and is using the fuel, mmBtu/hour. 14.0 percent O2, provided that this procedures specified in appendix D to this Qg = Metered flow rate of gaseous fuel maximum concentration of 14.0 percent part to monitor SO2 emissions or for any unit using a common stack for which the owner combusted during unit operation, O2 is also used in the calculation of CO2 hundred cubic feet. mass emissions for that hour. For or operator chooses to determine heat input by fuel sampling and analysis, use the GCVg = Gross calorific value of gaseous fuel, stationary gas turbines, a maximum as determined by sampling (for each concentration of 19.0 percent O2 may be following procedures to calculate hourly heat input rate in mmBtu/hr. The procedures of delivery for gaseous fuel in lots, for each substituted for measured diluent gas daily gas sample for gaseous fuel concentration values during hours when section 5.5.3 of this appendix shall not be used to determine heat input from a coal unit delivered by pipeline, for each hourly the hourly average concentration of O2 is that is required to comply with the average for gas measured hourly with a > 19.0 percent O2, provided that this gas chromatograph, or for each monthly maximum concentration of 19.0 percent provisions of this part for monitoring, recording, and reporting NOX mass emissions sample of pipeline natural gas, or as O2 is also used in the calculation of CO2 under a State or federal NOX mass emission verified by the contractual supplier at mass emissions for that hour. reduction program. least once every month pipeline natural 5.3 Heat Input Summation (for Heat Input 5.5.1(a) When the unit is combusting oil, gas is combusted, as specified in section Determined Using a Flow Monitor and use the following equation to calculate 2.3 of appendix D to this part) using Diluent Monitor) hourly heat input rate: ASTM D1826–88, ASTM D3588–91, 5.3.1 Calculate total quarterly heat input ASTM D4891–89, GPA Standard 2172– for a unit or common stack using a flow = GCVo 86 ‘‘Calculation of Gross Heating Value, monitor and diluent monitor to calculate heat HIo M o 6 (Eq . F-19) Relative Density and Compressibility input, using the following equation: 10 Factor for Natural Gas Mixtures from Where: Compositional Analysis,’’ or GPA n HIo = Hourly heat input rate from oil, Standard 2261–90 ‘‘Analysis for Natural = HIq∑ HI i t i ( Eq . F-18a) mmBtu/hr. Gas and Similar Gaseous Mixtures by hour=1 Mo = Mass rate of oil consumed per hour, as Gas Chromatography,’’ Btu/100 scf Where: determined using procedures in (incorporated by reference under § 75.6). appendix D to this part, in lb/hr, tons/ 106 = Conversion of Btu to mmBtu. HIq = Total heat input for the quarter, hr, or kg/hr. * * * * * GCVo = Gross calorific value of oil, as mmBtu. 5.6 Heat Input Rate Apportionment for HIi = Hourly heat input rate during unit measured by ASTM D240–87 Units Sharing a Common Stack or Pipe operation, using Equation F–15, F–16, F– (Reapproved 1991), ASTM D2015–91, or 5.6.1 Where applicable, the owner or 17, or F–18, mmBtu/hr. ASTM D2382–88 for each oil sample operator of an affected unit that determines ti = Hourly operating time for the unit or under section 2.2 of appendix D to this common stack, hour or fraction of an part, Btu/unit mass (incorporated by heat input rate at the unit level by hour (in equal increments that can range reference under § 75.6). apportioning the heat input monitored at a from one hundredth to one quarter of an 106 = Conversion of Btu to mmBtu. common stack or common pipe using hour, at the option of the owner or (b) When performing oil sampling and megawatts should apportion the heat input operator). analysis solely for the purpose of the missing rate using the following equation:

