  Apr. 20, 2020

      Title 40
      Protection of Environment
      Part 60 (§§ 60.1 to 60.499)
      Revised as of July 1, 2020
      Containing a codification of documents of general applicability and future effect
      As of July 1, 2020

        Published by the Office of the Federal Register National Archives and Records Administration as a Special Edition of the Federal Register

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      Table of Contents
      Page

        Explanation
        v

        Title 40:

          Chapter I—Environmental Protection Agency (Continued)
          3

        Finding Aids:
        Table of CFR Titles and Chapters
        645
        Alphabetical List of Agencies Appearing in the CFR
        665
        List of CFR Sections Affected
        675

      Cite this Code: CFR

      To cite the regulations in this volume use title, part and section number. Thus, 40 CFR 60.1 refers to title 40, part 60, section 1.

      Explanation
      The Code of Federal Regulations is a codification of the general and permanent rules published in the Federal Register by the Executive departments and agencies of the Federal Government. The Code is divided into 50 titles which represent broad areas subject to Federal regulation. Each title is divided into chapters which usually bear the name of the issuing agency. Each chapter is further subdivided into parts covering specific regulatory areas.
      Each volume of the Code is revised at least once each calendar year and issued on a quarterly basis approximately as follows:

        Title 1 through Title 16
        as of January 1
        Title 17 through Title 27
        as of April 1
        Title 28 through Title 41
        as of July 1
        Title 42 through Title 50
        as of October 1

      The appropriate revision date is printed on the cover of each volume.

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        “[RESERVED]” TERMINOLOGY
        The term “[Reserved]” is used as a place holder within the Code of Federal Regulations. An agency may add regulatory information at a “[Reserved]” location at any time. Occasionally “[Reserved]” is used editorially to indicate that a portion of the CFR was left vacant and not accidentally dropped due to a printing or computer error.

        INCORPORATION BY REFERENCE

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          What is a proper incorporation by reference? The Director of the Federal Register will approve an incorporation by reference only when the requirements of 1 CFR part 51 are met. Some of the elements on which approval is based are:
        (a) The incorporation will substantially reduce the volume of material published in the Federal Register.
        (b) The matter incorporated is in fact available to the extent necessary to afford fairness and uniformity in the administrative process.
        (c) The incorporating document is drafted and submitted for publication in accordance with 1 CFR part 51.

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        The e-CFR is a regularly updated, unofficial editorial compilation of CFR material and Federal Register amendments, produced by the Office of the Federal Register and the Government Publishing Office. It is available at www.ecfr.gov.

          Oliver A. Potts,

          Director,

          Office of the Federal Register.

          July 1, 2020.

      THIS TITLE
      Title 40—Protection of Environment is composed of thirty-seven volumes. The parts in these volumes are arranged in the following order: Parts 1-49, parts 50-51, part 52 (52.01-52.1018), part 52 (52.1019-52.2019), part 52 (52.2020-end of part 52), parts 53-59, part 60 (60.1-60.499), part 60 (60.500-end of part 60, sections), part 60 (Appendices), parts 61-62, part 63 (63.1-63.599), part 63 (63.600-63.1199), part 63 (63.1200-63.1439), part 63 (63.1440-63.6175), part 63 (63.6580-63.8830), part 63 (63.8980-end of part 63), parts 64-71, parts 72-79, part 80, part 81, parts 82-86, parts 87-95, parts 96-99, parts 100-135, parts 136-149, parts 150-189, parts 190-259, parts 260-265, parts 266-299, parts 300-399, parts 400-424, parts 425-699, parts 700-722, parts 723-789, parts 790-999, parts 1000-1059, and part 1060 to end. The contents of these volumes represent all current regulations codified under this title of the CFR as of July 1, 2020.
      Chapter I—Environmental Protection Agency appears in all thirty-seven volumes. OMB control numbers for title 40 appear in § 9.1 of this chapter.
      Chapters IV-VIII—Regulations issued by the Environmental Protection Agency and Department of Justice, Council on Environmental Quality, Chemical Safety and Hazard Investigation Board, Environmental Protection Agency and Department of Defense; Uniform National Discharge Standards for Vessels of the Armed Forces, and the Gulf Coast Ecosystem Restoration Council appear in volume thirty seven.
      For this volume, Ann Worley was Chief Editor. The Code of Federal Regulations publication program is under the direction of John Hyrum Martinez, assisted by Stephen J. Frattini.

    40 CFR Ch. I (7-1-20 Edition)
    Environmental Protection Agency

        Title 40—Protection of Environment
        (This book contains part 60, §§ 60.1 to 60.499)

        Part

            chapter i—Environmental Protection Agency (Continued)
          60

          CHAPTER I—ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)

          Editorial Note:
          Nomenclature changes to chapter I appear at 65 FR 47324, 47325, Aug. 2, 2000; 66 FR 34375, 34376, June 28, 2001.

          SUBCHAPTER C—AIR PROGRAMS (CONTINUED)

        Part
        Page

          60
          Standards of performance for new stationary sources
          5

        SUBCHAPTER C—AIR PROGRAMS (CONTINUED)

          Pt. 60
          PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

              Subpart A—General Provisions
              Sec.
              60.1
              Applicability.
              60.2
              Definitions.
              60.3
              Units and abbreviations.
              60.4
              Address.
              60.5
              Determination of construction or modification.
              60.6
              Review of plans.
              60.7
              Notification and record keeping.
              60.8
              Performance tests.
              60.9
              Availability of information.
              60.10
              State authority.
              60.11
              Compliance with standards and maintenance requirements.
              60.12
              Circumvention.
              60.13
              Monitoring requirements.
              60.14
              Modification.
              60.15
              Reconstruction.
              60.16
              Priority list.
              60.17
              Incorporations by reference.
              60.18
              General control device and work practice requirements.
              60.19
              General notification and reporting requirements.
              Table 1 to Subpart A of Part 60—Detection Sensitivity Levels (grams per hour)

              Subpart B—Adoption and Submittal of State Plans for Designated Facilities
              60.20
              Applicability.
              60.21
              Definitions.
              60.22
              Publication of guideline documents, emission guidelines, and final compliance times.
              60.23
              Adoption and submittal of State plans; public hearings.
              60.24
              Emission standards and compliance schedules.
              60.25
              Emission inventories, source surveillance, reports.
              60.26
              Legal authority.
              60.27
              Actions by the Administrator.
              60.28
              Plan revisions by the State.
              60.29
              Plan revisions by the Administrator.

              Subpart Ba—Adoption and Submittal of State Plans for Designated Facilities
              60.20a
              Applicability.
              60.21a
              Definitions.
              60.22a
              Publication of emission guidelines.
              60.23a
              Adoption and submittal of State plans; public hearings.
              60.24a
              Standards of performance and compliance schedules.
              60.25a
              Emission inventories, source surveillance, reports.
              60.26a
              Legal authority.
              60.27a
              Actions by the Administrator.
              60.28a
              Plan revisions by the State.
              60.29a
              Plan revisions by the Administrator.

              Subpart C—Emission Guidelines and Compliance Times
              60.30
              Scope.
              60.31
              Definitions.

              Subpart Ca [Reserved]

              Subpart Cb—Emissions Guidelines and Compliance Times for Large Municipal Waste Combustors That Are Constructed on or Before September 20, 1994
              60.30b
              Scope and delegation of authority.
              60.31b
              Definitions.
              60.32b
              Designated facilities.
              60.33b
              Emission guidelines for municipal waste combustor metals, acid gases, organics, and nitrogen oxides.
              60.34b
              Emission guidelines for municipal waste combustor operating practices.
              60.35b
              Emission guidelines for municipal waste combustor operator training and certification.
              60.36b
              Emission guidelines for municipal waste combustor fugitive ash emissions.
              60.37b
              Emission guidelines for air curtain incinerators.
              60.38b
              Compliance and performance testing.
              60.39b
              Reporting and recordkeeping guidelines and compliance schedules.
              Table 1 to Subpart Cb of Part 60—Nitrogen Oxides Guidelines for Designated Facilities
              Table 2 to Subpart Cb of Part 60—Nitrogen Oxides Limits for Existing Designated Facilities Included in an Emissions Averaging Plan at a Municipal Waste Combustor Plant
              Table 3 to Subpart Cb of Part 60—Municipal Waste Combustor Operating Guidelines

              Subpart Cc—Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills
              60.30c
              Scope.
              60.31c
              Definitions.
              60.32c
              Designated facilities.
              60.33c
              Emission guidelines for municipal solid waste landfill emissions.
              60.34c
              Test methods and procedures.

              60.35c
              Reporting and recordkeeping guidelines.
              60.36c
              Compliance times.

              Subpart Cd—Emissions Guidelines and Compliance Times for Sulfuric Acid Production Units
              60.30d
              Designated facilities.
              60.31d
              Emissions guidelines.
              60.32d
              Compliance times.

              Subpart Ce—Emission Guidelines and Compliance Times for Hospital/Medical/Infectious Waste Incinerators
              60.30e
              Scope.
              60.31e
              Definitions.
              60.32e
              Designated facilities.
              60.33e
              Emission guidelines.
              60.34e
              Operator training and qualification guidelines.
              60.35e
              Waste management guidelines.
              60.36e
              Inspection guidelines.
              60.37e
              Compliance, performance testing, and monitoring guidelines.
              60.38e
              Reporting and recordkeeping guidelines.
              60.39e
              Compliance times.
              Table 1A to Subpart Ce of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Designated Facilities as Defined in § 60.32e(a)(1)
              Table 1B to Subpart Ce of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Designated Facilities as Defined in § 60.32e(a)(1) and (a)(2)
              Table 2A to Subpart Ce of Part 60—Emissions Limits for Small HMIWI Which Meet the Criteria Under § 60.33e(b)(1)
              Table 2B to Subpart Ce of Part 60—Emissions Limits for Small HMIWI Which Meet the Criteria Under § 60.33e(b)(2)

              Subpart Cf—Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills
              60.30f
              Scope and delegated authorities.
              60.31f
              Designated facilities.
              60.32f
              Compliance times.
              60.33f
              Emission Guidelines for municipal solid waste landfill emissions.
              60.34f
              Operational standards for collection and control systems.
              60.35f
              Test methods and procedures.
              60.36f
              Compliance provisions.
              60.37f
              Monitoring of operations.
              60.38f
              Reporting guidelines.
              60.39f
              Recordkeeping guidelines.
              60.40f
              Specifications for active collection systems.
              60.41f
              Definitions.

              Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators
              60.40
              Applicability and designation of affected facility.
              60.41
              Definitions.
              60.42
              Standard for particulate matter (PM).
              60.43
              Standard for sulfur dioxide (SO2).
              60.44
              Standard for nitrogen oxides (NOX).
              60.45
              Emission and fuel monitoring.
              60.46
              Test methods and procedures.

              Subpart Da—Standards of Performance for Electric Utility Steam Generating Units
              60.40Da
              Applicability and designation of affected facility.
              60.41Da
              Definitions.
              60.42Da
              Standard for particulate matter (PM).
              60.43Da
              Standards for sulfur dioxide (SO2).
              60.44Da
              Standards for nitrogen oxides (NOX).
              60.45Da

              Alternative standards for combined nitrogen oxides (NOX) and carbon monoxide (CO).
              60.46Da
              [Reserved]
              60.47Da
              Commercial demonstration permit.
              60.48Da
              Compliance provisions.
              60.49Da
              Emission monitoring.
              60.50Da
              Compliance determination procedures and methods.
              60.51Da
              Reporting requirements.
              60.52Da
              Recordkeeping requirements.

              Subpart Db—Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units
              60.40b
              Applicability and delegation of authority.
              60.41b
              Definitions.
              60.42b
              Standard for sulfur dioxide (SO2).
              60.43b
              Standard for particulate matter (PM).
              60.44b
              Standard for nitrogen oxides (NOX).
              60.45b
              Compliance and performance test methods and procedures for sulfur dioxide.
              60.46b
              Compliance and performance test methods and procedures for particulate matter and nitrogen oxides.
              60.47b
              Emission monitoring for sulfur dioxide.
              60.48b
              Emission monitoring for particulate matter and nitrogen oxides.
              60.49b
              Reporting and recordkeeping requirements.

              Subpart Dc—Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units
              60.40c
              Applicability and delegation of authority.
              60.41c
              Definitions.
              60.42c
              Standard for sulfur dioxide (SO2).

              60.43c
              Standard for particulate matter (PM).
              60.44c
              Compliance and performance test methods and procedures for sulfur dioxide.
              60.45c
              Compliance and performance test methods and procedures for particulate matter.
              60.46c
              Emission monitoring for sulfur dioxide.
              60.47c
              Emission monitoring for particulate matter.
              60.48c
              Reporting and recordkeeping requirements.

              Subpart Ea—Standards of Performance for Municipal Waste Combustors for Which Construction Is Commenced After December 20, 1989 and On or Before September 20, 1994
              60.50a
              Applicability and delegation of authority.
              60.51a
              Definitions.
              60.52a
              Standard for municipal waste combustor metals.
              60.53a
              Standard for municipal waste combustor organics.
              60.54a
              Standard for municipal waste combustor acid gases.
              60.55a
              Standard for nitrogen oxides.
              60.56a
              Standard for municipal waste combustor operating practices.
              60.57a
              [Reserved]
              60.58a
              Compliance and performance testing.
              60.59a
              Reporting and recordkeeping requirements.

              Subpart Eb—Standards of Performance for Large Municipal Waste Combustors for Which Construction is Commenced After September 20, 1994 or for Which Modification or Reconstruction is Commenced After June 19, 1996
              60.50b
              Applicability and delegation of authority.
              60.51b
              Definitions.
              60.52b
              Standards for municipal waste combustor metals, acid gases, organics, and nitrogen oxides.
              60.53b
              Standards for municipal waste combustor operating practices.
              60.54b
              Standards for municipal waste combustor operator training and certification.
              60.55b
              Standards for municipal waste combustor fugitive ash emissions.
              60.56b
              Standards for air curtain incinerators.
              60.57b
              Siting requirements.
              60.58b
              Compliance and performance testing.
              60.59b
              Reporting and recordkeeping requirements.

              Subpart Ec—Standards of Performance for New Stationary Sources: Hospital/Medical/Infectious Waste Incinerators
              60.50c
              Applicability and delegation of authority.
              60.51c
              Definitions.
              60.52c
              Emission limits.
              60.53c
              Operator training and qualification requirements.
              60.54c
              Siting requirements.
              60.55c
              Waste management plan.
              60.56c
              Compliance and performance testing.
              60.57c
              Monitoring requirements.
              60.58c
              Reporting and recordkeeping requirements.
              Table 1 to Subpart Ec of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Affected Facilities as Defined in § 60.50c(a)(1) and (2)
              Table 1A to Subpart Ec of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Affected Facilities as Defined in § 60.50c(a)(1) and (2)
              Table 1B to Subpart Ec of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Affected Facilities as Defined in § 60.50c(a)(3) and (4)
              Table 2 to Subpart Ec of Part 60—Toxic Equivalency Factors
              Table 3 to Subpart Ec of Part 60—Operating Parameters To Be Monitored and Minimum Measurement and Recording Frequencies

              Subpart F—Standards of Performance for Portland Cement Plants
              60.60
              Applicability and designation of affected facility.
              60.61
              Definitions.
              60.62
              Standard for particulate matter.
              60.63
              Monitoring of operations.
              60.64
              Test methods and procedures.
              60.65
              Recordkeeping and reporting requirements.
              60.66
              Delegation of authority.

              Subpart G—Standards of Performance for Nitric Acid Plants
              60.70
              Applicability and designation of affected facility.
              60.71
              Definitions.
              60.72
              Standard for nitrogen oxides.
              60.73
              Emission monitoring.

              60.74
              Test methods and procedures.

              Subpart Ga—Standards of Performance for Nitric Acid Plants for Which Construction, Reconstruction, or Modification Commenced After October 14, 2011
              60.70a
              Applicability and designation of affected facility.
              60.71a
              Definitions.
              60.72a
              Standards.
              60.73a
              Emissions testing and monitoring.
              60.74a
              Affirmative defense for violations of emission standards during malfunction.
              60.75a
              Calculations.
              60.76a
              Recordkeeping.
              60.77a
              Reporting.

              Subpart H—Standards of Performance for Sulfuric Acid Plants
              60.80
              Applicability and designation of affected facility.
              60.81
              Definitions.
              60.82
              Standard for sulfur dioxide.
              60.83
              Standard for acid mist.
              60.84
              Emission monitoring.
              60.85
              Test methods and procedures.

              Subpart I—Standards of Performance for Hot Mix Asphalt Facilities
              60.90
              Applicability and designation of affected facility.
              60.91
              Definitions.
              60.92
              Standard for particulate matter.
              60.93
              Test methods and procedures.

              Subpart J—Standards of Performance for Petroleum Refineries
              60.100
              Applicability, designation of affected facility, and reconstruction.
              60.101
              Definitions.
              60.102
              Standard for particulate matter.
              60.103
              Standard for carbon monoxide.
              60.104
              Standards for sulfur oxides.
              60.105
              Monitoring of emissions and operations.
              60.106
              Test methods and procedures.
              60.107
              Reporting and recordkeeping requirements.
              60.108
              Performance test and compliance provisions.
              60.109
              Delegation of authority.

              Subpart Ja—Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007
              60.100a
              Applicability, designation of affected facility, and reconstruction.
              60.101a
              Definitions.
              60.102a
              Emissions limitations.
              60.103a
              Design, equipment, work practice or operational standards.
              60.104a
              Performance tests.
              60.105a
              Monitoring of emissions and operations for fluid catalytic cracking units (FCCU) and fluid coking units (FCU).
              60.106a
              Monitoring of emissions and operations for sulfur recovery plants.
              60.107a
              Monitoring of emissions and operations for fuel gas combustion devices and flares.
              60.108a
              Recordkeeping and reporting requirements.
              60.109a
              Delegation of authority.
              Table 1 to Subpart Ja of Part 60—Table 1 to subpart Ja of Part 60—Molar Exhaust Volumes and Molar Heat Content of Fuel Gas Constituents

              Subpart K—Standards of Performance for Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
              60.110
              Applicability and designation of affected facility.
              60.111
              Definitions.
              60.112
              Standard for volatile organic compounds (VOC).
              60.113
              Monitoring of operations.

              Subpart Ka—Standards of Performance for Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984
              60.110a
              Applicability and designation of affected facility.
              60.111a
              Definitions.
              60.112a
              Standard for volatile organic compounds (VOC).
              60.113a
              Testing and procedures.
              60.114a
              Alternative means of emission limitation.
              60.115a
              Monitoring of operations.

              Subpart Kb—Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
              60.110b
              Applicability and designation of affected facility.
              60.111b
              Definitions.
              60.112b
              Standard for volatile organic compounds (VOC).
              60.113b
              Testing and procedures.
              60.114b
              Alternative means of emission limitation.
              60.115b
              Reporting and recordkeeping requirements.
              60.116b
              Monitoring of operations.
              60.117b
              Delegation of authority.

              Subpart L—Standards of Performance for Secondary Lead Smelters
              60.120
              Applicability and designation of affected facility.
              60.121
              Definitions.
              60.122
              Standard for particulate matter.
              60.123
              Test methods and procedures.

              Subpart M—Standards of Performance for Secondary Brass and Bronze Production Plants
              60.130
              Applicability and designation of affected facility.
              60.131
              Definitions.
              60.132
              Standard for particulate matter.
              60.133
              Test methods and procedures.

              Subpart N—Standards of Performance for Primary Emissions from Basic Oxygen Process Furnances for Which Construction is Commenced After June 11, 1973
              60.140
              Applicability and designation of affected facility.
              60.141
              Definitions.
              60.142
              Standard for particulate matter.
              60.143
              Monitoring of operations.
              60.144
              Test methods and procedures.

              Subpart Na—Standards of Performance for Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983
              60.140a
              Applicability and designation of affected facilities.
              60.141a
              Definitions.
              60.142a
              Standards for particulate matter.
              60.143a
              Monitoring of operations.
              60.144a
              Test methods and procedures.
              60.145a
              Compliance provisions.

              Subpart O—Standards of Performance for Sewage Treatment Plants
              60.150
              Applicability and designation of affected facility.
              60.151
              Definitions.
              60.152
              Standard for particulate matter.
              60.153
              Monitoring of operations.
              60.154
              Test methods and procedures.
              60.155
              Reporting.
              60.156
              Delegation of authority.

              Subpart P—Standards of Performance for Primary Copper Smelters
              60.160
              Applicability and designation of affected facility.
              60.161
              Definitions.
              60.162
              Standard for particulate matter.
              60.163
              Standard for sulfur dioxide.
              60.164
              Standard for visible emissions.
              60.165
              Monitoring of operations.
              60.166
              Test methods and procedures.

              Subpart Q—Standards of Performance for Primary Zinc Smelters
              60.170
              Applicability and designation of affected facility.
              60.171
              Definitions.
              60.172
              Standard for particulate matter.
              60.173
              Standard for sulfur dioxide.
              60.174
              Standard for visible emissions.
              60.175
              Monitoring of operations.
              60.176
              Test methods and procedures.

              Subpart R—Standards of Performance for Primary Lead Smelters
              60.180
              Applicability and designation of affected facility.
              60.181
              Definitions.
              60.182
              Standard for particulate matter.
              60.183
              Standard for sulfur dioxide.
              60.184
              Standard for visible emissions.
              60.185
              Monitoring of operations.
              60.186
              Test methods and procedures.

              Subpart S—Standards of Performance for Primary Aluminum Reduction Plants
              60.190
              Applicability and designation of affected facility.
              60.191
              Definitions.
              60.192
              Standard for fluorides.
              60.193
              Standard for visible emissions.
              60.194
              Monitoring of operations.
              60.195
              Test methods and procedures.

              Subpart T—Standards of Performance for the Phosphate Fertilizer Industry: Wet-Process Phosphoric Acid Plants
              60.200
              Applicability and designation of affected facility.
              60.201
              Definitions.
              60.202
              Standard for fluorides.
              60.203
              Monitoring of operations.
              60.204
              Test methods and procedures.
              60.205
              Recordkeeping.

              Subpart U—Standards of Performance for the Phosphate Fertilizer Industry: Superphosphoric Acid Plants
              60.210
              Applicability and designation of affected facility.
              60.211
              Definitions.
              60.212
              Standard for fluorides.
              60.213
              Monitoring of operations.
              60.214
              Test methods and procedures.
              60.215
              Recordkeeping.

              Subpart V—Standards of Performance for the Phosphate Fertilizer Industry: Diammonium Phosphate Plants
              60.220

              Applicability and designation of affected facility.

              60.221
              Definitions.
              60.222
              Standard for fluorides.
              60.223
              Monitoring of operations.
              60.224
              Test methods and procedures.
              60.225
              Recordkeeping.

              Subpart W—Standards of Performance for the Phosphate Fertilizer Industry: Triple Superphosphate Plants
              60.230
              Applicability and designation of affected facility.
              60.231
              Definitions.
              60.232
              Standard for fluorides.
              60.233
              Monitoring of operations.
              60.234
              Test methods and procedures.
              60.235
              Recordkeeping.

              Subpart X—Standards of Performance for the Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
              60.240
              Applicability and designation of affected facility.
              60.241
              Definitions.
              60.242
              Standard for fluorides.
              60.243
              Monitoring of operations.
              60.244
              Test methods and procedures.
              60.245
              Recordkeeping.

              Subpart Y—Standards of Performance for Coal Preparation and Processing Plants
              60.250
              Applicability and designation of affected facility.
              60.251
              Definitions.
              60.252
              Standards for thermal dryers.
              60.253
              Standards for pneumatic coal-cleaning equipment.
              60.254
              Standards for coal processing and conveying equipment, coal storage systems, transfer and loading systems, and open storage piles.
              60.255
              Performance tests and other compliance requirements.
              60.256
              Continuous monitoring requirements.
              60.257
              Test methods and procedures.
              60.258
              Reporting and recordkeeping.

              Subpart Z—Standards of Performance for Ferroalloy Production Facilities
              60.260
              Applicability and designation of affected facility.
              60.261
              Definitions.
              60.262
              Standard for particulate matter.
              60.263
              Standard for carbon monoxide.
              60.264
              Emission monitoring.
              60.265
              Monitoring of operations.
              60.266
              Test methods and procedures.

              Subpart AA—Standards of Performance for Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
              60.270
              Applicability and designation of affected facility.
              60.271
              Definitions.
              60.272
              Standard for particulate matter.
              60.273
              Emission monitoring.
              60.274
              Monitoring of operations.
              60.275
              Test methods and procedures.
              60.276
              Recordkeeping and reporting requirements.

              Subpart AAa—Standards of Performance for Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983
              60.270a
              Applicability and designation of affected facility.
              60.271a
              Definitions.
              60.272a
              Standard for particulate matter.
              60.273a
              Emission monitoring.
              60.274a
              Monitoring of operations.
              60.275a
              Test methods and procedures.
              60.276a
              Recordkeeping and reporting requirements.

              Subpart BB—Standards of Performance for Kraft Pulp Mills
              60.280
              Applicability and designation of affected facility.
              60.281
              Definitions.
              60.282
              Standard for particulate matter.
              60.283
              Standard for total reduced sulfur (TRS).
              60.284
              Monitoring of emissions and operations.
              60.285
              Test methods and procedures.

              Subpart BBa—Standards of Performance for Kraft Pulp Mill Affected Sources for Which Construction, Reconstruction, or Modification Commenced After May 23, 2013
              60.280a
              Applicability and designation of affected facility.
              60.281a
              Definitions.
              60.282a
              Standard for filterable particulate matter.
              60.283a
              Standard for total reduced sulfur (TRS).
              60.284a
              Monitoring of emissions and operations.
              60.285a
              Test methods and procedures.
              60.286a
              Affirmative defense for violations of emission standards during malfunction.
              60.287a
              Recordkeeping.
              60.288a
              Reporting.

              Subpart CC—Standards of Performance for Glass Manufacturing Plants
              60.290
              Applicability and designation of affected facility.
              60.291
              Definitions.
              60.292
              Standards for particulate matter.
              60.293
              Standards for particulate matter from glass melting furnace with modified-processes.
              60.294-60.295
              [Reserved]
              60.296
              Test methods and procedures.

              Subpart DD—Standards of Performance for Grain Elevators
              60.300
              Applicability and designation of affected facility.
              60.301
              Definitions.
              60.302
              Standard for particulate matter.
              60.303
              Test methods and procedures.
              60.304
              Modifications.

              Subpart EE—Standards of Performance for Surface Coating of Metal Furniture
              60.310
              Applicability and designation of affected facility.
              60.311
              Definitions and symbols.
              60.312
              Standard for volatile organic compounds (VOC).
              60.313
              Performance tests and compliance provisions.
              60.314
              Monitoring of emissions and operations.
              60.315
              Reporting and recordkeeping requirements.
              60.316
              Test methods and procedures.

              Subpart FF [Reserved]

              Subpart GG—Standards of Performance for Stationary Gas Turbines
              60.330
              Applicability and designation of affected facility.
              60.331
              Definitions.
              60.332
              Standard for nitrogen oxides.
              60.333
              Standard for sulfur dioxide.
              60.334
              Monitoring of operations.
              60.335
              Test methods and procedures.

              Subpart HH—Standards of Performance for Lime Manufacturing Plants
              60.340
              Applicability and designation of affected facility.
              60.341
              Definitions.
              60.342
              Standard for particulate matter.
              60.343
              Monitoring of emissions and operations.
              60.344
              Test methods and procedures.

              Subpart KK—Standards of Performance for Lead-Acid Battery Manufacturing Plants
              60.370
              Applicability and designation of affected facility.
              60.371
              Definitions.
              60.372
              Standards for lead.
              60.373
              Monitoring of emissions and operations.
              60.374
              Test methods and procedures.

              Subpart LL—Standards of Performance for Metallic Mineral Processing Plants
              60.380
              Applicability and designation of affected facility.
              60.381
              Definitions.
              60.382
              Standard for particulate matter.
              60.383
              Reconstruction.
              60.384
              Monitoring of operations.
              60.385
              Recordkeeping and reporting requirements.
              60.386
              Test methods and procedures.

              Subpart MM—Standards of Performance for Automobile and Light Duty Truck Surface Coating Operations
              60.390
              Applicability and designation of affected facility.
              60.391
              Definitions.
              60.392
              Standards for volatile organic compounds.
              60.393
              Performance test and compliance provisions.
              60.394
              Monitoring of emissions and operations.
              60.395
              Reporting and recordkeeping requirements.
              60.396
              Reference methods and procedures.
              60.397
              Modifications.
              60.398
              Innovative technology waivers.

              Subpart NN—Standards of Performance for Phosphate Rock Plants
              60.400
              Applicability and designation of affected facility.
              60.401
              Definitions.
              60.402
              Standard for particulate matter.
              60.403
              Monitoring of emissions and operations.
              60.404
              Test methods and procedures.

              Subpart PP—Standards of Performance for Ammonium Sulfate Manufacture
              60.420
              Applicability and designation of affected facility.
              60.421
              Definitions.
              60.422
              Standards for particulate matter.
              60.423
              Monitoring of operations.
              60.424
              Test methods and procedures.

              Subpart QQ—Standards of Performance for the Graphic Arts Industry: Publication Rotogravure Printing
              60.430
              Applicability and designation of affected facility.
              60.431
              Definitions and notations.

              60.432
              Standard for volatile organic compounds.
              60.433
              Performance test and compliance provisions.
              60.434
              Monitoring of operations and recordkeeping.
              60.435
              Test methods and procedures.

              Subpart RR—Standards of Performance for Pressure Sensitive Tape and Label Surface Coating Operations
              60.440
              Applicability and designation of affected facility.
              60.441
              Definitions and symbols.
              60.442
              Standard for volatile organic compounds.
              60.443
              Compliance provisions.
              60.444
              Performance test procedures.
              60.445
              Monitoring of operations and recordkeeping.
              60.446
              Test methods and procedures.
              60.447
              Reporting requirements.

              Subpart SS—Standards of Performance for Industrial Surface Coating: Large Appliances
              60.450
              Applicability and designation of affected facility.
              60.451
              Definitions.
              60.452
              Standard for volatile organic compounds.
              60.453
              Performance test and compliance provisions.
              60.454
              Monitoring of emissions and operations.
              60.455
              Reporting and recordkeeping requirements.
              60.456
              Test methods and procedures.

              Subpart TT—Standards of Performance for Metal Coil Surface Coating
              60.460
              Applicability and designation of affected facility.
              60.461
              Definitions.
              60.462
              Standards for volatile organic compounds.
              60.463
              Performance test and compliance provisions.
              60.464
              Monitoring of emissions and operations.
              60.465
              Reporting and recordkeeping requirements.
              60.466
              Test methods and procedures.

              Subpart UU—Standards of Performance for Asphalt Processing and Asphalt Roofing Manufacture
              60.470
              Applicability and designation of affected facilities.
              60.471
              Definitions.
              60.472
              Standards for particulate matter.
              60.473
              Monitoring of operations.
              60.474
              Test methods and procedures.

              Subpart VV—Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for which Construction, Reconstruction, or Modification Commenced After January 5, 1981, and on or Before November 7, 2006
              60.480
              Applicability and designation of affected facility.
              60.481
              Definitions.
              60.482-1
              Standards: General.
              60.482-2
              Standards: Pumps in light liquid service.
              60.482-3
              Standards: Compressors.
              60.482-4
              Standards: Pressure relief devices in gas/vapor service.
              60.482-5
              Standards: Sampling connection systems.
              60.482-6
              Standards: Open-ended valves or lines.
              60.482-7
              Standards: Valves in gas/vapor service and in light liquid service.
              60.482-8
              Standards: Pumps and valves in heavy liquid service, pressure relief devices in light liquid or heavy liquid service, and connectors.
              60.482-9
              Standards: Delay of repair.
              60.482-10
              Standards: Closed vent systems and control devices.
              60.483-1
              Alternative standards for valves—allowable percentage of valves leaking.
              60.483-2
              Alternative standards for valves—skip period leak detection and repair.
              60.484
              Equivalence of means of emission limitation.
              60.485
              Test methods and procedures.
              60.486
              Recordkeeping requirements.
              60.487
              Reporting requirements.
              60.488
              Reconstruction.
              60.489
              List of chemicals produced by affected facilities.

              Subpart VVa—Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006
              60.480a
              Applicability and designation of affected facility.
              60.481a
              Definitions.
              60.482-1a
              Standards: General.
              60.482-2a
              Standards: Pumps in light liquid service.
              60.482-3a
              Standards: Compressors.
              60.482-4a
              Standards: Pressure relief devices in gas/vapor service.
              60.482-5a
              Standards: Sampling connection systems.
              60.482-6a
              Standards: Open-ended valves or lines.

              60.482-7a
              Standards: Valves in gas/vapor service and in light liquid service.
              60.482-8a
              Standards: Pumps, valves, and connectors in heavy liquid service and pressure relief devices in light liquid or heavy liquid service.
              60.482-9a
              Standards: Delay of repair.
              60.482-10a
              Standards: Closed vent systems and control devices.
              60.482-11a
              Standards: Connectors in gas/vapor service and in light liquid service.
              60.483-1a
              Alternative standards for valves—allowable percentage of valves leaking.
              60.483-2a
              Alternative standards for valves—skip period leak detection and repair.
              60.484a
              Equivalence of means of emission limitation.
              60.485a
              Test methods and procedures.
              60.486a
              Recordkeeping requirements.
              60.487a
              Reporting requirements.
              60.488a
              Reconstruction.
              60.489a
              List of chemicals produced by affected facilities.

              Subpart WW—Standards of Performance for the Beverage Can Surface Coating Industry
              60.490
              Applicability and designation of affected facility.
              60.491
              Definitions.
              60.492
              Standards for volatile organic compounds.
              60.493
              Performance test and compliance provisions.
              60.494
              Monitoring of emissions and operations.
              60.495
              Reporting and recordkeeping requirements.
              60.496
              Test methods and procedures.

            Authority:
            42 U.S.C. 7401 et seq.

            Source:
            36 FR 24877, Dec. 23, 1971, unless otherwise noted.

            Subpart A—General Provisions

              § 60.1
              Applicability.
              (a) Except as provided in subparts B and C, the provisions of this part apply to the owner or operator of any stationary source which contains an affected facility, the construction or modification of which is commenced after the date of publication in this part of any standard (or, if earlier, the date of publication of any proposed standard) applicable to that facility.
              (b) Any new or revised standard of performance promulgated pursuant to section 111(b) of the Act shall apply to the owner or operator of any stationary source which contains an affected facility, the construction or modification of which is commenced after the date of publication in this part of such new or revised standard (or, if earlier, the date of publication of any proposed standard) applicable to that facility.
              (c) In addition to complying with the provisions of this part, the owner or operator of an affected facility may be required to obtain an operating permit issued to stationary sources by an authorized State air pollution control agency or by the Administrator of the U.S. Environmental Protection Agency (EPA) pursuant to Title V of the Clean Air Act (Act) as amended November 15, 1990 (42 U.S.C. 7661). For more information about obtaining an operating permit see part 70 of this chapter.
              (d) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia. (1) This paragraph applies only to the pharmaceutical manufacturing facility, commonly referred to as the Stonewall Plant, located at Route 340 South, in Elkton, Virginia (“site”).
              (2) Except for compliance with 40 CFR 60.49b(u), the site shall have the option of either complying directly with the requirements of this part, or reducing the site-wide emissions caps in accordance with the procedures set forth in a permit issued pursuant to 40 CFR 52.2454. If the site chooses the option of reducing the site-wide emissions caps in accordance with the procedures set forth in such permit, the requirements of such permit shall apply in lieu of the otherwise applicable requirements of this part.
              (3) Notwithstanding the provisions of paragraph (d)(2) of this section, for any provisions of this part except for Subpart Kb, the owner/operator of the site shall comply with the applicable provisions of this part if the Administrator determines that compliance with the provisions of this part is necessary for achieving the objectives of the regulation and the Administrator notifies the site in accordance with the provisions of the permit issued pursuant to 40 CFR 52.2454.
              [40 FR 53346, Nov. 17, 1975, as amended at 55 FR 51382, Dec. 13, 1990; 59 FR 12427, Mar. 16, 1994; 62 FR 52641, Oct. 8, 1997]

              § 60.2
              Definitions.
              The terms used in this part are defined in the Act or in this section as follows:

                Act means the Clean Air Act (42 U.S.C. 7401 et seq.)

                Administrator means the Administrator of the Environmental Protection Agency or his authorized representative.

                Affected facility means, with reference to a stationary source, any apparatus to which a standard is applicable.

                Alternative method means any method of sampling and analyzing for an air pollutant which is not a reference or equivalent method but which has been demonstrated to the Administrator's satisfaction to, in specific cases, produce results adequate for his determination of compliance.

                Approved permit program means a State permit program approved by the Administrator as meeting the requirements of part 70 of this chapter or a Federal permit program established in this chapter pursuant to Title V of the Act (42 U.S.C. 7661).

                Capital expenditure means an expenditure for a physical or operational change to an existing facility which exceeds the product of the applicable “annual asset guideline repair allowance percentage” specified in the latest edition of Internal Revenue Service (IRS) Publication 534 and the existing facility's basis, as defined by section 1012 of the Internal Revenue Code. However, the total expenditure for a physical or operational change to an existing facility must not be reduced by any “excluded additions” as defined in IRS Publication 534, as would be done for tax purposes.

                Clean coal technology demonstration project means a project using funds appropriated under the heading ‘Department of Energy-Clean Coal Technology’, up to a total amount of $2,500,000,000 for commercial demonstrations of clean coal technology, or similar projects funded through appropriations for the Environmental Protection Agency.

                Commenced means, with respect to the definition of new source in section 111(a)(2) of the Act, that an owner or operator has undertaken a continuous program of construction or modification or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction or modification.

                Construction means fabrication, erection, or installation of an affected facility.

                Continuous monitoring system means the total equipment, required under the emission monitoring sections in applicable subparts, used to sample and condition (if applicable), to analyze, and to provide a permanent record of emissions or process parameters.

                Electric utility steam generating unit means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is also considered in determining the electrical energy output capacity of the affected facility.

                Equivalent method means any method of sampling and analyzing for an air pollutant which has been demonstrated to the Administrator's satisfaction to have a consistent and quantitatively known relationship to the reference method, under specified conditions.

                Excess Emissions and Monitoring Systems Performance Report is a report that must be submitted periodically by a source in order to provide data on its compliance with stated emission limits and operating parameters, and on the performance of its monitoring systems.

                Existing facility means, with reference to a stationary source, any apparatus of the type for which a standard is promulgated in this part, and the construction or modification of which was commenced before the date of proposal of that standard; or any apparatus which could be altered in such a way as to be of that type.

                Force majeure means, for purposes of § 60.8, an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents the owner or operator from complying with the regulatory requirement to conduct performance tests within the specified timeframe despite the affected facility's best efforts to fulfill the obligation. Examples of such events are acts of nature, acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility.

                Isokinetic sampling means sampling in which the linear velocity of the gas entering the sampling nozzle is equal to that of the undisturbed gas stream at the sample point.

                Issuance of a part 70 permit will occur, if the State is the permitting authority, in accordance with the requirements of part 70 of this chapter and the applicable, approved State permit program. When the EPA is the permitting authority, issuance of a Title V permit occurs immediately after the EPA takes final action on the final permit.

                Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner. Failures that are caused in part by poor maintenance or careless operation are not malfunctions.

                Modification means any physical change in, or change in the method of operation of, an existing facility which increases the amount of any air pollutant (to which a standard applies) emitted into the atmosphere by that facility or which results in the emission of any air pollutant (to which a standard applies) into the atmosphere not previously emitted.

                Monitoring device means the total equipment, required under the monitoring of operations sections in applicable subparts, used to measure and record (if applicable) process parameters.

                Nitrogen oxides means all oxides of nitrogen except nitrous oxide, as measured by test methods set forth in this part.

                One-hour period means any 60-minute period commencing on the hour.

                Opacity means the degree to which emissions reduce the transmission of light and obscure the view of an object in the background.

                Owner or operator means any person who owns, leases, operates, controls, or supervises an affected facility or a stationary source of which an affected facility is a part.

                Part 70 permit means any permit issued, renewed, or revised pursuant to part 70 of this chapter.

                Particulate matter means any finely divided solid or liquid material, other than uncombined water, as measured by the reference methods specified under each applicable subpart, or an equivalent or alternative method.

                Permit program means a comprehensive State operating permit system established pursuant to title V of the Act (42 U.S.C. 7661) and regulations codified in part 70 of this chapter and applicable State regulations, or a comprehensive Federal operating permit system established pursuant to title V of the Act and regulations codified in this chapter.

                Permitting authority means:
              (1) The State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to carry out a permit program under part 70 of this chapter; or
              (2) The Administrator, in the case of EPA-implemented permit programs under title V of the Act (42 U.S.C. 7661).

                Proportional sampling means sampling at a rate that produces a constant ratio of sampling rate to stack gas flow rate.

                Reactivation of a very clean coal-fired electric utility steam generating unit means any physical change or change in the method of operation associated with the commencement of commercial operations by a coal-fired utility unit after a period of discontinued operation where the unit:
              (1) Has not been in operation for the two-year period prior to the enactment of the Clean Air Act Amendments of 1990, and the emissions from such unit continue to be carried in the permitting authority's emissions inventory at the time of enactment;

              (2) Was equipped prior to shut-down with a continuous system of emissions control that achieves a removal efficiency for sulfur dioxide of no less than 85 percent and a removal efficiency for particulates of no less than 98 percent;

              (3) Is equipped with low-NOX burners prior to the time of commencement of operations following reactivation; and
              (4) Is otherwise in compliance with the requirements of the Clean Air Act.

                Reference method means any method of sampling and analyzing for an air pollutant as specified in the applicable subpart.

                Repowering means replacement of an existing coal-fired boiler with one of the following clean coal technologies: atmospheric or pressurized fluidized bed combustion, integrated gasification combined cycle, magnetohydrodynamics, direct and indirect coal-fired turbines, integrated gasification fuel cells, or as determined by the Administrator, in consultation with the Secretary of Energy, a derivative of one or more of these technologies, and any other technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of November 15, 1990. Repowering shall also include any oil and/or gas-fired unit which has been awarded clean coal technology demonstration funding as of January 1, 1991, by the Department of Energy.

                Run means the net period of time during which an emission sample is collected. Unless otherwise specified, a run may be either intermittent or continuous within the limits of good engineering practice.

                Shutdown means the cessation of operation of an affected facility for any purpose.

                Six-minute period means any one of the 10 equal parts of a one-hour period.

                Standard means a standard of performance proposed or promulgated under this part.

                Standard conditions means a temperature of 293 K (68F) and a pressure of 101.3 kilopascals (29.92 in Hg).

                Startup means the setting in operation of an affected facility for any purpose.

                State means all non-Federal authorities, including local agencies, interstate associations, and State-wide programs, that have delegated authority to implement: (1) The provisions of this part; and/or (2) the permit program established under part 70 of this chapter. The term State shall have its conventional meaning where clear from the context.

                Stationary source means any building, structure, facility, or installation which emits or may emit any air pollutant.

                Title V permit means any permit issued, renewed, or revised pursuant to Federal or State regulations established to implement title V of the Act (42 U.S.C. 7661). A title V permit issued by a State permitting authority is called a part 70 permit in this part.

                Volatile Organic Compound means any organic compound which participates in atmospheric photochemical reactions; or which is measured by a reference method, an equivalent method, an alternative method, or which is determined by procedures specified under any subpart.
              [44 FR 55173, Sept. 25, 1979, as amended at 45 FR 5617, Jan. 23, 1980; 45 FR 85415, Dec. 24, 1980; 54 FR 6662, Feb. 14, 1989; 55 FR 51382, Dec. 13, 1990; 57 FR 32338, July 21, 1992; 59 FR 12427, Mar. 16, 1994; 72 FR 27442, May 16, 2007]

              § 60.3
              Units and abbreviations.
              Used in this part are abbreviations and symbols of units of measure. These are defined as follows:
              (a) System International (SI) units of measure:

                A—ampere
                g—gram
                Hz—hertz
                J—joule
                K—degree Kelvin
                kg—kilogram
                m—meter
                m3—cubic meter
                mg—milligram—10 −3 gram
                mm—millimeter—10 −3 meter
                Mg—megagram—106 gram
                mol—mole
                N—newton
                ng—nanogram—10 −9 gram
                nm—nanometer—10 −9 meter
                Pa—pascal
                s—second
                V—volt
                W—watt
                Ω—ohm
                µg—microgram—10 −6 gram

              (b) Other units of measure:

                Btu—British thermal unit
                 °C—degree Celsius (centigrade)

                cal—calorie
                cfm—cubic feet per minute
                cu ft—cubic feet
                dcf—dry cubic feet
                dcm—dry cubic meter
                dscf—dry cubic feet at standard conditions
                dscm—dry cubic meter at standard conditions
                eq—equivalent
                °F—degree Fahrenheit
                ft—feet
                gal—gallon
                gr—grain
                g-eq—gram equivalent
                hr—hour
                in—inch
                k—1,000
                l—liter
                lpm—liter per minute
                lb—pound
                meq—milliequivalent
                min—minute
                ml—milliliter
                mol. wt.—molecular weight
                ppb—parts per billion
                ppm—parts per million
                psia—pounds per square inch absolute
                psig—pounds per square inch gage
                °R—degree Rankine
                scf—cubic feet at standard conditions
                scfh—cubic feet per hour at standard conditions
                scm—cubic meter at standard conditions
                sec—second
                sq ft—square feet
                std—at standard conditions

              (c) Chemical nomenclature:

                CdS—cadmium sulfide
                CO—carbon monoxide
                CO2—carbon dioxide
                HCl—hydrochloric acid
                Hg—mercury
                H2O—water
                H2S—hydrogen sulfide
                H2SO4—sulfuric acid
                N2—nitrogen
                NO—nitric oxide
                NO2—nitrogen dioxide
                NOX—nitrogen oxides
                O2—oxygen
                SO2—sulfur dioxide
                SO3—sulfur trioxide
                SOX—sulfur oxides

              (d) Miscellaneous:

                A.S.T.M.—American Society for Testing and Materials

              [42 FR 37000, July 19, 1977; 42 FR 38178, July 27, 1977]

              § 60.4
              Address.

              (a) All requests, reports, applications, submittals, and other communications to the Administrator pursuant to this part shall be submitted in duplicate to the appropriate Regional Office of the U.S. Environmental Protection Agency to the attention of the Director of the Division indicated in the following list of EPA Regional Offices.

                Region I (Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont) Director, Enforcement and Compliance Assurance Division, U.S. EPA Region I, 5 Post Office Square—Suite 100 (04-2), Boston, MA 02109-3912, Attn: Air Compliance Clerk.
                Region II (New Jersey, New York, Puerto Rico, Virgin Islands), Director, Air and Waste Management Division, U.S. Environmental Protection Agency, Federal Office Building, 26 Federal Plaza (Foley Square), New York, NY 10278.
                Region III (Delaware, District of Columbia, Maryland, Pennsylvania, Virginia, West Virginia), Director, Air Protection Division, Mail Code 3AP00, 1650 Arch Street, Philadelphia, PA 19103-2029.
                Region IV (Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina, Tennessee), Director, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, 61 Forsyth St. SW., Suite 9T43, Atlanta, Georgia 30303-8960.
                Region V (Illinois, Indiana, Michigan, Minnesota, Ohio, Wisconsin), Director, Air and Radiation Division, U.S. Environmental Protection Agency, 77 West Jackson Boulevard, Chicago, IL 60604-3590.
                Region VI (Arkansas, Louisiana, New Mexico, Oklahoma, Texas); Director; Enforcement and Compliance Assurance Division; U.S. Environmental Protection Agency, 1201 Elm Street, Suite 500, Mail Code 6ECD, Dallas, Texas 75270-2102.
                Region VII (Iowa, Kansas, Missouri, Nebraska), Director, Air and Waste Management Division, 11201 Renner Boulevard, Lenexa, Kansas 66219.
                Region VIII (Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming) Director, Air and Toxics Technical Enforcement Program, Office of Enforcement, Compliance and Environmental Justice, Mail Code 8ENF-AT, 1595 Wynkoop Street, Denver, CO 80202-1129.

                Region IX (Arizona, California, Hawaii and Nevada; the territories of American Samoa and Guam; the Commonwealth of the Northern Mariana Islands; the territories of Baker Island, Howland Island, Jarvis Island, Johnston Atoll, Kingman Reef, Midway Atoll, Palmyra Atoll, and Wake Islands; and certain U.S. Government activities in the freely associated states of the Republic of the Marshall Islands, the Federated States of Micronesia, and the Republic of Palau), Director, Air Division, U.S. Environmental Protection Agency, 75 Hawthorne Street, San Francisco, CA 94105.
                Region X (Alaska, Oregon, Idaho, Washington), Director, Air and Waste Management Division, U.S. Environmental Protection Agency, 1200 Sixth Avenue, Seattle, WA 98101.

              (b) Section 111(c) directs the Administrator to delegate to each State, when appropriate, the authority to implement and enforce standards of performance for new stationary sources located in such State. All information required to be submitted to EPA under paragraph (a) of this section, must also be submitted to the appropriate State Agency of any State to which this authority has been delegated (provided, that each specific delegation may except sources from a certain Federal or State reporting requirement). The appropriate mailing address for those States whose delegation request has been approved is as follows:
              (1) [Reserved]
              (2) State of Alabama: Alabama Department of Environmental Management, P.O. Box 301463, Montgomery, Alabama 36130-1463.
              (3) State of Alaska, Department of Environmental Conservation, Pouch O, Juneau, AK 99811.
              (4) Arizona:

                Arizona Department of Environmental Quality, 1110 West Washington Street, Phoenix, AZ 85007.
                Maricopa County Air Quality Department, 1001 North Central Avenue, Suite 900, Phoenix, AZ 85004.
                Pima County Department of Environmental Quality, 33 North Stone Avenue, Suite 700, Tucson, AZ 85701.
                Pinal County Air Quality Control District, 31 North Pinal Street, Building F, Florence, AZ 85132.

                Note:
                For tables listing the delegation status of agencies in Region IX, see paragraph (d) of this section.

              (5) State of Arkansas: Chief, Division of Air Pollution Control, Arkansas Department of Pollution Control and Ecology, 8001 National Drive, P.O. Box 9583, Little Rock, AR 72209.
              (6) California:

                Amador County Air Pollution Control District, 12200-B Airport Road, Jackson, CA 95642.
                Antelope Valley Air Quality Management District, 43301 Division Street, Suite 206, Lancaster, CA 93535.
                Bay Area Air Quality Management District, 939 Ellis Street, San Francisco, CA 94109.
                Butte County Air Quality Management District, 2525 Dominic Drive, Suite J, Chico, CA 95928.
                Calaveras County Air Pollution Control District, 891 Mountain Ranch Road, San Andreas, CA 95249.
                Colusa County Air Pollution Control District, 100 Sunrise Blvd., Suite A-3, Colusa, CA 95932-3246.
                El Dorado County Air Quality Management District, 2850 Fairlane Court, Bldg. C, Placerville, CA 95667-4100.
                Eastern Kern Air Pollution Control District, 2700 “M” Street, Suite 302, Bakersfield, CA 93301-2370.
                Feather River Air Quality Management District, 1007 Live Oak Blvd., Suite B-3, Yuba City, CA 95991.
                Glenn County Air Pollution Control District, 720 N. Colusa Street, P.O. Box 351, Willows, CA 95988-0351.
                Great Basin Unified Air Pollution Control District, 157 Short Street, Suite 6, Bishop, CA 93514-3537.
                Imperial County Air Pollution Control District, 150 South Ninth Street, El Centro, CA 92243-2801.
                Lake County Air Quality Management District, 885 Lakeport Blvd., Lakeport, CA 95453-5405.
                Lassen County Air Pollution Control District, 707 Nevada Street, Suite 1, Susanville, CA 96130.
                Mariposa County Air Pollution Control District, P.O. Box 5, Mariposa, CA 95338.
                Mendocino County Air Quality Management District, 306 E. Gobbi Street, Ukiah, CA 95482-5511.
                Modoc County Air Pollution Control District, 619 North Main Street, Alturas, CA 96101.
                Mojave Desert Air Quality Management District, 14306 Park Avenue, Victorville, CA 92392-2310.
                Monterey Bay Unified Air Pollution Control District, 24580 Silver Cloud Court, Monterey, CA 93940.
                North Coast Unified Air Quality Management District, 2300 Myrtle Avenue, Eureka, CA 95501-3327.
                Northern Sierra Air Quality Management District, 200 Litton Drive, Suite 320, P.O. Box 2509, Grass Valley, CA 95945-2509.
                Northern Sonoma County Air Pollution Control District, 150 Matheson Street, Healdsburg, CA 95448-4908.
                Placer County Air Pollution Control District, 3091 County Center Drive, Suite 240, Auburn, CA 95603.

                Sacramento Metropolitan Air Quality Management District, 777 12th Street, Third Floor, Sacramento, CA 95814-1908.

                San Diego County Air Pollution Control District, 10124 Old Grove Road, San Diego, CA 92131-1649.
                San Joaquin Valley Air Pollution Control District, 1990 E. Gettysburg, Fresno, CA 93726.
                San Luis Obispo County Air Pollution Control District, 3433 Roberto Court, San Luis Obispo, CA 93401-7126.
                Santa Barbara County Air Pollution Control District, 260 North San Antonio Road, Suite A, Santa Barbara, CA 93110-1315.
                Shasta County Air Quality Management District, 1855 Placer Street, Suite 101, Redding, CA 96001-1759.
                Siskiyou County Air Pollution Control District, 525 So. Foothill Drive, Yreka, CA 96097-3036.
                South Coast Air Quality Management District, 21865 Copley Drive, Diamond Bar, CA 91765-4182.
                Tehama County Air Pollution Control District, P.O. Box 8069 (1750 Walnut Street), Red Bluff, CA 96080-0038.
                Tuolumne County Air Pollution Control District, 22365 Airport, Columbia, CA 95310.
                Ventura County Air Pollution Control District, 669 County Square Drive, 2nd Floor, Ventura, CA 93003-5417.
                Yolo-Solano Air Quality Management District, 1947 Galileo Court, Suite 103, Davis, CA 95616-4882.

                Note:
                For tables listing the delegation status of agencies in Region IX, see paragraph (d) of this section.

              (7) State of Colorado, Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, CO 80222-1530.

                Note:
                For a table listing Region VIII's NSPS delegation status, see paragraph (c) of this section.

              (8) State of Connecticut, Compliance Analysis and Coordination Unit, Bureau of Air Management, Department of Energy and Environmental Protection, 79 Elm Street, 5th Floor, Hartford, CT 06106-5127.
              (9) State of Delaware, Department of Natural Resources & Environmental Control, 89 Kings Highway, P.O. Box 1401, Dover, Delaware 19903.
              (10) District of Columbia, Department of Public Health, Air Quality Division, 51 N Street, NE., Washington, DC 20002.
              (11) State of Florida: Florida Department of Environmental Protection, Division of Air Resources Management, 2600 Blair Stone Road, MS 5500, Tallahassee, Florida 32399-2400.
              (12) State of Georgia: Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, 4244 International Parkway, Suite 120, Atlanta, Georgia 30354.
              (13) Hawaii:

                Clean Air Branch, Hawaii Department of Health, 919 Ala Moana Blvd., Suite 203, Honolulu, HI 96814.

                Note:
                For tables listing the delegation status of agencies in Region IX, see paragraph (d) of this section.

              (14) State of Idaho, Department of Health and Welfare, Statehouse, Boise, ID 83701.
              (15) State of Illinois: Illinois Environmental Protection Agency, 1021 North Grand Avenue East, Springfield, Illinois 62794.
              (16) State of Indiana: Indiana Department of Environmental Management, Office of Air Quality, 100 North Senate Avenue, Indianapolis, Indiana 46204.
              (17) State of Iowa: Iowa Department of Natural Resources, Environmental Protection Division, Air Quality Bureau, 7900 Hickman Road, Suite 1, Urbandale, IA 50322.
              (18) State of Kansas: Kansas Department of Health and Environment, Bureau of Air and Radiation, 1000 S.W. Jackson, Suite 310, Topeka, KS 66612-1366.
              (19) Commonwealth of Kentucky: Kentucky Department for Environmental Protection, Division for Air Quality, 300 Sower Boulevard, 2nd Floor, Frankfort, Kentucky 40601 or local agency, Louisville Metro Air Pollution Control District, 701 W. Ormsby Ave., Suite 303, Louisville, Kentucky 40203.

              (20) State of Louisiana: Louisiana Department of Environmental Quality, P.O. Box 4301, Baton Rouge, Louisiana 70821-4301.

                Note:
                For a list of delegated standards for Louisiana (excluding Indian country), see paragraph (e)(2) of this section.

              (21) State of Maine, Maine Department of Environmental Protection, Bureau of Air Quality, 17 State House Station, Augusta, ME 04333-0017.

              (22) State of Maryland, Department of the Environment, 1800 Washington Boulevard, Suite 705, Baltimore, Maryland 21230.

              (23) Commonwealth of Massachusetts, Massachusetts Department of Environmental Protection, Division of Air and Climate Programs, One Winter Street, Boston, MA 02108.
              (24) State of Michigan: Michigan Department of Natural Resources and Environment, Air Quality Division, P.O. Box 30028, Lansing, Michigan 48909.
              (25) State of Minnesota: Minnesota Pollution Control Agency, Division of Air Quality, 520 Lafayette Road North, St. Paul, Minnesota 55155.
              (26) State of Mississippi: Hand Deliver or Courier: Mississippi Department of Environmental Quality, Office of Pollution Control, Air Division, 515 East Amite Street, Jackson, Mississippi 39201, Mailing Address: Mississippi Department of Environmental Quality, Office of Pollution Control, Air Division, P.O. Box 2261, Jackson, Mississippi 39225.
              (27) State of Missouri: Missouri Department of Natural Resources, Division of Environmental Quality, P.O. Box 176, Jefferson City, MO 65102.

              (28) State of Montana, Department of Environmental Quality, 1520 E. 6th Ave., PO Box 200901, Helena, MT 59620-0901.

                Note:
                For a table listing Region VIII's NSPS delegation status, see paragraph (c) of this section.

              (29) State of Nebraska, Nebraska Department of Environmental Control, P.O. Box 94877, State House Station, Lincoln, NE 68509.
              Lincoln-Lancaster County Health Department, Division of Environmental Health, 2200 St. Marys Avenue, Lincoln, NE 68502
              (30) Nevada:

                Nevada Division of Environmental Protection, 901 South Stewart Street, Suite 4001, Carson City, NV 89701-5249.
                Clark County Department of Air Quality and Environmental Management, 500 S. Grand Central Parkway, 1st Floor, P.O. Box 555210, Las Vegas, NV 89155-5210.
                Washoe County Health District, Air Quality Management Division, 1001 E. 9th Street, Building A, Suite 115A, Reno, NV 89520.

                Note:
                For tables listing the delegation status of agencies in Region IX, see paragraph (d) of this section.

              (31) State of New Hampshire, New Hampshire Department of Environmental Services, Air Resources Division, 29 Hazen Drive, P.O. Box 95, Concord, NH 03302-0095.
              (32) State of New Jersey: New Jersey Department of Environmental Protection, Division of Environmental Quality, Enforcement Element, John Fitch Plaza, CN-027, Trenton, NJ 08625.
              (1) The following table lists the specific source and pollutant categories that have been delegated to the states in Region II. The (X) symbol is used to indicate each category that has been delegated.

                  Subpart
                  State
                  New Jersey
                  New York
                  Puerto Rico
                  Virgin Islands

                  D
                  Fossil-Fuel Fired Steam Generators for Which Construction Commenced After August 17, 1971 (Steam Generators and Lignite Fired Steam Generators)
                  X
                  X
                  X
                  X

                  Da
                  Electric Utility Steam Generating Units for Which Construction Commenced After September 18, 1978
                  X

                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X
                  X
                  X

                  E
                  Incinerators
                  X
                  X
                  X
                  X

                  F
                  Portland Cement Plants
                  X
                  X
                  X
                  X

                  G
                  Nitric Acid Plants
                  X
                  X
                  X
                  X

                  H
                  Sulfuric Acid Plants
                  X
                  X
                  X
                  X

                  I
                  Asphalt Concrete Plants
                  X
                  X
                  X
                  X

                  J
                  Petroleum Refineries—(All Categories)
                  X
                  X
                  X
                  X

                  K
                  Storage Vessels for Petroleum Liquids Constructed After June 11, 1973, and prior to May 19, 1978
                  X
                  X
                  X
                  X

                  Ka
                  Storage Vessels for Petroleum Liquids Constructed After May 18, 1978
                  X
                  X
                  X

                  L
                  Secondary Lead Smelters
                  X
                  X
                  X
                  X

                  M
                  Secondary Brass and Bronze Ingot Production Plants
                  X
                  X
                  X
                  X

                  N
                  Iron and Steel Plants
                  X
                  X
                  X
                  X

                  O
                  Sewage Treatment Plants
                  X
                  X
                  X
                  X

                  P
                  Primary Copper Smelters
                  X
                  X
                  X
                  X

                  Q
                  Primary Zinc Smelters
                  X
                  X
                  X
                  X

                  R
                  Primary Lead Smelters
                  X
                  X
                  X
                  X

                  S
                  Primary Aluminum Reduction Plants
                  X
                  X
                  X
                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants
                  X
                  X
                  X
                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  X
                  X
                  X
                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  X
                  X
                  X
                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  X
                  X
                  X
                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate
                  X
                  X
                  X
                  X

                  Y
                  Coal Preparation Plants
                  X
                  X
                  X
                  X

                  Z
                  Ferroally Production Facilities
                  X
                  X
                  X
                  X

                  AA
                  Steel Plants: Electric Arc Furnaces
                  X
                  X
                  X
                  X

                  AAa
                  Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels in Steel Plants
                  X
                  X
                  X

                  BB
                  Kraft Pulp Mills
                  X
                  X
                  X

                  CC
                  Glass Manufacturing Plants
                  X
                  X
                  X

                  DD
                  Grain Elevators
                  X
                  X
                  X

                  EE
                  Surface Coating of Metal Furniture
                  X
                  X
                  X

                  GG
                  Stationary Gas Turbines
                  X
                  X
                  X

                  HH
                  Lime Plants
                  X
                  X
                  X

                  KK
                  Lead Acid Battery Manufacturing Plants
                  X
                  X

                  LL
                  Metallic Mineral Processing Plants
                  X
                  X
                  X

                  MM
                  Automobile and Light-Duty Truck Surface Coating Operations
                  X
                  X

                  NN
                  Phosphate Rock Plants
                  X
                  X

                  PP
                  Ammonium Sulfate Manufacturing Plants
                  X
                  X

                  QQ
                  Graphic Art Industry Publication Rotogravure Printing
                  X
                  X
                  X
                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations
                  X
                  X
                  X

                  SS
                  Industrial Surface Coating: Large Appliances
                  X
                  X
                  X

                  TT
                  Metal Coil Surface Coating
                  X
                  X
                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture
                  X
                  X
                  X

                  VV
                  Equipment Leaks of Volatile Organic Compounds in Synthetic Organic Chemical Manufacturing Industry
                  X

                  X

                  WW
                  Beverage Can Surface Coating Industry
                  X
                  X
                  X

                  XX
                  Bulk Gasoline Terminals
                  X
                  X
                  X

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing
                  X
                  X
                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries
                  X

                  X

                  HHH
                  Synthetic Fiber Production Facilities
                  X

                  X

                  JJJ
                  Petroleum Dry Clearners
                  X
                  X
                  X

                  KKK
                  Equipment Leaks of VOC from Onshore Natural Gas Processing Plants

                  LLL
                  Onshore Natural Gas Processing Plants; SO2 Emissions

                  X

                  OOO
                  Nonmetallic Mineral Processing Plants

                  X
                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants

                  X
                  X

              (33) State of New Mexico: New Mexico Environment Department, P.O. Box 5469, Santa Fe, New Mexico 87502-5469. Note: For a list of delegated standards for New Mexico (excluding Bernalillo County and Indian country), see paragraph (e)(1) of this section.
              (34) New York: New York State Department of Environmental Conservation, 50 Wolf Road Albany, New York 12233, attention: Division of Air Resources.
              (35) State of North Carolina: North Carolina Department of Environmental Quality, Division of Air Quality, 1641 Mail Service Center, Raleigh, North Carolina 27699-1641 or local agencies, Forsyth County Office of Environmental Assistance and Protection, 201 North Chestnut Street, Winston-Salem, North Carolina 27101-4120; Mecklenburg County Land Use and Environmental Services Agency, Air Quality, 2145 Suttle Avenue, Charlotte, North Carolina 28208; Western North Carolina Regional Air Quality Agency, 125 S. Lexington Ave., Suite 101, Asheville, North Carolina 28801-3661.

              (36) State of North Dakota, North Dakota Department of Environmental Quality, 918 East Divide Avenue, Bismarck, ND 58501-1947.

                Note:
                For a table listing Region VIII's NSPS delegation status, see paragraph (c) of this section.

              (37) State of Ohio:

              (i) Medina, Summit and Portage Counties; Director, Akron Regional Air Quality Management District, 146 South High Street, Room 904, Akron, OH 44308.

              (ii) Stark County; Director, Canton City Health Department, Air Pollution Control Division, 420 Market Avenue North, Canton, Ohio 44702-1544.
              (iii) Butler, Clermont, Hamilton, and Warren Counties; Director, Hamilton County Department of Environmental Services, 250 William Howard Taft Road, Cincinnati, Ohio 45219-2660.
              (iv) Cuyahoga County; Commissioner, Cleveland Department of Public Health, Division of Air Quality, 75 Erieview Plaza 2nd Floor, Cleveland, Ohio 44114.
              (v) Clark, Darke, Greene, Miami, Montgomery, and Preble Counties; Director, Regional Air Pollution Control Agency, 117 South Main Street, Dayton, Ohio 45422-1280.
              (vi) Lucas County and the City of Rossford (in Wood County); Director, City of Toledo, Division of Environmental Services, 348 South Erie Street, Toledo, OH 43604.
              (vii) Adams, Brown, Lawrence, and Scioto Counties; Portsmouth Local Air Agency, 605 Washington Street, Third Floor, Portsmouth, OH 45662.
              (viii) Allen, Ashland, Auglaize, Crawford, Defiance, Erie, Fulton, Hancock, Hardin, Henry, Huron, Marion, Mercer, Ottawa, Paulding, Putnam, Richland, Sandusky, Seneca, Van Wert Williams, Wood (Except City of Rossford), and Wyandot Counties; Ohio Environmental Protection Agency, Northwest District Office, Air Pollution Control, 347 North Dunbridge Road, Bowling Green, Ohio 43402.
              (ix) Ashtabula, Caroll, Colombiana, Holmes, Lorain, and Wayne Counties; Ohio Environmental Protection Agency, Northeast District Office, Air Pollution Unit, 2110 East Aurora Road, Twinsburg, OH 44087.
              (x) Athens, Belmont, Coshocton, Gallia, Guemsey, Harrison, Hocking, Jackson, Jefferson, Meigs, Monroe, Morgan, Muskingum, Noble, Perry, Pike, Ross, Tuscarawas, Vinton, and Washington Counties; Ohio Environmental Protection Agency, Southeast District Office, Air Pollution Unit, 2195 Front Street, Logan, OH 43138.
              (xi) Champaign, Clinton, Highland, Logan, and Shelby Counties; Ohio Environmental Protection Agency, Southwest District Office, Air Pollution Unit, 401 East Fifth Street, Dayton, Ohio 45402-2911.
              (xii) Delaware, Fairfield, Fayette, Franklin, Knox, Licking, Madison, Morrow, Pickaway, and Union Counties; Ohio Environmental Protection Agency, Central District Office, Air Pollution control, 50 West Town Street, Suite 700, Columbus, Ohio 43215.
              (xiii) Geauga and Lake Counties; Lake County General Health District, Air Pollution Control, 33 Mill Street, Painesville, OH 44077.
              (xiv) Mahoning and Trumbull Counties; Mahoning-Trumbull Air Pollution Control Agency, 345 Oak Hill Avenue, Suite 200, Youngstown, OH 44502.
              (38) State of Oklahoma, Oklahoma State Department of Health, Air Quality Service, P.O. Box 53551, Oklahoma City, OK 73152.
              (i) Oklahoma City and County: Director, Oklahoma City-County Health Department, 921 Northeast 23rd Street, Oklahoma City, OK 73105.
              (ii) Tulsa County: Tulsa City-County Health Department, 4616 East Fifteenth Street, Tulsa, OK 74112.

              (39) State of Oregon. (i) Oregon Department of Environmental Quality (ODEQ), 811 SW Sixth Avenue, Portland, OR 97204-1390, http://www.deq.state.or.us.

              (ii) Lane Regional Air Pollution Authority (LRAPA), 1010 Main Street, Springfield, Oregon 97477, http://www.lrapa.org.

              (40)(i) City of Philadelphia, Department of Public Health, Air Management Services, 321 University Avenue, Philadelphia, Pennsylvania 19104.
              (ii) Commonwealth of Pennsylvania, Department of Environmental Protection, Bureau of Air Quality Control, P.O. Box 8468, 400 Market Street, Harrisburg, Pennsylvania 17105.
              (iii) Allegheny County Health Department, Bureau of Environmental Quality, Division of Air Quality, 301 39th Street, Pittsburgh, Pennsylvania 15201.

              (41) State of Rhode Island, Rhode Island Department of Environmental Management, Office of Air Resources, 235 Promenade Street, Providence, RI 02908.

              (42) State of South Carolina: South Carolina Department of Health and Environmental Control, 2600 Bull Street, Columbia, South Carolina 29201.

              (43) State of South Dakota, Air Quality Program, Department of Environment and Natural Resources, Joe Foss Building, 523 East Capitol, Pierre, SD 57501-3181.

                Note:
                For a table listing Region VIII's NSPS delegation status, see paragragh (c) of this section.

              (44) State of Tennessee: Tennessee Department of Environment and Conservation, Division of Air Pollution Control, William R. Snodgrass Tennessee Tower, 312 Rosa L. Parks Avenue, 15th Floor, Nashville, Tennessee 37243, or local agencies, Knox County Air Quality Management—Department of Public Health, 140 Dameron Avenue, Knoxville, Tennessee 37917; Metro Public Health Department, Pollution Control Division, 2500 Charlotte Ave., Nashville, Tennessee 37209; Chattanooga-Hamilton County Air Pollution Control Bureau, 6125 Preservation Drive, Chattanooga, Tennessee 37416; Shelby County Health Department, Pollution Control Section, 814 Jefferson Avenue, Memphis, Tennessee 38105.
              (45) State of Texas, Texas Air Control Board, 6330 Highway 290 East, Austin, TX 78723.

              (46) State of Utah, Division of Air Quality, Department of Environmental Quality, P.O. Box 144820, Salt Lake City, UT 84114-4820.

                Note:
                For a table listing Region VIII's NSPS delegation status, see paragraph (c) of this section.

              (47) State of Vermont, Agency of Natural Resources, Department of Environmental Conservation, Air Quality and Climate Division, Davis 2, One National Life Drive, Montpelier, VT 05620-3802.
              (48) Commonwealth of Virginia, Department of Environmental Quality, 629 East Main Street, Richmond, Virginia 23219.
              (49) State of Washington. (i) Washington State Department of Ecology (Ecology), P.O. Box 47600, Olympia, WA 98504-7600, http://www.ecy.wa.gov/

              (ii) Benton Clean Air Authority (BCAA), 650 George Washington Way, Richland, WA 99352-4289, http://www.bcaa.net/

              (iii) Northwest Air Pollution Control Authority (NWAPA), 1600 South Second St., Mount Vernon, WA 98273-5202, http://www.nwair.org/

              (iv) Olympic Regional Clean Air Agency (ORCAA), 909 Sleater-Kinney Road S.E., Suite 1, Lacey, WA 98503-1128, http://www.orcaa.org/

              (v) Puget Sound Clean Air Agency (PSCAA), 110 Union Street, Suite 500, Seattle, WA 98101-2038, http://www.pscleanair.org/

              (vi) Spokane County Air Pollution Control Authority (SCAPCA), West 1101 College, Suite 403, Spokane, WA 99201, http://www.scapca.org/

              (vii) Southwest Clean Air Agency (SWCAA), 1308 NE. 134th St., Vancouver, WA 98685-2747, http://www.swcleanair.org/

              (viii) Yakima Regional Clean Air Authority (YRCAA), 6 South 2nd Street, Suite 1016, Yakima, WA 98901, http://co.yakima.wa.us/cleanair/default.htm

              (ix) The following table lists the delegation status of the New Source Performance Standards for the State of Washington. An “X” indicates the subpart has been delegated, subject to all the conditions and limitations set forth in Federal law and the letters granting delegation. Some authorities cannot be delegated and are retained by EPA. Refer to the letters granting delegation for a discussion of these retained authorities. The dates noted at the end of the table indicate the effective dates of Federal rules that have been delegated. Authority for implementing and enforcing any amendments made to these rules after these effective dates are not delegated.

                NSPS Subparts Delegated to Washington Air Agencies

                  Subpart 1

                  Washington
                  Ecology 2

                  BCAA 3

                  NWAPA 4

                  ORCAA 5

                  PSCAA 6

                  SCAPCA 7

                  SWCAA 8

                  YRCAA 9

                  A General Provisions
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  B Adoption and Submittal of State Plans for Designated Facilities

                  C Emission Guidelines and Compliance Times

                  Cb Large Municipal Waste Combustors that are Constructed on or before September 20, 1994 (Emission Guidelines and Compliance Times)

                  Cc Municipal Solid Waste Landfills (Emission Guidelines and Compliance Times)

                  Cd Sulfuric Acid Production Units (Emission Guidelines and Compliance Times)

                  Ce Hospital/Medical/Infectious Waste Incinerators (Emission Guidelines and Compliance Times)

                  D Fossil-Fuel-Fired Steam Generators for which Construction is Commenced after August 17, 1971
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Da Electric Utility Steam Generating Units for which Construction is Commenced after September 18, 1978
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Db Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Dc Small Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  E Incinerators
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Ea Municipal Waste Combustors for which Construction is Commenced after December 20, 1989 and on or before September 20, 1994
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Eb—Large Municipal Waste Combustors

                  X

                  X
                  X
                  X

                  Ec—Hospital/Medical/Infectious Waste Incinerators
                  X
                  X
                  X
                  X
                  X
                  X

                  F Portland Cement Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  G Nitric Acid Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  H Sulfuric Acid Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  I Hot Mix Asphalt Facilities
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  J Petroleum Refineries
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  K Storage Vessels for Petroleum Liquids for which Construction, Reconstruction, or Modification Commenced after June 11, 1973 and prior to May 19, 1978
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Ka Storage Vessels for Petroleum Liquids for which Construction, Reconstruction, or Modification Commenced after May 18, 1978 and prior to July 23, 1984
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Kb VOC Liquid Storage Vessels (including Petroleum Liquid Storage Vessels) for which Construction, Reconstruction, or Modification Commenced after July 23, 1984
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  L Secondary Lead Smelters
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  M Secondary Brass and Bronze Production Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  N Primary Emissions from Basic Oxygen Process Furnaces for which Construction is Commenced after June 11, 1973
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Na Secondary Emissions from Basic Oxygen Process Steel-making Facilities for which Construction is Commenced after January 20, 1983
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  O Sewage Treatment Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  P Primary Copper Smelters
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Q Primary Zinc Smelters
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  R Primary Lead Smelters
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  S Primary Aluminum Reduction Plants 10

                  X

                  T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  U Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  V Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  W Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Y Coal Preparation Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  Z Ferroalloy Production Facilities
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  AA Steel Plants: Electric Arc Furnaces Constructed after October 21, 1974 and on or before August 17, 1983
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  AAa Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed after August 7, 1983
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  BB Kraft Pulp Mills 11

                  X

                  CC Glass Manufacturing Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  DD Grain Elevators
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  EE Surface Coating of Metal Furniture
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  GG Stationary Gas Turbines
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  HH Lime Manufacturing Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  KK Lead-Acid Battery Manufacturing Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  LL Metallic Mineral Processing Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  MM Automobile and Light Duty Truck Surface Coating Operations
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  NN Phosphate Rock Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  PP Ammonium Sulfate Manufacture
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  QQ Graphic Arts Industry: Publication Rotogravure Printing
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  RR Pressure Sensitive Tape and Label Surface Coating Standards
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  SS Industrial Surface Coating: Large Appliances
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  TT Metal Coil Surface Coating
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  UU Asphalt Processing and Asphalt Roof Manufacture
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  VV Equipment Leaks of VOC in Synthetic Organic Chemical Manufacturing Industry
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  WW Beverage Can Surface Coating Industry
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  XX Bulk Gasoline Terminals
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  AAA New Residential Wood Heaters

                  BBB Rubber Tire Manufacturing Industry
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  DDD VOC Emissions from Polymer Manufacturing Industry
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  FFF Flexible Vinyl and Urethane Coating and Printing
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  GGG Equipment Leaks of VOC in Petroleum Refineries
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  HHH Synthetic Fiber Production Facilities
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  III VOC Emissions from Synthetic Organic Chemical Manufacturing Industry Air Oxidation Unit Processes
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  JJJ Petroleum Dry Cleaners
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  KKK Equipment Leaks of VOC from Onshore Natural Gas Processing Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  LLL Onshore Natural Gas Processing: SO2 Emissions
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  NNN VOC Emissions from Synthetic Organic Chemical Manufacturing Industry Distillation Operations
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  OOO Nonmetallic Mineral Processing Plants

                  X

                  X

                  X

                  PPP Wool Fiberglass Insulation Manufacturing Plants
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  QQQ VOC Emissions from Petroleum Refinery Wastewater Systems
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  RRR VOCs from Synthetic Organic Chemical Manufacturing Industry Reactor Processes
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  SSS Magnetic Tape Coating Facilities
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  UUU Calciners and Dryers in Mineral Industries
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  VVV Polymeric Coating of Supporting Substrates Facilities
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  WWW Municipal Solid Waste Landfills
                  X
                  X
                  X
                  X
                  X
                  X
                  X
                  X

                  AAAA Small Municipal Waste Combustion Units for which Construction is Commenced after August 30, 1999 or for which Modification or Reconstruction is Commenced after June 6, 2001
                  X
                  X

                  X
                  X
                  X

                  X

                  BBBB Small Municipal Waste Combustion Units Constructed on or before August 30, 1999 (Emission Guidelines and Compliance Times)

                  CCCC Commercial and Industrial Solid Waste Incineration Units for which Construction is Commenced after November, 30, 1999 or for which Modification or Reconstruction is Commenced on or after June 1, 2001
                  X
                  X

                  X
                  X
                  X

                  X

                  DDDD Commercial and Industrial Solid Waste Incineration Units that Commenced Construction on or before November 30, 1999 (Emission Guidelines and Compliance Times)

                  1 Any authority within any subpart of this part that is not delegable, is not delegated. Please refer to Attachment B to the delegation letters for a listing of the NSPS authorities excluded from delegation.

                  2 Washington State Department of Ecology, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

                  3 Benton Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

                  4 Northwest Air Pollution Authority, for all NSPS delegated, as in effect on July 1, 2000.

                  5 Olympic Regional Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

                  6 Puget Sound Clean Air Authority, for all NSPS delegated, as in effect on July 1, 2002.

                  7 Spokane County Air Pollution Control Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

                  8 Southwest Clean Air Agency, for all NSPS delegated, as in effect on July 1, 2000.

                  9 Yakima Regional Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

                  10 Subpart S of this part is not delegated to local agencies in Washington because the Washington State Department of Ecology retains sole authority to regulate Primary Aluminum Plants, pursuant to Washington Administrative Code 173-415-010.

                  11 Subpart BB of this part is not delegated to local agencies in Washington because the Washington State Department of Ecology retains sole authority to regulate Kraft and Sulfite Pulping Mills, pursuant to Washington State Administrative Code 173-405-012 and 173-410-012.

              (50) State of West Virginia, Department of Environmental Protection, Division of Air Quality, 601 57th Street, SE., Charleston, West Virginia 25304.
              (51) State of Wisconsin: Wisconsin Department of Natural Resouces, 101 South Webster St., P.O. Box 7921, Madison, Wisconsin 53707-7921.

              (52) State of Wyoming, Department of Environmental Quality, Air Quality Division, Herschler Building, 122 West 25th Street, Cheyenne, WY 82002.

                Note:
                For a table listing Region VIII's NSPS delegation status, see paragraph (c) of this section.

              (53) Territory of Guam: Guam Environmental Protection Agency, P.O. Box 22439 GMF, Barrigada, Guam 96921.

                Note:
                For tables listing the delegation status of agencies in Region IX, see paragraph (d) of this section.

              (54) Commonwealth of Puerto Rico: Commonwealth of Puerto Rico Environmental Quality Board, P.O. Box 11488, Santurce, PR 00910, Attention: Air Quality Area Director (see table under § 60.4(b)(FF)(1)).
              (55) U.S. Virgin Islands: U.S. Virgin Islands Department of Conservation and Cultural Affairs, P.O. Box 578, Charlotte Amalie, St. Thomas, VI 00801.

              (56) American Samoa: American Samoa Environmental Protection Agency, P.O. Box PPA, Pago Pago, American Samoa 96799.

                Note:
                For tables listing the delegation status of agencies in Region IX, see paragraph (d) of this section.

              (57) Commonwealth of the Northern Mariana Islands: CNMI Division of Environmental Quality, P.O. Box 501304, Saipan, MP 96950.

                Note:
                For tables listing the delegation status of agencies in Region IX, see paragraph (d) of this section.

              (c) The delegation status table for New Source Performance Standards for Region VIII can be found online at http://www2.epa.gov/region8/air-program.

              (d) The following tables list the specific part 60 standards that have been delegated unchanged to the air pollution control agencies in Region IX. The (X) symbol is used to indicate each standard that has been delegated. The following provisions of this subpart are not delegated: §§ 60.4(b), 60.8(b), 60.9, 60.11(b), 60.11(e), 60.13(a), 60.13(d)(2), 60.13(g), 60.13(i).
              (1) Arizona. The following table identifies delegations for Arizona:

                Table 3 to Paragraph (d)(1)—Delegation Status for New Source Performance Standards for Arizona

                  Subpart
                  Air pollution control agency
                  ArizonaDEQ

                  MaricopaCounty

                  PimaCounty

                  PinalCounty

                  A
                  General Provisions
                  X
                  X
                  X
                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X
                  X
                  X
                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978
                  X
                  X
                  X
                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X
                  X
                  X

                  Dc
                  Small Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X
                  X
                  X

                  E
                  Incinerators
                  X
                  X
                  X
                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994
                  X
                  X
                  X
                  X

                  Eb
                  Large Municipal Waste Combustors Constructed After September 20, 1994
                  X
                  X
                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996
                  X
                  X
                  X

                  F
                  Portland Cement Plants
                  X

                  X
                  X

                  G
                  Nitric Acid Plants
                  X
                  X
                  X
                  X

                  Ga
                  Nitric Acid Plants For Which Construction, Reconstruction or Modification Commenced After October 14, 2011

                  X
                  X

                  H
                  Sulfuric Acid Plant
                  X
                  X
                  X
                  X

                  I
                  Hot Mix Asphalt Facilities
                  X
                  X
                  X
                  X

                  J
                  Petroleum Refineries
                  X

                  X
                  X

                  Ja
                  Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X
                  X
                  X
                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984
                  X
                  X
                  X
                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
                  X
                  X
                  X
                  X

                  L
                  Secondary Lead Smelters
                  X

                  X
                  X

                  M
                  Secondary Brass and Bronze Production Plants
                  X
                  X
                  X
                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973
                  X
                  X
                  X
                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983
                  X
                  X
                  X
                  X

                  O
                  Sewage Treatment Plants
                  X
                  X
                  X
                  X

                  P
                  Primary Copper Smelters
                  X

                  X
                  X

                  Q
                  Primary Zinc Smelters
                  X

                  X
                  X

                  R
                  Primary Lead Smelters
                  X

                  X
                  X

                  S
                  Primary Aluminum Reduction Plants
                  X
                  X
                  X
                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants
                  X
                  X
                  X
                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  X
                  X
                  X
                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  X
                  X
                  X
                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  X
                  X
                  X
                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
                  X
                  X
                  X
                  X

                  Y
                  Coal Preparation and Processing Plants
                  X
                  X
                  X
                  X

                  Z
                  Ferroalloy Production Facilities
                  X
                  X
                  X
                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
                  X
                  X
                  X
                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983
                  X
                  X
                  X
                  X

                  BB
                  Kraft Pulp Mills
                  X
                  X
                  X
                  X

                  BBa
                  Kraft Pulp Mill Sources for which Construction, Reconstruction or Modification Commenced after May 23, 2013

                  X
                  X

                  CC
                  Glass Manufacturing Plants
                  X
                  X
                  X
                  X

                  DD
                  Grain Elevators
                  X
                  X
                  X
                  X

                  EE
                  Surface Coating of Metal Furniture
                  X
                  X
                  X
                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines
                  X
                  X
                  X
                  X

                  HH
                  Lime Manufacturing Plants
                  X
                  X
                  X
                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants
                  X
                  X
                  X
                  X

                  LL
                  Metallic Mineral Processing Plants
                  X
                  X
                  X
                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations
                  X
                  X
                  X
                  X

                  NN
                  Phosphate Rock Plants
                  X
                  X
                  X
                  X

                  PP
                  Ammonium Sulfate Manufacture
                  X
                  X
                  X
                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing
                  X
                  X
                  X
                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations
                  X
                  X
                  X
                  X

                  SS
                  Industrial Surface Coating: Large Appliances
                  X
                  X
                  X
                  X

                  TT
                  Metal Coil Surface Coating
                  X
                  X
                  X
                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture
                  X
                  X
                  X
                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing
                  X
                  X
                  X
                  X

                  VVa
                  Equipment Leaks of VOC in the Synthetic Organic Industry for Which Construction, Reconstruction, or Chemicals Manufacturing Modification Commenced After November 7, 2006
                  X
                  X
                  X

                  WW
                  Beverage Can Surface Coating Industry
                  X
                  X
                  X
                  X

                  XX
                  Bulk Gasoline Terminals
                  X
                  X
                  X
                  X

                  AAA
                  New Residential Wood Heaters
                  X
                  X
                  X
                  X

                  BBB
                  Rubber Tire Manufacturing Industry
                  X
                  X
                  X
                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry
                  X
                  X
                  X
                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing
                  X
                  X
                  X
                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries
                  X

                  X
                  X

                  GGGa
                  Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006
                  X

                  X

                  HHH
                  Synthetic Fiber Production Facilities
                  X
                  X
                  X
                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes
                  X
                  X
                  X
                  X

                  JJJ
                  Petroleum Dry Cleaners
                  X
                  X
                  X
                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants
                  X
                  X
                  X
                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions
                  X
                  X
                  X
                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations
                  X
                  X
                  X
                  X

                  OOO
                  Nonmetallic Mineral Processing Plants
                  X
                  X
                  X
                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants
                  X
                  X
                  X
                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems
                  X

                  X
                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes
                  X
                  X

                  SSS
                  Magnetic Tape Coating Facilities
                  X
                  X
                  X
                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines
                  X
                  X
                  X
                  X

                  UUU
                  Calciners and Dryers in Mineral Industries
                  X
                  X
                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities
                  X
                  X
                  X
                  X

                  WWW
                  Municipal Solid Waste Landfills
                  X
                  X
                  X

                  XXX
                  Municipal Solid Waste Landfills that Commenced Construction, Reconstruction, or Modification After July 17, 2014

                  X

                  AAAA
                  Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commended After June 6, 2001
                  X
                  X
                  X

                  CCCC
                  Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001
                  X
                  X
                  X

                  EEEE
                  Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006
                  X
                  X
                  X

                  GGGG
                  (Reserved)

                  HHHH
                  (Reserved)

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines
                  X
                  X
                  X

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines

                  X
                  X

                  KKKK
                  Stationary Combustion Turbines
                  X
                  X
                  X

                  LLLL
                  New Sewage Sludge Incineration Units

                  X

                  MMMM
                  Emissions Guidelines and Compliance Times for Existing Sewage Sludge Incineration Units
                  X

                  OOOO
                  Crude Oil and Natural Gas Production, Transmission, and Distribution

                  X
                  X

                  OOOOa
                  Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification or Reconstruction Commenced After September 18, 2015

                  X

                  QQQQ
                  Standards of Performance for New Residential Hydronic Heaters and Forced-Air Furnaces

                  X
                  X

                  TTTT
                  Standards of Performance for Greenhouse Gas Emissions for Electric Generating Units

                  X

              (2) California. The following tables identify delegations for each of the local air pollution control agencies of California.