     t   MW t  HI= HI CS i i (Eq . F-21a) i CS    n   t i  ∑ MWi t i   i=1 

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

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

     t   SF t  HI= HI CS i i (Eq . F-21b) i CS    n   t i  ∑SFi t i   i=1 

Where: or natural gas in § 72.2 of this chapter, SO2 (Eq. G–1) HIi = Heat input rate for a unit, mmBtu/hr. emissions are determined in accordance with Where: HICS = Heat input rate at the common stack § 75.11(e)(1). or pipe, mmBtu/hr. * * * * * SF = Gross steam load, lb/hr. E= ()(. ER (HI) Eq F-23) Wc = Carbon burned, lb/day, determined h using fuel sampling and analysis and ti = Operating time at a particular unit, hour Where: or fraction of an hour (in equal fuel feed rates. Collect at least one fuel increments that can range from one Eh = Hourly SO2 mass emissions, lb/hr. sample during each week that the unit combusts coal, one sample per each hundredth to one quarter of an hour, at ER = Applicable SO2 default emission rate the option of the owner or operator). from section 2.3.1.1 or 2.3.2.1.1 of shipment or delivery for oil and diesel fuel, one fuel sample for each delivery tCS = Operating time at common stack, hour appendix D to this part, lb/mmBtu. or fraction of an hour (in equal HI = Hourly heat input, as determined using for gaseous fuel in lots, one sample per increments that can range from one the procedures of section 5.2 of this day or per hour (as applicable) for each hundredth to one quarter of an hour, at appendix. gaseous fuel that is required to be sampled daily or hourly for gross the option of the owner or operator). 74. Appendix F is further amended by n = Total number of units using the common calorific value under section 2.3.5.6 of correcting section 8 to read as follows: stack. appendix D to this part, and one sample per month for each gaseous fuel that is i = Designation of a particular unit. 8. Procedures for NOX Mass Emissions required to be sampled monthly for gross 5.7 Heat Input Rate Summation for Units The owner or operator of a unit that is calorific value under section 2.3.4.1 or with Multiple Stacks or Pipes required to monitor, record, and report NOX 2.3.4.2 of appendix D to this part. Collect The owner or operator of an affected unit mass emissions under a State or federal NOX coal samples from a location in the fuel that determines the heat input rate at the unit mass emission reduction program must use handling system that provides a sample level by summing the heat input rates the procedures in section 8.1, 8.2, or 8.3, as representative of the fuel bunkered or monitored at multiple stacks or multiple applicable, to account for hourly NOX mass consumed during the week. Determine pipes should sum the heat input rates using emissions, and the procedures in section 8.4 the carbon content of each fuel sampling the following equation: using one of the following methods: to account for quarterly, seasonal, and annual ASTM D3178–89 or ASTM D5373–93 for NOX mass emissions to the extent that the n coal; ASTM D5291–92 ‘‘Standard Test provisions of subpart H of this part are ∑ HIs t s Methods for Instrumental Determination adopted as requirements under such a HI = s=1 (Eq . F-21c) of Carbon, Hydrogen, and Nitrogen in Unit t program. Petroleum Products and Lubricants,’’ Unit 75. Appendix G to part 75 is amended by ultimate analysis of oil, or computations Where: revising the paragraph defining the term based upon ASTM D3238–90 and either HIUnit = Heat input rate for a unit, mmBtu/ ‘‘Wc’’ that follows Equation G–1 and by ASTM D2502–87 or ASTM D2503–82 hr. revising the paragraph defining the term ‘‘Fc’’ (Reapproved 1987) for oil; and HIs = Heat input rate for each stack or duct that follows Equation G–4 to read as follows: computations based on ASTM D1945–91 leading from the unit, mmBtu/hr. or ASTM D1946–90 for gas. Use daily tUnit = Operating time for the unit, hour or Appendix G to Part 75—Determination of fuel feed rates from company records for fraction of the hour (in equal increments CO2 Emissions all fuels and the carbon content of the that can range from one hundredth to * * * * * most recent fuel sample under this one quarter of an hour, at the option of section to determine tons of carbon per the owner or operator). 2. Procedures for Estimating CO2 Emissions day from combustion of each fuel. (All ts = Operating time during which the unit is From Combustion ASTM methods are incorporated by exhausting through the stack or duct, * * * * * reference under § 75.6.) Where more than one fuel is combusted during a calendar hour or fraction of the hour (in equal 2.1 * * * increments that can range from one day, calculate total tons of carbon for the hundredth to one quarter of an hour, at day from all fuels. the option of the owner or operator). * * * * * 73. Appendix F is further amended by 2.3 * * * revising section 7 to read as follows: (Eq. G–4) 7. Procedures for SO2 Mass Emissions at Where: Units With SO2 Continuous Emission Monitoring Systems During the Combustion * * * * * of Pipeline Natural Gas or Natural Gas Fc = Carbon based F-factor, 1040 scf/mmBtu for natural gas; 1,240 scf/mmBtu for The owner or operator shall use the crude, residual, or distillate oil; and following equation to calculate hourly SO2 calculated according to the procedures in mass emissions as allowed for units with SO2 section 3.3.5 of appendix F to this part continuous emission monitoring systems if, for other gaseous fuels. during the combustion of gaseous fuel that meets the definition of pipeline natural gas * * * * *