              (i) Delegations for Amador County Air Pollution Control District, Antelope Valley Air Quality Management District, Bay Area Air Quality Management District, and Butte County Air Quality Management District are shown in the following table:

                Delegation Status for New Source Performance Standards for Amador County APCD, Antelope Valley AQMD, Bay Area AQMD, and Butte County AQMD

                  Subpart
                  Air pollution control agency
                  AmadorCounty APCD

                  AntelopeValley AQMD

                  Bay Area AQMD
                  Butte County AQMD

                  A
                  General Provisions

                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971

                  X
                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978

                  X
                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units

                  X
                  X

                  Dc
                  Small Industrial-Commercial-Institutional Steam Generating Units

                  X
                  X

                  E
                  Incinerators

                  X
                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994

                  X
                  X

                  Eb
                  Large Municipal Waste Combustors Constructed After September 20, 1994

                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996

                  X

                  F
                  Portland Cement Plants

                  X
                  X

                  G
                  Nitric Acid Plants

                  X
                  X

                  Ga
                  Nitric Acid Plants For Which Construction, Reconstruction or Modification Commenced After October 14, 2011

                  H
                  Sulfuric Acid Plant

                  X
                  X

                  I
                  Hot Mix Asphalt Facilities

                  X
                  X

                  J
                  Petroleum Refineries

                  X
                  X

                  Ja
                  Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978

                  X
                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984

                  X
                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984

                  X
                  X

                  L
                  Secondary Lead Smelters

                  X
                  X

                  M
                  Secondary Brass and Bronze Production Plants

                  X
                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973

                  X
                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983

                  X
                  X

                  O
                  Sewage Treatment Plants

                  X
                  X

                  P
                  Primary Copper Smelters

                  X
                  X

                  Q
                  Primary Zinc Smelters

                  X
                  X

                  R
                  Primary Lead Smelters

                  X
                  X

                  S
                  Primary Aluminum Reduction Plants

                  X
                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants

                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants

                  X
                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants

                  X
                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants

                  X
                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities

                  X
                  X

                  Y
                  Coal Preparation and Processing Plants

                  X
                  X

                  Z
                  Ferroalloy Production Facilities

                  X
                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983

                  X
                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983

                  X
                  X

                  BB
                  Kraft Pulp Mills

                  X
                  X

                  CC
                  Glass Manufacturing Plants

                  X
                  X

                  DD
                  Grain Elevators

                  X
                  X

                  EE
                  Surface Coating of Metal Furniture

                  X
                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines

                  X
                  X

                  HH
                  Lime Manufacturing Plants

                  X
                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants

                  X
                  X

                  LL
                  Metallic Mineral Processing Plants

                  X
                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations

                  X
                  X

                  NN
                  Phosphate Rock Plants

                  X
                  X

                  PP
                  Ammonium Sulfate Manufacture

                  X
                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing

                  X
                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations

                  X
                  X

                  SS
                  Industrial Surface Coating: Large Appliances

                  X
                  X

                  TT
                  Metal Coil Surface Coating

                  X
                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture

                  X
                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing

                  X
                  X

                  VVa
                  Equipment Leaks of VOC in the Synthetic Organic Industry for Which Construction, Reconstruction, or Chemicals Manufacturing Modification Commenced After November 7, 2006

                  X

                  WW
                  Beverage Can Surface Coating Industry

                  X
                  X

                  XX
                  Bulk Gasoline Terminals

                  AAA
                  New Residential Wood Heaters

                  X
                  X

                  BBB
                  Rubber Tire Manufacturing Industry

                  X
                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry

                  X
                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing

                  X
                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries

                  X
                  X

                  GGGa
                  Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

                  X

                  HHH
                  Synthetic Fiber Production Facilities

                  X
                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

                  X

                  JJJ
                  Petroleum Dry Cleaners

                  X
                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants

                  X
                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions

                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations

                  X
                  X

                  OOO
                  Nonmetallic Mineral Processing Plants

                  X
                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants

                  X
                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems

                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes

                  X

                  SSS
                  Magnetic Tape Coating Facilities

                  X
                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines

                  X
                  X

                  UUU
                  Calciners and Dryers in Mineral Industries

                  X
                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities

                  X
                  X

                  WWW
                  Municipal Solid Waste Landfills

                  X

                  AAAA
                  Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commended After June 6, 2001

                  X

                  CCCC
                  Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001

                  X

                  EEEE
                  Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006

                  X

                  GGGG
                  (Reserved)

                  HHHH
                  (Reserved)

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines

                  X

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines

                  X

                  KKKK
                  Stationary Combustion Turbines

                  X

                  LLLL
                  New Sewage Sludge Incineration Units

                  OOOO
                  Crude Oil and Natural Gas Production, Transmission, and Distribution

              (ii) [Reserved]
              (iii) Delegations for Glenn County Air Pollution Control District, Great Basin Unified Air Pollution Control District, Imperial County Air Pollution Control District, and Kern County Air Pollution Control District are shown in the following table:

                Delegation Status for New Source Performance Standards for Glenn County APCD, Great Basin Unified APCD, Imperial County APCD, and Kern County APCD

                  Subpart
                  Air pollution control agency
                  GlennCounty APCD

                  Great Basin Unified APCD
                  Imperial County APCD
                  Kern County APCD

                  A
                  General Provisions

                  X

                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971

                  X

                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978

                  X

                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units

                  X

                  X

                  Dc
                  Small Industrial Steam Generating Units

                  X

                  X

                  E
                  Incinerators

                  X

                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994

                  X

                  Eb
                  Municipal Waste Combustors Constructed After September 20, 1994

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996

                  F
                  Portland Cement Plants

                  X

                  X

                  G
                  Nitric Acid Plants

                  X

                  X

                  H
                  Sulfuric Acid Plants

                  X

                  I
                  Hot Mix Asphalt Facilities

                  X

                  X

                  J
                  Petroleum Refineries

                  X

                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978

                  X

                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984

                  X

                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984

                  X

                  X

                  L
                  Secondary Lead Smelters

                  X

                  X

                  M
                  Secondary Brass and Bronze Production Plants

                  X

                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973

                  X

                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983

                  X

                  X

                  O
                  Sewage Treatment Plants

                  X

                  X

                  P
                  Primary Copper Smelters

                  X

                  X

                  Q
                  Primary Zinc Smelters

                  X

                  X

                  R
                  Primary Lead Smelters

                  X

                  X

                  S
                  Primary Aluminum Reduction Plants

                  X

                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants

                  X

                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants

                  X

                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants

                  X

                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants

                  X

                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities

                  X

                  X

                  Y
                  Coal Preparation Plants

                  X

                  X

                  Z
                  Ferroalloy Production Facilities

                  X

                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983

                  X

                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983

                  X

                  X

                  BB
                  Kraft pulp Mills

                  X

                  X

                  CC
                  Glass Manufacturing Plants

                  X

                  X

                  DD
                  Grain Elevators

                  X

                  X

                  EE
                  Surface Coating of Metal Furniture

                  X

                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines

                  X

                  X

                  HH
                  Lime Manufacturing Plants

                  X

                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants

                  X

                  X

                  LL
                  Metallic Mineral Processing Plants

                  X

                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations

                  X

                  X

                  NN
                  Phosphate Rock Plants

                  X

                  X

                  PP
                  Ammonium Sulfate Manufacture

                  X

                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing

                  X

                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations

                  X

                  X

                  SS
                  Industrial Surface Coating: Large Appliances

                  X

                  X

                  TT
                  Metal Coil Surface Coating

                  X

                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture

                  X

                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry

                  X

                  X

                  WW
                  Beverage Can Surface Coating Industry

                  X

                  X

                  XX
                  Bulk Gasoline Terminals

                  AAA
                  New Residential Wool Heaters

                  X

                  X

                  BBB
                  Rubber Tire Manufacturing Industry

                  X

                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry

                  X

                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing

                  X

                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries

                  X

                  X

                  HHH
                  Synthetic Fiber Production Facilities

                  X

                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

                  X

                  X

                  JJJ
                  Petroleum Dry Cleaners

                  X

                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants

                  X

                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions

                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations

                  X

                  X

                  OOO
                  Nonmetallic Mineral Processing Plants

                  X

                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants

                  X

                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems

                  X

                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes

                  X

                  SSS
                  Magnetic Tape Coating Facilities

                  X

                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines

                  X
                  X

                  UUU
                  Calciners and Dryers in Mineral Industries

                  X

                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities

                  X

                  X

                  WWW
                  Municipal Solid Waste Landfills

                  X

              (iv) Delegations for Lake County Air Quality Management District, Lassen County Air Pollution Control District, Mariposa County Air Pollution Control District, and Mendocino County Air Pollution Control District are shown in the following table:

                Delegation Status for New Source Performance Standards for Lake County Air Quality Management District, Lassen County Air Pollution Control District, Mariposa County Air Pollution Control District, and Mendocino County Air Pollution Control District

                  Subpart
                  Air pollution control agency
                  Lake County AQMD
                  Lassen County APCD
                  Mariposa County AQMD
                  Mendocino County AQMD

                  A
                  General Provisions
                  X

                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X

                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978
                  X

                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units
                  X

                  Dc
                  Small Industrial Steam Generating Units
                  X

                  X

                  E
                  Incinerators
                  X

                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994
                  X

                  X

                  Eb
                  Municipal Waste Combustors Constructed After September 20, 1994

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996

                  F
                  Portland Cement Plants
                  X

                  X

                  G
                  Nitric Acid Plants
                  X

                  X

                  H
                  Sulfuric Acid Plants
                  X

                  X

                  I
                  Hot Mix Asphalt Facilities
                  X

                  X

                  J
                  Petroleum Refineries
                  X

                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X

                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984
                  X

                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
                  X

                  X

                  L
                  Secondary Lead Smelters
                  X

                  X

                  M
                  Secondary Brass and Bronze Production Plants
                  X

                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973
                  X

                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983
                  X

                  X

                  O
                  Sewage Treatment Plants
                  X

                  X

                  P
                  Primary Copper Smelters
                  X

                  X

                  Q
                  Primary Zinc Smelters
                  X

                  X

                  R
                  Primary Lead Smelters
                  X

                  X

                  S
                  Primary Aluminum Reduction Plants
                  X

                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants
                  X

                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  X

                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  X

                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  X

                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
                  X

                  X

                  Y
                  Coal Preparation Plants
                  X

                  X

                  Z
                  Ferroalloy Production Facilities
                  X

                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
                  X

                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983
                  X

                  X

                  BB
                  Kraft Pulp Mills
                  X

                  X

                  CC
                  Glass Manufacturing Plants
                  X

                  X

                  DD
                  Grain Elevators
                  X

                  X

                  EE
                  Surface Coating of Metal Furniture
                  X

                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines
                  X

                  X

                  HH
                  Lime Manufacturing Plants
                  X

                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants
                  X

                  X

                  LL
                  Metallic Mineral Processing Plants
                  X

                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations
                  X

                  X

                  NN
                  Phosphate Rock Plants
                  X

                  X

                  PP
                  Ammonium Sulfate Manufacture
                  X

                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing
                  X

                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations
                  X

                  X

                  SS
                  Industrial Surface Coating: Large Appliances
                  X

                  X

                  TT
                  Metal Coil Surface Coating
                  X

                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture
                  X

                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry
                  X

                  X

                  WW
                  Beverage Can Surface Coating Industry
                  X

                  X

                  XX
                  Bulk Gasoline Terminals

                  AAA
                  New Residential Wool Heaters
                  X

                  X

                  BBB
                  Rubber Tire Manufacturing Industry
                  X

                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry
                  X

                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing
                  X

                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries
                  X

                  X

                  HHH
                  Synthetic Fiber Production Facilities
                  X

                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes
                  X

                  X

                  JJJ
                  Petroleum Dry Cleaners
                  X

                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants
                  X

                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions
                  X

                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations
                  X

                  X

                  OOO
                  Nonmetallic Mineral Processing Plants
                  X

                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants
                  X

                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems
                  X

                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes
                  X

                  SSS
                  Magnetic Tape Coating Facilities
                  X

                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines

                  UUU
                  Calciners and Dryers in Mineral Industries
                  X

                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities
                  X

                  X

                  WWW
                  Municipal Solid Waste Landfills
                  X

              (v) Delegations for Modoc Air Pollution Control District, Mojave Desert Air Quality Management District, Monterey Bay Unified Air Pollution Control District and North Coast Unified Air Quality Management District are shown in the following table:

                Delegation Status for New Source Performance Standards for Modoc County APCD, Mojave Desert AQMD, Monterey Bay Unified APCD, and North Coast Unified AQMD

                  Subpart
                  Air pollution control agency
                  Modoc County APCD
                  Mojave Desert AQMD
                  Monterey Bay Unified APCD
                  North Coast Unified AQMD

                  A
                  General Provisions
                  X
                  X
                  X
                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X
                  X
                  X
                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978
                  X
                  X
                  X
                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X
                  X
                  X

                  Dc
                  Small Industrial-Commercial-Institutional Steam Generating Units

                  X
                  X

                  E
                  Incinerators
                  X
                  X
                  X
                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994

                  X

                  Eb
                  Large Municipal Waste Combustors Constructed After September 20, 1994

                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996

                  X

                  F
                  Portland Cement Plants
                  X
                  X
                  X
                  X

                  G
                  Nitric Acid Plants
                  X
                  X
                  X
                  X

                  Ga
                  Nitric Acid Plants For Which Construction, Reconstruction or Modification Commenced After October 14, 2011

                  H
                  Sulfuric Acid Plant
                  X
                  X
                  X
                  X

                  I
                  Hot Mix Asphalt Facilities
                  X
                  X
                  X
                  X

                  J
                  Petroleum Refineries
                  X
                  X
                  X
                  X

                  Ja
                  Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X
                  X
                  X
                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984
                  X
                  X
                  X
                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
                  X
                  X
                  X
                  X

                  L
                  Secondary Lead Smelters
                  X
                  X
                  X
                  X

                  M
                  Secondary Brass and Bronze Production Plants
                  X
                  X
                  X
                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973
                  X
                  X
                  X
                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983
                  X
                  X
                  X
                  X

                  O
                  Sewage Treatment Plants
                  X
                  X
                  X
                  X

                  P
                  Primary Copper Smelters
                  X
                  X
                  X
                  X

                  Q
                  Primary Zinc Smelters
                  X
                  X
                  X
                  X

                  R
                  Primary Lead Smelters
                  X
                  X
                  X
                  X

                  S
                  Primary Aluminum Reduction Plants
                  X
                  X
                  X
                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants
                  X
                  X
                  X
                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  X
                  X
                  X
                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  X
                  X
                  X
                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  X
                  X
                  X
                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
                  X
                  X
                  X
                  X

                  Y
                  Coal Preparation and Processing Plants
                  X
                  X
                  X
                  X

                  Z
                  Ferroalloy Production Facilities
                  X
                  X
                  X
                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
                  X
                  X
                  X
                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983
                  X
                  X
                  X
                  X

                  BB
                  Kraft Pulp Mills
                  X
                  X
                  X
                  X

                  CC
                  Glass Manufacturing Plants
                  X
                  X
                  X
                  X

                  DD
                  Grain Elevators
                  X
                  X
                  X
                  X

                  EE
                  Surface Coating of Metal Furniture
                  X
                  X
                  X
                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines
                  X
                  X
                  X
                  X

                  HH
                  Lime Manufacturing Plants
                  X
                  X
                  X
                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants
                  X
                  X
                  X
                  X

                  LL
                  Metallic Mineral Processing Plants
                  X
                  X
                  X
                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations
                  X
                  X
                  X
                  X

                  NN
                  Phosphate Rock Plants
                  X
                  X
                  X
                  X

                  PP
                  Ammonium Sulfate Manufacture
                  X
                  X
                  X
                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing
                  X
                  X
                  X
                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations
                  X
                  X
                  X
                  X

                  SS
                  Industrial Surface Coating: Large Appliances
                  X
                  X
                  X
                  X

                  TT
                  Metal Coil Surface Coating
                  X
                  X
                  X
                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture
                  X
                  X
                  X
                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing
                  X
                  X
                  X
                  X

                  VVa
                  Equipment Leaks of VOC in the Synthetic Organic Industry for Which Construction, Reconstruction, or Chemicals Manufacturing Modification Commenced After November 7, 2006

                  X

                  WW
                  Beverage Can Surface Coating Industry
                  X
                  X
                  X
                  X

                  XX
                  Bulk Gasoline Terminals

                  AAA
                  New Residential Wood Heaters
                  X
                  X
                  X
                  X

                  BBB
                  Rubber Tire Manufacturing Industry
                  X
                  X
                  X
                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry
                  X
                  X
                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing
                  X
                  X
                  X
                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries
                  X
                  X
                  X
                  X

                  GGGa
                  Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

                  X

                  HHH
                  Synthetic Fiber Production Facilities
                  X
                  X
                  X
                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

                  X

                  JJJ
                  Petroleum Dry Cleaners
                  X
                  X
                  X
                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants
                  X
                  X
                  X
                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions
                  X
                  X
                  X
                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations
                  X
                  X
                  X

                  OOO
                  Nonmetallic Mineral Processing Plants
                  X
                  X
                  X
                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants
                  X
                  X
                  X
                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems
                  X
                  X
                  X
                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes

                  X

                  SSS
                  Magnetic Tape Coating Facilities
                  X
                  X
                  X
                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines
                  X
                  X
                  X
                  X

                  UUU
                  Calciners and Dryers in Mineral Industries

                  X
                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities

                  X
                  X
                  X

                  WWW
                  Municipal Solid Waste Landfills

                  X

                  AAAA
                  Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commended After June 6, 2001

                  X

                  CCCC
                  Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001

                  X

                  EEEE
                  Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006

                  X

                  GGGG
                  (Reserved)

                  HHHH
                  (Reserved)

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines

                  X

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines

                  X

                  KKKK
                  Stationary Combustion Turbines

                  X

                  LLLL
                  New Sewage Sludge Incineration Units

                  OOOO
                  Crude Oil and Natural Gas Production, Transmission, and Distribution

              (vi) Delegations for Northern Sierra Air Quality Management District, Northern Sonoma County Air Pollution Control District, Placer County Air Pollution Control District, and Sacramento Metropolitan Air Quality Management District are shown in the following table:

                Delegation Status for New Source Performance Standards for Northern Sierra Air Quality Management District, Northern Sonoma County Air Pollution Control District, Placer County Air Pollution Control District, and Sacramento Metropolitan Air Quality Management District

                  Subpart
                  Air pollution control agency
                  Northern Sierra AQMD
                  Northern Sonoma County APCD
                  Placer County APCD
                  Sacramento Metropolitan AQMD

                  A
                  General Provisions

                  X

                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971

                  X

                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978

                  X

                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units

                  X

                  Dc
                  Small Industrial Steam Generating Units

                  X

                  E
                  Incinerators

                  X

                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994

                  X

                  Eb
                  Municipal Waste Combustors Constructed After September 20, 1994

                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996

                  X

                  F
                  Portland Cement Plants

                  X

                  X

                  G
                  Nitric Acid Plants

                  X

                  X

                  H
                  Sulfuric Acid Plants

                  X

                  X

                  I
                  Hot Mix Asphalt Facilities

                  X

                  X

                  J
                  Petroleum Refineries

                  X

                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978

                  X

                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984

                  X

                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984

                  X

                  L
                  Secondary Lead Smelters

                  X

                  X

                  M
                  Secondary Brass and Bronze Production Plants

                  X

                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973

                  X

                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983

                  X

                  O
                  Sewage Treatment Plants

                  X

                  X

                  P
                  Primary Copper Smelters

                  X

                  X

                  Q
                  Primary Zinc Smelters

                  X

                  X

                  R
                  Primary Lead Smelters

                  X

                  X

                  S
                  Primary Aluminum Reduction Plants

                  X

                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants

                  X

                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants

                  X

                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants

                  X

                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants

                  X

                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities

                  X

                  X

                  Y
                  Coal Preparation Plants

                  X

                  X

                  Z
                  Ferroalloy Production Facilities

                  X

                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983

                  X

                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983

                  X

                  BB
                  Kraft pulp Mills

                  X

                  X

                  CC
                  Glass Manufacturing Plants

                  X

                  X

                  DD
                  Grain Elevators

                  X

                  X

                  EE
                  Surface Coating of Metal Furniture

                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines

                  X

                  X

                  HH
                  Lime Manufacturing Plants

                  X

                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants

                  X

                  LL
                  Metallic Mineral Processing Plants

                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations

                  X

                  X

                  NN
                  Phosphate Rock Plants

                  X

                  PP
                  Ammonium Sulfate Manufacture

                  X

                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing

                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations

                  X

                  SS
                  Industrial Surface Coating: Large Appliances

                  X

                  TT
                  Metal Coil Surface Coating

                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture

                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry

                  X

                  WW
                  Beverage Can Surface Coating Industry

                  X

                  XX
                  Bulk Gasoline Terminals

                  AAA
                  New Residential Wool Heaters

                  X

                  BBB
                  Rubber Tire Manufacturing Industry

                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry

                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing

                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries

                  X

                  HHH
                  Synthetic Fiber Production Facilities

                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

                  X

                  JJJ
                  Petroleum Dry Cleaners

                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants

                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions

                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations

                  X

                  OOO
                  Nonmetallic Mineral Processing Plants

                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants

                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems

                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes

                  X

                  SSS
                  Magnetic Tape Coating Facilities

                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines

                  X

                  UUU
                  Calciners and Dryers in Mineral Industries

                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities

                  X

                  WWW
                  Municipal Solid Waste Landfills

                  X

              (vii) Delegations for San Diego County Air Pollution Control District, San Joaquin Valley Unified Air Pollution Control District, San Luis Obispo County Air Pollution Control District, and Santa Barbara County Air Pollution Control District are shown in the following table:

                Delegation Status for New Source Performance Standards for San Diego County APCD, San Joaquin Valley Unified APCD, San Luis Obispo County APCD, and Santa Barbara County APCD

                  Subpart
                  Air pollution control agency
                  San Diego County APCD
                  San Joaquin Valley Unified APCD
                  San Luis Obispo County APCD
                  Santa Barbara County APCD

                  A
                  General Provisions
                  X
                  X
                  X
                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X
                  X
                  X
                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978
                  X
                  X
                  X
                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X
                  X
                  X

                  Dc
                  Small Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X
                  X
                  X

                  E
                  Incinerators
                  X
                  X
                  X
                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994
                  X
                  X
                  X

                  Eb
                  Large Municipal Waste Combustors Constructed After September 20, 1994
                  X
                  X

                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996
                  X

                  X

                  F
                  Portland Cement Plants
                  X
                  X
                  X

                  G
                  Nitric Acid Plants
                  X
                  X
                  X

                  Ga
                  Nitric Acid Plants For Which Construction, Reconstruction or Modification Commenced After October 14, 2011

                  H
                  Sulfuric Acid Plant
                  X
                  X
                  X

                  I
                  Hot Mix Asphalt Facilities
                  X
                  X
                  X
                  X

                  J
                  Petroleum Refineries
                  X
                  X
                  X
                  X

                  Ja
                  Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X
                  X
                  X
                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984
                  X
                  X
                  X
                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
                  X
                  X
                  X
                  X

                  L
                  Secondary Lead Smelters
                  X
                  X
                  X
                  X

                  M
                  Secondary Brass and Bronze Production Plants
                  X
                  X
                  X
                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973
                  X
                  X
                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983
                  X
                  X
                  X

                  O
                  Sewage Treatment Plants
                  X
                  X
                  X
                  X

                  P
                  Primary Copper Smelters
                  X
                  X
                  X

                  Q
                  Primary Zinc Smelters
                  X
                  X
                  X

                  R
                  Primary Lead Smelters
                  X
                  X
                  X

                  S
                  Primary Aluminum Reduction Plants
                  X
                  X
                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants
                  X
                  X
                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  X
                  X
                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  X
                  X
                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  X
                  X
                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
                  X
                  X
                  X

                  Y
                  Coal Preparation and Processing Plants
                  X
                  X
                  X

                  Z
                  Ferroalloy Production Facilities
                  X
                  X
                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
                  X
                  X
                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983
                  X
                  X
                  X

                  BB
                  Kraft Pulp Mills
                  X
                  X
                  X

                  CC
                  Glass Manufacturing Plants
                  X
                  X
                  X
                  X

                  DD
                  Grain Elevators
                  X
                  X
                  X
                  X

                  EE
                  Surface Coating of Metal Furniture
                  X
                  X
                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines
                  X
                  X
                  X
                  X

                  HH
                  Lime Manufacturing Plants
                  X
                  X
                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants
                  X
                  X
                  X

                  LL
                  Metallic Mineral Processing Plants
                  X
                  X
                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations
                  X
                  X
                  X

                  NN
                  Phosphate Rock Plants
                  X
                  X
                  X

                  PP
                  Ammonium Sulfate Manufacture
                  X
                  X
                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing
                  X
                  X
                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations
                  X
                  X
                  X

                  SS
                  Industrial Surface Coating: Large Appliances
                  X
                  X
                  X

                  TT
                  Metal Coil Surface Coating
                  X
                  X
                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture
                  X
                  X
                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing
                  X
                  X
                  X

                  VVa
                  Equipment Leaks of VOC in the Synthetic Organic Industry for Which Construction, Reconstruction, or Chemicals Manufacturing Modification Commenced After November 7, 2006

                  X

                  WW
                  Beverage Can Surface Coating Industry
                  X
                  X
                  X

                  XX
                  Bulk Gasoline Terminals

                  AAA
                  New Residential Wood Heaters
                  X
                  X
                  X
                  X

                  BBB
                  Rubber Tire Manufacturing Industry
                  X
                  X
                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry
                  X
                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing
                  X
                  X
                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries
                  X
                  X
                  X

                  GGGa
                  Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

                  X

                  HHH
                  Synthetic Fiber Production Facilities
                  X
                  X
                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes
                  X
                  X

                  JJJ
                  Petroleum Dry Cleaners
                  X
                  X
                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants
                  X
                  X
                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions
                  X
                  X
                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations
                  X
                  X

                  OOO
                  Nonmetallic Mineral Processing Plants
                  X
                  X
                  X
                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants
                  X
                  X
                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems
                  X
                  X
                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes
                  X
                  X
                  X

                  SSS
                  Magnetic Tape Coating Facilities
                  X
                  X
                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines
                  X
                  X
                  X

                  UUU
                  Calciners and Dryers in Mineral Industries
                  X
                  X
                  X
                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities
                  X
                  X
                  X
                  X

                  WWW
                  Municipal Solid Waste Landfills
                  X
                  X
                  X
                  X

                  AAAA
                  Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commended After June 6, 2001
                  X

                  X

                  CCCC
                  Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001
                  X

                  X

                  EEEE
                  Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006
                  X

                  X

                  GGGG
                  (Reserved)

                  HHHH
                  (Reserved)

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines

                  X

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines

                  X

                  KKKK
                  Stationary Combustion Turbines
                  X

                  X

                  LLLL
                  New Sewage Sludge Incineration Units

                  OOOO
                  Crude Oil and Natural Gas Production, Transmission, and Distribution

              (viii) Delegations for Shasta County Air Quality Management District, Siskiyou County Air Pollution Control District, South Coast Air Quality Management District, and Tehama County Air Pollution Control District are shown in the following table:

                Delegation Status for New Source Performance Standards for Shasta County AQMD, Siskiyou County APCD, South Coast AQMD, and Tehama County APCD

                  Subpart
                  Air pollution control agency
                  Shasta County AQMD
                  Siskiyou County APCD
                  South Coast AQMD
                  TehamaCounty APCD

                  A
                  General Provisions
                  X
                  X
                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X

                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978

                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units

                  X

                  Dc
                  Small Industrial-Commercial-Institutional Steam Generating Units

                  X

                  E
                  Incinerators
                  X

                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994

                  X

                  Eb
                  Large Municipal Waste Combustors Constructed After September 20, 1994

                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996

                  X

                  F
                  Portland Cement Plants
                  X

                  X

                  G
                  Nitric Acid Plants
                  X

                  X

                  Ga
                  Nitric Acid Plants For Which Construction, Reconstruction or Modification Commenced After October 14, 2011

                  H
                  Sulfuric Acid Plant
                  X

                  X

                  I
                  Hot Mix Asphalt Facilities
                  X

                  X

                  J
                  Petroleum Refineries
                  X

                  X

                  Ja
                  Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X

                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984

                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984

                  X

                  L
                  Secondary Lead Smelters
                  X

                  X

                  M
                  Secondary Brass and Bronze Production Plants
                  X

                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973
                  X

                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983

                  X

                  O
                  Sewage Treatment Plants
                  X

                  X

                  P
                  Primary Copper Smelters
                  X

                  X

                  Q
                  Primary Zinc Smelters
                  X

                  X

                  R
                  Primary Lead Smelters
                  X

                  X

                  S
                  Primary Aluminum Reduction Plants
                  X

                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants
                  X

                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  X

                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  X

                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  X

                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
                  X

                  X

                  Y
                  Coal Preparation and Processing Plants
                  X

                  X

                  Z
                  Ferroalloy Production Facilities
                  X

                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
                  X

                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983

                  X

                  BB
                  Kraft Pulp Mills
                  X

                  X

                  CC
                  Glass Manufacturing Plants

                  X

                  DD
                  Grain Elevators
                  X

                  X

                  EE
                  Surface Coating of Metal Furniture

                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines

                  X

                  HH
                  Lime Manufacturing Plants
                  X

                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants

                  X

                  LL
                  Metallic Mineral Processing Plants

                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations

                  X

                  NN
                  Phosphate Rock Plants

                  X

                  PP
                  Ammonium Sulfate Manufacture

                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing

                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations

                  X

                  SS
                  Industrial Surface Coating: Large Appliances

                  X

                  TT
                  Metal Coil Surface Coating

                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture

                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing

                  X

                  VVa
                  Equipment Leaks of VOC in the Synthetic Organic Industry for Which Construction, Reconstruction, or Chemicals Manufacturing Modification Commenced After November 7, 2006

                  X

                  WW
                  Beverage Can Surface Coating Industry

                  X

                  XX
                  Bulk Gasoline Terminals

                  AAA
                  New Residential Wood Heaters

                  X
                  X

                  BBB
                  Rubber Tire Manufacturing Industry

                  X
                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry

                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing

                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries

                  X

                  GGGa
                  Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

                  X

                  HHH
                  Synthetic Fiber Production Facilities

                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

                  X

                  JJJ
                  Petroleum Dry Cleaners

                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants

                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions

                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations

                  X

                  OOO
                  Nonmetallic Mineral Processing Plants

                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants

                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems

                  X
                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes

                  X

                  SSS
                  Magnetic Tape Coating Facilities

                  X
                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines

                  X
                  X

                  UUU
                  Calciners and Dryers in Mineral Industries

                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities

                  X

                  WWW
                  Municipal Solid Waste Landfills

                  X

                  AAAA
                  Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commended After June 6, 2001
                  X
                  X
                  X

                  CCCC
                  Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001

                  X

                  EEEE
                  Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006

                  X

                  GGGG
                  (Reserved)

                  HHHH
                  (Reserved)

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines

                  X

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines

                  X

                  KKKK
                  Stationary Combustion Turbines

                  X

                  LLLL
                  New Sewage Sludge Incineration Units

                  OOOO
                  Crude Oil and Natural Gas Production, Transmission, and Distribution

              (ix) Delegations for Tuolumne County Air Pollution Control District, Ventura County Air Pollution Control District, and Yolo-Solano Air Quality Management District are shown in the following table:

                Delegation Status for New Source Performance Standards for Tuolumne County Air Pollution Control District, Ventura County Air Pollution Control District, and Yolo-Solano Air Quality Management District

                  Subpart
                  Air Pollution Control Agency
                  Tuolumne County APCD
                  Ventura County APCD
                  Yolo-Solano AQMD

                  A
                  General Provisions
                  X
                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X
                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978
                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X

                  Dc
                  Small Industrial Steam Generating Units
                  X

                  E
                  Incinerators
                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994
                  X

                  Eb
                  Municipal Waste Combustors Constructed After September 20, 1994
                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996
                  X

                  F
                  Portland Cement Plants
                  X

                  G
                  Nitric Acid Plants
                  X

                  H
                  Sulfuric Acid Plants
                  X

                  I
                  Hot Mix Asphalt Facilities
                  X
                  X

                  J
                  Petroleum Refineries
                  X
                  X

                  Ja
                  Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X
                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984
                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
                  X

                  L
                  Secondary Lead Smelters
                  X

                  M
                  Secondary Brass and Bronze Production Plants
                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973
                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983
                  X

                  O
                  Sewage Treatment Plants
                  X

                  P
                  Primary Copper Smelters
                  X

                  Q
                  Primary Zinc Smelters
                  X

                  R
                  Primary Lead Smelters
                  X

                  S
                  Primary Aluminum Reduction Plants
                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants
                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
                  X

                  Y
                  Coal Preparation Plants
                  X

                  Z
                  Ferroalloy Production Facilities
                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
                  X
                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983
                  X

                  BB
                  Kraft pulp Mills
                  X

                  CC
                  Glass Manufacturing Plants
                  X

                  DD
                  Grain Elevators
                  X

                  EE
                  Surface Coating of Metal Furniture
                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines
                  X

                  HH
                  Lime Manufacturing Plants
                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants
                  X

                  LL
                  Metallic Mineral Processing Plants
                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations
                  X

                  NN
                  Phosphate Rock Plants
                  X

                  PP
                  Ammonium Sulfate Manufacture
                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing
                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations
                  X

                  SS
                  Industrial Surface Coating: Large Appliances
                  X

                  TT
                  Metal Coil Surface Coating
                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture
                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry
                  X

                  VVa
                  Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

                  WW
                  Beverage Can Surface Coating Industry
                  X

                  XX
                  Bulk Gasoline Terminals

                  AAA
                  New Residential Wood Heaters
                  X

                  BBB
                  Rubber Tire Manufacturing Industry
                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry
                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing
                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries
                  X

                  GGGa
                  Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

                  HHH
                  Synthetic Fiber Production Facilities
                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes
                  X

                  JJJ
                  Petroleum Dry Cleaners
                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants
                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions
                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations
                  X

                  OOO
                  Nonmetallic Mineral Processing Plants
                  X
                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants
                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems
                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes
                  X

                  SSS
                  Magnetic Tape Coating Facilities
                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines
                  X

                  UUU
                  Calciners and Dryers in Mineral Industries
                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities
                  X

                  WWW
                  Municipal Solid Waste Landfills
                  X
                  X

                  AAAA
                  Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commenced After June 6, 2001
                  X

                  CCCC
                  Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001
                  X

                  EEEE
                  Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006

                  GGGG
                  (Reserved)

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines

                  KKKK
                  Stationary Combustion Turbines

              (3) Hawaii. The following table identifies delegations for Hawaii:
              Delegation Status for New Source Performance Standards for Hawaii:

                Delegation Status for New Source Performance Standards for Hawaii

                  Subpart
                  Hawaii

                  A
                  General Provisions
                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978
                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units
                  X

                  Dc
                  Small Industrial Steam Generating Units
                  X

                  E
                  Incinerators
                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994
                  X

                  Eb
                  Municipal Waste Combustors Constructed After September 20, 1994
                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996
                  X

                  F
                  Portland Cement Plants
                  X

                  G
                  Nitric Acid Plants

                  H
                  Sulfuric Acid Plants

                  I
                  Hot Mix Asphalt Facilities
                  X

                  J
                  Petroleum Refineries
                  X

                  Ja
                  Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984
                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
                  X

                  L
                  Secondary Lead Smelters

                  M
                  Secondary Brass and Bronze Production Plants

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983

                  O
                  Sewage Treatment Plants
                  X

                  P
                  Primary Copper Smelters

                  Q
                  Primary Zinc Smelters

                  R
                  Primary Lead Smelters

                  S
                  Primary Aluminum Reduction Plants

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities

                  Y
                  Coal Preparation Plants
                  X

                  Z
                  Ferroalloy Production Facilities

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983
                  X

                  BB
                  Kraft pulp Mills

                  CC
                  Glass Manufacturing Plants

                  DD
                  Grain Elevators

                  EE
                  Surface Coating of Metal Furniture

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines
                  X

                  HH
                  Lime Manufacturing Plants

                  KK
                  Lead-Acid Battery Manufacturing Plants

                  LL
                  Metallic Mineral Processing Plants

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations

                  NN
                  Phosphate Rock Plants

                  PP
                  Ammonium Sulfate Manufacture

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations

                  SS
                  Industrial Surface Coating: Large Appliances

                  TT
                  Metal Coil Surface Coating

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry
                  X

                  VVa
                  Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

                  WW
                  Beverage Can Surface Coating Industry
                  X

                  XX
                  Bulk Gasoline Terminals
                  X

                  AAA
                  New Residential Wool Heaters

                  BBB
                  Rubber Tire Manufacturing Industry

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries
                  X

                  GGGa
                  Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

                  HHH
                  Synthetic Fiber Production Facilities

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

                  JJJ
                  Petroleum Dry Cleaners
                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations
                  X

                  OOO
                  Nonmetallic Mineral Processing Plants
                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater
                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes

                  SSS
                  Magnetic Tape Coating Facilities

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines

                  UUU
                  Calciners and Dryers in Mineral Industries
                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities
                  X

                  WWW
                  Municipal Solid Waste Landfills
                  X

                  AAAA
                  Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commenced After June 6, 2001
                  X

                  CCCC
                  Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001
                  X

                  EEEE
                  Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006

                  GGGG
                  (Reserved)

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines

                  KKKK
                  Stationary Combustion Turbines

              (4) Nevada. The following table identifies delegations for Nevada:

                Table 12 to Paragraph (d)(4)—Delegation Status for New Source Performance Standards for Nevada

                  Subpart
                  Air pollution control agency
                  NevadaDEP

                  ClarkCounty

                  WashoeCounty

                  A
                  General Provisions
                  X
                  X
                  X

                  Cf
                  Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills
                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X
                  X
                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978
                  X
                  X

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X

                  Dc
                  Small Industrial-Commercial-Institutional Steam Generating Units
                  X
                  X

                  E
                  Incinerators
                  X
                  X
                  X

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994
                  X
                  X

                  Eb
                  Large Municipal Waste Combustors Constructed After September 20, 1994
                  X
                  X

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996
                  X
                  X

                  F
                  Portland Cement Plants
                  X
                  X
                  X

                  G
                  Nitric Acid Plants
                  X
                  X

                  Ga
                  Nitric Acid Plants For Which Construction, Reconstruction or Modification Commenced After October 14, 2011
                  X

                  H
                  Sulfuric Acid Plant
                  X
                  X

                  I
                  Hot Mix Asphalt Facilities
                  X
                  X
                  X

                  J
                  Petroleum Refineries
                  X
                  X

                  Ja
                  Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007
                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X
                  X
                  X

                  Ka
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984
                  X
                  X
                  X

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984
                  X
                  X

                  L
                  Secondary Lead Smelters
                  X
                  X
                  X

                  M
                  Secondary Brass and Bronze Production Plants
                  X
                  X

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973
                  X
                  X

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983
                  X
                  X

                  O
                  Sewage Treatment Plants
                  X
                  X
                  X

                  P
                  Primary Copper Smelters
                  X
                  X
                  X

                  Q
                  Primary Zinc Smelters
                  X
                  X
                  X

                  R
                  Primary Lead Smelters
                  X
                  X
                  X

                  S
                  Primary Aluminum Reduction Plants
                  X
                  X

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants

                  X

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants

                  X

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants

                  X

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants

                  X

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities

                  X

                  Y
                  Coal Preparation and Processing Plants
                  X
                  X
                  X

                  Z
                  Ferroalloy Production Facilities
                  X
                  X

                  AA
                  Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983
                  X
                  X

                  AAa
                  Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983
                  X
                  X

                  BB
                  Kraft Pulp Mills

                  X

                  CC
                  Glass Manufacturing Plants
                  X
                  X

                  DD
                  Grain Elevators
                  X
                  X
                  X

                  EE
                  Surface Coating of Metal Furniture
                  X
                  X
                  X

                  FF
                  (Reserved)

                  GG
                  Stationary Gas Turbines
                  X
                  X
                  X

                  HH
                  Lime Manufacturing Plants
                  X
                  X
                  X

                  KK
                  Lead-Acid Battery Manufacturing Plants
                  X
                  X
                  X

                  LL
                  Metallic Mineral Processing Plants
                  X
                  X
                  X

                  MM
                  Automobile and Light Duty Trucks Surface Coating Operations
                  X
                  X
                  X

                  NN
                  Phosphate Rock Plants
                  X
                  X
                  X

                  PP
                  Ammonium Sulfate Manufacture
                  X
                  X

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing
                  X
                  X
                  X

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations
                  X
                  X

                  SS
                  Industrial Surface Coating: Large Appliances
                  X
                  X
                  X

                  TT
                  Metal Coil Surface Coating
                  X
                  X
                  X

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture
                  X
                  X
                  X

                  VV
                  Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing
                  X
                  X
                  X

                  VVa
                  Equipment Leaks of VOC in the Synthetic Organic Industry for Which Construction, Reconstruction, or Chemicals Manufacturing Modification Commenced After November 7, 2006
                  X
                  X

                  WW
                  Beverage Can Surface Coating Industry
                  X
                  X

                  XX
                  Bulk Gasoline Terminals
                  X
                  X

                  AAA
                  New Residential Wood Heaters

                  X

                  BBB
                  Rubber Tire Manufacturing Industry
                  X
                  X

                  CCC
                  (Reserved)

                  DDD
                  Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry
                  X
                  X

                  EEE
                  (Reserved)

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing
                  X
                  X

                  GGG
                  Equipment Leaks of VOC in Petroleum Refineries
                  X
                  X

                  GGGa
                  Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006
                  X
                  X

                  HHH
                  Synthetic Fiber Production Facilities
                  X
                  X

                  III
                  Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes
                  X
                  X

                  JJJ
                  Petroleum Dry Cleaners
                  X
                  X
                  X

                  KKK
                  Equipment Leaks of VOC From Onshore Natural Gas Processing Plants
                  X
                  X

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions
                  X
                  X

                  MMM
                  (Reserved)

                  NNN
                  Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations
                  X
                  X

                  OOO
                  Nonmetallic Mineral Processing Plants
                  X
                  X

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants
                  X
                  X

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems
                  X
                  X

                  RRR
                  Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes
                  X
                  X

                  SSS
                  Magnetic Tape Coating Facilities
                  X
                  X

                  TTT
                  Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines
                  X
                  X
                  X

                  UUU
                  Calciners and Dryers in Mineral Industries
                  X
                  X
                  X

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities
                  X
                  X
                  X

                  WWW
                  Municipal Solid Waste Landfills
                  X
                  X
                  X

                  XXX
                  Municipal Solid Waste Landfills that Commenced Construction, Reconstruction, or Modification after July 17, 2014
                  X

                  AAAA
                  Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commended After June 6, 2001
                  X
                  X
                  X

                  CCCC
                  Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001
                  X
                  X
                  X

                  EEEE
                  Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006
                  X
                  X
                  X

                  GGGG
                  (Reserved)

                  HHHH
                  (Reserved)

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines
                  X
                  X
                  X

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines
                  X
                  X
                  X

                  KKKK
                  Stationary Combustion Turbines
                  X
                  X
                  X

                  LLLL
                  New Sewage Sludge Incineration Units

                  X

                  OOOO
                  Crude Oil and Natural Gas Production, Transmission, and Distribution
                  X

              (5) Guam. The following table identifies delegations as of June 15, 2001:

                Delegation Status for New Source Performance Standards for Guam

                  Subpart
                  Guam

                  A
                  General Provisions
                  X

                  D
                  Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971
                  X

                  Da
                  Electric Utility Steam Generating Units Constructed After September 18, 1978

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units

                  Dc
                  Small Industrial Steam Generating Units

                  E
                  Incinerators

                  Ea
                  Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994

                  Eb
                  Municipal Waste Combustors Constructed After September 20, 1994

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996

                  F
                  Portland Cement Plants
                  X

                  G
                  Nitric Acid Plants

                  H
                  Sulfuric Acid Plants

                  I
                  Hot Mix Asphalt Facilities
                  X

                  J
                  Petroleum Refineries
                  X

                  K
                  Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978
                  X

              (e) The following lists the specific part 60 standards that have been delegated unchanged to the air pollution control agencies in Region 6.
              (1) New Mexico. The New Mexico Environment Department has been delegated all part 60 standards promulgated by the EPA, except subpart AAA—Standards of Performance for New Residential Wood Heaters; and subpart QQQQ—Standards of Performance for New Residential Hydronic Heaters and Forced-Air Furnaces, as amended in the Federal Register through January 15, 2017.
              (2) Louisiana. The Louisiana Department of Environmental Quality has been delegated all part 60 standards promulgated by EPA, except subpart AAA—Standards of Performance for New Residential Wood Heaters, as amended in the Federal Register through July 1, 2013.

                Delegation Status for Part 60 Standards—State of Louisiana
                [Excluding Indian Country]

                  Subpart
                  Source category
                  LDEQ 1

                  A
                  General Provisions
                  Yes

                  Ce
                  Emission Guidelines and Compliance Times for Hospital/Medical/Infectious Waste Incinerators
                  Yes

                  D
                  Fossil Fueled Steam Generators (>250 MM BTU/hr)
                  Yes

                  Da
                  Electric Utility Steam Generating Units (>250 MM BTU/hr)
                  Yes

                  Db
                  Industrial-Commercial-Institutional Steam Generating Units (100 to 250 MM BTU/hr)
                  Yes

                  Dc
                  Industrial-Commercial-Institutional Small Steam Generating Units (10 to 100 MM BTU/hr)
                  Yes

                  E
                  Incinerators (>50 tons per day)
                  Yes

                  Ea
                  Municipal Waste Combustors
                  Yes

                  Eb
                  Large Municipal Waste Combustors
                  Yes

                  Ec
                  Hospital/Medical/Infectious Waste Incinerators
                  Yes

                  F
                  Portland Cement Plants
                  Yes

                  G
                  Nitric Acid Plants
                  Yes

                  Ga
                  Nitric Acid Plants (after October 14, 2011)
                  Yes

                  H
                  Sulfuric Acid Plants
                  Yes

                  I
                  Hot Mix Asphalt Facilities
                  Yes

                  J
                  Petroleum Refineries
                  Yes

                  Ja
                  Petroleum Refineries (After May 14, 2007)
                  Yes

                  K
                  Storage Vessels for Petroleum Liquids (After 6/11/73 & Before 5/19/78)
                  Yes

                  Ka
                  Storage Vessels for Petroleum Liquids (After 6/11/73 & Before 5/19/78)
                  Yes

                  Kb
                  Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Stg/Vessels) After 7/23/84
                  Yes

                  L
                  Secondary Lead Smelters Yes
                  Yes

                  M
                  Secondary Brass and Bronze Production Plants
                  Yes

                  N
                  Primary Emissions from Basic Oxygen Process Furnaces (Construction Commenced After June 11, 1973)
                  Yes

                  Na
                  Secondary Emissions from Basic Oxygen Process Steelmaking Facilities Construction is Commenced After January 20, 1983
                  Yes

                  O
                  Sewage Treatment Plants
                  Yes

                  P
                  Primary Copper Smelters
                  Yes

                  Q
                  Primary Zinc Smelters
                  Yes

                  R
                  Primary Lead Smelters
                  Yes

                  S
                  Primary Aluminum Reduction Plants
                  Yes

                  T
                  Phosphate Fertilizer Industry: Wet Process Phosphoric Plants
                  Yes

                  U
                  Phosphate Fertilizer Industry: Superphosphoric Acid Plants
                  Yes

                  V
                  Phosphate Fertilizer Industry: Diammonium Phosphate Plants
                  Yes

                  W
                  Phosphate Fertilizer Industry: Triple Superphosphate Plants
                  Yes

                  X
                  Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities
                  Yes

                  Y
                  Coal Preparation Plants
                  Yes

                  Z
                  Ferroalloy Production Facilities
                  Yes

                  AA
                  Steel Plants: Electric Arc Furnaces After 10/21/74 & On or Before 8/17/83
                  Yes

                  AAa
                  Steel Plants: Electric Arc Furnaces & Argon-Oxygen Decarburization Vessels After 8/07/83
                  Yes

                  BB
                  Kraft Pulp Mills
                  Yes

                  CC
                  Glass Manufacturing Plants
                  Yes

                  DD
                  Grain Elevators
                  Yes

                  EE
                  Surface Coating of Metal Furniture
                  Yes

                  GG
                  Stationary Gas Turbines
                  Yes

                  HH
                  Lime Manufacturing Plants
                  Yes

                  KK
                  Lead-Acid Battery Manufacturing Plants
                  Yes

                  LL
                  Metallic Mineral Processing Plants
                  Yes

                  MM
                  Automobile & Light Duty Truck Surface Coating Operations
                  Yes

                  NN
                  Phosphate Manufacturing Plants
                  Yes

                  PP
                  Ammonium Sulfate Manufacture
                  Yes

                  QQ
                  Graphic Arts Industry: Publication Rotogravure Printing
                  Yes

                  RR
                  Pressure Sensitive Tape and Label Surface Coating Operations
                  Yes

                  SS
                  Industrial Surface Coating: Large Appliances
                  Yes

                  TT
                  Metal Coil Surface Coating
                  Yes

                  UU
                  Asphalt Processing and Asphalt Roofing Manufacture
                  Yes

                  VV
                  VOC Equipment Leaks in the SOCMI Industry
                  Yes

                  VVa
                  VOC Equipment Leaks in the SOCMI Industry (After November 7, 2006)
                  Yes

                  XX
                  Bulk Gasoline Terminals
                  Yes

                  AAA
                  New Residential Wood Heaters
                  No

                  BBB
                  Rubber Tire Manufacturing Industry
                  Yes

                  DDD
                  Volatile Organic Compound (VOC) Emissions from the Polymer Manufacturing Industry
                  Yes

                  FFF
                  Flexible Vinyl and Urethane Coating and Printing
                  Yes

                  GGG
                  VOC Equipment Leaks in Petroleum Refineries
                  Yes

                  HHH
                  Synthetic Fiber Production
                  Yes

                  III
                  VOC Emissions from the SOCMI Air Oxidation Unit Processes
                  Yes

                  JJJ
                  Petroleum Dry Cleaners
                  Yes

                  KKK
                  VOC Equipment Leaks From Onshore Natural Gas Processing Plants
                  Yes

                  LLL
                  Onshore Natural Gas Processing: SO2 Emissions
                  Yes

                  NNN
                  VOC Emissions from SOCMI Distillation Operations
                  Yes

                  OOO
                  Nonmetallic Mineral Processing Plants
                  Yes

                  PPP
                  Wool Fiberglass Insulation Manufacturing Plants
                  Yes

                  QQQ
                  VOC Emissions From Petroleum Refinery Wastewater Systems
                  Yes

                  RRR
                  VOC Emissions from SOCMI Reactor Processes
                  Yes

                  SSS
                  Magnetic Tape Coating Operations
                  Yes

                  TTT
                  Industrial Surface Coating: Plastic Parts for Business Machines
                  Yes

                  UUU
                  Calciners and Dryers in Mineral Industries
                  Yes

                  VVV
                  Polymeric Coating of Supporting Substrates Facilities
                  Yes

                  WWW
                  Municipal Solid Waste Landfills
                  Yes

                  AAAA
                  Small Municipal Waste Combustion Units (Construction is Commenced After 8/30/99 or Modification/Reconstruction is Commenced After 6/06/2001)
                  Yes

                  CCCC
                  Commercial & Industrial Solid Waste Incineration Units (Construction is Commenced After 11/30/1999 or Modification/Reconstruction is Commenced on or After 6/01/2001)
                  Yes

                  DDDD
                  Emission Guidelines & Compliance Times for Commercial & Industrial Solid Waste Incineration Units (Commenced Construction On or Before 11/30/1999)
                  Yes

                  EEEE
                  Other Solid Waste Incineration Units (Constructed after 12/09/2004 or Modification/Reconstruction is commenced on or after 06/16/2004)
                  Yes

                  IIII
                  Stationary Compression Ignition Internal Combustion Engines
                  Yes

                  JJJJ
                  Stationary Spark Ignition Internal Combustion Engines
                  Yes

                  KKKK
                  Stationary Combustion Turbines (Construction Commenced After 02/18/2005)
                  Yes

                  LLLL
                  New Sewage Sludge Incineration Units
                  Yes

                  MMMM
                  Emission Guidelines and Compliance Times for Existing Sewage Sludge Incineration Units
                  Yes

                  OOOO
                  Crude Oil and Natural Gas Production, Transmission and Distribution
                  Yes

                  1 The Louisiana Department of Environmental Quality (LDEQ) has been delegated all Part 60 standards promulgated by EPA, except subpart AAA—Standards of Performance for New Residential Wood Heaters—as amended in the Federal Register through July 1, 2013.

              (3) Albuquerque-Bernalillo County Air Quality Control Board. The Albuquerque-Bernalillo County Air Quality Control Board has been delegated all part 60 standards promulgated by EPA, except subpart AAA—Standards of Performance for New Residential Wood Heaters, as amended in the Federal Register through September 13, 2013.
              [40 FR 18169, Apr. 25, 1975]

                Editorial Note:
                For Federal Register citations affecting § 60.4, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

              § 60.5
              Determination of construction or modification.
              (a) When requested to do so by an owner or operator, the Administrator will make a determination of whether action taken or intended to be taken by such owner or operator constitutes construction (including reconstruction) or modification or the commencement thereof within the meaning of this part.
              (b) The Administrator will respond to any request for a determination under paragraph (a) of this section within 30 days of receipt of such request.
              [40 FR 58418, Dec. 16, 1975]

              § 60.6
              Review of plans.
              (a) When requested to do so by an owner or operator, the Administrator will review plans for construction or modification for the purpose of providing technical advice to the owner or operator.
              (b)(1) A separate request shall be submitted for each construction or modification project.
              (2) Each request shall identify the location of such project, and be accompanied by technical information describing the proposed nature, size, design, and method of operation of each affected facility involved in such project, including information on any equipment to be used for measurement or control of emissions.
              (c) Neither a request for plans review nor advice furnished by the Administrator in response to such request shall (1) relieve an owner or operator of legal responsibility for compliance with any provision of this part or of any applicable State or local requirement, or (2) prevent the Administrator from implementing or enforcing any provision of this part or taking any other action authorized by the Act.
              [36 FR 24877, Dec. 23, 1971, as amended at 39 FR 9314, Mar. 8, 1974]

              § 60.7
              Notification and record keeping.
              (a) Any owner or operator subject to the provisions of this part shall furnish the Administrator written notification or, if acceptable to both the Administrator and the owner or operator of a source, electronic notification, as follows:
              (1) A notification of the date construction (or reconstruction as defined under § 60.15) of an affected facility is commenced postmarked no later than 30 days after such date. This requirement shall not apply in the case of mass-produced facilities which are purchased in completed form.
              (2) [Reserved]
              (3) A notification of the actual date of initial startup of an affected facility postmarked within 15 days after such date.
              (4) A notification of any physical or operational change to an existing facility which may increase the emission rate of any air pollutant to which a standard applies, unless that change is specifically exempted under an applicable subpart or in § 60.14(e). This notice shall be postmarked 60 days or as soon as practicable before the change is commenced and shall include information describing the precise nature of the change, present and proposed emission control systems, productive capacity of the facility before and after the change, and the expected completion date of the change. The Administrator may request additional relevant information subsequent to this notice.
              (5) A notification of the date upon which demonstration of the continuous monitoring system performance commences in accordance with § 60.13(c). Notification shall be postmarked not less than 30 days prior to such date.
              (6) A notification of the anticipated date for conducting the opacity observations required by § 60.11(e)(1) of this part. The notification shall also include, if appropriate, a request for the Administrator to provide a visible emissions reader during a performance test. The notification shall be postmarked not less than 30 days prior to such date.
              (7) A notification that continuous opacity monitoring system data results will be used to determine compliance with the applicable opacity standard during a performance test required by § 60.8 in lieu of Method 9 observation data as allowed by § 60.11(e)(5) of this part. This notification shall be postmarked not less than 30 days prior to the date of the performance test.
              (b) Any owner or operator subject to the provisions of this part shall maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of an affected facility; any malfunction of the air pollution control equipment; or any periods during which a continuous monitoring system or monitoring device is inoperative.
              (c) Each owner or operator required to install a continuous monitoring device shall submit excess emissions and monitoring systems performance report (excess emissions are defined in applicable subparts) and-or summary report form (see paragraph (d) of this section) to the Administrator semiannually, except when: more frequent reporting is specifically required by an applicable subpart; or the Administrator, on a case-by-case basis, determines that more frequent reporting is necessary to accurately assess the compliance status of the source. All reports shall be postmarked by the 30th day following the end of each six-month period. Written reports of excess emissions shall include the following information:
              (1) The magnitude of excess emissions computed in accordance with § 60.13(h), any conversion factor(s) used, and the date and time of commencement and completion of each time period of excess emissions. The process operating time during the reporting period.
              (2) Specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the affected facility. The nature and cause of any malfunction (if known), the corrective action taken or preventative measures adopted.
              (3) The date and time identifying each period during which the continuous monitoring system was inoperative except for zero and span checks and the nature of the system repairs or adjustments.

              (4) When no excess emissions have occurred or the continuous monitoring system(s) have not been inoperative, repaired, or adjusted, such information shall be stated in the report.
              (d) The summary report form shall contain the information and be in the format shown in figure 1 unless otherwise specified by the Administrator. One summary report form shall be submitted for each pollutant monitored at each affected facility.
              (1) If the total duration of excess emissions for the reporting period is less than 1 percent of the total operating time for the reporting period and CMS downtime for the reporting period is less than 5 percent of the total operating time for the reporting period, only the summary report form shall be submitted and the excess emission report described in § 60.7(c) need not be submitted unless requested by the Administrator.
              (2) If the total duration of excess emissions for the reporting period is 1 percent or greater of the total operating time for the reporting period or the total CMS downtime for the reporting period is 5 percent or greater of the total operating time for the reporting period, the summary report form and the excess emission report described in § 60.7(c) shall both be submitted.
              Figure 1—Summary Report—Gaseous and Opacity Excess Emission and Monitoring System Performance

                Pollutant (Circle One—SO2/NOX/TRS/H2S/CO/Opacity)
                Reporting period dates: From __________ to __________
                Company:
                Emission Limitation
                Address:
                Monitor Manufacturer and Model No.
                Date of Latest CMS Certification or Audit
                Process Unit(s) Description:
                Total source operating time in reporting period 1

                    Emission data summary 1

                    CMS performance summary 1

                    1. Duration of excess emissions in reporting period due to:

                    1. CMS downtime in reporting period due to:

                    a. Startup/shutdown

                     a. Monitor equipment malfunctions

                    b. Control equipment problems

                     b. Non-Monitor equipment malfunctions

                    c. Process problems

                     c. Quality assurance calibration

                    d. Other known causes

                     d. Other known causes

                    e. Unknown causes

                     e. Unknown causes

                    2. Total duration of excess emission

                    2. Total CMS Downtime

                    3. Total duration of excess emissions × (100) [Total source operating time]
                    % 2

                    3. [Total CMS Downtime] × (100) [Total source operating time]
                    % 2

                    1 For opacity, record all times in minutes. For gases, record all times in hours.

                    2 For the reporting period: If the total duration of excess emissions is 1 percent or greater of the total operating time or the total CMS downtime is 5 percent or greater of the total operating time, both the summary report form and the excess emission report described in § 60.7(c) shall be submitted.

                On a separate page, describe any changes since last quarter in CMS, process or controls. I certify that the information contained in this report is true, accurate, and complete.

                Name

                Signature

                Title

                Date

              (e)(1) Notwithstanding the frequency of reporting requirements specified in paragraph (c) of this section, an owner or operator who is required by an applicable subpart to submit excess emissions and monitoring systems performance reports (and summary reports) on a quarterly (or more frequent) basis may reduce the frequency of reporting for that standard to semiannual if the following conditions are met:
              (i) For 1 full year (e.g., 4 quarterly or 12 monthly reporting periods) the affected facility's excess emissions and monitoring systems reports submitted to comply with a standard under this part continually demonstrate that the facility is in compliance with the applicable standard;
              (ii) The owner or operator continues to comply with all recordkeeping and monitoring requirements specified in this subpart and the applicable standard; and

              (iii) The Administrator does not object to a reduced frequency of reporting for the affected facility, as provided in paragraph (e)(2) of this section.
              (2) The frequency of reporting of excess emissions and monitoring systems performance (and summary) reports may be reduced only after the owner or operator notifies the Administrator in writing of his or her intention to make such a change and the Administrator does not object to the intended change. In deciding whether to approve a reduced frequency of reporting, the Administrator may review information concerning the source's entire previous performance history during the required recordkeeping period prior to the intended change, including performance test results, monitoring data, and evaluations of an owner or operator's conformance with operation and maintenance requirements. Such information may be used by the Administrator to make a judgment about the source's potential for noncompliance in the future. If the Administrator disapproves the owner or operator's request to reduce the frequency of reporting, the Administrator will notify the owner or operator in writing within 45 days after receiving notice of the owner or operator's intention. The notification from the Administrator to the owner or operator will specify the grounds on which the disapproval is based. In the absence of a notice of disapproval within 45 days, approval is automatically granted.
              (3) As soon as monitoring data indicate that the affected facility is not in compliance with any emission limitation or operating parameter specified in the applicable standard, the frequency of reporting shall revert to the frequency specified in the applicable standard, and the owner or operator shall submit an excess emissions and monitoring systems performance report (and summary report, if required) at the next appropriate reporting period following the noncomplying event. After demonstrating compliance with the applicable standard for another full year, the owner or operator may again request approval from the Administrator to reduce the frequency of reporting for that standard as provided for in paragraphs (e)(1) and (e)(2) of this section.
              (f) Any owner or operator subject to the provisions of this part shall maintain a file of all measurements, including continuous monitoring system, monitoring device, and performance testing measurements; all continuous monitoring system performance evaluations; all continuous monitoring system or monitoring device calibration checks; adjustments and maintenance performed on these systems or devices; and all other information required by this part recorded in a permanent form suitable for inspection. The file shall be retained for at least two years following the date of such measurements, maintenance, reports, and records, except as follows:
              (1) This paragraph applies to owners or operators required to install a continuous emissions monitoring system (CEMS) where the CEMS installed is automated, and where the calculated data averages do not exclude periods of CEMS breakdown or malfunction. An automated CEMS records and reduces the measured data to the form of the pollutant emission standard through the use of a computerized data acquisition system. In lieu of maintaining a file of all CEMS subhourly measurements as required under paragraph (f) of this section, the owner or operator shall retain the most recent consecutive three averaging periods of subhourly measurements and a file that contains a hard copy of the data acquisition system algorithm used to reduce the measured data into the reportable form of the standard.

              (2) This paragraph applies to owners or operators required to install a CEMS where the measured data is manually reduced to obtain the reportable form of the standard, and where the calculated data averages do not exclude periods of CEMS breakdown or malfunction. In lieu of maintaining a file of all CEMS subhourly measurements as required under paragraph (f) of this section, the owner or operator shall retain all subhourly measurements for the most recent reporting period. The subhourly measurements shall be retained for 120 days from the date of the most recent summary or excess emission report submitted to the Administrator.

              (3) The Administrator or delegated authority, upon notification to the source, may require the owner or operator to maintain all measurements as required by paragraph (f) of this section, if the Administrator or the delegated authority determines these records are required to more accurately assess the compliance status of the affected source.
              (g) If notification substantially similar to that in paragraph (a) of this section is required by any other State or local agency, sending the Administrator a copy of that notification will satisfy the requirements of paragraph (a) of this section.
              (h) Individual subparts of this part may include specific provisions which clarify or make inapplicable the provisions set forth in this section.
              [36 FR 24877, Dec. 28, 1971, as amended at 40 FR 46254, Oct. 6, 1975; 40 FR 58418, Dec. 16, 1975; 45 FR 5617, Jan. 23, 1980; 48 FR 48335, Oct. 18, 1983; 50 FR 53113, Dec. 27, 1985; 52 FR 9781, Mar. 26, 1987; 55 FR 51382, Dec. 13, 1990; 59 FR 12428, Mar. 16, 1994; 59 FR 47265, Sep. 15, 1994; 64 FR 7463, Feb. 12, 1999]

              § 60.8
              Performance tests.
              (a) Except as specified in paragraphs (a)(1),(a)(2), (a)(3), and (a)(4) of this section, within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of such facility, or at such other times specified by this part, and at such other times as may be required by the Administrator under section 114 of the Act, the owner or operator of such facility shall conduct performance test(s) and furnish the Administrator a written report of the results of such performance test(s).
              (1) If a force majeure is about to occur, occurs, or has occurred for which the affected owner or operator intends to assert a claim of force majeure, the owner or operator shall notify the Administrator, in writing as soon as practicable following the date the owner or operator first knew, or through due diligence should have known that the event may cause or caused a delay in testing beyond the regulatory deadline, but the notification must occur before the performance test deadline unless the initial force majeure or a subsequent force majeure event delays the notice, and in such cases, the notification shall occur as soon as practicable.
              (2) The owner or operator shall provide to the Administrator a written description of the force majeure event and a rationale for attributing the delay in testing beyond the regulatory deadline to the force majeure; describe the measures taken or to be taken to minimize the delay; and identify a date by which the owner or operator proposes to conduct the performance test. The performance test shall be conducted as soon as practicable after the force majeure occurs.
              (3) The decision as to whether or not to grant an extension to the performance test deadline is solely within the discretion of the Administrator. The Administrator will notify the owner or operator in writing of approval or disapproval of the request for an extension as soon as practicable.
              (4) Until an extension of the performance test deadline has been approved by the Administrator under paragraphs (a)(1), (2), and (3) of this section, the owner or operator of the affected facility remains strictly subject to the requirements of this part.

              (b) Performance tests shall be conducted and data reduced in accordance with the test methods and procedures contained in each applicable subpart unless the Administrator (1) specifies or approves, in specific cases, the use of a reference method with minor changes in methodology, (2) approves the use of an equivalent method, (3) approves the use of an alternative method the results of which he has determined to be adequate for indicating whether a specific source is in compliance, (4) waives the requirement for performance tests because the owner or operator of a source has demonstrated by other means to the Administrator's satisfaction that the affected facility is in compliance with the standard, or (5) approves shorter sampling times and smaller sample volumes when necessitated by process variables or other factors. Nothing in this paragraph shall be construed to abrogate the Administrator's authority to require testing under section 114 of the Act.

              (c) Performance tests shall be conducted under such conditions as the Administrator shall specify to the plant operator based on representative performance of the affected facility. The owner or operator shall make available to the Administrator such records as may be necessary to determine the conditions of the performance tests. Operations during periods of startup, shutdown, and malfunction shall not constitute representative conditions for the purpose of a performance test nor shall emissions in excess of the level of the applicable emission limit during periods of startup, shutdown, and malfunction be considered a violation of the applicable emission limit unless otherwise specified in the applicable standard.
              (d) The owner or operator of an affected facility shall provide the Administrator at least 30 days prior notice of any performance test, except as specified under other subparts, to afford the Administrator the opportunity to have an observer present. If after 30 days notice for an initially scheduled performance test, there is a delay (due to operational problems, etc.) in conducting the scheduled performance test, the owner or operator of an affected facility shall notify the Administrator (or delegated State or local agency) as soon as possible of any delay in the original test date, either by providing at least 7 days prior notice of the rescheduled date of the performance test, or by arranging a rescheduled date with the Administrator (or delegated State or local agency) by mutual agreement.
              (e) The owner or operator of an affected facility shall provide, or cause to be provided, performance testing facilities as follows:
              (1) Sampling ports adequate for test methods applicable to such facility. This includes (i) constructing the air pollution control system such that volumetric flow rates and pollutant emission rates can be accurately determined by applicable test methods and procedures and (ii) providing a stack or duct free of cyclonic flow during performance tests, as demonstrated by applicable test methods and procedures.
              (2) Safe sampling platform(s).
              (3) Safe access to sampling platform(s).
              (4) Utilities for sampling and testing equipment.
              (f) Unless otherwise specified in the applicable subpart, each performance test shall consist of three separate runs using the applicable test method.
              (1) Each run shall be conducted for the time and under the conditions specified in the applicable standard. For the purpose of determining compliance with an applicable standard, the arithmetic means of results of the three runs shall apply. In the event that a sample is accidentally lost or conditions occur in which one of the three runs must be discontinued because of forced shutdown, failure of an irreplaceable portion of the sample train, extreme meteorological conditions, or other circumstances, beyond the owner or operator's control, compliance may, upon the Administrator's approval, be determined using the arithmetic mean of the results of the two other runs.
              (2) Contents of report (electronic or paper submitted copy). Unless otherwise specified in a relevant standard or test method, or as otherwise approved by the Administrator in writing, the report for a performance test shall include the elements identified in paragraphs (f)(2)(i) through (vi) of this section.
              (i) General identification information for the facility including a mailing address, the physical address, the owner or operator or responsible official (where applicable) and his/her email address, and the appropriate Federal Registry System (FRS) number for the facility.
              (ii) Purpose of the test including the applicable regulation(s) requiring the test, the pollutant(s) and other parameters being measured, the applicable emission standard and any process parameter component, and a brief process description.

              (iii) Description of the emission unit tested including fuel burned, control devices, and vent characteristics; the appropriate source classification code (SCC); the permitted maximum process rate (where applicable); and the sampling location.

              (iv) Description of sampling and analysis procedures used and any modifications to standard procedures, quality assurance procedures and results, record of process operating conditions that demonstrate the applicable test conditions are met, and values for any operating parameters for which limits were being set during the test.
              (v) Where a test method requires you record or report, the following shall be included: Record of preparation of standards, record of calibrations, raw data sheets for field sampling, raw data sheets for field and laboratory analyses, chain-of-custody documentation, and example calculations for reported results.
              (vi) Identification of the company conducting the performance test including the primary office address, telephone number, and the contact for this test program including his/her email address.
              (g) The performance testing shall include a test method performance audit (PA) during the performance test. The PAs consist of blind audit samples supplied by an accredited audit sample provider and analyzed during the performance test in order to provide a measure of test data bias. Gaseous audit samples are designed to audit the performance of the sampling system as well as the analytical system and must be collected by the sampling system during the compliance test just as the compliance samples are collected. If a liquid or solid audit sample is designed to audit the sampling system, it must also be collected by the sampling system during the compliance test. If multiple sampling systems or sampling trains are used during the compliance test for any of the test methods, the tester is only required to use one of the sampling systems per method to collect the audit sample. The audit sample must be analyzed by the same analyst using the same analytical reagents and analytical system and at the same time as the compliance samples. Retests are required when there is a failure to produce acceptable results for an audit sample. However, if the audit results do not affect the compliance or noncompliance status of the affected facility, the compliance authority may waive the reanalysis requirement, further audits, or retests and accept the results of the compliance test. Acceptance of the test results shall constitute a waiver of the reanalysis requirement, further audits, or retests. The compliance authority may also use the audit sample failure and the compliance test results as evidence to determine the compliance or noncompliance status of the affected facility. A blind audit sample is a sample whose value is known only to the sample provider and is not revealed to the tested facility until after they report the measured value of the audit sample. For pollutants that exist in the gas phase at ambient temperature, the audit sample shall consist of an appropriate concentration of the pollutant in air or nitrogen that can be introduced into the sampling system of the test method at or near the same entry point as a sample from the emission source. If no gas phase audit samples are available, an acceptable alternative is a sample of the pollutant in the same matrix that would be produced when the sample is recovered from the sampling system as required by the test method. For samples that exist only in a liquid or solid form at ambient temperature, the audit sample shall consist of an appropriate concentration of the pollutant in the same matrix that would be produced when the sample is recovered from the sampling system as required by the test method. An accredited audit sample provider (AASP) is an organization that has been accredited to prepare audit samples by an independent, third party accrediting body.

              (1) The source owner, operator, or representative of the tested facility shall obtain an audit sample, if commercially available, from an AASP for each test method used for regulatory compliance purposes. No audit samples are required for the following test methods: Methods 3A and 3C of appendix A-3 of part 60, Methods 6C, 7E, 9, and 10 of appendix A-4 of part 60, Methods 18 and 19 of appendix A-6 of part 60, Methods 20, 22, and 25A of appendix A-7 of part 60, Methods 30A and 30B of appendix A-8 of part 60, and Methods 303, 318, 320, and 321 of appendix A of part 63 of this chapter. If multiple sources at a single facility are tested during a compliance test event, only one audit sample is required for each method used during a compliance test. The compliance authority responsible for the compliance test may waive the requirement to include an audit sample if they believe that an audit sample is not necessary. “Commercially available” means that two or more independent AASPs have blind audit samples available for purchase. If the source owner, operator, or representative cannot find an audit sample for a specific method, the owner, operator, or representative shall consult the EPA Web site at the following URL, www.epa.gov/ttn/emc, to confirm whether there is a source that can supply an audit sample for that method. If the EPA Web site does not list an available audit sample at least 60 days prior to the beginning of the compliance test, the source owner, operator, or representative shall not be required to include an audit sample as part of the quality assurance program for the compliance test. When ordering an audit sample, the source owner, operator, or representative shall give the sample provider an estimate for the concentration of each pollutant that is emitted by the source or the estimated concentration of each pollutant based on the permitted level and the name, address, and phone number of the compliance authority. The source owner, operator, or representative shall report the results for the audit sample along with a summary of the emission test results for the audited pollutant to the compliance authority and shall report the results of the audit sample to the AASP. The source owner, operator, or representative shall make both reports at the same time and in the same manner or shall report to the compliance authority first and then report to the AASP. If the method being audited is a method that allows the samples to be analyzed in the field and the tester plans to analyze the samples in the field, the tester may analyze the audit samples prior to collecting the emission samples provided a representative of the compliance authority is present at the testing site. The tester may request and the compliance authority may grant a waiver to the requirement that a representative of the compliance authority must be present at the testing site during the field analysis of an audit sample. The source owner, operator, or representative may report the results of the audit sample to the compliance authority and report the results of the audit sample to the AASP prior to collecting any emission samples. The test protocol and final test report shall document whether an audit sample was ordered and utilized and the pass/fail results as applicable.
              (2) An AASP shall have and shall prepare, analyze, and report the true value of audit samples in accordance with a written technical criteria document that describes how audit samples will be prepared and distributed in a manner that will ensure the integrity of the audit sample program. An acceptable technical criteria document shall contain standard operating procedures for all of the following operations:
              (i) Preparing the sample;
              (ii) Confirming the true concentration of the sample;
              (iii) Defining the acceptance limits for the results from a well qualified tester. This procedure must use well established statistical methods to analyze historical results from well qualified testers. The acceptance limits shall be set so that there is 95 percent confidence that 90 percent of well qualified labs will produce future results that are within the acceptance limit range.
              (iv) Providing the opportunity for the compliance authority to comment on the selected concentration level for an audit sample;
              (v) Distributing the sample to the user in a manner that guarantees that the true value of the sample is unknown to the user;
              (vi) Recording the measured concentration reported by the user and determining if the measured value is within acceptable limits;

              (vii) The AASP shall report the results from each audit sample in a timely manner to the compliance authority and then to the source owner, operator, or representative. The AASP shall make both reports at the same time and in the same manner or shall report to the compliance authority first and then report to the source owner, operator, or representative. The results shall include the name of the facility tested, the date on which the compliance test was conducted, the name of the company performing the sample collection, the name of the company that analyzed the compliance samples including the audit sample, the measured result for the audit sample, and whether the testing company passed or failed the audit. The AASP shall report the true value of the audit sample to the compliance authority. The AASP may report the true value to the source owner, operator, or representative if the AASP's operating plan ensures that no laboratory will receive the same audit sample twice.
              (viii) Evaluating the acceptance limits of samples at least once every two years to determine in cooperation with the voluntary consensus standard body if they should be changed;
              (ix) Maintaining a database, accessible to the compliance authorities, of results from the audit that shall include the name of the facility tested, the date on which the compliance test was conducted, the name of the company performing the sample collection, the name of the company that analyzed the compliance samples including the audit sample, the measured result for the audit sample, the true value of the audit sample, the acceptance range for the measured value, and whether the testing company passed or failed the audit.
              (3) The accrediting body shall have a written technical criteria document that describes how it will ensure that the AASP is operating in accordance with the AASP technical criteria document that describes how audit samples are to be prepared and distributed. This document shall contain standard operating procedures for all of the following operations:
              (i) Checking audit samples to confirm their true value as reported by the AASP;
              (ii) Performing technical systems audits of the AASP's facilities and operating procedures at least once every two years;
              (iii) Providing standards for use by the voluntary consensus standard body to approve the accrediting body that will accredit the audit sample providers.

              (4) The technical criteria documents for the accredited sample providers and the accrediting body shall be developed through a public process guided by a voluntary consensus standards body (VCSB). The VCSB shall operate in accordance with the procedures and requirements in the Office of Management and Budget Circular A-119. A copy of Circular A-119 is available upon request by writing the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW., Washington, DC 20503, by calling (202) 395-6880 or downloading online at http://standards.gov/standards__gov/a119.cfm. The VCSB shall approve all accrediting bodies. The Administrator will review all technical criteria documents. If the technical criteria documents do not meet the minimum technical requirements in paragraphs (g)(2) through (4)of this section, the technical criteria documents are not acceptable and the proposed audit sample program is not capable of producing audit samples of sufficient quality to be used in a compliance test. All acceptable technical criteria documents shall be posted on the EPA Web site at the following URL, http://www.epa.gov/ttn/emc.

              (h) Unless otherwise specified in the applicable subpart, each test location must be verified to be free of cyclonic flow and evaluated for the existence of emission gas stratification and the required number of sampling traverse points. If other procedures are not specified in the applicable subpart to the regulations, use the appropriate procedures in Method 1 to check for cyclonic flow and Method 7E to evaluate emission gas stratification and selection of sampling points.

              (i) Whenever the use of multiple calibration gases is required by a test method, performance specification, or quality assurance procedure in a part 60 standard or appendix, Method 205 of 40 CFR part 51, appendix M of this chapter, “Verification of Gas Dilution Systems for Field Instrument Calibrations,” may be used.
              [36 FR 24877, Dec. 23, 1971, as amended at 39 FR 9314, Mar. 8, 1974; 42 FR 57126, Nov. 1, 1977; 44 FR 33612, June 11, 1979; 54 FR 6662, Feb. 14, 1989; 54 FR 21344, May 17, 1989; 64 FR 7463, Feb. 12, 1999; 72 FR 27442, May 16, 2007; 75 FR 55646, Sept. 13, 2010; 79 FR 11241, Feb. 27, 2014; 81 FR 59809, Aug. 30, 2016]

              § 60.9
              Availability of information.
              The availability to the public of information provided to, or otherwise obtained by, the Administrator under this part shall be governed by part 2 of this chapter. (Information submitted voluntarily to the Administrator for the purposes of §§ 60.5 and 60.6 is governed by §§ 2.201 through 2.213 of this chapter and not by § 2.301 of this chapter.)

              § 60.10
              State authority.
              The provisions of this part shall not be construed in any manner to preclude any State or political subdivision thereof from:
              (a) Adopting and enforcing any emission standard or limitation applicable to an affected facility, provided that such emission standard or limitation is not less stringent than the standard applicable to such facility.
              (b) Requiring the owner or operator of an affected facility to obtain permits, licenses, or approvals prior to initiating construction, modification, or operation of such facility.

              § 60.11
              Compliance with standards and maintenance requirements.
              (a) Compliance with standards in this part, other than opacity standards, shall be determined in accordance with performance tests established by § 60.8, unless otherwise specified in the applicable standard.
              (b) Compliance with opacity standards in this part shall be determined by conducting observations in accordance with Method 9 in appendix A of this part, any alternative method that is approved by the Administrator, or as provided in paragraph (e)(5) of this section. For purposes of determining initial compliance, the minimum total time of observations shall be 3 hours (30 6-minute averages) for the performance test or other set of observations (meaning those fugitive-type emission sources subject only to an opacity standard).
              (c) The opacity standards set forth in this part shall apply at all times except during periods of startup, shutdown, malfunction, and as otherwise provided in the applicable standard.
              (d) At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source.

              (e)(1) For the purpose of demonstrating initial compliance, opacity observations shall be conducted concurrently with the initial performance test required in § 60.8 unless one of the following conditions apply. If no performance test under § 60.8 is required, then opacity observations shall be conducted within 60 days after achieving the maximum production rate at which the affected facility will be operated but no later than 180 days after initial startup of the facility. If visibility or other conditions prevent the opacity observations from being conducted concurrently with the initial performance test required under § 60.8, the source owner or operator shall reschedule the opacity observations as soon after the initial performance test as possible, but not later than 30 days thereafter, and shall advise the Administrator of the rescheduled date. In these cases, the 30-day prior notification to the Administrator required in § 60.7(a)(6) shall be waived. The rescheduled opacity observations shall be conducted (to the extent possible) under the same operating conditions that existed during the initial performance test conducted under § 60.8. The visible emissions observer shall determine whether visibility or other conditions prevent the opacity observations from being made concurrently with the initial performance test in accordance with procedures contained in Method 9 of appendix B of this part. Opacity readings of portions of plumes which contain condensed, uncombined water vapor shall not be used for purposes of determing compliance with opacity standards. The owner or operator of an affected facility shall make available, upon request by the Administrator, such records as may be necessary to determine the conditions under which the visual observations were made and shall provide evidence indicating proof of current visible observer emission certification. Except as provided in paragraph (e)(5) of this section, the results of continuous monitoring by transmissometer which indicate that the opacity at the time visual observations were made was not in excess of the standard are probative but not conclusive evidence of the actual opacity of an emission, provided that the source shall meet the burden of proving that the instrument used meets (at the time of the alleged violation) Performance Specification 1 in appendix B of this part, has been properly maintained and (at the time of the alleged violation) that the resulting data have not been altered in any way.
              (2) Except as provided in paragraph (e)(3) of this section, the owner or operator of an affected facility to which an opacity standard in this part applies shall conduct opacity observations in accordance with paragraph (b) of this section, shall record the opacity of emissions, and shall report to the Administrator the opacity results along with the results of the initial performance test required under § 60.8. The inability of an owner or operator to secure a visible emissions observer shall not be considered a reason for not conducting the opacity observations concurrent with the initial performance test.
              (3) The owner or operator of an affected facility to which an opacity standard in this part applies may request the Administrator to determine and to record the opacity of emissions from the affected facility during the initial performance test and at such times as may be required. The owner or operator of the affected facility shall report the opacity results. Any request to the Administrator to determine and to record the opacity of emissions from an affected facility shall be included in the notification required in § 60.7(a)(6). If, for some reason, the Administrator cannot determine and record the opacity of emissions from the affected facility during the performance test, then the provisions of paragraph (e)(1) of this section shall apply.
              (4) An owner or operator of an affected facility using a continuous opacity monitor (transmissometer) shall record the monitoring data produced during the initial performance test required by § 60.8 and shall furnish the Administrator a written report of the monitoring results along with Method 9 and § 60.8 performance test results.

              (5) An owner or operator of an affected facility subject to an opacity standard may submit, for compliance purposes, continuous opacity monitoring system (COMS) data results produced during any performance test required under § 60.8 in lieu of Method 9 observation data. If an owner or operator elects to submit COMS data for compliance with the opacity standard, he shall notify the Administrator of that decision, in writing, at least 30 days before any performance test required under § 60.8 is conducted. Once the owner or operator of an affected facility has notified the Administrator to that effect, the COMS data results will be used to determine opacity compliance during subsequent tests required under § 60.8 until the owner or operator notifies the Administrator, in writing, to the contrary. For the purpose of determining compliance with the opacity standard during a performance test required under § 60.8 using COMS data, the minimum total time of COMS data collection shall be averages of all 6-minute continuous periods within the duration of the mass emission performance test. Results of the COMS opacity determinations shall be submitted along with the results of the performance test required under § 60.8. The owner or operator of an affected facility using a COMS for compliance purposes is responsible for demonstrating that the COMS meets the requirements specified in § 60.13(c) of this part, that the COMS has been properly maintained and operated, and that the resulting data have not been altered in any way. If COMS data results are submitted for compliance with the opacity standard for a period of time during which Method 9 data indicates noncompliance, the Method 9 data will be used to determine compliance with the opacity standard.
              (6) Upon receipt from an owner or operator of the written reports of the results of the performance tests required by § 60.8, the opacity observation results and observer certification required by § 60.11(e)(1), and the COMS results, if applicable, the Administrator will make a finding concerning compliance with opacity and other applicable standards. If COMS data results are used to comply with an opacity standard, only those results are required to be submitted along with the performance test results required by § 60.8. If the Administrator finds that an affected facility is in compliance with all applicable standards for which performance tests are conducted in accordance with § 60.8 of this part but during the time such performance tests are being conducted fails to meet any applicable opacity standard, he shall notify the owner or operator and advise him that he may petition the Administrator within 10 days of receipt of notification to make appropriate adjustment to the opacity standard for the affected facility.
              (7) The Administrator will grant such a petition upon a demonstration by the owner or operator that the affected facility and associated air pollution control equipment was operated and maintained in a manner to minimize the opacity of emissions during the performance tests; that the performance tests were performed under the conditions established by the Administrator; and that the affected facility and associated air pollution control equipment were incapable of being adjusted or operated to meet the applicable opacity standard.

              (8) The Administrator will establish an opacity standard for the affected facility meeting the above requirements at a level at which the source will be able, as indicated by the performance and opacity tests, to meet the opacity standard at all times during which the source is meeting the mass or concentration emission standard. The Administrator will promulgate the new opacity standard in the Federal Register.

              (f) Special provisions set forth under an applicable subpart shall supersede any conflicting provisions in paragraphs (a) through (e) of this section.
              (g) For the purpose of submitting compliance certifications or establishing whether or not a person has violated or is in violation of any standard in this part, nothing in this part shall preclude the use, including the exclusive use, of any credible evidence or information, relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed.
              [38 FR 28565, Oct. 15, 1973, as amended at 39 FR 39873, Nov. 12, 1974; 43 FR 8800, Mar. 3, 1978; 45 FR 23379, Apr. 4, 1980; 48 FR 48335, Oct. 18, 1983; 50 FR 53113, Dec. 27, 1985; 51 FR 1790, Jan. 15, 1986; 52 FR 9781, Mar. 26, 1987; 62 FR 8328, Feb. 24, 1997; 65 FR 61749, Oct. 17, 2000]

              § 60.12
              Circumvention.
              No owner or operator subject to the provisions of this part shall build, erect, install, or use any article, machine, equipment or process, the use of which conceals an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere.
              [39 FR 9314, Mar. 8, 1974]

              § 60.13
              Monitoring requirements.

              (a) For the purposes of this section, all continuous monitoring systems required under applicable subparts shall be subject to the provisions of this section upon promulgation of performance specifications for continuous monitoring systems under appendix B to this part and, if the continuous monitoring system is used to demonstrate compliance with emission limits on a continuous basis, appendix F to this part, unless otherwise specified in an applicable subpart or by the Administrator. Appendix F is applicable December 4, 1987.
              (b) All continuous monitoring systems and monitoring devices shall be installed and operational prior to conducting performance tests under § 60.8. Verification of operational status shall, as a minimum, include completion of the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device.
              (c) If the owner or operator of an affected facility elects to submit continous opacity monitoring system (COMS) data for compliance with the opacity standard as provided under § 60.11(e)(5), he shall conduct a performance evaluation of the COMS as specified in Performance Specification 1, appendix B, of this part before the performance test required under § 60.8 is conducted. Otherwise, the owner or operator of an affected facility shall conduct a performance evaluation of the COMS or continuous emission monitoring system (CEMS) during any performance test required under § 60.8 or within 30 days thereafter in accordance with the applicable performance specification in appendix B of this part, The owner or operator of an affected facility shall conduct COMS or CEMS performance evaluations at such other times as may be required by the Administrator under section 114 of the Act.
              (1) The owner or operator of an affected facility using a COMS to determine opacity compliance during any performance test required under § 60.8 and as described in § 60.11(e)(5) shall furnish the Administrator two or, upon request, more copies of a written report of the results of the COMS performance evaluation described in paragraph (c) of this section at least 10 days before the performance test required under § 60.8 is conducted.
              (2) Except as provided in paragraph (c)(1) of this section, the owner or operator of an affected facility shall furnish the Administrator within 60 days of completion two or, upon request, more copies of a written report of the results of the performance evaluation.
              (d)(1) Owners and operators of a CEMS installed in accordance with the provisions of this part, must check the zero (or low level value between 0 and 20 percent of span value) and span (50 to 100 percent of span value) calibration drifts at least once each operating day in accordance with a written procedure. The zero and span must, at a minimum, be adjusted whenever either the 24-hour zero drift or the 24-hour span drift exceeds two times the limit of the applicable performance specification in appendix B of this part. The system must allow the amount of the excess zero and span drift to be recorded and quantified whenever specified. Owners and operators of a COMS installed in accordance with the provisions of this part must check the zero and upscale (span) calibration drifts at least once daily. For a particular COMS, the acceptable range of zero and upscale calibration materials is defined in the applicable version of PS-1 in appendix B of this part. For a COMS, the optical surfaces, exposed to the effluent gases, must be cleaned before performing the zero and upscale drift adjustments, except for systems using automatic zero adjustments. The optical surfaces must be cleaned when the cumulative automatic zero compensation exceeds 4 percent opacity.
              (2) Unless otherwise approved by the Administrator, the following procedures must be followed for a COMS. Minimum procedures must include an automated method for producing a simulated zero opacity condition and an upscale opacity condition using a certified neutral density filter or other related technique to produce a known obstruction of the light beam. Such procedures must provide a system check of all active analyzer internal optics with power or curvature, all active electronic circuitry including the light source and photodetector assembly, and electronic or electro-mechanical systems and hardware and or software used during normal measurement operation.

              (e) Except for system breakdowns, repairs, calibration checks, and zero and span adjustments required under paragraph (d) of this section, all continuous monitoring systems shall be in continuous operation and shall meet minimum frequency of operation requirements as follows:
              (1) All continuous monitoring systems referenced by paragraph (c) of this section for measuring opacity of emissions shall complete a minimum of one cycle of sampling and analyzing for each successive 10-second period and one cycle of data recording for each successive 6-minute period.
              (2) All continuous monitoring systems referenced by paragraph (c) of this section for measuring emissions, except opacity, shall complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.
              (f) All continuous monitoring systems or monitoring devices shall be installed such that representative measurements of emissions or process parameters from the affected facility are obtained. Additional procedures for location of continuous monitoring systems contained in the applicable Performance Specifications of appendix B of this part shall be used.
              (g) When the effluents from a single affected facility or two or more affected facilities subject to the same emission standards are combined before being released to the atmosphere, the owner or operator may install applicable continuous monitoring systems on each effluent or on the combined effluent. When the affected facilities are not subject to the same emission standards, separate continuous monitoring systems shall be installed on each effluent. When the effluent from one affected facility is released to the atmosphere through more than one point, the owner or operator shall install an applicable continuous monitoring system on each separate effluent unless the installation of fewer systems is approved by the Administrator. When more than one continuous monitoring system is used to measure the emissions from one affected facility (e.g., multiple breechings, multiple outlets), the owner or operator shall report the results as required from each continuous monitoring system.
              (h)(1) Owners or operators of all continuous monitoring systems for measurement of opacity shall reduce all data to 6-minute averages and for continuous monitoring systems other than opacity to 1-hour averages for time periods as defined in § 60.2. Six-minute opacity averages shall be calculated from 36 or more data points equally spaced over each 6-minute period.
              (2) For continuous monitoring systems other than opacity, 1-hour averages shall be computed as follows, except that the provisions pertaining to the validation of partial operating hours are only applicable for affected facilities that are required by the applicable subpart to include partial hours in the emission calculations:

              (i) Except as provided under paragraph (h)(2)(iii) of this section, for a full operating hour (any clock hour with 60 minutes of unit operation), at least four valid data points are required to calculate the hourly average, i.e., one data point in each of the 15-minute quadrants of the hour.
              (ii) Except as provided under paragraph (h)(2)(iii) of this section, for a partial operating hour (any clock hour with less than 60 minutes of unit operation), at least one valid data point in each 15-minute quadrant of the hour in which the unit operates is required to calculate the hourly average.
              (iii) For any operating hour in which required maintenance or quality-assurance activities are performed:
              (A) If the unit operates in two or more quadrants of the hour, a minimum of two valid data points, separated by at least 15 minutes, is required to calculate the hourly average; or
              (B) If the unit operates in only one quadrant of the hour, at least one valid data point is required to calculate the hourly average.
              (iv) If a daily calibration error check is failed during any operating hour, all data for that hour shall be invalidated, unless a subsequent calibration error test is passed in the same hour and the requirements of paragraph (h)(2)(iii) of this section are met, based solely on valid data recorded after the successful calibration.

              (v) For each full or partial operating hour, all valid data points shall be used to calculate the hourly average.

              (vi) Except as provided under paragraph (h)(2)(vii) of this section, data recorded during periods of continuous monitoring system breakdown, repair, calibration checks, and zero and span adjustments shall not be included in the data averages computed under this paragraph.
              (vii) Owners and operators complying with the requirements of § 60.7(f)(1) or (2) must include any data recorded during periods of monitor breakdown or malfunction in the data averages.
              (viii) When specified in an applicable subpart, hourly averages for certain partial operating hours shall not be computed or included in the emission averages (e.g., hours with < 30 minutes of unit operation under § 60.47b(d)).

              (ix) Either arithmetic or integrated averaging of all data may be used to calculate the hourly averages. The data may be recorded in reduced or nonreduced form (e.g., ppm pollutant and percent O2 or ng/J of pollutant).
              (3) All excess emissions shall be converted into units of the standard using the applicable conversion procedures specified in the applicable subpart. After conversion into units of the standard, the data may be rounded to the same number of significant digits used in the applicable subpart to specify the emission limit.
              (i) After receipt and consideration of written application, the Administrator may approve alternatives to any monitoring procedures or requirements of this part including, but not limited to the following:
              (1) Alternative monitoring requirements when installation of a continuous monitoring system or monitoring device specified by this part would not provide accurate measurements due to liquid water or other interferences caused by substances in the effluent gases.
              (2) Alternative monitoring requirements when the affected facility is infrequently operated.
              (3) Alternative monitoring requirements to accommodate continuous monitoring systems that require additional measurements to correct for stack moisture conditions.
              (4) Alternative locations for installing continuous monitoring systems or monitoring devices when the owner or operator can demonstrate that installation at alternate locations will enable accurate and representative measurements.
              (5) Alternative methods of converting pollutant concentration measurements to units of the standards.
              (6) Alternative procedures for performing daily checks of zero and span drift that do not involve use of span gases or test cells.
              (7) Alternatives to the A.S.T.M. test methods or sampling procedures specified by any subpart.
              (8) Alternative continuous monitoring systems that do not meet the design or performance requirements in Performance Specification 1, appendix B, but adequately demonstrate a definite and consistent relationship between its measurements and the measurements of opacity by a system complying with the requirements in Performance Specification 1. The Administrator may require that such demonstration be performed for each affected facility.
              (9) Alternative monitoring requirements when the effluent from a single affected facility or the combined effluent from two or more affected facilities is released to the atmosphere through more than one point.
              (j) An alternative to the relative accuracy (RA) test specified in Performance Specification 2 of appendix B may be requested as follows:

              (1) An alternative to the reference method tests for determining RA is available for sources with emission rates demonstrated to be less than 50 percent of the applicable standard. A source owner or operator may petition the Administrator to waive the RA test in Section 8.4 of Performance Specification 2 and substitute the procedures in Section 16.0 if the results of a performance test conducted according to the requirements in § 60.8 of this subpart or other tests performed following the criteria in § 60.8 demonstrate that the emission rate of the pollutant of interest in the units of the applicable standard is less than 50 percent of the applicable standard. For sources subject to standards expressed as control efficiency levels, a source owner or operator may petition the Administrator to waive the RA test and substitute the procedures in Section 16.0 of Performance Specification 2 if the control device exhaust emission rate is less than 50 percent of the level needed to meet the control efficiency requirement. The alternative procedures do not apply if the continuous emission monitoring system is used to determine compliance continuously with the applicable standard. The petition to waive the RA test shall include a detailed description of the procedures to be applied. Included shall be location and procedure for conducting the alternative, the concentration or response levels of the alternative RA materials, and the other equipment checks included in the alternative procedure. The Administrator will review the petition for completeness and applicability. The determination to grant a waiver will depend on the intended use of the CEMS data (e.g., data collection purposes other than NSPS) and may require specifications more stringent than in Performance Specification 2 (e.g., the applicable emission limit is more stringent than NSPS).
              (2) The waiver of a CEMS RA test will be reviewed and may be rescinded at such time, following successful completion of the alternative RA procedure, that the CEMS data indicate that the source emissions are approaching the level. The criterion for reviewing the waiver is the collection of CEMS data showing that emissions have exceeded 70 percent of the applicable standard for seven, consecutive, averaging periods as specified by the applicable regulation(s). For sources subject to standards expressed as control efficiency levels, the criterion for reviewing the waiver is the collection of CEMS data showing that exhaust emissions have exceeded 70 percent of the level needed to meet the control efficiency requirement for seven, consecutive, averaging periods as specified by the applicable regulation(s) [e.g., §§ 60.45(g) (2) and (3), 60.73(e), and 60.84(e)]. It is the responsibility of the source operator to maintain records and determine the level of emissions relative to the criterion on the waiver of RA testing. If this criterion is exceeded, the owner or operator must notify the Administrator within 10 days of such occurrence and include a description of the nature and cause of the increasing emissions. The Administrator will review the notification and may rescind the waiver and require the owner or operator to conduct a RA test of the CEMS as specified in Section 8.4 of Performance Specification 2.
              [40 FR 46255, Oct. 6, 1975]

                Editorial Note:
                For Federal Register citations affecting § 60.13, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

              § 60.14
              Modification.
              (a) Except as provided under paragraphs (e) and (f) of this section, any physical or operational change to an existing facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies shall be considered a modification within the meaning of section 111 of the Act. Upon modification, an existing facility shall become an affected facility for each pollutant to which a standard applies and for which there is an increase in the emission rate to the atmosphere.
              (b) Emission rate shall be expressed as kg/hr of any pollutant discharged into the atmosphere for which a standard is applicable. The Administrator shall use the following to determine emission rate:
              (1) Emission factors as specified in the latest issue of “Compilation of Air Pollutant Emission Factors,” EPA Publication No. AP-42, or other emission factors determined by the Administrator to be superior to AP-42 emission factors, in cases where utilization of emission factors demonstrates that the emission level resulting from the physical or operational change will either clearly increase or clearly not increase.

              (2) Material balances, continuous monitor data, or manual emission tests in cases where utilization of emission factors as referenced in paragraph (b)(1) of this section does not demonstrate to the Administrator's satisfaction whether the emission level resulting from the physical or operational change will either clearly increase or clearly not increase, or where an owner or operator demonstrates to the Administrator's satisfaction that there are reasonable grounds to dispute the result obtained by the Administrator utilizing emission factors as referenced in paragraph (b)(1) of this section. When the emission rate is based on results from manual emission tests or continuous monitoring systems, the procedures specified in appendix C of this part shall be used to determine whether an increase in emission rate has occurred. Tests shall be conducted under such conditions as the Administrator shall specify to the owner or operator based on representative performance of the facility. At least three valid test runs must be conducted before and at least three after the physical or operational change. All operating parameters which may affect emissions must be held constant to the maximum feasible degree for all test runs.
              (c) The addition of an affected facility to a stationary source as an expansion to that source or as a replacement for an existing facility shall not by itself bring within the applicability of this part any other facility within that source.
              (d) [Reserved]
              (e) The following shall not, by themselves, be considered modifications under this part:
              (1) Maintenance, repair, and replacement which the Administrator determines to be routine for a source category, subject to the provisions of paragraph (c) of this section and § 60.15.
              (2) An increase in production rate of an existing facility, if that increase can be accomplished without a capital expenditure on that facility.
              (3) An increase in the hours of operation.
              (4) Use of an alternative fuel or raw material if, prior to the date any standard under this part becomes applicable to that source type, as provided by § 60.1, the existing facility was designed to accommodate that alternative use. A facility shall be considered to be designed to accommodate an alternative fuel or raw material if that use could be accomplished under the facility's construction specifications as amended prior to the change. Conversion to coal required for energy considerations, as specified in section 111(a)(8) of the Act, shall not be considered a modification.
              (5) The addition or use of any system or device whose primary function is the reduction of air pollutants, except when an emission control system is removed or is replaced by a system which the Administrator determines to be less environmentally beneficial.
              (6) The relocation or change in ownership of an existing facility.
              (f) Special provisions set forth under an applicable subpart of this part shall supersede any conflicting provisions of this section.
              (g) Within 180 days of the completion of any physical or operational change subject to the control measures specified in paragraph (a) of this section, compliance with all applicable standards must be achieved.
              (h) No physical change, or change in the method of operation, at an existing electric utility steam generating unit shall be treated as a modification for the purposes of this section provided that such change does not increase the maximum hourly emissions of any pollutant regulated under this section above the maximum hourly emissions achievable at that unit during the 5 years prior to the change.
              (i) Repowering projects that are awarded funding from the Department of Energy as permanent clean coal technology demonstration projects (or similar projects funded by EPA) are exempt from the requirements of this section provided that such change does not increase the maximum hourly emissions of any pollutant regulated under this section above the maximum hourly emissions achievable at that unit during the five years prior to the change.
              (j)(1) Repowering projects that qualify for an extension under section 409(b) of the Clean Air Act are exempt from the requirements of this section, provided that such change does not increase the actual hourly emissions of any pollutant regulated under this section above the actual hourly emissions achievable at that unit during the 5 years prior to the change.
              (2) This exemption shall not apply to any new unit that:

              (i) Is designated as a replacement for an existing unit;

              (ii) Qualifies under section 409(b) of the Clean Air Act for an extension of an emission limitation compliance date under section 405 of the Clean Air Act; and
              (iii) Is located at a different site than the existing unit.

              (k) The installation, operation, cessation, or removal of a temporary clean coal technology demonstration project is exempt from the requirements of this section. A temporary clean coal control technology demonstration project, for the purposes of this section is a clean coal technology demonstration project that is operated for a period of 5 years or less, and which complies with the State implementation plan for the State in which the project is located and other requirements necessary to attain and maintain the national ambient air quality standards during the project and after it is terminated.
              (l) The reactivation of a very clean coal-fired electric utility steam generating unit is exempt from the requirements of this section.
              [40 FR 58419, Dec. 16, 1975, as amended at 43 FR 34347, Aug. 3, 1978; 45 FR 5617, Jan. 23, 1980; 57 FR 32339, July 21, 1992; 65 FR 61750, Oct. 17, 2000]

              § 60.15
              Reconstruction.
              (a) An existing facility, upon reconstruction, becomes an affected facility, irrespective of any change in emission rate.
              (b) “Reconstruction” means the replacement of components of an existing facility to such an extent that:
              (1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and
              (2) It is technologically and economically feasible to meet the applicable standards set forth in this part.
              (c) “Fixed capital cost” means the capital needed to provide all the depreciable components.
              (d) If an owner or operator of an existing facility proposes to replace components, and the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, he shall notify the Administrator of the proposed replacements. The notice must be postmarked 60 days (or as soon as practicable) before construction of the replacements is commenced and must include the following information:
              (1) Name and address of the owner or operator.
              (2) The location of the existing facility.
              (3) A brief description of the existing facility and the components which are to be replaced.
              (4) A description of the existing air pollution control equipment and the proposed air pollution control equipment.
              (5) An estimate of the fixed capital cost of the replacements and of constructing a comparable entirely new facility.
              (6) The estimated life of the existing facility after the replacements.
              (7) A discussion of any economic or technical limitations the facility may have in complying with the applicable standards of performance after the proposed replacements.
              (e) The Administrator will determine, within 30 days of the receipt of the notice required by paragraph (d) of this section and any additional information he may reasonably require, whether the proposed replacement constitutes reconstruction.
              (f) The Administrator's determination under paragraph (e) shall be based on:
              (1) The fixed capital cost of the replacements in comparison to the fixed capital cost that would be required to construct a comparable entirely new facility;
              (2) The estimated life of the facility after the replacements compared to the life of a comparable entirely new facility;
              (3) The extent to which the components being replaced cause or contribute to the emissions from the facility; and
              (4) Any economic or technical limitations on compliance with applicable standards of performance which are inherent in the proposed replacements.

              (g) Individual subparts of this part may include specific provisions which refine and delimit the concept of reconstruction set forth in this section.
              [40 FR 58420, Dec. 16, 1975]

              § 60.16
              Priority list.

                Prioritized Major Source Categories

                    Priority Number 1

                    Source Category

                  1.
                  Synthetic Organic Chemical Manufacturing Industry (SOCMI) and Volatile Organic Liquid Storage Vessels and Handling Equipment

                  (a) SOCMI unit processes

                  (b) Volatile organic liquid (VOL) storage vessels and handling equipment

                  (c) SOCMI fugitive sources

                  (d) SOCMI secondary sources

                  2.
                  Industrial Surface Coating: Cans

                  3.
                  Petroleum Refineries: Fugitive Sources

                  4.
                  Industrial Surface Coating: Paper

                  5.
                  Dry Cleaning

                  (a) Perchloroethylene

                  (b) Petroleum solvent

                  6.
                  Graphic Arts

                  7.
                  Polymers and Resins: Acrylic Resins

                  8.
                  Mineral Wool (Deleted)

                  9.
                  Stationary Internal Combustion Engines

                  10.
                  Industrial Surface Coating: Fabric

                  11.
                  Industrial-Commercial-Institutional Steam Generating Units.

                  12.
                  Incineration: Non-Municipal (Deleted)

                  13.
                  Non-Metallic Mineral Processing

                  14.
                  Metallic Mineral Processing

                  15.
                  Secondary Copper (Deleted)

                  16.
                  Phosphate Rock Preparation

                  17.
                  Foundries: Steel and Gray Iron

                  18.
                  Polymers and Resins: Polyethylene

                  19.
                  Charcoal Production

                  20.
                  Synthetic Rubber

                  (a) Tire manufacture

                  (b) SBR production

                  21.
                  Vegetable Oil

                  22.
                  Industrial Surface Coating: Metal Coil

                  23.
                  Petroleum Transportation and Marketing

                  24.
                  By-Product Coke Ovens

                  25.
                  Synthetic Fibers

                  26.
                  Plywood Manufacture

                  27.
                  Industrial Surface Coating: Automobiles

                  28.
                  Industrial Surface Coating: Large Appliances

                  29.
                  Crude Oil and Natural Gas Production

                  30.
                  Secondary Aluminum

                  31.
                  Potash (Deleted)

                  32.
                  Lightweight Aggregate Industry: Clay, Shale, and Slate 2

                  33.
                  Glass

                  34.
                  Gypsum

                  35.
                  Sodium Carbonate

                  36.
                  Secondary Zinc (Deleted)

                  37.
                  Polymers and Resins: Phenolic

                  38.
                  Polymers and Resins: Urea-Melamine

                  39.
                  Ammonia (Deleted)

                  40.
                  Polymers and Resins: Polystyrene

                  41.
                  Polymers and Resins: ABS-SAN Resins

                  42.
                  Fiberglass

                  43.
                  Polymers and Resins: Polypropylene

                  44.
                  Textile Processing

                  45.
                  Asphalt Processing and Asphalt Roofing Manufacture

                  46.
                  Brick and Related Clay Products

                  47.
                  Ceramic Clay Manufacturing (Deleted)

                  48.
                  Ammonium Nitrate Fertilizer

                  49.
                  Castable Refractories (Deleted)

                  50.
                  Borax and Boric Acid (Deleted)

                  51.
                  Polymers and Resins: Polyester Resins

                  52.
                  Ammonium Sulfate

                  53.
                  Starch

                  54.
                  Perlite

                  55.
                  Phosphoric Acid: Thermal Process (Deleted)

                  56.
                  Uranium Refining

                  57.
                  Animal Feed Defluorination (Deleted)

                  58.
                  Urea (for fertilizer and polymers)

                  59.
                  Detergent (Deleted)

                    Other Source Categories

                  Lead acid battery manufacture 3

                  Organic solvent cleaning 3

                  Industrial surface coating: metal furniture 3

                  Stationary gas turbines 4

                  Municipal solid waste landfills 4

                  1 Low numbers have highest priority, e.g., No. 1 is high priority, No. 59 is low priority.

                  2 Formerly titled “Sintering: Clay and Fly Ash”.

                  3 Minor source category, but included on list since an NSPS is being developed for that source category.

                  4 Not prioritized, since an NSPS for this major source category has already been promulgated.

              [47 FR 951, Jan. 8, 1982, as amended at 47 FR 31876, July 23, 1982; 51 FR 42796, Nov. 25, 1986; 52 FR 11428, Apr. 8, 1987; 61 FR 9919, Mar. 12, 1996]

              § 60.17
              Incorporations by reference.

              (a) Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other than that specified in this section, the EPA must publish notice of change in the Federal Register and the material must be available to the public. All approved material is available for inspection at the EPA Docket Center, Public Reading Room, EPA WJC West, Room 3334, 1301 Constitution Ave. NW., Washington, DC, telephone number 202-566-1744, and is available from the sources listed below. It is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call (202) 741-6030 or go to http://www.archives.gov/federal_ register/code_of_federal _regulations/ibr_ locations.html.

              (b) American Gas Association, available through ILI Infodisk, 610 Winters Avenue, Paramus, New Jersey 07652:

              (1) American Gas Association Report No. 3: Orifice Metering for Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines (1990), IBR approved for § 60.107a(d).
              (2) American Gas Association Report No. 3: Orifice Metering for Natural Gas and Other Related Hydrocarbon Fluids, Part 2: Specification and Installation Requirements (2000), IBR approved for § 60.107a(d).
              (3) American Gas Association Report No. 11: Measurement of Natural Gas by Coriolis Meter (2003), IBR approved for § 60.107a(d).
              (4) American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Revised February 2006), IBR approved for § 60.107a(d).
              (c) American Hospital Association (AHA) Service, Inc., Post Office Box 92683, Chicago, Illinois 60675-2683. You may inspect a copy at the EPA's Air and Radiation Docket and Information Center (Docket A-91-61, Item IV-J-124), Room M-1500, 1200 Pennsylvania Ave. NW., Washington, DC 20460.
              (1) An Ounce of Prevention: Waste Reduction Strategies for Health Care Facilities. American Society for Health Care Environmental Services of the American Hospital Association. Chicago, Illinois. 1993. AHA Catalog No. 057007. ISBN 0-87258-673-5. IBR approved for §§ 60.35e and 60.55c.
              (2) [Reserved]

              (d) The following material is available for purchase from the American National Standards Institute (ANSI), 25 W. 43rd Street, 4th Floor, New York, NY 10036, Telephone (212) 642-4980, and is also available at the following Web site: http://www.ansi.org.
              (1) ANSI No. C12.20-2010 American National Standard for Electricity Meters—0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR approved for § 60.5535(d).
              (2) [Reserved]
              (e) American Petroleum Institute (API), 1220 L Street NW., Washington, DC 20005.
              (1) API Publication 2517, Evaporation Loss from External Floating Roof Tanks, Second Edition, February 1980, IBR approved for §§ 60.111(i), 60.111a(f), and 60.116b(e).
              (2) API Manual of Petroleum Measurement Standards, Chapter 22—Testing Protocol, Section 2—Differential Pressure Flow Measurement Devices, First Edition, August 2005, IBR approved for § 60.107a(d).
              (f) American Public Health Association, 1015 18th Street NW., Washington, DC 20036.
              (1) “Standard Methods for the Examination of Water and Wastewater,” 16th edition, 1985. Method 303F: “Determination of Mercury by the Cold Vapor Technique.” Incorporated by reference for appendix A-8 to part 60, Method 29, §§ 9.2.3, 10.3, and 11.1.3.
              (2) 2540 G. Total, Fixed, and Volatile Solids in Solid and Semisolid Samples, in Standard Methods for the Examination of Water and Wastewater, 20th Edition, 1998, IBR approved for § 60.154(b).

              (g) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), Two Park Avenue, New York, NY 10016-5990, Telephone (800) 843-2763, and is also available at the following Web site: http://www.asme.org.

              (1) ASME Interim Supplement 19.5 on Instruments and Apparatus: Application, Part II of Fluid Meters, 6th Edition (1971), IBR approved for §§ 60.58a(h), 60.58b(i), 60.1320(a), and 60.1810(a).
              (2) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, IBR approved for § 60.107a(d).
              (3) ASME/ANSI MFC-4M-1986 (Reaffirmed 2008), Measurement of Gas Flow by Turbine Meters, IBR approved for § 60.107a(d).
              (4) ASME/ANSI MFC-5M-1985 (Reaffirmed 2006), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR approved for § 60.107a(d).
              (5) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for § 60.107a(d).
              (6) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, IBR approved for § 60.107a(d).

              (7) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for § 60.107a(d).
              (8) ASME MFC-11M-2006, Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters, IBR approved for § 60.107a(d).
              (9) ASME MFC-14M-2003, Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for § 60.107a(d).
              (10) ASME MFC-16-2007, Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters, IBR approved for § 60.107a(d).
              (11) ASME MFC-18M-2001, Measurement of Fluid Flow Using Variable Area Meters, IBR approved for § 60.107a(d).
              (12) ASME MFC-22-2007, Measurement of Liquid by Turbine Flowmeters, IBR approved for § 60.107a(d).
              (13) ASME PTC 4.1-1964 (Reaffirmed 1991), Power Test Codes: Test Code for Steam Generating Units (with 1968 and 1969 Addenda), IBR approved for §§ 60.46b, 60.58a(h), 60.58b(i), 60.1320(a), and 60.1810(a).
              (14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved for §§ 60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), and (j), 60.105a(b), (d), (f), and (g), 60.106a(a), 60.107a(a), (c), and (d), tables 1 and 3 to subpart EEEE, tables 2 and 4 to subpart FFFF, table 2 to subpart JJJJ, §§ 60.285a(f), 60.4415(a), 60.2145(s) and (t), 60.2710(s) and (t), 60.2730(q), 60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart MMMM, §§ 60.5406(c), 60.5406a(c), 60.5407a(g), 60.5413(b), 60.5413a(b), and 60.5413a(d).
              (15) ASME PTC 22-2014, Gas Turbines: Performance Test Codes, (Issued December 31, 2014), IBR approved for § 60.5580.
              (16) ASME PTC 46-1996, Performance Test Code on Overall Plant Performance, (Issued October 15, 1997), IBR approved for § 60.5580.
              (17) ASME QRO-1-1994, Standard for the Qualification and Certification of Resource Recovery Facility Operators, IBR approved for §§ 60.54b(a) and (b), 60.56a, 60.1185(a) and (c), and 60.1675(a) and (c).

              (h) The following material is available for purchase from ASTM International, 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-2959, (800) 262-1373, http://www.astm.org.

              (1) ASTM A99-76, Standard Specification for Ferromanganese, IBR approved for § 60.261.
              (2) ASTM A99-82 (Reapproved 1987), Standard Specification for Ferromanganese, IBR approved for § 60.261.
              (3) ASTM A100-69, Standard Specification for Ferrosilicon, IBR approved for § 60.261.
              (4) ASTM A100-74, Standard Specification for Ferrosilicon, IBR approved for § 60.261.
              (5) ASTM A100-93, Standard Specification for Ferrosilicon, IBR approved for § 60.261.
              (6) ASTM A101-73, Standard Specification for Ferrochromium, IBR approved for § 60.261.
              (7) ASTM A101-93, Standard Specification for Ferrochromium, IBR approved for § 60.261.
              (8) ASTM A482-76, Standard Specification for Ferrochromesilicon, IBR approved for § 60.261.
              (9) ASTM A482-93, Standard Specification for Ferrochromesilicon, IBR approved for § 60.261.
              (10) ASTM A483-64, Standard Specification for Silicomanganese, IBR approved for § 60.261.
              (11) ASTM A483-74 (Reapproved 1988), Standard Specification for Silicomanganese, IBR approved for § 60.261.
              (12) ASTM A495-76, Standard Specification for Calcium-Silicon and Calcium Manganese-Silicon, IBR approved for § 60.261.
              (13) ASTM A495-94, Standard Specification for Calcium-Silicon and Calcium Manganese-Silicon, IBR approved for § 60.261.
              (14) ASTM D86-78, Distillation of Petroleum Products, IBR approved for §§ 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).
              (15) ASTM D86-82, Distillation of Petroleum Products, IBR approved for §§ 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).

              (16) ASTM D86-90, Distillation of Petroleum Products, IBR approved for §§ 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).

              (17) ASTM D86-93, Distillation of Petroleum Products, IBR approved for §§ 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).
              (18) ASTM D86-95, Distillation of Petroleum Products, IBR approved for §§ 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).
              (19) ASTM D86-96, Distillation of Petroleum Products, (Approved April 10, 1996), IBR approved for §§ 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h), 60.5401(f), 60.5401a(f).
              (20) ASTM D129-64, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for §§ 60.106(j) and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (21) ASTM D129-78, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for §§ 60.106(j) and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (22) ASTM D129-95, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for §§ 60.106(j) and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (23) ASTM D129-00, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for § 60.335(b).
              (24) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for § 60.4415(a).
              (25) ASTM D240-76, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for §§ 60.46(c), 60.296(b), and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (26) ASTM D240-92, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for §§ 60.46(c), 60.296(b), and appendix A-7: Method 19, Section 12.5.2.2.3.
              (27) ASTM D240-02 (Reapproved 2007), Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, (Approved May 1, 2007), IBR approved for § 60.107a(d).
              (28) ASTM D270-65, Standard Method of Sampling Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.1.
              (29) ASTM D270-75, Standard Method of Sampling Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.1.
              (30) ASTM D323-82, Test Method for Vapor Pressure of Petroleum Products (Reid Method), IBR approved for §§ 60.111(l), 60.111a(g), 60.111b, and 60.116b(f).
              (31) ASTM D323-94, Test Method for Vapor Pressure of Petroleum Products (Reid Method), IBR approved for §§ 60.111(l), 60.111a(g), 60.111b, and 60.116b(f).
              (32) ASTM D388-77, Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, and 60.251.
              (33) ASTM D388-90, Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, and 60.251.
              (34) ASTM D388-91, Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, and 60.251.
              (35) ASTM D388-95, Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, and 60.251.
              (36) ASTM D388-98a, Standard Specification for Classification of Coals by Rank, IBR approved for §§ 60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, and 60.251.
              (37) ASTM D388-99 (Reapproved 2004) ε1 Standard Classification of Coals by Rank, IBR approved for §§ 60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, 60.251, and 60.5580.
              (38) ASTM D396-78, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b, 60.41c, 60.111(b), and 60.111a(b).
              (39) ASTM D396-89, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b, 60.41c, 60.111(b), and 60.111a(b).
              (40) ASTM D396-90, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b, 60.41c, 60.111(b), and 60.111a(b).
              (41) ASTM D396-92, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b, 60.41c, 60.111(b), and 60.111a(b).
              (42) ASTM D396-98, Standard Specification for Fuel Oils, IBR approved for §§ 60.41b, 60.41c, 60.111(b), 60.111a(b), and 60.5580.

              (43) ASTM D975-78, Standard Specification for Diesel Fuel Oils, IBR approved for §§ 60.111(b) and 60.111a(b).

              (44) ASTM D975-96, Standard Specification for Diesel Fuel Oils, IBR approved for §§ 60.111(b) and 60.111a(b).
              (45) ASTM D975-98a, Standard Specification for Diesel Fuel Oils, IBR approved for §§ 60.111(b) and 60.111a(b).
              (46) ASTM D975-08a, Standard Specification for Diesel Fuel Oils, IBR approved for §§ 60.41b 60.41c, and 60.5580.
              (47) ASTM D1072-80, Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for § 60.335(b).
              (48) ASTM D1072-90 (Reapproved 1994), Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for § 60.335(b).
              (49) ASTM D1072-90 (Reapproved 1999), Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for § 60.4415(a).
              (50) ASTM D1137-53, Standard Method for Analysis of Natural Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR approved for § 60.45(f).
              (51) ASTM D1137-75, Standard Method for Analysis of Natural Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR approved for § 60.45(f).
              (52) ASTM D1193-77, Standard Specification for Reagent Water, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.3; Method 5E, Section 7.2.1; Method 5F, Section 7.2.1; appendix A-4 to part 60: Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; appendix A-5 to part 60: Method 11, Section 7.1.3; Method 12, Section 7.1.3; Method 13A, Section 7.1.2; appendix A-8 to part 60: Method 26, Section 7.1.2; Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
              (53) ASTM D1193-91, Standard Specification for Reagent Water, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.3; Method 5E, Section 7.2.1; Method 5F, Section 7.2.1; appendix A-4 to part 60: Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; appendix A-5 to part 60: Method 11, Section 7.1.3; Method 12, Section 7.1.3; Method 13A, Section 7.1.2; appendix A-8 to part 60: Method 26, Section 7.1.2; Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.
              (54) ASTM D1266-87, Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for §§ 60.106(j) and 60.335(b).
              (55) ASTM D1266-91, Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for §§ 60.106(j) and 60.335(b).
              (56) ASTM D1266-98, Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for §§ 60.106(j) and 60.335(b).
              (57) ASTM D1266-98 (Reapproved 2003) ε,1 Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for § 60.4415(a).
              (58) ASTM D1475-60 (Reapproved 1980), Standard Test Method for Density of Paint, Varnish Lacquer, and Related Products, IBR approved for § 60.435(d), appendix A-8 to part 60: Method 24, Section 6.1; and Method 24A, Sections 6.5 and 7.1.
              (59) ASTM D1475-90, Standard Test Method for Density of Paint, Varnish Lacquer, and Related Products, IBR approved for § 60.435(d), appendix A-8 to part 60: Method 24, Section 6.1; and Method 24A, §§ 6.5 and 7.1.
              (60) ASTM D1552-83, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for §§ 60.106(j), 60.335(b), and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (61) ASTM D1552-95, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for §§ 60.106(j), 60.335(b), and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (62) ASTM D1552-01, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for §§ 60.106(j), 60.335(b), and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (63) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for § 60.4415(a).

              (64) ASTM D1826-77, Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for §§ 60.45(f), 60.46(c), 60.296(b), and appendix A-7 to part 60: Method 19, Section 12.3.2.4.
              (65) ASTM D1826-94, Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for §§ 60.45(f), 60.46(c), 60.296(b), and appendix A-7 to part 60: Method 19, Section 12.3.2.4.
              (66) ASTM D1826-94 (Reapproved 2003), Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, (Approved May 10, 2003), IBR approved for § 60.107a(d).
              (67) ASTM D1835-87, Standard Specification for Liquefied Petroleum (LP) Gases, IBR approved for §§ 60.41Da, 60.41b, and 60.41c.
              (68) ASTM D1835-91, Standard Specification for Liquefied Petroleum (LP) Gases, IBR approved for §§ 60.41Da, 60.41b, and 60.41c.
              (69) ASTM D1835-97, Standard Specification for Liquefied Petroleum (LP) Gases, IBR approved for §§ 60.41Da, 60.41b, and 60.41c.
              (70) ASTM D1835-03a, Standard Specification for Liquefied Petroleum (LP) Gases, IBR approved for §§ 60.41Da, 60.41b, and 60.41c.
              (71) ASTM D1945-64, Standard Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 60.45(f).
              (72) ASTM D1945-76, Standard Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 60.45(f).
              (73) ASTM D1945-91, Standard Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 60.45(f).
              (74) ASTM D1945-96, Standard Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 60.45(f).
              (75) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis of Natural Gas by Gas Chromatography, (Approved January 1, 2010), IBR approved for §§ 60.107a(d), 60.5413(d), 60.5413a(d).
              (76) ASTM D1946-77, Standard Method for Analysis of Reformed Gas by Gas Chromatography, IBR approved for §§ 60.18(f), 60.45(f), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).
              (77) ASTM D1946-90 (Reapproved 1994), Standard Method for Analysis of Reformed Gas by Gas Chromatography, IBR approved for §§ 60.18(f), 60.45(f), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).
              (78) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis of Reformed Gas by Gas Chromatography, (Approved June 1, 2006), IBR approved for § 60.107a(d).
              (79) ASTM D2013-72, Standard Method of Preparing Coal Samples for Analysis, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (80) ASTM D2013-86, Standard Method of Preparing Coal Samples for Analysis, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (81) ASTM D2015-77 (Reapproved 1978), Standard Test Method for Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR approved for §§ 60.45(f), 60.46(c), and appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (82) ASTM D2015-96, Standard Test Method for Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR approved for §§ 60.45(f), 60.46(c), and appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (83) ASTM D2016-74, Standard Test Methods for Moisture Content of Wood, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.
              (84) ASTM D2016-83, Standard Test Methods for Moisture Content of Wood, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.
              (85) ASTM D2234-76, Standard Methods for Collection of a Gross Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.1.
              (86) ASTM D2234-96, Standard Methods for Collection of a Gross Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.1.
              (87) ASTM D2234-97b, Standard Methods for Collection of a Gross Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.1.

              (88) ASTM D2234-98, Standard Methods for Collection of a Gross Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.1.

              (89) ASTM D2369-81, Standard Test Method for Volatile Content of Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section 6.2.
              (90) ASTM D2369-87, Standard Test Method for Volatile Content of Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section 6.2.
              (91) ASTM D2369-90, Standard Test Method for Volatile Content of Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section 6.2.
              (92) ASTM D2369-92, Standard Test Method for Volatile Content of Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section 6.2.
              (93) ASTM D2369-93, Standard Test Method for Volatile Content of Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section 6.2.
              (94) ASTM D2369-95, Standard Test Method for Volatile Content of Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section 6.2.
              (95) ASTM D2382-76, Heat of Combustion of Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), IBR approved for §§ 60.18(f), 60.485(g), 60.485a(g), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).
              (96) ASTM D2382-88, Heat of Combustion of Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), IBR approved for §§ 60.18(f), 60.485(g), 60.485a(g), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).
              (97) ASTM D2504-67, Noncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for §§ 60.485(g) and 60.485a(g).
              (98) ASTM D2504-77, Noncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for §§ 60.485(g) and 60.485a(g).
              (99) ASTM D2504-88 (Reapproved 1993), Noncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for §§ 60.485(g) and 60.485a(g).
              (100) ASTM D2584-68(Reapproved 1985), Standard Test Method for Ignition Loss of Cured Reinforced Resins, IBR approved for § 60.685(c).
              (101) ASTM D2584-94, Standard Test Method for Ignition Loss of Cured Reinforced Resins, IBR approved for § 60.685(c).
              (102) ASTM D2597-94 (Reapproved 1999), Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for § 60.335(b).
              (103) ASTM D2622-87, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §§ 60.106(j) and 60.335(b).
              (104) ASTM D2622-94, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §§ 60.106(j) and 60.335(b).
              (105) ASTM D2622-98, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §§ 60.106(j) and 60.335(b).
              (106) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR approved for § 60.4415(a).
              (107) ASTM D2879-83Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope, IBR approved for §§ 60.111b(f)(3), 60.116b(e), 60.116b(f), 60.485(e), and 60.485a(e).
              (108) ASTM D2879-96, Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope, IBR approved for §§ 60.111b(f)(3), 60.116b(e), 60.116b(f), 60.485(e), and 60.485a(e).
              (109) ASTM D2879-97, Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope, IBR approved for §§ 60.111b(f)(3), 60.116b(e), 60.116b(f), 60.485(e), and 60.485a(e).
              (110) ASTM D2880-78, Standard Specification for Gas Turbine Fuel Oils, IBR approved for §§ 60.111(b), 60.111a(b), and 60.335(d).
              (111) ASTM D2880-96, Standard Specification for Gas Turbine Fuel Oils, IBR approved for §§ 60.111(b), 60.111a(b), and 60.335(d).

              (112) ASTM D2908-74, Standard Practice for Measuring Volatile Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR approved for § 60.564(j).

              (113) ASTM D2908-91, Standard Practice for Measuring Volatile Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR approved for § 60.564(j).
              (114) ASTM D2986-71, Standard Method for Evaluation of Air, Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section 7.1.1.2.
              (115) ASTM D2986-78, Standard Method for Evaluation of Air, Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section 7.1.1.2.
              (116) ASTM D2986-95a, Standard Method for Evaluation of Air, Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section 7.1.1.2.
              (117) ASTM D3173-73, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (118) ASTM D3173-87, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (119) ASTM D3176-74, Standard Method for Ultimate Analysis of Coal and Coke, IBR approved for § 60.45(f)(5)(i) and appendix A-7 to part 60: Method 19, Section 12.3.2.3.
              (120) ASTM D3176-89, Standard Method for Ultimate Analysis of Coal and Coke, IBR approved for § 60.45(f)(5)(i) and appendix A-7 to part 60: Method 19, Section 12.3.2.3.
              (121) ASTM D3177-75, Standard Test Method for Total Sulfur in the Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (122) ASTM D3177-89, Standard Test Method for Total Sulfur in the Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (123) ASTM D3178-73 (Reapproved 1979), Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR approved for § 60.45(f).
              (124) ASTM D3178-89, Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR approved for § 60.45(f).
              (125) ASTM D3246-81, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for § 60.335(b).
              (126) ASTM D3246-92, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for § 60.335(b).
              (127) ASTM D3246-96, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for § 60.335(b).
              (128) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for § 60.4415(a)(1).
              (129) ASTM D3270-73T, Standard Test Methods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR approved for appendix A-5 to part 60: Method 13A, Section 16.1.
              (130) ASTM D3270-80, Standard Test Methods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR approved for appendix A-5 to part 60: Method 13A, Section 16.1.
              (131) ASTM D3270-91, Standard Test Methods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR approved for appendix A-5 to part 60: Method 13A, Section 16.1.
              (132) ASTM D3270-95, Standard Test Methods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR approved for appendix A-5 to part 60: Method 13A, Section 16.1.
              (133) ASTM D3286-85, Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

              (134) ASTM D3286-96, Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (135) ASTM D3370-76, Standard Practices for Sampling Water, IBR approved for § 60.564(j).
              (136) ASTM D3370-95a, Standard Practices for Sampling Water, IBR approved for § 60.564(j).
              (137) ASTM D3588-98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, (Approved May 10, 2003), IBR approved for §§ 60.107a(d), 60.5413(d), and 60.5413a(d).
              (138) ASTM D3699-08, Standard Specification for Kerosine, including Appendix X1, (Approved September 1, 2008), IBR approved for §§ 60.41b, 60.41c, and 60.5580.
              (139) ASTM D3792-79, Standard Test Method for Water Content of Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR approved for appendix A-7 to part 60: Method 24, Section 6.3.
              (140) ASTM D3792-91, Standard Test Method for Water Content of Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR approved for appendix A-7 to part 60: Method 24, Section 6.3.
              (141) ASTM D4017-81, Standard Test Method for Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR approved for appendix A-7 to part 60: Method 24, Section 6.4.
              (142) ASTM D4017-90, Standard Test Method for Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR approved for appendix A-7 to part 60: Method 24, Section 6.4.
              (143) ASTM D4017-96a, Standard Test Method for Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR approved for appendix A-7 to part 60: Method 24, Section 6.4.
              (144) ASTM D4057-81, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (145) ASTM D4057-95, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.
              (146) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for § 60.4415(a).
              (147) ASTM D4084-82, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for § 60.334(h).
              (148) ASTM D4084-94, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for § 60.334(h).
              (149) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for §§ 60.4360 and 60.4415(a).
              (150) ASTM D4177-95, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.1.
              (151) ASTM D4177-95 (Reapproved 2000), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for § 60.4415(a).
              (152) ASTM D4239-85, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (153) ASTM D4239-94, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (154) ASTM D4239-97, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.
              (155) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for § 60.335(b).

              (156) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for § 60.4415(a).
              (157) ASTM D4442-84, Standard Test Methods for Direct Moisture Content Measurement in Wood and Wood-base Materials, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.
              (158) ASTM D4442-92, Standard Test Methods for Direct Moisture Content Measurement in Wood and Wood-base Materials, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.
              (159) ASTM D4444-92, Standard Test Methods for Use and Calibration of Hand-Held Moisture Meters, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.
              (160) ASTM D4457-85 (Reapproved 1991), Test Method for Determination of Dichloromethane and 1,1,1-Trichloroethane in Paints and Coatings by Direct Injection into a Gas Chromatograph, IBR approved for appendix A-7 to part 60: Method 24, Section 6.5.
              (161) ASTM D4468-85 (Reapproved 2000), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, IBR approved for §§ 60.335(b) and 60.4415(a).
              (162) ASTM D4468-85 (Reapproved 2006), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, (Approved June 1, 2006), IBR approved for § 60.107a(e).
              (163) ASTM D4629-02, Standard Test Method for Trace Nitrogen in Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and Chemiluminescence Detection, IBR approved for §§ 60.49b(e) and 60.335(b).
              (164) ASTM D4809-95, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for §§ 60.18(f), 60.485(g), 60.485a(g), 60.564(f), 60.614(d), 60.664(e), and 60.704(d).
              (165) ASTM D4809-06, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), (Approved December 1, 2006), IBR approved for § 60.107a(d).
              (166) ASTM D4810-88 (Reapproved 1999), Standard Test Method for Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes, IBR approved for §§ 60.4360 and 60.4415(a).
              (167) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, (Approved June 1, 2006), IBR approved for §§ 60.107a(d), 60.5413(d), and 60.5413a(d).
              (168) ASTM D5287-97 (Reapproved 2002), Standard Practice for Automatic Sampling of Gaseous Fuels, IBR approved for § 60.4415(a).
              (169) ASTM D5403-93, Standard Test Methods for Volatile Content of Radiation Curable Materials, IBR approved for appendix A-7 to part 60: Method 24, Section 6.6.
              (170) ASTM D5453-00, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for § 60.335(b).
              (171) ASTM D5453-05, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for § 60.4415(a).
              (172) ASTM D5504-01, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, IBR approved for §§ 60.334(h) and 60.4360.
              (173) ASTM D5504-08, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, (Approved June 15, 2008), IBR approved for §§ 60.107a(e) and 60.5413(d).
              (174) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved for § 60.335(b).
              (175) ASTM D5865-98, Standard Test Method for Gross Calorific Value of Coal and Coke, IBR approved for §§ 60.45(f) and 60.46(c), and appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

              (176) ASTM D5865-10, Standard Test Method for Gross Calorific Value of Coal and Coke, (Approved January 1, 2010), IBR approved for §§ 60.45(f), 60.46(c), and appendix A-7 to part 60: Method 19, section 12.5.2.1.3.

              (177) ASTM D6216-12, Standard Practice for Opacity Monitor Manufacturers to Certify Conformance with Design and Performance Specifications, approved October 1, 2012; IBR approved for appendix B to part 60.
              (178) ASTM D6228-98, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR approved for § 60.334(h).
              (179) ASTM D6228-98 (Reapproved 2003), Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR approved for §§ 60.4360 and 60.4415.
              (180) ASTM D6348-03, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, (Approved October 1, 2003), IBR approved for § 60.73a(b), table 7 to subpart IIII, table 2 to subpart JJJJ, and § 60.4245(d).
              (181) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative Combustion and Electrochemical Detection, IBR approved for § 60.335(b)(9).
              (182) ASTM D6420-99 (Reapproved 2004), Standard Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography-Mass Spectrometry, (Approved October 1, 2004), IBR approved for § 60.107a(d) and table 2 to subpart JJJJ.
              (183) ASTM D6522-00, Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR approved for § 60.335(a).
              (184) ASTM D6522-00 (Reapproved 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, (Approved October 1, 2005), IBR approved for table 2 to subpart JJJJ, §§ 60.5413(b) and (d), and 60.5413a(b).
              (185) ASTM D6522-11 Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers (Approved December 1, 2011), IBR approved for § 60.37f(a), 60.766(a).
              (186) ASTM D6667-01, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR approved for § 60.335(b).
              (187) ASTM D6667-04, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR approved for § 60.4415(a).
              (188) ASTM D6751-11b, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1 through X3, (Approved July 15, 2011), IBR approved for §§ 60.41b, 60.41c, and 60.5580.
              (189) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), IBR approved for § 60.56c(b) and appendix B to part 60: Performance Specification 12A, Section 8.6.2.
              (190) ASTM D6784-02 (Reapproved 2008) Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), (Approved April 1, 2008), IBR approved for §§ 60.2165(j) and 60.2730(j), tables 5, 6 and 8 to subpart CCCC, and tables 2, 6, 7, and 9 to subpart DDDD, §§ 60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, and tables 2 and 3 to subpart MMMM.
              (191) ASTM D6911-15, Standard Guide for Packaging and Shipping Environmental Samples for Laboratory Analysis, approved January 15, 2015, IBR approved for appendix A-8: Method 30B.

              (192) ASTM D7467-10, Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20), including Appendices X1 through X3, (Approved August 1, 2010), IBR approved for §§ 60.41b, 60.41c, and 60.5580.
              (193) ASTM E168-67, General Techniques of Infrared Quantitative Analysis, IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), and 60.632(f).
              (194) ASTM E168-77, General Techniques of Infrared Quantitative Analysis, IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), and 60.632(f).
              (195) ASTM E168-92, General Techniques of Infrared Quantitative Analysis, IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400, 60.5400a(f).
              (196) ASTM E169-63, General Techniques of Ultraviolet Quantitative Analysis, IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), and 60.632(f) .
              (197) ASTM E169-77, General Techniques of Ultraviolet Quantitative Analysis, IBR approved for §§ 60.485a(d), 60.593(b), and 60.593a(b), 60.632(f).
              (198) ASTM E169-93, General Techniques of Ultraviolet Quantitative Analysis, (Approved May 15, 1993), IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), and 60.5400a(f).
              (199) ASTM E260-73, General Gas Chromatography Procedures, IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), and 60.632(f).
              (200) ASTM E260-91, General Gas Chromatography Procedures, (IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), and 60.632(f).
              (201) ASTM E260-96, General Gas Chromatography Procedures, (Approved April 10, 1996), IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), 60.5400a(f) 60.5406(b), and 60.5406a(b)(3).
              (202) ASTM E617-13, Standard Specification for Laboratory Weights and Precision Mass Standards, approved May 1, 2013, IBR approved for appendix A-3: Methods 4, 5, 5H, 5I, and appendix A-8: Method 29.
              (203) ASTM E871-82 (Reapproved 2013), Standard Test Method for Moisture Analysis of Particulate Wood Fuels, (Approved August 15, 2013), IBR approved for appendix A-8: method 28R.
              (204) ASTM E1584-11, Standard Test Method for Assay of Nitric Acid, (Approved August 1, 2011), IBR approved for § 60.73a(c).
              (205) ASTM E2515-11, Standard Test Method for Determination of Particulate Matter Emissions Collected by a Dilution Tunnel, (Approved November 1, 2011), IBR approved for § 60.534 and § 60.5476.
              (206) ASTM E2618-13 Standard Test Method for Measurement of Particulate Matter Emissions and Heating Efficiency of Outdoor Solid Fuel-Fired Hydronic Heating Appliances, (Approved September 1, 2013), IBR approved for § 60.5476.
              (207) ASTM E2779-10, Standard Test Method for Determining Particulate Matter Emissions from Pellet Heaters, (Approved October 1, 2010), IBR approved for § 60.534.
              (208) ASTM E2780-10, Standard Test Method for Determining Particulate Matter Emissions from Wood Heaters, (Approved October 1, 2010), IBR approved for appendix A: method 28R.
              (209) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography, (Copyright 1997), IBR approved for § 60.107a(d).
              (i) Association of Official Analytical Chemists, 1111 North 19th Street, Suite 210, Arlington, VA 22209.
              (1) AOAC Method 9, Official Methods of Analysis of the Association of Official Analytical Chemists (AOAC), 11th edition, 1970, pp. 11-12, IBR approved for §§ 60.204(b), 60.214(b), 60.224(b), and 60.234(b).
              (2) [Reserved]

              (j) U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov.

              (1) EPA-454/R-98-015, Office of Air Quality Planning and Standards (OAQPS) Fabric Filter Bag Leak Detection Guidance, September 1997, IBR approved for §§ 60.2145(r), 60.2710(r), 60.4905(b), and 60.5225(b).
              (2) EPA-600/R-12/531, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards, May 2012, IBR approved for §§ 60.5413(d) and 60.5413a(d).

              (k) The Gas Processors Association, 6526 East 60th Street, Tulsa, OK 74145; also available through Information Handling Services, 15 Inverness Way East, PO Box 1154, Englewood, CO 80150-1154. You may inspect a copy at the EPA's Air and Radiation Docket and Information Center, Room 3334, 1301 Constitution Ave. NW., Washington, DC 20460.
              (1) Gas Processors Association Standard 2172-09, Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer (2009), IBR approved for § 60.107a(d).
              (2) Gas Processors Association Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (2000), IBR approved for § 60.107a(d).
              (3) Gas Processors Association Standard 2377-86, Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes, 1986 Revision, IBR approved for §§ 60.105(b), 60.107a(b), 60.334(h), 60.4360, and 60.4415(a).
              (l) International Organization for Standardization (ISO) available through IHS Inc., 15 Inverness Way East, Englewood, CO 80112.
              (1) ISO 8178-4: 1996(E), Reciprocating Internal Combustion Engines—Exhaust Emission Measurement—part 4: Test Cycles for Different Engine Applications, IBR approved for § 60.4241(b).
              (2) [Reserved]

              (m) International Organization for Standardization (ISO), 1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland, + 41 22 749 01 11, http://www.iso.org/iso/home.htm.

              (1) ISO 2314:2009(E), Gas turbines-Acceptance tests, Third edition (December 15, 2009), IBR approved for § 60.5580.
              (2) ISO 8316: Measurement of Liquid Flow in Closed Conduits—Method by Collection of the Liquid in a Volumetric Tank (1987-10-01)—First Edition, IBR approved for § 60.107a(d).
              (n) This material is available for purchase from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, Virginia 22161. You may inspect a copy at the EPA's Air and Radiation Docket and Information Center (Docket A-91-61, Item IV-J-125), Room M-1500, 1200 Pennsylvania Ave. NW., Washington, DC 20460.
              (1) OMB Bulletin No. 93-17: Revised Statistical Definitions for Metropolitan Areas. Office of Management and Budget, June 30, 1993. NTIS No. PB 93-192-664. IBR approved for § 60.31e.
              (2) [Reserved]

              (o) North American Electric Reliability Corporation, 1325 G Street NW., Suite 600, Washington, DC 20005-3801, http://www.nerc.com.

              (1) North American Electric Reliability Corporation Reliability Standard EOP-002-3, Capacity and Energy Emergencies, updated November 19, 2012, IBR approved for §§ 60.4211(f) and 60.4243(d). Also available online: http://www.nerc.com/files/EOP-002-3 __1.pdf.

              (2) [Reserved]

              (p) The following material is available for purchase from the Technical Association of the Pulp and Paper Industry (TAPPI), 15 Technology Parkway South, Suite 115, Peachtree Corners, GA 30092, Telephone (800) 332-8686, and is also available at the following Web site: http://www.tappi.org.

              (1) TAPPI Method T 624 cm-11, (Copyright 2011), IBR approved, for §§ 60.285(d) and 60.285a(d).
              (2) [Reserved]
              (q) Underwriter's Laboratories, Inc. (UL), 333 Pfingsten Road, Northbrook, IL 60062.
              (1) UL 103, Sixth Edition revised as of September 3, 1986, Standard for Chimneys, Factory-built, Residential Type and Building Heating Appliance, IBR approved for appendix A-8 to part 60.
              (2) [Reserved]
              (r) Water Pollution Control Federation (WPCF), 2626 Pennsylvania Avenue NW., Washington, DC 20037.
              (1) Method 209A, Total Residue Dried at 103-105 °C, in Standard Methods for the Examination of Water and Wastewater, 15th Edition, 1980, IBR approved for § 60.683(b).
              (2) [Reserved]
              (s) West Coast Lumber Inspection Bureau, 6980 SW. Barnes Road, Portland, OR 97223.
              (1) West Coast Lumber Standard Grading Rules No. 16, pages 5-21, 90 and 91, September 3, 1970, revised 1984, IBR approved for appendix A-8 to part 60.
              (2) [Reserved]
              (t) This material is available for purchase from the Canadian Standards Association (CSA), 5060 Spectrum Way, Suite 100, Mississauga, Ontario, Canada L4W 5N6, Telephone: 800-463-6727.

              (1) CSA B415.1-10, Performance Testing of Solid-fuel-burning Heating Appliances, (March 2010), IBR approved for § 60.534 and § 60.5476. (The standard is also available at http://shop.csa.ca/en/canada/fuel-burning-equipment/b4151-10/invt/27013322010)
              (2) [Reserved]
              (u) This European National (EN) standards material is available for purchase at European Committee for Standardization, Management Centre, Avenue Marnix 17, B-1000 Brussels, Belgium, Telephone: + 32 2 550 08 11.

              (1) DIN EN 303-5:2012E (EN 303-5), Heating boilers—Part 5: Heating boilers for solid fuels, manually and automatically stoked, nominal heat output of up to 500 kW—Terminology, requirements, testing and marking, (October 2012), IBR approved for § 60.5476. (The standard is also available at http://www.en-standard.eu/csn-en-303- 5-heating-boilers-part-5-heating- boilers-for-solid-fuels- manually-and-automatically- stoked-nominal-heat-output- of-up-to-500-kw-terminology- requirements-testing-and- marking/?gclid=CJXI2P_ _97MMCFdccgQodan8ATA)
              (2) [Reserved]
              [79 FR 11242, Feb. 27, 2014, as amended at 79 FR 18965, Apr. 4, 2014; 80 FR 13701, Mar. 16, 2015; 80 FR 64648, Oct. 23, 2015; 81 FR 35895, June 3, 2016; 81 FR 59313, 59368, Aug. 29, 2016; 81 FR 59809, Aug. 30, 2016; 82 FR 28562, June 23, 2017; 83 FR 56720, Nov. 14, 2018; 83 FR 60713, Nov. 26, 2018; 84 FR 15852, Apr. 16, 2019]

              § 60.18
              General control device and work practice requirements.
              (a) Introduction. (1) This section contains requirements for control devices used to comply with applicable subparts of 40 CFR parts 60 and 61. The requirements are placed here for administrative convenience and apply only to facilities covered by subparts referring to this section.
              (2) This section also contains requirements for an alternative work practice used to identify leaking equipment. This alternative work practice is placed here for administrative convenience and is available to all subparts in 40 CFR parts 60, 61, 63, and 65 that require monitoring of equipment with a 40 CFR part 60, appendix A-7, Method 21 monitor.
              (b) Flares. Paragraphs (c) through (f) apply to flares.
              (c)(1) Flares shall be designed for and operated with no visible emissions as determined by the methods specified in paragraph (f), except for periods not to exceed a total of 5 minutes during any 2 consecutive hours.
              (2) Flares shall be operated with a flame present at all times, as determined by the methods specified in paragraph (f).
              (3) An owner/operator has the choice of adhering to either the heat content specifications in paragraph (c)(3)(ii) of this section and the maximum tip velocity specifications in paragraph (c)(4) of this section, or adhering to the requirements in paragraph (c)(3)(i) of this section.

              (i)(A) Flares shall be used that have a diameter of 3 inches or greater, are nonassisted, have a hydrogen content of 8.0 percent (by volume), or greater, and are designed for and operated with an exit velocity less than 37.2 m/sec (122 ft/sec) and less than the velocity, Vmax, as determined by the following equation:

              Vmax = (XH2−K1)* K2

                Where:

                Vmax = Maximum permitted velocity, m/sec.
                K1 = Constant, 6.0 volume-percent hydrogen.
                K2 = Constant, 3.9(m/sec)/volume-percent hydrogen.
                XH2 = The volume-percent of hydrogen, on a wet basis, as calculated by using the American Society for Testing and Materials (ASTM) Method D1946-77. (Incorporated by reference as specified in § 60.17).

              (B) The actual exit velocity of a flare shall be determined by the method specified in paragraph (f)(4) of this section.
              (ii) Flares shall be used only with the net heating value of the gas being combusted being 11.2 MJ/scm (300 Btu/scf) or greater if the flare is steam-assisted or air-assisted; or with the net heating value of the gas being combusted being 7.45 MJ/scm (200 Btu/scf) or greater if the flare is nonassisted. The net heating value of the gas being combusted shall be determined by the methods specified in paragraph (f)(3) of this section.

              (4)(i) Steam-assisted and nonassisted flares shall be designed for and operated with an exit velocity, as determined by the methods specified in paragraph (f)(4) of this section, less than 18.3 m/sec (60 ft/sec), except as provided in paragraphs (c)(4) (ii) and (iii) of this section.
              (ii) Steam-assisted and nonassisted flares designed for and operated with an exit velocity, as determined by the methods specified in paragraph (f)(4), equal to or greater than 18.3 m/sec (60 ft/sec) but less than 122 m/sec (400 ft/sec) are allowed if the net heating value of the gas being combusted is greater than 37.3 MJ/scm (1,000 Btu/scf).

              (iii) Steam-assisted and nonassisted flares designed for and operated with an exit velocity, as determined by the methods specified in paragraph (f)(4), less than the velocity, Vmax, as determined by the method specified in paragraph (f)(5), and less than 122 m/sec (400 ft/sec) are allowed.

              (5) Air-assisted flares shall be designed and operated with an exit velocity less than the velocity, Vmax, as determined by the method specified in paragraph (f)(6).
              (6) Flares used to comply with this section shall be steam-assisted, air-assisted, or nonassisted.
              (d) Owners or operators of flares used to comply with the provisions of this subpart shall monitor these control devices to ensure that they are operated and maintained in conformance with their designs. Applicable subparts will provide provisions stating how owners or operators of flares shall monitor these control devices.
              (e) Flares used to comply with provisions of this subpart shall be operated at all times when emissions may be vented to them.
              (f)(1) Method 22 of appendix A to this part shall be used to determine the compliance of flares with the visible emission provisions of this subpart. The observation period is 2 hours and shall be used according to Method 22.
              (2) The presence of a flare pilot flame shall be monitored using a thermocouple or any other equivalent device to detect the presence of a flame.
              (3) The net heating value of the gas being combusted in a flare shall be calculated using the following equation:

                EC01JN92.008

                where:

                HT = Net heating value of the sample, MJ/scm; where the net enthalpy per mole of offgas is based on combustion at 25 °C and 760 mm Hg, but the standard temperature for determining the volume corresponding to one mole is 20 °C;

                  EC01JN92.009

                Ci = Concentration of sample component i in ppm on a wet basis, as measured for organics by Reference Method 18 and measured for hydrogen and carbon monoxide by ASTM D1946-77 or 90 (Reapproved 1994) (Incorporated by reference as specified in § 60.17); and
                Hi = Net heat of combustion of sample component i, kcal/g mole at 25 °C and 760 mm Hg. The heats of combustion may be determined using ASTM D2382-76 or 88 or D4809-95 (incorporated by reference as specified in § 60.17) if published values are not available or cannot be calculated.

              (4) The actual exit velocity of a flare shall be determined by dividing the volumetric flowrate (in units of standard temperature and pressure), as determined by Reference Methods 2, 2A, 2C, or 2D as appropriate; by the unobstructed (free) cross sectional area of the flare tip.
              (5) The maximum permitted velocity, Vmax, for flares complying with paragraph (c)(4)(iii) shall be determined by the following equation.

                Log10 (Vmax) = (HT + 28.8)/31.7

                Vmax = Maximum permitted velocity, M/sec
                28.8 = Constant
                31.7 = Constant
                HT = The net heating value as determined in paragraph (f)(3).

              (6) The maximum permitted velocity, Vmax, for air-assisted flares shall be determined by the following equation.

                Vmax = 8.706 + 0.7084 (HT)

                Vmax = Maximum permitted velocity, m/sec
                8.706 = Constant
                0.7084 = Constant
                HT = The net heating value as determined in paragraph (f)(3).

              (g) Alternative work practice for monitoring equipment for leaks. Paragraphs (g), (h), and (i) of this section apply to all equipment for which the applicable subpart requires monitoring with a 40 CFR part 60, appendix A-7, Method 21 monitor, except for closed vent systems, equipment designated as leakless, and equipment identified in the applicable subpart as having no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background. An owner or operator may use an optical gas imaging instrument instead of a 40 CFR part 60, appendix A-7, Method 21 monitor. Requirements in the existing subparts that are specific to the Method 21 instrument do not apply under this section. All other requirements in the applicable subpart that are not addressed in paragraphs (g), (h), and (i) of this section apply to this standard. For example, equipment specification requirements, and non-Method 21 instrument recordkeeping and reporting requirements in the applicable subpart continue to apply. The terms defined in paragraphs (g)(1) through (5) of this section have meanings that are specific to the alternative work practice standard in paragraphs (g), (h), and (i) of this section.
              (1) Applicable subpart means the subpart in 40 CFR parts 60, 61, 63, or 65 that requires monitoring of equipment with a 40 CFR part 60, appendix A-7, Method 21 monitor.
              (2) Equipment means pumps, valves, pressure relief valves, compressors, open-ended lines, flanges, connectors, and other equipment covered by the applicable subpart that require monitoring with a 40 CFR part 60, appendix A-7, Method 21 monitor.
              (3) Imaging means making visible emissions that may otherwise be invisible to the naked eye.
              (4) Optical gas imaging instrument means an instrument that makes visible emissions that may otherwise be invisible to the naked eye.
              (5) Repair means that equipment is adjusted, or otherwise altered, in order to eliminate a leak.
              (6) Leak means:
              (i) Any emissions imaged by the optical gas instrument;
              (ii) Indications of liquids dripping;
              (iii) Indications by a sensor that a seal or barrier fluid system has failed; or
              (iv) Screening results using a 40 CFR part 60, appendix A-7, Method 21 monitor that exceed the leak definition in the applicable subpart to which the equipment is subject.
              (h) The alternative work practice standard for monitoring equipment for leaks is available to all subparts in 40 CFR parts 60, 61, 63, and 65 that require monitoring of equipment with a 40 CFR part 60, appendix A-7, Method 21 monitor.
              (1) An owner or operator of an affected source subject to CFR parts 60, 61, 63, or 65 can choose to comply with the alternative work practice requirements in paragraph (i) of this section instead of using the 40 CFR part 60, appendix A-7, Method 21 monitor to identify leaking equipment. The owner or operator must document the equipment, process units, and facilities for which the alternative work practice will be used to identify leaks.
              (2) Any leak detected when following the leak survey procedure in paragraph (i)(3) of this section must be identified for repair as required in the applicable subpart.
              (3) If the alternative work practice is used to identify leaks, re-screening after an attempted repair of leaking equipment must be conducted using either the alternative work practice or the 40 CFR part 60, appendix A-7, Method 21 monitor at the leak definition required in the applicable subpart to which the equipment is subject.
              (4) The schedule for repair is as required in the applicable subpart.

              (5) When this alternative work practice is used for detecting leaking equipment, choose one of the monitoring frequencies listed in Table 1 to subpart A of this part in lieu of the monitoring frequency specified for regulated equipment in the applicable subpart. Reduced monitoring frequencies for good performance are not applicable when using the alternative work practice.
              (6) When this alternative work practice is used for detecting leaking equipment the following are not applicable for the equipment being monitored:
              (i) Skip period leak detection and repair;
              (ii) Quality improvement plans; or
              (iii) Complying with standards for allowable percentage of valves and pumps to leak.
              (7) When the alternative work practice is used to detect leaking equipment, the regulated equipment in paragraph (h)(1)(i) of this section must also be monitored annually using a 40 CFR part 60, appendix A-7, Method 21 monitor at the leak definition required in the applicable subpart. The owner or operator may choose the specific monitoring period (for example, first quarter) to conduct the annual monitoring. Subsequent monitoring must be conducted every 12 months from the initial period. Owners or operators must keep records of the annual Method 21 screening results, as specified in paragraph (i)(4)(vii) of this section.
              (i) An owner or operator of an affected source who chooses to use the alternative work practice must comply with the requirements of paragraphs (i)(1) through (i)(5) of this section.
              (1) Instrument Specifications. The optical gas imaging instrument must comply with the requirements in (i)(1)(i) and (i)(1)(ii) of this section.
              (i) Provide the operator with an image of the potential leak points for each piece of equipment at both the detection sensitivity level and within the distance used in the daily instrument check described in paragraph (i)(2) of this section. The detection sensitivity level depends upon the frequency at which leak monitoring is to be performed.
              (ii) Provide a date and time stamp for video records of every monitoring event.
              (2) Daily Instrument Check. On a daily basis, and prior to beginning any leak monitoring work, test the optical gas imaging instrument at the mass flow rate determined in paragraph (i)(2)(i) of this section in accordance with the procedure specified in paragraphs (i)(2)(ii) through (i)(2)(iv) of this section for each camera configuration used during monitoring (for example, different lenses used), unless an alternative method to demonstrate daily instrument checks has been approved in accordance with paragraph (i)(2)(v) of this section.
              (i) Calculate the mass flow rate to be used in the daily instrument check by following the procedures in paragraphs (i)(2)(i)(A) and (i)(2)(i)(B) of this section.
              (A) For a specified population of equipment to be imaged by the instrument, determine the piece of equipment in contact with the lowest mass fraction of chemicals that are detectable, within the distance to be used in paragraph (i)(2)(iv)(B) of this section, at or below the standard detection sensitivity level.
              (B) Multiply the standard detection sensitivity level, corresponding to the selected monitoring frequency in Table 1 of subpart A of this part, by the mass fraction of detectable chemicals from the stream identified in paragraph (i)(2)(i)(A) of this section to determine the mass flow rate to be used in the daily instrument check, using the following equation.

                ER22DE08.007

                Where:

                Edic = Mass flow rate for the daily instrument check, grams per hour
                xi = Mass fraction of detectable chemical(s) i seen by the optical gas imaging instrument, within the distance to be used in paragraph (i)(2)(iv)(B) of this section, at or below the standard detection sensitivity level, Esds.
                Esds = Standard detection sensitivity level from Table 1 to subpart A, grams per hour
                k = Total number of detectable chemicals emitted from the leaking equipment and seen by the optical gas imaging instrument.

              (ii) Start the optical gas imaging instrument according to the manufacturer's instructions, ensuring that all appropriate settings conform to the manufacturer's instructions.

              (iii) Use any gas chosen by the user that can be viewed by the optical gas imaging instrument and that has a purity of no less than 98 percent.
              (iv) Establish a mass flow rate by using the following procedures:
              (A) Provide a source of gas where it will be in the field of view of the optical gas imaging instrument.
              (B) Set up the optical gas imaging instrument at a recorded distance from the outlet or leak orifice of the flow meter that will not be exceeded in the actual performance of the leak survey. Do not exceed the operating parameters of the flow meter.
              (C) Open the valve on the flow meter to set a flow rate that will create a mass emission rate equal to the mass rate specified in paragraph (i)(2)(i) of this section while observing the gas flow through the optical gas imaging instrument viewfinder. When an image of the gas emission is seen through the viewfinder at the required emission rate, make a record of the reading on the flow meter.
              (v) Repeat the procedures specified in paragraphs (i)(2)(ii) through (i)(2)(iv) of this section for each configuration of the optical gas imaging instrument used during the leak survey.
              (vi) To use an alternative method to demonstrate daily instrument checks, apply to the Administrator for approval of the alternative under § 60.13(i).
              (3) Leak Survey Procedure. Operate the optical gas imaging instrument to image every regulated piece of equipment selected for this work practice in accordance with the instrument manufacturer's operating parameters. All emissions imaged by the optical gas imaging instrument are considered to be leaks and are subject to repair. All emissions visible to the naked eye are also considered to be leaks and are subject to repair.
              (4) Recordkeeping. You must keep the records described in paragraphs (i)(4)(i) through (i)(4)(vii) of this section:
              (i) The equipment, processes, and facilities for which the owner or operator chooses to use the alternative work practice.
              (ii) The detection sensitivity level selected from Table 1 to subpart A of this part for the optical gas imaging instrument.
              (iii) The analysis to determine the piece of equipment in contact with the lowest mass fraction of chemicals that are detectable, as specified in paragraph (i)(2)(i)(A) of this section.
              (iv) The technical basis for the mass fraction of detectable chemicals used in the equation in paragraph (i)(2)(i)(B) of this section.
              (v) The daily instrument check. Record the distance, per paragraph (i)(2)(iv)(B) of this section, and the flow meter reading, per paragraph (i)(2)(iv)(C) of this section, at which the leak was imaged. Keep a video record of the daily instrument check for each configuration of the optical gas imaging instrument used during the leak survey (for example, the daily instrument check must be conducted for each lens used). The video record must include a time and date stamp for each daily instrument check. The video record must be kept for 5 years.
              (vi) Recordkeeping requirements in the applicable subpart. A video record must be used to document the leak survey results. The video record must include a time and date stamp for each monitoring event. A video record can be used to meet the recordkeeping requirements of the applicable subparts if each piece of regulated equipment selected for this work practice can be identified in the video record. The video record must be kept for 5 years.
              (vii) The results of the annual Method 21 screening required in paragraph (h)(7) of this section. Records must be kept for all regulated equipment specified in paragraph (h)(1) of this section. Records must identify the equipment screened, the screening value measured by Method 21, the time and date of the screening, and calibration information required in the existing applicable subpart.

              (5) Reporting. Submit the reports required in the applicable subpart. Submit the records of the annual Method 21 screening required in paragraph (h)(7) of this section to the Administrator via e-mail to CCG-AWP@EPA.GOV.

              [51 FR 2701, Jan. 21, 1986, as amended at 63 FR 24444, May 4, 1998; 65 FR 61752, Oct. 17, 2000; 73 FR 78209, Dec. 22, 2008]

              § 60.19
              General notification and reporting requirements.
              (a) For the purposes of this part, time periods specified in days shall be measured in calendar days, even if the word “calendar” is absent, unless otherwise specified in an applicable requirement.
              (b) For the purposes of this part, if an explicit postmark deadline is not specified in an applicable requirement for the submittal of a notification, application, report, or other written communication to the Administrator, the owner or operator shall postmark the submittal on or before the number of days specified in the applicable requirement. For example, if a notification must be submitted 15 days before a particular event is scheduled to take place, the notification shall be postmarked on or before 15 days preceding the event; likewise, if a notification must be submitted 15 days after a particular event takes place, the notification shall be delivered or postmarked on or before 15 days following the end of the event. The use of reliable non-Government mail carriers that provide indications of verifiable delivery of information required to be submitted to the Administrator, similar to the postmark provided by the U.S. Postal Service, or alternative means of delivery, including the use of electronic media, agreed to by the permitting authority, is acceptable.
              (c) Notwithstanding time periods or postmark deadlines specified in this part for the submittal of information to the Administrator by an owner or operator, or the review of such information by the Administrator, such time periods or deadlines may be changed by mutual agreement between the owner or operator and the Administrator. Procedures governing the implementation of this provision are specified in paragraph (f) of this section.
              (d) If an owner or operator of an affected facility in a State with delegated authority is required to submit periodic reports under this part to the State, and if the State has an established timeline for the submission of periodic reports that is consistent with the reporting frequency(ies) specified for such facility under this part, the owner or operator may change the dates by which periodic reports under this part shall be submitted (without changing the frequency of reporting) to be consistent with the State's schedule by mutual agreement between the owner or operator and the State. The allowance in the previous sentence applies in each State beginning 1 year after the affected facility is required to be in compliance with the applicable subpart in this part. Procedures governing the implementation of this provision are specified in paragraph (f) of this section.
              (e) If an owner or operator supervises one or more stationary sources affected by standards set under this part and standards set under part 61, part 63, or both such parts of this chapter, he/she may arrange by mutual agreement between the owner or operator and the Administrator (or the State with an approved permit program) a common schedule on which periodic reports required by each applicable standard shall be submitted throughout the year. The allowance in the previous sentence applies in each State beginning 1 year after the stationary source is required to be in compliance with the applicable subpart in this part, or 1 year after the stationary source is required to be in compliance with the applicable 40 CFR part 61 or part 63 of this chapter standard, whichever is latest. Procedures governing the implementation of this provision are specified in paragraph (f) of this section.
              (f)(1)(i) Until an adjustment of a time period or postmark deadline has been approved by the Administrator under paragraphs (f)(2) and (f)(3) of this section, the owner or operator of an affected facility remains strictly subject to the requirements of this part.
              (ii) An owner or operator shall request the adjustment provided for in paragraphs (f)(2) and (f)(3) of this section each time he or she wishes to change an applicable time period or postmark deadline specified in this part.

              (2) Notwithstanding time periods or postmark deadlines specified in this part for the submittal of information to the Administrator by an owner or operator, or the review of such information by the Administrator, such time periods or deadlines may be changed by mutual agreement between the owner or operator and the Administrator. An owner or operator who wishes to request a change in a time period or postmark deadline for a particular requirement shall request the adjustment in writing as soon as practicable before the subject activity is required to take place. The owner or operator shall include in the request whatever information he or she considers useful to convince the Administrator that an adjustment is warranted.
              (3) If, in the Administrator's judgment, an owner or operator's request for an adjustment to a particular time period or postmark deadline is warranted, the Administrator will approve the adjustment. The Administrator will notify the owner or operator in writing of approval or disapproval of the request for an adjustment within 15 calendar days of receiving sufficient information to evaluate the request.
              (4) If the Administrator is unable to meet a specified deadline, he or she will notify the owner or operator of any significant delay and inform the owner or operator of the amended schedule.
              [59 FR 12428, Mar. 16, 1994, as amended at 64 FR 7463, Feb. 12, 1998]

              Pt. 60, Subpt. A, Table 1
              Table 1 to Subpart A of Part 60—Detection Sensitivity Levels (grams per hour)

                  Monitoring frequency per subpart a

                  Detection sensitivity level

                  Bi-Monthly
                  60

                  Semi-Quarterly
                  85

                  Monthly
                  100

                  a When this alternative work practice is used to identify leaking equipment, the owner or operator must choose one of the monitoring frequencies listed in this table in lieu of the monitoring frequency specified in the applicable subpart. Bi-monthly means every other month. Semi-quarterly means twice per quarter. Monthly means once per month.

              [73 FR 78211, Dec. 22, 2008]

            Subpart B—Adoption and Submittal of State Plans for Designated Facilities

              Source:
              40 FR 53346, Nov. 17, 1975, unless otherwise noted.

              § 60.20
              Applicability.
              The provisions of this subpart apply to States upon publication of a final guideline document under § 60.22(a).

              § 60.21
              Definitions.
              Terms used but not defined in this subpart shall have the meaning given them in the Act and in subpart A:
              (a) Designated pollutant means any air pollutant, the emissions of which are subject to a standard of performance for new stationary sources, but for which air quality criteria have not been issued and that is not included on a list published under section 108(a) or section 112(b)(1)(A) of the Act.
              (b) Designated facility means any existing facility (see § 60.2(aa)) which emits a designated pollutant and which would be subject to a standard of performance for that pollutant if the existing facility were an affected facility (see § 60.2(e)).
              (c) Plan means a plan under section 111(d) of the Act which establishes emission standards for designated pollutants from designated facilities and provides for the implementation and enforcement of such emission standards.
              (d) Applicable plan means the plan, or most recent revision thereof, which has been approved under § 60.27(b) or promulgated under § 60.27(d).
              (e) Emission guideline means a guideline set forth in subpart C of this part, or in a final guideline document published under § 60.22(a), which reflects the degree of emission reduction achievable through the application of the best system of emission reduction which (taking into account the cost of such reduction) the Administrator has determined has been adequately demonstrated for designated facilities.
              (f) Emission standard means a legally enforceable regulation setting forth an allowable rate of emissions into the atmosphere, establishing an allowance system, or prescribing equipment specifications for control of air pollution emissions.
              (g) Compliance schedule means a legally enforceable schedule specifying a date or dates by which a source or category of sources must comply with specific emission standards contained in a plan or with any increments of progress to achieve such compliance.
              (h) Increments of progress means steps to achieve compliance which must be taken by an owner or operator of a designated facility, including:
              (1) Submittal of a final control plan for the designated facility to the appropriate air pollution control agency;
              (2) Awarding of contracts for emission control systems or for process modifications, or issuance of orders for the purchase of component parts to accomplish emission control or process modification;
              (3) Initiation of on-site construction or installation of emission control equipment or process change;
              (4) Completion of on-site construction or installation of emission control equipment or process change; and
              (5) Final compliance.
              (i) Region means an air quality control region designated under section 107 of the Act and described in part 81 of this chapter.
              (j) Local agency means any local governmental agency.
              [40 FR 53346, Nov. 17, 1975, as amended at 70 FR 28649, May 18, 2005; 77 FR 9447, Feb. 16, 2012]

              § 60.22
              Publication of guideline documents, emission guidelines, and final compliance times.

              (a) Concurrently upon or after proposal of standards of performance for the control of a designated pollutant from affected facilities, the Administrator will publish a draft guideline document containing information pertinent to control of the designated pollutant form designated facilities. Notice of the availability of the draft guideline document will be published in the Federal Register and public comments on its contents will be invited. After consideration of public comments and upon or after promulgation of standards of performance for control of a designated pollutant from affected facilities, a final guideline document will be published and notice of its availability will be published in the Federal Register.

              (b) Guideline documents published under this section will provide information for the development of State plans, such as:
              (1) Information concerning known or suspected endangerment of public health or welfare caused, or contributed to, by the designated pollutant.
              (2) A description of systems of emission reduction which, in the judgment of the Administrator, have been adequately demonstrated.
              (3) Information on the degree of emission reduction which is achievable with each system, together with information on the costs and environmental effects of applying each system to designated facilities.
              (4) Incremental periods of time normally expected to be necessary for the design, installation, and startup of identified control systems.
              (5) An emission guideline that reflects the application of the best system of emission reduction (considering the cost of such reduction) that has been adequately demonstrated for designated facilities, and the time within which compliance with emission standards of equivalent stringency can be achieved. The Administrator will specify different emission guidelines or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate. (6) Such other available information as the Administrator determines may contribute to the formulation of State plans.
              (c) Except as provided in paragraph (d)(1) of this section, the emission guidelines and compliance times referred to in paragraph (b)(5) of this section will be proposed for comment upon publication of the draft guideline document, and after consideration of comments will be promulgated in subpart C of this part with such modifications as may be appropriate.

              (d)(1) If the Administrator determines that a designated pollutant may cause or contribute to endangerment of public welfare, but that adverse effects on public health have not been demonstrated, he will include the determination in the draft guideline document and in the Federal Register notice of its availability. Except as provided in paragraph (d)(2) of this section, paragraph (c) of this section shall be inapplicable in such cases.

              (2) If the Administrator determines at any time on the basis of new information that a prior determination under paragraph (d)(1) of this section is incorrect or no longer correct, he will publish notice of the determination in the Federal Register, revise the guideline document as necessary under paragraph (a) of this section, and propose and promulgate emission guidelines and compliance times under paragraph (c) of this section.
              [40 FR 53346, Nov. 17, 1975, as amended at 54 FR 52189, Dec. 20, 1989]

              § 60.23
              Adoption and submittal of State plans; public hearings.
              (a)(1) Unless otherwise specified in the applicable subpart, within 9 months after notice of the availability of a final guideline document is published under § 60.22(a), each State shall adopt and submit to the Administrator, in accordance with § 60.4 of subpart A of this part, a plan for the control of the designated pollutant to which the guideline document applies.
              (2) Within nine months after notice of the availability of a final revised guideline document is published as provided in § 60.22(d)(2), each State shall adopt and submit to the Administrator any plan revision necessary to meet the requirements of this subpart.
              (b) If no designated facility is located within a State, the State shall submit a letter of certification to that effect to the Administrator within the time specified in paragraph (a) of this section. Such certification shall exempt the State from the requirements of this subpart for that designated pollutant.
              (c)(1) Except as provided in paragraphs (c)(2) and (c)(3) of this section, the State shall, prior to the adoption of any plan or revision thereof, conduct one or more public hearings within the State on such plan or plan revision.
              (2) No hearing shall be required for any change to an increment of progress in an approved compliance schedule unless the change is likely to cause the facility to be unable to comply with the final compliance date in the schedule.
              (3) No hearing shall be required on an emission standard in effect prior to the effective date of this subpart if it was adopted after a public hearing and is at least as stringent as the corresponding emission guideline specified in the applicable guideline document published under § 60.22(a).
              (d) Any hearing required by paragraph (c) of this section shall be held only after reasonable notice. Notice shall be given at least 30 days prior to the date of such hearing and shall include:
              (1) Notification to the public by prominently advertising the date, time, and place of such hearing in each region affected;
              (2) Availability, at the time of public announcement, of each proposed plan or revision thereof for public inspection in at least one location in each region to which it will apply;
              (3) Notification to the Administrator;
              (4) Notification to each local air pollution control agency in each region to which the plan or revision will apply; and
              (5) In the case of an interstate region, notification to any other State included in the region.
              (e) The State shall prepare and retain, for a minimum of 2 years, a record of each hearing for inspection by any interested party. The record shall contain, as a minimum, a list of witnesses together with the text of each presentation.
              (f) The State shall submit with the plan or revision:
              (1) Certification that each hearing required by paragraph (c) of this section was held in accordance with the notice required by paragraph (d) of this section; and
              (2) A list of witnesses and their organizational affiliations, if any, appearing at the hearing and a brief written summary of each presentation or written submission.