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76. Appendix G to part 75 is amended by 5.1.1 Most Recent Previous Data section to substitute for missing carbon adding new sections 5 through 5.3 to read as Substitute the most recent, previous carbon content data. follows: content value available for that fuel type (gas, 5.2.1 In all cases (i.e., for weekly coal 5. Missing Data Substitution Procedures for oil, or coal) of the same grade (for oil) or rank samples or composite oil samples from Fuel Analytical Data (for coal). To the extent practicable, use a continuous sampling, for oil samples taken from the storage tank after transfer of a new Use the following procedures to substitute carbon content value from the same fuel for missing fuel analytical data used to supply. Where no previous carbon content delivery of fuel, for as-delivered samples of calculate CO2 mass emissions under this data are available for a particular fuel type or oil, diesel fuel, or gaseous fuel delivered in appendix. rank of coal, substitute the default carbon lots, and for gaseous fuel that is supplied by 5.1 Missing Carbon Content Data Prior to content from Table G–1 of this appendix. a pipeline and sampled monthly, daily or 4/1/2000 5.1.2 [Reserved] hourly for gross calorific value) when carbon content data is missing, report the Prior to April 1, 2000, follow either the 5.2 Missing Carbon Content Data On and appropriate default value from Table G–1. procedures of this section or the procedures After 4/1/2000 of section 5.2 of this appendix to substitute 5.2.2 The missing data values in Table G– for missing carbon content data. On and after Prior to April 1, 2000, follow either the 1 shall be reported whenever the results of April 1, 2000, use the procedures of section procedures of this section or the procedures a required sample of fuel carbon content are 5.2 of this appendix to substitute for missing of section 5.1 of this appendix to substitute either missing or invalid. The substitute data carbon content data, not the procedures of for missing carbon content data. On and after value shall be used until the next valid this section. April 1, 2000, use the procedures of this carbon content sample is obtained.

TABLE G±1.ÐMISSING DATA SUBSTITUTION PROCEDURES FOR MISSING CARBON CONTENT DATA

Parameter Sampling technique/frequency Missing data value

Oil and coal carbon content ...... All oil and coal samples, prior to April 1, 2000 Most recent, previous carbon content value available for that grade of oil, or default value, in this table. Gas carbon content ...... All gaseous fuel samples, prior to April 1, Most recent, previous carbon content value 2000. available for that type of gaseous fuel, or default value, in this table. Default coal carbon content ...... All, on and after April 1, 2000 ...... Anthracite: 90.0 percent. Bituminous: 85.0 percent. Subbituminous/Lignite: 75.0 percent. Default oil carbon content ...... All, on and after April 1, 2000 ...... 90.0 percent. Default gas carbon content ...... All, on and after April 1, 2000 ...... Natural gas: 75.0 percent. Other gaseous fuels: 90.0 percent.

5.3 Gross Calorific Value Data Appendix H to Part 75—Revised Appendix J to Part 75—Compliance Dates For a gas-fired unit using the procedures of Traceability Protocol No. 1 for Revised Recordkeeping Requirements and Missing Data Procedures section 2.3 of this appendix to determine CO2 77. Appendix H to part 75 is removed and emissions, substitute for missing gross reserved. 78. Appendix J to part 75 is removed and calorific value data used to calculate heat reserved. input by following the missing data procedures for gross calorific value in section [FR Doc. 99–8939 Filed 5–25–99; 8:45 am] 2.4 of appendix D to this part. BILLING CODE 6560±50±U

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