              (g) Upon written application by a State agency (through the appropriate Regional Office), the Administrator may approve State procedures designed to insure public participation in the matters for which hearings are required and public notification of the opportunity to participate if, in the judgment of the Administrator, the procedures, although different from the requirements of this subpart, in fact provide for adequate notice to and participation of the public. The Administrator may impose such conditions on his approval as he deems necessary. Procedures approved under this section shall be deemed to satisfy the requirements of this subpart regarding procedures for public hearings.
              [40 FR 53346, Nov. 17, 1975, as amended at 60 FR 65414, Dec. 19, 1995]

              § 60.24
              Emission standards and compliance schedules.
              (a) Each plan shall include emission standards and compliance schedules.
              (b) (1) Emission standards shall either be based on an allowance system or prescribe allowable rates of emissions except when it is clearly impracticable. Such cases will be identified in the guideline documents issued under § 60.22. Where emission standards prescribing equipment specifications are established, the plan shall, to the degree possible, set forth the emission reductions achievable by implementation of such specifications, and may permit compliance by the use of equipment determined by the State to be equivalent to that prescribed.
              (2) Test methods and procedures for determining compliance with the emission standards shall be specified in the plan. Methods other than those specified in appendix A to this part may be specified in the plan if shown to be equivalent or alternative methods as defined in § 60.2 (t) and (u).
              (3) Emission standards shall apply to all designated facilities within the State. A plan may contain emission standards adopted by local jurisdictions provided that the standards are enforceable by the State.
              (c) Except as provided in paragraph (f) of this section, where the Administrator has determined that a designated pollutant may cause or contribute to endangerment of public health, emission standards shall be no less stringent than the corresponding emission guideline(s) specified in subpart C of this part, and final compliance shall be required as expeditiously as practicable but no later than the compliance times specified in subpart C of this part.
              (d) Where the Administrator has determined that a designated pollutant may cause or contribute to endangerment of public welfare but that adverse effects on public health have not been demonstrated, States may balance the emission guidelines, compliance times, and other information provided in the applicable guideline document against other factors of public concern in establishing emission standards, compliance schedules, and variances. Appropriate consideration shall be given to the factors specified in § 60.22(b) and to information presented at the public hearing(s) conducted under § 60.23(c).
              (e)(1) Any compliance schedule extending more than 12 months from the date required for submittal of the plan must include legally enforceable increments of progress to achieve compliance for each designated facility or category of facilities. Unless otherwise specified in the applicable subpart, increments of progress must include, where practicable, each increment of progress specified in § 60.21(h) and must include such additional increments of progress as may be necessary to permit close and effective supervision of progress toward final compliance.
              (2) A plan may provide that compliance schedules for individual sources or categories of sources will be formulated after plan submittal. Any such schedule shall be the subject of a public hearing held according to § 60.23 and shall be submitted to the Administrator within 60 days after the date of adoption of the schedule but in no case later than the date prescribed for submittal of the first semiannual report required by § 60.25(e).
              (f) Unless otherwise specified in the applicable subpart on a case-by-case basis for particular designated facilities or classes of facilities, States may provide for the application of less stringent emissions standards or longer compliance schedules than those otherwise required by paragraph (c) of this section, provided that the State demonstrates with respect to each such facility (or class of facilities):
              (1) Unreasonable cost of control resulting from plant age, location, or basic process design;

              (2) Physical impossibility of installing necessary control equipment; or

              (3) Other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable.
              (g) Nothing in this subpart shall be construed to preclude any State or political subdivision thereof from adopting or enforcing (1) emission standards more stringent than emission guidelines specified in subpart C of this part or in applicable guideline documents or (2) compliance schedules requiring final compliance at earlier times than those specified in subpart C or in applicable guideline documents.
              [40 FR 53346, Nov. 17, 1975, as amended at 60 FR 65414, Dec. 19, 1995; 65 FR 76384, Dec. 6, 2000; 70 FR 28649, May 18, 2005; 71 FR 33398, June 9, 2006; 72 FR 59204, Oct. 19, 2007; 77 FR 9447, Feb. 16, 2012]

              § 60.25
              Emission inventories, source surveillance, reports.
              (a) Each plan shall include an inventory of all designated facilities, including emission data for the designated pollutants and information related to emissions as specified in appendix D to this part. Such data shall be summarized in the plan, and emission rates of designated pollutants from designated facilities shall be correlated with applicable emission standards. As used in this subpart, “correlated” means presented in such a manner as to show the relationship between measured or estimated amounts of emissions and the amounts of such emissions allowable under applicable emission standards.
              (b) Each plan shall provide for monitoring the status of compliance with applicable emission standards. Each plan shall, as a minimum, provide for:
              (1) Legally enforceable procedures for requiring owners or operators of designated facilities to maintain records and periodically report to the State information on the nature and amount of emissions from such facilities, and/or such other information as may be necessary to enable the State to determine whether such facilities are in compliance with applicable portions of the plan. Submission of electronic documents shall comply with the requirements of 40 CFR part 3—(Electronic reporting).
              (2) Periodic inspection and, when applicable, testing of designated facilities.
              (c) Each plan shall provide that information obtained by the State under paragraph (b) of this section shall be correlated with applicable emission standards (see § 60.25(a)) and made available to the general public.
              (d) The provisions referred to in paragraphs (b) and (c) of this section shall be specifically identified. Copies of such provisions shall be submitted with the plan unless:
              (1) They have been approved as portions of a preceding plan submitted under this subpart or as portions of an implementation plan submitted under section 110 of the Act, and
              (2) The State demonstrates:
              (i) That the provisions are applicable to the designated pollutant(s) for which the plan is submitted, and
              (ii) That the requirements of § 60.26 are met.
              (e) The State shall submit reports on progress in plan enforcement to the Administrator on an annual (calendar year) basis, commencing with the first full report period after approval of a plan or after promulgation of a plan by the Administrator. Information required under this paragraph must be included in the annual report required by § 51.321 of this chapter.
              (f) Each progress report shall include:
              (1) Enforcement actions initiated against designated facilities during the reporting period, under any emission standard or compliance schedule of the plan.
              (2) Identification of the achievement of any increment of progress required by the applicable plan during the reporting period.
              (3) Identification of designated facilities that have ceased operation during the reporting period.
              (4) Submission of emission inventory data as described in paragraph (a) of this section for designated facilities that were not in operation at the time of plan development but began operation during the reporting period.

              (5) Submission of additional data as necessary to update the information submitted under paragraph (a) of this section or in previous progress reports.

              (6) Submission of copies of technical reports on all performance testing on designated facilities conducted under paragraph (b)(2) of this section, complete with concurrently recorded process data.
              [40 FR 53346, Nov. 17, 1975, as amended at 44 FR 65071, Nov. 9, 1979; 70 FR 59887, Oct. 13, 2005]

              § 60.26
              Legal authority.
              (a) Each plan shall show that the State has legal authority to carry out the plan, including authority to:
              (1) Adopt emission standards and compliance schedules applicable to designated facilities.
              (2) Enforce applicable laws, regulations, standards, and compliance schedules, and seek injunctive relief.
              (3) Obtain information necessary to determine whether designated facilities are in compliance with applicable laws, regulations, standards, and compliance schedules, including authority to require recordkeeping and to make inspections and conduct tests of designated facilities.
              (4) Require owners or operators of designated facilities to install, maintain, and use emission monitoring devices and to make periodic reports to the State on the nature and amounts of emissions from such facilities; also authority for the State to make such data available to the public as reported and as correlated with applicable emission standards.
              (b) The provisions of law or regulations which the State determines provide the authorities required by this section shall be specifically identified. Copies of such laws or regulations shall be submitted with the plan unless:
              (1) They have been approved as portions of a preceding plan submitted under this subpart or as portions of an implementation plan submitted under section 110 of the Act, and
              (2) The State demonstrates that the laws or regulations are applicable to the designated pollutant(s) for which the plan is submitted.
              (c) The plan shall show that the legal authorities specified in this section are available to the State at the time of submission of the plan. Legal authority adequate to meet the requirements of paragraphs (a)(3) and (4) of this section may be delegated to the State under section 114 of the Act.
              (d) A State governmental agency other than the State air pollution control agency may be assigned responsibility for carrying out a portion of a plan if the plan demonstrates to the Administrator's satisfaction that the State governmental agency has the legal authority necessary to carry out that portion of the plan.
              (e) The State may authorize a local agency to carry out a plan, or portion thereof, within the local agency's jurisdiction if the plan demonstrates to the Administrator's satisfaction that the local agency has the legal authority necessary to implement the plan or portion thereof, and that the authorization does not relieve the State of responsibility under the Act for carrying out the plan or portion thereof.

              § 60.27
              Actions by the Administrator.
              (a) The Administrator may, whenever he determines necessary, extend the period for submission of any plan or plan revision or portion thereof.
              (b) After receipt of a plan or plan revision, the Administrator will propose the plan or revision for approval or disapproval. The Administrator will, within four months after the date required for submission of a plan or plan revision, approve or disapprove such plan or revision or each portion thereof.
              (c) The Administrator will, after consideration of any State hearing record, promptly prepare and publish proposed regulations setting forth a plan, or portion thereof, for a State if:
              (1) The State fails to submit a plan within the time prescribed;
              (2) The State fails to submit a plan revision required by § 60.23(a)(2) within the time prescribed; or
              (3) The Administrator disapproves the State plan or plan revision or any portion thereof, as unsatisfactory because the requirements of this subpart have not been met.

              (d) The Administrator will, within six months after the date required for submission of a plan or plan revision, promulgate the regulations proposed under paragraph (c) of this section with such modifications as may be appropriate unless, prior to such promulgation, the State has adopted and submitted a plan or plan revision which the Administrator determines to be approvable.
              (e)(1) Except as provided in paragraph (e)(2) of this section, regulations proposed and promulgated by the Administrator under this section will prescribe emission standards of the same stringency as the corresponding emission guideline(s) specified in the final guideline document published under § 60.22(a) and will require final compliance with such standards as expeditiously as practicable but no later than the times specified in the guideline document.
              (2) Upon application by the owner or operator of a designated facility to which regulations proposed and promulgated under this section will apply, the Administrator may provide for the application of less stringent emission standards or longer compliance schedules than those otherwise required by this section in accordance with the criteria specified in § 60.24(f).
              (f) Prior to promulgation of a plan under paragraph (d) of this section, the Administrator will provide the opportunity for at least one public hearing in either:
              (1) Each State that failed to hold a public hearing as required by § 60.23(c); or

              (2) Washington, DC or an alternate location specified in the Federal Register.

              [40 FR 53346, Nov. 17, 1975, as amended at 65 FR 76384, Dec. 6, 2000]

              § 60.28
              Plan revisions by the State.
              (a) Plan revisions which have the effect of delaying compliance with applicable emission standards or increments of progress or of establishing less stringent emission standards shall be submitted to the Administrator within 60 days after adoption in accordance with the procedures and requirements applicable to development and submission of the original plan.
              (b) More stringent emission standards, or orders which have the effect of accelerating compliance, may be submitted to the Administrator as plan revisions in accordance with the procedures and requirements applicable to development and submission of the original plan.
              (c) A revision of a plan, or any portion thereof, shall not be considered part of an applicable plan until approved by the Administrator in accordance with this subpart.

              § 60.29
              Plan revisions by the Administrator.
              After notice and opportunity for public hearing in each affected State, the Administrator may revise any provision of an applicable plan if:
              (a) The provision was promulgated by the Administrator, and
              (b) The plan, as revised, will be consistent with the Act and with the requirements of this subpart.

            Subpart Ba—Adoption and Submittal of State Plans for Designated Facilities

              Source:
              84 FR 32575, July 8, 2019, unless otherwise noted.

              § 60.20a
              Applicability.
              (a) The provisions of this subpart apply upon publication of a final emission guideline under § 60.22a(a) if implementation of such final guideline is ongoing as of f or if the final guideline is published after July 8, 2019.
              (1) Each emission guideline promulgated under this part is subject to the requirements of this subpart, except that each emission guideline may include specific provisions in addition to or that supersede requirements of this subpart. Each emission guideline must identify explicitly any provision of this subpart that is superseded.
              (2) Terms used throughout this part are defined in § 60.21a or in the Clean Air Act (Act) as amended in 1990, except that emission guidelines promulgated as individual subparts of this part may include specific definitions in addition to or that supersede definitions in § 60.21a.

              (b) No standard of performance or other requirement established under this part shall be interpreted, construed, or applied to diminish or replace the requirements of a more stringent emission limitation or other applicable requirement established by the Administrator pursuant to other authority of the Act (section 112, Part C or D, or any other authority of this Act), or a standard issued under State authority.

              § 60.21a
              Definitions.
              Terms used but not defined in this subpart shall have the meaning given them in the Act and in subpart A of this part:
              (a) Designated pollutant means any air pollutant, the emissions of which are subject to a standard of performance for new stationary sources, but for which air quality criteria have not been issued and that is not included on a list published under section 108(a) or section 112(b)(1)(A) of the Act.
              (b) Designated facility means any existing facility (see § 60.2) which emits a designated pollutant and which would be subject to a standard of performance for that pollutant if the existing facility were an affected facility (see § 60.2).
              (c) Plan means a plan under section 111(d) of the Act which establishes standards of performance for designated pollutants from designated facilities and provides for the implementation and enforcement of such standards of performance.
              (d) Applicable plan means the plan, or most recent revision thereof, which has been approved under § 60.27a(b) or promulgated under § 60.27a(d).
              (e) Emission guideline means a guideline set forth in subpart C of this part, or in a final guideline document published under § 60.22a(a), which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator has determined has been adequately demonstrated for designated facilities.
              (f) Standard of performance means a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated, including, but not limited to a legally enforceable regulation setting forth an allowable rate or limit of emissions into the atmosphere, or prescribing a design, equipment, work practice, or operational standard, or combination thereof.
              (g) Compliance schedule means a legally enforceable schedule specifying a date or dates by which a source or category of sources must comply with specific standards of performance contained in a plan or with any increments of progress to achieve such compliance.
              (h) Increments of progress means steps to achieve compliance which must be taken by an owner or operator of a designated facility, including:
              (1) Submittal of a final control plan for the designated facility to the appropriate air pollution control agency;
              (2) Awarding of contracts for emission control systems or for process modifications, or issuance of orders for the purchase of component parts to accomplish emission control or process modification;
              (3) Initiation of on-site construction or installation of emission control equipment or process change;
              (4) Completion of on-site construction or installation of emission control equipment or process change; and
              (5) Final compliance.
              (i) Region means an air quality control region designated under section 107 of the Act and described in part 81 of this chapter.
              (j) Local agency means any local governmental agency.

              § 60.22a
              Publication of emission guidelines.

              (a) Concurrently upon or after proposal of standards of performance for the control of a designated pollutant from affected facilities, the Administrator will publish a draft emission guideline containing information pertinent to control of the designated pollutant from designated facilities. Notice of the availability of the draft emission guideline will be published in the Federal Register and public comments on its contents will be invited. After consideration of public comments and upon or after promulgation of standards of performance for control of a designated pollutant from affected facilities, a final emission guideline will be published and notice of its availability will be published in the Federal Register.
              (b) Emission guidelines published under this section will provide information for the development of State plans, such as:
              (1) Information concerning known or suspected endangerment of public health or welfare caused, or contributed to, by the designated pollutant.
              (2) A description of systems of emission reduction which, in the judgment of the Administrator, have been adequately demonstrated.
              (3) Information on the degree of emission limitation which is achievable with each system, together with information on the costs, nonair quality health environmental effects, and energy requirements of applying each system to designated facilities.
              (4) Incremental periods of time normally expected to be necessary for the design, installation, and startup of identified control systems.
              (5) The degree of emission limitation achievable through the application of the best system of emission reduction (considering the cost of such achieving reduction and any nonair quality health and environmental impact and energy requirements) that has been adequately demonstrated for designated facilities, and the time within which compliance with standards of performance can be achieved. The Administrator may specify different degrees of emission limitation or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate.
              (6) Such other available information as the Administrator determines may contribute to the formulation of State plans.
              (c) The emission guidelines and compliance times referred to in paragraph (b)(5) of this section will be proposed for comment upon publication of the draft guideline document, and after consideration of comments will be promulgated in subpart C of this part with such modifications as may be appropriate.

              § 60.23a
              Adoption and submittal of State plans; public hearings.
              (a)(1) Unless otherwise specified in the applicable subpart, within three years after notice of the availability of a final emission guideline is published under § 60.22a(a), each State shall adopt and submit to the Administrator, in accordance with § 60.4, a plan for the control of the designated pollutant to which the emission guideline applies.
              (2) At any time, each State may adopt and submit to the Administrator any plan revision necessary to meet the requirements of this subpart or an applicable subpart of this part.
              (b) If no designated facility is located within a State, the State shall submit a letter of certification to that effect to the Administrator within the time specified in paragraph (a) of this section. Such certification shall exempt the State from the requirements of this subpart for that designated pollutant.
              (c) The State shall, prior to the adoption of any plan or revision thereof, conduct one or more public hearings within the State on such plan or plan revision in accordance with the provisions under this section.
              (d) Any hearing required by paragraph (c) of this section shall be held only after reasonable notice. Notice shall be given at least 30 days prior to the date of such hearing and shall include:
              (1) Notification to the public by prominently advertising the date, time, and place of such hearing in each region affected. This requirement may be satisfied by advertisement on the internet;
              (2) Availability, at the time of public announcement, of each proposed plan or revision thereof for public inspection in at least one location in each region to which it will apply. This requirement may be satisfied by posting each proposed plan or revision on the internet;
              (3) Notification to the Administrator;

              (4) Notification to each local air pollution control agency in each region to which the plan or revision will apply; and
              (5) In the case of an interstate region, notification to any other State included in the region.
              (e) The State may cancel the public hearing through a method it identifies if no request for a public hearing is received during the 30 day notification period under paragraph (d) of this section and the original notice announcing the 30 day notification period states that if no request for a public hearing is received the hearing will be cancelled; identifies the method and time for announcing that the hearing has been cancelled; and provides a contact phone number for the public to call to find out if the hearing has been cancelled.
              (f) The State shall prepare and retain, for a minimum of 2 years, a record of each hearing for inspection by any interested party. The record shall contain, as a minimum, a list of witnesses together with the text of each presentation.
              (g) The State shall submit with the plan or revision:
              (1) Certification that each hearing required by paragraph (c) of this section was held in accordance with the notice required by paragraph (d) of this section; and
              (2) A list of witnesses and their organizational affiliations, if any, appearing at the hearing and a brief written summary of each presentation or written submission.
              (h) Upon written application by a State agency (through the appropriate Regional Office), the Administrator may approve State procedures designed to insure public participation in the matters for which hearings are required and public notification of the opportunity to participate if, in the judgment of the Administrator, the procedures, although different from the requirements of this subpart, in fact provide for adequate notice to and participation of the public. The Administrator may impose such conditions on his approval as he deems necessary. Procedures approved under this section shall be deemed to satisfy the requirements of this subpart regarding procedures for public hearings.

              § 60.24a
              Standards of performance and compliance schedules.
              (a) Each plan shall include standards of performance and compliance schedules.
              (b) Standards of performance shall either be based on allowable rate or limit of emissions, except when it is not feasible to prescribe or enforce a standard of performance. The EPA shall identify such cases in the emission guidelines issued under § 60.22a. Where standards of performance prescribing design, equipment, work practice, or operational standard, or combination thereof are established, the plan shall, to the degree possible, set forth the emission reductions achievable by implementation of such standards, and may permit compliance by the use of equipment determined by the State to be equivalent to that prescribed.
              (1) Test methods and procedures for determining compliance with the standards of performance shall be specified in the plan. Methods other than those specified in appendix A to this part or an applicable subpart of this part may be specified in the plan if shown to be equivalent or alternative methods as defined in § 60.2.
              (2) Standards of performance shall apply to all designated facilities within the State. A plan may contain standards of performance adopted by local jurisdictions provided that the standards are enforceable by the State.
              (c) Except as provided in paragraph (e) of this section, standards of performance shall be no less stringent than the corresponding emission guideline(s) specified in subpart C of this part, and final compliance shall be required as expeditiously as practicable, but no later than the compliance times specified in an applicable subpart of this part.

              (d) Any compliance schedule extending more than 24 months from the date required for submittal of the plan must include legally enforceable increments of progress to achieve compliance for each designated facility or category of facilities. Unless otherwise specified in the applicable subpart, increments of progress must include, where practicable, each increment of progress specified in § 60.21a(h) and must include such additional increments of progress as may be necessary to permit close and effective supervision of progress toward final compliance.
              (e) In applying a standard of performance to a particular source, the State may take into consideration factors, such as the remaining useful life of such source, provided that the State demonstrates with respect to each such facility (or class of such facilities):
              (1) Unreasonable cost of control resulting from plant age, location, or basic process design;
              (2) Physical impossibility of installing necessary control equipment; or
              (3) Other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable.
              (f) Nothing in this subpart shall be construed to preclude any State or political subdivision thereof from adopting or enforcing:
              (1) Standards of performance more stringent than emission guidelines specified in subpart C of this part or in applicable emission guidelines; or
              (2) Compliance schedules requiring final compliance at earlier times than those specified in subpart C of this part or in applicable emission guidelines.

              § 60.25a
              Emission inventories, source surveillance, reports.
              (a) Each plan shall include an inventory of all designated facilities, including emission data for the designated pollutants and information related to emissions as specified in appendix D to this part. Such data shall be summarized in the plan, and emission rates of designated pollutants from designated facilities shall be correlated with applicable standards of performance. As used in this subpart, “correlated” means presented in such a manner as to show the relationship between measured or estimated amounts of emissions and the amounts of such emissions allowable under applicable standards of performance.
              (b) Each plan shall provide for monitoring the status of compliance with applicable standards of performance. Each plan shall, as a minimum, provide for:
              (1) Legally enforceable procedures for requiring owners or operators of designated facilities to maintain records and periodically report to the State information on the nature and amount of emissions from such facilities, and/or such other information as may be necessary to enable the State to determine whether such facilities are in compliance with applicable portions of the plan. Submission of electronic documents shall comply with the requirements of 40 CFR part 3 (Electronic reporting).
              (2) Periodic inspection and, when applicable, testing of designated facilities.
              (c) Each plan shall provide that information obtained by the State under paragraph (b) of this section shall be correlated with applicable standards of performance (see § 60.25a(a)) and made available to the general public.
              (d) The provisions referred to in paragraphs (b) and (c) of this section shall be specifically identified. Copies of such provisions shall be submitted with the plan unless:
              (1) They have been approved as portions of a preceding plan submitted under this subpart or as portions of an implementation plan submitted under section 110 of the Act; and
              (2) The State demonstrates:
              (i) That the provisions are applicable to the designated pollutant(s) for which the plan is submitted, and
              (ii) That the requirements of § 60.26a are met.
              (e) The State shall submit reports on progress in plan enforcement to the Administrator on an annual (calendar year) basis, commencing with the first full report period after approval of a plan or after promulgation of a plan by the Administrator. Information required under this paragraph must be included in the annual report required by § 51.321 of this chapter.
              (f) Each progress report shall include:
              (1) Enforcement actions initiated against designated facilities during the reporting period, under any standard of performance or compliance schedule of the plan.

              (2) Identification of the achievement of any increment of progress required by the applicable plan during the reporting period.

              (3) Identification of designated facilities that have ceased operation during the reporting period.
              (4) Submission of emission inventory data as described in paragraph (a) of this section for designated facilities that were not in operation at the time of plan development but began operation during the reporting period.
              (5) Submission of additional data as necessary to update the information submitted under paragraph (a) of this section or in previous progress reports.
              (6) Submission of copies of technical reports on all performance testing on designated facilities conducted under paragraph (b)(2) of this section, complete with concurrently recorded process data.

              § 60.26a
              Legal authority.
              (a) Each plan or plan revision shall show that the State has legal authority to carry out the plan or plan revision, including authority to:
              (1) Adopt standards of performance and compliance schedules applicable to designated facilities.
              (2) Enforce applicable laws, regulations, standards, and compliance schedules, and seek injunctive relief.
              (3) Obtain information necessary to determine whether designated facilities are in compliance with applicable laws, regulations, standards, and compliance schedules, including authority to require recordkeeping and to make inspections and conduct tests of designated facilities.
              (4) Require owners or operators of designated facilities to install, maintain, and use emission monitoring devices and to make periodic reports to the State on the nature and amounts of emissions from such facilities; also authority for the State to make such data available to the public as reported and as correlated with applicable standards of performance.
              (b) The provisions of law or regulations which the State determines provide the authorities required by this section shall be specifically identified. Copies of such laws or regulations shall be submitted with the plan unless:
              (1) They have been approved as portions of a preceding plan submitted under this subpart or as portions of an implementation plan submitted under section 110 of the Act; and
              (2) The State demonstrates that the laws or regulations are applicable to the designated pollutant(s) for which the plan is submitted.
              (c) The plan shall show that the legal authorities specified in this section are available to the State at the time of submission of the plan. Legal authority adequate to meet the requirements of paragraphs (a)(3) and (4) of this section may be delegated to the State under section 114 of the Act.
              (d) A State governmental agency other than the State air pollution control agency may be assigned responsibility for carrying out a portion of a plan if the plan demonstrates to the Administrator's satisfaction that the State governmental agency has the legal authority necessary to carry out that portion of the plan.
              (e) The State may authorize a local agency to carry out a plan, or portion thereof, within the local agency's jurisdiction if the plan demonstrates to the Administrator's satisfaction that the local agency has the legal authority necessary to implement the plan or portion thereof, and that the authorization does not relieve the State of responsibility under the Act for carrying out the plan or portion thereof.

              § 60.27a
              Actions by the Administrator.
              (a) The Administrator may, whenever he determines necessary, shorten the period for submission of any plan or plan revision or portion thereof.
              (b) After determination that a plan or plan revision is complete per the requirements of § 60.27a(g), the Administrator will take action on the plan or revision. The Administrator will, within twelve months of finding that a plan or plan revision is complete, approve or disapprove such plan or revision or each portion thereof.
              (c) The Administrator will promulgate, through notice-and-comment rulemaking, a federal plan, or portion thereof, at any time within two years after the Administrator:

              (1) Finds that a State fails to submit a required plan or plan revision or finds that the plan or plan revision does not satisfy the minimum criteria under paragraph (g) of this section; or

              (2) Disapproves the required State plan or plan revision or any portion thereof, as unsatisfactory because the applicable requirements of this subpart or an applicable subpart under this part have not been met.
              (d) The Administrator will promulgate a final federal plan as described in paragraph (c) of this section unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administrator promulgates such federal plan.
              (e)(1) Except as provided in paragraph (e)(2) of this section, a federal plan promulgated by the Administrator under this section will prescribe standards of performance of the same stringency as the corresponding emission guideline(s) specified in the final emission guideline published under § 60.22a(a) and will require compliance with such standards as expeditiously as practicable but no later than the times specified in the emission guideline.
              (2) Upon application by the owner or operator of a designated facility to which regulations proposed and promulgated under this section will apply, the Administrator may provide for the application of less stringent standards of performance or longer compliance schedules than those otherwise required by this section in accordance with the criteria specified in § 60.24a(e).
              (f) Prior to promulgation of a federal plan under paragraph (d) of this section, the Administrator will provide the opportunity for at least one public hearing in either:
              (1) Each State that failed to submit a required complete plan or plan revision, or whose required plan or plan revision is disapproved by the Administrator; or

              (2) Washington, DC or an alternate location specified in the Federal Register.
              (g) Each plan or plan revision that is submitted to the Administrator shall be reviewed for completeness as described in paragraphs (g)(1) through (3) of this section.
              (1) General. Within 60 days of the Administrator's receipt of a state submission, but no later than 6 months after the date, if any, by which a State is required to submit the plan or revision, the Administrator shall determine whether the minimum criteria for completeness have been met. Any plan or plan revision that a State submits to the EPA, and that has not been determined by the EPA by the date 6 months after receipt of the submission to have failed to meet the minimum criteria, shall on that date be deemed by operation of law to meet such minimum criteria. Where the Administrator determines that a plan submission does not meet the minimum criteria of this paragraph, the State will be treated as not having made the submission and the requirements of § 60.27a regarding promulgation of a federal plan shall apply.
              (2) Administrative criteria. In order to be deemed complete, a State plan must contain each of the following administrative criteria:
              (i) A formal letter of submittal from the Governor or her designee requesting EPA approval of the plan or revision thereof;
              (ii) Evidence that the State has adopted the plan in the state code or body of regulations; or issued the permit, order, consent agreement (hereafter “document”) in final form. That evidence must include the date of adoption or final issuance as well as the effective date of the plan, if different from the adoption/issuance date;
              (iii) Evidence that the State has the necessary legal authority under state law to adopt and implement the plan;

              (iv) A copy of the actual regulation, or document submitted for approval and incorporation by reference into the plan, including indication of the changes made (such as redline/strikethrough) to the existing approved plan, where applicable. The submittal must be a copy of the official state regulation or document signed, stamped and dated by the appropriate state official indicating that it is fully enforceable by the State. The effective date of the regulation or document must, whenever possible, be indicated in the document itself. The State's electronic copy must be an exact duplicate of the hard copy. If the regulation/document provided by the State for approval and incorporation by reference into the plan is a copy of an existing publication, the State submission should, whenever possible, include a copy of the publication cover page and table of contents;
              (v) Evidence that the State followed all of the procedural requirements of the state's laws and constitution in conducting and completing the adoption and issuance of the plan;
              (vi) Evidence that public notice was given of the proposed change with procedures consistent with the requirements of § 60.23a, including the date of publication of such notice;
              (vii) Certification that public hearing(s) were held in accordance with the information provided in the public notice and the State's laws and constitution, if applicable and consistent with the public hearing requirements in § 60.23a;
              (viii) Compilation of public comments and the State's response thereto; and
              (ix) Such other criteria for completeness as may be specified by the Administrator under the applicable emission guidelines.
              (3) Technical criteria. In order to be deemed complete, a State plan must contain each of the following technical criteria:
              (i) Description of the plan approach and geographic scope;
              (ii) Identification of each designated facility, identification of standards of performance for the designated facilities, and monitoring, recordkeeping and reporting requirements that will determine compliance by each designated facility;
              (iii) Identification of compliance schedules and/or increments of progress;
              (iv) Demonstration that the State plan submittal is projected to achieve emissions performance under the applicable emission guidelines;
              (v) Documentation of state recordkeeping and reporting requirements to determine the performance of the plan as a whole; and
              (vi) Demonstration that each emission standard is quantifiable, non-duplicative, permanent, verifiable, and enforceable.

              § 60.28a
              Plan revisions by the State.
              (a) Any revision to a state plan shall be adopted by such State after reasonable notice and public hearing. For plan revisions required in response to a revised emission guideline, such plan revisions shall be submitted to the Administrator within three years, or shorter if required by the Administrator, after notice of the availability of a final revised emission guideline is published under § 60.22a. All plan revisions must be submitted in accordance with the procedures and requirements applicable to development and submission of the original plan.
              (b) A revision of a plan, or any portion thereof, shall not be considered part of an applicable plan until approved by the Administrator in accordance with this subpart.

              § 60.29a
              Plan revisions by the Administrator.
              After notice and opportunity for public hearing in each affected State, the Administrator may revise any provision of an applicable federal plan if:
              (a) The provision was promulgated by the Administrator; and
              (b) The plan, as revised, will be consistent with the Act and with the requirements of this subpart.

            Subpart C—Emission Guidelines and Compliance Times

              § 60.30
              Scope.
              The following subparts contain emission guidelines and compliance times for the control of certain designated pollutants in accordance with section 111(d) and section 129 of the Clean Air Act and subpart B of this part.
              (a) Subpart Ca [Reserved]
              (b) Subpart Cb—Municipal Waste Combustors.
              (c) Subpart Cc—Municipal Solid Waste Landfills.
              (d) Subpart Cd—Sulfuric Acid Production Plants.
              (e) Subpart Ce—Hospital/Medical/Infectious Waste Incinerators.
              [62 FR 48379, Sept. 15, 1997]

              § 60.31
              Definitions.
              Terms used but not defined in this subpart have the meaning given them in the Act and in subparts A and B of this part.
              [42 FR 55797, Oct. 18, 1977]

            Subpart Ca [Reserved]

            Subpart Cb—Emissions Guidelines and Compliance Times for Large Municipal Waste Combustors That are Constructed on or Before September 20, 1994

              Source:
              60 FR 65415, Dec. 19, 1995, unless otherwise noted.

              § 60.30b
              Scope and delegation of authority.
              (a) This subpart contains emission guidelines and compliance schedules for the control of certain designated pollutants from certain municipal waste combustors in accordance with section 111(d) and section 129 of the Clean Air Act and subpart B of this part. The provisions in these emission guidelines apply instead of the provisions of § 60.24(f) of subpart B of this part.
              (b) The following authorities are retained by EPA:
              (1) Approval of exemption claims in § 60.32b(b)(1), (d), (e), (f)(1), (i)(1);
              (2) Approval of a nitrogen oxides trading program under § 60.33b(d)(2);
              (3) Approval of major alternatives to test methods;
              (4) Approval of major alternatives to monitoring;
              (5) Waiver of recordkeeping; and
              (6) Performance test and data reduction waivers under § 608(b).
              [71 FR 27332, May 10, 2006]

              § 60.31b
              Definitions.
              Terms used but not defined in this subpart have the meaning given them in the Clean Air Act and subparts A, B, and Eb of this part.

                EPA means the Administrator of the U.S. EPA or employee of the U.S. EPA who is delegated to perform the specified task.

                Municipal waste combustor plant means one or more designated facilities (as defined in § 60.32b) at the same location.

                Semi-suspension refuse-derived fuel-fired combustor/wet refuse-derived fuel process conversion means a combustion unit that was converted from a wet refuse-derived fuel process to a dry refuse-derived fuel process, and because of constraints in the design of the system, includes a low furnace height (less than 60 feet between the grate and the roof) and a high waste capacity-to-undergrate air zone ratio (greater than 300 tons of waste per day (tpd) fuel per each undergrate air zone).

                Spreader stoker fixed floor refuse-derived fuel-fired combustor/100 percent coal capable means a spreader stoker type combustor with a fixed floor grate design that typically fires 100 percent refuse-derived fuel but is equipped to burn 100 percent coal instead of refuse-derived fuel to fulfill 100 percent steam or energy demand.
              [60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45119, 45125, Aug. 25, 1997; 71 FR 27332, May 10, 2006]

              § 60.32b
              Designated facilities.
              (a) The designated facility to which these guidelines apply is each municipal waste combustor unit with a combustion capacity greater than 250 tons per day of municipal solid waste for which construction was commenced on or before September 20, 1994.
              (b) Any municipal waste combustion unit that is capable of combusting more than 250 tons per day of municipal solid waste and is subject to a federally enforceable permit limiting the maximum amount of municipal solid waste that may be combusted in the unit to less than or equal to 11 tons per day is not subject to this subpart if the owner or operator:
              (1) Notifies EPA of an exemption claim,
              (2) Provides a copy of the federally enforceable permit that limits the firing of municipal solid waste to less than 11 tons per day, and
              (3) Keeps records of the amount of municipal solid waste fired on a daily basis.
              (c) Physical or operational changes made to an existing municipal waste combustor unit primarily for the purpose of complying with emission guidelines under this subpart are not considered in determining whether the unit is a modified or reconstructed facility under subpart Ea or subpart Eb of this part.

              (d) A qualifying small power production facility, as defined in section 3(17)(C) of the Federal Power Act (16 U.S.C. 796(17)(C)), that burns homogeneous waste (such as automotive tires or used oil, but not including refuse-derived fuel) for the production of electric energy is not subject to this subpart if the owner or operator of the facility notifies EPA of this exemption and provides data documenting that the facility qualifies for this exemption.
              (e) A qualifying cogeneration facility, as defined in section 3(18)(B) of the Federal Power Act (16 U.S.C. 796(18)(B)), that burns homogeneous waste (such as automotive tires or used oil, but not including refuse-derived fuel) for the production of electric energy and steam or forms of useful energy (such as heat) that are used for industrial, commercial, heating, or cooling purposes, is not subject to this subpart if the owner or operator of the facility notifies EPA of this exemption and provides data documenting that the facility qualifies for this exemption.
              (f) Any unit combusting a single-item waste stream of tires is not subject to this subpart if the owner or operator of the unit:
              (1) Notifies EPA of an exemption claim, and
              (2) Provides data documenting that the unit qualifies for this exemption.
              (g) Any unit required to have a permit under section 3005 of the Solid Waste Disposal Act is not subject to this subpart.
              (h) Any materials recovery facility (including primary or secondary smelters) that combusts waste for the primary purpose of recovering metals is not subject to this subpart.
              (i) Any cofired combustor, as defined under § 60.51b of subpart Eb of this part, that meets the capacity specifications in paragraph (a) of this section is not subject to this subpart if the owner or operator of the cofired combustor:
              (1) Notifies EPA of an exemption claim,
              (2) Provides a copy of the federally enforceable permit (specified in the definition of cofired combustor in this section), and
              (3) Keeps a record on a calendar quarter basis of the weight of municipal solid waste combusted at the cofired combustor and the weight of all other fuels combusted at the cofired combustor.
              (j) Air curtain incinerators, as defined under § 60.51b of subpart Eb of this part, that meet the capacity specifications in paragraph (a) of this section, and that combust a fuel stream composed of 100 percent yard waste are exempt from all provisions of this subpart except the opacity standard under § 60.37b, the testing procedures under § 60.38b, and the reporting and recordkeeping provisions under § 60.39b.
              (k) Air curtain incinerators that meet the capacity specifications in paragraph (a) of this section and that combust municipal solid waste other than yard waste are subject to all provisions of this subpart.
              (l) Pyrolysis/combustion units that are an integrated part of a plastics/rubber recycling unit (as defined in § 60.51b) are not subject to this subpart if the owner or operator of the plastics/rubber recycling unit keeps records of the weight of plastics, rubber, and/or rubber tires processed on a calendar quarter basis; the weight of chemical plant feedstocks and petroleum refinery feedstocks produced and marketed on a calendar quarter basis; and the name and address of the purchaser of the feedstocks. The combustion of gasoline, diesel fuel, jet fuel, fuel oils, residual oil, refinery gas, petroleum coke, liquified petroleum gas, propane, or butane produced by chemical plants or petroleum refineries that use feedstocks produced by plastics/rubber recycling units are not subject to this subpart.
              (m) Cement kilns firing municipal solid waste are not subject to this subpart.
              (n) Any affected facility meeting the applicability requirements under this section is not subject to subpart E of this part.
              [60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45119, 45125, Aug. 25, 1997; 71 FR 27332, May 10, 2006]

              § 60.33b
              Emission guidelines for municipal waste combustor metals, acid gases, organics, and nitrogen oxides.

              (a) The emission limits for municipal waste combustor metals are specified in paragraphs (a)(1) through (a)(3) of this section.
              (1) For approval, a State plan shall include emission limits for particulate matter and opacity at least as protective as the emission limits for particulate matter and opacity specified in paragraphs (a)(1)(i) through (a)(1)(iii) of this section.
              (i) Before April 28, 2009, the emission limit for particulate matter contained in the gases discharged to the atmosphere from a designated facility is 27 milligrams per dry standard cubic meter, corrected to 7 percent oxygen. On and after April 28, 2009, the emission limit for particulate matter contained in the gases discharged to the atmosphere from a designated facility is 25 milligrams per dry standard cubic meter, corrected to 7 percent oxygen.
              (ii) [Reserved]
              (iii) The emission limit for opacity exhibited by the gases discharged to the atmosphere from a designated facility is 10 percent (6-minute average).
              (2) For approval, a State plan shall include emission limits for cadmium at least as protective as the emission limits for cadmium specified in paragraphs (a)(2)(i) through (a)(2)(iv) of this section.
              (i) Before April 28, 2009, the emission limit for cadmium contained in the gases discharged to the atmosphere from a designated facility is 40 micrograms per dry standard cubic meter, corrected to 7 percent oxygen. On and after April 28, 2009, the emission limit for cadmium contained in the gases discharged to the atmosphere from a designated facility is 35 micrograms per dry standard cubic meter, corrected to 7 percent oxygen.
              (ii) [Reserved]
              (3) For approval, a State plan shall include emission limits for mercury at least as protective as the emission limits specified in this paragraph. Before April 28, 2009, the emission limit for mercury contained in the gases discharged to the atmosphere from a designated facility is 80 micrograms per dry standard cubic meter or 15 percent of the potential mercury emission concentration (85-percent reduction by weight), corrected to 7 percent oxygen, whichever is less stringent. On and after April 28, 2009, the emission limit for mercury contained in the gases discharged to the atmosphere from a designated facility is 50 micrograms per dry standard cubic meter or 15 percent of the potential mercury emission concentration (85-percent reduction by weight), corrected to 7 percent oxygen, whichever is less stringent.
              (4) For approval, a State plan shall include an emission limit for lead at least as protective as the emission limit for lead specified in this paragraph. Before April 28, 2009, the emission limit for lead contained in the gases discharged to the atmosphere from a designated facility is 440 micrograms per dry standard cubic meter, corrected to 7 percent oxygen. On and after April 28, 2009, the emission limit for lead contained in the gases discharged to the atmosphere from a designated facility is 400 micrograms per dry standard cubic meter, corrected to 7 percent oxygen.
              (b) The emission limits for municipal waste combustor acid gases, expressed as sulfur dioxide and hydrogen chloride, are specified in paragraphs (b)(1) and (b)(2) of this section.
              (1) For approval, a State plan shall include emission limits for sulfur dioxide at least as protective as the emission limits for sulfur dioxide specified in paragraphs (b)(1)(i) and (b)(1)(ii) of this section.
              (i) The emission limit for sulfur dioxide contained in the gases discharged to the atmosphere from a designated facility is 31 parts per million by volume or 25 percent of the potential sulfur dioxide emission concentration (75-percent reduction by weight or volume), corrected to 7 percent oxygen (dry basis), whichever is less stringent. Compliance with this emission limit is based on a 24-hour daily geometric mean.
              (ii) [Reserved]
              (2) For approval, a State plan shall include emission limits for hydrogen chloride at least as protective as the emission limits for hydrogen chloride specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section.

              (i) The emission limit for hydrogen chloride contained in the gases discharged to the atmosphere from a designated facility is 31 parts per million by volume or 5 percent of the potential hydrogen chloride emission concentration (95-percent reduction by weight or volume), corrected to 7 percent oxygen (dry basis), whichever is less stringent.
              (ii) [Reserved]
              (3) For approval, a State plan shall be submitted by August 25, 1998 and shall include emission limits for sulfur dioxide and hydrogen chloride at least as protective as the emission limits specified in paragraphs (b)(3)(i) and (b)(3)(ii) of this section.
              (i) The emission limit for sulfur dioxide contained in the gases discharged to the atmosphere from a designated facility is 29 parts per million by volume or 25 percent of the potential sulfur dioxide emission concentration (75-percent reduction by weight or volume), corrected to 7 percent oxygen (dry basis), whichever is less stringent. Compliance with this emission limit is based on a 24-hour daily geometric mean.
              (ii) The emission limit for hydrogen chloride contained in the gases discharged to the atmosphere from a designated facility is 29 parts per million by volume or 5 percent of the potential hydrogen chloride emission concentration (95-percent reduction by weight or volume), corrected to 7 percent oxygen (dry basis), whichever is less stringent.
              (c) The emission limits for municipal waste combustor organics, expressed as total mass dioxin/furan, are specified in paragraphs (c)(1) and (c)(2) of this section.
              (1) For approval, a State plan shall include an emission limit for dioxin/furan contained in the gases discharged to the atmosphere from a designated facility at least as protective as the emission limit for dioxin/furan specified in paragraphs (c)(1)(i), (c)(1)(ii), and (c)(1)(iii) of this section, as applicable.
              (i) Before April 28, 2009, the emission limit for designated facilities that employ an electrostatic precipitator-based emission control system is 60 nanograms per dry standard cubic meter (total mass), corrected to 7 percent oxygen.
              (ii) On and after April 28, 2009, the emission limit for designated facilities that employ an electrostatic precipitator-based emission control system is 35 nanograms per dry standard cubic meter (total mass), corrected to 7 percent oxygen.
              (iii) The emission limit for designated facilities that do not employ an electrostatic precipitator-based emission control system is 30 nanograms per dry standard cubic meter (total mass), corrected to 7 percent oxygen.
              (d) For approval, a State plan shall include emission limits for nitrogen oxides at least as protective as the emission limits listed in table 1 of this subpart for designated facilities. table 1 provides emission limits for the nitrogen oxides concentration level for each type of designated facility.
              (1) A State plan may allow nitrogen oxides emissions averaging as specified in paragraphs (d)(1)(i) through (d)(1)(v) of this section.
              (i) The owner or operator of a municipal waste combustor plant may elect to implement a nitrogen oxides emissions averaging plan for the designated facilities that are located at that plant and that are subject to subpart Cb, except as specified in paragraphs (d)(1)(i)(A) and (d)(1)(i)(B) of this section.
              (A) Municipal waste combustor units subject to subpart Ea or Eb cannot be included in the emissions averaging plan.
              (B) Mass burn refractory municipal waste combustor units and other municipal waste combustor technologies not listed in paragraph (d)(1)(iii) of this section may not be included in the emissions averaging plan.
              (ii) The designated facilities included in the nitrogen oxides emissions averaging plan must be identified in the initial compliance report specified in § 60.59b(f) or in the annual report specified in § 60.59b(g), as applicable, prior to implementing the averaging plan. The designated facilities being included in the averaging plan may be redesignated each calendar year. Partial year redesignation is allowable with State approval.

              (iii) To implement the emissions averaging plan, the average daily (24-hour) nitrogen oxides emission concentration level for gases discharged from the designated facilities being included in the emissions averaging plan must be no greater than the levels specified in table 2 of this subpart. table 2 provides emission limits for the nitrogen oxides concentration level for each type of designated facility.
              (iv) Under the emissions averaging plan, the average daily nitrogen oxides emissions specified in paragraph (d)(1)(iii) of this section shall be calculated using equation (1). Designated facilities that are offline shall not be included in calculating the average daily nitrogen oxides emission level.

                ER19de95.000

                where:

                NOX 24-hr = 24-hr daily average nitrogen oxides emission concentration level for the emissions averaging plan (parts per million by volume corrected to 7 percent oxygen).
                NOX i-hr = 24-hr daily average nitrogen oxides emission concentration level for designated facility i (parts per million by volume, corrected to 7 percent oxygen), calculated according to the procedures in § 60.58b(h) of this subpart.
                Si = maximum demonstrated municipal waste combustor unit load for designated facility i (pounds per hour steam or feedwater flow as determined in the most recent dioxin/furan performance test).
                h = total number of designated facilities being included in the daily emissions average.

              (v) For any day in which any designated facility included in the emissions averaging plan is offline, the owner or operator of the municipal waste combustor plant must demonstrate compliance according to either paragraph (d)(1)(v)(A) of this section or both paragraphs (d)(1)(v)(B) and (d)(1)(v)(C) of this section.
              (A) Compliance with the applicable limits specified in table 2 of this subpart shall be demonstrated using the averaging procedure specified in paragraph (d)(1)(iv) of this section for the designated facilities that are online.
              (B) For each of the designated facilities included in the emissions averaging plan, the nitrogen oxides emissions on a daily average basis shall be calculated and shall be equal to or less than the maximum daily nitrogen oxides emission level achieved by that designated facility on any of the days during which the emissions averaging plan was achieved with all designated facilities online during the most recent calendar quarter. The requirements of this paragraph do not apply during the first quarter of operation under the emissions averaging plan.

              (C) The average nitrogen oxides emissions (kilograms per day) calculated according to paragraph (d)(1)(v)(C)(2) of this section shall not exceed the average nitrogen oxides emissions (kilograms per day) calculated according to paragraph (d)(1)(v)(C)(1) of this section.
              (1) For all days during which the emissions averaging plan was implemented and achieved and during which all designated facilities were online, the average nitrogen oxides emissions shall be calculated. The average nitrogen oxides emissions (kilograms per day) shall be calculated on a calendar year basis according to paragraphs (d)(1)(v)(C)(1)(i) through (d)(1)(v)(C)(1)(iii) of this section.
              (i) For each designated facility included in the emissions averaging plan, the daily amount of nitrogen oxides emitted (kilograms per day) shall be calculated based on the hourly nitrogen oxides data required under § 60.38b(a) and specified under § 60.58b(h)(5) of subpart Eb of this part, the flue gas flow rate determined using table 19-1 of EPA Reference Method 19 or a State-approved method, and the hourly average steam or feedwater flow rate.
              (ii) The daily total nitrogen oxides emissions shall be calculated as the sum of the daily nitrogen oxides emissions from each designated facility calculated under paragraph (d)(1)(v)(C)(1)(i) of this section.
              (iii) The average nitrogen oxides emissions (kilograms per day) on a calendar year basis shall be calculated as the sum of all daily total nitrogen oxides emissions calculated under paragraph (d)(1)(v)(C)(1)(ii) of this section divided by the number of calendar days for which a daily total was calculated.
              (2) For all days during which one or more of the designated facilities under the emissions averaging plan was offline, the average nitrogen oxides emissions shall be calculated. The average nitrogen oxides emissions (kilograms per day) shall be calculated on a calendar year basis according to paragraphs (d)(1)(v)(C)(2)(i) through (d)(1)(v)(C)(2)(iii) of this section.
              (i) For each designated facility included in the emissions averaging plan, the daily amount of nitrogen oxides emitted (kilograms per day) shall be calculated based on the hourly nitrogen oxides data required under § 60.38b(a) and specified under § 60.58b(h)(5) of subpart Eb of this part, the flue gas flow rate determined using table 19-1 of EPA Reference Method 19 or a State-approved method, and the hourly average steam or feedwater flow rate.
              (ii) The daily total nitrogen oxides emissions shall be calculated as the sum of the daily nitrogen oxides emissions from each designated facility calculated under paragraph (d)(1)(v)(C)(2)(i) of this section.
              (iii) The average nitrogen oxides emissions (kilograms per day) on a calendar year basis shall be calculated as the sum of all daily total nitrogen oxides emissions calculated under paragraph (d)(1)(v)(C)(2)(ii) of this section divided by the number of calendar days for which a daily total was calculated.
              (2) A State plan may establish a program to allow owners or operators of municipal waste combustor plants to engage in trading of nitrogen oxides emission credits. A trading program must be approved by EPA before implementation.
              (3) For approval, a State plan shall include emission limits for nitrogen oxides from fluidized bed combustors at least as protective as the emission limits listed in paragraphs (d)(3)(i) and (d)(3)(ii) of this section.
              (i) The emission limit for nitrogen oxides contained in the gases discharged to the atmosphere from a designated facility that is a fluidized bed combustor is 180 parts per million by volume, corrected to 7 percent oxygen.
              (ii) If a State plan allows nitrogen oxides emissions averaging as specified in paragraphs (d)(1)(i) through (d)(1)(v) of this section, the emission limit for nitrogen oxides contained in the gases discharged to the atmosphere from a designated facility that is a fluidized bed combustor is 165 parts per million by volume, corrected to 7 percent oxygen.
              [60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45119, 45125, Aug. 25, 1997; 71 FR 27333, May 10, 2006]

              § 60.34b
              Emission guidelines for municipal waste combustor operating practices.
              (a) For approval, a State plan shall include emission limits for carbon monoxide at least as protective as the emission limits for carbon monoxide listed in table 3 of this subpart. table 3 provides emission limits for the carbon monoxide concentration level for each type of designated facility.
              (b) For approval, a State plan shall include requirements for municipal waste combustor operating practices at least as protective as those requirements listed in § 60.53b(b) and (c) of subpart Eb of this part.
              [60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, 45125, Aug. 25, 1997; 69 FR 42121, July 14, 2004; 71 FR 27333, May 10, 2006]

              § 60.35b
              Emission guidelines for municipal waste combustor operator training and certification.
              For approval, a State plan shall include requirements for designated facilities for municipal waste combustor operator training and certification at least as protective as those requirements listed in § 60.54b of subpart Eb of this part. The State plan shall require compliance with these requirements according to the schedule specified in § 60.39b(c)(4).
              [60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, Aug. 25, 1997]

              § 60.36b
              Emission guidelines for municipal waste combustor fugitive ash emissions.
              For approval, a State plan shall include requirements for municipal waste combustor fugitive ash emissions at least as protective as those requirements listed in § 60.55b of subpart Eb of this part.

              § 60.37b
              Emission guidelines for air curtain incinerators.

              For approval, a State plan shall include emission limits for opacity for air curtain incinerators at least as protective as those listed in § 60.56b of subpart Eb of this part.

              § 60.38b
              Compliance and performance testing.
              (a) For approval, a State plan shall include the performance testing methods listed in § 60.58b of subpart Eb of this part, as applicable, except as provided for under § 60.24(b)(2) of subpart B of this part and paragraphs (b) and (c) of this section.
              (b) For approval, a State plan shall include for designated facilities the alternative performance testing schedule for dioxins/furans specified in § 60.58b(g)(5)(iii) of subpart Eb of this part, as applicable, for those designated facilities that achieve a dioxin/furan emission level less than or equal to 15 nanograms per dry standard cubic meter total mass, corrected to 7 percent oxygen.
              (c) [Reserved]
              [60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, Aug. 25, 1997]

              § 60.39b
              Reporting and recordkeeping guidelines and compliance schedules.
              (a) For approval, a State plan shall include the reporting and recordkeeping provisions listed in § 60.59b of subpart Eb of this part, as applicable, except for the siting requirements under § 60.59b(a), (b)(5), and (d)(11) of subpart Eb of this part.
              (b) Except as provided in paragraph (e) of this section, not later than December 19, 1996, each State in which a designated facility is located shall submit to EPA a plan to implement and enforce all provisions of this subpart except the revised April 28, 2009 emission limits in § 60.33b(a), (c), and (d). Not later than April 28, 2007, each State in which a designated facility is located shall submit to EPA a plan to implement and enforce all provisions of this subpart, as amended on May 10, 2006. The submittal schedule specified in this paragraph is in accordance with section 129(b)(2) of the Clean Air Act and applies instead of the schedule provided in § 60.23(a)(1) of subpart B of this part.
              (c) For approval, a State plan that is submitted prior to May 10, 2006 shall include the compliance schedules specified in paragraphs (c)(1) through (c)(5) of this section.
              (1) A State plan shall allow designated facilities to comply with all requirements of a State plan (or close) within 1 year after approval of the State plan, except as provided by paragraph (c)(1)(i) and (c)(1)(ii) of this section.
              (i) A State plan that allows designated facilities more than 1 year but less than 3 years following the date of issuance of a revised construction or operation permit, if a permit modification is required, or more than 1 year but less than 3 years following approval of the State plan, if a permit modification is not required, shall include measurable and enforceable incremental steps of progress toward compliance. Suggested measurable and enforceable activities are specified in paragraphs (c)(1)(i)(A) through (c)(1)(i)(J) of this section.
              (A) Date for obtaining services of an architectural and engineering firm regarding the air pollution control device(s);
              (B) Date for obtaining design drawings of the air pollution control device(s);
              (C) Date for submittal of permit modifications, if necessary;
              (D) Date for submittal of the final control plan to the Administrator. [§ 60.21 (h)(1) of subpart B of this part.];
              (E) Date for ordering the air pollution control device(s);
              (F) Date for obtaining the major components of the air pollution control device(s);
              (G) Date for initiation of site preparation for installation of the air pollution control device(s);
              (H) Date for initiation of installation of the air pollution control device(s);
              (I) Date for initial startup of the air pollution control device(s); and
              (J) Date for initial performance test(s) of the air pollution control device(s).

              (ii) A State plan that allows designated facilities more than 1 year but up to 3 years after State plan approval to close shall require a closure agreement. The closure agreement must include the date of plant closure.

              (2) If the State plan requirements for a designated facility include a compliance schedule longer than 1 year after approval of the State plan in accordance with paragraph (c)(1)(i) or (c)(1)(ii) of this section, the State plan submittal (for approval) shall include performance test results for dioxin/furan emissions for each designated facility that has a compliance schedule longer than 1 year following the approval of the State plan, and the performance test results shall have been conducted during or after 1990. The performance test shall be conducted according to the procedures in § 60.38b.
              (3) [Reserved]
              (4) A State plan shall require compliance with the municipal waste combustor operator training and certification requirements under § 60.35b according to the schedule specified in paragraphs (c)(4)(i) through (c)(4)(iii) of this section.
              (i) [Reserved]
              (ii) For designated facilities, the State plan shall require compliance with the municipal waste combustor operator training and certification requirements specified under § 60.54b (a) through (c) of subpart Eb of this part by the date 6 months after the date of startup or 12 months after State plan approval, whichever is later.
              (iii) For designated facilities, the State plan shall require compliance with the requirements specified in § 60.54b (d), (f), and (g) of subpart Eb of this part no later than 6 months after startup or 12 months after State plan approval, whichever is later.
              (A) The requirement specified in § 60.54b(d) of subpart Eb of this part does not apply to chief facility operators, shift supervisors, and control room operators who have obtained full certification from the American Society of Mechanical Engineers on or before the date of State plan approval.
              (B) The owner or operator of a designated facility may request that the Administrator waive the requirement specified in § 60.54b(d) of subpart Eb of this part for chief facility operators, shift supervisors, and control room operators who have obtained provisional certification from the American Society of Mechanical Engineers on or before the initial date of State plan approval.

              (C) The initial training requirements specified in § 60.54b(f)(1) of subpart Eb of this part shall be completed no later than the date specified in paragraph (c)(4)(iii)(C)(1), (c)(4)(iii)(C)(2), or (c)(4)(iii)(C)(3), of this section whichever is later.
              (1) The date 6 months after the date of startup of the affected facility;
              (2) Twelve months after State plan approval; or
              (3) The date prior to the day when the person assumes responsibilities affecting municipal waste combustor unit operation.
              (5) A State plan shall require all designated facilities for which construction, modification, or reconstruction is commenced after June 26, 1987 to comply with the emission limit for mercury specified in § 60.33b(a)(3) and the emission limit for dioxins/furans specified in § 60.33b(c)(1) within 1 year following issuance of a revised construction or operation permit, if a permit modification is required, or within 1 year following approval of the State plan, whichever is later.
              (d) In the event no plan for implementing the emission guidelines is approved by EPA, all designated facilities meeting the applicability requirements under § 60.32b shall be in compliance with all of the guidelines, except those specified under § 60.33b (a)(4), (b)(3), and (d)(3), no later than December 19, 2000.
              (e) Not later than August 25, 1998, each State in which a designated facility is operating shall submit to EPA a plan to implement and enforce all provisions of this subpart specified in § 60.33b(b)(3) and (d)(3) and the emission limit in paragraph (a)(4) that applies before April 28, 2009.
              (f) In the event no plan for implementing the emission guidelines is approved by EPA, all designated facilities meeting the applicability requirements under § 60.32b shall be in compliance with all of the guidelines, including those specified under § 60.33b (a)(4), (b)(3), and (d)(3), no later than August 26, 2002.

              (g) For approval, a revised State plan submitted not later than April 28, 2007 in accordance with paragraph (b) of this section, shall include compliance schedules for meeting the revised April 28, 2009 emission limits in § 60.33b(a), (c), and (d) and the revised testing provisions in § 60.38b(b).
              (1) Compliance with the revised April 28, 2009 emission limits is required as expeditiously as practicable, but no later than April 28, 2009, except as provided in paragraph (g)(2) of this section.
              (2) The owner or operator of an affected facility who is planning an extensive emission control system upgrade may petition the Administrator for a longer compliance schedule and must demonstrate to the satisfaction of the Administrator the need for the additional time. If approved, the schedule may exceed the schedule in paragraph (g)(1) of this section, but cannot exceed May 10, 2011.
              (h) In the event no plan for implementing the emission guidelines is approved by EPA, all designated facilities meeting the applicability requirements under § 60.32b shall be in compliance with all of the guidelines, including the revised April 28, 2009 emission limits in §§ 60.33b(a), (b), (c), (d), and 60.34b(a), and the revised testing provisions in § 60.38b(b), no later than May 10, 2011.
              [60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, 45125, Aug. 25, 1997; 71 FR 27333, May 10, 2006]

              Pt. 60, Subpt. Cb, Table 1
              Table 1 to Subpart Cb of Part 60—Nitrogen Oxides Guidelines for Designated Facilities

                  Municipal waste combustor technology
                  Before April 28, 2009,nitrogen oxides emission limit
                    (parts per million by volume) a

                  On and after April 28, 2009,nitrogen oxides emission limit
                    (parts per million by volume) a

                  Mass burn waterwall
                  205
                  205.

                  Mass burn rotary waterwall
                  250
                  210.

                  Refuse-derived fuel combustor
                  250
                  250.

                  Fluidized bed combustor
                  180
                  180.

                  Mass burn refractory combustors
                  No limit
                  No limit.

                  a Corrected to 7 percent oxygen, dry basis.

              [71 FR 27334, May 10, 2006]

              Pt. 60, Subpt. Cb, Table 2
              Table 2 to Subpart Cb of Part 60—Nitrogen Oxides Limits for Existing Designated Facilities Included in an Emissions Averaging Plan at a Municipal Waste Combustor Plant b

                  Municipal waste combustor technology
                  Before April 28, 2009,nitrogen oxides emission limit
                    (parts per million by volume) b

                  On and after April 28, 2009,nitrogen oxides emission limit
                    (parts per million by volume) a

                  Mass burn waterwall
                  185
                  185

                  Mass burn rotary waterwall
                  220
                  190

                  Refuse-derived fuel combustor
                  230
                  230

                  Fluidized bed combustor
                  165
                  165

                  a Mass burn refractory municipal waste combustors and other MWC technologies not listed above may not be included in an emissions averaging plan.

                  b Corrected to 7 percent oxygen, dry basis.

              [71 FR 27334, May 10, 2006]

              Pt. 60, Subpt. Cb, Table 3
              Table 3 to Subpart Cb of Part 60—Municipal Waste Combustor Operating Guidelines

                  Municipal waste combustor technology
                  Carbon monoxide emissions levels (parts per million by volume) a

                  Averaging time (hrs) b

                  Mass burn waterwall
                  100
                  4

                  Mass burn refractory
                  100
                  4

                  Mass burn rotary refractory
                  100
                  24

                  Mass burn rotary waterwall
                  250
                  24

                  Modular starved air
                  50
                  4

                  Modular excess air
                  50
                  4

                  Refuse-derived fuel stoker
                  200
                  24

                  Fluidized bed, mixed fuel (wood/refuse-derived fuel)
                  200

                    c 24

                  Bubbling fluidized bed combustor
                  100
                  4

                  Circulating fluidized bed combustor
                  100
                  4

                  Pulverized coal/refuse-derived fuel mixed fuel-fired combustor
                  150
                  4

                  Spreader stoker coal/refuse-derived fuel mixed fuel-fired combustor
                  200
                  24

                  Semi-suspension refuse-derived fuel-fired combustor/wet refuse-derived fuel process conversion
                  250

                    c 24

                  Spreader stoker fixed floor refuse-derived fuel-fired combustor/100 percent coal capable
                  250

                    c 24

                  a Measured at the combustor outlet in conjunction with a measurement of oxygen concentration, corrected to 7 percent oxygen, dry basis. Calculated as an arithmetic average.

                  b Averaging times are 4-hour or 24-hour block averages.

                  c 24-hour block average, geometric mean.

              [71 FR 27334, May 10, 2006]

            Subpart Cc—Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills

              Source:
              61 FR 9919, Mar. 12, 1996, unless otherwise noted.

              § 60.30c
              Scope.
              This subpart contains emission guidelines and compliance times for the control of certain designated pollutants from certain designated municipal solid waste landfills in accordance with section 111(d) of the Act and subpart B.

              § 60.31c
              Definitions.
              Terms used but not defined in this subpart have the meaning given them in the Act and in subparts A, B, and WWW of this part.

                Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of RCRA Subtitle D wastes such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste, and industrial solid waste. Portions of an MSW landfill may be separated by access roads. An MSW landfill may be publicly or privately owned. An MSW landfill may be a new MSW landfill, an existing MSW landfill or a lateral expansion.

              § 60.32c
              Designated facilities.
              (a) The designated facility to which the guidelines apply is each existing MSW landfill for which construction, reconstruction or modification was commenced before May 30, 1991.
              (b) Physical or operational changes made to an existing MSW landfill solely to comply with an emission guideline are not considered a modification or reconstruction and would not subject an existing MSW landfill to the requirements of subpart WWW [see § 60.750 of subpart WWW].

              (c) For purposes of obtaining an operating permit under title V of the Act, the owner or operator of a MSW landfill subject to this subpart with a design capacity less than 2.5 million megagrams or 2.5 million cubic meters is not subject to the requirement to obtain an operating permit for the landfill under part 70 or 71 of this chapter, unless the landfill is otherwise subject to either part 70 or 71. For purposes of submitting a timely application for an operating permit under part 70 or 71, the owner or operator of a MSW landfill subject to this subpart with a design capacity greater than or equal to 2.5 million megagrams and 2.5 million cubic meters on the effective date of EPA approval of the State's program under section 111(d) of the Act, and not otherwise subject to either part 70 or 71, becomes subject to the requirements of §§ 70.5(a)(1)(i) or 71.5(a)(1)(i) of this chapter 90 days after the effective date of such 111(d) program approval, even if the design capacity report is submitted earlier.

              (d) When a MSW landfill subject to this subpart is closed, the owner or operator is no longer subject to the requirement to maintain an operating permit under part 70 or 71 of this chapter for the landfill if the landfill is not otherwise subject to the requirements of either part 70 or 71 and if either of the following conditions are met.
              (1) The landfill was never subject to the requirement for a control system under § 60.33c(c) of this subpart; or
              (2) The owner or operator meets the conditions for control system removal specified in § 60.752(b)(2)(v) of subpart WWW.
              [61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998]

              § 60.33c
              Emission guidelines for municipal solid waste landfill emissions.
              (a) For approval, a State plan shall include control of MSW landfill emissions at each MSW landfill meeting the following three conditions:
              (1) The landfill has accepted waste at any time since November 8, 1987, or has additional design capacity available for future waste deposition;
              (2) The landfill has a design capacity greater than or equal to 2.5 million megagrams and 2.5 million cubic meters. The landfill may calculate design capacity in either megagrams or cubic meters for comparison with the exemption values. Any density conversions shall be documented and submitted with the design capacity report; and
              (3) The landfill has a nonmethane organic compound emission rate of 50 megagrams per year or more.
              (b) For approval, a State plan shall include the installation of a collection and control system meeting the conditions provided in § 60.752(b)(2)(ii) of this part at each MSW landfill meeting the conditions in paragraph (a) of this section. The State plan shall include a process for State review and approval of the site-specific design plans for the gas collection and control system(s).
              (c) For approval, a State plan shall include provisions for the control of collected MSW landfill emissions through the use of control devices meeting the requirements of paragraph (c)(1), (2), or (3) of this section, except as provided in § 60.24.
              (1) An open flare designed and operated in accordance with the parameters established in § 60.18; or
              (2) A control system designed and operated to reduce NMOC by 98 weight percent; or
              (3) An enclosed combustor designed and operated to reduce the outlet NMOC concentration to 20 parts per million as hexane by volume, dry basis at 3 percent oxygen, or less.
              (d) For approval, a State plan shall require each owner or operator of an MSW landfill having a design capacity less than 2.5 million megagrams by mass or 2.5 million cubic meters by volume to submit an initial design capacity report to the Administrator as provided in § 60.757(a)(2) of subpart WWW by the date specified in § 60.35c of this subpart. The landfill may calculate design capacity in either megagrams or cubic meters for comparison with the exemption values. Any density conversions shall be documented and submitted with the report. Submittal of the initial design capacity report shall fulfill the requirements of this subpart except as provided in paragraph (d)(1) and (d)(2) of this section.
              (1) The owner or operator shall submit an amended design capacity report as provided in § 60.757(a)(3) of subpart WWW. [Guidance: Note that if the design capacity increase is the result of a modification, as defined in § 60.751 of subpart WWW, that was commenced on or after May 30, 1991, the landfill will become subject to subpart WWW instead of this subpart. If the design capacity increase is the result of a change in operating practices, density, or some other change that is not a modification, the landfill remains subject to this subpart.]
              (2) When an increase in the maximum design capacity of a landfill with an initial design capacity less than 2.5 million megagrams or 2.5 million cubic meters results in a revised maximum design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters, the owner or operator shall comply with paragraph (e) of this section.

              (e) For approval, a State plan shall require each owner or operator of an MSW landfill having a design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters to either install a collection and control system as provided in paragraph (b) of this section and § 60.752(b)(2) of subpart WWW or calculate an initial NMOC emission rate for the landfill using the procedures specified in § 60.34c of this subpart and § 60.754 of subpart WWW. The NMOC emission rate shall be recalculated annually, except as provided in § 60.757(b)(1)(ii) of subpart WWW.
              (1) If the calculated NMOC emission rate is less than 50 megagrams per year, the owner or operator shall:
              (i) Submit an annual emission report, except as provided for in § 60.757(b)(1)(ii); and
              (ii) Recalculate the NMOC emission rate annually using the procedures specified in § 60.754(a)(1) of subpart WWW until such time as the calculated NMOC emission rate is equal to or greater than 50 megagrams per year, or the landfill is closed.
              (2)(i) If the NMOC emission rate, upon initial calculation or annual recalculation required in paragraph (e)(1)(ii) of this section, is equal to or greater than 50 megagrams per year, the owner or operator shall install a collection and control system as provided in paragraph (b) of this section and § 60.752(b)(2) of subpart WWW.
              (ii) If the landfill is permanently closed, a closure notification shall be submitted to the Administrator as provided in § 60.35c of this subpart and § 60.757(d) of subpart WWW.
              [61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998; 64 FR 9261, Feb. 24, 1999]

              § 60.34c
              Test methods and procedures.
              For approval, a State plan shall include provisions for: the calculation of the landfill NMOC emission rate listed in § 60.754, as applicable, to determine whether the landfill meets the condition in § 60.33c(a)(3); the operational standards in § 60.753; the compliance provisions in § 60.755; and the monitoring provisions in § 60.756.

              § 60.35c
              Reporting and recordkeeping guidelines.
              For approval, a State plan shall include the recordkeeping and reporting provisions listed in §§ 60.757 and 60.758, as applicable, except as provided under § 60.24.
              (a) For existing MSW landfills subject to this subpart the initial design capacity report shall be submitted no later than 90 days after the effective date of EPA approval of the State's plan under section 111(d) of the Act.
              (b) For existing MSW landfills covered by this subpart with a design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters, the initial NMOC emission rate report shall be submitted no later than 90 days after the effective date of EPA approval of the State's plan under section 111(d) of the Act.
              [61 FR 9919, Mar. 12, 1996, as amended at 64 FR 9262, Feb. 24, 1999]

              § 60.36c
              Compliance times.
              (a) Except as provided for under paragraph (b) of this section, planning, awarding of contracts, and installation of MSW landfill air emission collection and control equipment capable of meeting the emission guidelines established under § 60.33c shall be accomplished within 30 months after the date the initial NMOC emission rate report shows NMOC emissions equal or exceed 50 megagrams per year.
              (b) For each existing MSW landfill meeting the conditions in § 60.33c(a)(1) and § 60.33c(a)(2) whose NMOC emission rate is less than 50 megagrams per year on the effective date of the State emission standard, installation of collection and control systems capable of meeting emission guidelines in § 60.33c shall be accomplished within 30 months of the date when the condition in § 60.33c(a)(3) is met (i.e., the date of the first annual nonmethane organic compounds emission rate which equals or exceeds 50 megagrams per year).
              [61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998]

            Subpart Cd—Emissions Guidelines and Compliance Times for Sulfuric Acid Production Units

              Source:
              60 FR 65414, Dec. 19, 1995, unless otherwise noted.

              § 60.30d
              Designated facilities.
              Sulfuric acid production units. The designated facility to which §§ 60.31d and 60.32d apply is each existing “sulfuric acid production unit” as defined in § 60.81(a) of subpart H of this part.

              § 60.31d
              Emissions guidelines.
              Sulfuric acid production units. The emission guideline for designated facilities is 0.25 grams sulfuric acid mist (as measured by EPA Reference Method 8 of appendix A of this part) per kilogram (0.5 pounds per ton) of sulfuric acid produced, the production being expressed as 100 percent sulfuric acid.

              § 60.32d
              Compliance times.
              Sulfuric acid production units. Planning, awarding of contracts, and installation of equipment capable of attaining the level of the emission guideline established under § 60.31d can be accomplished within 17 months after the effective date of a State emission standard for sulfuric acid mist.

            Subpart Ce—Emission Guidelines and Compliance Times for Hospital/Medical/Infectious Waste Incinerators

              Source:
              62 FR 48379, Sept. 15, 1997, unless otherwise noted.

              § 60.30e
              Scope.
              This subpart contains emission guidelines and compliance times for the control of certain designated pollutants from hospital/medical/infectious waste incinerator(s) (HMIWI) in accordance with sections 111 and 129 of the Clean Air Act and subpart B of this part. The provisions in these emission guidelines supersede the provisions of § 60.24(f) of subpart B of this part.

              § 60.31e
              Definitions.
              Terms used but not defined in this subpart have the meaning given them in the Clean Air Act and in subparts A, B, and Ec of this part.

                Standard Metropolitan Statistical Area or SMSA means any areas listed in OMB Bulletin No. 93-17 entitled “Revised Statistical Definitions for Metropolitan Areas” dated June 30, 1993 (incorporated by reference, see § 60.17).

              § 60.32e
              Designated facilities.
              (a) Except as provided in paragraphs (b) through (h) of this section, the designated facility to which the guidelines apply is each individual HMIWI:
              (1) For which construction was commenced on or before June 20, 1996, or for which modification was commenced on or before March 16, 1998.
              (2) For which construction was commenced after June 20, 1996 but no later than December 1, 2008, or for which modification is commenced after March 16, 1998 but no later than April 6, 2010.
              (b) A combustor is not subject to this subpart during periods when only pathological waste, low-level radioactive waste, and/or chemotherapeutic waste (all defined in § 60.51c) is burned, provided the owner or operator of the combustor:
              (1) Notifies the Administrator of an exemption claim; and
              (2) Keeps records on a calendar quarter basis of the periods of time when only pathological waste, low-level radioactive waste, and/or chemotherapeutic waste is burned.
              (c) Any co-fired combustor (defined in § 60.51c) is not subject to this subpart if the owner or operator of the co-fired combustor:
              (1) Notifies the Administrator of an exemption claim;
              (2) Provides an estimate of the relative weight of hospital waste, medical/infectious waste, and other fuels and/or wastes to be combusted; and
              (3) Keeps records on a calendar quarter basis of the weight of hospital waste and medical/infectious waste combusted, and the weight of all other fuels and wastes combusted at the co-fired combustor.
              (d) Any combustor required to have a permit under Section 3005 of the Solid Waste Disposal Act is not subject to this subpart.

              (e) Any combustor which meets the applicability requirements under subpart Cb, Ea, or Eb of this part (standards or guidelines for certain municipal waste combustors) is not subject to this subpart.

              (f) Any pyrolysis unit (defined in § 60.51c) is not subject to this subpart.
              (g) Cement kilns firing hospital waste and/or medical/infectious waste are not subject to this subpart.
              (h) Physical or operational changes made to an existing HMIWI unit solely for the purpose of complying with emission guidelines under this subpart are not considered a modification and do not result in an existing HMIWI unit becoming subject to the provisions of subpart Ec (see § 60.50c).
              (i) Beginning September 15, 2000, or on the effective date of an EPA approved operating permit program under Clean Air Act title V and the implementing regulations under 40 CFR part 70 in the State in which the unit is located, whichever date is later, designated facilities subject to this subpart shall operate pursuant to a permit issued under the EPA-approved operating permit program.
              (j) The requirements of this subpart as promulgated on September 15, 1997, shall apply to the designated facilities defined in paragraph (a)(1) of this section until the applicable compliance date of the requirements of this subpart, as amended on October 6, 2009. Upon the compliance date of the requirements of this subpart, designated facilities as defined in paragraph (a)(1) of this section are no longer subject to the requirements of this subpart, as promulgated on September 15, 1997, but are subject to the requirements of this subpart, as amended on October 6, 2009.
              (k) The authorities listed under § 60.50c(i) shall be retained by the Administrator and not be transferred to a state.
              [60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51402, Oct. 6, 2009; 76 FR 18412, Apr. 4, 2011]

              § 60.33e
              Emissions guidelines.
              (a) For approval, a State plan shall include the requirements for emissions limits at least as protective as the following requirements, as applicable:
              (1) For a designated facility as defined in § 60.32e(a)(1) subject to the emissions guidelines as promulgated on September 15, 1997, the requirements listed in Table 1A of this subpart, except as provided in paragraph (b) of this section.
              (2) For a designated facility as defined in § 60.32e(a)(1) subject to the emissions guidelines as amended on October 6, 2009, the requirements listed in Table 1B of this subpart, except as provided in paragraph (b) of this section.
              (3) For a designated facility as defined in § 60.32e(a)(2), the more stringent of the requirements listed in Table 1B of this subpart and Table 1A of subpart Ec of this part.
              (b) For approval, a State plan shall include the requirements for emissions limits for any small HMIWI constructed on or before June 20, 1996, which is located more than 50 miles from the boundary of the nearest Standard Metropolitan Statistical Area (defined in § 60.31e) and which burns less than 2,000 pounds per week of hospital waste and medical/infectious waste that are at least as protective as the requirements in paragraphs (b)(1) and (b)(2) of this section, as applicable. The 2,000 lb/week limitation does not apply during performance tests.
              (1) For a designated facility as defined in § 60.32e(a)(1) subject to the emissions guidelines as promulgated on September 15, 1997, the requirements listed in Table 2A of this subpart.
              (2) For a designated facility as defined in § 60.32e(a)(1) subject to the emissions guidelines as amended on October 6, 2009, the requirements listed in Table 2B of this subpart.
              (c) For approval, a State plan shall include the requirements for stack opacity at least as protective as the following, as applicable:
              (1) For a designated facility as defined in § 60.32e(a)(1) subject to the emissions guidelines as promulgated on September 15, 1997, the requirements in § 60.52c(b)(1) of subpart Ec of this part.
              (2) For a designated facility as defined in § 60.32e(a)(1) subject to the emissions guidelines as amended on October 6, 2009 and a designated facility as defined in § 60.32e(a)(2), the requirements in § 60.52c(b)(2) of subpart Ec of this part.
              [74 FR 51403, Oct. 6, 2009]

              § 60.34e
              Operator training and qualification guidelines.

              For approval, a State plan shall include the requirements for operator training and qualification at least as protective as those requirements listed in § 60.53c of subpart Ec of this part. The State plan shall require compliance with these requirements according to the schedule specified in § 60.39e(e).

              § 60.35e
              Waste management guidelines.
              For approval, a State plan shall include the requirements for a waste management plan at least as protective as those requirements listed in § 60.55c of subpart Ec of this part.

              § 60.36e
              Inspection guidelines.
              (a) For approval, a State plan shall require each small HMIWI subject to the emissions limits under § 60.33e(b) and each HMIWI subject to the emissions limits under § 60.33e(a)(2) and (a)(3) to undergo an initial equipment inspection that is at least as protective as the following within 1 year following approval of the State plan:
              (1) At a minimum, an inspection shall include the following:
              (i) Inspect all burners, pilot assemblies, and pilot sensing devices for proper operation; clean pilot flame sensor, as necessary;
              (ii) Ensure proper adjustment of primary and secondary chamber combustion air, and adjust as necessary;
              (iii) Inspect hinges and door latches, and lubricate as necessary;
              (iv) Inspect dampers, fans, and blowers for proper operation;
              (v) Inspect HMIWI door and door gaskets for proper sealing;
              (vi) Inspect motors for proper operation;
              (vii) Inspect primary chamber refractory lining; clean and repair/replace lining as necessary;
              (viii) Inspect incinerator shell for corrosion and/or hot spots;
              (ix) Inspect secondary/tertiary chamber and stack, clean as necessary;
              (x) Inspect mechanical loader, including limit switches, for proper operation, if applicable;
              (xi) Visually inspect waste bed (grates), and repair/seal, as appropriate;
              (xii) For the burn cycle that follows the inspection, document that the incinerator is operating properly and make any necessary adjustments;
              (xiii) Inspect air pollution control device(s) for proper operation, if applicable;
              (xiv) Inspect waste heat boiler systems to ensure proper operation, if applicable;
              (xv) Inspect bypass stack components;
              (xvi) Ensure proper calibration of thermocouples, sorbent feed systems and any other monitoring equipment; and
              (xvii) Generally observe that the equipment is maintained in good operating condition.
              (2) Within 10 operating days following an equipment inspection all necessary repairs shall be completed unless the owner or operator obtains written approval from the State agency establishing a date whereby all necessary repairs of the designated facility shall be completed.
              (b) For approval, a State plan shall require each small HMIWI subject to the emissions limits under § 60.33e(b) and each HMIWI subject to the emissions limits under § 60.33e(a)(2) and (a)(3) to undergo an equipment inspection annually (no more than 12 months following the previous annual equipment inspection), as outlined in paragraph (a) of this section.
              (c) For approval, a State plan shall require each small HMIWI subject to the emissions limits under § 60.33e(b)(2) and each HMIWI subject to the emissions limits under § 60.33e(a)(2) and (a)(3) to undergo an initial air pollution control device inspection, as applicable, that is at least as protective as the following within 1 year following approval of the State plan:
              (1) At a minimum, an inspection shall include the following:
              (i) Inspect air pollution control device(s) for proper operation, if applicable;
              (ii) Ensure proper calibration of thermocouples, sorbent feed systems, and any other monitoring equipment; and
              (iii) Generally observe that the equipment is maintained in good operating condition.

              (2) Within 10 operating days following an air pollution control device inspection, all necessary repairs shall be completed unless the owner or operator obtains written approval from the State agency establishing a date whereby all necessary repairs of the designated facility shall be completed.
              (d) For approval, a State plan shall require each small HMIWI subject to the emissions limits under § 60.33e(b)(2) and each HMIWI subject to the emissions limits under § 60.33e(a)(2) and (a)(3) to undergo an air pollution control device inspection, as applicable, annually (no more than 12 months following the previous annual air pollution control device inspection), as outlined in paragraph (c) of this section.
              [60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51403, Oct. 6, 2009]

              § 60.37e
              Compliance, performance testing, and monitoring guidelines.
              (a) Except as provided in paragraph (b) of this section, for approval, a State plan shall include the requirements for compliance and performance testing listed in § 60.56c of subpart Ec of this part, with the following exclusions:
              (1) For a designated facility as defined in § 60.32e(a)(1) subject to the emissions limits in § 60.33e(a)(1), the test methods listed in § 60.56c(b)(7) and (8), the fugitive emissions testing requirements under § 60.56c(b)(14) and (c)(3), the CO CEMS requirements under § 60.56c(c)(4), and the compliance requirements for monitoring listed in § 60.56c(c)(5)(ii) through (v), (c)(6), (c)(7), (e)(6) through (10), (f)(7) through (10), (g)(6) through (10), and (h).
              (2) For a designated facility as defined in § 60.32e(a)(1) and (a)(2) subject to the emissions limits in § 60.33e(a)(2) and (a)(3), the annual fugitive emissions testing requirements under § 60.56c(c)(3), the CO CEMS requirements under § 60.56c(c)(4), and the compliance requirements for monitoring listed in § 60.56c(c)(5)(ii) through (v), (c)(6), (c)(7), (e)(6) through (10), (f)(7) through (10), and (g)(6) through (10). Sources subject to the emissions limits under § 60.33e(a)(2) and (a)(3) may, however, elect to use CO CEMS as specified under § 60.56c(c)(4) or bag leak detection systems as specified under § 60.57c(h).
              (b) Except as provided in paragraphs (b)(1) and (b)(2) of this section, for approval, a State plan shall require each small HMIWI subject to the emissions limits under § 60.33e(b) to meet the performance testing requirements listed in § 60.56c of subpart Ec of this part. The 2,000 lb/week limitation under § 60.33e(b) does not apply during performance tests.
              (1) For a designated facility as defined in § 60.32e(a)(1) subject to the emissions limits under § 60.33e(b)(1), the test methods listed in § 60.56c(b)(7), (8), (12), (13) (Pb and Cd), and (14), the annual PM, CO, and HCl emissions testing requirements under § 60.56c(c)(2), the annual fugitive emissions testing requirements under § 60.56c(c)(3), the CO CEMS requirements under § 60.56c(c)(4), and the compliance requirements for monitoring listed in § 60.56c(c)(5) through (7), and (d) through (k) do not apply.
              (2) For a designated facility as defined in § 60.32e(a)(2) subject to the emissions limits under § 60.33e(b)(2), the annual fugitive emissions testing requirements under § 60.56c(c)(3), the CO CEMS requirements under § 60.56c(c)(4), and the compliance requirements for monitoring listed in § 60.56c(c)(5)(ii) through (v), (c)(6), (c)(7), (e)(6) through (10), (f)(7) through (10), and (g)(6) through (10) do not apply. Sources subject to the emissions limits under § 60.33e(b)(2) may, however, elect to use CO CEMS as specified under § 60.56c(c)(4) or bag leak detection systems as specified under § 60.57c(h).
              (c) For approval, a State plan shall require each small HMIWI subject to the emissions limits under § 60.33e(b) that is not equipped with an air pollution control device to meet the following compliance and performance testing requirements:
              (1) Establish maximum charge rate and minimum secondary chamber temperature as site-specific operating parameters during the initial performance test to determine compliance with applicable emission limits.

              (2) Following the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, ensure that the designated facility does not operate above the maximum charge rate or below the minimum secondary chamber temperature measured as 3-hour rolling averages (calculated each hour as the average of the previous 3 operating hours) at all times. Operating parameter limits do not apply during performance tests. Operation above the maximum charge rate or below the minimum secondary chamber temperature shall constitute a violation of the established operating parameter(s).
              (3) Except as provided in paragraph (c)(4) of this section, operation of the designated facility above the maximum charge rate and below the minimum secondary chamber temperature (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the PM, CO, and dioxin/furan emissions limits.
              (4) The owner or operator of a designated facility may conduct a repeat performance test within 30 days of violation of applicable operating parameter(s) to demonstrate that the designated facility is not in violation of the applicable emissions limit(s). Repeat performance tests conducted pursuant to this paragraph must be conducted under process and control device operating conditions duplicating as nearly as possible those that indicated a violation under paragraph (c)(3) of this section.
              (d) For approval, a State plan shall include the requirements for monitoring listed in § 60.57c of subpart Ec of this part for HMIWI subject to the emissions limits under § 60.33e(a) and (b), except as provided for under paragraph (e) of this section.
              (e) For approval, a State plan shall require small HMIWI subject to the emissions limits under § 60.33e(b) that are not equipped with an air pollution control device to meet the following monitoring requirements:
              (1) Install, calibrate (to manufacturers' specifications), maintain, and operate a device for measuring and recording the temperature of the secondary chamber on a continuous basis, the output of which shall be recorded, at a minimum, once every minute throughout operation.
              (2) Install, calibrate (to manufacturers' specifications), maintain, and operate a device which automatically measures and records the date, time, and weight of each charge fed into the HMIWI.
              (3) The owner or operator of a designated facility shall obtain monitoring data at all times during HMIWI operation except during periods of monitoring equipment malfunction, calibration, or repair. At a minimum, valid monitoring data shall be obtained for 75 percent of the operating hours per day for 90 percent of the operating hours per calendar quarter that the designated facility is combusting hospital waste and/or medical/infectious waste.
              (f) The owner or operator of a designated facility as defined in § 60.32e(a)(1) or (a)(2) subject to emissions limits under § 60.33e(a)(2), (a)(3), or (b)(2) may use the results of previous emissions tests to demonstrate compliance with the emissions limits, provided that the conditions in paragraphs (f)(1) through (f)(3) of this section are met:
              (1) The designated facility's previous emissions tests must have been conducted using the applicable procedures and test methods listed in § 60.56c(b) of subpart Ec of this part. Previous emissions test results obtained using EPA-accepted voluntary consensus standards are also acceptable.

              (2) The HMIWI at the designated facility shall currently be operated in a manner (e.g., with charge rate, secondary chamber temperature, etc.) that would be expected to result in the same or lower emissions than observed during the previous emissions test(s), and the HMIWI may not have been modified such that emissions would be expected to exceed (notwithstanding normal test-to-test variability) the results from previous emissions test(s).
              (3) The previous emissions test(s) must have been conducted in 1996 or later.
              [60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51403, Oct. 6, 2009]

              § 60.38e
              Reporting and recordkeeping guidelines.

              (a) Except as provided in paragraphs (a)(1) and (a)(2) of this section, for approval, a State plan shall include the reporting and recordkeeping requirements listed in § 60.58c(b) through (g) of subpart Ec of this part.

              (1) For a designated facility as defined in § 60.32e(a)(1) subject to emissions limits under § 60.33e(a)(1) or (b)(1), excluding § 60.58c(b)(2)(ii) (fugitive emissions), (b)(2)(viii) (NOX reagent), (b)(2)(xvii) (air pollution control device inspections), (b)(2)(xviii) (bag leak detection system alarms), (b)(2)(xix) (CO CEMS data), and (b)(7) (siting documentation).
              (2) For a designated facility as defined in § 60.32e(a)(1) or (a)(2) subject to emissions limits under § 60.33e(a)(2), (a)(3), or (b)(2), excluding § 60.58c(b)(2)(xviii) (bag leak detection system alarms), (b)(2)(xix) (CO CEMS data), and (b)(7) (siting documentation).
              (b) For approval, a State plan shall require the owner or operator of each HMIWI subject to the emissions limits under § 60.33e to:
              (1) As specified in § 60.36e, maintain records of the annual equipment inspections that are required for each HMIWI subject to the emissions limits under § 60.33e(a)(2), (a)(3), and (b), and the annual air pollution control device inspections that are required for each HMIWI subject to the emissions limits under § 60.33e(a)(2), (a)(3), and (b)(2), any required maintenance, and any repairs not completed within 10 days of an inspection or the timeframe established by the State regulatory agency; and
              (2) Submit an annual report containing information recorded under paragraph (b)(1) of this section no later than 60 days following the year in which data were collected. Subsequent reports shall be sent no later than 12 calendar months following the previous report (once the unit is subject to permitting requirements under Title V of the Act, the owner or operator must submit these reports semiannually). The report shall be signed by the facilities manager.
              [60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51404, Oct. 6, 2009]

              § 60.39e
              Compliance times.
              (a) Each State in which a designated facility is operating shall submit to the Administrator a plan to implement and enforce the emissions guidelines as specified in paragraphs (a)(1) and (a)(2) of this section:
              (1) Not later than September 15, 1998, for the emissions guidelines as promulgated on September 15, 1997.
              (2) Not later than October 6, 2010, for the emissions guidelines as amended on October 6, 2009.
              (b) Except as provided in paragraphs (c) and (d) of this section, State plans shall provide that designated facilities comply with all requirements of the State plan on or before the date 1 year after EPA approval of the State plan, regardless of whether a designated facility is identified in the State plan inventory required by § 60.25(a) of subpart B of this part.
              (c) State plans that specify measurable and enforceable incremental steps of progress towards compliance for designated facilities planning to install the necessary air pollution control equipment may allow compliance on or before the date 3 years after EPA approval of the State plan (but not later than September 16, 2002), for the emissions guidelines as promulgated on September 15, 1997, and on or before the date 3 years after approval of an amended State plan (but not later than October 6, 2014), for the emissions guidelines as amended on October 6, 2009). Suggested measurable and enforceable activities to be included in State plans are:
              (1) Date for submitting a petition for site-specific operating parameters under § 60.56c(j) of subpart Ec of this part.
              (2) Date for obtaining services of an architectural and engineering firm regarding the air pollution control device(s);
              (3) Date for obtaining design drawings of the air pollution control device(s);
              (4) Date for ordering the air pollution control device(s);
              (5) Date for obtaining the major components of the air pollution control device(s);
              (6) Date for initiation of site preparation for installation of the air pollution control device(s);
              (7) Date for initiation of installation of the air pollution control device(s);
              (8) Date for initial startup of the air pollution control device(s); and

              (9) Date for initial compliance test(s) of the air pollution control device(s).

              (d) State plans that include provisions allowing designated facilities to petition the State for extensions beyond the compliance times required in paragraph (b) of this section shall:
              (1) Require that the designated facility requesting an extension submit the following information in time to allow the State adequate time to grant or deny the extension within 1 year after EPA approval of the State plan:
              (i) Documentation of the analyses undertaken to support the need for an extension, including an explanation of why up to 3 years after EPA approval of the State plan is sufficient time to comply with the State plan while 1 year after EPA approval of the State plan is not sufficient. The documentation shall also include an evaluation of the option to transport the waste offsite to a commercial medical waste treatment and disposal facility on a temporary or permanent basis; and
              (ii) Documentation of measurable and enforceable incremental steps of progress to be taken towards compliance with the emission guidelines.
              (2) Include procedures for granting or denying the extension; and
              (3) If an extension is granted, require expeditious compliance with the emissions guidelines on or before the date 3 years after EPA approval of the state plan (but not later than September 16, 2002), for the emissions guidelines as promulgated on September 15, 1997, and on or before the date 3 years after EPA approval of an amended state plan (but not later than October 6, 2014), for the emissions guidelines as amended on October 6, 2009.
              (e) For approval, a State plan shall require compliance with § 60.34e—Operator training and qualification guidelines and § 60.36e—Inspection guidelines by the date 1 year after EPA approval of a State plan.
              (f) The Administrator shall develop, implement, and enforce a plan for existing HMIWI located in any State that has not submitted an approvable plan within 2 years after September 15, 1997, for the emissions guidelines as promulgated on September 15, 1997, and within 2 years after October 6, 2009 for the emissions guidelines as amended on October 6, 2009. Such plans shall ensure that each designated facility is in compliance with the provisions of this subpart no later than 5 years after September 15, 1997, for the emissions guidelines as promulgated on September 15, 1997, and no later than 5 years after October 6, 2009 for the emissions guidelines as amended on October 6, 2009.
              [60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51404, Oct. 6, 2009; 76 FR 18412, Apr. 4, 2011]

              Pt. 60, Subpt. Ce, Table 1A
              Table 1A to Subpart Ce of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Designated Facilities as Defined in § 60.32e(a)(1)

                  Pollutant
                  Units (7 percent oxygen, dry basis)
                  Emissions limits
                  HMIWI size
                  Small
                  Medium
                  Large
                  Averaging time 1

                  Method for demonstrating compliance 2

                  Particulate matter
                  Milligrams per dry standard cubic meter (mg/dscm) (grains per dry standard cubic foot (gr/dscf))
                  115 (0.05)
                  69 (0.03)
                  34 (0.015)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 5 of appendix A-3 of part 60, or EPA Reference Method 26A or 29 of appendix A-8 of part 60.

                  Carbon monoxide
                  Parts per million by volume (ppmv)
                  40
                  40
                  40
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 10 or 10B of appendix A-4 of part 60.

                  Dioxins/furans
                  Nanograms per dry standard cubic meter total dioxins/furans (ng/dscm) (grains per billion dry standard cubic feet (gr/109 dscf)) or ng/dscm TEQ (gr/109 dscf)
                  125 (55) or 2.3 (1.0)
                  125 (55) or 2.3 (1.0)
                  125 (55) or 2.3 (1.0)
                  3-run average (4-hour minimum sample time per run)
                  EPA Reference Method 23 of appendix A-7 of part 60.

                  Hydrogen chloride
                  ppmv or percent reduction
                  100 or 93%
                  100 or 93%
                  100 or 93%
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 26 or 26A of appendix A-8 of part 60.

                  Sulfur dioxide
                  ppmv
                  55
                  55
                  55
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 6 or 6C of appendix A-4 of part 60.

                  Nitrogen oxides
                  ppmv
                  250
                  250
                  250
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 7 or 7E of appendix A-4 of part 60.

                  Lead
                  mg/dscm (grains per thousand dry standard cubic feet (gr/103 dscf)) or percent reduction
                  1.2 (0.52) or 70%
                  1.2 (0.52) or 70%
                  1.2 (0.52) or 70%
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Cadmium
                  mg/dscm (gr/103 dscf) or percent reduction
                  0.16 (0.07) or 65%
                  0.16 (0.07) or 65%
                  0.16 (0.07) or 65%
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Mercury
                  mg/dscm (gr/103 dscf) or percent reduction
                  0.55 (0.24) or 85%
                  0.55 (0.24) or 85%
                  0.55 (0.24) or 85%
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  1 Except as allowed under § 60.56c(c) for HMIWI equipped with CEMS.

                  2 Does not include CEMS and approved alternative non-EPA test methods allowed under § 60.56c(b).

              [60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51405, Oct. 6, 2009; 76 FR 18412, Apr. 4, 2011]

              Pt. 60, Subpt. Ce, Table 1B
              Table 1B to Subpart Ce of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Designated Facilities as Defined in § 60.32e(a)(1) and (a)(2)

                  Pollutant
                  Units(7 percent oxygen, dry basis)

                  Emissions limits
                  HMIWI size
                  Small
                  Medium
                  Large
                  Averaging time 1

                  Method for demonstrating compliance 2

                  Particulate matter
                  Milligrams per dry standard cubic meter (mg/dscm) (grains per dry standard cubic foot (gr/dscf))
                  66 (0.029)
                  46 (0.020)
                  25 (0.011)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 5 of appendix A-3 of part 60, or EPA Reference Method 26A or 29 of appendix A-8 of part 60.

                  Carbon monoxide
                  Parts per million by volume (ppmv)
                  20
                  5.5
                  11
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 10 or 10B of appendix A-4 of part 60.

                  Dioxins/furans
                  Nanograms per dry standard cubic meter total dioxins/furans (ng/dscm) (grains per billion dry standard cubic feet (gr/109 dscf)) or ng/dscm TEQ (gr/109 dscf)
                  16 (7.0) or 0.013 (0.0057)
                  0.85 (0.37) or 0.020 (0.0087)
                  9.3 (4.1) or 0.054 (0.024)
                  3-run average (4-hour minimum sample time per run)
                  EPA Reference Method 23 of appendix A-7 of part 60.

                  Hydrogen chloride
                  ppmv
                  44
                  7.7
                  6.6
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 26 or 26A of appendix A-8 of part 60.

                  Sulfur dioxide
                  ppmv
                  4.2
                  4.2
                  9.0
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 6 or 6C of appendix A-4 of part 60.

                  Nitrogen oxides
                  ppmv
                  190
                  190
                  140
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 7 or 7E of appendix A-4 of part 60.

                  Lead
                  mg/dscm (grains per thousand dry standard cubic feet (gr/103 dscf))
                  0.31 (0.14)
                  0.018 (0.0079)
                  0.036 (0.016)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Cadmium
                  mg/dscm (gr/103 dscf)
                  0.017 (0.0074)
                  0.013 (0.0057)
                  0.0092 (0.0040)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Mercury
                  mg/dscm (gr/103 dscf)
                  0.014 (0.0061)
                  0.025 (0.011)
                  0.018 (0.0079)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  1 Except as allowed under § 60.56c(c) for HMIWI equipped with CEMS.

                  2 Does not include CEMS and approved alternative non-EPA test methods allowed under § 60.56c(b).

              [74 FR 51406, Oct. 6, 2009]

              Pt. 60, Subpt. Ce, Table 2A
              Table 2A to Subpart Ce of Part 60—Emissions Limits for Small HMIWI Which Meet the Criteria Under § 60.33e(b)(1)

                  Pollutant
                  Units(7 percent oxygen, dry basis)

                  HMIWI emissions limits
                  Averaging time 1

                  Method for demonstrating compliance 2

                  Particulate matter
                  mg/dscm (gr/dscf)
                  197 (0.086)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 5 of appendix A-3 of part 60, or EPA Reference Method 26A or 29 of appendix A-8 of part 60.

                  Carbon monoxide
                  ppmv
                  40
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 10 or 10B of appendix A-4 of part 60.

                  Dioxins/furans
                  ng/dscm total dioxins/furans (gr/109 dscf) or ng/dscm TEQ (gr/109 dscf)
                  800 (350) or 15 (6.6)
                  3-run average (4-hour minimum sample time per run)
                  EPA Reference Method 23 of appendix A-7 of part 60.

                  Hydrogen chloride
                  ppmv
                  3,100
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 26 or 26A of appendix A-8 of part 60.

                  Sulfur dioxide
                  ppmv
                  55
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 6 or 6C of appendix A-4 of part 60.

                  Nitrogen oxides
                  ppmv
                  250
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 7 or 7E of appendix A-4 of part 60.

                  Lead
                  mg/dscm (gr/103 dscf)
                  10 (4.4)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Cadmium
                  mg/dscm (gr/103 dscf)
                  4 (1.7)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Mercury
                  mg/dscm (gr/103 dscf)
                  7.5 (3.3)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  1 Except as allowed under § 60.56c(c) for HMIWI equipped with CEMS.

                  2 Does not include CEMS and approved alternative non-EPA test methods allowed under § 60.56c(b).

              [74 FR 51407, Oct. 6, 2009]

              Pt. 60, Subpt. Ce, Table 2B
              Table 2B to Subpart Ce of Part 60—Emissions Limits for Small HMIWI Which Meet the Criteria Under § 60.33e(b)(2)

                  Pollutant
                  Units(7 percent oxygen, dry basis)

                  HMIWI Emissions limits
                  Averaging time 1

                  Method for demonstrating compliance 2

                  Particulate matter
                  mg/dscm (gr/dscf)
                  87 (0.038)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 5 of appendix A-3 of part 60, or EPA Reference Method 26A or 29 of appendix A-8 of part 60.

                  Carbon monoxide
                  ppmv
                  20
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 10 or 10B of appendix A-4 of part 60.

                  Dioxins/furans
                  ng/dscm total dioxins/furans (gr/109 dscf) or ng/dscm TEQ (gr/109 dscf)
                  240 (100) or 5.1 (2.2)
                  3-run average (4-hour minimum sample time per run)
                  EPA Reference Method 23 of appendix A-7 of part 60.

                  Hydrogen chloride
                  ppmv
                  810
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 26 or 26A of appendix A-8 of part 60.

                  Sulfur dioxide
                  ppmv
                  55
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 6 or 6C of appendix A-4 of part 60.

                  Nitrogen oxides
                  ppmv
                  130
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 7 or 7E of appendix A-4 of part 60.

                  Lead
                  mg/dscm (gr/103 dscf)
                  0.50 (0.22)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Cadmium
                  mg/dscm (gr/103 dscf)
                  0.11 (0.048)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Mercury
                  mg/dscm (gr/103 dscf)
                  0.0051 (0.0022)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  1 Except as allowed under § 60.56c(c) for HMIWI equipped with CEMS.

                  2 Does not include CEMS and approved alternative non-EPA test methods allowed under § 60.56c(b).

              [74 FR 51407, Oct. 6, 2009]

            Subpart Cf—Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills

              Source:
              81 FR 59313, Aug. 29, 2016, unless otherwise noted.

              § 60.30f
              Scope and delegated authorities.
              This subpart establishes Emission Guidelines and compliance times for the control of designated pollutants from certain designated municipal solid waste (MSW) landfills in accordance with section 111(d) of the Clean Air Act and subpart B of this part.
              (a) If you are the Administrator of an air quality program in a state or United States protectorate with one or more existing MSW landfills that commenced construction, modification, or reconstruction on or before July 17, 2014, you must submit a state plan to the U.S. Environmental Protection Agency (EPA) that implements the Emission Guidelines contained in this subpart. The requirements for state and federal plans are specified in subpart B of this part with the exception that §§ 60.23 and 60.27 will not apply. Notwithstanding the provisions of § 60.20a(a) in subpart Ba of this part, the requirements of §§ 60.23a and 60.27a will apply for state plans submitted after September 6, 2019, and federal plans, except that the requirements of § 60.23a(a)(1) will apply to a notice of availability of a final guideline document that was published under § 60.22(a). Likewise, the requirements of § 60.27a(e)(1) will refer to a final guideline document that was published under § 60.22(a).
              (b) You must submit a state plan to the EPA by August 29, 2019.
              (c) The following authorities will not be delegated to state, local, or tribal agencies:
              (1) Approval of alternative methods to determine the NMOC concentration or a site-specific methane generation rate constant (k).
              (2) [Reserved]
              [81 FR 59313, Aug. 29, 2016, as amended at 84 FR 44555, Aug. 26, 2019]

              § 60.31f
              Designated facilities.
              (a) The designated facility to which these Emission Guidelines apply is each existing MSW landfill for which construction, reconstruction, or modification was commenced on or before July 17, 2014.

              (b) Physical or operational changes made to an existing MSW landfill solely to comply with an emission guideline are not considered a modification or reconstruction and would not subject an existing MSW landfill to the requirements of a standard of performance for new MSW landfills.
              (c) For purposes of obtaining an operating permit under title V of the Clean Air Act, the owner or operator of an MSW landfill subject to this subpart with a design capacity less than 2.5 million megagrams or 2.5 million cubic meters is not subject to the requirement to obtain an operating permit for the landfill under part 70 or 71 of this chapter, unless the landfill is otherwise subject to either part 70 or 71. For purposes of submitting a timely application for an operating permit under part 70 or 71, the owner or operator of an MSW landfill subject to this subpart with a design capacity greater than or equal to 2.5 million megagrams and 2.5 million cubic meters on the effective date of EPA approval of the state's program under section 111(d) of the Clean Air Act, and not otherwise subject to either part 70 or 71, becomes subject to the requirements of § 70.5(a)(1)(i) or § 71.5(a)(1)(i) of this chapter 90 days after the effective date of such section 111(d) program approval, even if the design capacity report is submitted earlier.
              (d) When an MSW landfill subject to this subpart is closed as defined in this subpart, the owner or operator is no longer subject to the requirement to maintain an operating permit under part 70 or 71 of this chapter for the landfill if the landfill is not otherwise subject to the requirements of either part 70 or 71 and if either of the following conditions are met:
              (1) The landfill was never subject to the requirement to install and operate a gas collection and control system under § 60.33f; or
              (2) The landfill meets the conditions for control system removal specified in § 60.33f(f).
              (e) When an MSW landfill subject to this subpart is in the closed landfill subcategory, the owner or operator is not subject to the following reports of this subpart, provided the owner or operator submitted these reports under the provisions of subpart WWW of this part; 40 CFR part 62, subpart GGG; or a state plan implementing subpart Cc of this part on or before July 17, 2014:
              (1) Initial design capacity report specified in § 60.38f(a).
              (2) Initial or subsequent NMOC emission rate report specified in § 60.38f(c), provided that the most recent NMOC emission rate report indicated the NMOC emissions were below 50 Mg/yr.
              (3) Collection and control system design plan specified in § 60.38f(d).
              (4) Closure report specified in § 60.38f(f).
              (5) Equipment removal report specified in § 60.38f(g).
              (6) Initial annual report specified in § 60.38f(h).
              (7) Initial performance test report in § 60.38f(i).

              § 60.32f
              Compliance times.
              Planning, awarding of contracts, installing, and starting up MSW landfill air emission collection and control equipment that is capable of meeting the Emission Guidelines under § 60.33f must be completed within 30 months after the date an NMOC emission rate report shows NMOC emissions equal or exceed 34 megagrams per year (50 megagrams per year for the closed landfill subcategory); or within 30 months after the date of the most recent NMOC emission rate report that shows NMOC emissions equal or exceed 34 megagrams per year (50 megagrams per year for the closed landfill subcategory), if Tier 4 surface emissions monitoring shows a surface emission concentration of 500 parts per million methane or greater.

              § 60.33f
              Emission Guidelines for municipal solid waste landfill emissions.
              (a) Landfills. For approval, a state plan must require each owner or operator of an MSW landfill having a design capacity greater than or equal to 2.5 million megagrams by mass and 2.5 million cubic meters by volume to collect and control MSW landfill emissions at each MSW landfill that meets the following conditions:
              (1) The landfill has accepted waste at any time since November 8, 1987, or has additional design capacity available for future waste deposition.

              (2) The landfill commenced construction, reconstruction, or modification on or before July 17, 2014.

              (3) The landfill has an NMOC emission rate greater than or equal to 34 megagrams per year or Tier 4 surface emissions monitoring shows a surface emission concentration of 500 parts per million methane or greater.
              (4) The landfill in the closed landfill subcategory and has an NMOC emission rate greater than or equal to 50 megagrams per year or Tier 4 surface emissions monitoring shows a surface emission concentration of 500 parts per million methane or greater.
              (b) Collection system. For approval, a state plan must include provisions for the installation of a gas collection and control system meeting the requirements in paragraphs (b)(1) through (3) and (c) of this section at each MSW landfill meeting the conditions in paragraph (a) of this section.
              (1) Collection system. Install and start up a collection and control system that captures the gas generated within the landfill within 30 months after:
              (i) The first annual report in which the NMOC emission rate equals or exceeds 34 megagrams per year, unless Tier 2 or Tier 3 sampling demonstrates that the NMOC emission rate is less than 34 megagrams per year, as specified in § 60.38f(d)(4); or
              (ii) The first annual NMOC emission rate report for a landfill in the closed landfill subcategory in which the NMOC emission rate equals or exceeds 50 megagrams per year, unless Tier 2 or Tier 3 sampling demonstrates that the NMOC emission rate is less than 50 megagrams per year, as specified in § 60.38f(d)(4); or
              (iii) The most recent NMOC emission rate report in which the NMOC emission rate equals or exceeds 34 megagrams per year based on Tier 2, if the Tier 4 surface emissions monitoring shows a surface methane emission concentration of 500 parts per million methane or greater as specified in § 60.38f(d)(4)(iii).
              (2) Active. An active collection system must:
              (i) Be designed to handle the maximum expected gas flow rate from the entire area of the landfill that warrants control over the intended use period of the gas control system equipment.
              (ii) Collect gas from each area, cell, or group of cells in the landfill in which the initial solid waste has been placed for a period of 5 years or more if active; or 2 years or more if closed or at final grade.
              (iii) Collect gas at a sufficient extraction rate.
              (iv) Be designed to minimize off-site migration of subsurface gas.
              (3) Passive. A passive collection system must:
              (i) Comply with the provisions specified in paragraphs (b)(2)(i), (ii), and (iv) of this section.
              (ii) Be installed with liners on the bottom and all sides in all areas in which gas is to be collected. The liners must be installed as required under § 258.40 of this chapter.
              (c) Control system. For approval, a state plan must include provisions for the control of the gas collected from within the landfill through the use of control devices meeting the following requirements, except as provided in § 60.24.
              (1) A non-enclosed flare designed and operated in accordance with the parameters established in § 60.18 except as noted in § 60.37f(d); or
              (2) A control system designed and operated to reduce NMOC by 98 weight percent; or when an enclosed combustion device is used for control, to either reduce NMOC by 98 weight percent or reduce the outlet NMOC concentration to less than 20 parts per million by volume, dry basis as hexane at 3 percent oxygen or less. The reduction efficiency or concentration in parts per million by volume must be established by an initial performance test to be completed no later than 180 days after the initial startup of the approved control system using the test methods specified in § 60.35f(d). The performance test is not required for boilers and process heaters with design heat input capacities equal to or greater than 44 megawatts that burn landfill gas for compliance with this subpart.

              (i) If a boiler or process heater is used as the control device, the landfill gas stream must be introduced into the flame zone.

              (ii) The control device must be operated within the parameter ranges established during the initial or most recent performance test. The operating parameters to be monitored are specified in § 60.37f.
              (iii) For the closed landfill subcategory, the initial or most recent performance test conducted to comply with subpart WWW of this part; 40 CFR part 62, subpart GGG; or a state plan implementing subpart Cc of this part on or before July 17, 2014 is sufficient for compliance with this subpart.
              (3) Route the collected gas to a treatment system that processes the collected gas for subsequent sale or beneficial use such as fuel for combustion, production of vehicle fuel, production of high-Btu gas for pipeline injection, or use as a raw material in a chemical manufacturing process. Venting of treated landfill gas to the ambient air is not allowed. If the treated landfill gas cannot be routed for subsequent sale or beneficial use, then the treated landfill gas must be controlled according to either paragraph (c)(1) or (2) of this section.
              (4) All emissions from any atmospheric vent from the gas treatment system are subject to the requirements of paragraph (b) or (c) of this section. For purposes of this subpart, atmospheric vents located on the condensate storage tank are not part of the treatment system and are exempt from the requirements of paragraph (b) or (c) of this section.
              (d) Design capacity. For approval, a state plan must require each owner or operator of an MSW landfill having a design capacity less than 2.5 million megagrams by mass or 2.5 million cubic meters by volume to submit an initial design capacity report to the Administrator as provided in § 60.38f(a). The landfill may calculate design capacity in either megagrams or cubic meters for comparison with the exemption values. Any density conversions must be documented and submitted with the report. Submittal of the initial design capacity report fulfills the requirements of this subpart except as provided in paragraphs (d)(1) and (2) of this section.

              (1) The owner or operator must submit an amended design capacity report as provided in § 60.38f(b).

                Note to paragraph (d)(1):
                Note that if the design capacity increase is the result of a modification, as defined in this subpart, that was commenced after July 17, 2014, then the landfill becomes subject to subpart XXX of this part instead of this subpart. If the design capacity increase is the result of a change in operating practices, density, or some other change that is not a modification as defined in this subpart, then the landfill remains subject to this subpart.

              (2) When an increase in the maximum design capacity of a landfill with an initial design capacity less than 2.5 million megagrams or 2.5 million cubic meters results in a revised maximum design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters, the owner or operator must comply with paragraph (e) of this section.
              (e) Emissions. For approval, a state plan must require each owner or operator of an MSW landfill having a design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters to either install a collection and control system as provided in paragraphs (b) and (c) of this section or calculate an initial NMOC emission rate for the landfill using the procedures specified in § 60.35f(a). The NMOC emission rate must be recalculated annually, except as provided in § 60.38f(c)(3).
              (1) If the calculated NMOC emission rate is less than 34 megagrams per year, the owner or operator must:
              (i) Submit an annual NMOC emission rate report according to § 60.38f(c), except as provided in § 60.38f(c)(3); and
              (ii) Recalculate the NMOC emission rate annually using the procedures specified in § 60.35f(a) until such time as the calculated NMOC emission rate is equal to or greater than 34 megagrams per year, or the landfill is closed.

              (A) If the calculated NMOC emission rate, upon initial calculation or annual recalculation required in paragraph (e)(1)(ii) of this section, is equal to or greater than 34 megagrams per year, the owner or operator must either: Comply with paragraphs (b) and (c) of this section; calculate NMOC emissions using the next higher tier in § 60.35f; or conduct a surface emission monitoring demonstration using the procedures specified in § 60.35f(a)(6).
              (B) If the landfill is permanently closed, a closure report must be submitted to the Administrator as provided in § 60.38f(f), except for exemption allowed under § 60.31f(e)(4).
              (C) For the closed landfill subcategory, if the most recently calculated NMOC emission rate is equal to or greater than 50 megagrams per year, the owner or operator must either: Submit a gas collection and control system design plan as specified in § 60.38f(d), except for exemptions allowed under § 60.31f(e)(3), and install a collection and control system as provided in paragraphs (b) and (c) of this section; calculate NMOC emissions using the next higher tier in § 60.35f; or conduct a surface emission monitoring demonstration using the procedures specified in § 60.35f(a)(6).
              (2) If the calculated NMOC emission rate is equal to or greater than 34 megagrams per year using Tier 1, 2, or 3 procedures, the owner or operator must either: submit a collection and control system design plan prepared by a professional engineer to the Administrator within 1 year as specified in § 60.38f(d), except for exemptions allowed under § 60.31f(e)(3); calculate NMOC emissions using a higher tier in § 60.35f; or conduct a surface emission monitoring demonstration using the procedures specified in § 60.35f(a)(6).
              (3) For the closed landfill subcategory, if the calculated NMOC emission rate is equal to or greater than 50 megagrams per year using Tier 1, 2, or 3 procedures, the owner or operator must either: Submit a collection and control system design plan as specified in § 60.38f(d), except for exemptions allowed under § 60.31f(e)(3); calculate NMOC emissions using a higher tier in § 60.35f; or conduct a surface emission monitoring demonstration using the procedures specified in § 60.35f(a)(6).
              (f) Removal criteria. The collection and control system may be capped, removed, or decommissioned if the following criteria are met:
              (1) The landfill is a closed landfill (as defined in § 60.41f). A closure report must be submitted to the Administrator as provided in § 60.38f(f).
              (2) The collection and control system has been in operation a minimum of 15 years or the landfill owner or operator demonstrates that the GCCS will be unable to operate for 15 years due to declining gas flow.
              (3) Following the procedures specified in § 60.35f(b), the calculated NMOC emission rate at the landfill is less than 34 megagrams per year on three successive test dates. The test dates must be no less than 90 days apart, and no more than 180 days apart.
              (4) For the closed landfill subcategory (as defined in § 60.41), following the procedures specified in § 60.35f(b), the calculated NMOC emission rate at the landfill is less than 50 megagrams per year on three successive test dates. The test dates must be no less than 90 days apart, and no more than 180 days apart.

              § 60.34f
              Operational standards for collection and control systems.
              For approval, a state plan must include provisions for the operational standards in this section (as well as the provisions in §§ 60.36f and 60.37f), or the operational standards in § 63.1958 of this chapter (as well as the provisions in §§ 63.1960 of this chapter and 63.1961 of this chapter), or both as alternative means of compliance, for an MSW landfill with a gas collection and control system used to comply with the provisions of § 60.33f(b) and (c). Once the owner or operator begins to comply with the provisions of § 63.1958 of this chapter, the owner or operator must continue to operate the collection and control device according to those provisions and cannot return to the provisions of this section. Each owner or operator of an MSW landfill with a gas collection and control system used to comply with the provisions of § 60.33f(b) and (c) must:
              (a) Operate the collection system such that gas is collected from each area, cell, or group of cells in the MSW landfill in which solid waste has been in place for:
              (1) Five (5) years or more if active; or

              (2) Two (2) years or more if closed or at final grade.

              (b) Operate the collection system with negative pressure at each wellhead except under the following conditions:
              (1) A fire or increased well temperature. The owner or operator must record instances when positive pressure occurs in efforts to avoid a fire. These records must be submitted with the annual reports as provided in § 60.38f(h)(1).
              (2) Use of a geomembrane or synthetic cover. The owner or operator must develop acceptable pressure limits in the design plan.
              (3) A decommissioned well. A well may experience a static positive pressure after shut down to accommodate for declining flows. All design changes must be approved by the Administrator as specified in § 60.38f(d).

              (c) Operate each interior wellhead in the collection system with a landfill gas temperature less than 55 degrees Celsius (131 degrees Fahrenheit). The owner or operator may establish a higher operating temperature value at a particular well. A higher operating value demonstration must be submitted to the Administrator for approval and must include supporting data demonstrating that the elevated parameter neither causes fires nor significantly inhibits anaerobic decomposition by killing methanogens. The demonstration must satisfy both criteria in order to be approved (i.e., neither causing fires nor killing methanogens is acceptable).
              (d) Operate the collection system so that the methane concentration is less than 500 parts per million above background at the surface of the landfill. To determine if this level is exceeded, the owner or operator must conduct surface testing using an organic vapor analyzer, flame ionization detector, or other portable monitor meeting the specifications provided in § 60.36(d). The owner or operator must conduct surface testing around the perimeter of the collection area and along a pattern that traverses the landfill at no more than 30-meter intervals and where visual observations indicate elevated concentrations of landfill gas, such as distressed vegetation and cracks or seeps in the cover and all cover penetrations. Thus, the owner or operator must monitor any openings that are within an area of the landfill where waste has been placed and a gas collection system is required. The owner or operator may establish an alternative traversing pattern that ensures equivalent coverage. A surface monitoring design plan must be developed that includes a topographical map with the monitoring route and the rationale for any site-specific deviations from the 30-meter intervals. Areas with steep slopes or other dangerous areas may be excluded from the surface testing.
              (e) Operate the system such that all collected gases are vented to a control system designed and operated in compliance with § 60.33f(c). In the event the collection or control system is not operating, the gas mover system must be shut down and all valves in the collection and control system contributing to venting of the gas to the atmosphere must be closed within 1 hour of the collection or control system not operating.
              (f) Operate the control system at all times when the collected gas is routed to the system.
              (g) If monitoring demonstrates that the operational requirements in paragraph (b), (c), or (d) of this section are not met, corrective action must be taken as specified in § 60.36f(a)(3) and (5) or (c). If corrective actions are taken as specified in § 60.36f, the monitored exceedance is not a violation of the operational requirements in this section.
              [81 FR 59313, Aug. 29, 2016, as amended at 85 FR 17259, Mar. 26, 2020]

              § 60.35f
              Test methods and procedures.
              For approval, a state plan must include provisions in this section to calculate the landfill NMOC emission rate or to conduct a surface emission monitoring demonstration.
              (a)(1) NMOC Emission Rate. The landfill owner or operator must calculate the NMOC emission rate using either Equation 1 provided in paragraph (a)(1)(i) of this section or Equation 2 provided in paragraph (a)(1)(ii) of this section. Both Equation 1 and Equation 2 may be used if the actual year-to-year solid waste acceptance rate is known, as specified in paragraph (a)(1)(i) of this section, for part of the life of the landfill and the actual year-to-year solid waste acceptance rate is unknown, as specified in paragraph (a)(1)(ii) of this section, for part of the life of the landfill. The values to be used in both Equation 1 and Equation 2 are 0.05 per year for k, 170 cubic meters per megagram for Lo, and 4,000 parts per million by volume as hexane for the CNMOC. For landfills located in geographical areas with a 30-year annual average precipitation of less than 25 inches, as measured at the nearest representative official meteorologic site, the k value to be used is 0.02 per year.
              (i)(A) Equation 1 must be used if the actual year-to-year solid waste acceptance rate is known.

                ER29AU16.000

                Where:

                MNMOC = Total NMOC emission rate from the landfill, megagrams per year.
                k = Methane generation rate constant, year−1.
                Lo = Methane generation potential, cubic meters per megagram solid waste.
                Mi = Mass of solid waste in the ith section, megagrams.
                ti = Age of the ith section, years.
                CNMOC = Concentration of NMOC, parts per million by volume as hexane.
                3.6 × 10−9 = Conversion factor.

              (B) The mass of nondegradable solid waste may be subtracted from the total mass of solid waste in a particular section of the landfill when calculating the value for Mi if documentation of the nature and amount of such wastes is maintained.
              (ii)(A) Equation 2 must be used if the actual year-to-year solid waste acceptance rate is unknown.

                ER29AU16.001

                Where:

                MNMOC = Mass emission rate of NMOC, megagrams per year.
                Lo = Methane generation potential, cubic meters per megagram solid waste.
                R = Average annual acceptance rate, megagrams per year.
                k = Methane generation rate constant, year −1.
                t = Age of landfill, years.
                CNMOC = Concentration of NMOC, parts per million by volume as hexane.

                c = Time since closure, years; for an active landfill c = 0 and e−kc = 1.
                3.6 × 10−9 = Conversion factor.

              (B) The mass of nondegradable solid waste may be subtracted from the total mass of solid waste in a particular section of the landfill when calculating the value of R, if documentation of the nature and amount of such wastes is maintained.
              (2) Tier 1. The owner or operator must compare the calculated NMOC mass emission rate to the standard of 34 megagrams per year.
              (i) If the NMOC emission rate calculated in paragraph (a)(1) of this section is less than 34 megagrams per year, then the owner or operator must submit an NMOC emission rate report according to § 60.38f(c), and must recalculate the NMOC mass emission rate annually as required under § 60.33f(e).
              (ii) If the NMOC emission rate calculated in paragraph (a)(1) of this section is equal to or greater than 34 megagrams per year, then the landfill owner or operator must either:
              (A) Submit a gas collection and control system design plan within 1 year as specified in § 60.38f(d) and install and operate a gas collection and control system within 30 months according to § 60.33f(b) and (c);
              (B) Determine a site-specific NMOC concentration and recalculate the NMOC emission rate using the Tier 2 procedures provided in paragraph (a)(3) of this section; or

              (C) Determine a site-specific methane generation rate constant and recalculate the NMOC emission rate using the Tier 3 procedures provided in paragraph (a)(4) of this section.

              (3) Tier 2. The landfill owner or operator must determine the site-specific NMOC concentration using the following sampling procedure. The landfill owner or operator must install at least two sample probes per hectare, evenly distributed over the landfill surface that has retained waste for at least 2 years. If the landfill is larger than 25 hectares in area, only 50 samples are required. The probes should be evenly distributed across the sample area. The sample probes should be located to avoid known areas of nondegradable solid waste. The owner or operator must collect and analyze one sample of landfill gas from each probe to determine the NMOC concentration using Method 25 or 25C of appendix A of this part. Taking composite samples from different probes into a single cylinder is allowed; however, equal sample volumes must be taken from each probe. For each composite, the sampling rate, collection times, beginning and ending cylinder vacuums, or alternative volume measurements must be recorded to verify that composite volumes are equal. Composite sample volumes should not be less than one liter unless evidence can be provided to substantiate the accuracy of smaller volumes. Terminate compositing before the cylinder approaches ambient pressure where measurement accuracy diminishes. If more than the required number of samples is taken, all samples must be used in the analysis. The landfill owner or operator must divide the NMOC concentration from Method 25 or 25C by six to convert from CNMOC as carbon to CNMOC as hexane. If the landfill has an active or passive gas removal system in place, Method 25 or 25C samples may be collected from these systems instead of surface probes provided the removal system can be shown to provide sampling as representative as the two sampling probe per hectare requirement. For active collection systems, samples may be collected from the common header pipe. The sample location on the common header pipe must be before any gas moving, condensate removal, or treatment system equipment. For active collection systems, a minimum of three samples must be collected from the header pipe.
              (i) Within 60 days after the date of determining the NMOC concentration and corresponding NMOC emission rate, the owner or operator must submit the results according to § 60.38f(j)(2).
              (ii) The landfill owner or operator must recalculate the NMOC mass emission rate using Equation 1 or Equation 2 provided in paragraph (a)(1)(i) or (ii) of this section using the average site-specific NMOC concentration from the collected samples instead of the default value provided in paragraph (a)(1) of this section.
              (iii) If the resulting NMOC mass emission rate is less than 34 megagrams per year, then the owner or operator must submit a periodic estimate of NMOC emissions in an NMOC emission rate report according to § 60.38f(c), and must recalculate the NMOC mass emission rate annually as required under § 60.33f(e). The site-specific NMOC concentration must be retested every 5 years using the methods specified in this section.
              (iv) If the NMOC mass emission rate as calculated using the Tier 2 site-specific NMOC concentration is equal to or greater than 34 megagrams per year, the owner or operator must either:
              (A) Submit a gas collection and control system design plan within 1 year as specified in § 60.38f(d) and install and operate a gas collection and control system within 30 months according to § 60.33f(b) and (c);
              (B) Determine a site-specific methane generation rate constant and recalculate the NMOC emission rate using the site-specific methane generation rate using the Tier 3 procedures specified in paragraph (a)(4) of this section; or
              (C) Conduct a surface emission monitoring demonstration using the Tier 4 procedures specified in paragraph (a)(6) of this section.
              (4) Tier 3. The site-specific methane generation rate constant must be determined using the procedures provided in Method 2E of appendix A of this part. The landfill owner or operator must estimate the NMOC mass emission rate using Equation 1 or Equation 2 in paragraph (a)(1)(i) or (ii) of this section and using a site-specific methane generation rate constant, and the site-specific NMOC concentration as determined in paragraph (a)(3) of this section instead of the default values provided in paragraph (a)(1) of this section. The landfill owner or operator must compare the resulting NMOC mass emission rate to the standard of 34 megagrams per year.
              (i) If the NMOC mass emission rate as calculated using the Tier 2 site-specific NMOC concentration and Tier 3 site-specific methane generation rate is equal to or greater than 34 megagrams per year, the owner or operator must either:
              (A) Submit a gas collection and control system design plan within 1 year as specified in § 60.38f(d) and install and operate a gas collection and control system within 30 months according to § 60.33f(b) and (c); or
              (B) Conduct a surface emission monitoring demonstration using the Tier 4 procedures specified in paragraph (a)(6) of this section.
              (ii) If the NMOC mass emission rate is less than 34 megagrams per year, then the owner or operator must recalculate the NMOC mass emission rate annually using Equation 1 or Equation 2 in paragraph (a)(1) of this section and using the site-specific Tier 2 NMOC concentration and Tier 3 methane generation rate constant and submit a periodic NMOC emission rate report as provided in § 60.38f(c). The calculation of the methane generation rate constant is performed only once, and the value obtained from this test must be used in all subsequent annual NMOC emission rate calculations.
              (5) Other methods. The owner or operator may use other methods to determine the NMOC concentration or a site-specific methane generation rate constant as an alternative to the methods required in paragraphs (a)(3) and (4) of this section if the method has been approved by the Administrator.
              (6) Tier 4. The landfill owner or operator must demonstrate that surface methane emissions are below 500 parts per million. Surface emission monitoring must be conducted on a quarterly basis using the following procedures. Tier 4 is allowed only if the landfill owner or operator can demonstrate that NMOC emissions are greater than or equal to 34 Mg/yr but less than 50 Mg/yr using Tier 1 or Tier 2. If both Tier 1 and Tier 2 indicate NMOC emissions are 50 Mg/yr or greater, then Tier 4 cannot be used. In addition, the landfill must meet the criteria in paragraph (a)(6)(viii) of this section.
              (i) The owner or operator must measure surface concentrations of methane along the entire perimeter of the landfill and along a pattern that traverses the landfill at no more than 30-meter intervals using an organic vapor analyzer, flame ionization detector, or other portable monitor meeting the specifications provided in § 60.36f(d).
              (ii) The background concentration must be determined by moving the probe inlet upwind and downwind at least 30 meters from the waste mass boundary of the landfill.
              (iii) Surface emission monitoring must be performed in accordance with section 8.3.1 of Method 21 of appendix A of this part, except that the probe inlet must be placed no more than 5 centimeters above the landfill surface; the constant measurement of distance above the surface should be based on a mechanical device such as with a wheel on a pole.
              (A) The owner or operator must use a wind barrier, similar to a funnel, when onsite average wind speed exceeds 4 miles per hour or 2 meters per second or gust exceeding 10 miles per hour. Average on-site wind speed must also be determined in an open area at 5-minute intervals using an on-site anemometer with a continuous recorder and data logger for the entire duration of the monitoring event. The wind barrier must surround the SEM monitor, and must be placed on the ground, to ensure wind turbulence is blocked. SEM cannot be conducted if average wind speed exceeds 25 miles per hour.
              (B) Landfill surface areas where visual observations indicate elevated concentrations of landfill gas, such as distressed vegetation and cracks or seeps in the cover, and all cover penetrations must also be monitored using a device meeting the specifications provided in § 60.36f(d).

              (iv) Each owner or operator seeking to comply with the Tier 4 provisions in paragraph (a)(6) of this section must maintain records of surface emission monitoring as provided in § 60.39f(g) and submit a Tier 4 surface emissions report as provided in § 60.38f(d)(4)(iii).
              (v) If there is any measured concentration of methane of 500 parts per million or greater from the surface of the landfill, the owner or operator must submit a gas collection and control system design plan within 1 year of the first measured concentration of methane of 500 parts per million or greater from the surface of the landfill according to § 60.38f(d) and install and operate a gas collection and control system according to § 60.33f(b) and (c) within 30 months of the most recent NMOC emission rate report in which the NMOC emission rate equals or exceeds 34 megagrams per year based on Tier 2.
              (vi) If after four consecutive quarterly monitoring periods at a landfill, other than a closed landfill, there is no measured concentration of methane of 500 parts per million or greater from the surface of the landfill, the owner or operator must continue quarterly surface emission monitoring using the methods specified in this section.
              (vii) If after four consecutive quarterly monitoring periods at a closed landfill there is no measured concentration of methane of 500 parts per million or greater from the surface of the landfill, the owner or operator must conduct annual surface emission monitoring using the methods specified in this section.
              (viii) If a landfill has installed and operates a collection and control system that is not required by this subpart, then the collection and control system must meet the following criteria:
              (A) The gas collection and control system must have operated for at least 6,570 out of 8,760 hours preceding the Tier 4 surface emissions monitoring demonstration.
              (B) During the Tier 4 surface emissions monitoring demonstration, the gas collection and control system must operate as it normally would to collect and control as much landfill gas as possible.
              (b) After the installation and startup of a collection and control system in compliance with this subpart, the owner or operator must calculate the NMOC emission rate for purposes of determining when the system can be capped, removed, or decommissioned as provided in § 60.33f(f), using Equation 3:

                ER29AU16.002

                Where:

                MNMOC = Mass emission rate of NMOC, megagrams per year.
                QLFG = Flow rate of landfill gas, cubic meters per minute.
                CNMOC = NMOC concentration, parts per million by volume as hexane.

              (1) The flow rate of landfill gas, QLFG, must be determined by measuring the total landfill gas flow rate at the common header pipe that leads to the control system using a gas flow measuring device calibrated according to the provisions of section 10 of Method 2E of appendix A of this part.
              (2) The average NMOC concentration, CNMOC, must be determined by collecting and analyzing landfill gas sampled from the common header pipe before the gas moving or condensate removal equipment using the procedures in Method 25 or Method 25C of appendix A of this part. The sample location on the common header pipe must be before any condensate removal or other gas refining units. The landfill owner or operator must divide the NMOC concentration from Method 25 or Method 25C by six to convert from CNMOC as carbon to CNMOC as hexane.
              (3) The owner or operator may use another method to determine landfill gas flow rate and NMOC concentration if the method has been approved by the Administrator.
              (i) Within 60 days after the date of calculating the NMOC emission rate for purposes of determining when the system can be capped or removed, the owner or operator must submit the results according to § 60.38f(j)(2).
              (ii) [Reserved]

              (c) When calculating emissions for Prevention of Significant Deterioration purposes, the owner or operator of each MSW landfill subject to the provisions of this subpart must estimate the NMOC emission rate for comparison to the Prevention of Significant Deterioration major source and significance levels in § 51.166 or § 52.21 of this chapter using Compilation of Air Pollutant Emission Factors, Volume I: Stationary Point and Area Sources (AP-42) or other approved measurement procedures.
              (d) For the performance test required in § 60.33f(c)(1), the net heating value of the combusted landfill gas as determined in § 60.18(f)(3) is calculated from the concentration of methane in the landfill gas as measured by Method 3C. A minimum of three 30-minute Method 3C samples are determined. The measurement of other organic components, hydrogen, and carbon monoxide is not applicable. Method 3C may be used to determine the landfill gas molecular weight for calculating the flare gas exit velocity under § 60.18(f)(4).
              (1) Within 60 days after the date of completing each performance test (as defined in § 60.8), the owner or operator must submit the results of the performance tests required by paragraph (b) or (d) of this section, including any associated fuel analyses, according to § 60.38f(j)(1).
              (2) [Reserved]

              (e) For the performance test required in § 60.33f(c)(2), Method 25 or 25C (Method 25C may be used at the inlet only) of appendix A of this part must be used to determine compliance with the 98 weight-percent efficiency or the 20 parts per million by volume outlet NMOC concentration level, unless another method to demonstrate compliance has been approved by the Administrator as provided by § 60.38f(d)(2). Method 3, 3A, or 3C must be used to determine oxygen for correcting the NMOC concentration as hexane to 3 percent. In cases where the outlet concentration is less than 50 ppm NMOC as carbon (8 ppm NMOC as hexane), Method 25A should be used in place of Method 25. Method 18 may be used in conjunction with Method 25A on a limited basis (compound specific, e.g., methane) or Method 3C may be used to determine methane. The methane as carbon should be subtracted from the Method 25A total hydrocarbon value as carbon to give NMOC concentration as carbon. The landfill owner or operator must divide the NMOC concentration as carbon by 6 to convert the CNMOC as carbon to CNMOC as hexane. Equation 4 must be used to calculate efficiency:

                ER29AU16.003

                Where:

                NMOCin = Mass of NMOC entering control device.
                NMOCout = Mass of NMOC exiting control device.

              (1) Within 60 days after the date of completing each performance test (as defined in § 60.8), the owner or operator must submit the results of the performance tests, including any associated fuel analyses, according to § 60.38f(j)(1).
              (2) [Reserved]

              § 60.36f
              Compliance provisions.
              For approval, a state plan must include the compliance provisions in this section (as well as the provisions in §§ 60.34f and 60.37f), or the compliance provisions in § 63.1960 of this chapter (as well as the provisions in §§ 63.1958 of this chapter and 63.1961 of this chapter), or both as alternative means of compliance, for an MSW landfill with a gas collection and control system used to comply with the provisions of § 60.33f(b) and (c). Once the owner or operator begins to comply with the provisions of § 63.1960 of this chapter, the owner or operator must continue to operate the collection and control device according to those provisions and cannot return to the provisions of this section.

              (a) Except as provided in § 60.38f(d)(2), the specified methods in paragraphs (a)(1) through (6) of this section must be used to determine whether the gas collection system is in compliance with § 60.33f(b)(2).

              (1) For the purposes of calculating the maximum expected gas generation flow rate from the landfill to determine compliance with § 60.33f(b)(2)(i), either Equation 5 or Equation 6 in paragraph (a)(1)(i) or (ii) of this section must be used. The methane generation rate constant (k) and methane generation potential (Lo) kinetic factors should be those published in the most recent AP-42 or other site-specific values demonstrated to be appropriate and approved by the Administrator. If k has been determined as specified in § 60.35f(a)(4), the value of k determined from the test must be used. A value of no more than 15 years must be used for the intended use period of the gas mover equipment. The active life of the landfill is the age of the landfill plus the estimated number of years until closure.
              (i) For sites with unknown year-to-year solid waste acceptance rate:

                ER29AU16.004

                Where:

                Qm = Maximum expected gas generation flow rate, cubic meters per year.
                Lo = Methane generation potential, cubic meters per megagram solid waste.
                R = Average annual acceptance rate, megagrams per year.
                k = Methane generation rate constant, year−1.
                t = Age of the landfill at equipment installation plus the time the owner or operator intends to use the gas mover equipment or active life of the landfill, whichever is less. If the equipment is installed after closure, t is the age of the landfill at installation, years.

                c = Time since closure, years (for an active landfill c = 0 and e−kc = 1).

              (ii) For sites with known year-to-year solid waste acceptance rate:

                ER29AU16.005

                Where:

                QM = Maximum expected gas generation flow rate, cubic meters per year.
                k = Methane generation rate constant, year−1.
                Lo = Methane generation potential, cubic meters per megagram solid waste.
                Mi = Mass of solid waste in the ith section, megagrams.
                ti = Age of the ith section, years.

              (iii) If a collection and control system has been installed, actual flow data may be used to project the maximum expected gas generation flow rate instead of, or in conjunction with, Equation 5 or Equation 6 in paragraph (a)(1)(i) or (ii) of this section. If the landfill is still accepting waste, the actual measured flow data will not equal the maximum expected gas generation rate, so calculations using Equation 5 or Equation 6 or other methods must be used to predict the maximum expected gas generation rate over the intended period of use of the gas control system equipment.
              (2) For the purposes of determining sufficient density of gas collectors for compliance with § 60.33f(b)(2)(ii), the owner or operator must design a system of vertical wells, horizontal collectors, or other collection devices, satisfactory to the Administrator, capable of controlling and extracting gas from all portions of the landfill sufficient to meet all operational and performance standards.

              (3) For the purpose of demonstrating whether the gas collection system flow rate is sufficient to determine compliance with § 60.33f(b)(2)(iii), the owner or operator must measure gauge pressure in the gas collection header applied to each individual well monthly. If a positive pressure exists, action must be initiated to correct the exceedance within 5 calendar days, except for the three conditions allowed under § 60.34f(b). Any attempted corrective measure must not cause exceedances of other operational or performance standards.
              (i) If negative pressure cannot be achieved without excess air infiltration within 15 calendar days of the first measurement of positive pressure, the owner or operator must conduct a root cause analysis and correct the exceedance as soon as practicable, but not later than 60 days after positive pressure was first measured. The owner or operator must keep records according to § 60.39f(e)(3).
              (ii) If corrective actions cannot be fully implemented within 60 days following the positive pressure or elevated temperature measurement for which the root cause analysis was required, the owner or operator must also conduct a corrective action analysis and develop an implementation schedule to complete the corrective action(s) as soon as practicable, but no more than 120 days following the measurement of landfill gas temperature greater than 55 degrees Celsius (131 degrees Fahrenheit) or positive pressure. The owner or operator must submit the items listed in § 60.38f(h)(7) as part of the next annual report. The owner or operator must keep records according to § 60.39f(e)(4).
              (iii) If corrective action is expected to take longer than 120 days to complete after the initial exceedance, the owner or operator must submit the root cause analysis, corrective action analysis, and corresponding implementation timeline to the Administrator, according to § 60.38f(h)(7) and (k). The owner or operator must keep records according to § 60.39f(e)(5).
              (4) [Reserved]
              (5) For the purpose of identifying whether excess air infiltration into the landfill is occurring, the owner or operator must monitor each well monthly for temperature as provided in § 60.34f(c). If a well exceeds the operating parameter for temperature, action must be initiated to correct the exceedance within 5 calendar days. Any attempted corrective measure must not cause exceedances of other operational or performance standards.
              (i) If a landfill gas temperature less than 55 degrees Celsius (131 degrees Fahrenheit) cannot be achieved within 15 calendar days of the first measurement of landfill gas temperature greater than 55 degrees Celsius (131 degrees Fahrenheit), the owner or operator must conduct a root cause analysis and correct the exceedance as soon as practicable, but no later than 60 days after a landfill gas temperature greater than 55 degrees Celsius (131 degrees Fahrenheit) was first measured. The owner or operator must keep records according to § 60.39f(e)(3).
              (ii) If corrective actions cannot be fully implemented within 60 days following the positive pressure measurement for which the root cause analysis was required, the owner or operator must also conduct a corrective action analysis and develop an implementation schedule to complete the corrective action(s) as soon as practicable, but no more than 120 days following the measurement of landfill gas temperature greater than 55 degrees Celsius (131 degrees Fahrenheit). The owner or operator must submit the items listed in § 60.38f(h)(7) as part of the next annual report. The owner or operator must keep records according to § 60.39f(e)(4).
              (iii) If corrective action is expected to take longer than 120 days to complete after the initial exceedance, the owner or operator must submit the root cause analysis, corrective action analysis, and corresponding implementation timeline to the Administrator, according to § 60.38f(h)(7) and (k). The owner or operator must keep records according to § 60.39f(e)(5).
              (6) An owner or operator seeking to demonstrate compliance with § 60.33f(b)(2)(iv) through the use of a collection system not conforming to the specifications provided in § 60.40f must provide information satisfactory to the Administrator as specified in § 60.38f(d)(3) demonstrating that off-site migration is being controlled.

              (b) For purposes of compliance with § 60.34f(a), each owner or operator of a controlled landfill must place each well or design component as specified in the approved design plan as provided in § 60.38f(d). Each well must be installed no later than 60 days after the date on which the initial solid waste has been in place for a period of:
              (1) Five (5) years or more if active; or
              (2) Two (2) years or more if closed or at final grade.
              (c) The following procedures must be used for compliance with the surface methane operational standard as provided in § 60.34f(d):
              (1) After installation and startup of the gas collection system, the owner or operator must monitor surface concentrations of methane along the entire perimeter of the collection area and along a pattern that traverses the landfill at no more than 30-meter intervals (or a site-specific established spacing) for each collection area on a quarterly basis using an organic vapor analyzer, flame ionization detector, or other portable monitor meeting the specifications provided in paragraph (d) of this section.
              (2) The background concentration must be determined by moving the probe inlet upwind and downwind outside the boundary of the landfill at a distance of at least 30 meters from the perimeter wells.
              (3) Surface emission monitoring must be performed in accordance with section 8.3.1 of Method 21 of appendix A of this part, except that the probe inlet must be placed within 5 to 10 centimeters of the ground. Monitoring must be performed during typical meteorological conditions.
              (4) Any reading of 500 parts per million or more above background at any location must be recorded as a monitored exceedance and the actions specified in paragraphs (c)(4)(i) through (v) of this section must be taken. As long as the specified actions are taken, the exceedance is not a violation of the operational requirements of § 60.34f(d).
              (i) The location of each monitored exceedance must be marked and the location and concentration recorded. For location, you must determine the latitude and longitude coordinates using an instrument with an accuracy of at least 4 meters. The coordinates must be in decimal degrees with at least five decimal places.
              (ii) Cover maintenance or adjustments to the vacuum of the adjacent wells to increase the gas collection in the vicinity of each exceedance must be made and the location must be re-monitored within 10 calendar days of detecting the exceedance.
              (iii) If the re-monitoring of the location shows a second exceedance, additional corrective action must be taken and the location must be monitored again within 10 days of the second exceedance. If the re-monitoring shows a third exceedance for the same location, the action specified in paragraph (c)(4)(v) of this section must be taken, and no further monitoring of that location is required until the action specified in paragraph (c)(4)(v) of this section has been taken.
              (iv) Any location that initially showed an exceedance but has a methane concentration less than 500 parts per million methane above background at the 10-day re-monitoring specified in paragraph (c)(4)(ii) or (iii) of this section must be re-monitored 1 month from the initial exceedance. If the 1-month re-monitoring shows a concentration less than 500 parts per million above background, no further monitoring of that location is required until the next quarterly monitoring period. If the 1-month re-monitoring shows an exceedance, the actions specified in paragraph (c)(4)(iii) or (v) of this section must be taken.
              (v) For any location where monitored methane concentration equals or exceeds 500 parts per million above background three times within a quarterly period, a new well or other collection device must be installed within 120 calendar days of the initial exceedance. An alternative remedy to the exceedance, such as upgrading the blower, header pipes or control device, and a corresponding timeline for installation may be submitted to the Administrator for approval.
              (5) The owner or operator must implement a program to monitor for cover integrity and implement cover repairs as necessary on a monthly basis.

              (d) Each owner or operator seeking to comply with the provisions in paragraph (c) of this section or § 60.35f(a)(6) must comply with the following instrumentation specifications and procedures for surface emission monitoring devices:
              (1) The portable analyzer must meet the instrument specifications provided in section 6 of Method 21 of appendix A of this part, except that “methane” replaces all references to “VOC”.
              (2) The calibration gas must be methane, diluted to a nominal concentration of 500 parts per million in air.
              (3) To meet the performance evaluation requirements in section 8.1 of Method 21 of appendix A of this part, the instrument evaluation procedures of section 8.1 of Method 21 must be used.
              (4) The calibration procedures provided in sections 8 and 10 of Method 21 of appendix A of this part must be followed immediately before commencing a surface monitoring survey.
              (e) The provisions of this subpart apply at all times, including periods of startup, shutdown, or malfunction. During periods of startup, shutdown, and malfunction, you must comply with the work practice specified in § 60.34f(e) in lieu of the compliance provisions in § 60.36f.
              [81 FR 59313, Aug. 29, 2016, as amended at 85 FR 17259, Mar. 26, 2020]

              § 60.37f
              Monitoring of operations.
              For approval, a state plan must include the monitoring provisions in this section, (as well as the provisions in §§ 60.34f and 60.36f) except as provided in § 60.38f(d)(2), or the monitoring provisions in § 63.1961 of this chapter (as well as the provisions in §§ 63.1958 of this chapter and 63.1960 of this chapter), or both as alternative means of compliance, for an MSW landfill with a gas collection and control system used to comply with the provisions of § 60.33f(b) and (c). Once the owner or operator begins to comply with the provisions of § 63.1961 of this chapter, the owner or operator must continue to operate the collection and control device according to those provisions and cannot return to the provisions of this section.
              (a) Each owner or operator seeking to comply with § 60.33f(b)(2) for an active gas collection system must install a sampling port and a thermometer, other temperature measuring device, or an access port for temperature measurements at each wellhead and:
              (1) Measure the gauge pressure in the gas collection header on a monthly basis as provided in § 60.36f(a)(3); and
              (2) Monitor nitrogen or oxygen concentration in the landfill gas on a monthly basis as follows:
              (i) The nitrogen level must be determined using Method 3C, unless an alternative test method is established as allowed by § 60.38f(d)(2).
              (ii) Unless an alternative test method is established as allowed by § 60.38f(d)(2), the oxygen level must be determined by an oxygen meter using Method 3A, 3C, or ASTM D6522-11 (incorporated by reference, see § 60.17). Determine the oxygen level by an oxygen meter using Method 3A, 3C, or ASTM D6522-11 (if sample location is prior to combustion) except that:
              (A) The span must be set between 10 and 12 percent oxygen;
              (B) A data recorder is not required;
              (C) Only two calibration gases are required, a zero and span;
              (D) A calibration error check is not required; and
              (E) The allowable sample bias, zero drift, and calibration drift are ±10 percent.
              (iii) A portable gas composition analyzer may be used to monitor the oxygen levels provided:
              (A) The analyzer is calibrated; and
              (B) The analyzer meets all quality assurance and quality control requirements for Method 3A or ASTM D6522-11 (incorporated by reference, see § 60.17).
              (3) Monitor temperature of the landfill gas on a monthly basis as provided in § 60.36f(a)(5). The temperature measuring device must be calibrated annually using the procedure in this part 60, appendix A-1, Method 2, Section 10.3.
              (b) Each owner or operator seeking to comply with § 60.33f(c) using an enclosed combustor must calibrate, maintain, and operate according to the manufacturer's specifications, the following equipment:

              (1) A temperature monitoring device equipped with a continuous recorder and having a minimum accuracy of ±1 percent of the temperature being measured expressed in degrees Celsius or ±0.5 degrees Celsius, whichever is greater. A temperature monitoring device is not required for boilers or process heaters with design heat input capacity equal to or greater than 44 megawatts.
              (2) A device that records flow to the control device and bypass of the control device (if applicable). The owner or operator must:
              (i) Install, calibrate, and maintain a gas flow rate measuring device that must record the flow to the control device at least every 15 minutes; and
              (ii) Secure the bypass line valve in the closed position with a car-seal or a lock-and-key type configuration. A visual inspection of the seal or closure mechanism must be performed at least once every month to ensure that the valve is maintained in the closed position and that the gas flow is not diverted through the bypass line.
              (c) Each owner or operator seeking to comply with § 60.33f(c) using a non-enclosed flare must install, calibrate, maintain, and operate according to the manufacturer's specifications the following equipment:
              (1) A heat sensing device, such as an ultraviolet beam sensor or thermocouple, at the pilot light or the flame itself to indicate the continuous presence of a flame.
              (2) A device that records flow to the flare and bypass of the flare (if applicable). The owner or operator must:
              (i) Install, calibrate, and maintain a gas flow rate measuring device that records the flow to the control device at least every 15 minutes; and
              (ii) Secure the bypass line valve in the closed position with a car-seal or a lock-and-key type configuration. A visual inspection of the seal or closure mechanism must be performed at least once every month to ensure that the valve is maintained in the closed position and that the gas flow is not diverted through the bypass line.
              (d) Each owner or operator seeking to demonstrate compliance with § 60.33f(c) using a device other than a non-enclosed flare or an enclosed combustor or a treatment system must provide information satisfactory to the Administrator as provided in § 60.38f(d)(2) describing the operation of the control device, the operating parameters that would indicate proper performance, and appropriate monitoring procedures. The Administrator must review the information and either approve it, or request that additional information be submitted. The Administrator may specify additional appropriate monitoring procedures.
              (e) Each owner or operator seeking to install a collection system that does not meet the specifications in § 60.40f or seeking to monitor alternative parameters to those required by §§ 60.34f through 60.37f must provide information satisfactory to the Administrator as provided in § 60.38f(d)(2) and (3) describing the design and operation of the collection system, the operating parameters that would indicate proper performance, and appropriate monitoring procedures. The Administrator may specify additional appropriate monitoring procedures.
              (f) Each owner or operator seeking to demonstrate compliance with the 500 parts per million surface methane operational standard in § 60.34f(d) must monitor surface concentrations of methane according to the procedures provided in § 60.36f(c) and the instrument specifications in § 60.36f(d). Any closed landfill that has no monitored exceedances of the operational standard in three consecutive quarterly monitoring periods may skip to annual monitoring. Any methane reading of 500 parts per million or more above background detected during the annual monitoring returns the frequency for that landfill to quarterly monitoring.
              (g) Each owner or operator seeking to demonstrate compliance with the control system requirements in § 60.33f(c) using a landfill gas treatment system must maintain and operate all monitoring systems associated with the treatment system in accordance with the site-specific treatment system monitoring plan required in § 60.39f(b)(5)(ii) and must calibrate, maintain, and operate according to the manufacturer's specifications a device that records flow to the treatment system and bypass of the treatment system (if applicable). The owner or operator must:
              (1) Install, calibrate, and maintain a gas flow rate measuring device that records the flow to the treatment system at least every 15 minutes; and

              (2) Secure the bypass line valve in the closed position with a car-seal or a lock-and-key type configuration. A visual inspection of the seal or closure mechanism must be performed at least once every month to ensure that the valve is maintained in the closed position and that the gas flow is not diverted through the bypass line.
              (h) The monitoring requirements of paragraphs (b), (c) (d) and (g) of this section apply at all times the affected source is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities. A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. You are required to complete monitoring system repairs in response to monitoring system malfunctions and to return the monitoring system to operation as expeditiously as practicable.
              [81 FR 59313, Aug. 29, 2016, as amended at 85 FR 17260, Mar. 26, 2020]

              § 60.38f
              Reporting guidelines.
              For approval, a state plan must include the reporting provisions listed in this section, as applicable, except as provided under §§ 60.24 and 60.38f(d)(2).
              (a) Design capacity report. For existing MSW landfills subject to this subpart, the initial design capacity report must be submitted no later than 90 days after the effective date of EPA approval of the state's plan under section 111(d) of the Clean Air Act. The initial design capacity report must contain the following information:
              (1) A map or plot of the landfill, providing the size and location of the landfill, and identifying all areas where solid waste may be landfilled according to the permit issued by the state, local, or tribal agency responsible for regulating the landfill.
              (2) The maximum design capacity of the landfill. Where the maximum design capacity is specified in the permit issued by the state, local, or tribal agency responsible for regulating the landfill, a copy of the permit specifying the maximum design capacity may be submitted as part of the report. If the maximum design capacity of the landfill is not specified in the permit, the maximum design capacity must be calculated using good engineering practices. The calculations must be provided, along with the relevant parameters as part of the report. The landfill may calculate design capacity in either megagrams or cubic meters for comparison with the exemption values. If the owner or operator chooses to convert the design capacity from volume to mass or from mass to volume to demonstrate its design capacity is less than 2.5 million megagrams or 2.5 million cubic meters, the calculation must include a site-specific density, which must be recalculated annually. Any density conversions must be documented and submitted with the design capacity report. The state, local, or tribal agency or the Administrator may request other reasonable information as may be necessary to verify the maximum design capacity of the landfill.
              (b) Amended design capacity report. An amended design capacity report must be submitted providing notification of an increase in the design capacity of the landfill, within 90 days of an increase in the maximum design capacity of the landfill to meet or exceed 2.5 million megagrams and 2.5 million cubic meters. This increase in design capacity may result from an increase in the permitted volume of the landfill or an increase in the density as documented in the annual recalculation required in § 60.39f(f).
              (c) NMOC emission rate report. For existing MSW landfills covered by this subpart with a design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters, the NMOC emission rate report must be submitted following the procedure specified in paragraph (j)(2) of this section no later than 90 days after the effective date of EPA approval of the state's plan under section 111(d) of the Clean Air Act. The NMOC emission rate report must be submitted to the Administrator annually following the procedure specified in paragraph (j)(2) of this section, except as provided for in paragraph (c)(3) of this section. The Administrator may request such additional information as may be necessary to verify the reported NMOC emission rate.
              (1) The NMOC emission rate report must contain an annual or 5-year estimate of the NMOC emission rate calculated using the formula and procedures provided in § 60.35f(a) or (b), as applicable.
              (2) The NMOC emission rate report must include all the data, calculations, sample reports and measurements used to estimate the annual or 5-year emissions.
              (3) If the estimated NMOC emission rate as reported in the annual report to the Administrator is less than 34 megagrams per year in each of the next 5 consecutive years, the owner or operator may elect to submit, following the procedure specified in paragraph (j)(2) of this section, an estimate of the NMOC emission rate for the next 5-year period in lieu of the annual report. This estimate must include the current amount of solid waste-in-place and the estimated waste acceptance rate for each year of the 5 years for which an NMOC emission rate is estimated. All data and calculations upon which this estimate is based must be provided to the Administrator. This estimate must be revised at least once every 5 years. If the actual waste acceptance rate exceeds the estimated waste acceptance rate in any year reported in the 5-year estimate, a revised 5-year estimate must be submitted to the Administrator. The revised estimate must cover the 5-year period beginning with the year in which the actual waste acceptance rate exceeded the estimated waste acceptance rate.
              (4) Each owner or operator subject to the requirements of this subpart is exempted from the requirements to submit an NMOC emission rate report, after installing a collection and control system that complies with § 60.33f(b) and (c), during such time as the collection and control system is in operation and in compliance with §§ 60.34f and 60.36f.
              (d) Collection and control system design plan. The state plan must include a process for state review and approval of the site-specific design plan for each gas collection and control system. The collection and control system design plan must be prepared and approved by a professional engineer and must meet the following requirements:
              (1) The collection and control system as described in the design plan must meet the design requirements in § 60.33f(b) and (c).
              (2) The collection and control system design plan must include any alternatives to the operational standards, test methods, procedures, compliance measures, monitoring, recordkeeping, or reporting provisions of §§ 60.34f through 60.39f proposed by the owner or operator.
              (3) The collection and control system design plan must either conform to specifications for active collection systems in § 60.40f or include a demonstration to the Administrator's satisfaction of the sufficiency of the alternative provisions to § 60.40f.
              (4) Each owner or operator of an MSW landfill having a design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters must submit a copy of the collection and control system design plan cover page that contains the engineer's seal to the Administrator within 1 year of the first NMOC emission rate report in which the NMOC emission rate equals or exceeds 34 megagrams per year, except as follows:
              (i) If the owner or operator elects to recalculate the NMOC emission rate after Tier 2 NMOC sampling and analysis as provided in § 60.35f(a)(3) and the resulting rate is less than 34 megagrams per year, annual periodic reporting must be resumed, using the Tier 2 determined site-specific NMOC concentration, until the calculated NMOC emission rate is equal to or greater than 34 megagrams per year or the landfill is closed. The revised NMOC emission rate report, with the recalculated NMOC emission rate based on NMOC sampling and analysis, must be submitted, following the procedures in paragraph (j)(2) of this section, within 180 days of the first calculated exceedance of 34 megagrams per year.

              (ii) If the owner or operator elects to recalculate the NMOC emission rate after determining a site-specific methane generation rate constant k, as provided in Tier 3 in § 60.35f(a)(4), and the resulting NMOC emission rate is less than 34 megagrams per year, annual periodic reporting must be resumed. The resulting site-specific methane generation rate constant k must be used in the NMOC emission rate calculation until such time as the emissions rate calculation results in an exceedance. The revised NMOC emission rate report based on the provisions of § 60.35f(a)(4) and the resulting site-specific methane generation rate constant k must be submitted, following the procedure specified in paragraph (j)(2) of this section, to the Administrator within 1 year of the first calculated NMOC emission rate equaling or exceeding 34 megagrams per year.
              (iii) If the owner or operator elects to demonstrate that site-specific surface methane emissions are below 500 parts per million methane, based on the provisions of § 60.35f(a)(6), then the owner or operator must submit annually a Tier 4 surface emissions report as specified in this paragraph (d)(4)(iii) following the procedure specified in paragraph (j)(2) of this section until a surface emissions readings of 500 parts per million methane or greater is found. If the Tier 4 surface emissions report shows no surface emissions readings of 500 parts per million methane or greater for four consecutive quarters at a closed landfill, then the landfill owner or operator may reduce Tier 4 monitoring from a quarterly to an annual frequency. The Administrator may request such additional information as may be necessary to verify the reported instantaneous surface emission readings. The Tier 4 surface emissions report must clearly identify the location, date and time (to the nearest second), average wind speeds including wind gusts, and reading (in parts per million) of any value 500 parts per million methane or greater, other than non-repeatable, momentary readings. For location, you must determine the latitude and longitude coordinates using an instrument with an accuracy of at least 4 meters. The coordinates must be in decimal degrees with at least five decimal places. The Tier 4 surface emission report should also include the results of the most recent Tier 1 and Tier 2 results in order to verify that the landfill does not exceed 50 Mg/yr of NMOC.
              (A) The initial Tier 4 surface emissions report must be submitted annually, starting within 30 days of completing the fourth quarter of Tier 4 surface emissions monitoring that demonstrates that site-specific surface methane emissions are below 500 parts per million methane, and following the procedure specified in paragraph (j)(2) of this section.
              (B) The Tier 4 surface emissions rate report must be submitted within 1 year of the first measured surface exceedance of 500 parts per million methane, following the procedure specified in paragraph (j)(2) of this section.
              (iv) If the landfill is in the closed landfill subcategory, the owner or operator must submit a collection and control system design plan to the Administrator within 1 year of the first NMOC emission rate report in which the NMOC emission rate equals or exceeds 50 megagrams per year, except as follows:
              (A) If the owner or operator elects to recalculate the NMOC emission rate after Tier 2 NMOC sampling and analysis as provided in § 60.35f(a)(3) and the resulting rate is less than 50 megagrams per year, annual periodic reporting must be resumed, using the Tier 2 determined site-specific NMOC concentration, until the calculated NMOC emission rate is equal to or greater than 50 megagrams per year or the landfill is closed. The revised NMOC emission rate report, with the recalculated NMOC emission rate based on NMOC sampling and analysis, must be submitted, following the procedure specified in paragraph (j)(2) of this section, within 180 days of the first calculated exceedance of 50 megagrams per year.

              (B) If the owner or operator elects to recalculate the NMOC emission rate after determining a site-specific methane generation rate constant k, as provided in Tier 3 in § 60.35f(a)(4), and the resulting NMOC emission rate is less than 50 megagrams per year, annual periodic reporting must be resumed. The resulting site-specific methane generation rate constant k must be used in the NMOC emission rate calculation until such time as the emissions rate calculation results in an exceedance. The revised NMOC emission rate report based on the provisions of § 60.35f(a)(4) and the resulting site-specific methane generation rate constant k must be submitted, following the procedure specified in paragraph (j)(2) of this section, to the Administrator within 1 year of the first calculated NMOC emission rate equaling or exceeding 50 megagrams per year.
              (C) The landfill owner or operator elects to demonstrate surface emissions are low, consistent with the provisions in paragraph (d)(4)(iii) of this section.
              (D) The landfill has already submitted a gas collection and control system design plan consistent with the provisions of subpart WWW of this part; 40 CFR part 62, subpart GGG; or a state plan implementing subpart Cc of this part.
              (5) The landfill owner or operator must notify the Administrator that the design plan is completed and submit a copy of the plan's signature page. The Administrator has 90 days to decide whether the design plan should be submitted for review. If the Administrator chooses to review the plan, the approval process continues as described in paragraph (c)(6) of this section. However, if the Administrator indicates that submission is not required or does not respond within 90 days, the landfill owner or operator can continue to implement the plan with the recognition that the owner or operator is proceeding at their own risk. In the event that the design plan is required to be modified to obtain approval, the owner or operator must take any steps necessary to conform any prior actions to the approved design plan and any failure to do so could result in an enforcement action.
              (6) Upon receipt of an initial or revised design plan, the Administrator must review the information submitted under paragraphs (d)(1) through (3) of this section and either approve it, disapprove it, or request that additional information be submitted. Because of the many site-specific factors involved with landfill gas system design, alternative systems may be necessary. A wide variety of system designs are possible, such as vertical wells, combination horizontal and vertical collection systems, or horizontal trenches only, leachate collection components, and passive systems. If the Administrator does not approve or disapprove the design plan, or does not request that additional information be submitted within 90 days of receipt, then the owner or operator may continue with implementation of the design plan, recognizing they would be proceeding at their own risk.
              (7) If the owner or operator chooses to demonstrate compliance with the emission control requirements of this subpart using a treatment system as defined in this subpart, then the owner or operator must prepare a site-specific treatment system monitoring plan as specified in § 60.39f(b)(5).
              (e) Revised design plan. The owner or operator who has already been required to submit a design plan under paragraph (d) of this section, or under subpart WWW of this part; 40 CFR part 62, subpart GGG; or a state plan implementing subpart Cc of this part, must submit a revised design plan to the Administrator for approval as follows:
              (1) At least 90 days before expanding operations to an area not covered by the previously approved design plan.
              (2) Prior to installing or expanding the gas collection system in a way that is not consistent with the design plan that was submitted to the Administrator according to paragraph (d) of this section.
              (f) Closure report. Each owner or operator of a controlled landfill must submit a closure report to the Administrator within 30 days of ceasing waste acceptance. The Administrator may request additional information as may be necessary to verify that permanent closure has taken place in accordance with the requirements of 40 CFR 258.60. If a closure report has been submitted to the Administrator, no additional wastes may be placed into the landfill without filing a notification of modification as described under § 60.7(a)(4).
              (g) Equipment removal report. Each owner or operator of a controlled landfill must submit an equipment removal report to the Administrator 30 days prior to removal or cessation of operation of the control equipment.

              (1) The equipment removal report must contain the following items:

              (i) A copy of the closure report submitted in accordance with paragraph (f) of this section; and
              (ii) A copy of the initial performance test report demonstrating that the 15-year minimum control period has expired, unless the report of the results of the performance test has been submitted to the EPA via the EPA's CDX, or information that demonstrates that the GCCS will be unable to operate for 15 years due to declining gas flows. In the equipment removal report, the process unit(s) tested, the pollutant(s) tested, and the date that such performance test was conducted may be submitted in lieu of the performance test report if the report has been previously submitted to the EPA's CDX; and
              (iii) Dated copies of three successive NMOC emission rate reports demonstrating that the landfill is no longer producing 34 megagrams or greater of NMOC per year, unless the NMOC emission rate reports have been submitted to the EPA via the EPA's CDX. If the NMOC emission rate reports have been previously submitted to the EPA's CDX, a statement that the NMOC emission rate reports have been submitted electronically and the dates that the reports were submitted to the EPA's CDX may be submitted in the equipment removal report in lieu of the NMOC emission rate reports; or
              (iv) For the closed landfill subcategory, dated copies of three successive NMOC emission rate reports demonstrating that the landfill is no longer producing 50 megagrams or greater of NMOC per year, unless the NMOC emission rate reports have been submitted to the EPA via the EPA's CDX. If the NMOC emission rate reports have been previously submitted to the EPA's CDX, a statement that the NMOC emission rate reports have been submitted electronically and the dates that the reports were submitted to the EPA's CDX may be submitted in the equipment removal report in lieu of the NMOC emission rate reports.
              (2) The Administrator may request such additional information as may be necessary to verify that all of the conditions for removal in § 60.33f(f) have been met.
              (h) Annual report. The owner or operator of a landfill seeking to comply with § 60.33f(e)(2) using an active collection system designed in accordance with § 60.33f(b) must submit to the Administrator, following the procedures specified in paragraph (j)(2) of this section, an annual report of the recorded information in paragraphs (h)(1) through (7) of this section. The initial annual report must be submitted within 180 days of installation and startup of the collection and control system. The initial annual report must include the initial performance test report required under § 60.8, as applicable, unless the report of the results of the performance test has been submitted to the EPA via the EPA's CDX. In the initial annual report, the process unit(s) tested, the pollutant(s) tested and the date that such performance test was conducted may be submitted in lieu of the performance test report if the report has been previously submitted to the EPA's CDX. The initial performance test report must be submitted, following the procedure specified in paragraph (j)(1) of this section, no later than the date that the initial annual report is submitted. For enclosed combustion devices and flares, reportable exceedances are defined under § 60.39f(c)(1). If complying with the operational provisions of §§ 63.1958, 63.1960, and 63.1961 of this chapter, as allowed at §§ 60.34f, 60.36f, and 60.37f, the owner or operator must follow the semi-annual reporting requirements in § 63.1981(h) of this chapter in lieu of this paragraph.
              (1) Value and length of time for exceedance of applicable parameters monitored under § 60.37f(a)(1), (b), (c), (d), and (g).
              (2) Description and duration of all periods when the gas stream was diverted from the control device or treatment system through a bypass line or the indication of bypass flow as specified under § 60.37f.
              (3) Description and duration of all periods when the control device or treatment system was not operating and length of time the control device or treatment system was not operating.
              (4) All periods when the collection system was not operating.

              (5) The location of each exceedance of the 500 parts per million methane concentration as provided in § 60.34f(d) and the concentration recorded at each location for which an exceedance was recorded in the previous month. For location, you must determine the latitude and longitude coordinates using an instrument with an accuracy of at least 4 meters. The coordinates must be in decimal degrees with at least five decimal places.
              (6) The date of installation and the location of each well or collection system expansion added pursuant to § 60.36f(a)(3), (a)(5), (b), and (c)(4).
              (7) For any corrective action analysis for which corrective actions are required in § 60.36f(a)(3) or (5) and that take more than 60 days to correct the exceedance, the root cause analysis conducted, including a description of the recommended corrective action(s), the date for corrective action(s) already completed following the positive pressure or elevated temperature reading, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates.
              (i) Initial performance test report. Each owner or operator seeking to comply with § 60.33f(c) must include the following information with the initial performance test report required under § 60.8:
              (1) A diagram of the collection system showing collection system positioning including all wells, horizontal collectors, surface collectors, or other gas extraction devices, including the locations of any areas excluded from collection and the proposed sites for the future collection system expansion;
              (2) The data upon which the sufficient density of wells, horizontal collectors, surface collectors, or other gas extraction devices and the gas mover equipment sizing are based;
              (3) The documentation of the presence of asbestos or nondegradable material for each area from which collection wells have been excluded based on the presence of asbestos or nondegradable material;
              (4) The sum of the gas generation flow rates for all areas from which collection wells have been excluded based on nonproductivity and the calculations of gas generation flow rate for each excluded area;
              (5) The provisions for increasing gas mover equipment capacity with increased gas generation flow rate, if the present gas mover equipment is inadequate to move the maximum flow rate expected over the life of the landfill; and
              (6) The provisions for the control of off-site migration.
              (j) Electronic reporting. The owner or operator must submit reports electronically according to paragraphs (j)(1) and (2) of this section.
              (1) Within 60 days after the date of completing each performance test (as defined in § 60.8), the owner or operator must submit the results of each performance test according to the following procedures:

              (i) For data collected using test methods supported by the EPA's Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site (https://www3.epa.gov/ttn/chief/ert/ert__info.html) at the time of the test, you must submit the results of the performance test to the EPA via the Compliance and Emissions Data Reporting Interface (CEDRI). CEDRI can be accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). Performance test data must be submitted in a file format generated through the use of the EPA's ERT or an alternative file format consistent with the extensible markup language (XML) schema listed on the EPA's ERT Web site, once the XML schema is available. If you claim that some of the performance test information being submitted is confidential business information (CBI), you must submit a complete file generated through the use of the EPA's ERT or an alternate electronic file consistent with the XML schema listed on the EPA's ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage media to the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA's CDX as described earlier in this paragraph (j)(1)(i).
              (ii) For data collected using test methods that are not supported by the EPA's ERT as listed on the EPA's ERT Web site at the time of the test, you must submit the results of the performance test to the Administrator at the appropriate address listed in § 60.4.

              (2) Each owner or operator required to submit reports following the procedure specified in this paragraph must submit reports to the EPA via the CEDRI. (CEDRI can be accessed through the EPA's CDX.) The owner or operator must use the appropriate electronic report in CEDRI for this subpart or an alternate electronic file format consistent with the XML schema listed on the CEDRI Web site (https://www3.epa.gov/ttn/chief/cedri/index.html). If the reporting form specific to this subpart is not available in CEDRI at the time that the report is due, the owner or operator must submit the report to the Administrator at the appropriate address listed in § 60.4. Once the form has been available in CEDRI for 90 calendar days, the owner or operator must begin submitting all subsequent reports via CEDRI. The reports must be submitted by the deadlines specified in this subpart, regardless of the method in which the reports are submitted.
              (k) Corrective action and the corresponding timeline. The owner or operator must submit according to paragraphs (k)(1) and (2) of this section. If complying with the operational provisions of §§ 63.1958, 63.1960, and 63.1961 of this chapter, as allowed at §§ 60.34f, 60.36f, and 60.37f, the owner or operator must follow the corrective action and the corresponding timeline reporting requirements in § 63.1981(j) of this chapter in lieu of paragraphs (k)(1) and (2) of this section.
              (1) For corrective action that is required according to § 60.36f(a)(3)(iii) or (a)(5)(iii) and is expected to take longer than 120 days after the initial exceedance to complete, you must submit the root cause analysis, corrective action analysis, and corresponding implementation timeline to the Administrator as soon as practicable but no later than 75 days after the first measurement of positive pressure or temperature monitoring value of 55 degrees Celsius (131 degrees Fahrenheit) or above. The Administrator must approve the plan for corrective action and the corresponding timeline.
              (2) For corrective action that is required according to § 60.36f(a)(3)(iii) or (a)(5)(iii) and is not completed within 60 days after the initial exceedance, you must submit a notification to the Administrator as soon as practicable but no later than 75 days after the first measurement of positive pressure or temperature exceedance.
              (l) Liquids addition. The owner or operator of an affected landfill with a design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters that has employed leachate recirculation or added liquids based on a Research, Development, and Demonstration permit (issued through Resource Conservation and Recovery Act, subtitle D, part 258) within the last 10 years must submit to the Administrator, annually, following the procedure specified in paragraph (j)(2) of this section, the following information:
              (1) Volume of leachate recirculated (gallons per year) and the reported basis of those estimates (records or engineering estimates).
              (2) Total volume of all other liquids added (gallons per year) and the reported basis of those estimates (records or engineering estimates).
              (3) Surface area (acres) over which the leachate is recirculated (or otherwise applied).
              (4) Surface area (acres) over which any other liquids are applied.
              (5) The total waste disposed (megagrams) in the areas with recirculated leachate and/or added liquids based on on-site records to the extent data are available, or engineering estimates and the reported basis of those estimates.
              (6) The annual waste acceptance rates (megagrams per year) in the areas with recirculated leachate and/or added liquids, based on on-site records to the extent data are available, or engineering estimates.

              (7) The initial report must contain items in paragraph (l)(1) through (6) of this section per year for the most recent 365 days as well as for each of the previous 10 years, to the extent historical data are available in on-site records, and the report must be submitted no later than:
              (i) September 27, 2017, for landfills that commenced construction, modification, or reconstruction after July 17, 2014 but before August 29, 2016; or
              (ii) 365 days after the date of commenced construction, modification, or reconstruction for landfills that commence construction, modification, or reconstruction after August 29, 2016.
              (8) Subsequent annual reports must contain items in paragraph (l)(1) through (6) of this section for the 365-day period following the 365-day period included in the previous annual report, and the report must be submitted no later than 365 days after the date the previous report was submitted.
              (9) Landfills in the closed landfill subcategory are exempt from reporting requirements contained in paragraphs (l)(1) through (7) of this section.
              (10) Landfills may cease annual reporting of items in paragraphs (l)(1) through (6) of this section once they have submitted the closure report in § 60.38f(f).
              (m) Tier 4 notification. (1) The owner or operator of an affected landfill with a design capacity equal to or greater than 2.5 million megagrams and 2.5 million cubic meters must provide a notification of the date(s) upon which it intends to demonstrate site-specific surface methane emissions are below 500 parts per million methane, based on the Tier 4 provisions of § 60.35f(a)(6). The landfill must also include a description of the wind barrier to be used during the SEM in the notification. Notification must be postmarked not less than 30 days prior to such date.
              (2) If there is a delay to the scheduled Tier 4 SEM date due to weather conditions, including not meeting the wind requirements in § 60.35f (a)(6)(iii)(A), the owner or operator of a landfill shall notify the Administrator by email or telephone no later than 48 hours before any known delay in the original test date, and arrange an updated date with the Administrator by mutual agreement.
              (n) Each owner or operator that chooses to comply with the provisions in §§ 63.1958, 63.1960, and 63.1961 of this chapter, as allowed in §§ 60.34f, 60.36f, and 60.37f, must submit the 24-hour high temperature report according to § 63.1981(k) of this chapter.
              [81 FR 59313, Aug. 29, 2016, as amended at 85 FR 17260, Mar. 26, 2020]

              § 60.39f
              Recordkeeping guidelines.
              For approval, a state plan must include the recordkeeping provisions in this section.
              (a) Except as provided in § 60.38f(d)(2), each owner or operator of an MSW landfill subject to the provisions of § 60.33f(e) must keep for at least 5 years up-to-date, readily accessible, on-site records of the design capacity report that triggered § 60.33f(e), the current amount of solid waste in-place, and the year-by-year waste acceptance rate. Off-site records may be maintained if they are retrievable within 4 hours. Either paper copy or electronic formats are acceptable.
              (b) Except as provided in § 60.38f(d)(2), each owner or operator of a controlled landfill must keep up-to-date, readily accessible records for the life of the control system equipment of the data listed in paragraphs (b)(1) through (5) of this section as measured during the initial performance test or compliance determination. Records of subsequent tests or monitoring must be maintained for a minimum of 5 years. Records of the control device vendor specifications must be maintained until removal.
              (1) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.33f(b):
              (i) The maximum expected gas generation flow rate as calculated in § 60.36f(a)(1). The owner or operator may use another method to determine the maximum gas generation flow rate, if the method has been approved by the Administrator.
              (ii) The density of wells, horizontal collectors, surface collectors, or other gas extraction devices determined using the procedures specified in § 60.40f(a)(1).

              (2) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.33f(c) through use of an enclosed combustion device other than a boiler or process heater with a design heat input capacity equal to or greater than 44 megawatts:
              (i) The average temperature measured at least every 15 minutes and averaged over the same time period of the performance test.
              (ii) The percent reduction of NMOC determined as specified in § 60.33f(c)(2) achieved by the control device.
              (3) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.33f(c)(2)(i) through use of a boiler or process heater of any size: A description of the location at which the collected gas vent stream is introduced into the boiler or process heater over the same time period of the performance testing.

              (4) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.33f(c)(1) through use of a non-enclosed flare, the flare type (i.e., steam-assisted, air-assisted, or non-assisted), all visible emission readings, heat content determination, flow rate or bypass flow rate measurements, and exit velocity determinations made during the performance test as specified in § 60.18; and continuous records of the flare pilot flame or flare flame monitoring and records of all periods of operations during which the pilot flame or the flare flame is absent.
              (5) Where an owner or operator subject to the provisions of this subpart seeks to demonstrate compliance with § 60.33f(c)(3) through use of a landfill gas treatment system:
              (i) Bypass records. Records of the flow of landfill gas to, and bypass of, the treatment system.
              (ii) Site-specific treatment monitoring plan, to include:
              (A) Monitoring records of parameters that are identified in the treatment system monitoring plan and that ensure the treatment system is operating properly for each intended end use of the treated landfill gas. At a minimum, records should include records of filtration, de-watering, and compression parameters that ensure the treatment system is operating properly for each intended end use of the treated landfill gas.
              (B) Monitoring methods, frequencies, and operating ranges for each monitored operating parameter based on manufacturer's recommendations or engineering analysis for each intended end use of the treated landfill gas.
              (C) Documentation of the monitoring methods and ranges, along with justification for their use.
              (D) Identify who is responsible (by job title) for data collection.
              (E) Processes and methods used to collect the necessary data.
              (F) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems.
              (c) Except as provided in § 60.38f(d)(2), each owner or operator of a controlled landfill subject to the provisions of this subpart must keep for 5 years up-to-date, readily accessible continuous records of the equipment operating parameters specified to be monitored in § 60.37f as well as up-to-date, readily accessible records for periods of operation during which the parameter boundaries established during the most recent performance test are exceeded.
              (1) The following constitute exceedances that must be recorded and reported under § 60.38f:
              (i) For enclosed combustors except for boilers and process heaters with design heat input capacity of 44 megawatts (150 million British thermal unit per hour) or greater, all 3-hour periods of operation during which the average temperature was more than 28 degrees Celsius (82 degrees Fahrenheit) below the average combustion temperature during the most recent performance test at which compliance with § 60.33f(c) was determined.
              (ii) For boilers or process heaters, whenever there is a change in the location at which the vent stream is introduced into the flame zone as required under paragraph (b)(3) of this section.
              (2) Each owner or operator subject to the provisions of this subpart must keep up-to-date, readily accessible continuous records of the indication of flow to the control system and the indication of bypass flow or records of monthly inspections of car-seals or lock-and-key configurations used to seal bypass lines, specified under § 60.37f.

              (3) Each owner or operator subject to the provisions of this subpart who uses a boiler or process heater with a design heat input capacity of 44 megawatts or greater to comply with § 60.33f(c) must keep an up-to-date, readily accessible record of all periods of operation of the boiler or process heater. (Examples of such records could include records of steam use, fuel use, or monitoring data collected pursuant to other state, local, tribal, or federal regulatory requirements.)
              (4) Each owner or operator seeking to comply with the provisions of this subpart by use of a non-enclosed flare must keep up-to-date, readily accessible continuous records of the flame or flare pilot flame monitoring specified under § 60.37f(c), and up-to-date, readily accessible records of all periods of operation in which the flame or flare pilot flame is absent.
              (5) Each owner or operator of a landfill seeking to comply with § 60.33f(e) using an active collection system designed in accordance with § 60.33f(b) must keep records of periods when the collection system or control device is not operating.
              (d) Except as provided in § 60.38f(d)(2), each owner or operator subject to the provisions of this subpart must keep for the life of the collection system an up-to-date, readily accessible plot map showing each existing and planned collector in the system and providing a unique identification location label on each collector that matches the labeling on the plot map.
              (1) Each owner or operator subject to the provisions of this subpart must keep up-to-date, readily accessible records of the installation date and location of all newly installed collectors as specified under § 60.36f(b).
              (2) Each owner or operator subject to the provisions of this subpart must keep readily accessible documentation of the nature, date of deposition, amount, and location of asbestos-containing or nondegradable waste excluded from collection as provided in § 60.40f(a)(3)(i) as well as any nonproductive areas excluded from collection as provided in § 60.40f(a)(3)(ii).
              (e) Except as provided in § 60.38f(d)(2), each owner or operator subject to the provisions of this subpart must keep for at least 5 years up-to-date, readily accessible records of the items in paragraphs (e)(1) through (5) of this section. Each owner or operator that chooses to comply with the provisions in §§ 63.1958, 63.1960, and 63.1961 of this chapter, as allowed in §§ 60.34f, 60.36f, and 60.37f, must keep the records in paragraph (e)(6) of this section and must keep records according to § 63.1983(e)(1) through (5) of this chapter in lieu of paragraphs (e)(1) through (5) of this section.
              (1) All collection and control system exceedances of the operational standards in § 60.34f, the reading in the subsequent month whether or not the second reading is an exceedance, and the location of each exceedance.
              (2) Each owner or operator subject to the provisions of this subpart must also keep records of each wellhead temperature monitoring value of 55 degrees Celsius (131 degrees Fahrenheit) or above, each wellhead nitrogen level at or above 20 percent, and each wellhead oxygen level at or above 5 percent.
              (3) For any root cause analysis for which corrective actions are required in § 60.36f(a)(3) or (5), keep a record of the root cause analysis conducted, including a description of the recommended corrective action(s) taken, and the date(s) the corrective action(s) were completed.
              (4) For any root cause analysis for which corrective actions are required in § 60.36f(a)(3)(ii) or (a)(5)(ii), keep a record of the root cause analysis conducted, the corrective action analysis, the date for corrective action(s) already completed following the positive pressure reading or high temperature reading, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates.

              (5) For any root cause analysis for which corrective actions are required in § 60.36f(a)(3)(iii) or (a)(5)(iii), keep a record of the root cause analysis conducted, the corrective action analysis, the date for corrective action(s) already completed following the positive pressure reading or high temperature reading, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates, and a copy of any comments or final approval on the corrective action analysis or schedule from the regulatory agency.
              (6) Each owner or operator that chooses to comply with the provisions in §§ 63.1958, 63.1960, and 63.1961 of this chapter, as allowed in §§ 60.34f, 60.36f, and 60.37f, must keep records of the date upon which the owner or operator started complying with the provisions in §§ 63.1958, 63.1960, and 63.1961.
              (f) Landfill owners or operators who convert design capacity from volume to mass or mass to volume to demonstrate that landfill design capacity is less than 2.5 million megagrams or 2.5 million cubic meters, as provided in the definition of “design capacity”, must keep readily accessible, on-site records of the annual recalculation of site-specific density, design capacity, and the supporting documentation. Off-site records may be maintained if they are retrievable within 4 hours. Either paper copy or electronic formats are acceptable.
              (g) Landfill owners or operators seeking to demonstrate that site-specific surface methane emissions are below 500 parts per million by conducting surface emission monitoring under the Tier 4 procedures specified in § 60.35f(a)(6) must keep for at least 5 years up-to-date, readily accessible records of all surface emissions monitoring and information related to monitoring instrument calibrations conducted according to sections 8 and 10 of Method 21 of appendix A of this part, including all of the following items:
              (1) Calibration records:
              (i) Date of calibration and initials of operator performing the calibration.
              (ii) Calibration gas cylinder identification, certification date, and certified concentration.
              (iii) Instrument scale(s) used.
              (iv) A description of any corrective action taken if the meter readout could not be adjusted to correspond to the calibration gas value.
              (v) If an owner or operator makes their own calibration gas, a description of the procedure used.
              (2) Digital photographs of the instrument setup. The photographs must be time and date-stamped and taken at the first sampling location prior to sampling and at the last sampling location after sampling at the end of each sampling day, for the duration of the Tier 4 monitoring demonstration.
              (3) Timestamp of each surface scan reading:
              (i) Timestamp should be detailed to the nearest second, based on when the sample collection begins.

              (ii) A log for the length of time each sample was taken using a stopwatch (e.g., the time the probe was held over the area).
              (4) Location of each surface scan reading. The owner or operator must determine the coordinates using an instrument with an accuracy of at least 4 meters. Coordinates must be in decimal degrees with at least five decimal places.
              (5) Monitored methane concentration (parts per million) of each reading.
              (6) Background methane concentration (parts per million) after each instrument calibration test.
              (7) Adjusted methane concentration using most recent calibration (parts per million).
              (8) For readings taken at each surface penetration, the unique identification location label matching the label specified in paragraph (d) of this section.
              (9) Records of the operating hours of the gas collection system for each destruction device.
              (h) Except as provided in § 60.38f(d)(2), each owner or operator subject to the provisions of this subpart must keep for at least 5 years up-to-date, readily accessible records of all collection and control system monitoring data for parameters measured in § 60.37f(a)(1), (2), and (3).
              (i) Any records required to be maintained by this subpart that are submitted electronically via the EPA's CDX may be maintained in electronic format.

              (j) For each owner or operator reporting leachate or other liquids addition under § 60.38f(l), keep records of any engineering calculations or company records used to estimate the quantities of leachate or liquids added, the surface areas for which the leachate or liquids were applied, and the estimates of annual waste acceptance or total waste in place in the areas where leachate or liquids were applied.
              [81 FR 59313, Aug. 29, 2016, as amended at 85 FR 17260, Mar. 26, 2020]

              § 60.40f
              Specifications for active collection systems.
              For approval, a state plan must include the specifications for active collection systems in this section.
              (a) Each owner or operator seeking to comply with § 60.33f(b) must site active collection wells, horizontal collectors, surface collectors, or other extraction devices at a sufficient density throughout all gas producing areas using the following procedures unless alternative procedures have been approved by the Administrator.
              (1) The collection devices within the interior must be certified to achieve comprehensive control of surface gas emissions by a professional engineer. The following issues must be addressed in the design: depths of refuse, refuse gas generation rates and flow characteristics, cover properties, gas system expandability, leachate and condensate management, accessibility, compatibility with filling operations, integration with closure end use, air intrusion control, corrosion resistance, fill settlement, resistance to the refuse decomposition heat, and ability to isolate individual components or sections for repair or troubleshooting without shutting down entire collection system.
              (2) The sufficient density of gas collection devices determined in paragraph (a)(1) of this section must address landfill gas migration issues and augmentation of the collection system through the use of active or passive systems at the landfill perimeter or exterior.
              (3) The placement of gas collection devices determined in paragraph (a)(1) of this section must control all gas producing areas, except as provided by paragraphs (a)(3)(i) and (ii) of this section.
              (i) Any segregated area of asbestos or nondegradable material may be excluded from collection if documented as provided under § 60.39f(d). The documentation must provide the nature, date of deposition, location and amount of asbestos or nondegradable material deposited in the area, and must be provided to the Administrator upon request.
              (ii) Any nonproductive area of the landfill may be excluded from control, provided that the total of all excluded areas can be shown to contribute less than 1 percent of the total amount of NMOC emissions from the landfill. The amount, location, and age of the material must be documented and provided to the Administrator upon request. A separate NMOC emissions estimate must be made for each section proposed for exclusion, and the sum of all such sections must be compared to the NMOC emissions estimate for the entire landfill.
              (A) The NMOC emissions from each section proposed for exclusion must be computed using Equation 7:

                ER29AU16.006

                Where:

                Qi = NMOC emission rate from the ith section, megagrams per year.
                k = Methane generation rate constant, year−1.
                Lo = Methane generation potential, cubic meters per megagram solid waste.
                Mi = Mass of the degradable solid waste in the ith section, megagram.
                ti = Age of the solid waste in the ith section, years.
                CNMOC = Concentration of NMOC, parts per million by volume.
                3.6×10−9 = Conversion factor.

              (B) If the owner or operator is proposing to exclude, or cease gas collection and control from, nonproductive physically separated (e.g., separately lined) closed areas that already have gas collection systems, NMOC emissions from each physically separated closed area must be computed using either Equation 3 in § 60.35f or Equation 7 in paragraph (a)(3)(ii)(A) of this section.
              (iii) The values for k and CNMOC determined in field testing must be used if field testing has been performed in determining the NMOC emission rate or the radii of influence (the distance from the well center to a point in the landfill where the pressure gradient applied by the blower or compressor approaches zero). If field testing has not been performed, the default values for k, Lo, and CNMOC provided in § 60.35f or the alternative values from § 60.35f must be used. The mass of nondegradable solid waste contained within the given section may be subtracted from the total mass of the section when estimating emissions provided the nature, location, age, and amount of the nondegradable material is documented as provided in paragraph (a)(3)(i) of this section.
              (b) Each owner or operator seeking to comply with § 60.33f(b) must construct the gas collection devices using the following equipment or procedures:
              (1) The landfill gas extraction components must be constructed of polyvinyl chloride (PVC), high density polyethylene (HDPE) pipe, fiberglass, stainless steel, or other nonporous corrosion resistant material of suitable dimensions to: Convey projected amounts of gases; withstand installation, static, and settlement forces; and withstand planned overburden or traffic loads. The collection system must extend as necessary to comply with emission and migration standards. Collection devices such as wells and horizontal collectors must be perforated to allow gas entry without head loss sufficient to impair performance across the intended extent of control. Perforations must be situated with regard to the need to prevent excessive air infiltration.
              (2) Vertical wells must be placed so as not to endanger underlying liners and must address the occurrence of water within the landfill. Holes and trenches constructed for piped wells and horizontal collectors must be of sufficient cross-section so as to allow for their proper construction and completion including, for example, centering of pipes and placement of gravel backfill. Collection devices must be designed so as not to allow indirect short circuiting of air into the cover or refuse into the collection system or gas into the air. Any gravel used around pipe perforations should be of a dimension so as not to penetrate or block perforations.
              (3) Collection devices may be connected to the collection header pipes below or above the landfill surface. The connector assembly must include a positive closing throttle valve, any necessary seals and couplings, access couplings and at least one sampling port. The collection devices must be constructed of PVC, HDPE, fiberglass, stainless steel, or other nonporous material of suitable thickness.
              (c) Each owner or operator seeking to comply with § 60.33f(c) must convey the landfill gas to a control system in compliance with § 60.33f(c) through the collection header pipe(s). The gas mover equipment must be sized to handle the maximum gas generation flow rate expected over the intended use period of the gas moving equipment using the following procedures:
              (1) For existing collection systems, the flow data must be used to project the maximum flow rate. If no flow data exist, the procedures in paragraph (c)(2) of this section must be used.
              (2) For new collection systems, the maximum flow rate must be in accordance with § 60.36f(a)(1).

              § 60.41f
              Definitions.
              Terms used but not defined in this subpart have the meaning given them in the Clean Air Act and in subparts A and B of this part.

                Active collection system means a gas collection system that uses gas mover equipment.

                Active landfill means a landfill in which solid waste is being placed or a landfill that is planned to accept waste in the future.

                Administrator means the Administrator of the U.S. Environmental Protection Agency or his/her authorized representative or the Administrator of a state air pollution control agency.

                Closed area means a separately lined area of an MSW landfill in which solid waste is no longer being placed. If additional solid waste is placed in that area of the landfill, that landfill area is no longer closed. The area must be separately lined to ensure that the landfill gas does not migrate between open and closed areas.

                Closed landfill means a landfill in which solid waste is no longer being placed, and in which no additional solid wastes will be placed without first filing a notification of modification as prescribed under § 60.7(a)(4). Once a notification of modification has been filed, and additional solid waste is placed in the landfill, the landfill is no longer closed.

                Closed landfill subcategory means a closed landfill that has submitted a closure report as specified in § 60.38f(f) on or before September 27, 2017.

                Closure means that point in time when a landfill becomes a closed landfill.

                Commercial solid waste means all types of solid waste generated by stores, offices, restaurants, warehouses, and other nonmanufacturing activities, excluding residential and industrial wastes.

                Controlled landfill means any landfill at which collection and control systems are required under this subpart as a result of the NMOC emission rate. The landfill is considered controlled at the time a collection and control system design plan is prepared in compliance with § 60.33f(e)(2).

                Corrective action analysis means a description of all reasonable interim and long-term measures, if any, that are available, and an explanation of why the selected corrective action(s) is/are the best alternative(s), including, but not limited to, considerations of cost effectiveness, technical feasibility, safety, and secondary impacts.

                Design capacity means the maximum amount of solid waste a landfill can accept, as indicated in terms of volume or mass in the most recent permit issued by the state, local, or tribal agency responsible for regulating the landfill, plus any in-place waste not accounted for in the most recent permit. If the owner or operator chooses to convert the design capacity from volume to mass or from mass to volume to demonstrate its design capacity is less than 2.5 million megagrams or 2.5 million cubic meters, the calculation must include a site-specific density, which must be recalculated annually.

                Disposal facility means all contiguous land and structures, other appurtenances, and improvements on the land used for the disposal of solid waste.

                Emission rate cutoff means the threshold annual emission rate to which a landfill compares its estimated emission rate to determine if control under the regulation is required.

                Enclosed combustor means an enclosed firebox which maintains a relatively constant limited peak temperature generally using a limited supply of combustion air. An enclosed flare is considered an enclosed combustor.

                Flare means an open combustor without enclosure or shroud.

                Gas mover equipment means the equipment (i.e., fan, blower, compressor) used to transport landfill gas through the header system.

                Gust means the highest instantaneous wind speed that occurs over a 3-second running average.

                Household waste means any solid waste (including garbage, trash, and sanitary waste in septic tanks) derived from households (including, but not limited to, single and multiple residences, hotels and motels, bunkhouses, ranger stations, crew quarters, campgrounds, picnic grounds, and day-use recreation areas). Household waste does not include fully segregated yard waste. Segregated yard waste means vegetative matter resulting exclusively from the cutting of grass, the pruning and/or removal of bushes, shrubs, and trees, the weeding of gardens, and other landscaping maintenance activities. Household waste does not include construction, renovation, or demolition wastes, even if originating from a household.

                Industrial solid waste means solid waste generated by manufacturing or industrial processes that is not a hazardous waste regulated under Subtitle C of the Resource Conservation and Recovery Act, parts 264 and 265 of this chapter. Such waste may include, but is not limited to, waste resulting from the following manufacturing processes: electric power generation; fertilizer/agricultural chemicals; food and related products/by-products; inorganic chemicals; iron and steel manufacturing; leather and leather products; nonferrous metals manufacturing/foundries; organic chemicals; plastics and resins manufacturing; pulp and paper industry; rubber and miscellaneous plastic products; stone, glass, clay, and concrete products; textile manufacturing; transportation equipment; and water treatment. This term does not include mining waste or oil and gas waste.

                Interior well means any well or similar collection component located inside the perimeter of the landfill waste. A perimeter well located outside the landfilled waste is not an interior well.

                Landfill means an area of land or an excavation in which wastes are placed for permanent disposal, and that is not a land application unit, surface impoundment, injection well, or waste pile as those terms are defined under § 257.2 of this title.

                Lateral expansion means a horizontal expansion of the waste boundaries of an existing MSW landfill. A lateral expansion is not a modification unless it results in an increase in the design capacity of the landfill.

                Leachate recirculation means the practice of taking the leachate collected from the landfill and reapplying it to the landfill by any of one of a variety of methods, including pre-wetting of the waste, direct discharge into the working face, spraying, infiltration ponds, vertical injection wells, horizontal gravity distribution systems, and pressure distribution systems.

                Modification means an increase in the permitted volume design capacity of the landfill by either lateral or vertical expansion based on its permitted design capacity as of July 17, 2014. Modification does not occur until the owner or operator commences construction on the lateral or vertical expansion.

                Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of Resource Conservation and Recovery Act (RCRA) Subtitle D wastes (§ 257.2 of this title) such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste, and industrial solid waste. Portions of an MSW landfill may be separated by access roads. An MSW landfill may be publicly or privately owned. An MSW landfill may be a new MSW landfill, an existing MSW landfill, or a lateral expansion.

                Municipal solid waste landfill emissions or MSW landfill emissions means gas generated by the decomposition of organic waste deposited in an MSW landfill or derived from the evolution of organic compounds in the waste.

                NMOC means nonmethane organic compounds, as measured according to the provisions of § 60.35f.

                Nondegradable waste means any waste that does not decompose through chemical breakdown or microbiological activity. Examples are, but are not limited to, concrete, municipal waste combustor ash, and metals.

                Passive collection system means a gas collection system that solely uses positive pressure within the landfill to move the gas rather than using gas mover equipment.

                Protectorate means American Samoa, the Commonwealth of Puerto Rico, the District of Columbia, Guam, the Northern Mariana Islands, and the Virgin Islands.

                Root cause analysis means an assessment conducted through a process of investigation to determine the primary cause, and any other contributing causes, of positive pressure at a wellhead.

                Sludge means the term sludge as defined in 40 CFR 258.2.

                Solid waste means the term solid waste as defined in 40 CFR 258.2.

                State means any of the 50 United States and the protectorates of the United States.

                State plan means a plan submitted pursuant to section 111(d) of the Clean Air Act and subpart B of this part that implements and enforces this subpart.

                Sufficient density means any number, spacing, and combination of collection system components, including vertical wells, horizontal collectors, and surface collectors, necessary to maintain emission and migration control as determined by measures of performance set forth in this part.

                Sufficient extraction rate means a rate sufficient to maintain a negative pressure at all wellheads in the collection system without causing air infiltration, including any wellheads connected to the system as a result of expansion or excess surface emissions, for the life of the blower.

                Treated landfill gas means landfill gas processed in a treatment system as defined in this subpart.

                Treatment system means a system that filters, de-waters, and compresses landfill gas for sale or beneficial use.

                Untreated landfill gas means any landfill gas that is not treated landfill gas.

            Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators

              Source:
              72 FR 32717, June 13, 2007, unless otherwise noted.

              § 60.40
              Applicability and designation of affected facility.
              (a) The affected facilities to which the provisions of this subpart apply are:
              (1) Each fossil-fuel-fired steam generating unit of more than 73 megawatts (MW) heat input rate (250 million British thermal units per hour (MMBtu/hr)).
              (2) Each fossil-fuel and wood-residue-fired steam generating unit capable of firing fossil fuel at a heat input rate of more than 73 MW (250 MMBtu/hr).
              (b) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels as defined in this subpart, shall not bring that unit under the applicability of this subpart.
              (c) Except as provided in paragraph (d) of this section, any facility under paragraph (a) of this section that commenced construction or modification after August 17, 1971, is subject to the requirements of this subpart.
              (d) The requirements of §§ 60.44 (a)(4), (a)(5), (b) and (d), and 60.45(f)(4)(vi) are applicable to lignite-fired steam generating units that commenced construction or modification after December 22, 1976.
              (e) Any facility subject to either subpart Da or KKKK of this part is not subject to this subpart.
              [72 FR 32717, June 13, 2007, as amended at 77 FR 9447, Feb. 16, 2012]

              § 60.41
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act, and in subpart A of this part.

                Boiler operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be combusted the entire 24-hour period.

                Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM D388 (incorporated by reference, see § 60.17).

                Coal refuse means waste-products of coal mining, cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.

                Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such materials for the purpose of creating useful heat.

                Fossil fuel and wood residue-fired steam generating unit means a furnace or boiler used in the process of burning fossil fuel and wood residue for the purpose of producing steam by heat transfer.

                Fossil-fuel-fired steam generating unit means a furnace or boiler used in the process of burning fossil fuel for the purpose of producing steam by heat transfer.

                Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.

                Wood residue means bark, sawdust, slabs, chips, shavings, mill trim, and other wood products derived from wood processing and forest management operations.
              [72 FR 32717, June 13, 2007, as amended at 77 FR 9447, Feb. 16, 2012]

              § 60.42
              Standard for particulate matter (PM).
              (a) Except as provided under paragraphs (b), (c), (d), and (e) of this section, on and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that:
              (1) Contain PM in excess of 43 nanograms per joule (ng/J) heat input (0.10 lb/MMBtu) derived from fossil fuel or fossil fuel and wood residue.
              (2) Exhibit greater than 20 percent opacity except for one six-minute period per hour of not more than 27 percent opacity.
              (b)(1) On or after December 28, 1979, no owner or operator shall cause to be discharged into the atmosphere from the Southwestern Public Service Company's Harrington Station #1, in Amarillo, TX, any gases which exhibit greater than 35 percent opacity, except that a maximum or 42 percent opacity shall be permitted for not more than 6 minutes in any hour.
              (2) Interstate Power Company shall not cause to be discharged into the atmosphere from its Lansing Station Unit No. 4 in Lansing, IA, any gases which exhibit greater than 32 percent opacity, except that a maximum of 39 percent opacity shall be permitted for not more than six minutes in any hour.
              (c) As an alternate to meeting the requirements of paragraph (a) of this section, an owner or operator that elects to install, calibrate, maintain, and operate a continuous emissions monitoring systems (CEMS) for measuring PM emissions can petition the Administrator (in writing) to comply with § 60.42Da(a) of subpart Da of this part. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.42Da(a) of subpart Da of this part.
              (d) An owner or operator of an affected facility that combusts only natural gas is exempt from the PM and opacity standards specified in paragraph (a) of this section.

              (e) An owner or operator of an affected facility that combusts only gaseous or liquid fossil fuel (excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that does not use post-combustion technology to reduce emissions of SO2 or PM is exempt from the PM standards specified in paragraph (a) of this section.
              [60 FR 65415, Dec. 19, 1995, as amended at 76 FR 3522, Jan. 20, 2011; 74 FR 5077, Jan. 28, 2009; 77 FR 9447, Feb. 16, 2012]

              § 60.43
              Standard for sulfur dioxide (SO2).

              (a) Except as provided under paragraph (d) of this section, on and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that contain SO2 in excess of:
              (1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil fuel or liquid fossil fuel and wood residue.
              (2) 520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue, except as provided in paragraph (e) of this section.
              (b) Except as provided under paragraph (d) of this section, when different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) shall be determined by proration using the following formula:

                ER13JN07.000

                Where:

                PSSO
                  2 = Prorated standard for SO2 when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels or from all fossil fuels and wood residue fired;

                y = Percentage of total heat input derived from liquid fossil fuel; and
                z = Percentage of total heat input derived from solid fossil fuel.

              (c) Compliance shall be based on the total heat input from all fossil fuels burned, including gaseous fuels.
              (d) As an alternate to meeting the requirements of paragraphs (a) and (b) of this section, an owner or operator can petition the Administrator (in writing) to comply with § 60.43Da(i)(3) of subpart Da of this part or comply with § 60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.43Da(i)(3) of subpart Da of this part or § 60.42b(k)(4) of subpart Db of this part, as applicable to the affected source.
              (e) Units 1 and 2 (as defined in appendix G of this part) at the Newton Power Station owned or operated by the Central Illinois Public Service Company will be in compliance with paragraph (a)(2) of this section if Unit 1 and Unit 2 individually comply with paragraph (a)(2) of this section or if the combined emission rate from Units 1 and 2 does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1 and 2.
              [60 FR 65415, Dec. 19, 1995, as amended at 74 FR 5077, Jan. 28, 2009]

              § 60.44
              Standard for nitrogen oxides (NOX).

              (a) Except as provided under paragraph (e) of this section, on and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that contain NOX, expressed as NO2 in excess of:
              (1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil fuel.
              (2) 129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and wood residue.
              (3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue (except lignite or a solid fossil fuel containing 25 percent, by weight, or more of coal refuse).
              (4) 260 ng/J heat input (0.60 lb MMBtu) derived from lignite or lignite and wood residue (except as provided under paragraph (a)(5) of this section).
              (5) 340 ng/J heat input (0.80 lb MMBtu) derived from lignite which is mined in North Dakota, South Dakota, or Montana and which is burned in a cyclone-fired unit.
              (b) Except as provided under paragraphs (c), (d), and (e) of this section, when different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) is determined by proration using the following formula:

                ER13JN07.001

                Where:

                PSNO
                  X = Prorated standard for NOX when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels fired or from all fossil fuels and wood residue fired;
                w = Percentage of total heat input derived from lignite;
                x = Percentage of total heat input derived from gaseous fossil fuel;
                y = Percentage of total heat input derived from liquid fossil fuel; and
                z = Percentage of total heat input derived from solid fossil fuel (except lignite).

              (c) When a fossil fuel containing at least 25 percent, by weight, of coal refuse is burned in combination with gaseous, liquid, or other solid fossil fuel or wood residue, the standard for NOX does not apply.

              (d) Except as provided under paragraph (e) of this section, cyclone-fired units which burn fuels containing at least 25 percent of lignite that is mined in North Dakota, South Dakota, or Montana remain subject to paragraph (a)(5) of this section regardless of the types of fuel combusted in combination with that lignite.
              (e) As an alternate to meeting the requirements of paragraphs (a), (b), and (d) of this section, an owner or operator can petition the Administrator (in writing) to comply with § 60.44Da(e)(3) of subpart Da of this part. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in § 60.44Da(e)(3) of subpart Da of this part.

              § 60.45
              Emissions and fuel monitoring.

              (a) Each owner or operator of an affected facility subject to the applicable emissions standard shall install, calibrate, maintain, and operate continuous opacity monitoring system (COMS) for measuring opacity and a continuous emissions monitoring system (CEMS) for measuring SO2 emissions, NOX emissions, and either oxygen (O2) or carbon dioxide (CO2) except as provided in paragraph (b) of this section.
              (b) Certain of the CEMS and COMS requirements under paragraph (a) of this section do not apply to owners or operators under the following conditions:

              (1) For a fossil-fuel-fired steam generator that combusts only gaseous or liquid fossil fuel (excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that does not use post-combustion technology to reduce emissions of SO2 or PM, COMS for measuring the opacity of emissions and CEMS for measuring SO2 emissions are not required if the owner or operator monitors SO2 emissions by fuel sampling and analysis or fuel receipts.

              (2) For a fossil-fuel-fired steam generator that does not use a flue gas desulfurization device, a CEMS for measuring SO2 emissions is not required if the owner or operator monitors SO2 emissions by fuel sampling and analysis.

              (3) Notwithstanding § 60.13(b), installation of a CEMS for NOX may be delayed until after the initial performance tests under § 60.8 have been conducted. If the owner or operator demonstrates during the performance test that emissions of NOX are less than 70 percent of the applicable standards in § 60.44, a CEMS for measuring NOX emissions is not required. If the initial performance test results show that NOX emissions are greater than 70 percent of the applicable standard, the owner or operator shall install a CEMS for NOX within one year after the date of the initial performance tests under § 60.8 and comply with all other applicable monitoring requirements under this part.

              (4) If an owner or operator is not required to and elects not to install any CEMS for either SO2 or NOX, a CEMS for measuring either O2 or CO2 is not required.
              (5) For affected facilities using a PM CEMS, a bag leak detection system to monitor the performance of a fabric filter (baghouse) according to the most current requirements in § 60.48Da of this part, or an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section § 60.48Da of this part a COMS is not required.

              (6) A COMS for measuring the opacity of emissions is not required for an affected facility that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO2, or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected source are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating day average basis. Owners and operators of affected sources electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (b)(6)(i) through (iv) of this section.

              (i) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (b)(6)(i)(A) through (D) of this section.

              (A) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part.
              (B) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
              (C) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data points required in § 60.13(h)(2).
              (D) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.
              (ii) You must calculate the 1-hour average CO emissions levels for each boiler operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each boiler operating day.
              (iii) You must evaluate the preceding 24-hour average CO emission level each boiler operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less.
              (iv) You must record the CO measurements and calculations performed according to paragraph (b)(6) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the corrective action.
              (7) An owner or operator of an affected facility subject to an opacity standard under § 60.42 that elects to not use a COMS because the affected facility burns only fuels as specified under paragraph (b)(1) of this section, monitors PM emissions as specified under paragraph (b)(5) of this section, or monitors CO emissions as specified under paragraph (b)(6) of this section, shall conduct a performance test using Method 9 of appendix A-4 of this part and the procedures in § 60.11 to demonstrate compliance with the applicable limit in § 60.42 by April 29, 2011 or within 45 days after stopping use of an existing COMS, whichever is later, and shall comply with either paragraph (b)(7)(i), (b)(7)(ii), or (b)(7)(iii) of this section. The observation period for Method 9 of appendix A-4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation. The permitting authority may exempt owners or operators of affected facilities burning only natural gas from the opacity monitoring requirements.
              (i) Except as provided in paragraph (b)(7)(ii) or (b)(7)(iii) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A-4 of this part performance tests using the procedures in paragraph (b)(7) of this section according to the applicable schedule in paragraphs (b)(7)(i)(A) through (b)(7)(i)(D) of this section, as determined by the most recent Method 9 of appendix A-4 of this part performance test results.
              (A) If no visible emissions are observed, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;

              (B) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 6 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
              (C) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or
              (D) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted.
              (ii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A-4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A-4 of this part performance test, elect to perform subsequent monitoring using Method 22 of appendix A-7 of this part according to the procedures specified in paragraphs (b)(7)(ii)(A) and (B) of this section.

              (A) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A-7 of this part and demonstrate that the sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation period (i.e., 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period (i.e., 90 seconds per 30 minute period), the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute observation (i.e., 90 seconds) or conduct a new Method 9 of appendix A-4 of this part performance test using the procedures in paragraph (b)(7) of this section within 45 calendar days according to the requirements in § 60.46(b)(3).
              (B) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed.
              (iii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A-4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A-4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily identical, to the requirements in paragraph (b)(7)(ii) of this section. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243-02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods.
              (8) A COMS for measuring the opacity of emissions is not required for an affected facility at which the owner or operator installs, calibrates, operates, and maintains a particulate matter continuous parametric monitoring system (PM CPMS) according to the requirements specified in subpart UUUUU of part 63.

              (c) For performance evaluations under § 60.13(c) and calibration checks under § 60.13(d), the following procedures shall be used:

              (1) Methods 6, 7, and 3B of appendix A of this part, as applicable, shall be used for the performance evaluations of SO2 and NOX continuous monitoring systems. Acceptable alternative methods for Methods 6, 7, and 3B of appendix A of this part are given in § 60.46(d).
              (2) Sulfur dioxide or nitric oxide, as applicable, shall be used for preparing calibration gas mixtures under Performance Specification 2 of appendix B to this part.

              (3) For affected facilities burning fossil fuel(s), the span value for a continuous monitoring system measuring the opacity of emissions shall be 80, 90, or 100 percent. For a continuous monitoring system measuring sulfur oxides or NOX the span value shall be determined using one of the following procedures:

              (i) Except as provided under paragraph (c)(3)(ii) of this section, SO2 and NOX span values shall be determined as follows:

                  Fossil fuel
                  In parts per million
                  Span value for SO2

                  Span value for NOX

                  Gas
                  (1)
                  500.

                  Liquid
                  1,000
                  500.

                  Solid
                  1,500
                  1,000.

                  Combinations
                  1,000y + 1,500z
                  500 (x + y) + 1,000z.

                  1 Not applicable.

                Where:

                x = Fraction of total heat input derived from gaseous fossil fuel;
                y = Fraction of total heat input derived from liquid fossil fuel; and
                z = Fraction of total heat input derived from solid fossil fuel.

              (ii) As an alternative to meeting the requirements of paragraph (c)(3)(i) of this section, the owner or operator of an affected facility may elect to use the SO2 and NOX span values determined according to sections 2.1.1 and 2.1.2 in appendix A to part 75 of this chapter.
              (4) All span values computed under paragraph (c)(3)(i) of this section for burning combinations of fossil fuels shall be rounded to the nearest 500 ppm. Span values that are computed under paragraph (c)(3)(ii) of this section shall be rounded off according to the applicable procedures in section 2 of appendix A to part 75 of this chapter.
              (5) For a fossil-fuel-fired steam generator that simultaneously burns fossil fuel and nonfossil fuel, the span value of all CEMS shall be subject to the Administrator's approval.
              (d) [Reserved]
              (e) For any CEMS installed under paragraph (a) of this section, the following conversion procedures shall be used to convert the continuous monitoring data into units of the applicable standards (ng/J, lb/MMBtu):
              (1) When a CEMS for measuring O2 is selected, the measurement of the pollutant concentration and O2 concentration shall each be on a consistent basis (wet or dry). Alternative procedures approved by the Administrator shall be used when measurements are on a wet basis. When measurements are on a dry basis, the following conversion procedure shall be used:

                ER13JN07.002

                Where E, C, F, and %O2 are determined under paragraph (f) of this section.

              (2) When a CEMS for measuring CO2 is selected, the measurement of the pollutant concentration and CO2 concentration shall each be on a consistent basis (wet or dry) and the following conversion procedure shall be used:

                ER13JN07.003

                Where E, C, Fc and %CO2 are determined under paragraph (f) of this section.

              (f) The values used in the equations under paragraphs (e)(1) and (2) of this section are derived as follows:
              (1) E = pollutant emissions, ng/J (lb/MMBtu).

              (2) C = pollutant concentration, ng/dscm (lb/dscf), determined by multiplying the average concentration (ppm) for each one-hour period by 4.15 × 104 M ng/dscm per ppm (2.59 × 10−9 M lb/dscf per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO2 and 46.01 for NOX.
              (3) %O2, %CO2 = O2 or CO2 volume (expressed as percent), determined with equipment specified under paragraph (a) of this section.
              (4) F, Fc = a factor representing a ratio of the volume of dry flue gases generated to the calorific value of the fuel combusted (F), and a factor representing a ratio of the volume of CO2 generated to the calorific value of the fuel combusted (Fc), respectively. Values of F and Fc are given as follows:

              (i) For anthracite coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2,723 × 10−17 dscm/J (10,140 dscf/MMBtu) and Fc = 0.532 × 10−17 scm CO2/J (1,980 scf CO2/MMBtu).

              (ii) For subbituminous and bituminous coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2.637 × 10−7 dscm/J (9,820 dscf/MMBtu) and Fc = 0.486 × 10−7 scm CO2/J (1,810 scf CO2/MMBtu).

              (iii) For liquid fossil fuels including crude, residual, and distillate oils, F = 2.476 × 10−7 dscm/J (9,220 dscf/MMBtu) and Fc = 0.384 × 10−7 scm CO2/J (1,430 scf CO2/MMBtu).
              (iv) For gaseous fossil fuels, F = 2.347 × 10−7 dscm/J (8,740 dscf/MMBtu). For natural gas, propane, and butane fuels, Fc = 0.279 × 10−7 scm CO2/J (1,040 scf CO2/MMBtu) for natural gas, 0.322 × 10−7 scm CO2/J (1,200 scf CO2/MMBtu) for propane, and 0.338 × 10−7 scm CO2/J (1,260 scf CO2/MMBtu) for butane.
              (v) For bark F = 2.589 × 10−7 dscm/J (9,640 dscf/MMBtu) and Fc = 0.500 × 10−7 scm CO2/J (1,840 scf CO2/MMBtu). For wood residue other than bark F = 2.492 × 10−7 dscm/J (9,280 dscf/MMBtu) and Fc = 0.494 × 10−7 scm CO2/J (1,860 scf CO2/MMBtu).

              (vi) For lignite coal as classified according to ASTM D388 (incorporated by reference, see § 60.17), F = 2.659 × 10−7 dscm/J (9,900 dscf/MMBtu) and Fc = 0.516 × 10−7 scm CO2/J (1,920 scf CO2/MMBtu).

              (5) The owner or operator may use the following equation to determine an F factor (dscm/J or dscf/MMBtu) on a dry basis (if it is desired to calculate F on a wet basis, consult the Administrator) or Fc factor (scm CO2/J, or scf CO2/MMBtu) on either basis in lieu of the F or Fc factors specified in paragraph (f)(4) of this section:

                ER13JN07.004

              (i) %H, %C, %S, %N, and %O are content by weight of hydrogen, carbon, sulfur, nitrogen, and O2 (expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or computed from results using ASTM D1137, D1945, or D1946 (gaseous fuels) as applicable. (These five methods are incorporated by reference, see § 60.17.)
              (ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted determined by the ASTM test methods D2015 or D5865 for solid fuels and D1826 for gaseous fuels as applicable. (These three methods are incorporated by reference, see § 60.17.)
              (iii) For affected facilities which fire both fossil fuels and nonfossil fuels, the F or Fc value shall be subject to the Administrator's approval.
              (6) For affected facilities firing combinations of fossil fuels or fossil fuels and wood residue, the F or Fc factors determined by paragraphs (f)(4) or (f)(5) of this section shall be prorated in accordance with the applicable formula as follows:

                ER13JN07.005

                Where:

                Xi = Fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood residue, etc.);
                Fi or (Fc)i = Applicable F or Fc factor for each fuel type determined in accordance with paragraphs (f)(4) and (f)(5) of this section; and
                n = Number of fuels being burned in combination.

              (g) Excess emission and monitoring system performance reports shall be submitted to the Administrator semiannually for each six-month period in the calendar year. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period. Each excess emission and MSP report shall include the information required in § 60.7(c). Periods of excess emissions and monitoring systems (MS) downtime that shall be reported are defined as follows:
              (1) Opacity. Excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 20 percent opacity, except that one six-minute average per hour of up to 27 percent opacity need not be reported.

              (i) For sources subject to the opacity standard of § 60.42(b)(1), excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 35 percent opacity, except that one six-minute average per hour of up to 42 percent opacity need not be reported.
              (ii) For sources subject to the opacity standard of § 60.42(b)(2), excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 32 percent opacity, except that one six-minute average per hour of up to 39 percent opacity need not be reported.
              (2) Sulfur dioxide. Excess emissions for affected facilities are defined as:

              (i) For affected facilities electing not to comply with § 60.43(d), any three-hour period during which the average emissions (arithmetic average of three contiguous one-hour periods) of SO2 as measured by a CEMS exceed the applicable standard in § 60.43; or

              (ii) For affected facilities electing to comply with § 60.43(d), any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of SO2 as measured by a CEMS exceed the applicable standard in § 60.43. Facilities complying with the 30-day SO2 standard shall use the most current associated SO2 compliance and monitoring requirements in §§ 60.48Da and 60.49Da of subpart Da of this part or §§ 60.45b and 60.47b of subpart Db of this part, as applicable.
              (3) Nitrogen oxides. Excess emissions for affected facilities using a CEMS for measuring NOX are defined as:
              (i) For affected facilities electing not to comply with § 60.44(e), any three-hour period during which the average emissions (arithmetic average of three contiguous one-hour periods) exceed the applicable standards in § 60.44; or

              (ii) For affected facilities electing to comply with § 60.44(e), any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of NOX as measured by a CEMS exceed the applicable standard in § 60.44. Facilities complying with the 30-day NOX standard shall use the most current associated NOX compliance and monitoring requirements in §§ 60.48Da and 60.49Da of subpart Da of this part.
              (4) Particulate matter. Excess emissions for affected facilities using a CEMS for measuring PM are defined as any boiler operating day period during which the average emissions (arithmetic average of all operating one-hour periods) exceed the applicable standards in § 60.42. Affected facilities using PM CEMS must follow the most current applicable compliance and monitoring provisions in §§ 60.48Da and 60.49Da of subpart Da of this part.
              (h) The owner or operator of an affected facility subject to the opacity limits in § 60.42 that elects to monitor emissions according to the requirements in § 60.45(b)(7) shall maintain records according to the requirements specified in paragraphs (h)(1) through (3) of this section, as applicable to the visible emissions monitoring method used.
              (1) For each performance test conducted using Method 9 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (h)(1)(i) through (iii) of this section.
              (i) Dates and time intervals of all opacity observation periods;
              (ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and
              (iii) Copies of all visible emission observer opacity field data sheets;
              (2) For each performance test conducted using Method 22 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (h)(2)(i) through (iv) of this section.
              (i) Dates and time intervals of all visible emissions observation periods;
              (ii) Name and affiliation for each visible emission observer participating in the performance test;
              (iii) Copies of all visible emission observer opacity field data sheets; and
              (iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements.

              (3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the Administrator.
              [60 FR 65415, Dec. 19, 1995, as amended at 74 FR 5077, Jan. 28, 2009; 76 FR 3522, Jan. 20, 2011; 77 FR 9447, Feb. 16, 2012]

              § 60.46
              Test methods and procedures.
              (a) In conducting the performance tests required in § 60.8, and subsequent performance tests as requested by the EPA Administrator, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b). Acceptable alternative methods and procedures are given in paragraph (d) of this section.

              (b) The owner or operator shall determine compliance with the PM, SO2, and NOX standards in §§ 60.42, 60.43, and 60.44 as follows:
              (1) The emission rate (E) of PM, SO2, or NOX shall be computed for each run using the following equation:

                ER13JN07.006

                Where:

                E = Emission rate of pollutant, ng/J (1b/million Btu);
                C = Concentration of pollutant, ng/dscm (1b/dscf);
                %O2 = O2 concentration, percent dry basis; and
                Fd = Factor as determined from Method 19 of appendix A of this part.

              (2) Method 5 of appendix A of this part shall be used to determine the PM concentration (C) at affected facilities without wet flue-gas-desulfurization (FGD) systems and Method 5B of appendix A of this part shall be used to determine the PM concentration (C) after FGD systems.
              (i) The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder heating systems in the sampling train shall be set to provide an average gas temperature of 160±14 °C (320±25 °F).

              (ii) The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O2 concentration (%O2). The O2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate sample. If the grab sampling procedure is used, the O2 concentration for the run shall be the arithmetic mean of the sample O2 concentrations at all traverse points.

              (iii) If the particulate run has more than 12 traverse points, the O2 traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O2 traverse points.
              (3) Method 9 of appendix A of this part and the procedures in § 60.11 shall be used to determine opacity.

              (4) Method 6 of appendix A of this part shall be used to determine the SO2 concentration.
              (i) The sampling site shall be the same as that selected for the particulate sample. The sampling location in the duct shall be at the centroid of the cross section or at a point no closer to the walls than 1 m (3.28 ft). The sampling time and sample volume for each sample run shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples shall be taken during a 1-hour period, with each sample taken within a 30-minute interval.

              (ii) The emission rate correction factor, integrated sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O2 concentration (%O2). The O2 sample shall be taken simultaneously with, and at the same point as, the SO2 sample. The SO2 emission rate shall be computed for each pair of SO2 and O2 samples. The SO2 emission rate (E) for each run shall be the arithmetic mean of the results of the two pairs of samples.

              (5) Method 7 of appendix A of this part shall be used to determine the NOX concentration.

              (i) The sampling site and location shall be the same as for the SO2 sample. Each run shall consist of four grab samples, with each sample taken at about 15-minute intervals.
              (ii) For each NOX sample, the emission rate correction factor, grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O2 concentration (%O2). The sample shall be taken simultaneously with, and at the same point as, the NOX sample.
              (iii) The NOX emission rate shall be computed for each pair of NOX and O2 samples. The NOX emission rate (E) for each run shall be the arithmetic mean of the results of the four pairs of samples.
              (c) When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator (in order to compute the prorated standard as shown in §§ 60.43(b) and 60.44(b)) shall determine the percentage (w, x, y, or z) of the total heat input derived from each type of fuel as follows:
              (1) The heat input rate of each fuel shall be determined by multiplying the gross calorific value of each fuel fired by the rate of each fuel burned.
              (2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid fuels), or D1826 (gaseous fuels) (all of these methods are incorporated by reference, see § 60.17) shall be used to determine the gross calorific values of the fuels. The method used to determine the calorific value of wood residue must be approved by the Administrator.
              (3) Suitable methods shall be used to determine the rate of each fuel burned during each test period, and a material balance over the steam generating system shall be used to confirm the rate.
              (d) The owner or operator may use the following as alternatives to the reference methods and procedures in this section or in other sections as specified:
              (1) The emission rate (E) of PM, SO2 and NOX may be determined by using the Fc factor, provided that the following procedure is used:

              (i) The emission rate (E) shall be computed using the following equation:

                ER13JN07.007

                Where:

                E = Emission rate of pollutant, ng/J (lb/MMBtu);
                C = Concentration of pollutant, ng/dscm (lb/dscf);
                %CO2 = CO2 concentration, percent dry basis; and
                Fc = Factor as determined in appropriate sections of Method 19 of appendix A of this part.

              (ii) If and only if the average Fc factor in Method 19 of appendix A of this part is used to calculate E and either E is from 0.97 to 1.00 of the emission standard or the relative accuracy of a continuous emission monitoring system is from 17 to 20 percent, then three runs of Method 3B of appendix A of this part shall be used to determine the O2 and CO2 concentration according to the procedures in paragraph (b)(2)(ii), (4)(ii), or (5)(ii) of this section. Then if Fo (average of three runs), as calculated from the equation in Method 3B of appendix A of this part, is more than ±3 percent than the average Fo value, as determined from the average values of Fd and Fc in Method 19 of appendix A of this part, i.e., Foa = 0.209 (Fda/Fca), then the following procedure shall be followed:
              (A) When Fo is less than 0.97 Foa, then E shall be increased by that proportion under 0.97 Foa, e.g., if Fo is 0.95 Foa, E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the emission standard.
              (B) When Fo is less than 0.97 Foa and when the average difference (d) between the continuous monitor minus the reference methods is negative, then E shall be increased by that proportion under 0.97 Foa, e.g., if Fo is 0.95 Foa, E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the relative accuracy specification.
              (C) When Fo is greater than 1.03 Foa and when the average difference d is positive, then E shall be decreased by that proportion over 1.03 Foa, e.g., if Fo is 1.05 Foa, E shall be decreased by 2 percent. This recalculated value shall be used to determine compliance with the relative accuracy specification.

              (2) For Method 5 or 5B of appendix A-3 of this part, Method 17 of appendix A-6 of this part may be used at facilities with or without wet FGD systems if the stack gas temperature at the sampling location does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of this part may be used with Method 17 of appendix A-6 of this part only if it is used after wet FGD systems. Method 17 of appendix A-6 of this part shall not be used after wet FGD systems if the effluent gas is saturated or laden with water droplets.
              (3) Particulate matter and SO2 may be determined simultaneously with the Method 5 of appendix A of this part train provided that the following changes are made:
              (i) The filter and impinger apparatus in sections 2.1.5 and 2.1.6 of Method 8 of appendix A of this part is used in place of the condenser (section 2.1.7) of Method 5 of appendix A of this part.

              (ii) All applicable procedures in Method 8 of appendix A of this part for the determination of SO2 (including moisture) are used:

              (4) For Method 6 of appendix A of this part, Method 6C of appendix A of this part may be used. Method 6A of appendix A of this part may also be used whenever Methods 6 and 3B of appendix A of this part data are specified to determine the SO2 emission rate, under the conditions in paragraph (d)(1) of this section.

              (5) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be at least 1 hour and the integrated sampling approach shall be used to determine the O2 concentration (%O2) for the emission rate correction factor.
              (6) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used.
              (7) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used.
              [60 FR 65415, Dec. 19, 1995, as amended at 74 FR 5078, Jan. 28, 2009]

            Subpart Da—Standards of Performance for Electric Utility Steam Generating Units

              Source:
              72 FR 32722, June 13, 2007, unless otherwise noted.

              § 60.40Da
              Applicability and designation of affected facility.
              (a) Except as specified in paragraph (e) of this section, the affected facility to which this subpart applies is each electric utility steam generating unit:
              (1) That is capable of combusting more than 73 megawatts (MW) (250 million British thermal units per hour (MMBtu/hr)) heat input of fossil fuel (either alone or in combination with any other fuel); and
              (2) For which construction, modification, or reconstruction is commenced after September 18, 1978.
              (b) An IGCC electric utility steam generating unit (both the stationary combustion turbine and any associated duct burners) is subject to this part and is not subject to subpart GG or KKKK of this part if both of the conditions specified in paragraphs (b)(1) and (2) of this section are met.
              (1) The IGCC electric utility steam generating unit is capable of combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel) in the combustion turbine engine and associated heat recovery steam generator; and
              (2) The IGCC electric utility steam generating unit commenced construction, modification, or reconstruction after February 28, 2005.
              (c) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels, shall not bring that unit under the applicability of this subpart.
              (d) Any change to an existing steam generating unit originally designed to fire gaseous or liquid fossil fuels, to accommodate the use of any other fuel (fossil or nonfossil) shall not bring that unit under the applicability of this subpart.
              (e) Applicability of this subpart to an electric utility combined cycle gas turbine other than an IGCC electric utility steam generating unit is as specified in paragraphs (e)(1) through (3) of this section.
              (1) Affected facilities (i.e. heat recovery steam generators used with duct burners) associated with a stationary combustion turbine that are capable of combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel are subject to this subpart except in cases when the affected facility (i.e. heat recovery steam generator) meets the applicability requirements of and is subject to subpart KKKK of this part.

              (2) For heat recovery steam generators use with duct burners subject to this subpart, only emissions resulting from the combustion of fuels in the steam generating unit (i.e. duct burners) are subject to the standards under this subpart. (The emissions resulting from the combustion of fuels in the stationary combustion turbine engine are subject to subpart GG or KKKK, as applicable, of this part.)
              (3) Any affected facility that meets the applicability requirements and is subject to subpart Eb or subpart CCCC of this part is not subject to the emission standards under subpart Da.
              [72 FR 32722, June 13, 2007, as amended at 74 FR 5078, Jan. 28, 2009; 77 FR 9448, Feb. 16, 2012]

              § 60.41Da
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.

                Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.

                Anthracite means coal that is classified as anthracite according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

                Available system capacity means the capacity determined by subtracting the system load and the system emergency reserves from the net system capacity.

                Biomass means plant materials and animal waste.

                Bituminous coal means coal that is classified as bituminous according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

                Boiler operating day for units constructed, reconstructed, or modified before March 1, 2005, means a 24-hour period during which fossil fuel is combusted in a steam-generating unit for the entire 24 hours. For units constructed, reconstructed, or modified after February 28, 2005, boiler operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be combusted the entire 24-hour period.

                Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17) and coal refuse. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal, coal-oil mixtures, and coal-water mixtures are included in this definition for the purposes of this subpart.

                Coal-fired electric utility steam generating unit means an electric utility steam generating unit that burns coal, coal refuse, or a synthetic gas derived from coal either exclusively, in any combination together, or in any combination with other fuels in any amount.

                Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.

                Combined cycle gas turbine means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a steam generating unit.

                Combined heat and power, also known as “cogeneration,” means a steam-generating unit that simultaneously produces both electric (and mechanical) and useful thermal energy from the same primary energy source.

                Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit.

                Electric utility combined cycle gas turbine means any combined cycle gas turbine used for electric generation that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW net-electrical output to any utility power distribution system for sale. Any steam distribution system that is constructed for the purpose of providing steam to a steam electric generator that would produce electrical power for sale is also considered in determining the electrical energy output capacity of the affected facility.

                Electric utility steam-generating unit means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW net-electrical output to any utility power distribution system for sale. Also, any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is considered in determining the electrical energy output capacity of the affected facility.

                Electrostatic precipitator or ESP means an add-on air pollution control device used to capture particulate matter (PM) by charging the particles using an electrostatic field, collecting the particles using a grounded collecting surface, and transporting the particles into a hopper.

                Emission limitation means any emissions limit or operating limit.

                Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24.

                Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.

                Gaseous fuel means any fuel that is present as a gas at standard conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.

                Gross energy output means:

              (1) For facilities constructed, reconstructed, or modified before May 4, 2011, the gross electrical or mechanical output from the affected facility plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process);

              (2) For facilities constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process);

              (3) For combined heat and power facilities constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility divided by 0.95 minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process);

              (4) For a IGCC electric utility generating unit that coproduces chemicals constructed, reconstructed, or modified after May 3, 2011, the gross useful work performed is the gross electrical or mechanical output from the unit minus electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) that are associated with power production plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process). Auxiliary loads that are associated with power production are determined based on the energy in the coproduced chemicals compared to the energy of the syngas combusted in combustion turbine engine and associated duct burners.

                24-hour period means the period of time between 12:01 a.m. and 12:00 midnight.

                Integrated gasification combined cycle electric utility steam generating unit or IGCC electric utility steam generating unit means an electric utility combined cycle gas turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation.

                ISO conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals.

                Lignite means coal that is classified as lignite A or B according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

                Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.

                Neighboring company means any one of those electric utility companies with one or more electric power interconnections to the principal company and which have geographically adjoining service areas.

                Net-electric output means the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis.

                Net energy output means the gross energy output minus the parasitic load associated with power production. Parasitic load includes, but is not limited to, the power required to operate the equipment used for fuel delivery systems, air pollution control systems, wastewater treatment systems, ash handling and disposal systems, and other controls (i.e., pumps, fans, compressors, motors, instrumentation, and other ancillary equipment required to operate the affected facility).

                Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands.

                Out-of-control period means any period beginning with the quadrant corresponding to the completion of a daily calibration error, linearity check, or quality assurance audit that indicates that the instrument is not measuring and recording within the applicable performance specifications and ending with the quadrant corresponding to the completion of an additional calibration error, linearity check, or quality assurance audit following corrective action that demonstrates that the instrument is measuring and recording within the applicable performance specifications.

                Petroleum for facilities constructed, reconstructed, or modified before May 4, 2011, means crude oil or a fuel derived from crude oil, including, but not limited to, distillate oil, and residual oil. For units constructed, reconstructed, or modified after May 3, 2011, petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate oil, residual oil, and petroleum coke.

                Petroleum coke, also known as “petcoke,” means a carbonization product of high-boiling hydrocarbon fractions obtained in petroleum processing (heavy residues). Petroleum coke
                is typically derived from oil refinery coker units or other cracking processes.

                Potential combustion concentration means the theoretical emissions (nanograms per joule (ng/J), lb/MMBtu heat input) that would result from combustion of a fuel in an uncleaned state without emission control systems. For sulfur dioxide (SO2) the potential combustion concentration is determined under § 60.50Da(c).

                Potential electrical output capacity means 33 percent of the maximum design heat input capacity of the steam generating unit, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr (e.g., a steam generating unit with a 100 MW (340 MMBtu/hr) fossil-fuel heat input capacity would have a 289,080 MWh 12 month potential electrical output capacity). For electric utility combined cycle gas turbines the potential electrical output capacity is determined on the basis of the fossil-fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine.

                Resource recovery unit means a facility that combusts more than 75 percent non-fossil fuel on a quarterly (calendar) heat input basis.

                Solid-derived fuel means any solid, liquid, or gaseous fuel derived from solid fuel for the purpose of creating useful heat and includes, but is not limited to, solvent refined coal, liquified coal, synthetic gas, gasified coal, gasified petroleum coke, gasified biomass, and gasified tire derived fuel.

                Steam generating unit for facilities constructed, reconstructed, or modified before May 4, 2011, means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included). For units constructed, reconstructed, or modified after May 3, 2011, steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included) plus any integrated combustion turbines and fuel cells.

                Subbituminous coal means coal that is classified as subbituminous A, B, or C according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

                Wet flue gas desulfurization technology or wet FGD means a SO2 control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet FGD technology include, but are not limited to, lime, limestone, and sodium.
              [72 FR 32722, June 13, 2007, as amended at 74 FR 5079, Jan. 28, 2009; 77 FR 9448, Feb. 16, 2012; 77 FR 23402, Apr. 19, 2012; 78 FR 24082, Apr. 24, 2013]

              § 60.42Da
              Standards for particulate matter (PM).
              (a) Except as provided in paragraph (f) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, an owner or operator of an affected facility shall not cause to be discharged into the atmosphere from any affected facility for which construction, reconstruction, or modification commenced before March 1, 2005, any gases that contain PM in excess of 13 ng/J (0.03 lb/MMBtu) heat input.
              (b) Except as provided in paragraphs (b)(1) and (b)(2) of this section, on and after the date the initial PM performance test is completed or required to be completed under § 60.8, whichever date comes first, an owner or operator of an affected facility shall not cause to be discharged into the atmosphere any gases which exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.

              (1) An owner or operator of an affected facility that elects to install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart is exempt from the opacity standard specified in this paragraph (b) of this section.
              (2) An owner or operator of an affected facility that combusts only natural gas and/or synthetic natural gas that chemically meets the definition of natural gas is exempt from the opacity standard specified in paragraph (b) of this section.
              (c) Except as provided in paragraphs (d) and (f) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005, but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of either:
              (1) 18 ng/J (0.14 lb/MWh) gross energy output; or
              (2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel.
              (d) As an alternative to meeting the requirements of paragraph (c) of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, but before May 4, 2011, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of:
              (1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel, and
              (2) For an affected facility that commenced construction or reconstruction, 0.1 percent of the combustion concentration determined according to the procedure in § 60.48Da(o)(5) (99.9 percent reduction) when combusting solid, liquid, or gaseous fuel, or
              (3) For an affected facility that commenced modification, 0.2 percent of the combustion concentration determined according to the procedure in § 60.48Da(o)(5) (99.8 percent reduction) when combusting solid, liquid, or gaseous fuel.
              (e) Except as provided in paragraph (f) of this section, the owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after May 3, 2011, shall meet the requirements specified in paragraphs (e)(1) and (2) of this section.
              (1) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator shall not cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the applicable emissions limit specified in paragraphs (e)(1)(i) or (ii) of this section.
              (i) For an affected facility which commenced construction or reconstruction:
              (A) 11 ng/J (0.090 lb/MWh) gross energy output; or
              (B) 12 ng/J (0.097 lb/MWh) net energy output.
              (ii) For an affected facility which commenced modification, the emission limits specified in paragraphs (c) or (d) of this section.
              (2) During startup periods and shutdown periods, owners or operators of facilities subject to subpart UUUUU of part 63 of this chapter shall meet the work practice standards specified in Table 3 to subpart UUUUU of part 63 and use the relevant definitions in § 63.10042, and owners or operators of facilities subject to subpart DDDDD of part 63 shall meet the work practice standards specified in Table 3 to subpart DDDDD of part 63 and use the relevant definition used in § 63.7575.
              (f) An owner or operator of an affected facility that meets the conditions in either paragraphs (f)(1) or (2) of this section is exempt from the PM emissions limits in this section.

              (1) The affected facility combusts only gaseous or liquid fuels (excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and that does not use a post-combustion technology to reduce emissions of SO2 or PM.

              (2) The affected facility is operated under a PM commercial demonstration permit issued by the Administrator according to the provisions of § 60.47Da.
              [77 FR 9450, Feb. 16, 2012, as amended at 78 FR 24083, Apr. 24, 2013; 79 FR 68788, Nov. 19, 2014]

              § 60.43Da
              Standards for sulfur dioxide (SO2).

              (a) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid fuel or solid-derived fuel and for which construction, reconstruction, or modification commenced before or on February 28, 2005, except as provided under paragraphs (c), (d), (f) or (h) of this section, any gases that contain SO2 in excess of:
              (1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction);
              (2) 30 percent of the potential combustion concentration (70 percent reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat input;
              (3) 180 ng/J (1.4 lb/MWh) gross energy output; or
              (4) 65 ng/J (0.15 lb/MMBtu) heat input.

              (b) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts liquid or gaseous fuels (except for liquid or gaseous fuels derived from solid fuels and as provided under paragraphs (e) or (h) of this section) and for which construction, reconstruction, or modification commenced before or on February 28, 2005, any gases that contain SO2 in excess of:
              (1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); or
              (2) 100 percent of the potential combustion concentration (zero percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu) heat input.

              (c) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid solvent refined coal (SRC-I) any gases that contain SO2 in excess of 520 ng/J (1.20 lb/MMBtu) heat input and 15 percent of the potential combustion concentration (85 percent reduction) except as provided under paragraph (f) of this section; compliance with the emission limitation is determined on a 30-day rolling average basis and compliance with the percent reduction requirement is determined on a 24-hour basis.
              (d) Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/MMBtu) heat input from any affected facility which:
              (1) Combusts 100 percent anthracite;
              (2) Is classified as a resource recovery unit; or
              (3) Is located in a noncontinental area and combusts solid fuel or solid-derived fuel.
              (e) Sulfur dioxide emissions are limited to 340 ng/J (0.80 lb/MMBtu) heat input from any affected facility which is located in a noncontinental area and combusts liquid or gaseous fuels (excluding solid-derived fuels).
              (f) The SO2 standards under this section do not apply to an owner or operator of an affected facility that is operated under an SO2 commercial demonstration permit issued by the Administrator in accordance with the provisions of § 60.47Da.
              (g) Compliance with the emission limitation and percent reduction requirements under this section are both determined on a 30-day rolling average basis except as provided under paragraph (c) of this section.
              (h) When different fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:
              (1) If emissions of SO2 to the atmosphere are greater than 260 ng/J (0.60 lb/MMBtu) heat input

                ER13JN07.008

              (2) If emissions of SO2 to the atmosphere are equal to or less than 260 ng/J (0.60 lb/MMBtu) heat input:

                ER13JN07.009

                Where:

                Es = Prorated SO2 emission limit (ng/J heat input);
                %Ps = Percentage of potential SO2 emission allowed;
                x = Percentage of total heat input derived from the combustion of liquid or gaseous fuels (excluding solid-derived fuels); and
                y = Percentage of total heat input derived from the combustion of solid fuel (including solid-derived fuels).

              (i) Except as provided in paragraphs (j) and (k) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO2 in excess of the applicable emissions limit specified in paragraphs (i)(1) through (3) of this section.

              (1) For an affected facility which commenced construction, any gases that contain SO2 in excess of either:
              (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
              (ii) 5 percent of the potential combustion concentration (95 percent reduction).

              (2) For an affected facility which commenced reconstruction, any gases that contain SO2 in excess of either:
              (i) 180 ng/J (1.4 lb/MWh) gross energy output;
              (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
              (iii) 5 percent of the potential combustion concentration (95 percent reduction).

              (3) For an affected facility which commenced modification, any gases that contain SO2 in excess of either:
              (i) 180 ng/J (1.4 lb/MWh) gross energy output;
              (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
              (iii) 10 percent of the potential combustion concentration (90 percent reduction).

              (j) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after February 28, 2005, and that burns 75 percent or more (by heat input) coal refuse on a 12-month rolling average basis, shall caused to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of the applicable emission limitation specified in paragraphs (j)(1) through (3) of this section.

              (1) For an affected facility for which construction commenced after February 28, 2005, any gases that contain SO2 in excess of either:
              (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or
              (ii) 6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling average basis.

              (2) For an affected facility for which reconstruction commenced after February 28, 2005, any gases that contain SO2 in excess of either:
              (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;
              (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or
              (iii) 6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling average basis.

              (3) For an affected facility for which modification commenced after February 28, 2005, any gases that contain SO2 in excess of either:

              (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis;
              (ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or
              (iii) 10 percent of the potential combustion concentration (90 percent reduction) on a 30-day rolling average basis.

              (k) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area for which construction, reconstruction, or modification commenced after February 28, 2005, but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of the applicable emissions limit specified in paragraphs (k)(1) and (2) of this section.

              (1) For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input.

              (2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO2 in excess of 230 ng/J (0.54 lb/MMBtu) heat input.

              (l) Except as provided in paragraphs (j) and (m) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility for which construction, reconstruction, or modification commenced after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO2 in excess of the applicable emissions limit specified in paragraphs (l)(1) and (2) of this section.

              (1) For an affected facility which commenced construction or reconstruction, any gases that contain SO2 in excess of either:
              (i) 130 ng/J (1.0 lb/MWh) gross energy output; or
              (ii) 140 ng/J (1.2 lb/MWh) net energy output; or
              (iii) 3 percent of the potential combustion concentration (97 percent reduction).

              (2) For an affected facility which commenced modification, any gases that contain SO2 in excess of either:
              (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
              (ii) 10 percent of the potential combustion concentration (90 percent reduction).

              (m) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area for which construction, reconstruction, or modification commenced after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of the applicable emissions limit specified in paragraphs (m)(1) and (2) of this section.

              (1) For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input.

              (2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO2 in excess of 230 ng/J (0.54 lb/MMBtu) heat input.
              [72 FR 32722, June 13, 2007, as amended at 77 FR 9450, Feb. 16, 2012]

              § 60.44Da
              Standards for nitrogen oxides (NO2).

              (a) Except as provided in paragraph (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which construction, reconstruction, or modification commenced before July 10, 1997 any gases that contain NOX (expressed as NO2) in excess of the applicable emissions limit in paragraphs (a)(1) and (2) of this section.

              (1) The owner or operator shall not cause to be discharged into the atmosphere any gases that contain NOX in excess of the emissions limit listed in the following table as applicable to the fuel type combusted and as determined on a 30-boiler operating day rolling average basis.

                  Fuel type
                  Emission limit for heat input
                  ng/J
                  lb/MMBtu

                  Gaseous fuels:

                  Coal-derived fuels
                  210
                  0.50

                  All other fuels
                  86
                  0.20

                  Liquid fuels:

                  Coal-derived fuels
                  210
                  0.50

                  Shale oil
                  210
                  0.50

                  All other fuels
                  130
                  0.30

                  Solid fuels:

                  Coal-derived fuels
                  210
                  0.50

                  Any fuel containing more than 25%, by weight, coal refuse
                  (1)
                  (1)

                  Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace 2

                  340
                  0.80

                  Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit 2

                  260
                  0.60

                  Subbituminous coal
                  210
                  0.50

                  Bituminous coal
                  260
                  0.60

                  Anthracite coal
                  260
                  0.60

                  All other fuels
                  260
                  0.60

                  1 Exempt from NOX standards and NOX monitoring requirements.

                  2 Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel.

              (2) When two or more fuels are combusted simultaneously in an affected facility, the applicable emissions limit (En) is determined by proration using the following formula:

                ER16FE12.019

                Where:

                En = Applicable NOX emissions limit when multiple fuels are combusted simultaneously (ng/J heat input);
                w = Percentage of total heat input derived from the combustion of fuels subject to the 86 ng/J heat input standard;
                x = Percentage of total heat input derived from the combustion of fuels subject to the 130 ng/J heat input standard;
                y = Percentage of total heat input derived from the combustion of fuels subject to the 210 ng/J heat input standard;
                z = Percentage of total heat input derived from the combustion of fuels subject to the 260 ng/J heat input standard; and
                v = Percentage of total heat input delivered from the combustion of fuels subject to the 340 ng/J heat input standard.

              (b)-(c) [Reserved]

              (d) Except as provided in paragraph (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after July 9, 1997, but before March 1, 2005, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NOX (expressed as NO2) in excess of the applicable emissions limit specified in paragraphs (d)(1) and (2) of this section as determined on a 30-boiler operating day rolling average basis.

              (1) For an affected facility which commenced construction, any gases that contain NOX in excess of 200 ng/J (1.6 lb/MWh) gross energy output.

              (2) For an affected facility which commenced reconstruction, any gases that contain NOX in excess of 65 ng/J (0.15 lb/MMBtu) heat input.

              (e) Except as provided in paragraphs (f) and (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NOX (expressed as NO2) in excess of the applicable emissions limit specified in paragraphs (e)(1) through (3) of this section as determined on a 30-boiler operating day rolling average basis.

              (1) For an affected facility which commenced construction, any gases that contain NOX in excess of 130 ng/J (1.0 lb/MWh) gross energy output.

              (2) For an affected facility which commenced reconstruction, any gases that contain NOX in excess of either:
              (i) 130 ng/J (1.0 lb/MWh) gross energy output; or
              (ii) 47 ng/J (0.11 lb/MMBtu) heat input.

              (3) For an affected facility which commenced modification, any gases that contain NOX in excess of either:
              (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
              (ii) 65 ng/J (0.15 lb/MMBtu) heat input.
              (f) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an IGCC electric utility steam generating unit subject to the provisions of this subpart and for which construction, reconstruction, or modification commenced after February 28, 2005 but before May 4, 2011, shall meet the requirements specified in paragraphs (f)(1) through (3) of this section.

              (1) Except as provided for in paragraphs (f)(2) and (3) of this section, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NOX (expressed as NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output.

              (2) When burning liquid fuel exclusively or in combination with solid-derived fuel such that the liquid fuel contributes 50 percent or more of the total heat input to the combined cycle combustion turbine, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NOX (expressed as NO2) in excess of 190 ng/J (1.5 lb/MWh) gross energy output.

              (3) In cases when during a 30-boiler operating day rolling average compliance period liquid fuel is burned in such a manner to meet the conditions in paragraph (f)(2) of this section for only a portion of the clock hours in the 30-day compliance period, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NOX (expressed as NO2) in excess of the computed weighted-average emissions limit based on the proportion of gross energy output (in MWh) generated during the compliance period for each of emissions limits in paragraphs (f)(1) and (2) of this section.

              (g) Except as provided in paragraphs (h) of this section and § 60.45Da, on and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NOX (expressed as NO2) in excess of the applicable emissions limit specified in paragraphs (g)(1) through (3) of this section.

              (1) For an affected facility which commenced construction or reconstruction, any gases that contain NOX in excess of either:
              (i) 88 ng/J (0.70 lb/MWh) gross energy output; or
              (ii) 95 ng/J (0.76 lb/MWh) net energy output.

              (2) For an affected facility which commenced construction or reconstruction and that burns 75 percent or more coal refuse (by heat input) on a 12-month rolling average basis, any gases that contain NOX in excess of either:
              (i) 110 ng/J (0.85 lb/MWh) gross energy output; or
              (ii) 120 ng/J (0.92 lb/MWh) net energy output.

              (3) For an affected facility which commenced modification, any gases that contain NOX in excess of 140 ng/J (1.1 lb/MWh) gross energy output.
              (h) The NOX emissions limits under this section do not apply to an owner or operator of an affected facility which is operating under a commercial demonstration permit issued by the Administrator in accordance with the provisions of § 60.47Da.
              [77 FR 9451, Feb. 16, 2012]

              § 60.45Da

              Alternative standards for combined nitrogen oxides (NOX) and carbon monoxide (CO).

              (a) The owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011 as alternate to meeting the applicable NOX emissions limits specified in § 60.44Da may elect to meet the applicable standards for combined NOX and CO specified in paragraph (b) of this section.

              (b) On and after the date on which the initial performance test is completed or required to be completed under § 60.8 no owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NOX (expressed as NO2) plus CO in excess of the applicable emissions limit specified in paragraphs (b)(1) through (3) of this section as determined on a 30-boiler operating day rolling average basis.

              (1) For an affected facility which commenced construction or reconstruction, any gases that contain NOX plus CO in excess of either:
              (i) 140 ng/J (1.1 lb/MWh) gross energy output; or
              (ii) 150 ng/J (1.2 lb/MWh) net energy output.

              (2) For an affected facility which commenced construction or reconstruction and that burns 75 percent or more coal refuse (by heat input) on a 12-month rolling average basis, any gases that contain NOX plus CO in excess of either:
              (i) 160 ng/J (1.3 lb/MWh) gross energy output; or
              (ii) 170 ng/J (1.4 lb/MWh) net energy output.

              (3) For an affected facility which commenced modification, any gases that contain NOX plus CO in excess of 190 ng/J (1.5 lb/MWh) gross energy output.
              [77 FR 9453, Feb. 16, 2012]

              § 60.46Da
              [Reserved]

              § 60.47Da
              Commercial demonstration permit.
              (a) An owner or operator of an affected facility proposing to demonstrate an emerging technology may apply to the Administrator for a commercial demonstration permit. The Administrator will issue a commercial demonstration permit in accordance with paragraph (e) of this section. Commercial demonstration permits may be issued only by the Administrator, and this authority will not be delegated.

              (b) An owner or operator of an affected facility that combusts solid solvent refined coal (SRC-I) and who is issued a commercial demonstration permit by the Administrator is not subject to the SO2 emission reduction requirements under § 60.43Da(c) but must, as a minimum, reduce SO2 emissions to 20 percent of the potential combustion concentration (80 percent reduction) for each 24-hour period of steam generator operation and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis.

              (c) An owner or operator of an affected facility that uses fluidized bed combustion (atmospheric or pressurized) and who is issued a commercial demonstration permit by the Administrator is not subject to the SO2 emission reduction requirements under § 60.43Da(a) but must, as a minimum, reduce SO2 emissions to 15 percent of the potential combustion concentration (85 percent reduction) on a 30-day rolling average basis and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis.

              (d) The owner or operator of an affected facility that combusts coal-derived liquid fuel and who is issued a commercial demonstration permit by the Administrator is not subject to the applicable NOX emission limitation and percent reduction under § 60.44Da(a) but must, as a minimum, reduce emissions to less than 300 ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis.
              (e) Commercial demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category, and the total equivalent MW electrical generation capacity for all commercial demonstration plants may not exceed 15,000 MW.

                  Technology
                  Pollutant
                  Equivalent electrical capacity(MW electrical output)

                  Solid solvent refined coal (SCR I)
                  SO2

                  6,000-10,000

                  Fluidized bed combustion (atmospheric)
                  SO2

                  400-3,000

                  Fluidized bed combustion (pressurized)
                  SO2

                  400-1,200

                  Coal liquification
                  NOX

                  750-10,000

                  Total allowable for all technologies

                  15,000

              (f) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions controls system who is issued a commercial demonstration permit by the Administrator is not subject to the total PM emission reduction requirements under § 60.42Da but must, as a minimum, reduce PM emissions to less than 6.4 ng/J (0.015 lb/MMBtu) heat input.

              (g) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions controls system who is issued a commercial demonstration permit by the Administrator is not subject to the SO2 standards or emission reduction requirements under § 60.43Da but must, as a minimum, reduce SO2 emissions to 5 percent of the potential combustion concentration (95 percent reduction) or to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-boiler operating day rolling average basis.

              (h) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions control system or advanced combustion controls who is issued a commercial demonstration permit by the Administrator is not subject to the NOX standards or emission reduction requirements under § 60.44Da but must, as a minimum, reduce NOX emissions to less than 130 ng/J (1.0 lb/MWh) or the combined NOX plus CO emissions to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-boiler operating day rolling average basis.
              (i) Commercial demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category listed in the following table.

                  Technology
                  Pollutant
                  Equivalent electrical capacity(MW electrical output)

                  Multi-pollutant Emission Control
                  SO2

                  1,000

                  Multi-pollutant Emission Control
                  NOX

                  1,000

                  Multi-pollutant Emission Control
                  PM
                  1,000

                  Pressurized Fluidized Bed Combustion
                  SO2

                  1,000

                  Pressurized Fluidized Bed Combustion
                  NOX

                  1,000

                  Pressurized Fluidized Bed Combustion
                  PM
                  1,000

                  Advanced Combustion Controls
                  NOX

                  1,000

              [72 FR 32722, June 13, 2007, as amended at 77 FR 9450, Feb. 16, 2012]

              § 60.48Da
              Compliance provisions.

              (a) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, the applicable PM emissions limit and opacity standard under § 60.42Da, SO2 emissions limit under § 60.43Da, and NOX emissions limit under § 60.44Da apply at all times except during periods of startup, shutdown, or malfunction. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, the applicable SO2 emissions limit under § 60.43Da, NOX emissions limit under § 60.44Da, and NOX plus CO emissions limit under § 60.45Da apply at all times. The applicable PM emissions limit and opacity standard under § 60.42Da apply at all times except during periods of startup and shutdown.

              (b) After the initial performance test required under § 60.8, compliance with the applicable SO2 emissions limit and percentage reduction requirements under § 60.43Da, NOX emissions limit under § 60.44Da, and NOX plus CO emissions limit under § 60.45Da is based on the average emission rate for 30 successive boiler operating days. A separate performance test is completed at the end of each boiler operating day after the initial performance test, and a new 30-boiler operating day rolling average emission rate for both SO2, NOX or NOX plus CO as applicable, and a new percent reduction for SO2 are calculated to demonstrate compliance with the standards.

              (c) For the initial performance test required under § 60.8, compliance with the applicable SO2 emissions limits and percentage reduction requirements under § 60.43Da, the NOX emissions limits under § 60.44Da, and the NOX plus CO emissions limits under § 60.45Da is based on the average emission rates for SO2, NOX, CO, and percent reduction for SO2 for the first 30 successive boiler operating days. The initial performance test is the only test in which at least 30 days prior notice is required unless otherwise specified by the Administrator. The initial performance test is to be scheduled so that the first boiler operating day of the 30 successive boiler operating days is completed within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility.

              (d) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, compliance with applicable 30-boiler operating day rolling average SO2 and NOX emissions limits is determined by calculating the arithmetic average of all hourly emission rates for SO2 and NOX for the 30 successive boiler operating days, except for data obtained during startup, shutdown, or malfunction. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable 30-boiler operating day rolling average SO2 and NOX emissions limits is determined by dividing the sum of the SO2 and NOX emissions for the 30 successive boiler operating days by the sum of the gross energy output or net energy output, as applicable, for the 30 successive boiler operating days.

              (e) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, compliance with applicable SO2 percentage reduction requirements is determined based on the average inlet and outlet SO2 emission rates for the 30 successive boiler operating days. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable SO2 percentage reduction requirements is determined based on the “as fired” total potential emissions and the total outlet SO2 emissions for the 30 successive boiler operating days.

              (f) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, compliance with the applicable daily average PM emissions limit is determined by calculating the arithmetic average of all hourly emission rates each boiler operating day, except for data obtained during startup, shutdown, or malfunction periods. Daily averages are only calculated for boiler operating days that have non-out-of-control data for at least 18 hours of unit operation during which the standard applies. Instead, all of the non-out-of-control hourly emission rates of the operating day(s) not meeting the minimum 18 hours non-out-of-control data daily average requirement are averaged with all of the non-out-of-control hourly emission rates of the next boiler operating day with 18 hours or more of non-out-of-control PM CEMS data to determine compliance. For affected facilities for which construction or reconstruction commenced after May 3, 2011 that elect to demonstrate compliance using PM CEMS, compliance with the applicable PM emissions limit in § 60.42Da is determined on a 30-boiler operating day rolling average basis by calculating the arithmetic average of all hourly PM emission rates for the 30 successive boiler operating days, except for data obtained during periods of startup and shutdown.

              (g) For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable 30-boiler operating day rolling average NOX plus CO emissions limit is determined by dividing the sum of the NOX plus CO emissions for the 30 successive boiler operating days by the sum of the gross energy output or net energy output, as applicable, for the 30 successive boiler operating days.
              (h) If an owner or operator has not obtained the minimum quantity of emission data as required under § 60.49Da of this subpart, compliance of the affected facility with the emission requirements under §§ 60.43Da and 60.44Da of this subpart for the day on which the 30-day period ends may be determined by the Administrator by following the applicable procedures in section 7 of Method 19 of appendix A of this part.
              (i) Compliance provisions for sources subject to § 60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), (f), or (g). The owner or operator shall calculate NOX emissions as 1.194 × 10−7 lb/scf-ppm times the average hourly NOX output concentration in ppm (measured according to the provisions of § 60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the provisions of § 60.49Da(l) or § 60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)) or the average hourly net energy output, as applicable. Alternatively, for oil-fired and gas-fired units, NOX emissions may be calculated by multiplying the hourly NOX emission rate in lb/MMBtu (measured by the CEMS required under § 60.49Da(c) and (d)), by the hourly heat input rate (measured according to the provisions of § 60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of § 60.49Da(k)) or the average hourly net energy output, as applicable.
              (j) Compliance provisions for duct burners subject to § 60.44Da(a)(1). To determine compliance with the emissions limits for NOX required by § 60.44Da(a) for duct burners used in combined cycle systems, either of the procedures described in paragraph (j)(1) or (2) of this section may be used:
              (1) The owner or operator of an affected duct burner shall conduct the performance test required under § 60.8 using the appropriate methods in appendix A of this part. Compliance with the emissions limits under § 60.44Da(a)(1) is determined on the average of three (nominal 1-hour) runs for the initial and subsequent performance tests. During the performance test, one sampling site shall be located in the exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outlet from the heat recovery steam generating unit. Measurements shall be taken at both sampling sites during the performance test; or

              (2) The owner or operator of an affected duct burner may elect to determine compliance by using the CEMS specified under § 60.49Da for measuring NOX and oxygen (O2) (or carbon dioxide (CO2)) and meet the requirements of § 60.49Da. Alternatively, data from a NOX emission rate (i.e., NOX-diluent) CEMS certified according to the provisions of § 75.20(c) of this chapter and appendix A to part 75 of this chapter, and meeting the quality assurance requirements of § 75.21 of this chapter and appendix B to part 75 of this chapter, may be used, with the following caveats. Data used to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam generating unit. The NOX emission rate at the outlet from the steam generating unit shall constitute the NOX emission rate from the duct burner of the combined cycle system.
              (k) Compliance provisions for duct burners subject to § 60.44Da(d)(1) or (e)(1). To determine compliance with the emission limitation for NOX required by § 60.44Da(d)(1) or (e)(1) for duct burners used in combined cycle systems, either of the procedures described in paragraphs (k)(1) and (2) of this section may be used:

              (1) The owner or operator of an affected duct burner used in combined cycle systems shall determine compliance with the applicable NOX emission limitation in § 60.44Da(d)(1) or (e)(1) as follows:
              (i) The emission rate (E) of NOX shall be computed using Equation 2 in this section:

                ER16FE12.000

                Where:

                E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) gross energy output;
                Csg = Average hourly concentration of NOX exiting the steam generating unit, ng/dscm (lb/dscf);
                Cte = Average hourly concentration of NOX in the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf);
                Qsg = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/h (dscf/h);
                Qte = Average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/h (dscf/h);
                Osg = Average hourly gross energy output from steam generating unit, J/h (MW); and
                h = Average hourly fraction of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner.

              (ii) Method 7E of appendix A of this part shall be used to determine the NOX concentrations (Csg and Cte). Method 2, 2F or 2G of appendix A of this part, as appropriate, shall be used to determine the volumetric flow rates (Qsg and Qte) of the exhaust gases. The volumetric flow rate measurements shall be taken at the same time as the concentration measurements.
              (iii) The owner or operator shall develop, demonstrate, and provide information satisfactory to the Administrator to determine the average hourly gross energy output from the steam generating unit, and the average hourly percentage of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner.
              (iv) Compliance with the applicable NOX emission limitation in § 60.44Da(d)(1) or (e)(1) is determined by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests.

              (2) The owner or operator of an affected duct burner used in a combined cycle system may elect to determine compliance with the applicable NOX emission limitation in § 60.44Da(d)(1) or (e)(1) on a 30-day rolling average basis as indicated in paragraphs (k)(2)(i) through (iv) of this section.
              (i) The emission rate (E) of NOX shall be computed using Equation 3 in this section:

                ER16FE12.001

                Where:

                E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) gross energy output;
                Csg = Average hourly concentration of NOX exiting the steam generating unit, ng/dscm (lb/dscf);
                Qsg = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/h (dscf/h); and
                Occ = Average hourly gross energy output from entire combined cycle unit, J/h (MW).

              (ii) The CEMS specified under § 60.49Da for measuring NOX and O2 (or CO2) shall be used to determine the average hourly NOX concentrations (Csg). The continuous flow monitoring system specified in § 60.49Da(l) or § 60.49Da(m) shall be used to determine the volumetric flow rate (Qsg) of the exhaust gas. If the option to use the flow monitoring system in § 60.49Da(m) is selected, the flow rate data used to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam generating unit.

              (iii) The continuous monitoring system specified under § 60.49Da(k) for measuring and determining gross energy output shall be used to determine the average hourly gross energy output from the entire combined cycle unit (Occ), which is the combined output from the combustion turbine and the steam generating unit.

              (iv) The owner or operator may, in lieu of installing, operating, and recording data from the continuous flow monitoring system specified in § 60.49Da(l), determine the mass rate (lb/h) of NOX emissions by installing, operating, and maintaining continuous fuel flowmeters following the appropriate measurements procedures specified in appendix D of part 75 of this chapter. If this compliance option is selected, the emission rate (E) of NOX shall be computed using Equation 4 in this section:

                ER16FE12.002

                Where:

                E = Emission rate of NOX from the duct burner, ng/J (lb/MWh) gross energy output;
                ERsg = Average hourly emission rate of NOX exiting the steam generating unit heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part, ng/J (lb/MMBtu);
                Hcc = Average hourly heat input rate of entire combined cycle unit, J/h (MMBtu/h); and
                Occ = Average hourly gross energy output from entire combined cycle unit, J/h (MW).

              (3) When an affected duct burner steam generating unit utilizes a common steam turbine with one or more affected duct burner steam generating units, the owner or operator shall either:
              (i) Determine compliance with the applicable NOX emissions limits by measuring the emissions combined with the emissions from the other unit(s) utilizing the common steam turbine; or
              (ii) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined gross energy output from the steam turbine for each of the affected duct burners. The Administrator may approve such demonstrated substitute methods for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions regulated under this part.
              (l) [Reserved]

              (m) Compliance provisions for sources subject to § 60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), (j)(3)(i), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator shall calculate SO2 emissions as 1.660 × 10−7 lb/scf-ppm times the average hourly SO2 output concentration in ppm (measured according to the provisions of § 60.49Da(b)), times the average hourly flow rate (measured according to the provisions of § 60.49Da(l) or § 60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)) or the average hourly net energy output, as applicable. Alternatively, for oil-fired and gas-fired units, SO2 emissions may be calculated by multiplying the hourly SO2 emission rate (in lb/MMBtu), measured by the CEMS required under § 60.49Da, by the hourly heat input rate (measured according to the provisions of § 60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of § 60.49Da(k)) or the average hourly net energy output, as applicable.
              (n) Compliance provisions for sources subject to § 60.42Da(c)(1) or (e)(1)(i). The owner or operator shall calculate PM emissions by multiplying the average hourly PM output concentration (measured according to the provisions of § 60.49Da(t)), by the average hourly flow rate (measured according to the provisions of § 60.49Da(l) or § 60.49Da(m)), and dividing by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)) or the average hourly net energy output, as applicable.
              (o) Compliance provisions for sources subject to § 60.42Da(c)(2), (d), or (e)(1)(ii). Except as provided for in paragraph (p) of this section, the owner or operator must demonstrate compliance with each applicable emissions limit according to the requirements in paragraphs (o)(1) through (o)(5) of this section.
              (1) You must conduct a performance test to demonstrate initial compliance with the applicable PM emissions limit in § 60.42Da by the applicable date specified in § 60.8(a). Thereafter, you must conduct each subsequent performance test within 12 calendar months following the date the previous performance test was required to be conducted. You must conduct each performance test according to the requirements in § 60.8 using the test methods and procedures in § 60.50Da. The owner or operator of an affected facility that has not operated for 60 consecutive calendar days prior to the date that the subsequent performance test would have been required had the unit been operating is not required to perform the subsequent performance test until 30 calendar days after the next boiler operating day. Requests for additional 30 day extensions shall be granted by the relevant air division or office director of the appropriate Regional Office of the U.S. EPA.
              (2) You must monitor the performance of each electrostatic precipitator or fabric filter (baghouse) operated to comply with the applicable PM emissions limit in § 60.42Da using a continuous opacity monitoring system (COMS) according to the requirements in paragraphs (o)(2)(i) through (vi) unless you elect to comply with one of the alternatives provided in paragraphs (o)(3) and (o)(4) of this section, as applicable to your control device.
              (i) Each COMS must meet Performance Specification 1 in 40 CFR part 60, appendix B.
              (ii) You must comply with the quality assurance requirements in paragraphs (o)(2)(ii)(A) through (E) of this section.
              (A) You must automatically (intrinsic to the opacity monitor) check the zero and upscale (span) calibration drifts at least once daily. For a particular COMS, the acceptable range of zero and upscale calibration materials is as defined in the applicable version of Performance Specification 1 in 40 CFR part 60, appendix B.
              (B) You must adjust the zero and span whenever the 24-hour zero drift or 24-hour span drift exceeds 4 percent opacity. The COMS must allow for the amount of excess zero and span drift measured at the 24-hour interval checks to be recorded and quantified. The optical surfaces exposed to the effluent gases must be cleaned prior to performing the zero and span drift adjustments, except for systems using automatic zero adjustments. For systems using automatic zero adjustments, the optical surfaces must be cleaned when the cumulative automatic zero compensation exceeds 4 percent opacity.
              (C) You must apply a method for producing a simulated zero opacity condition and an upscale (span) opacity condition using a certified neutral density filter or other related technique to produce a known obscuration of the light beam. All procedures applied must provide a system check of the analyzer internal optical surfaces and all electronic circuitry including the lamp and photodetector assembly.

              (D) Except during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments, the COMS must be in continuous operation and must complete a minimum of one cycle of sampling and analyzing for each successive 10 second period and one cycle of data recording for each successive 6-minute period.
              (E) You must reduce all data from the COMS to 6-minute averages. Six-minute opacity averages must be calculated from 36 or more data points equally spaced over each 6-minute period. Data recorded during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments must not be included in the data averages. An arithmetic or integrated average of all data may be used.
              (iii) During each performance test conducted according to paragraph (o)(1) of this section, you must establish an opacity baseline level. The value of the opacity baseline level is determined by averaging all of the 6-minute average opacity values (reported to the nearest 0.1 percent opacity) from the COMS measurements recorded during each of the test run intervals conducted for the performance test, and then adding 2.5 percent opacity to your calculated average opacity value for all of the test runs. If your opacity baseline level is less than 5.0 percent, then the opacity baseline level is set at 5.0 percent.
              (iv) You must evaluate the preceding 24-hour average opacity level measured by the COMS each boiler operating day excluding periods of affected facility startup, shutdown, or malfunction. If the measured 24-hour average opacity emission level is greater than the baseline opacity level determined in paragraph (o)(2)(iii) of this section, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high opacity incident and take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the measured 24-hour average opacity to a level below the baseline opacity level. In cases when a wet scrubber is used in combination with another PM control device that serves as the primary PM control device, the wet scrubber must be maintained and operated.
              (v) You must record the opacity measurements, calculations performed, and any corrective actions taken. The record of corrective action taken must include the date and time during which the measured 24-hour average opacity was greater than baseline opacity level, and the date, time, and description of the corrective action.
              (vi) If the measured 24-hour average opacity for your affected facility remains at a level greater than the opacity baseline level after 7 boiler operating days, then you must conduct a new PM performance test according to paragraph (o)(1) of this section and establish a new opacity baseline value according to paragraph (o)(2) of this section. This new performance test must be conducted within 60 days of the date that the measured 24-hour average opacity was first determined to exceed the baseline opacity level unless a waiver is granted by the permitting authority.
              (3) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of an electrostatic precipitator (ESP) operated to comply with the applicable PM emissions limit in § 60.42Da using an ESP predictive model developed in accordance with the requirements in paragraphs (o)(3)(i) through (v) of this section.
              (i) You must calibrate the ESP predictive model with each PM control device used to comply with the applicable PM emissions limit in § 60.42Da operating under normal conditions. In cases when a wet scrubber is used in combination with an ESP to comply with the PM emissions limit, the wet scrubber must be maintained and operated.

              (ii) You must develop a site-specific monitoring plan that includes a description of the ESP predictive model used, the model input parameters, and the procedures and criteria for establishing monitoring parameter baseline levels indicative of compliance with the PM emissions limit. You must submit the site-specific monitoring plan for approval by the permitting authority. For reference purposes in preparing the monitoring plan, see the OAQPS “Compliance Assurance Monitoring (CAM) Protocol for an Electrostatic Precipitator (ESP) Controlling Particulate Matter (PM) Emissions from a Coal-Fired Boiler.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality Planning and Standards; Sector Policies and Programs Division; Measurement Policy Group (D243-02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Continuous Emission Monitoring.
              (iii) You must run the ESP predictive model using the applicable input data each boiler operating day and evaluate the model output for the preceding boiler operating day excluding periods of affected facility startup, shutdown, or malfunction. If the values for one or more of the model parameters exceed the applicable baseline levels determined according to your approved site-specific monitoring plan, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of a model parameter deviation and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to return the model output to within the applicable baseline levels.
              (iv) You must record the ESP predictive model inputs and outputs and any corrective actions taken. The record of corrective action taken must include the date and time during which the model output values exceeded the applicable baseline levels, and the date, time, and description of the corrective action.
              (v) If after 7 consecutive days a model parameter continues to exceed the applicable baseline level, then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This new performance test must be conducted within 60 calendar days of the date that the model parameter was first determined to exceed its baseline level unless a waiver is granted by the permitting authority.
              (4) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of a fabric filter (baghouse) operated to comply with the applicable PM emissions limit in § 60.42Da by using a bag leak detection system according to the requirements in paragraphs (o)(4)(i) through (v) of this section.
              (i) Each bag leak detection system must meet the specifications and requirements in paragraphs (o)(4)(i)(A) through (H) of this section.
              (A) The bag leak detection system must be certified by the manufacturer to be capable of detecting PM emissions at concentrations of 1 milligram per actual cubic meter (0.00044 grains per actual cubic foot) or less.
              (B) The bag leak detection system sensor must provide output of relative PM loadings. The owner or operator must continuously record the output from the bag leak detection system using electronic or other means (e.g., using a strip chart recorder or a data logger.)
              (C) The bag leak detection system must be equipped with an alarm system that will react when the system detects an increase in relative particulate loading over the alarm set point established according to paragraph (o)(4)(i)(D) of this section, and the alarm must be located such that it can be noticed by the appropriate plant personnel.
              (D) In the initial adjustment of the bag leak detection system, you must establish, at a minimum, the baseline output by adjusting the sensitivity (range) and the averaging period of the device, the alarm set points, and the alarm delay time.
              (E) Following initial adjustment, you must not adjust the averaging period, alarm set point, or alarm delay time without approval from the permitting authority except as provided in paragraph (d)(1)(vi) of this section.
              (F) Once per quarter, you may adjust the sensitivity of the bag leak detection system to account for seasonal effects, including temperature and humidity, according to the procedures identified in the site-specific monitoring plan required by paragraph (o)(4)(ii) of this section.
              (G) You must install the bag leak detection sensor downstream of the fabric filter and upstream of any wet scrubber.
              (H) Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors.

              (ii) You must develop and submit to the permitting authority for approval a site-specific monitoring plan for each bag leak detection system. You must operate and maintain the bag leak detection system according to the site-specific monitoring plan at all times. Each monitoring plan must describe the items in paragraphs (o)(4)(ii)(A) through (F) of this section.
              (A) Installation of the bag leak detection system;
              (B) Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point will be established;
              (C) Operation of the bag leak detection system, including quality assurance procedures;
              (D) How the bag leak detection system will be maintained, including a routine maintenance schedule and spare parts inventory list;
              (E) How the bag leak detection system output will be recorded and stored; and
              (F) Corrective action procedures as specified in paragraph (o)(4)(iii) of this section. In approving the site-specific monitoring plan, the permitting authority may allow owners and operators more than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation of this condition as expeditiously as practicable.
              (iii) For each bag leak detection system, you must initiate procedures to determine the cause of every alarm within 1 hour of the alarm. Except as provided in paragraph (o)(4)(ii)(F) of this section, you must alleviate the cause of the alarm within 3 hours of the alarm by taking whatever corrective action(s) are necessary. Corrective actions may include, but are not limited to the following:
              (A) Inspecting the fabric filter for air leaks, torn or broken bags or filter media, or any other condition that may cause an increase in particulate emissions;
              (B) Sealing off defective bags or filter media;
              (C) Replacing defective bags or filter media or otherwise repairing the control device;
              (D) Sealing off a defective fabric filter compartment;
              (E) Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection system; or
              (F) Shutting down the process producing the particulate emissions.
              (iv) You must maintain records of the information specified in paragraphs (o)(4)(iv)(A) through (C) of this section for each bag leak detection system.
              (A) Records of the bag leak detection system output;
              (B) Records of bag leak detection system adjustments, including the date and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings; and
              (C) The date and time of all bag leak detection system alarms, the time that procedures to determine the cause of the alarm were initiated, if procedures were initiated within 1 hour of the alarm, the cause of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was alleviated, and if the alarm was alleviated within 3 hours of the alarm.
              (v) If after any period composed of 30 boiler operating days during which the alarm rate exceeds 5 percent of the process operating time (excluding control device or process startup, shutdown, and malfunction), then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This new performance test must be conducted within 60 calendar days of the date that the alarm rate was first determined to exceed 5 percent limit unless a waiver is granted by the permitting authority.

              (5) An owner or operator of a modified affected facility electing to meet the emission limitations in § 60.42Da(d) shall determine the percent reduction in PM by using the emission rate for PM determined by the performance test conducted according to the requirements in paragraph (o)(1) of this section and the ash content on a mass basis of the fuel burned during each performance test run as determined by analysis of the fuel as fired.

              (p) As an alternative to meeting the compliance provisions specified in paragraph (o) of this section, an owner or operator may elect to install, evaluate, maintain, and operate a CEMS measuring PM emissions discharged from the affected facility to the atmosphere and record the output of the system as specified in paragraphs (p)(1) through (p)(8) of this section.
              (1) The owner or operator shall submit a written notification to the Administrator of intent to demonstrate compliance with this subpart by using a CEMS measuring PM. This notification shall be sent at least 30 calendar days before the initial startup of the monitor for compliance determination purposes. The owner or operator may discontinue operation of the monitor and instead return to demonstration of compliance with this subpart according to the requirements in paragraph (o) of this section by submitting written notification to the Administrator of such intent at least 30 calendar days before shutdown of the monitor for compliance determination purposes.
              (2) Each CEMS shall be installed, evaluated, operated, and maintained according to the requirements in § 60.49Da(v).
              (3) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of the date of notification to the Administrator required under paragraph (p)(1) of this section, whichever is later.
              (4) Compliance with the applicable emissions limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emissions concentrations using the continuous monitoring system outlet data. The 24-hour block arithmetic average emission concentration shall be calculated using EPA Reference Method 19 of appendix A of this part, section 4.1.
              (5) At a minimum, non-out-of-control CEMS hourly averages shall be obtained for 75 percent of all operating hours on a 30-boiler operating day rolling average basis. Beginning on January 1, 2012, non-out-of-control CEMS hourly averages shall be obtained for 90 percent of all operating hours on a 30-boiler operating day rolling average basis.
              (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
              (ii) [Reserved]
              (6) The 1-hour arithmetic averages required shall be expressed in ng/J, MMBtu/hr, or lb/MWh and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
              (7) All non-out-of-control CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(5) of this section are not met.
              (8) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, non-out-of-control emissions data for a minimum of 90 percent (only 75 percent is required prior to January 1, 2012) of all operating hours per 30-boiler operating day rolling average.
              (q) Compliance provisions for sources subject to § 60.42Da(b). An owner or operator of an affected facility subject to the opacity standard in § 60.42Da(b) shall monitor the opacity of emissions discharged from the affected facility to the atmosphere according to the requirements in § 60.49Da(a), as applicable to the affected facility.

              (r) Compliance provisions for sources subject to § 60.45Da. To determine compliance with the NOX plus CO emissions limit, the owner or operator shall use the procedures specified in paragraphs (r)(1) through (3) of this section.
              (1) Calculate NOX emissions as 1.194 × 10−7 lb/scf-ppm times the average hourly NOX output concentration in ppm (measured according to the provisions of § 60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the provisions of § 60.49Da(l) or § 60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)) or the average hourly net energy output, as applicable.
              (2) Calculate CO emissions by multiplying the average hourly CO output concentration (measured according to the provisions of § 60.49Da(u), by the average hourly flow rate (measured according to the provisions of § 60.49Da(l) or § 60.49Da(m)), and dividing by the average hourly gross energy output (measured according to the provisions of § 60.49Da(k)) or the average hourly net energy output, as applicable.
              (3) Calculate NOX plus CO emissions by summing the NOX emissions results from paragraph (r)(1) of this section plus the CO emissions results from paragraph (r)(2) of this section.
              (s) Affirmative defense for exceedance of emissions limit during malfunction. In response to an action to enforce the standards set forth in paragraph §§ 60.42Da, 60.43Da, 60.44Da, and 60.45Da, you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense as specified in paragraphs (s)(1) and (2) of this section. The affirmative defense shall not be available for claims for injunctive relief.
              (1) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragraph (s)(2) of this section, and must prove by a preponderance of evidence that:
              (i) The excess emissions:
              (A) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner; and
              (B) Could not have been prevented through careful planning, proper design, or better operation and maintenance practices; and
              (C) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and
              (D) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and
              (ii) Repairs were made as expeditiously as possible when the applicable emissions limits were being exceeded. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and
              (iii) The frequency, amount, and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; and
              (iv) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and
              (v) All possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment, and human health; and
              (vi) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and
              (vii) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and
              (viii) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions; and
              (ix) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction.
              (2) Notification. The owner or operator of the affected source experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction or, if it is not possible to determine within two business days whether the malfunction caused or contributed to an exceedance, no later than two business days after the owner or operator knew or should have known that the malfunction caused or contributed to an exceedance, but, in no event later than two business days after the end of the averaging period, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction. The owner or operator seeking to assert an affirmative defense shall also submit a written report to the Administrator within 45 days of the initial occurrence of the exceedance of the standard in § 63.9991 to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (s)(1) of this section. The owner or operator may seek an extension of this deadline for up to 30 additional days by submitting a written request to the Administrator before the expiration of the 45 day period. Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requirement to submit such report within 45 days of the initial occurrence of the exceedance.
              [72 FR 32722, June 13, 2007, as amended at 74 FR 5079, Jan. 28, 2009; 76 FR 3522, Jan. 20, 2011; 77 FR 9454, Feb. 16, 2012; 78 FR 24083, Apr. 24, 2013; 81 FR 20180, Apr. 6, 2016]

              § 60.49Da
              Emission monitoring.
              (a) An owner or operator of an affected facility subject to the opacity standard in § 60.42Da must monitor the opacity of emissions discharged from the affected facility to the atmosphere according to the applicable requirements in paragraphs (a)(1) through (4) of this section.

              (1) Except as provided for in paragraphs (a)(2) and (4) of this section, the owner or operator of an affected facility subject to an opacity standard, shall install, calibrate, maintain, and operate a COMS, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere. If opacity interference due to water droplets exists in the stack (for example, from the use of an FGD system), the opacity is monitored upstream of the interference (at the inlet to the FGD system). If opacity interference is experienced at all locations (both at the inlet and outlet of the SO2 control system), alternate parameters indicative of the PM control system's performance and/or good combustion are monitored (subject to the approval of the Administrator).
              (2) As an alternative to the monitoring requirements in paragraph (a)(1) of this section, an owner or operator of an affected facility that meets the conditions in either paragraph (a)(2)(i), (ii), (iii), or (iv) of this section may elect to monitor opacity as specified in paragraph (a)(3) of this section.
              (i) The affected facility uses a fabric filter (baghouse) to meet the standards in § 60.42Da and a bag leak detection system is installed and operated according to the requirements in paragraphs § 60.48Da(o)(4)(i) through (v);

              (ii) The affected facility burns only gaseous or liquid fuels (excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion technology to reduce emissions of SO2 or PM;
              (iii) The affected facility meets all of the conditions specified in paragraphs (a)(2)(iii)(A) through (C) of this section.

              (A) No post-combustion technology (except a wet scrubber) is used for reducing PM, SO2, or CO emissions;
              (B) Only natural gas, gaseous fuels, or fuel oils that contain less than or equal to 0.30 weight percent sulfur are burned; and
              (C) Emissions of CO discharged to the atmosphere are maintained at levels less than or equal to 1.4 lb/MWh on a boiler operating day average basis as demonstrated by the use of a CEMS measuring CO emissions according to the procedures specified in paragraph (u) of this section; or
              (iv) The affected facility uses an ESP and uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section § 60.48Da of this part.

              (3) The owner or operator of an affected facility that meets the conditions in paragraph (a)(2) of this section may, as an alternative to using a COMS, elect to monitor visible emissions using the applicable procedures specified in paragraphs (a)(3)(i) through (iv) of this section. The opacity performance test requirement in paragraph (a)(3)(i) must be conducted by April 29, 2011, within 45 days after stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later.
              (i) The owner or operator shall conduct a performance test using Method 9 of appendix A-4 of this part and the procedures in § 60.11. If during the initial 60 minutes of the observation all the 6-minute averages are less than 10 percent and all the individual 15-second observations are less than or equal to 20 percent, then the observation period may be reduced from 3 hours to 60 minutes.
              (ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A-4 of this part performance tests using the procedures in paragraph (a)(3)(i) of this section according to the applicable schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(C) of this section, as determined by the most recent Method 9 of appendix A-4 of this part performance test results.
              (A) If the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
              (B) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or
              (C) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted.
              (iii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A-4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A-4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A-7 of this part according to the procedures specified in paragraphs (a)(3)(iii)(A) and (B) of this section.

              (A) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A-7 of this part and demonstrate that the sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation period (i.e., 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period (i.e., 90 seconds per 30 minute period), the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute observation (i.e., 90 seconds) or conduct a new Method 9 of appendix A-4 of this part performance test using the procedures in paragraph (a)(3)(i) of this section within 45 calendar days according to the requirements in § 60.50Da(b)(3).
              (B) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed.

              (iv) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A-4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A-4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations must be similar, but not necessarily identical, to the requirements in paragraph (a)(3)(iii) of this section. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243-02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods.
              (4) An owner or operator of an affected facility that is subject to an opacity standard under § 60.42Da is not required to operate a COMS provided that affected facility meets the conditions in either paragraph (a)(4)(i) or (ii) of this section.

              (i) The affected facility combusts only gaseous and/or liquid fuels (excluding residue oil) where the potential SO2 emissions rate of each fuel is no greater than 26 ng/J (0.060 lb/MMBtu), and the unit operates according to a written site-specific monitoring plan approved by the permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard. For testing performed as part of this site-specific monitoring plan, the permitting authority may require as an alternative to the notification and reporting requirements specified in §§ 60.8 and 60.11 that the owner or operator submit any deviations with the excess emissions report required under § 60.51Da(d).
              (ii) The owner or operator of the affected facility installs, calibrates, operates, and maintains a particulate matter continuous parametric monitoring system (PM CPMS) according to the requirements specified in subpart UUUUU of part 63.

              (b) The owner or operator of an affected facility must install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring SO2 emissions, except where only gaseous and/or liquid fuels (excluding residual oil) where the potential SO2 emissions rate of each fuel is 26 ng/J (0.060 lb/MMBtu) or less are combusted, as follows:

              (1) Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO2 control device.

              (2) For a facility that qualifies under the numerical limit provisions of § 60.43Da, SO2 emissions are only monitored as discharged to the atmosphere.

              (3) An “as fired” fuel monitoring system (upstream of coal pulverizers) meeting the requirements of Method 19 of appendix A of this part may be used to determine potential SO2 emissions in place of a continuous SO2 emission monitor at the inlet to the SO2 control device as required under paragraph (b)(1) of this section.

              (4) If the owner or operator has installed and certified a SO2 CEMS according to the requirements of § 75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of § 75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used to meet the requirements of this section, provided that:
              (i) A CO2 or O2 continuous monitoring system is installed, calibrated, maintained and operated at the same location, according to paragraph (d) of this section; and
              (ii) For sources subject to an SO2 emission limit in lb/MMBtu under § 60.43Da:
              (A) When relative accuracy testing is conducted, SO2 concentration data and CO2 (or O2) data are collected simultaneously; and
              (B) In addition to meeting the applicable SO2 and CO2 (or O2) relative accuracy specifications in Figure 2 of appendix B to part 75 of this chapter, the relative accuracy (RA) standard in section 13.2 of Performance Specification 2 in appendix B to this part is met when the RA is calculated on a lb/MMBtu basis; and

              (iii) The reporting requirements of § 60.51Da are met. The SO2 and, if required, CO2 (or O2) data reported to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the SO2 data have been bias adjusted according to the procedures of part 75 of this chapter.

              (c)(1) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring NOX emissions discharged to the atmosphere; or
              (2) If the owner or operator has installed a NOX emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this section, except that the owner or operator shall also meet the requirements of § 60.51Da. Data reported to meet the requirements of § 60.51Da shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.

              (d) The owner or operator of an affected facility not complying with an output based limit shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring the O2 or carbon dioxide (CO2) content of the flue gases at each location where SO2 or NOX emissions are monitored. For affected facilities subject to a lb/MMBtu SO2 emission limit under § 60.43Da, if the owner or operator has installed and certified a CO2 or O2 monitoring system according to § 75.20(c) of this chapter and appendix A to part 75 of this chapter and the monitoring system continues to meet the applicable quality-assurance provisions of § 75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used together with the part 75 SO2 concentration monitoring system described in paragraph (b) of this section, to determine the SO2 emission rate in lb/MMBtu. SO2 data used to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
              (e) The CEMS under paragraphs (b), (c), and (d) of this section are operated and data recorded during all periods of operation of the affected facility including periods of startup, shutdown, and malfunction, except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments.
              (f)(1) For units that began construction, reconstruction, or modification on or before February 28, 2005, the owner or operator shall obtain emission data for at least 18 hours in at least 22 out of 30 successive boiler operating days. If this minimum data requirement cannot be met with CEMS, the owner or operator shall supplement emission data with other monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph (h) of this section.
              (2) For units that began construction, reconstruction, or modification after February 28, 2005, the owner or operator shall obtain emission data for at least 90 percent of all operating hours for each 30 successive boiler operating days. If this minimum data requirement cannot be met with a CEMS, the owner or operator shall supplement emission data with other monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph (h) of this section.
              (g) The 1-hour averages required under paragraph § 60.13(h) are expressed in ng/J (lb/MMBtu) heat input and used to calculate the average emission rates under § 60.48Da. The 1-hour averages are calculated using the data points required under § 60.13(h)(2).
              (h) When it becomes necessary to supplement CEMS data to meet the minimum data requirements in paragraph (f) of this section, the owner or operator shall use the reference methods and procedures as specified in this paragraph. Acceptable alternative methods and procedures are given in paragraph (j) of this section.

              (1) Method 6 of appendix A of this part shall be used to determine the SO2 concentration at the same location as the SO2 monitor. Samples shall be taken at 60-minute intervals. The sampling time and sample volume for each sample shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour average.

              (2) Method 7 of appendix A of this part shall be used to determine the NOX concentration at the same location as the NOX monitor. Samples shall be taken at 30-minute intervals. The arithmetic average of two consecutive samples represents a 1-hour average.

              (3) The emission rate correction factor, integrated bag sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O2 or CO2 concentration at the same location as the O2 or CO2 monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample represents a 1-hour average.
              (4) The procedures in Method 19 of appendix A of this part shall be used to compute each 1-hour average concentration in ng/J (lb/MMBtu) heat input.
              (i) The owner or operator shall use methods and procedures in this paragraph to conduct monitoring system performance evaluations under § 60.13(c) and calibration checks under § 60.13(d). Acceptable alternative methods and procedures are given in paragraph (j) of this section.

              (1) Methods 3B, 6, and 7 of appendix A of this part shall be used to determine O2, SO2, and NOX concentrations, respectively.
              (2) SO2 or NOX (NO), as applicable, shall be used for preparing the calibration gas mixtures (in N2, as applicable) under Performance Specification 2 of appendix B of this part.

              (3) For affected facilities burning only fossil fuel, the span value for a COMS is between 60 and 80 percent. Span values for a CEMS measuring NOX shall be determined using one of the following procedures:

              (i) Except as provided under paragraph (i)(3)(ii) of this section, NOX span values shall be determined as follows:

                  Fossil fuel
                  Span values for NOX
                    (ppm)

                  Gas
                  500.

                  Liquid
                  500.

                  Solid
                  1,000.

                  Combination
                  500 (x + y) + 1,000z.

                Where:

                x = Fraction of total heat input derived from gaseous fossil fuel,
                y = Fraction of total heat input derived from liquid fossil fuel, and
                z = Fraction of total heat input derived from solid fossil fuel.

              (ii) As an alternative to meeting the requirements of paragraph (i)(3)(i) of this section, the owner or operator of an affected facility may elect to use the NOX span values determined according to section 2.1.2 in appendix A to part 75 of this chapter.
              (4) All span values computed under paragraph (i)(3)(i) of this section for burning combinations of fossil fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (i)(3)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter.

              (5) For affected facilities burning fossil fuel, alone or in combination with non-fossil fuel and determining span values under paragraph (i)(3)(i) of this section, the span value of the SO2 CEMS at the inlet to the SO2 control device is 125 percent of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the SO2 control device is 50 percent of maximum estimated hourly potential emissions of the fuel fired. For affected facilities determining span values under paragraph (i)(3)(ii) of this section, SO2 span values shall be determined according to section 2.1.1 in appendix A to part 75 of this chapter.
              (j) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section:
              (1) For Method 6 of appendix A of this part, Method 6A or 6B (whenever Methods 6 and 3 or 3B of appendix A of this part data are used) or 6C of appendix A of this part may be used. Each Method 6B of appendix A of this part sample obtained over 24 hours represents 24 1-hour averages. If Method 6A or 6B of appendix A of this part is used under paragraph (i) of this section, the conditions under § 60.48Da(d)(1) apply; these conditions do not apply under paragraph (h) of this section.

              (2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be 1 hour.

              (3) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used if the sampling time is 1 hour.
              (4) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used.
              (k) The procedures specified in paragraphs (k)(1) through (3) of this section shall be used to determine gross energy output for sources demonstrating compliance with an output-based standard.
              (1) The owner or operator of an affected facility with electricity generation shall install, calibrate, maintain, and operate a wattmeter; measure gross electrical output in MWh on a continuous basis; and record the output of the monitor.
              (2) The owner or operator of an affected facility with process steam generation shall install, calibrate, maintain, and operate meters for steam flow, temperature, and pressure; measure gross process steam output in joules per hour (or Btu per hour) on a continuous basis; and record the output of the monitor.
              (3) For an affected facility generating process steam in combination with electrical generation, the gross energy output is determined according to the definition of “gross energy output” specified in § 60.41Da that is applicable to the affected facility.
              (l) The owner or operator of an affected facility demonstrating compliance with an output-based standard shall install, certify, operate, and maintain a continuous flow monitoring system meeting the requirements of Performance Specification 6 of appendix B of this part and the calibration drift (CD) assessment, relative accuracy test audit (RATA), and reporting provisions of procedure 1 of appendix F of this part, and record the output of the system, for measuring the volumetric flow rate of exhaust gases discharged to the atmosphere; or
              (m) Alternatively, data from a continuous flow monitoring system certified according to the requirements of § 75.20(c) of this chapter and appendix A to part 75 of this chapter, and continuing to meet the applicable quality control and quality assurance requirements of § 75.21 of this chapter and appendix B to part 75 of this chapter, may be used. Flow rate data reported to meet the requirements of § 60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
              (n) Gas-fired and oil-fired units. The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in 40 CFR 72.2, may use, as an alternative to the requirements specified in either paragraph (l) or (m) of this section, a fuel flow monitoring system certified and operated according to the requirements of appendix D of part 75 of this chapter.

              (o) The owner or operator of a duct burner, as described in § 60.41Da, which is subject to the NOX standards of § 60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to measure NOX emissions; a wattmeter to measure gross electrical output; meters to measure steam flow, temperature, and pressure; and a continuous flow monitoring system to measure the flow of exhaust gases discharged to the atmosphere.
              (p)-(r) [Reserved]
              (s) The owner or operator shall prepare and submit to the Administrator for approval a unit-specific monitoring plan for each monitoring system, at least 45 days before commencing certification testing of the monitoring systems. The owner or operator shall comply with the requirements in your plan. The plan must address the requirements in paragraphs (s)(1) through (6) of this section.
              (1) Installation of the CEMS sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of the exhaust emissions (e.g., on or downstream of the last control device);
              (2) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems;

              (3) Performance evaluation procedures and acceptance criteria (e.g., calibrations, relative accuracy test audits (RATA), etc.);

              (4) Ongoing operation and maintenance procedures in accordance with the general requirements of § 60.13(d) or part 75 of this chapter (as applicable);
              (5) Ongoing data quality assurance procedures in accordance with the general requirements of § 60.13 or part 75 of this chapter (as applicable); and
              (6) Ongoing recordkeeping and reporting procedures in accordance with the requirements of this subpart.
              (t) The owner or operator of an affected facility demonstrating compliance with the output-based emissions limit under § 60.42Da must either install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section or install, calibrate, operate, and maintain a PM CPMS according to the requirements for new facilities specified in subpart UUUUU of part 63 of this chapter. An owner or operator of an affected facility demonstrating compliance with the input-based emissions limit in § 60.42Da may install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section.
              (u) The owner or operator of an affected facility using a CEMS measuring CO emissions to meet requirements of this subpart shall meet the requirements specified in paragraphs (u)(1) through (4) of this section.
              (1) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (u)(1)(i) through (iv) of this section.
              (i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part.
              (ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
              (iii) At a minimum, non-out-of-control 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-boiler operating day rolling average basis. The 1-hour averages are calculated using the data points required in § 60.13(h)(2).
              (iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.
              (2) You must calculate the 1-hour average CO emissions levels for each boiler operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly useful energy output from the affected facility. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each boiler operating day.
              (3) You must evaluate the preceding 24-hour average CO emission level each boiler operating day excluding periods of affected facility startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 1.4 lb/MWh, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 1.4 lb/MWh or less.
              (4) You must record the CO measurements and calculations performed according to paragraph (u)(3) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 1.4 lb/MWh, and the date, time, and description of the corrective action.
              (v) The owner or operator of an affected facility using a CEMS measuring PM emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (v)(1) through (v)(4) of this section.
              (1) The owner or operator shall conduct a performance evaluation of the CEMS according to the applicable requirements of § 60.13, Performance Specification 11 in appendix B of this part, and procedure 2 in appendix F of this part.

              (2) During each PM correlation testing run of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O2 (or CO2) data shall be collected concurrently (or within a 30- to 60-minute period) by both the CEMS and performance tests conducted using the following test methods.
              (i) For PM, Method 5 or 5B of appendix A-3 of this part or Method 17 of appendix A-6 of this part shall be used; and
              (ii) For O2 (or CO2), Method 3A or 3B of appendix A-2 of this part, as applicable shall be used.
              (3) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years.

              (4) As of January 1, 2012, and within 90 days after the date of completing each performance test, as defined in § 60.8, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief /ert/ert tool.html/) or other compatible electronic spreadsheet. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically into EPA's WebFire database.
              (w) The owner or operator using a SO2, NOX, CO2, and O2 CEMS to meet the requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (w)(1) through (w)(5) of this section.

              (1) Except as provided for under paragraphs (w)(2), (w)(3), and (w)(4) of this section, each SO2, NOX, CO2, and O2 CEMS required under paragraphs (b) through (d) of this section shall be installed, certified, and operated in accordance with the applicable procedures in Performance Specification 2 or 3 in appendix B to this part or according to the procedures in appendices A and B to part 75 of this chapter. Daily calibration drift assessments and quarterly accuracy determinations shall be done in accordance with Procedure 1 in appendix F to this part, and a data assessment report (DAR), prepared according to section 7 of Procedure 1 in appendix F to this part, shall be submitted with each compliance report required under § 60.51Da.

              (2) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to implement the following alternative data accuracy assessment procedures. For all required CO2 and O2 CEMS and for SO2 and NOX CEMS with span values greater than or equal to 100 ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F of this part. If this option is selected, the data validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this chapter shall be followed instead of the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part. For the purposes of data validation under this subpart, the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part shall apply to SO2 and NOX span values less than 100 ppm;

              (3) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For all required CO2 and O2 CEMS and for SO2 and NOX CEMS with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits (CGAs) described in Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linearity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.2.4 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the cylinder gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for SO2 and NOX span values less than or equal to 30 ppm;

              (4) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For SO2, CO2, and O2 CEMS and for NOX CEMS, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall be met on a lb/MMBtu basis for SO2 (regardless of the SO2 emission level during the RATA), and for NOX when the average NOX emission rate measured by the reference method during the RATA is less than 0.100 lb/MMBtu;
              (5) If the owner or operator elects to implement the alternative data assessment procedures described in paragraphs (w)(2) through (w)(4) of this section, each data assessment report shall include a summary of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift assessments required by paragraphs (w)(2) through (w)(4) of this section.
              [72 FR 32722, June 13, 2007, as amended at 74 FR 5081, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9456, Feb. 16, 2012; 77 FR 23402, Apr. 19, 2012; 78 FR 24083, Apr. 24, 2013]

              § 60.50Da
              Compliance determination procedures and methods.

              (a) In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the methods in appendix A of this part or the methods and procedures as specified in this section, except as provided in § 60.8(b). Section 60.8(f) does not apply to this section for SO2 and NOX. Acceptable alternative methods are given in paragraph (e) of this section.
              (b) In conducting the performance tests to determine compliance with the PM emissions limits in § 60.42Da, the owner or operator shall meet the requirements specified in paragraphs (b)(1) through (3) of this section.
              (1) The owner or operator shall measure filterable PM to determine compliance with the applicable PM emissions limit in § 60.42Da as specified in paragraphs (b)(1)(i) through (ii) of this section.
              (i) The dry basis F factor (O2) procedures in Method 19 of appendix A of this part shall be used to compute the emission rate of PM.
              (ii) For the PM concentration, Method 5 of appendix A of this part shall be used for an affected facility that does not use a wet FGD. For an affected facility that uses a wet FGD, Method 5B of appendix A of this part shall be used downstream of the wet FGD.
              (A) The sampling time and sample volume for each run shall be at least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder heating system in the sampling train may be set to provide an average gas temperature of no greater than 160 14 °C (320 25  °F).

              (B) For each particulate run, the emission rate correction factor, integrated or grab sampling and analysis procedures of Method 3B of appendix A of this part shall be used to determine the O2 concentration. The O2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate run. If the particulate run has more than 12 traverse points, the O2 traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O2 traverse points. If the grab sampling procedure is used, the O2 concentration for the run shall be the arithmetic mean of the sample O2 concentrations at all traverse points.
              (2) In conjunction with a performance test performed according to the requirements in paragraph (b)(1) of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after May 3, 2011, shall measure condensable PM using Method 202 of appendix M of part 51.
              (3) Method 9 of appendix A of this part and the procedures in § 60.11 shall be used to determine opacity.

              (c) The owner or operator shall determine compliance with the SO2 standards in § 60.43Da as follows:
              (1) The percent of potential SO2 emissions (%Ps) to the atmosphere shall be computed using the following equation:

                ER13JN07.015

                Where:

                %Ps = Percent of potential SO2 emissions, percent;
                %Rf = Percent reduction from fuel pretreatment, percent; and
                %Rg = Percent reduction by SO2 control system, percent.

              (2) The procedures in Method 19 of appendix A of this part may be used to determine percent reduction (%Rf) of sulfur by such processes as fuel pretreatment (physical coal cleaning, hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom and fly ash interactions. This determination is optional.

              (3) The procedures in Method 19 of appendix A of this part shall be used to determine the percent SO2 reduction (%Rg) of any SO2 control system. Alternatively, a combination of an “as fired” fuel monitor and emission rates measured after the control system, following the procedures in Method 19 of appendix A of this part, may be used if the percent reduction is calculated using the average emission rate from the SO2 control device and the average SO2 input rate from the “as fired” fuel analysis for 30 successive boiler operating days.
              (4) The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the emission rate.

              (5) The CEMS in § 60.49Da(b) and (d) shall be used to determine the concentrations of SO2 and CO2 or O2.

              (d) The owner or operator shall determine compliance with the NOX standard in § 60.44Da as follows:

              (1) The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the emission rate of NOX.

              (2) The continuous monitoring system in § 60.49Da(c) and (d) shall be used to determine the concentrations of NOX and CO2 or O2.
              (e) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section:
              (1) For Method 5 or 5B of appendix A-3 of this part, Method 17 of appendix A-6 of this part may be used at facilities with or without wet FGD systems if the stack temperature at the sampling location does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of this part may be used in Method 17 of appendix A-6 of this part only if it is used after wet FGD systems. Method 17 of appendix A-6 of this part shall not be used after wet FGD systems if the effluent is saturated or laden with water droplets.
              (2) The Fc factor (CO2) procedures in Method 19 of appendix A of this part may be used to compute the emission rate of PM under the stipulations of § 60.46(d)(1). The CO2 shall be determined in the same manner as the O2 concentration.

              (f) The owner or operator of an electric utility combined cycle gas turbine that does not meet the definition of an IGCC must conduct performance tests for PM, SO2, and NOX using the procedures of Method 19 of appendix A-7 of this part. The SO2 and NOX emission rates calculations from the gas turbine used in Method 19 of appendix A-7 of this part are determined when the gas turbine is performance tested under subpart GG of this part. The potential uncontrolled PM emission rate from a gas turbine is defined as 17 ng/J (0.04 lb/MMBtu) heat input.
              [72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009; 77 FR 9458, Feb. 16, 2012; 78 FR 24084, Apr. 24, 2013]

              § 60.51Da
              Reporting requirements.
              (a) For SO2, NOX, PM, and NOX plus CO emissions, the performance test data from the initial and subsequent performance test and from the performance evaluation of the continuous monitors (including the transmissometer) must be reported to the Administrator.
              (b) For SO2 and NOX the following information is reported to the Administrator for each 24-hour period.
              (1) Calendar date.
              (2) The average SO2 and NOX emission rates (ng/J, lb/MMBtu, or lb/MWh) for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the emission standards; and, description of corrective actions taken.

              (3) For owners or operators of affected facilities complying with the percent reduction requirement, percent reduction of the potential combustion concentration of SO2 for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the standard; and, description of corrective actions taken.
              (4) Identification of the boiler operating days for which pollutant or diluent data have not been obtained by an approved method for at least 75 percent of the hours of operation of the facility; justification for not obtaining sufficient data; and description of corrective actions taken.
              (5) Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, or malfunction.
              (6) Identification of “F” factor used for calculations, method of determination, and type of fuel combusted.
              (7) Identification of times when hourly averages have been obtained based on manual sampling methods.
              (8) Identification of the times when the pollutant concentration exceeded full span of the CEMS.
              (9) Description of any modifications to CEMS which could affect the ability of the CEMS to comply with Performance Specifications 2 or 3.
              (c) If the minimum quantity of emission data as required by § 60.49Da is not obtained for any 30 successive boiler operating days, the following information obtained under the requirements of § 60.48Da(h) is reported to the Administrator for that 30-day period:

              (1) The number of hourly averages available for outlet emission rates (no) and inlet emission rates (ni) as applicable.

              (2) The standard deviation of hourly averages for outlet emission rates (so) and inlet emission rates (si) as applicable.

              (3) The lower confidence limit for the mean outlet emission rate (Eo*) and the upper confidence limit for the mean inlet emission rate (Ei*) as applicable.
              (4) The applicable potential combustion concentration.

              (5) The ratio of the upper confidence limit for the mean outlet emission rate (Eo*) and the allowable emission rate (Estd) as applicable.
              (d) In addition to the applicable requirements in § 60.7, the owner or operator of an affected facility subject to the opacity limits in § 60.43c(c) and conducting performance tests using Method 9 of appendix A-4 of this part shall submit excess emission reports for any excess emissions from the affected facility that occur during the reporting period and maintain records according to the requirements specified in paragraph (d)(1) of this section.
              (1) For each performance test conducted using Method 9 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (d)(1)(i) through (iii) of this section.
              (i) Dates and time intervals of all opacity observation periods;
              (ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and
              (iii) Copies of all visible emission observer opacity field data sheets.
              (2) [Reserved]
              (e) If fuel pretreatment credit toward the SO2 emission standard under § 60.43Da is claimed, the owner or operator of the affected facility shall submit a signed statement:
              (1) Indicating what percentage cleaning credit was taken for the calendar quarter, and whether the credit was determined in accordance with the provisions of § 60.50Da and Method 19 of appendix A of this part; and
              (2) Listing the quantity, heat content, and date each pretreated fuel shipment was received during the previous quarter; the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels received at the affected facility during the previous quarter.
              (f) For any periods for which opacity, SO2 or NOX emissions data are not available, the owner or operator of the affected facility shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability.
              (g) [Reserved]
              (h) The owner or operator of the affected facility shall submit a signed statement indicating whether:
              (1) The required CEMS calibration, span, and drift checks or other periodic audits have or have not been performed as specified.
              (2) The data used to show compliance was or was not obtained in accordance with approved methods and procedures of this part and is representative of plant performance.
              (3) The minimum data requirements have or have not been met; or, the minimum data requirements have not been met for errors that were unavoidable.
              (4) Compliance with the standards has or has not been achieved during the reporting period.
              (i) For the purposes of the reports required under § 60.7, periods of excess emissions are defined as all 6-minute periods during which the average opacity exceeds the applicable opacity standards under § 60.42Da(b). Opacity levels in excess of the applicable opacity standard and the date of such excesses are to be submitted to the Administrator each calendar quarter.
              (j) The owner or operator of an affected facility shall submit the written reports required under this section and subpart A to the Administrator semiannually for each six-month period. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period.

              (k) The owner or operator of an affected facility may submit electronic quarterly reports for SO2 and/or NOX and/or opacity in lieu of submitting the written reports required under paragraphs (b) and (i) of this section. The format of each quarterly electronic report shall be coordinated with the permitting authority. The electronic report(s) shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a certification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period.
              [72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009; 77 FR 9458, Feb. 16, 2012]

              § 60.52Da
              Recordkeeping requirements.
              (a) [Reserved]
              (b) The owner or operator of an affected facility subject to the opacity limits in § 60.42Da(b) that elects to monitor emissions according to the requirements in § 60.49Da(a)(3) shall maintain records according to the requirements specified in paragraphs (b)(1) through (3) of this section, as applicable to the visible emissions monitoring method used.
              (1) For each performance test conducted using Method 9 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (b)(1)(i) through (iii) of this section.
              (i) Dates and time intervals of all opacity observation periods;

              (ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and

              (iii) Copies of all visible emission observer opacity field data sheets;
              (2) For each performance test conducted using Method 22 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (b)(2)(i) through (iv) of this section.
              (i) Dates and time intervals of all visible emissions observation periods;
              (ii) Name and affiliation for each visible emission observer participating in the performance test;
              (iii) Copies of all visible emission observer opacity field data sheets; and
              (iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements.
              (3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the Administrator.
              [74 FR 5083, Jan. 28, 2009, as amended at 77 FR 9459, Feb. 16, 2012]

            Subpart Db—Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units

              Source:
              72 FR 32742, June 13, 2007, unless otherwise noted.

              § 60.40b
              Applicability and delegation of authority.
              (a) The affected facility to which this subpart applies is each steam generating unit that commences construction, modification, or reconstruction after June 19, 1984, and that has a heat input capacity from fuels combusted in the steam generating unit of greater than 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/hr)).
              (b) Any affected facility meeting the applicability requirements under paragraph (a) of this section and commencing construction, modification, or reconstruction after June 19, 1984, but on or before June 19, 1986, is subject to the following standards:

              (1) Coal-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to the particulate matter (PM) and nitrogen oxides (NOX) standards under this subpart.

              (2) Coal-fired affected facilities having a heat input capacity greater than 73 MW (250 MMBtu/hr) and meeting the applicability requirements under subpart D (Standards of performance for fossil-fuel-fired steam generators; § 60.40) are subject to the PM and NOX standards under this subpart and to the sulfur dioxide (SO2) standards under subpart D (§ 60.43).

              (3) Oil-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, are subject to the NOX standards under this subpart.

              (4) Oil-fired affected facilities having a heat input capacity greater than 73 MW (250 MMBtu/hr) and meeting the applicability requirements under subpart D (Standards of performance for fossil-fuel-fired steam generators; § 60.40) are also subject to the NOX standards under this subpart and the PM and SO2 standards under subpart D (§§ 60.42 and 60.43).

              (c) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja of this part are subject to the PM and NOX standards under this subpart and the SO2 standards under subpart J or subpart Ja of this part, as applicable.

              (d) Affected facilities that also meet the applicability requirements under subpart E (Standards of performance for incinerators; § 60.50) are subject to the NOX and PM standards under this subpart.
              (e) Steam generating units meeting the applicability requirements under subpart Da (Standards of performance for electric utility steam generating units; § 60.40Da) are not subject to this subpart.

              (f) Any change to an existing steam generating unit for the sole purpose of combusting gases containing total reduced sulfur (TRS) as defined under § 60.281 is not considered a modification under § 60.14 and the steam generating unit is not subject to this subpart.

              (g) In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, the following authorities shall be retained by the Administrator and not transferred to a State.
              (1) Section 60.44b(f).
              (2) Section 60.44b(g).
              (3) Section 60.49b(a)(4).
              (h) Any affected facility that meets the applicability requirements and is subject to subpart Ea, subpart Eb, subpart AAAA, or subpart CCCC of this part is not subject to this subpart.
              (i) Affected facilities (i.e., heat recovery steam generators) that are associated with stationary combustion turbines and that meet the applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other affected facilities (i.e. heat recovery steam generators with duct burners) that are capable of combusting more than 29 MW (100 MMBtu/h) heat input of fossil fuel. If the affected facility (i.e. heat recovery steam generator) is subject to this subpart, only emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. (The stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part.)
              (j) Any affected facility meeting the applicability requirements under paragraph (a) of this section and commencing construction, modification, or reconstruction after June 19, 1986 is not subject to subpart D (Standards of Performance for Fossil-Fuel-Fired Steam Generators, § 60.40).
              (k) Any affected facility that meets the applicability requirements and is subject to an EPA approved State or Federal section 111(d)/129 plan implementing subpart Cb or subpart BBBB of this part is not covered by this subpart.

              (l) Affected facilities that also meet the applicability requirements under subpart BB of this part (Standards of Performance for Kraft Pulp Mills) are subject to the SO2 and NOX standards under this subpart and the PM standards under subpart BB.
              (m) Temporary boilers are not subject to this subpart.
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 77 FR 9459, Feb. 16, 2012]

              § 60.41b
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air Act and in subpart A of this part.

                Annual capacity factor means the ratio between the actual heat input to a steam generating unit from the fuels listed in § 60.42b(a), § 60.43b(a), or § 60.44b(a), as applicable, during a calendar year and the potential heat input to the steam generating unit had it been operated for 8,760 hours during a calendar year at the maximum steady state design heat input capacity. In the case of steam generating units that are rented or leased, the actual heat input shall be determined based on the combined heat input from all operations of the affected facility in a calendar year.

                Byproduct/waste means any liquid or gaseous substance produced at chemical manufacturing plants, petroleum refineries, or pulp and paper mills (except natural gas, distillate oil, or residual oil) and combusted in a steam generating unit for heat recovery or for disposal. Gaseous substances with carbon dioxide (CO2) levels greater than 50 percent or carbon monoxide levels greater than 10 percent are not byproduct/waste for the purpose of this subpart.

                Chemical manufacturing plants mean industrial plants that are classified by the Department of Commerce under Standard Industrial Classification (SIC) Code 28.

                Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Coal-derived synthetic fuels, including but not limited to solvent refined coal, gasified coal not meeting the definition of natural gas, coal-oil mixtures, coke oven gas, and coal-water mixtures, are also included in this definition for the purposes of this subpart.

                Coal refuse means any byproduct of coal mining or coal cleaning operations with an ash content greater than 50 percent, by weight, and a heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a dry basis.

                Cogeneration, also known as combined heat and power, means a facility that simultaneously produces both electric (or mechanical) and useful thermal energy from the same primary energy source.

                Coke oven gas means the volatile constituents generated in the gaseous exhaust during the carbonization of bituminous coal to form coke.

                Combined cycle system means a system in which a separate source, such as a gas turbine, internal combustion engine, kiln, etc., provides exhaust gas to a steam generating unit.

                Conventional technology means wet flue gas desulfurization (FGD) technology, dry FGD technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology.

                Distillate oil means fuel oils that contain 0.05 weight percent nitrogen or less and comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17), diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17), kerosine, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17), biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17), or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17).

                Dry flue gas desulfurization technology means a SO2 control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline slurries or solutions used in dry flue gas desulfurization technology include but are not limited to lime and sodium.

                Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a steam generating unit.

                Emerging technology means any SO2 control system that is not defined as a conventional technology under this section, and for which the owner or operator of the facility has applied to the Administrator and received approval to operate as an emerging technology under § 60.49b(a)(4).

                Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State Implementation Plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24.

                Fluidized bed combustion technology means combustion of fuel in a bed or series of beds (including but not limited to bubbling bed units and circulating bed units) of limestone aggregate (or other sorbent materials) in which these materials are forced upward by the flow of combustion air and the gaseous products of combustion.

                Fuel pretreatment means a process that removes a portion of the sulfur in a fuel before combustion of the fuel in a steam generating unit.

                Full capacity means operation of the steam generating unit at 90 percent or more of the maximum steady-state design heat input capacity.

                Gaseous fuel means any fuel that is a gas at ISO conditions. This includes, but is not limited to, natural gas and gasified coal (including coke oven gas).

                Gross output means the gross useful work performed by the steam generated. For units generating only electricity, the gross useful work performed is the gross electrical output from the turbine/generator set. For cogeneration units, the gross useful work performed is the gross electrical or mechanical output plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process).

                Heat input means heat derived from combustion of fuel in a steam generating unit and does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

                Heat release rate means the steam generating unit design heat input capacity (in MW or Btu/hr) divided by the furnace volume (in cubic meters or cubic feet); the furnace volume is that volume bounded by the front furnace wall where the burner is located, the furnace side waterwall, and extending to the level just below or in front of the first row of convection pass tubes.

                Heat transfer medium means any material that is used to transfer heat from one point to another point.

                High heat release rate means a heat release rate greater than 730,000 J/sec-m3 (70,000 Btu/hr-ft3).

                ISO Conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals.

                Lignite means a type of coal classified as lignite A or lignite B by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17).

                Low heat release rate means a heat release rate of 730,000 J/sec-m3 (70,000 Btu/hr-ft3) or less.

                Mass-feed stoker steam generating unit means a steam generating unit where solid fuel is introduced directly into a retort or is fed directly onto a grate where it is combusted.

                Maximum heat input capacity means the ability of a steam generating unit to combust a stated maximum amount of fuel on a steady state basis, as determined by the physical design and characteristics of the steam generating unit.

                Municipal-type solid waste means refuse, more than 50 percent of which is waste consisting of a mixture of paper, wood, yard wastes, food wastes, plastics, leather, rubber, and other combustible materials, and noncombustible materials such as glass and rock.

                Natural gas means:
              (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or
              (2) Liquefied petroleum gas, as defined by the American Society for Testing and Materials in ASTM D1835 (incorporated by reference, see § 60.17); or
              (3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot).

                Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands.

                Oil means crude oil or petroleum or a liquid fuel derived from crude oil or petroleum, including distillate and residual oil.

                Petroleum refinery means industrial plants as classified by the Department of Commerce under Standard Industrial Classification (SIC) Code 29.

                Potential sulfur dioxide emission rate means the theoretical SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems. For gasified coal or oil that is desulfurized prior to combustion, the Potential sulfur dioxide emission rate is the theoretical SO2 emissions (ng/J or lb/MMBtu heat input) that would result from combusting fuel in a cleaned state without using any post combustion emission control systems.

                Process heater means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst.

                Pulp and paper mills means industrial plants that are classified by the Department of Commerce under North American Industry Classification System (NAICS) Code 322 or Standard Industrial Classification (SIC) Code 26.

                Pulverized coal-fired steam generating unit means a steam generating unit in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the steam generating unit where it is fired in suspension. This includes both conventional pulverized coal-fired and micropulverized coal-fired steam generating units. Residual oil means crude oil, fuel oil numbers 1 and 2 that have a nitrogen content greater than 0.05 weight percent, and all fuel oil numbers 4, 5 and 6, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17).

                Spreader stoker steam generating unit means a steam generating unit in which solid fuel is introduced to the combustion zone by a mechanism that throws the fuel onto a grate from above. Combustion takes place both in suspension and on the grate.

                Steam generating unit means a device that combusts any fuel or byproduct/waste and produces steam or heats water or heats any heat transfer medium. This term includes any municipal-type solid waste incinerator with a heat recovery steam generating unit or any steam generating unit that combusts fuel and is part of a cogeneration system or a combined cycle system. This term does not include process heaters as they are defined in this subpart.

                Steam generating unit operating day means a 24-hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period.

                Temporary boiler means any gaseous or liquid fuel-fired steam generating unit that is designed to, and is capable of, being carried or moved from one location to another by means of, for example, wheels, skids, carrying handles, dollies, trailers, or platforms. A steam generating unit is not a temporary boiler if any one of the following conditions exists:
              (1) The equipment is attached to a foundation.
              (2) The steam generating unit or a replacement remains at a location for more than 180 consecutive days. Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar function will be included in calculating the consecutive time period.
              (3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year.
              (4) The equipment is moved from one location to another in an attempt to circumvent the residence time requirements of this definition.

                Very low sulfur oil means for units constructed, reconstructed, or modified on or before February 28, 2005, oil that contains no more than 0.5 weight percent sulfur or that, when combusted without SO2 emission control, has a SO2 emission rate equal to or less than 215 ng/J (0.5 lb/MMBtu) heat input. For units constructed, reconstructed, or modified after February 28, 2005 and not located in a noncontinental area, very low sulfur oil means oil that contains no more than 0.30 weight percent sulfur or that, when combusted without SO2 emission control, has a SO2 emission rate equal to or less than 140 ng/J (0.32 lb/MMBtu) heat input. For units constructed, reconstructed, or modified after February 28, 2005 and located in a noncontinental area, very low sulfur oil means oil that contains no more than 0.5 weight percent sulfur or that, when combusted without SO2 emission control, has a SO2 emission rate equal to or less than 215 ng/J (0.50 lb/MMBtu) heat input.

                Wet flue gas desulfurization technology means a SO2 control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gas with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet flue gas desulfurization technology include, but are not limited to, lime, limestone, and sodium.

                Wet scrubber system means any emission control device that mixes an aqueous stream or slurry with the exhaust gases from a steam generating unit to control emissions of PM or SO2.

                Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including, but not limited to, sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues.
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 77 FR 9459, Feb. 16, 2012]

              § 60.42b
              Standard for sulfur dioxide (SO2).

              (a) Except as provided in paragraphs (b), (c), (d), or (j) of this section, on and after the date on which the performance test is completed or required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal or oil shall cause to be discharged into the atmosphere any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO2 emission rate (90 percent reduction) and the emission limit determined according to the following formula:

                ER28JA09.003

                Where:

                Es = SO2 emission limit, in ng/J or lb/MMBtu heat input;
                Ka = 520 ng/J (or 1.2 lb/MMBtu);
                Kb = 340 ng/J (or 0.80 lb/MMBtu);
                Ha = Heat input from the combustion of coal, in J (MMBtu); and
                Hb = Heat input from the combustion of oil, in J (MMBtu).

              For facilities complying with the percent reduction standard, only the heat input supplied to the affected facility from the combustion of coal and oil is counted in this paragraph. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

              (b) On and after the date on which the performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal refuse alone in a fluidized bed combustion steam generating unit shall cause to be discharged into the atmosphere any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO2 emission rate (80 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. If coal or oil is fired with coal refuse, the affected facility is subject to paragraph (a) or (d) of this section, as applicable. For facilities complying with the percent reduction standard, only the heat input supplied to the affected facility from the combustion of coal and oil is counted in this paragraph. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

              (c) On and after the date on which the performance test is completed or is required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that combusts coal or oil, either alone or in combination with any other fuel, and that uses an emerging technology for the control of SO2 emissions, shall cause to be discharged into the atmosphere any gases that contain SO2 in excess of 50 percent of the potential SO2 emission rate (50 percent reduction) and that contain SO2 in excess of the emission limit determined according to the following formula:

                ER28JA09.004

                Where:

                Es = SO2 emission limit, in ng/J or lb/MM Btu heat input;
                Kc = 260 ng/J (or 0.60 lb/MMBtu);
                Kd = 170 ng/J (or 0.40 lb/MMBtu);
                Hc = Heat input from the combustion of coal, in J (MMBtu); and
                Hd = Heat input from the combustion of oil, in J (MMBtu).

              For facilities complying with the percent reduction standard, only the heat input supplied to the affected facility from the combustion of coal and oil is counted in this paragraph. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels, or from the heat input derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

              (d) On and after the date on which the performance test is completed or required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005 and listed in paragraphs (d)(1), (2), (3), or (4) of this section shall cause to be discharged into the atmosphere any gases that contain SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input if the affected facility combusts oil other than very low sulfur oil. Percent reduction requirements are not applicable to affected facilities under paragraphs (d)(1), (2), (3) or (4) of this section. For facilities complying with paragraphs (d)(1), (2), or (3) of this section, only the heat input supplied to the affected facility from the combustion of coal and oil is counted in this paragraph. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.
              (1) Affected facilities that have an annual capacity factor for coal and oil of 30 percent (0.30) or less and are subject to a federally enforceable permit limiting the operation of the affected facility to an annual capacity factor for coal and oil of 30 percent (0.30) or less;
              (2) Affected facilities located in a noncontinental area; or
              (3) Affected facilities combusting coal or oil, alone or in combination with any fuel, in a duct burner as part of a combined cycle system where 30 percent (0.30) or less of the heat entering the steam generating unit is from combustion of coal and oil in the duct burner and 70 percent (0.70) or more of the heat entering the steam generating unit is from the exhaust gases entering the duct burner; or
              (4) The affected facility burns coke oven gas alone or in combination with natural gas or very low sulfur distillate oil.
              (e) Except as provided in paragraph (f) of this section, compliance with the emission limits, fuel oil sulfur limits, and/or percent reduction requirements under this section are determined on a 30-day rolling average basis.
              (f) Except as provided in paragraph (j)(2) of this section, compliance with the emission limits or fuel oil sulfur limits under this section is determined on a 24-hour average basis for affected facilities that (1) have a federally enforceable permit limiting the annual capacity factor for oil to 10 percent or less, (2) combust only very low sulfur oil, and (3) do not combust any other fuel.

              (g) Except as provided in paragraph (i) of this section and § 60.45b(a), the SO2 emission limits and percent reduction requirements under this section apply at all times, including periods of startup, shutdown, and malfunction.
              (h) Reductions in the potential SO2 emission rate through fuel pretreatment are not credited toward the percent reduction requirement under paragraph (c) of this section unless:

              (1) Fuel pretreatment results in a 50 percent or greater reduction in potential SO2 emissions and

              (2) Emissions from the pretreated fuel (without combustion or post-combustion SO2 control) are equal to or less than the emission limits specified in paragraph (c) of this section.

              (i) An affected facility subject to paragraph (a), (b), or (c) of this section may combust very low sulfur oil or natural gas when the SO2 control system is not being operated because of malfunction or maintenance of the SO2 control system.

              (j) Percent reduction requirements are not applicable to affected facilities combusting only very low sulfur oil. The owner or operator of an affected facility combusting very low sulfur oil shall demonstrate that the oil meets the definition of very low sulfur oil by: (1) Following the performance testing procedures as described in § 60.45b(c) or § 60.45b(d), and following the monitoring procedures as described in § 60.47b(a) or § 60.47b(b) to determine SO2 emission rate or fuel oil sulfur content; or (2) maintaining fuel records as described in § 60.49b(r).

              (k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, natural gas, a mixture of these fuels, or a mixture of these fuels with any other fuels shall cause to be discharged into the atmosphere any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 8 percent (0.08) of the potential SO2 emission rate (92 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. For facilities complying with the percent reduction standard and paragraph (k)(3) of this section, only the heat input supplied to the affected facility from the combustion of coal and oil is counted in paragraph (k) of this section. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

              (2) Units firing only very low sulfur oil, gaseous fuel, a mixture of these fuels, or a mixture of these fuels with any other fuels with a potential SO2 emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less are exempt from the SO2 emissions limit in paragraph (k)(1) of this section.

              (3) Units that are located in a noncontinental area and that combust coal, oil, or natural gas shall not discharge any gases that contain SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input if the affected facility combusts oil or natural gas.

              (4) As an alternative to meeting the requirements under paragraph (k)(1) of this section, modified facilities that combust coal or a mixture of coal with other fuels shall not cause to be discharged into the atmosphere any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO2 emission rate (90 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input.
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011]

              § 60.43b
              Standard for particulate matter (PM).
              (a) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005 that combusts coal or combusts mixtures of coal with other fuels, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
              (1) 22 ng/J (0.051 lb/MMBtu) heat input, (i) If the affected facility combusts only coal, or
              (ii) If the affected facility combusts coal and other fuels and has an annual capacity factor for the other fuels of 10 percent (0.10) or less.

              (2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal and other fuels and has an annual capacity factor for the other fuels greater than 10 percent (0.10) and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor greater than 10 percent (0.10) for fuels other than coal.
              (3) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts coal or coal and other fuels and
              (i) Has an annual capacity factor for coal or coal and other fuels of 30 percent (0.30) or less,
              (ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less,
              (iii) Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30 percent (0.30) or less for coal or coal and other solid fuels, and
              (iv) Construction of the affected facility commenced after June 19, 1984, and before November 25, 1986.

              (4) An affected facility burning coke oven gas alone or in combination with other fuels not subject to a PM standard under § 60.43b and not using a post-combustion technology (except a wet scrubber) for reducing PM or SO2 emissions is not subject to the PM limits under § 60.43b(a).

              (b) On and after the date on which the performance test is completed or required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, and that combusts oil (or mixtures of oil with other fuels) and uses a conventional or emerging technology to reduce SO2 emissions shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
              (c) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, and that combusts wood, or wood with other fuels, except coal, shall cause to be discharged from that affected facility any gases that contain PM in excess of the following emission limits:
              (1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor greater than 30 percent (0.30) for wood.
              (2) 86 ng/J (0.20 lb/MMBtu) heat input if (i) The affected facility has an annual capacity factor of 30 percent (0.30) or less for wood;
              (ii) Is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30 percent (0.30) or less for wood; and
              (iii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less.
              (d) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts municipal-type solid waste or mixtures of municipal-type solid waste with other fuels, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
              (1) 43 ng/J (0.10 lb/MMBtu) heat input;
              (i) If the affected facility combusts only municipal-type solid waste; or
              (ii) If the affected facility combusts municipal-type solid waste and other fuels and has an annual capacity factor for the other fuels of 10 percent (0.10) or less.
              (2) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts municipal-type solid waste or municipal-type solid waste and other fuels; and
              (i) Has an annual capacity factor for municipal-type solid waste and other fuels of 30 percent (0.30) or less;
              (ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less;
              (iii) Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30 percent (0.30) or less for municipal-type solid waste, or municipal-type solid waste and other fuels; and
              (iv) Construction of the affected facility commenced after June 19, 1984, but on or before November 25, 1986.

              (e) For the purposes of this section, the annual capacity factor is determined by dividing the actual heat input to the steam generating unit during the calendar year from the combustion of coal, wood, or municipal-type solid waste, and other fuels, as applicable, by the potential heat input to the steam generating unit if the steam generating unit had been operated for 8,760 hours at the maximum heat input capacity.
              (f) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, wood, or mixtures of these fuels with any other fuels shall cause to be discharged into the atmosphere any gases that exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity. An owner or operator of an affected facility that elects to install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart and is subject to a federally enforceable PM limit of 0.030 lb/MMBtu or less is exempt from the opacity standard specified in this paragraph.
              (g) The PM and opacity standards apply at all times, except during periods of startup, shutdown, or malfunction.
              (h)(1) Except as provided in paragraphs (h)(2), (h)(3), (h)(4), (h)(5), and (h)(6) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input,
              (2) As an alternative to meeting the requirements of paragraph (h)(1) of this section, the owner or operator of an affected facility for which modification commenced after February 28, 2005, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under § 60.8, no owner or operator of an affected facility that commences modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of both:
              (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels; and
              (ii) 0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels.
              (3) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a maximum heat input capacity of 73 MW (250 MMBtu/h) or less shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
              (4) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a maximum heat input capacity greater than 73 MW (250 MMBtu/h) shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 37 ng/J (0.085 lb/MMBtu) heat input.

              (5) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, an owner or operator of an affected facility not located in a noncontinental area that commences construction, reconstruction, or modification after February 28, 2005, and that combusts only oil that contains no more than 0.30 weight percent sulfur, coke oven gas, a mixture of these fuels, or either fuel (or a mixture of these fuels) in combination with other fuels not subject to a PM standard in § 60.43b and not using a post-combustion technology (except a wet scrubber) to reduce SO2 or PM emissions is not subject to the PM limits in (h)(1) of this section.

              (6) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, an owner or operator of an affected facility located in a noncontinental area that commences construction, reconstruction, or modification after February 28, 2005, and that combusts only oil that contains no more than 0.5 weight percent sulfur, coke oven gas, a mixture of these fuels, or either fuel (or a mixture of these fuels) in combination with other fuels not subject to a PM standard in § 60.43b and not using a post-combustion technology (except a wet scrubber) to reduce SO2 or PM emissions is not subject to the PM limits in (h)(1) of this section.
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 77 FR 9459, Feb. 16, 2012]

              § 60.44b
              Standard for nitrogen oxides (NO2).

              (a) Except as provided under paragraphs (k) and (l) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that is subject to the provisions of this section and that combusts only coal, oil, or natural gas shall cause to be discharged into the atmosphere from that affected facility any gases that contain NOX (expressed as NO2) in excess of the following emission limits:

                  Fuel/steam generating unit type
                  Nitrogen oxide emission limits (expressed as NO2) heat input
                  ng/J
                  lb/MMBTu

                  (1) Natural gas and distillate oil, except (4):

                  (i) Low heat release rate
                  43
                  0.10

                  (ii) High heat release rate
                  86
                  0.20

                  (2) Residual oil:

                  (i) Low heat release rate
                  130
                  0.30

                  (ii) High heat release rate
                  170
                  0.40

                  (3) Coal:

                  (i) Mass-feed stoker
                  210
                  0.50

                  (ii) Spreader stoker and fluidized bed combustion
                  260
                  0.60

                  (iii) Pulverized coal
                  300
                  0.70

                  (iv) Lignite, except (v)
                  260
                  0.60

                  (v) Lignite mined in North Dakota, South Dakota, or Montana and combusted in a slag tap furnace
                  340
                  0.80

                  (vi) Coal-derived synthetic fuels
                  210
                  0.50

                  (4) Duct burner used in a combined cycle system:

                  (i) Natural gas and distillate oil
                  86
                  0.20

                  (ii) Residual oil
                  170
                  0.40

              (b) Except as provided under paragraphs (k) and (l) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts mixtures of only coal, oil, or natural gas shall cause to be discharged into the atmosphere from that affected facility any gases that contain NOX in excess of a limit determined by the use of the following formula:

                ER13JN07.024

                Where:

                En = NOX emission limit (expressed as NO2), ng/J (lb/MMBtu);
                ELgo = Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);
                Hgo = Heat input from combustion of natural gas or distillate oil, J (MMBtu);

                ELro = Appropriate emission limit from paragraph (a)(2) for combustion of residual oil, ng/J (lb/MMBtu);
                Hro = Heat input from combustion of residual oil, J (MMBtu);
                ELc = Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and
                Hc = Heat input from combustion of coal, J (MMBtu).

              (c) Except as provided under paragraph (d) and (l) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts coal or oil, natural gas (or any combination of the three), and wood, or any other fuel shall cause to be discharged into the atmosphere any gases that contain NOX in excess of the emission limit for the coal, oil, natural gas (or any combination of the three), combusted in the affected facility, as determined pursuant to paragraph (a) or (b) of this section. This standard does not apply to an affected facility that is subject to and in compliance with a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10 percent (0.10) or less for coal, oil, natural gas (or any combination of the three).

              (d) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts natural gas and/or distillate oil with a potential SO2 emissions rate of 26 ng/J (0.060 lb/MMBtu) or less with wood, municipal-type solid waste, or other solid fuel, except coal, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NOX in excess of 130 ng/J (0.30 lb/MMBtu) heat input unless the affected facility has an annual capacity factor for natural gas, distillate oil, or a mixture of these fuels of 10 percent (0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10 percent (0.10) or less for natural gas, distillate oil, or a mixture of these fuels.

              (e) Except as provided under paragraph (l) of this section, on and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that simultaneously combusts only coal, oil, or natural gas with byproduct/waste shall cause to be discharged into the atmosphere any gases that contain NOX in excess of the emission limit determined by the following formula unless the affected facility has an annual capacity factor for coal, oil, and natural gas of 10 percent (0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10 percent (0.10) or less:

              (f) Any owner or operator of an affected facility that combusts byproduct/waste with either natural gas or oil may petition the Administrator within 180 days of the initial startup of the affected facility to establish a NOX emission limit that shall apply specifically to that affected facility when the byproduct/waste is combusted. The petition shall include sufficient and appropriate data, as determined by the Administrator, such as NOX emissions from the affected facility, waste composition (including nitrogen content), and combustion conditions to allow the Administrator to confirm that the affected facility is unable to comply with the emission limits in paragraph (e) of this section and to determine the appropriate emission limit for the affected facility.

              (1) Any owner or operator of an affected facility petitioning for a facility-specific NOX emission limit under this section shall:
              (i) Demonstrate compliance with the emission limits for natural gas and distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, by conducting a 30-day performance test as provided in § 60.46b(e). During the performance test only natural gas, distillate oil, or residual oil shall be combusted in the affected facility; and

              (ii) Demonstrate that the affected facility is unable to comply with the emission limits for natural gas and distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, when gaseous or liquid byproduct/waste is combusted in the affected facility under the same conditions and using the same technological system of emission reduction applied when demonstrating compliance under paragraph (f)(1)(i) of this section.
              (2) The NOX emission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, shall be applicable to the affected facility until and unless the petition is approved by the Administrator. If the petition is approved by the Administrator, a facility-specific NOX emission limit will be established at the NOX emission level achievable when the affected facility is combusting oil or natural gas and byproduct/waste in a manner that the Administrator determines to be consistent with minimizing NOX emissions. In lieu of amending this subpart, a letter will be sent to the facility describing the facility-specific NOX limit. The facility shall use the compliance procedures detailed in the letter and make the letter available to the public. If the Administrator determines it is appropriate, the conditions and requirements of the letter can be reviewed and changed at any point.

              (g) Any owner or operator of an affected facility that combusts hazardous waste (as defined by 40 CFR part 261 or 40 CFR part 761) with natural gas or oil may petition the Administrator within 180 days of the initial startup of the affected facility for a waiver from compliance with the NOX emission limit that applies specifically to that affected facility. The petition must include sufficient and appropriate data, as determined by the Administrator, on NOX emissions from the affected facility, waste destruction efficiencies, waste composition (including nitrogen content), the quantity of specific wastes to be combusted and combustion conditions to allow the Administrator to determine if the affected facility is able to comply with the NOX emission limits required by this section. The owner or operator of the affected facility shall demonstrate that when hazardous waste is combusted in the affected facility, thermal destruction efficiency requirements for hazardous waste specified in an applicable federally enforceable requirement preclude compliance with the NOX emission limits of this section. The NOX emission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, are applicable to the affected facility until and unless the petition is approved by the Administrator. (See 40 CFR 761.70 for regulations applicable to the incineration of materials containing polychlorinated biphenyls (PCB's).) In lieu of amending this subpart, a letter will be sent to the facility describing the facility-specific NOX limit. The facility shall use the compliance procedures detailed in the letter and make the letter available to the public. If the Administrator determines it is appropriate, the conditions and requirements of the letter can be reviewed and changed at any point.

              (h) For purposes of paragraph (i) of this section, the NOX standards under this section apply at all times including periods of startup, shutdown, or malfunction.
              (i) Except as provided under paragraph (j) of this section, compliance with the emission limits under this section is determined on a 30-day rolling average basis.
              (j) Compliance with the emission limits under this section is determined on a 24-hour average basis for the initial performance test and on a 3-hour average basis for subsequent performance tests for any affected facilities that:
              (1) Combust, alone or in combination, only natural gas, distillate oil, or residual oil with a nitrogen content of 0.30 weight percent or less;
              (2) Have a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen content of 0.30 weight percent or less; and

              (3) Are subject to a federally enforceable requirement limiting operation of the affected facility to the firing of natural gas, distillate oil, and/or residual oil with a nitrogen content of 0.30 weight percent or less and limiting operation of the affected facility to a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a nitrogen content of 0.30 weight percent or less.

              (k) Affected facilities that meet the criteria described in paragraphs (j)(1), (2), and (3) of this section, and that have a heat input capacity of 73 MW (250 MMBtu/hr) or less, are not subject to the NOX emission limits under this section.
              (l) On and after the date on which the initial performance test is completed or is required to be completed under 60.8, whichever date is first, no owner or operator of an affected facility that commenced construction after July 9, 1997 shall cause to be discharged into the atmosphere from that affected facility any gases that contain NOx (expressed as NO2) in excess of the following limits:
              (1) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts coal, oil, or natural gas (or any combination of the three), alone or with any other fuels. The affected facility is not subject to this limit if it is subject to and in compliance with a federally enforceable requirement that limits operation of the facility to an annual capacity factor of 10 percent (0.10) or less for coal, oil, and natural gas (or any combination of the three); or
              (2) If the affected facility has a low heat release rate and combusts natural gas or distillate oil in excess of 30 percent of the heat input on a 30-day rolling average from the combustion of all fuels, a limit determined by use of the following formula:

                ER13JN07.026

                Where:

                En = NOX emission limit, (lb/MMBtu);
                Hgo = 30-day heat input from combustion of natural gas or distillate oil; and
                Hr = 30-day heat input from combustion of any other fuel.

              (3) After February 27, 2006, units where more than 10 percent of total annual output is electrical or mechanical may comply with an optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on a 30-day rolling average. Units complying with this output-based limit must demonstrate compliance according to the procedures of § 60.48Da(i) of subpart Da of this part, and must monitor emissions according to § 60.49Da(c), (k), through (n) of subpart Da of this part.
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009; 77 FR 9459, Feb. 16, 2012]

              § 60.45b
              Compliance and performance test methods and procedures for sulfur dioxide.
              (a) The SO2 emission standards in § 60.42b apply at all times. Facilities burning coke oven gas alone or in combination with any other gaseous fuels or distillate oil are allowed to exceed the limit 30 operating days per calendar year for SO2 control system maintenance.
              (b) In conducting the performance tests required under § 60.8, the owner or operator shall use the methods and procedures in appendix A (including fuel certification and sampling) of this part or the methods and procedures as specified in this section, except as provided in § 60.8(b). Section 60.8(f) does not apply to this section. The 30-day notice required in § 60.8(d) applies only to the initial performance test unless otherwise specified by the Administrator.

              (c) The owner or operator of an affected facility shall conduct performance tests to determine compliance with the percent of potential SO2 emission rate (% Ps) and the SO2 emission rate (Es) pursuant to § 60.42b following the procedures listed below, except as provided under paragraph (d) and (k) of this section.

              (1) The initial performance test shall be conducted over 30 consecutive operating days of the steam generating unit. Compliance with the SO2 standards shall be determined using a 30-day average. The first operating day included in the initial performance test shall be scheduled within 30 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility.

              (2) If only coal, only oil, or a mixture of coal and oil is combusted, the following procedures are used:

              (i) The procedures in Method 19 of appendix A-7 of this part are used to determine the hourly SO2 emission rate (Eho) and the 30-day average emission rate (Eao). The hourly averages used to compute the 30-day averages are obtained from the CEMS of § 60.47b(a) or (b).
              (ii) The percent of potential SO2 emission rate (%Ps) emitted to the atmosphere is computed using the following formula:

                ER13JN07.027

                Where:

                %Ps = Potential SO2 emission rate, percent;
                %Rg = SO2 removal efficiency of the control device as determined by Method 19 of appendix A of this part, in percent; and
                %Rf = SO2 removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, in percent.

              (3) If coal or oil is combusted with other fuels, the same procedures required in paragraph (c)(2) of this section are used, except as provided in the following:
              (i) An adjusted hourly SO2 emission rate (Eho

                o) is used in Equation 19-19 of Method 19 of appendix A of this part to compute an adjusted 30-day average emission rate (Eao
                o). The Eho° is computed using the following formula:

                ER13JN07.028

                Where:

                Eho
                  o = Adjusted hourly SO2 emission rate, ng/J (lb/MMBtu);
                Eho = Hourly SO2 emission rate, ng/J (lb/MMBtu);
                Ew = SO2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by the fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The value Ew for each fuel lot is used for each hourly average during the time that the lot is being combusted; and
                Xk = Fraction of total heat input from fuel combustion derived from coal, oil, or coal and oil, as determined by applicable procedures in Method 19 of appendix A of this part.

              (ii) To compute the percent of potential SO2 emission rate (%Ps), an adjusted %Rg (%Rg
                o) is computed from the adjusted Eao

                o from paragraph (b)(3)(i) of this section and an adjusted average SO2 inlet rate (Eai
                o) using the following formula:

                ER13JN07.029

              To compute Eai
                o, an adjusted hourly SO2 inlet rate (Ehi
                o) is used. The Ehi
                o is computed using the following formula:

                ER13JN07.030

                Where:

                Ehi
                  o = Adjusted hourly SO2 inlet rate, ng/J (lb/MMBtu); and
                Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu).

              (4) The owner or operator of an affected facility subject to paragraph (c)(3) of this section does not have to measure parameters Ew or Xk if the owner or operator elects to assume that Xk = 1.0. Owners or operators of affected facilities who assume Xk = 1.0 shall:
              (i) Determine %Ps following the procedures in paragraph (c)(2) of this section; and
              (ii) Sulfur dioxide emissions (Es) are considered to be in compliance with SO2 emission limits under § 60.42b.

              (5) The owner or operator of an affected facility that qualifies under the provisions of § 60.42b(d) does not have to measure parameters Ew or Xk in paragraph (c)(3) of this section if the owner or operator of the affected facility elects to measure SO2 emission rates of the coal or oil following the fuel sampling and analysis procedures in Method 19 of appendix A-7 of this part.

              (d) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility that combusts only very low sulfur oil, natural gas, or a mixture of these fuels, has an annual capacity factor for oil of 10 percent (0.10) or less, and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for oil of 10 percent (0.10) or less shall:

              (1) Conduct the initial performance test over 24 consecutive steam generating unit operating hours at full load;
              (2) Determine compliance with the standards after the initial performance test based on the arithmetic average of the hourly emissions data during each steam generating unit operating day if a CEMS is used, or based on a daily average if Method 6B of appendix A of this part or fuel sampling and analysis procedures under Method 19 of appendix A of this part are used.
              (e) The owner or operator of an affected facility subject to § 60.42b(d)(1) shall demonstrate the maximum design capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. This demonstration will be made during the initial performance test and a subsequent demonstration may be requested at any other time. If the 24-hour average firing rate for the affected facility is less than the maximum design capacity provided by the manufacturer of the affected facility, the 24-hour average firing rate shall be used to determine the capacity utilization rate for the affected facility, otherwise the maximum design capacity provided by the manufacturer is used.

              (f) For the initial performance test required under § 60.8, compliance with the SO2 emission limits and percent reduction requirements under § 60.42b is based on the average emission rates and the average percent reduction for SO2 for the first 30 consecutive steam generating unit operating days, except as provided under paragraph (d) of this section. The initial performance test is the only test for which at least 30 days prior notice is required unless otherwise specified by the Administrator. The initial performance test is to be scheduled so that the first steam generating unit operating day of the 30 successive steam generating unit operating days is completed within 30 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility. The boiler load during the 30-day period does not have to be the maximum design load, but must be representative of future operating conditions and include at least one 24-hour period at full load.

              (g) After the initial performance test required under § 60.8, compliance with the SO2 emission limits and percent reduction requirements under § 60.42b is based on the average emission rates and the average percent reduction for SO2 for 30 successive steam generating unit operating days, except as provided under paragraph (d). A separate performance test is completed at the end of each steam generating unit operating day after the initial performance test, and a new 30-day average emission rate and percent reduction for SO2 are calculated to show compliance with the standard.

              (h) Except as provided under paragraph (i) of this section, the owner or operator of an affected facility shall use all valid SO2 emissions data in calculating %Ps and Eho under paragraph (c), of this section whether or not the minimum emissions data requirements under § 60.46b are achieved. All valid emissions data, including valid SO2 emission data collected during periods of startup, shutdown and malfunction, shall be used in calculating %Ps and Eho pursuant to paragraph (c) of this section.

              (i) During periods of malfunction or maintenance of the SO2 control systems when oil is combusted as provided under § 60.42b(i), emission data are not used to calculate %Ps or Es under § 60.42b(a), (b) or (c), however, the emissions data are used to determine compliance with the emission limit under § 60.42b(i).

              (j) The owner or operator of an affected facility that only combusts very low sulfur oil, natural gas, or a mixture of these fuels with any other fuels not subject to an SO2 standard is not subject to the compliance and performance testing requirements of this section if the owner or operator obtains fuel receipts as described in § 60.49b(r).
              (k) The owner or operator of an affected facility seeking to demonstrate compliance in §§ 60.42b(d)(4), 60.42b(j), 60.42b(k)(2), and 60.42b(k)(3) (when not burning coal) shall follow the applicable procedures in § 60.49b(r).
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009]

              § 60.46b
              Compliance and performance test methods and procedures for particulate matter and nitrogen oxides.

              (a) The PM emission standards and opacity limits under § 60.43b apply at all times except during periods of startup, shutdown, or malfunction. The NOX emission standards under § 60.44b apply at all times.
              (b) Compliance with the PM emission standards under § 60.43b shall be determined through performance testing as described in paragraph (d) of this section, except as provided in paragraph (i) of this section.
              (c) Compliance with the NOX emission standards under § 60.44b shall be determined through performance testing under paragraph (e) or (f), or under paragraphs (g) and (h) of this section, as applicable.
              (d) To determine compliance with the PM emission limits and opacity limits under § 60.43b, the owner or operator of an affected facility shall conduct an initial performance test as required under § 60.8, and shall conduct subsequent performance tests as requested by the Administrator, using the following procedures and reference methods:
              (1) Method 3A or 3B of appendix A-2 of this part is used for gas analysis when applying Method 5 of appendix A-3 of this part or Method 17 of appendix A-6 of this part.
              (2) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as follows:
              (i) Method 5 of appendix A of this part shall be used at affected facilities without wet flue gas desulfurization (FGD) systems; and
              (ii) Method 17 of appendix A-6 of this part may be used at facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of this part may be used in Method 17 of appendix A-6 of this part only if it is used after a wet FGD system. Do not use Method 17 of appendix A-6 of this part after wet FGD systems if the effluent is saturated or laden with water droplets.
              (iii) Method 5B of appendix A of this part is to be used only after wet FGD systems.
              (3) Method 1 of appendix A of this part is used to select the sampling site and the number of traverse sampling points. The sampling time for each run is at least 120 minutes and the minimum sampling volume is 1.7 dscm (60 dscf) except that smaller sampling times or volumes may be approved by the Administrator when necessitated by process variables or other factors.
              (4) For Method 5 of appendix A of this part, the temperature of the sample gas in the probe and filter holder is monitored and is maintained at 160±14 °C (320±25 °F).
              (5) For determination of PM emissions, the oxygen (O2) or CO2 sample is obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling location.
              (6) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rate expressed in ng/J heat input is determined using:
              (i) The O2 or CO2 measurements and PM measurements obtained under this section;
              (ii) The dry basis F factor; and
              (iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this part.
              (7) Method 9 of appendix A of this part is used for determining the opacity of stack emissions.

              (e) To determine compliance with the emission limits for NOX required under § 60.44b, the owner or operator of an affected facility shall conduct the performance test as required under § 60.8 using the continuous system for monitoring NOX under § 60.48(b).
              (1) For the initial compliance test, NOX from the steam generating unit are monitored for 30 successive steam generating unit operating days and the 30-day average emission rate is used to determine compliance with the NOX emission standards under § 60.44b. The 30-day average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 30-day test period.

              (2) Following the date on which the initial performance test is completed or is required to be completed in § 60.8, whichever date comes first, the owner or operator of an affected facility which combusts coal (except as specified under § 60.46b(e)(4)) or which combusts residual oil having a nitrogen content greater than 0.30 weight percent shall determine compliance with the NOX emission standards in § 60.44b on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated for each steam generating unit operating day as the average of all of the hourly NOX emission data for the preceding 30 steam generating unit operating days.

              (3) Following the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility that has a heat input capacity greater than 73 MW (250 MMBtu/hr) and that combusts natural gas, distillate oil, or residual oil having a nitrogen content of 0.30 weight percent or less shall determine compliance with the NOX standards under § 60.44b on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NOX emission data for the preceding 30 steam generating unit operating days.

              (4) Following the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility that has a heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts natural gas, distillate oil, gasified coal, or residual oil having a nitrogen content of 0.30 weight percent or less shall upon request determine compliance with the NOX standards in § 60.44b through the use of a 30-day performance test. During periods when performance tests are not requested, NOX emissions data collected pursuant to § 60.48b(g)(1) or § 60.48b(g)(2) are used to calculate a 30-day rolling average emission rate on a daily basis and used to prepare excess emission reports, but will not be used to determine compliance with the NOX emission standards. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NOX emission data for the preceding 30 steam generating unit operating days.
              (5) If the owner or operator of an affected facility that combusts residual oil does not sample and analyze the residual oil for nitrogen content, as specified in § 60.49b(e), the requirements of § 60.48b(g)(1) apply and the provisions of § 60.48b(g)(2) are inapplicable.

              (f) To determine compliance with the emissions limits for NOX required by § 60.44b(a)(4) or § 60.44b(l) for duct burners used in combined cycle systems, either of the procedures described in paragraph (f)(1) or (2) of this section may be used:
              (1) The owner or operator of an affected facility shall conduct the performance test required under § 60.8 as follows:
              (i) The emissions rate (E) of NOX shall be computed using Equation 1 in this section:

                ER13JN07.031

                Where:

                E = Emissions rate of NOX from the duct burner, ng/J (lb/MMBtu) heat input;
                Esg = Combined effluent emissions rate, in ng/J (lb/MMBtu) heat input using appropriate F factor as described in Method 19 of appendix A of this part;
                Hg = Heat input rate to the combustion turbine, in J/hr (MMBtu/hr);
                Hb = Heat input rate to the duct burner, in J/hr (MMBtu/hr); and
                Eg = Emissions rate from the combustion turbine, in ng/J (lb/MMBtu) heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part.

              (ii) Method 7E of appendix A of this part or Method 320 of appendix A of part 63 shall be used to determine the NOX concentrations. Method 3A or 3B of appendix A of this part shall be used to determine O2 concentration.

              (iii) The owner or operator shall identify and demonstrate to the Administrator's satisfaction suitable methods to determine the average hourly heat input rate to the combustion turbine and the average hourly heat input rate to the affected duct burner.

              (iv) Compliance with the emissions limits under § 60.44b(a)(4) or § 60.44b(l) is determined by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests; or

              (2) The owner or operator of an affected facility may elect to determine compliance on a 30-day rolling average basis by using the CEMS specified under § 60.48b for measuring NOX and O2 and meet the requirements of § 60.48b. The sampling site shall be located at the outlet from the steam generating unit. The NOX emissions rate at the outlet from the steam generating unit shall constitute the NOX emissions rate from the duct burner of the combined cycle system.

              (g) The owner or operator of an affected facility described in § 60.44b(j) or § 60.44b(k) shall demonstrate the maximum heat input capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. The owner or operator of an affected facility shall determine the maximum heat input capacity using the heat loss method or the heat input method described in sections 5 and 7.3 of the ASME Power Test Codes 4.1 (incorporated by reference, see § 60.17). This demonstration of maximum heat input capacity shall be made during the initial performance test for affected facilities that meet the criteria of § 60.44b(j). It shall be made within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial start-up of each facility, for affected facilities meeting the criteria of § 60.44b(k). Subsequent demonstrations may be required by the Administrator at any other time. If this demonstration indicates that the maximum heat input capacity of the affected facility is less than that stated by the manufacturer of the affected facility, the maximum heat input capacity determined during this demonstration shall be used to determine the capacity utilization rate for the affected facility. Otherwise, the maximum heat input capacity provided by the manufacturer is used.
              (h) The owner or operator of an affected facility described in § 60.44b(j) that has a heat input capacity greater than 73 MW (250 MMBtu/hr) shall:

              (1) Conduct an initial performance test as required under § 60.8 over a minimum of 24 consecutive steam generating unit operating hours at maximum heat input capacity to demonstrate compliance with the NOX emission standards under § 60.44b using Method 7, 7A, or 7E of appendix A of this part, Method 320 of appendix A of part 63 of this chapter, or other approved reference methods; and

              (2) Conduct subsequent performance tests once per calendar year or every 400 hours of operation (whichever comes first) to demonstrate compliance with the NOX emission standards under § 60.44b over a minimum of 3 consecutive steam generating unit operating hours at maximum heat input capacity using Method 7, 7A, or 7E of appendix A of this part, Method 320 of appendix A of part 63, or other approved reference methods.
              (i) The owner or operator of an affected facility seeking to demonstrate compliance with the PM limit in paragraphs § 60.43b(a)(4) or § 60.43b(h)(5) shall follow the applicable procedures in § 60.49b(r).
              (j) In place of PM testing with Method 5 or 5B of appendix A-3 of this part, or Method 17 of appendix A-6 of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for monitoring PM emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who elects to continuously monitor PM emissions instead of conducting performance testing using Method 5 or 5B of appendix A-3 of this part or Method 17 of appendix A-6 of this part shall comply with the requirements specified in paragraphs (j)(1) through (j)(14) of this section.
              (1) Notify the Administrator one month before starting use of the system.
              (2) Notify the Administrator one month before stopping use of the system.
              (3) The monitor shall be installed, evaluated, and operated in accordance with § 60.13 of subpart A of this part.

              (4) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of the CEMS if the owner or operator was previously determining compliance by Method 5, 5B, or 17 of appendix A of this part performance tests, whichever is later.
              (5) The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required under § 60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS specified in paragraph (j) of this section to measure PM and calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19 of appendix A of this part, section 4.1.
              (6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emission concentrations using CEMS outlet data.
              (7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraphs (j)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average.
              (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
              (ii) [Reserved]
              (8) The 1-hour arithmetic averages required under paragraph (j)(7) of this section shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
              (9) All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(7) of this section are not met.
              (10) The CEMS shall be operated according to Performance Specification 11 in appendix B of this part.

              (11) During the correlation testing runs of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O2 (or CO2) data shall be collected concurrently (or within a 30-to 60-minute period) by both the continuous emission monitors and performance tests conducted using the following test methods.
              (i) For PM, Method 5 or 5B of appendix A-3 of this part or Method 17 of appendix A-6 of this part shall be used; and
              (ii) For O2 (or CO2), Method 3A or 3B of appendix A-2 of this part, as applicable shall be used.
              (12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years.
              (13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours per 30-day rolling average.

              (14) As of January 1, 2012, and within 90 days after the date of completing each performance test, as defined in § 60.8, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert /ert__tool.html/) or other compatible electronic spreadsheet. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically into EPA's WebFIRE database.
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9460, Feb. 16, 2012; 79 FR 11249, Feb. 27, 2014]

              § 60.47b
              Emission monitoring for sulfur dioxide.

              (a) Except as provided in paragraphs (b) and (f) of this section, the owner or operator of an affected facility subject to the SO2 standards in § 60.42b shall install, calibrate, maintain, and operate CEMS for measuring SO2 concentrations and either O2 or CO2 concentrations and shall record the output of the systems. For units complying with the percent reduction standard, the SO2 and either O2 or CO2 concentrations shall both be monitored at the inlet and outlet of the SO2 control device. If the owner or operator has installed and certified SO2 and O2 or CO2 CEMS according to the requirements of § 75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of § 75.21 of this chapter and appendix B to part 75 of this chapter, those CEMS may be used to meet the requirements of this section, provided that:
              (1) When relative accuracy testing is conducted, SO2 concentration data and CO2 (or O2) data are collected simultaneously; and
              (2) In addition to meeting the applicable SO2 and CO2 (or O2) relative accuracy specifications in Figure 2 of appendix B to part 75 of this chapter, the relative accuracy (RA) standard in section 13.2 of Performance Specification 2 in appendix B to this part is met when the RA is calculated on a lb/MMBtu basis; and

              (3) The reporting requirements of § 60.49b are met. SO2 and CO2 (or O2) data used to meet the requirements of § 60.49b shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the SO2 data have been bias adjusted according to the procedures of part 75 of this chapter.

              (b) As an alternative to operating CEMS as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO2 emissions and percent reduction by:

              (1) Collecting coal or oil samples in an as-fired condition at the inlet to the steam generating unit and analyzing them for sulfur and heat content according to Method 19 of appendix A of this part. Method 19 of appendix A of this part provides procedures for converting these measurements into the format to be used in calculating the average SO2 input rate, or
              (2) Measuring SO2 according to Method 6B of appendix A of this part at the inlet or outlet to the SO2 control system. An initial stratification test is required to verify the adequacy of the sampling location for Method 6B of appendix A of this part. The stratification test shall consist of three paired runs of a suitable SO2 and CO2 measurement train operated at the candidate location and a second similar train operated according to the procedures in Section 3.2 and the applicable procedures in Section 7 of Performance Specification 2. Method 6B of appendix A of this part, Method 6A of appendix A of this part, or a combination of Methods 6 and 3 or 3B of appendix A of this part or Methods 6C or Method 320 of appendix A of part 63 of this chapter and 3A of appendix A of this part are suitable measurement techniques. If Method 6B of appendix A of this part is used for the second train, sampling time and timer operation may be adjusted for the stratification test as long as an adequate sample volume is collected; however, both sampling trains are to be operated similarly. For the location to be adequate for Method 6B of appendix A of this part, 24-hour tests, the mean of the absolute difference between the three paired runs must be less than 10 percent.
              (3) A daily SO2 emission rate, ED, shall be determined using the procedure described in Method 6A of appendix A of this part, section 7.6.2 (Equation 6A-8) and stated in ng/J (lb/MMBtu) heat input.
              (4) The mean 30-day emission rate is calculated using the daily measured values in ng/J (lb/MMBtu) for 30 successive steam generating unit operating days using equation 19-20 of Method 19 of appendix A of this part.

              (c) The owner or operator of an affected facility shall obtain emission data for at least 75 percent of the operating hours in at least 22 out of 30 successive boiler operating days. If this minimum data requirement is not met with a single monitoring system, the owner or operator of the affected facility shall supplement the emission data with data collected with other monitoring systems as approved by the Administrator or the reference methods and procedures as described in paragraph (b) of this section.
              (d) The 1-hour average SO2 emission rates measured by the CEMS required by paragraph (a) of this section and required under § 60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used to calculate the average emission rates under § 60.42(b). Each 1-hour average SO2 emission rate must be based on 30 or more minutes of steam generating unit operation. The hourly averages shall be calculated according to § 60.13(h)(2). Hourly SO2 emission rates are not calculated if the affected facility is operated less than 30 minutes in a given clock hour and are not counted toward determination of a steam generating unit operating day.
              (e) The procedures under § 60.13 shall be followed for installation, evaluation, and operation of the CEMS.
              (1) Except as provided for in paragraph (e)(4) of this section, all CEMS shall be operated in accordance with the applicable procedures under Performance Specifications 1, 2, and 3 of appendix B of this part.
              (2) Except as provided for in paragraph (e)(4) of this section, quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 of appendix F of this part.

              (3) For affected facilities combusting coal or oil, alone or in combination with other fuels, the span value of the SO2 CEMS at the inlet to the SO2 control device is 125 percent of the maximum estimated hourly potential SO2 emissions of the fuel combusted, and the span value of the CEMS at the outlet to the SO2 control device is 50 percent of the maximum estimated hourly potential SO2 emissions of the fuel combusted. Alternatively, SO2 span values determined according to section 2.1.1 in appendix A to part 75 of this chapter may be used.
              (4) As an alternative to meeting the requirements of requirements of paragraphs (e)(1) and (e)(2) of this section, the owner or operator may elect to implement the following alternative data accuracy assessment procedures:
              (i) For all required CO2 and O2 monitors and for SO2 and NOX monitors with span values greater than or equal to 100 ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F to this part.
              (ii) For all required CO2 and O2 monitors and for SO2 and NOX monitors with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits (CGAs) described in Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linearity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.2.4 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the cylinder gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for SO2 and NOX span values less than or equal to 30 ppm; and
              (iii) For SO2, CO2, and O2 monitoring systems and for NOX emission rate monitoring systems, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall be met on a lb/MMBtu basis for SO2 (regardless of the SO2 emission level during the RATA), and for NOX when the average NOX emission rate measured by the reference method during the RATA is less than 0.100 lb/MMBtu.
              (f) The owner or operator of an affected facility that combusts very low sulfur oil or is demonstrating compliance under § 60.45b(k) is not subject to the emission monitoring requirements under paragraph (a) of this section if the owner or operator maintains fuel records as described in § 60.49b(r).
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5087, Jan. 28, 2009; 79 FR 11249, Feb. 27, 2014]

              § 60.48b
              Emission monitoring for particulate matter and nitrogen oxides.
              (a) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility subject to the opacity standard under § 60.43b shall install, calibrate, maintain, and operate a continuous opacity monitoring systems (COMS) for measuring the opacity of emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility subject to an opacity standard under § 60.43b and meeting the conditions under paragraphs (j)(1), (2), (3), (4), (5), or (6) of this section who elects not to use a COMS shall conduct a performance test using Method 9 of appendix A-4 of this part and the procedures in § 60.11 to demonstrate compliance with the applicable limit in § 60.43b by April 29, 2011, within 45 days of stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this section. The observation period for Method 9 of appendix A-4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation.
              (1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A-4 of this part performance tests using the procedures in paragraph (a) of this section according to the applicable schedule in paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined by the most recent Method 9 of appendix A-4 of this part performance test results.
              (i) If no visible emissions are observed, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
              (ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 6 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
              (iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or
              (iv) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted.

              (2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A-4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A-4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A-7 of this part according to the procedures specified in paragraphs (a)(2)(i) and (ii) of this section.

              (i) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A-7 of this part and demonstrate that the sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation period (i.e., 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period (i.e., 90 seconds per 30 minute period), the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute observation (i.e., 90 seconds) or conduct a new Method 9 of appendix A-4 of this part performance test using the procedures in paragraph (a) of this section within 45 calendar days according to the requirements in § 60.46d(d)(7).
              (ii) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed.
              (3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A-4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A-4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily identical, to the requirements in paragraph (a)(2) of this section. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243-02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods.

              (b) Except as provided under paragraphs (g), (h), and (i) of this section, the owner or operator of an affected facility subject to a NOX standard under § 60.44b shall comply with either paragraphs (b)(1) or (b)(2) of this section.

              (1) Install, calibrate, maintain, and operate CEMS for measuring NOX and O2 (or CO2) emissions discharged to the atmosphere, and shall record the output of the system; or
              (2) If the owner or operator has installed a NOX emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this section, except that the owner or operator shall also meet the requirements of § 60.49b. Data reported to meet the requirements of § 60.49b shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
              (c) The CEMS required under paragraph (b) of this section shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments.
              (d) The 1-hour average NOX emission rates measured by the continuous NOX monitor required by paragraph (b) of this section and required under § 60.13(h) shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the average emission rates under § 60.44b. The 1-hour averages shall be calculated using the data points required under § 60.13(h)(2).

              (e) The procedures under § 60.13 shall be followed for installation, evaluation, and operation of the continuous monitoring systems.
              (1) For affected facilities combusting coal, wood or municipal-type solid waste, the span value for a COMS shall be between 60 and 80 percent.

              (2) For affected facilities combusting coal, oil, or natural gas, the span value for NOX is determined using one of the following procedures:

              (i) Except as provided under paragraph (e)(2)(ii) of this section, NOX span values shall be determined as follows:

                  Fuel
                  Span values for NOX
                    (ppm)

                  Natural gas
                  500.

                  Oil
                  500.

                  Coal
                  1,000.

                  Mixtures
                  500 (x + y) + 1,000z.

                Where:

                x = Fraction of total heat input derived from natural gas;
                y = Fraction of total heat input derived from oil; and
                z = Fraction of total heat input derived from coal.

              (ii) As an alternative to meeting the requirements of paragraph (e)(2)(i) of this section, the owner or operator of an affected facility may elect to use the NOX span values determined according to section 2.1.2 in appendix A to part 75 of this chapter.
              (3) All span values computed under paragraph (e)(2)(i) of this section for combusting mixtures of regulated fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (e)(2)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter.
              (f) When NOX emission data are not obtained because of CEMS breakdowns, repairs, calibration checks and zero and span adjustments, emission data will be obtained by using standby monitoring systems, Method 7 of appendix A of this part, Method 7A of appendix A of this part, or other approved reference methods to provide emission data for a minimum of 75 percent of the operating hours in each steam generating unit operating day, in at least 22 out of 30 successive steam generating unit operating days.
              (g) The owner or operator of an affected facility that has a heat input capacity of 73 MW (250 MMBtu/hr) or less, and that has an annual capacity factor for residual oil having a nitrogen content of 0.30 weight percent or less, natural gas, distillate oil, gasified coal, or any mixture of these fuels, greater than 10 percent (0.10) shall:
              (1) Comply with the provisions of paragraphs (b), (c), (d), (e)(2), (e)(3), and (f) of this section; or

              (2) Monitor steam generating unit operating conditions and predict NOX emission rates as specified in a plan submitted pursuant to § 60.49b(c).

              (h) The owner or operator of a duct burner, as described in § 60.41b, that is subject to the NOX standards in § 60.44b(a)(4), § 60.44b(e), or § 60.44b(l) is not required to install or operate a continuous emissions monitoring system to measure NOX emissions.

              (i) The owner or operator of an affected facility described in § 60.44b(j) or § 60.44b(k) is not required to install or operate a CEMS for measuring NOX emissions.
              (j) The owner or operator of an affected facility that meets the conditions in either paragraph (j)(1), (2), (3), (4), (5), (6), or (7) of this section is not required to install or operate a COMS if:
              (1) The affected facility uses a PM CEMS to monitor PM emissions; or

              (2) The affected facility burns only liquid (excluding residual oil) or gaseous fuels with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion technology to reduce SO2 or PM emissions. The owner or operator must maintain fuel records of the sulfur content of the fuels burned, as described under § 60.49b(r); or

              (3) The affected facility burns coke oven gas alone or in combination with fuels meeting the criteria in paragraph (j)(2) of this section and does not use a post-combustion technology to reduce SO2 or PM emissions; or

              (4) The affected facility does not use post-combustion technology (except a wet scrubber) for reducing PM, SO2, or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a steam generating unit operating day average basis. Owners and operators of affected facilities electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (j)(4)(i) through (iv) of this section; or
              (i) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (j)(4)(i)(A) through (D) of this section.
              (A) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part.
              (B) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
              (C) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data points required in § 60.13(h)(2).
              (D) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.
              (ii) You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each steam generating unit operating day.
              (iii) You must evaluate the preceding 24-hour average CO emission level each steam generating unit operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less.
              (iv) You must record the CO measurements and calculations performed according to paragraph (j)(4) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the corrective action.
              (5) The affected facility uses a bag leak detection system to monitor the performance of a fabric filter (baghouse) according to the most current requirements in section § 60.48Da of this part; or
              (6) The affected facility uses an ESP as the primary PM control device and uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section § 60.48Da of this part; or
              (7) The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur and operates according to a written site-specific monitoring plan approved by the permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard.
              (k) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere as specified in § 60.46b(j). The CEMS specified in paragraph § 60.46b(j) shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments.

              (l) An owner or operator of an affected facility that is subject to an opacity standard under § 60.43b(f) is not required to operate a COMS provided that the unit burns only gaseous fuels and/or liquid fuels (excluding residue oil) with a potential SO2 emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit operates according to a written site-specific monitoring plan approved by the permitting authority is not required to operate a COMS. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard. For testing performed as part of this site-specific monitoring plan, the permitting authority may require as an alternative to the notification and reporting requirements specified in §§ 60.8 and 60.11 that the owner or operator submit any deviations with the excess emissions report required under § 60.49b(h).
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5087, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9460, Feb. 16, 2012]

              § 60.49b
              Reporting and recordkeeping requirements.
              (a) The owner or operator of each affected facility shall submit notification of the date of initial startup, as provided by § 60.7. This notification shall include:
              (1) The design heat input capacity of the affected facility and identification of the fuels to be combusted in the affected facility;
              (2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under § 60.42b(d)(1), § 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii), (d)(2)(iii), § 60.44b(c), (d), (e), (i), (j), (k), § 60.45b(d), (g), § 60.46b(h), or § 60.48b(i);
              (3) The annual capacity factor at which the owner or operator anticipates operating the facility based on all fuels fired and based on each individual fuel fired; and

              (4) Notification that an emerging technology will be used for controlling emissions of SO2. The Administrator will examine the description of the emerging technology and will determine whether the technology qualifies as an emerging technology. In making this determination, the Administrator may require the owner or operator of the affected facility to submit additional information concerning the control device. The affected facility is subject to the provisions of § 60.42b(a) unless and until this determination is made by the Administrator.

              (b) The owner or operator of each affected facility subject to the SO2, PM, and/or NOX emission limits under §§ 60.42b, 60.43b, and 60.44b shall submit to the Administrator the performance test data from the initial performance test and the performance evaluation of the CEMS using the applicable performance specifications in appendix B of this part. The owner or operator of each affected facility described in § 60.44b(j) or § 60.44b(k) shall submit to the Administrator the maximum heat input capacity data from the demonstration of the maximum heat input capacity of the affected facility.

              (c) The owner or operator of each affected facility subject to the NOX standard in § 60.44b who seeks to demonstrate compliance with those standards through the monitoring of steam generating unit operating conditions in the provisions of § 60.48b(g)(2) shall submit to the Administrator for approval a plan that identifies the operating conditions to be monitored in § 60.48b(g)(2) and the records to be maintained in § 60.49b(g). This plan shall be submitted to the Administrator for approval within 360 days of the initial startup of the affected facility. An affected facility burning coke oven gas alone or in combination with other gaseous fuels or distillate oil shall submit this plan to the Administrator for approval within 360 days of the initial startup of the affected facility or by November 30, 2009, whichever date comes later. If the plan is approved, the owner or operator shall maintain records of predicted nitrogen oxide emission rates and the monitored operating conditions, including steam generating unit load, identified in the plan. The plan shall:

              (1) Identify the specific operating conditions to be monitored and the relationship between these operating conditions and NOX emission rates (i.e., ng/J or lbs/MMBtu heat input). Steam generating unit operating conditions include, but are not limited to, the degree of staged combustion (i.e., the ratio of primary air to secondary and/or tertiary air) and the level of excess air (i.e., flue gas O2 level);

              (2) Include the data and information that the owner or operator used to identify the relationship between NOX emission rates and these operating conditions; and
              (3) Identify how these operating conditions, including steam generating unit load, will be monitored under § 60.48b(g) on an hourly basis by the owner or operator during the period of operation of the affected facility; the quality assurance procedures or practices that will be employed to ensure that the data generated by monitoring these operating conditions will be representative and accurate; and the type and format of the records of these operating conditions, including steam generating unit load, that will be maintained by the owner or operator under § 60.49b(g).
              (d) Except as provided in paragraph (d)(2) of this section, the owner or operator of an affected facility shall record and maintain records as specified in paragraph (d)(1) of this section.
              (1) The owner or operator of an affected facility shall record and maintain records of the amounts of each fuel combusted during each day and calculate the annual capacity factor individually for coal, distillate oil, residual oil, natural gas, wood, and municipal-type solid waste for the reporting period. The annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of each calendar month.
              (2) As an alternative to meeting the requirements of paragraph (d)(1) of this section, the owner or operator of an affected facility that is subject to a federally enforceable permit restricting fuel use to a single fuel such that the facility is not required to continuously monitor any emissions (excluding opacity) or parameters indicative of emissions may elect to record and maintain records of the amount of each fuel combusted during each calendar month.
              (e) For an affected facility that combusts residual oil and meets the criteria under § 60.46b(e)(4), § 60.44b(j), or (k), the owner or operator shall maintain records of the nitrogen content of the residual oil combusted in the affected facility and calculate the average fuel nitrogen content for the reporting period. The nitrogen content shall be determined using ASTM Method D4629 (incorporated by reference, see § 60.17), or fuel suppliers. If residual oil blends are being combusted, fuel nitrogen specifications may be prorated based on the ratio of residual oils of different nitrogen content in the fuel blend.
              (f) For an affected facility subject to the opacity standard in § 60.43b, the owner or operator shall maintain records of opacity. In addition, an owner or operator that elects to monitor emissions according to the requirements in § 60.48b(a) shall maintain records according to the requirements specified in paragraphs (f)(1) through (3) of this section, as applicable to the visible emissions monitoring method used.
              (1) For each performance test conducted using Method 9 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (f)(1)(i) through (iii) of this section.
              (i) Dates and time intervals of all opacity observation periods;
              (ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and
              (iii) Copies of all visible emission observer opacity field data sheets;
              (2) For each performance test conducted using Method 22 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (f)(2)(i) through (iv) of this section.
              (i) Dates and time intervals of all visible emissions observation periods;
              (ii) Name and affiliation for each visible emission observer participating in the performance test;
              (iii) Copies of all visible emission observer opacity field data sheets; and

              (iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements.
              (3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the Administrator.

              (g) Except as provided under paragraph (p) of this section, the owner or operator of an affected facility subject to the NOX standards under § 60.44b shall maintain records of the following information for each steam generating unit operating day:
              (1) Calendar date;
              (2) The average hourly NOX emission rates (expressed as NO2) (ng/J or lb/MMBtu heat input) measured or predicted;
              (3) The 30-day average NOX emission rates (ng/J or lb/MMBtu heat input) calculated at the end of each steam generating unit operating day from the measured or predicted hourly nitrogen oxide emission rates for the preceding 30 steam generating unit operating days;

              (4) Identification of the steam generating unit operating days when the calculated 30-day average NOX emission rates are in excess of the NOX emissions standards under § 60.44b, with the reasons for such excess emissions as well as a description of corrective actions taken;
              (5) Identification of the steam generating unit operating days for which pollutant data have not been obtained, including reasons for not obtaining sufficient data and a description of corrective actions taken;
              (6) Identification of the times when emission data have been excluded from the calculation of average emission rates and the reasons for excluding data;
              (7) Identification of “F” factor used for calculations, method of determination, and type of fuel combusted;
              (8) Identification of the times when the pollutant concentration exceeded full span of the CEMS;
              (9) Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specification 2 or 3; and
              (10) Results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 1 of this part.
              (h) The owner or operator of any affected facility in any category listed in paragraphs (h)(1) or (2) of this section is required to submit excess emission reports for any excess emissions that occurred during the reporting period.
              (1) Any affected facility subject to the opacity standards in § 60.43b(f) or to the operating parameter monitoring requirements in § 60.13(i)(1).
              (2) Any affected facility that is subject to the NOX standard of § 60.44b, and that:
              (i) Combusts natural gas, distillate oil, gasified coal, or residual oil with a nitrogen content of 0.3 weight percent or less; or

              (ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and is required to monitor NOX emissions on a continuous basis under § 60.48b(g)(1) or steam generating unit operating conditions under § 60.48b(g)(2).
              (3) For the purpose of § 60.43b, excess emissions are defined as all 6-minute periods during which the average opacity exceeds the opacity standards under § 60.43b(f).

              (4) For purposes of § 60.48b(g)(1), excess emissions are defined as any calculated 30-day rolling average NOX emission rate, as determined under § 60.46b(e), that exceeds the applicable emission limits in § 60.44b.

              (i) The owner or operator of any affected facility subject to the continuous monitoring requirements for NOX under § 60.48(b) shall submit reports containing the information recorded under paragraph (g) of this section.

              (j) The owner or operator of any affected facility subject to the SO2 standards under § 60.42b shall submit reports.
              (k) For each affected facility subject to the compliance and performance testing requirements of § 60.45b and the reporting requirement in paragraph (j) of this section, the following information shall be reported to the Administrator:
              (1) Calendar dates covered in the reporting period;
              (2) Each 30-day average SO2 emission rate (ng/J or lb/MMBtu heat input) measured during the reporting period, ending with the last 30-day period; reasons for noncompliance with the emission standards; and a description of corrective actions taken; For an exceedance due to maintenance of the SO2 control system covered in paragraph 60.45b(a), the report shall identify the days on which the maintenance was performed and a description of the maintenance;
              (3) Each 30-day average percent reduction in SO2 emissions calculated during the reporting period, ending with the last 30-day period; reasons for noncompliance with the emission standards; and a description of corrective actions taken;

              (4) Identification of the steam generating unit operating days that coal or oil was combusted and for which SO2 or diluent (O2 or CO2) data have not been obtained by an approved method for at least 75 percent of the operating hours in the steam generating unit operating day; justification for not obtaining sufficient data; and description of corrective action taken;
              (5) Identification of the times when emissions data have been excluded from the calculation of average emission rates; justification for excluding data; and description of corrective action taken if data have been excluded for periods other than those during which coal or oil were not combusted in the steam generating unit;
              (6) Identification of “F” factor used for calculations, method of determination, and type of fuel combusted;
              (7) Identification of times when hourly averages have been obtained based on manual sampling methods;
              (8) Identification of the times when the pollutant concentration exceeded full span of the CEMS;
              (9) Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specification 2 or 3;
              (10) Results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 1 of this part; and
              (11) The annual capacity factor of each fired as provided under paragraph (d) of this section.
              (l) For each affected facility subject to the compliance and performance testing requirements of § 60.45b(d) and the reporting requirements of paragraph (j) of this section, the following information shall be reported to the Administrator:
              (1) Calendar dates when the facility was in operation during the reporting period;
              (2) The 24-hour average SO2 emission rate measured for each steam generating unit operating day during the reporting period that coal or oil was combusted, ending in the last 24-hour period in the quarter; reasons for noncompliance with the emission standards; and a description of corrective actions taken;

              (3) Identification of the steam generating unit operating days that coal or oil was combusted for which S02 or diluent (O2 or CO2) data have not been obtained by an approved method for at least 75 percent of the operating hours; justification for not obtaining sufficient data; and description of corrective action taken;
              (4) Identification of the times when emissions data have been excluded from the calculation of average emission rates; justification for excluding data; and description of corrective action taken if data have been excluded for periods other than those during which coal or oil were not combusted in the steam generating unit;
              (5) Identification of “F” factor used for calculations, method of determination, and type of fuel combusted;
              (6) Identification of times when hourly averages have been obtained based on manual sampling methods;
              (7) Identification of the times when the pollutant concentration exceeded full span of the CEMS;
              (8) Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specification 2 or 3; and

              (9) Results of daily CEMS drift tests and quarterly accuracy assessments as required under Procedure 1 of appendix F 1 of this part. If the owner or operator elects to implement the alternative data assessment procedures described in §§ 60.47b(e)(4)(i) through (e)(4)(iii), each data assessment report shall include a summary of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift assessments required by §§ 60.47b(e)(4)(i) through (e)(4)(iii).
              (m) For each affected facility subject to the SO2 standards in § 60.42(b) for which the minimum amount of data required in § 60.47b(c) were not obtained during the reporting period, the following information is reported to the Administrator in addition to that required under paragraph (k) of this section:
              (1) The number of hourly averages available for outlet emission rates and inlet emission rates;
              (2) The standard deviation of hourly averages for outlet emission rates and inlet emission rates, as determined in Method 19 of appendix A of this part, section 7;
              (3) The lower confidence limit for the mean outlet emission rate and the upper confidence limit for the mean inlet emission rate, as calculated in Method 19 of appendix A of this part, section 7; and
              (4) The ratio of the lower confidence limit for the mean outlet emission rate and the allowable emission rate, as determined in Method 19 of appendix A of this part, section 7.

              (n) If a percent removal efficiency by fuel pretreatment (i.e., %Rf) is used to determine the overall percent reduction (i.e., %Ro) under § 60.45b, the owner or operator of the affected facility shall submit a signed statement with the report.

              (1) Indicating what removal efficiency by fuel pretreatment (i.e., %Rf) was credited during the reporting period;
              (2) Listing the quantity, heat content, and date each pre-treated fuel shipment was received during the reporting period, the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels received at the affected facility during the reporting period;
              (3) Documenting the transport of the fuel from the fuel pretreatment facility to the steam generating unit; and
              (4) Including a signed statement from the owner or operator of the fuel pretreatment facility certifying that the percent removal efficiency achieved by fuel pretreatment was determined in accordance with the provisions of Method 19 of appendix A of this part and listing the heat content and sulfur content of each fuel before and after fuel pretreatment.
              (o) All records required under this section shall be maintained by the owner or operator of the affected facility for a period of 2 years following the date of such record.
              (p) The owner or operator of an affected facility described in § 60.44b(j) or (k) shall maintain records of the following information for each steam generating unit operating day:
              (1) Calendar date;
              (2) The number of hours of operation; and
              (3) A record of the hourly steam load.
              (q) The owner or operator of an affected facility described in § 60.44b(j) or § 60.44b(k) shall submit to the Administrator a report containing:
              (1) The annual capacity factor over the previous 12 months;
              (2) The average fuel nitrogen content during the reporting period, if residual oil was fired; and

              (3) If the affected facility meets the criteria described in § 60.44b(j), the results of any NOX emission tests required during the reporting period, the hours of operation during the reporting period, and the hours of operation since the last NOX emission test.
              (r) The owner or operator of an affected facility who elects to use the fuel based compliance alternatives in § 60.42b or § 60.43b shall either:

              (1) The owner or operator of an affected facility who elects to demonstrate that the affected facility combusts only very low sulfur oil, natural gas, wood, a mixture of these fuels, or any of these fuels (or a mixture of these fuels) in combination with other fuels that are known to contain an insignificant amount of sulfur in § 60.42b(j) or § 60.42b(k) shall obtain and maintain at the affected facility fuel receipts (such as a current, valid purchase contract, tariff sheet, or transportation contract) from the fuel supplier that certify that the oil meets the definition of distillate oil and gaseous fuel meets the definition of natural gas as defined in § 60.41b and the applicable sulfur limit. For the purposes of this section, the distillate oil need not meet the fuel nitrogen content specification in the definition of distillate oil. Reports shall be submitted to the Administrator certifying that only very low sulfur oil meeting this definition, natural gas, wood, and/or other fuels that are known to contain insignificant amounts of sulfur were combusted in the affected facility during the reporting period; or
              (2) The owner or operator of an affected facility who elects to demonstrate compliance based on fuel analysis in § 60.42b or § 60.43b shall develop and submit a site-specific fuel analysis plan to the Administrator for review and approval no later than 60 days before the date you intend to demonstrate compliance. Each fuel analysis plan shall include a minimum initial requirement of weekly testing and each analysis report shall contain, at a minimum, the following information:
              (i) The potential sulfur emissions rate of the representative fuel mixture in ng/J heat input;
              (ii) The method used to determine the potential sulfur emissions rate of each constituent of the mixture. For distillate oil and natural gas a fuel receipt or tariff sheet is acceptable;
              (iii) The ratio of different fuels in the mixture; and
              (iv) The owner or operator can petition the Administrator to approve monthly or quarterly sampling in place of weekly sampling.
              (s) Facility specific NOX standard for Cytec Industries Fortier Plant's C.AOG incinerator located in Westwego, Louisiana:
              (1) Definitions.

                Oxidation zone is defined as the portion of the C.AOG incinerator that extends from the inlet of the oxidizing zone combustion air to the outlet gas stack.

                Reducing zone is defined as the portion of the C.AOG incinerator that extends from the burner section to the inlet of the oxidizing zone combustion air.

                Total inlet air is defined as the total amount of air introduced into the C.AOG incinerator for combustion of natural gas and chemical by-product waste and is equal to the sum of the air flow into the reducing zone and the air flow into the oxidation zone.
              (2) Standard for nitrogen oxides. (i) When fossil fuel alone is combusted, the NOX emission limit for fossil fuel in § 60.44b(a) applies.

              (ii) When natural gas and chemical by-product waste are simultaneously combusted, the NOX emission limit is 289 ng/J (0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air provided for combustion shall be provided to the reducing zone of the C.AOG incinerator.
              (3) Emission monitoring. (i) The percent of total inlet air provided to the reducing zone shall be determined at least every 15 minutes by measuring the air flow of all the air entering the reducing zone and the air flow of all the air entering the oxidation zone, and compliance with the percentage of total inlet air that is provided to the reducing zone shall be determined on a 3-hour average basis.
              (ii) The NOX emission limit shall be determined by the compliance and performance test methods and procedures for NOX in § 60.46b(i).
              (iii) The monitoring of the NOX emission limit shall be performed in accordance with § 60.48b.
              (4) Reporting and recordkeeping requirements. (i) The owner or operator of the C.AOG incinerator shall submit a report on any excursions from the limits required by paragraph (a)(2) of this section to the Administrator with the quarterly report required by paragraph (i) of this section.
              (ii) The owner or operator of the C.AOG incinerator shall keep records of the monitoring required by paragraph (a)(3) of this section for a period of 2 years following the date of such record.
              (iii) The owner of operator of the C.AOG incinerator shall perform all the applicable reporting and recordkeeping requirements of this section.
              (t) Facility-specific NOX standard for Rohm and Haas Kentucky Incorporated's Boiler No. 100 located in Louisville, Kentucky:
              (1) Definitions.

                Air ratio control damper is defined as the part of the low NOX burner that is adjusted to control the split of total combustion air delivered to the reducing and oxidation portions of the combustion flame.

                Flue gas recirculation line is defined as the part of Boiler No. 100 that recirculates a portion of the boiler flue gas back into the combustion air.
              (2) Standard for nitrogen oxides. (i) When fossil fuel alone is combusted, the NOX emission limit for fossil fuel in § 60.44b(a) applies.

              (ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the NOX emission limit is 473 ng/J (1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at a minimum of 5 inches (12.7 centimeters) out of the boiler, and the flue gas recirculation line shall be operated at a minimum of 10 percent open as indicated by its valve opening position indicator.
              (3) Emission monitoring for nitrogen oxides. (i) The air ratio control damper tee handle setting and the flue gas recirculation line valve opening position indicator setting shall be recorded during each 8-hour operating shift.
              (ii) The NOX emission limit shall be determined by the compliance and performance test methods and procedures for NOX in § 60.46b.
              (iii) The monitoring of the NOX emission limit shall be performed in accordance with § 60.48b.
              (4) Reporting and recordkeeping requirements. (i) The owner or operator of Boiler No. 100 shall submit a report on any excursions from the limits required by paragraph (b)(2) of this section to the Administrator with the quarterly report required by § 60.49b(i).
              (ii) The owner or operator of Boiler No. 100 shall keep records of the monitoring required by paragraph (b)(3) of this section for a period of 2 years following the date of such record.
              (iii) The owner of operator of Boiler No. 100 shall perform all the applicable reporting and recordkeeping requirements of § 60.49b.
              (u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia. (1) This paragraph (u) applies only to the pharmaceutical manufacturing facility, commonly referred to as the Stonewall Plant, located at Route 340 South, in Elkton, Virginia (“site”) and only to the natural gas-fired boilers installed as part of the powerhouse conversion required pursuant to 40 CFR 52.2454(g). The requirements of this paragraph shall apply, and the requirements of §§ 60.40b through 60.49b(t) shall not apply, to the natural gas-fired boilers installed pursuant to 40 CFR 52.2454(g).

              (i) The site shall equip the natural gas-fired boilers with low NOX technology.

              (ii) The site shall install, calibrate, maintain, and operate a continuous monitoring and recording system for measuring NOX emissions discharged to the atmosphere and opacity using a continuous emissions monitoring system or a predictive emissions monitoring system.
              (iii) Within 180 days of the completion of the powerhouse conversion, as required by 40 CFR 52.2454, the site shall perform a performance test to quantify criteria pollutant emissions.
              (2) [Reserved]

              (v) The owner or operator of an affected facility may submit electronic quarterly reports for SO2 and/or NOX and/or opacity in lieu of submitting the written reports required under paragraphs (h), (i), (j), (k) or (l) of this section. The format of each quarterly electronic report shall be coordinated with the permitting authority. The electronic report(s) shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a certification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period. Before submitting reports in the electronic format, the owner or operator shall coordinate with the permitting authority to obtain their agreement to submit reports in this alternative format.
              (w) The reporting period for the reports required under this subpart is each 6 month period. All reports shall be submitted to the Administrator and shall be postmarked by the 30th day following the end of the reporting period.
              (x) Facility-specific NOX standard for Weyerhaeuser Company's No. 2 Power Boiler located in New Bern, North Carolina:
              (1) Standard for nitrogen oxides. (i) When fossil fuel alone is combusted, the NOX emission limit for fossil fuel in § 60.44b(a) applies.

              (ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the NOX emission limit is 215 ng/J (0.5 lb/MMBtu).
              (2) Emission monitoring for nitrogen oxides. (i) The NOX emissions shall be determined by the compliance and performance test methods and procedures for NOX in § 60.46b.
              (ii) The monitoring of the NOX emissions shall be performed in accordance with § 60.48b.
              (3) Reporting and recordkeeping requirements. (i) The owner or operator of the No. 2 Power Boiler shall submit a report on any excursions from the limits required by paragraph (x)(2) of this section to the Administrator with the quarterly report required by § 60.49b(i).
              (ii) The owner or operator of the No. 2 Power Boiler shall keep records of the monitoring required by paragraph (x)(3) of this section for a period of 2 years following the date of such record.
              (iii) The owner or operator of the No. 2 Power Boiler shall perform all the applicable reporting and recordkeeping requirements of § 60.49b.
              (y) Facility-specific NOX standard for INEOS USA's AOGI located in Lima, Ohio:
              (1) Standard for NO
                X. (i) When fossil fuel alone is combusted, the NOX emission limit for fossil fuel in § 60.44b(a) applies.

              (ii) When fossil fuel and chemical byproduct/waste are simultaneously combusted, the NOX emission limit is 645 ng/J (1.5 lb/MMBtu).
              (2) Emission monitoring for NO
                X. (i) The NOX emissions shall be determined by the compliance and performance test methods and procedures for NOX in § 60.46b.
              (ii) The monitoring of the NOX emissions shall be performed in accordance with § 60.48b.
              (3) Reporting and recordkeeping requirements. (i) The owner or operator of the AOGI shall submit a report on any excursions from the limits required by paragraph (y)(2) of this section to the Administrator with the quarterly report required by paragraph (i) of this section.
              (ii) The owner or operator of the AOGI shall keep records of the monitoring required by paragraph (y)(3) of this section for a period of 2 years following the date of such record.
              (iii) The owner or operator of the AOGI shall perform all the applicable reporting and recordkeeping requirements of this section.
              [72 FR 32742, June 13, 2007, as amended at 74 FR 5089, Jan. 28, 2009; 77 FR 9461, Feb. 16, 2012]

            Subpart Dc—Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units

              Source:
              72 FR 32759, June 13, 2007, unless otherwise noted.

              § 60.40c
              Applicability and delegation of authority.
              (a) Except as provided in paragraphs (d), (e), (f), and (g) of this section, the affected facility to which this subpart applies is each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/h)) or less, but greater than or equal to 2.9 MW (10 MMBtu/h).
              (b) In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, § 60.48c(a)(4) shall be retained by the Administrator and not transferred to a State.

              (c) Steam generating units that meet the applicability requirements in paragraph (a) of this section are not subject to the sulfur dioxide (SO2) or particulate matter (PM) emission limits, performance testing requirements, or monitoring requirements under this subpart (§ 60.42c, § 60.43c, § 60.44c, § 60.45c, § 60.46c, or § 60.47c) during periods of combustion research, as defined in § 60.41c.
              (d) Any temporary change to an existing steam generating unit for the purpose of conducting combustion research is not considered a modification under § 60.14.
              (e) Affected facilities (i.e. heat recovery steam generators and fuel heaters) that are associated with stationary combustion turbines and meet the applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other heat recovery steam generators, fuel heaters, and other affected facilities that are capable of combusting more than or equal to 2.9 MW (10 MMBtu/h) heat input of fossil fuel but less than or equal to 29 MW (100 MMBtu/h) heat input of fossil fuel. If the heat recovery steam generator, fuel heater, or other affected facility is subject to this subpart, only emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. (The stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part.)
              (f) Any affected facility that meets the applicability requirements of and is subject to subpart AAAA or subpart CCCC of this part is not subject to this subpart.
              (g) Any facility that meets the applicability requirements and is subject to an EPA approved State or Federal section 111(d)/129 plan implementing subpart BBBB of this part is not subject to this subpart.

              (h) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja of this part are subject to the PM and NOX standards under this subpart and the SO2 standards under subpart J or subpart Ja of this part, as applicable.
              (i) Temporary boilers are not subject to this subpart.
              [72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009; 77 FR 9461, Feb. 16, 2012]

              § 60.41c
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air Act and in subpart A of this part.

                Annual capacity factor means the ratio between the actual heat input to a steam generating unit from an individual fuel or combination of fuels during a period of 12 consecutive calendar months and the potential heat input to the steam generating unit from all fuels had the steam generating unit been operated for 8,760 hours during that 12-month period at the maximum design heat input capacity. In the case of steam generating units that are rented or leased, the actual heat input shall be determined based on the combined heat input from all operations of the affected facility during a period of 12 consecutive calendar months.

                Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Coal-derived synthetic fuels derived from coal for the purposes of creating useful heat, including but not limited to solvent refined coal, gasified coal not meeting the definition of natural gas, coal-oil mixtures, and coal-water mixtures, are also included in this definition for the purposes of this subpart.

                Coal refuse means any by-product of coal mining or coal cleaning operations with an ash content greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000 Btu per pound (Btu/lb) on a dry basis.

                Combined cycle system means a system in which a separate source (such as a stationary gas turbine, internal combustion engine, or kiln) provides exhaust gas to a steam generating unit.

                Combustion research means the experimental firing of any fuel or combination of fuels in a steam generating unit for the purpose of conducting research and development of more efficient combustion or more effective prevention or control of air pollutant emissions from combustion, provided that, during these periods of research and development, the heat generated is not used for any purpose other than preheating combustion air for use by that steam generating unit (i.e., the heat generated is released to the atmosphere without being used for space heating, process heating, driving pumps, preheating combustion air for other units, generating electricity, or any other purpose).

                Conventional technology means wet flue gas desulfurization technology, dry flue gas desulfurization technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology.

                Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17), diesel fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17), kerosine, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17), biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17), or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17).

                Dry flue gas desulfurization technology means a SO2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline reagents used in dry flue gas desulfurization systems include, but are not limited to, lime and sodium compounds.

                Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source (such as a stationary gas turbine, internal combustion engine, kiln, etc.) to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a steam generating unit.

                Emerging technology means any SO2 control system that is not defined as a conventional technology under this section, and for which the owner or operator of the affected facility has received approval from the Administrator to operate as an emerging technology under § 60.48c(a)(4).

                Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24.

                Fluidized bed combustion technology means a device wherein fuel is distributed onto a bed (or series of beds) of limestone aggregate (or other sorbent materials) for combustion; and these materials are forced upward in the device by the flow of combustion air and the gaseous products of combustion. Fluidized bed combustion technology includes, but is not limited to, bubbling bed units and circulating bed units.

                Fuel pretreatment means a process that removes a portion of the sulfur in a fuel before combustion of the fuel in a steam generating unit.

                Heat input means heat derived from combustion of fuel in a steam generating unit and does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases from other sources (such as stationary gas turbines, internal combustion engines, and kilns).

                Heat transfer medium means any material that is used to transfer heat from one point to another point.

                Maximum design heat input capacity means the ability of a steam generating unit to combust a stated maximum amount of fuel (or combination of fuels) on a steady state basis as determined by the physical design and characteristics of the steam generating unit.

                Natural gas means:
              (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or
              (2) Liquefied petroleum (LP) gas, as defined by the American Society for Testing and Materials in ASTM D1835 (incorporated by reference, see § 60.17); or

              (3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot).

                Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands.

                Oil means crude oil or petroleum, or a liquid fuel derived from crude oil or petroleum, including distillate oil and residual oil.

                Potential sulfur dioxide emission rate means the theoretical SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems.

                Process heater means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst.

                Residual oil means crude oil, fuel oil that does not comply with the specifications under the definition of distillate oil, and all fuel oil numbers 4, 5, and 6, as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17).

                Steam generating unit means a device that combusts any fuel and produces steam or heats water or heats any heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term does not include process heaters as defined in this subpart.

                Steam generating unit operating day means a 24-hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period.

                Temporary boiler means a steam generating unit that combusts natural gas or distillate oil with a potential SO2 emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed to, and is capable of, being carried or moved from one location to another by means of, for example, wheels, skids, carrying handles, dollies, trailers, or platforms. A steam generating unit is not a temporary boiler if any one of the following conditions exists:
              (1) The equipment is attached to a foundation.
              (2) The steam generating unit or a replacement remains at a location for more than 180 consecutive days. Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar function will be included in calculating the consecutive time period.
              (3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year.
              (4) The equipment is moved from one location to another in an attempt to circumvent the residence time requirements of this definition.

                Wet flue gas desulfurization technology means an SO2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition includes devices where the liquid material is subsequently converted to another form. Alkaline reagents used in wet flue gas desulfurization systems include, but are not limited to, lime, limestone, and sodium compounds.

                Wet scrubber system means any emission control device that mixes an aqueous stream or slurry with the exhaust gases from a steam generating unit to control emissions of PM or SO2.

                Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including but not limited to sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues.
              [72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009; 77 FR 9461, Feb. 16, 2012]

              § 60.42c
              Standard for sulfur dioxide (SO2).

              (a) Except as provided in paragraphs (b), (c), and (e) of this section, on and after the date on which the performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility that combusts only coal shall neither: cause to be discharged into the atmosphere from the affected facility any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO2 emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases that contain SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected facility shall neither: cause to be discharged into the atmosphere from the affected facility any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO2 emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases that contain SO2 in excess of the emission limit is determined pursuant to paragraph (e)(2) of this section.
              (b) Except as provided in paragraphs (c) and (e) of this section, on and after the date on which the performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility that:
              (1) Combusts only coal refuse alone in a fluidized bed combustion steam generating unit shall neither:

              (i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO2 emission rate (80 percent reduction); nor

              (ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is fired with coal refuse, the affected facility subject to paragraph (a) of this section. If oil or any other fuel (except coal) is fired with coal refuse, the affected facility is subject to the 87 ng/J (0.20 lb/MMBtu) heat input SO2 emissions limit or the 90 percent SO2 reduction requirement specified in paragraph (a) of this section and the emission limit is determined pursuant to paragraph (e)(2) of this section.

              (2) Combusts only coal and that uses an emerging technology for the control of SO2 emissions shall neither:

              (i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of 50 percent (0.50) of the potential SO2 emission rate (50 percent reduction); nor

              (ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of 260 ng/J (0.60 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected facility is subject to the 50 percent SO2 reduction requirement specified in this paragraph and the emission limit determined pursuant to paragraph (e)(2) of this section.

              (c) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, alone or in combination with any other fuel, and is listed in paragraphs (c)(1), (2), (3), or (4) of this section shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of the emission limit determined pursuant to paragraph (e)(2) of this section. Percent reduction requirements are not applicable to affected facilities under paragraphs (c)(1), (2), (3), or (4).
              (1) Affected facilities that have a heat input capacity of 22 MW (75 MMBtu/h) or less;
              (2) Affected facilities that have an annual capacity for coal of 55 percent (0.55) or less and are subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for coal of 55 percent (0.55) or less.
              (3) Affected facilities located in a noncontinental area; or
              (4) Affected facilities that combust coal in a duct burner as part of a combined cycle system where 30 percent (0.30) or less of the heat entering the steam generating unit is from combustion of coal in the duct burner and 70 percent (0.70) or more of the heat entering the steam generating unit is from exhaust gases entering the duct burner.

              (d) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts oil shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of 215 ng/J (0.50 lb/MMBtu) heat input from oil; or, as an alternative, no owner or operator of an affected facility that combusts oil shall combust oil in the affected facility that contains greater than 0.5 weight percent sulfur. The percent reduction requirements are not applicable to affected facilities under this paragraph.

              (e) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, or coal and oil with any other fuel shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of the following:
              (1) The percent of potential SO2 emission rate or numerical SO2 emission rate required under paragraph (a) or (b)(2) of this section, as applicable, for any affected facility that
              (i) Combusts coal in combination with any other fuel;
              (ii) Has a heat input capacity greater than 22 MW (75 MMBtu/h); and
              (iii) Has an annual capacity factor for coal greater than 55 percent (0.55); and

              (2) The emission limit determined according to the following formula for any affected facility that combusts coal, oil, or coal and oil with any other fuel:

                ER28JA09.005

                Where:

                Es = SO2 emission limit, expressed in ng/J or lb/MMBtu heat input;
                Ka = 520 ng/J (1.2 lb/MMBtu);
                Kb = 260 ng/J (0.60 lb/MMBtu);
                Kc = 215 ng/J (0.50 lb/MMBtu);
                Ha = Heat input from the combustion of coal, except coal combusted in an affected facility subject to paragraph (b)(2) of this section, in Joules (J) [MMBtu];
                Hb = Heat input from the combustion of coal in an affected facility subject to paragraph (b)(2) of this section, in J (MMBtu); and
                Hc = Heat input from the combustion of oil, in J (MMBtu).

              (f) Reduction in the potential SO2 emission rate through fuel pretreatment is not credited toward the percent reduction requirement under paragraph (b)(2) of this section unless:

              (1) Fuel pretreatment results in a 50 percent (0.50) or greater reduction in the potential SO2 emission rate; and

              (2) Emissions from the pretreated fuel (without either combustion or post-combustion SO2 control) are equal to or less than the emission limits specified under paragraph (b)(2) of this section.
              (g) Except as provided in paragraph (h) of this section, compliance with the percent reduction requirements, fuel oil sulfur limits, and emission limits of this section shall be determined on a 30-day rolling average basis.
              (h) For affected facilities listed under paragraphs (h)(1), (2), (3), or (4) of this section, compliance with the emission limits or fuel oil sulfur limits under this section may be determined based on a certification from the fuel supplier, as described under § 60.48c(f), as applicable.
              (1) Distillate oil-fired affected facilities with heat input capacities between 2.9 and 29 MW (10 and 100 MMBtu/hr).
              (2) Residual oil-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
              (3) Coal-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
              (4) Other fuels-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
              (i) The SO2 emission limits, fuel oil sulfur limits, and percent reduction requirements under this section apply at all times, including periods of startup, shutdown, and malfunction.

              (j) For affected facilities located in noncontinental areas and affected facilities complying with the percent reduction standard, only the heat input supplied to the affected facility from the combustion of coal and oil is counted under this section. No credit is provided for the heat input to the affected facility from wood or other fuels or for heat derived from exhaust gases from other sources, such as stationary gas turbines, internal combustion engines, and kilns.
              [72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009; 77 FR 9462, Feb. 16, 2012]

              § 60.43c
              Standard for particulate matter (PM).
              (a) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal or combusts mixtures of coal with other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits:
              (1) 22 ng/J (0.051 lb/MMBtu) heat input if the affected facility combusts only coal, or combusts coal with other fuels and has an annual capacity factor for the other fuels of 10 percent (0.10) or less.
              (2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal with other fuels, has an annual capacity factor for the other fuels greater than 10 percent (0.10), and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor greater than 10 percent (0.10) for fuels other than coal.
              (b) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts wood or combusts mixtures of wood with other fuels (except coal) and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emissions limits:
              (1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood greater than 30 percent (0.30); or
              (2) 130 ng/J (0.30 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood of 30 percent (0.30) or less and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for wood of 30 percent (0.30) or less.
              (c) On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity. Owners and operators of an affected facility that elect to install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart and are subject to a federally enforceable PM limit of 0.030 lb/MMBtu or less are exempt from the opacity standard specified in this paragraph (c).
              (d) The PM and opacity standards under this section apply at all times, except during periods of startup, shutdown, or malfunction.
              (e)(1) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this section.

              (2) As an alternative to meeting the requirements of paragraph (e)(1) of this section, the owner or operator of an affected facility for which modification commenced after February 28, 2005, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of both:
              (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels; and
              (ii) 0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels.
              (3) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a heat input capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.

              (4) An owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts only oil that contains no more than 0.50 weight percent sulfur or a mixture of 0.50 weight percent sulfur oil with other fuels not subject to a PM standard under § 60.43c and not using a post-combustion technology (except a wet scrubber) to reduce PM or SO2 emissions is not subject to the PM limit in this section.
              [72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 77 FR 9462, Feb. 16, 2012]

              § 60.44c
              Compliance and performance test methods and procedures for sulfur dioxide.
              (a) Except as provided in paragraphs (g) and (h) of this section and § 60.8(b), performance tests required under § 60.8 shall be conducted following the procedures specified in paragraphs (b), (c), (d), (e), and (f) of this section, as applicable. Section 60.8(f) does not apply to this section. The 30-day notice required in § 60.8(d) applies only to the initial performance test unless otherwise specified by the Administrator.

              (b) The initial performance test required under § 60.8 shall be conducted over 30 consecutive operating days of the steam generating unit. Compliance with the percent reduction requirements and SO2 emission limits under § 60.42c shall be determined using a 30-day average. The first operating day included in the initial performance test shall be scheduled within 30 days after achieving the maximum production rate at which the affect facility will be operated, but not later than 180 days after the initial startup of the facility. The steam generating unit load during the 30-day period does not have to be the maximum design heat input capacity, but must be representative of future operating conditions.

              (c) After the initial performance test required under paragraph (b) of this section and § 60.8, compliance with the percent reduction requirements and SO2 emission limits under § 60.42c is based on the average percent reduction and the average SO2 emission rates for 30 consecutive steam generating unit operating days. A separate performance test is completed at the end of each steam generating unit operating day, and a new 30-day average percent reduction and SO2 emission rate are calculated to show compliance with the standard.

              (d) If only coal, only oil, or a mixture of coal and oil is combusted in an affected facility, the procedures in Method 19 of appendix A of this part are used to determine the hourly SO2 emission rate (Eho) and the 30-day average SO2 emission rate (Eao). The hourly averages used to compute the 30-day averages are obtained from the CEMS. Method 19 of appendix A of this part shall be used to calculate Eao when using daily fuel sampling or Method 6B of appendix A of this part.

              (e) If coal, oil, or coal and oil are combusted with other fuels:

              (1) An adjusted Eho (Ehoo) is used in Equation 19-19 of Method 19 of appendix A of this part to compute the adjusted Eao (Eaoo). The Ehoo is computed using the following formula:

                ER13JN07.033

                Where:

                Ehoo = Adjusted Eho, ng/J (lb/MMBtu);
                Eho = Hourly SO2 emission rate, ng/J (lb/MMBtu);
                Ew = SO2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Method 9 of appendix A of this part, ng/J (lb/MMBtu). The value Ew for each fuel lot is used for each hourly average during the time that the lot is being combusted. The owner or operator does not have to measure Ew if the owner or operator elects to assume Ew = 0.
                Xk = Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by applicable procedures in Method 19 of appendix A of this part.

              (2) The owner or operator of an affected facility that qualifies under the provisions of § 60.42c(c) or (d) (where percent reduction is not required) does not have to measure the parameters Ew or Xk if the owner or operator of the affected facility elects to measure emission rates of the coal or oil using the fuel sampling and analysis procedures under Method 19 of appendix A of this part.

              (f) Affected facilities subject to the percent reduction requirements under § 60.42c(a) or (b) shall determine compliance with the SO2 emission limits under § 60.42c pursuant to paragraphs (d) or (e) of this section, and shall determine compliance with the percent reduction requirements using the following procedures:

              (1) If only coal is combusted, the percent of potential SO2 emission rate is computed using the following formula:

                ER13JN07.034

                Where:

                %Ps = Potential SO2 emission rate, in percent;
                %Rg = SO2 removal efficiency of the control device as determined by Method 19 of appendix A of this part, in percent; and
                %Rf = SO2 removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, in percent.

              (2) If coal, oil, or coal and oil are combusted with other fuels, the same procedures required in paragraph (f)(1) of this section are used, except as provided for in the following:
              (i) To compute the %Ps, an adjusted %Rg (%Rgo) is computed from Eaoo from paragraph (e)(1) of this section and an adjusted average SO2 inlet rate (Eaio) using the following formula:

                ER13JN07.035

                Where:

                %Rgo = Adjusted %Rg, in percent;
                Eaoo = Adjusted Eao, ng/J (lb/MMBtu); and
                Eaio = Adjusted average SO2 inlet rate, ng/J (lb/MMBtu).

              (ii) To compute Eaio, an adjusted hourly SO2 inlet rate (Ehio) is used. The Ehio is computed using the following formula:

                ER13JN07.036

                Where:

                Ehio = Adjusted Ehi, ng/J (lb/MMBtu);
                Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu);
                Ew = SO2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The value Ew for each fuel lot is used for each hourly average during the time that the lot is being combusted. The owner or operator does not have to measure Ew if the owner or operator elects to assume Ew = 0; and
                Xk = Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by applicable procedures in Method 19 of appendix A of this part.

              (g) For oil-fired affected facilities where the owner or operator seeks to demonstrate compliance with the fuel oil sulfur limits under § 60.42c based on shipment fuel sampling, the initial performance test shall consist of sampling and analyzing the oil in the initial tank of oil to be fired in the steam generating unit to demonstrate that the oil contains 0.5 weight percent sulfur or less. Thereafter, the owner or operator of the affected facility shall sample the oil in the fuel tank after each new shipment of oil is received, as described under § 60.46c(d)(2).

              (h) For affected facilities subject to § 60.42c(h)(1), (2), or (3) where the owner or operator seeks to demonstrate compliance with the SO2 standards based on fuel supplier certification, the performance test shall consist of the certification from the fuel supplier, as described in § 60.48c(f), as applicable.

              (i) The owner or operator of an affected facility seeking to demonstrate compliance with the SO2 standards under § 60.42c(c)(2) shall demonstrate the maximum design heat input capacity of the steam generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial performance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall be used.

              (j) The owner or operator of an affected facility shall use all valid SO2 emissions data in calculating %Ps and Eho under paragraphs (d), (e), or (f) of this section, as applicable, whether or not the minimum emissions data requirements under § 60.46c(f) are achieved. All valid emissions data, including valid data collected during periods of startup, shutdown, and malfunction, shall be used in calculating %Ps or Eho pursuant to paragraphs (d), (e), or (f) of this section, as applicable.
              [72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009]

              § 60.45c
              Compliance and performance test methods and procedures for particulate matter.
              (a) The owner or operator of an affected facility subject to the PM and/or opacity standards under § 60.43c shall conduct an initial performance test as required under § 60.8, and shall conduct subsequent performance tests as requested by the Administrator, to determine compliance with the standards using the following procedures and reference methods, except as specified in paragraph (c) of this section.
              (1) Method 1 of appendix A of this part shall be used to select the sampling site and the number of traverse sampling points.
              (2) Method 3A or 3B of appendix A-2 of this part shall be used for gas analysis when applying Method 5 or 5B of appendix A-3 of this part or 17 of appendix A-6 of this part.
              (3) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as follows:
              (i) Method 5 of appendix A of this part may be used only at affected facilities without wet scrubber systems.
              (ii) Method 17 of appendix A of this part may be used at affected facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C (320 °F). The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of this part may be used in Method 17 of appendix A of this part only if Method 17 of appendix A of this part is used in conjunction with a wet scrubber system. Method 17 of appendix A of this part shall not be used in conjunction with a wet scrubber system if the effluent is saturated or laden with water droplets.
              (iii) Method 5B of appendix A of this part may be used in conjunction with a wet scrubber system.
              (4) The sampling time for each run shall be at least 120 minutes and the minimum sampling volume shall be 1.7 dry standard cubic meters (dscm) [60 dry standard cubic feet (dscf)] except that smaller sampling times or volumes may be approved by the Administrator when necessitated by process variables or other factors.

              (5) For Method 5 or 5B of appendix A of this part, the temperature of the sample gas in the probe and filter holder shall be monitored and maintained at 160 ±14 °C (320±25 °F).
              (6) For determination of PM emissions, an oxygen (O2) or carbon dioxide (CO2) measurement shall be obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling location.
              (7) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rates expressed in ng/J (lb/MMBtu) heat input shall be determined using:
              (i) The O2 or CO2 measurements and PM measurements obtained under this section, (ii) The dry basis F factor, and
              (iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this part.
              (8) Method 9 of appendix A-4 of this part shall be used for determining the opacity of stack emissions.
              (b) The owner or operator of an affected facility seeking to demonstrate compliance with the PM standards under § 60.43c(b)(2) shall demonstrate the maximum design heat input capacity of the steam generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial performance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall be used.
              (c) In place of PM testing with Method 5 or 5B of appendix A-3 of this part or Method 17 of appendix A-6 of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for monitoring PM emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who elects to continuously monitor PM emissions instead of conducting performance testing using Method 5 or 5B of appendix A-3 of this part or Method 17 of appendix A-6 of this part shall install, calibrate, maintain, and operate a CEMS and shall comply with the requirements specified in paragraphs (c)(1) through (c)(14) of this section.
              (1) Notify the Administrator 1 month before starting use of the system.
              (2) Notify the Administrator 1 month before stopping use of the system.
              (3) The monitor shall be installed, evaluated, and operated in accordance with § 60.13 of subpart A of this part.
              (4) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of CEMS if the owner or operator was previously determining compliance by Method 5, 5B, or 17 of appendix A of this part performance tests, whichever is later.
              (5) The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required under § 60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS specified in paragraph (d) of this section to measure PM and calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19 of appendix A of this part, section 4.1.
              (6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emission concentrations using CEMS outlet data.
              (7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraph (c)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average.
              (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
              (ii) [Reserved]

              (8) The 1-hour arithmetic averages required under paragraph (c)(7) of this section shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
              (9) All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (c)(7) of this section are not met.
              (10) The CEMS shall be operated according to Performance Specification 11 in appendix B of this part.

              (11) During the correlation testing runs of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O2 (or CO2) data shall be collected concurrently (or within a 30- to 60-minute period) by both the continuous emission monitors and performance tests conducted using the following test methods.
              (i) For PM, Method 5 or 5B of appendix A-3 of this part or Method 17 of appendix A-6 of this part shall be used; and
              (ii) For O2 (or CO2), Method 3A or 3B of appendix A-2 of this part, as applicable shall be used.
              (12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years.
              (13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours on a 30-day rolling average.

              (14) As of January 1, 2012, and within 90 days after the date of completing each performance test, as defined in § 60.8, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief /ert/ert tool.html/) or other compatible electronic spreadsheet. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically into EPA's WebFIRE database.
              (d) The owner or operator of an affected facility seeking to demonstrate compliance under § 60.43c(e)(4) shall follow the applicable procedures under § 60.48c(f). For residual oil-fired affected facilities, fuel supplier certifications are only allowed for facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30 MMBtu/h).
              [72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9463, Feb. 16, 2012]

              § 60.46c
              Emission monitoring for sulfur dioxide.

              (a) Except as provided in paragraphs (d) and (e) of this section, the owner or operator of an affected facility subject to the SO2 emission limits under § 60.42c shall install, calibrate, maintain, and operate a CEMS for measuring SO2 concentrations and either O2 or CO2 concentrations at the outlet of the SO2 control device (or the outlet of the steam generating unit if no SO2 control device is used), and shall record the output of the system. The owner or operator of an affected facility subject to the percent reduction requirements under § 60.42c shall measure SO2 concentrations and either O2 or CO2 concentrations at both the inlet and outlet of the SO2 control device.
              (b) The 1-hour average SO2 emission rates measured by a CEMS shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the average emission rates under § 60.42c. Each 1-hour average SO2 emission rate must be based on at least 30 minutes of operation, and shall be calculated using the data points required under § 60.13(h)(2). Hourly SO2 emission rates are not calculated if the affected facility is operated less than 30 minutes in a 1-hour period and are not counted toward determination of a steam generating unit operating day.

              (c) The procedures under § 60.13 shall be followed for installation, evaluation, and operation of the CEMS.

              (1) All CEMS shall be operated in accordance with the applicable procedures under Performance Specifications 1, 2, and 3 of appendix B of this part.
              (2) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 of appendix F of this part.

              (3) For affected facilities subject to the percent reduction requirements under § 60.42c, the span value of the SO2 CEMS at the inlet to the SO2 control device shall be 125 percent of the maximum estimated hourly potential SO2 emission rate of the fuel combusted, and the span value of the SO2 CEMS at the outlet from the SO2 control device shall be 50 percent of the maximum estimated hourly potential SO2 emission rate of the fuel combusted.

              (4) For affected facilities that are not subject to the percent reduction requirements of § 60.42c, the span value of the SO2 CEMS at the outlet from the SO2 control device (or outlet of the steam generating unit if no SO2 control device is used) shall be 125 percent of the maximum estimated hourly potential SO2 emission rate of the fuel combusted.

              (d) As an alternative to operating a CEMS at the inlet to the SO2 control device (or outlet of the steam generating unit if no SO2 control device is used) as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO2 emission rate by sampling the fuel prior to combustion. As an alternative to operating a CEMS at the outlet from the SO2 control device (or outlet of the steam generating unit if no SO2 control device is used) as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO2 emission rate by using Method 6B of appendix A of this part. Fuel sampling shall be conducted pursuant to either paragraph (d)(1) or (d)(2) of this section. Method 6B of appendix A of this part shall be conducted pursuant to paragraph (d)(3) of this section.

              (1) For affected facilities combusting coal or oil, coal or oil samples shall be collected daily in an as-fired condition at the inlet to the steam generating unit and analyzed for sulfur content and heat content according the Method 19 of appendix A of this part. Method 19 of appendix A of this part provides procedures for converting these measurements into the format to be used in calculating the average SO2 input rate.
              (2) As an alternative fuel sampling procedure for affected facilities combusting oil, oil samples may be collected from the fuel tank for each steam generating unit immediately after the fuel tank is filled and before any oil is combusted. The owner or operator of the affected facility shall analyze the oil sample to determine the sulfur content of the oil. If a partially empty fuel tank is refilled, a new sample and analysis of the fuel in the tank would be required upon filling. Results of the fuel analysis taken after each new shipment of oil is received shall be used as the daily value when calculating the 30-day rolling average until the next shipment is received. If the fuel analysis shows that the sulfur content in the fuel tank is greater than 0.5 weight percent sulfur, the owner or operator shall ensure that the sulfur content of subsequent oil shipments is low enough to cause the 30-day rolling average sulfur content to be 0.5 weight percent sulfur or less.

              (3) Method 6B of appendix A of this part may be used in lieu of CEMS to measure SO2 at the inlet or outlet of the SO2 control system. An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of this part sampling location. The stratification test shall consist of three paired runs of a suitable SO2 and CO2 measurement train operated at the candidate location and a second similar train operated according to the procedures in § 3.2 and the applicable procedures in section 7 of Performance Specification 2 of appendix B of this part. Method 6B of appendix A of this part, Method 6A of appendix A of this part, or a combination of Methods 6 and 3 of appendix A of this part or Methods 6C and 3A of appendix A of this part are suitable measurement techniques. If Method 6B of appendix A of this part is used for the second train, sampling time and timer operation may be adjusted for the stratification test as long as an adequate sample volume is collected; however, both sampling trains are to be operated similarly. For the location to be adequate for Method 6B of appendix A of this part 24-hour tests, the mean of the absolute difference between the three paired runs must be less than 10 percent (0.10).

              (e) The monitoring requirements of paragraphs (a) and (d) of this section shall not apply to affected facilities subject to § 60.42c(h) (1), (2), or (3) where the owner or operator of the affected facility seeks to demonstrate compliance with the SO2 standards based on fuel supplier certification, as described under § 60.48c(f), as applicable.
              (f) The owner or operator of an affected facility operating a CEMS pursuant to paragraph (a) of this section, or conducting as-fired fuel sampling pursuant to paragraph (d)(1) of this section, shall obtain emission data for at least 75 percent of the operating hours in at least 22 out of 30 successive steam generating unit operating days. If this minimum data requirement is not met with a single monitoring system, the owner or operator of the affected facility shall supplement the emission data with data collected with other monitoring systems as approved by the Administrator.

              § 60.47c
              Emission monitoring for particulate matter.
              (a) Except as provided in paragraphs (c), (d), (e), and (f) of this section, the owner or operator of an affected facility combusting coal, oil, or wood that is subject to the opacity standards under § 60.43c shall install, calibrate, maintain, and operate a continuous opacity monitoring system (COMS) for measuring the opacity of the emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility subject to an opacity standard in § 60.43c(c) that is not required to use a COMS due to paragraphs (c), (d), (e), or (f) of this section that elects not to use a COMS shall conduct a performance test using Method 9 of appendix A-4 of this part and the procedures in § 60.11 to demonstrate compliance with the applicable limit in § 60.43c by April 29, 2011, within 45 days of stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this section. The observation period for Method 9 of appendix A-4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation.
              (1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A-4 of this part performance tests using the procedures in paragraph (a) of this section according to the applicable schedule in paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined by the most recent Method 9 of appendix A-4 of this part performance test results.
              (i) If no visible emissions are observed, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
              (ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 6 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later;
              (iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or

              (iv) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A-4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted.
              (2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A-4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A-4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A-7 of this part according to the procedures specified in paragraphs (a)(2)(i) and (ii) of this section.

              (i) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A-7 of this part and demonstrate that the sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation period (i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period (i.e., 90 seconds per 30 minute period), the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute observation (i.e., 90 seconds) or conduct a new Method 9 of appendix A-4 of this part performance test using the procedures in paragraph (a) of this section within 45 calendar days according to the requirements in § 60.45c(a)(8).
              (ii) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed.
              (3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A-4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A-4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily identical, to the requirements in paragraph (a)(2) of this section. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243-02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods.
              (b) All COMS shall be operated in accordance with the applicable procedures under Performance Specification 1 of appendix B of this part. The span value of the opacity COMS shall be between 60 and 80 percent.
              (c) Owners and operators of an affected facilities that burn only distillate oil that contains no more than 0.5 weight percent sulfur and/or liquid or gaseous fuels with potential sulfur dioxide emission rates of 26 ng/J (0.060 lb/MMBtu) heat input or less and that do not use a post-combustion technology to reduce SO2 or PM emissions and that are subject to an opacity standard in § 60.43c(c) are not required to operate a COMS if they follow the applicable procedures in § 60.48c(f).

              (d) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere as specified in § 60.45c(c). The CEMS specified in paragraph § 60.45c(c) shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments.

              (e) Owners and operators of an affected facility that is subject to an opacity standard in § 60.43c(c) and that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO2, or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur, and is operated such that emissions of CO discharged to the atmosphere from the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating day average basis is not required to operate a COMS. Owners and operators of affected facilities electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (e)(1) through (4) of this section; or
              (1) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (e)(1)(i) through (iv) of this section.
              (i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in § 60.58b(i)(3) of subpart Eb of this part.
              (ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
              (iii) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data points required in § 60.13(h)(2).
              (iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.
              (2) You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each steam generating unit operating day.
              (3) You must evaluate the preceding 24-hour average CO emission level each steam generating unit operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less.
              (4) You must record the CO measurements and calculations performed according to paragraph (e) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the corrective action.
              (f) An owner or operator of an affected facility that is subject to an opacity standard in § 60.43c(c) is not required to operate a COMS provided that the affected facility meets the conditions in either paragraphs (f)(1), (2), or (3) of this section.
              (1) The affected facility uses a fabric filter (baghouse) as the primary PM control device and, the owner or operator operates a bag leak detection system to monitor the performance of the fabric filter according to the requirements in section § 60.48Da of this part.
              (2) The affected facility uses an ESP as the primary PM control device, and the owner or operator uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the requirements in section § 60.48Da of this part.

              (3) The affected facility burns only gaseous fuels and/or fuel oils that contain no greater than 0.5 weight percent sulfur, and the owner or operator operates the unit according to a written site-specific monitoring plan approved by the permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard. For testing performed as part of this site-specific monitoring plan, the permitting authority may require as an alternative to the notification and reporting requirements specified in §§ 60.8 and 60.11 that the owner or operator submit any deviations with the excess emissions report required under § 60.48c(c).
              [72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9463, Feb. 16, 2012]

              § 60.48c
              Reporting and recordkeeping requirements.
              (a) The owner or operator of each affected facility shall submit notification of the date of construction or reconstruction and actual startup, as provided by § 60.7 of this part. This notification shall include:
              (1) The design heat input capacity of the affected facility and identification of fuels to be combusted in the affected facility.
              (2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under § 60.42c, or § 60.43c.
              (3) The annual capacity factor at which the owner or operator anticipates operating the affected facility based on all fuels fired and based on each individual fuel fired.

              (4) Notification if an emerging technology will be used for controlling SO2 emissions. The Administrator will examine the description of the control device and will determine whether the technology qualifies as an emerging technology. In making this determination, the Administrator may require the owner or operator of the affected facility to submit additional information concerning the control device. The affected facility is subject to the provisions of § 60.42c(a) or (b)(1), unless and until this determination is made by the Administrator.

              (b) The owner or operator of each affected facility subject to the SO2 emission limits of § 60.42c, or the PM or opacity limits of § 60.43c, shall submit to the Administrator the performance test data from the initial and any subsequent performance tests and, if applicable, the performance evaluation of the CEMS and/or COMS using the applicable performance specifications in appendix B of this part.
              (c) In addition to the applicable requirements in § 60.7, the owner or operator of an affected facility subject to the opacity limits in § 60.43c(c) shall submit excess emission reports for any excess emissions from the affected facility that occur during the reporting period and maintain records according to the requirements specified in paragraphs (c)(1) through (3) of this section, as applicable to the visible emissions monitoring method used.
              (1) For each performance test conducted using Method 9 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (c)(1)(i) through (iii) of this section.
              (i) Dates and time intervals of all opacity observation periods;
              (ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and
              (iii) Copies of all visible emission observer opacity field data sheets;
              (2) For each performance test conducted using Method 22 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (c)(2)(i) through (iv) of this section.
              (i) Dates and time intervals of all visible emissions observation periods;
              (ii) Name and affiliation for each visible emission observer participating in the performance test;
              (iii) Copies of all visible emission observer opacity field data sheets; and
              (iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements.

              (3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the Administrator

              (d) The owner or operator of each affected facility subject to the SO2 emission limits, fuel oil sulfur limits, or percent reduction requirements under § 60.42c shall submit reports to the Administrator.

              (e) The owner or operator of each affected facility subject to the SO2 emission limits, fuel oil sulfur limits, or percent reduction requirements under § 60.42c shall keep records and submit reports as required under paragraph (d) of this section, including the following information, as applicable.
              (1) Calendar dates covered in the reporting period.
              (2) Each 30-day average SO2 emission rate (ng/J or lb/MMBtu), or 30-day average sulfur content (weight percent), calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of corrective actions taken.
              (3) Each 30-day average percent of potential SO2 emission rate calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of the corrective actions taken.

              (4) Identification of any steam generating unit operating days for which SO2 or diluent (O2 or CO2) data have not been obtained by an approved method for at least 75 percent of the operating hours; justification for not obtaining sufficient data; and a description of corrective actions taken.
              (5) Identification of any times when emissions data have been excluded from the calculation of average emission rates; justification for excluding data; and a description of corrective actions taken if data have been excluded for periods other than those during which coal or oil were not combusted in the steam generating unit.
              (6) Identification of the F factor used in calculations, method of determination, and type of fuel combusted.
              (7) Identification of whether averages have been obtained based on CEMS rather than manual sampling methods.
              (8) If a CEMS is used, identification of any times when the pollutant concentration exceeded the full span of the CEMS.
              (9) If a CEMS is used, description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specifications 2 or 3 of appendix B of this part.
              (10) If a CEMS is used, results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 1 of this part.
              (11) If fuel supplier certification is used to demonstrate compliance, records of fuel supplier certification as described under paragraph (f)(1), (2), (3), or (4) of this section, as applicable. In addition to records of fuel supplier certifications, the report shall include a certified statement signed by the owner or operator of the affected facility that the records of fuel supplier certifications submitted represent all of the fuel combusted during the reporting period.
              (f) Fuel supplier certification shall include the following information:
              (1) For distillate oil:
              (i) The name of the oil supplier;
              (ii) A statement from the oil supplier that the oil complies with the specifications under the definition of distillate oil in § 60.41c; and
              (iii) The sulfur content or maximum sulfur content of the oil.
              (2) For residual oil:
              (i) The name of the oil supplier;
              (ii) The location of the oil when the sample was drawn for analysis to determine the sulfur content of the oil, specifically including whether the oil was sampled as delivered to the affected facility, or whether the sample was drawn from oil in storage at the oil supplier's or oil refiner's facility, or other location;
              (iii) The sulfur content of the oil from which the shipment came (or of the shipment itself); and
              (iv) The method used to determine the sulfur content of the oil.
              (3) For coal:
              (i) The name of the coal supplier;

              (ii) The location of the coal when the sample was collected for analysis to determine the properties of the coal, specifically including whether the coal was sampled as delivered to the affected facility or whether the sample was collected from coal in storage at the mine, at a coal preparation plant, at a coal supplier's facility, or at another location. The certification shall include the name of the coal mine (and coal seam), coal storage facility, or coal preparation plant (where the sample was collected);
              (iii) The results of the analysis of the coal from which the shipment came (or of the shipment itself) including the sulfur content, moisture content, ash content, and heat content; and
              (iv) The methods used to determine the properties of the coal.
              (4) For other fuels:
              (i) The name of the supplier of the fuel;
              (ii) The potential sulfur emissions rate or maximum potential sulfur emissions rate of the fuel in ng/J heat input; and
              (iii) The method used to determine the potential sulfur emissions rate of the fuel.
              (g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of this section, the owner or operator of each affected facility shall record and maintain records of the amount of each fuel combusted during each operating day.

              (2) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility that combusts only natural gas, wood, fuels using fuel certification in § 60.48c(f) to demonstrate compliance with the SO2 standard, fuels not subject to an emissions standard (excluding opacity), or a mixture of these fuels may elect to record and maintain records of the amount of each fuel combusted during each calendar month.

              (3) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility or multiple affected facilities located on a contiguous property unit where the only fuels combusted in any steam generating unit (including steam generating units not subject to this subpart) at that property are natural gas, wood, distillate oil meeting the most current requirements in § 60.42C to use fuel certification to demonstrate compliance with the SO2 standard, and/or fuels, excluding coal and residual oil, not subject to an emissions standard (excluding opacity) may elect to record and maintain records of the total amount of each steam generating unit fuel delivered to that property during each calendar month.
              (h) The owner or operator of each affected facility subject to a federally enforceable requirement limiting the annual capacity factor for any fuel or mixture of fuels under § 60.42c or § 60.43c shall calculate the annual capacity factor individually for each fuel combusted. The annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of the calendar month.
              (i) All records required under this section shall be maintained by the owner or operator of the affected facility for a period of two years following the date of such record.
              (j) The reporting period for the reports required under this subpart is each six-month period. All reports shall be submitted to the Administrator and shall be postmarked by the 30th day following the end of the reporting period.
              [72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009]

            Subpart E—Standards of Performance for Incinerators

              § 60.50
              Applicability and designation of affected facility.
              (a) The provisions of this subpart are applicable to each incinerator of more than 45 metric tons per day charging rate (50 tons/day), which is the affected facility.
              (b) Any facility under paragraph (a) of this section that commences construction or modification after August 17, 1971, is subject to the requirements of this subpart.
              (c) Any facility covered by subpart Cb, Eb, AAAA, or BBBB of this part is not covered by this subpart.

              (d) Any facility covered by an EPA approved State section 111(d)/129 plan implementing subpart Cb or BBBB of this part is not covered by this subpart.

              (e) Any facility covered by subpart FFF or JJJ of part 62 of this title (Federal section 111(d)/129 plan implementing subpart Cb or BBBB of this part) is not covered by this subpart.
              [42 FR 37936, July 25, 1977, as amended at 71 FR 27335, May 10, 2006]

              § 60.51
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.
              (a) Incinerator means any furnace used in the process of burning solid waste for the purpose of reducing the volume of the waste by removing combustible matter.
              (b) Solid waste means refuse, more than 50 percent of which is municipal type waste consisting of a mixture of paper, wood, yard wastes, food wastes, plastics, leather, rubber, and other combustibles, and noncombustible materials such as glass and rock.
              (c) Day means 24 hours.
              [36 FR 24877, Dec. 23, 1971, as amended at 39 FR 20792, June 14, 1974]

              § 60.52
              Standard for particulate matter.

              (a) On and after the date on which the initial performance test is completed or required to be completed under § 60.8 of this part, whichever date comes first, no owner or operator subject to the provisions of this part shall cause to be discharged into the atmosphere from any affected facility any gases which contain particulate matter in excess of 0.18 g/dscm (0.08 gr/dscf) corrected to 12 percent CO2.
              [39 FR 20792, June 14, 1974, as amended at 65 FR 61753, Oct. 17, 2000]

              § 60.53
              Monitoring of operations.
              (a) The owner or operator of any incinerator subject to the provisions of this part shall record the daily charging rates and hours of operation.

              § 60.54
              Test methods and procedures.
              (a) In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b).
              (b) The owner or operator shall determine compliance with the particulate matter standard in § 60.52 as follows:
              (1) The concentration (c12) of particulate matter, corrected to 12 percent CO2, shall be computed for each run using the following equation:

              c12 = cs (12/%CO2)

                where:

                c12 = concentration of particulate matter, corrected to 12 percent CO2, g/dscm (gr/dscf).
                cs = concentration of particulate matter, g/dscm (gr/dscf).
                %CO2 = CO2 concentration, percent dry basis.

              (2) Method 5 shall be used to determine the particulate matter concentration (cs). The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 dscf).

              (3) The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 3B shall be used to determine CO2 concentration (%CO2).
              (i) The CO2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate run. If the particulate run has more than 12 traverse points, the CO2 traverse points may be reduced to 12 if Method 1 is used to locate the 12 CO2 traverse points. If individual CO2 samples are taken at each traverse point, the CO2 concentration (%CO2) used in the correction equation shall be the arithmetic mean of the sample CO2 concentrations at all traverse points.

              (ii) If sampling is conducted after a wet scrubber, an “adjusted” CO2 concentration [(%CO2)adj], which accounts for the effects of CO2 absorption and dilution air, may be used instead of the CO2 concentration determined in this paragraph. The adjusted CO2 concentration shall be determined by either of the procedures in paragraph (c) of this section.

              (c) The owner or operator may use either of the following procedures to determine the adjusted CO2 concentration.

              (1) The volumetric flow rates at the inlet and outlet of the wet scrubber and the inlet CO2 concentration may be used to determine the adjusted CO2
                concentration [(%CO2)adj] using the following equation:

              (%CO2)adj = (%CO2)di (Qdi/Qdo)

                where:

                (%CO2)adj = adjusted outlet CO2 concentration, percent dry basis.
                (%CO2)di = CO2 concentration measured before the scrubber, percent dry basis.
                Qdi = volumetric flow rate of effluent gas before the wet scrubber, dscm/min (dscf/min).
                Qdo = volumetric flow rate of effluent gas after the wet scrubber, dscm/min (dscf/min).

              (i) At the outlet, Method 5 is used to determine the volumetric flow rate (Qdo) of the effluent gas.

              (ii) At the inlet, Method 2 is used to determine the volumetric flow rate (Qdi) of the effluent gas as follows: Two full velocity traverses are conducted, one immediately before and one immediately after each particulate run conducted at the outlet, and the results are averaged.

              (iii) At the inlet, the emission rate correction factor, integrated sampling and analysis procedure of Method 3B is used to determine the CO2 concentration [(%CO2)di] as follows: At least nine sampling points are selected randomly from the velocity traverse points and are divided randomly into three sets, equal in number of points; the first set of three or more points is used for the first run, the second set for the second run, and the third set for the third run. The CO2 sample is taken simultaneously with each particulate run being conducted at the outlet, by traversing the three sampling points (or more) and sampling at each point for equal increments of time.

              (2) Excess air measurements may be used to determine the adjusted CO2 concentration [(%CO2)adj] using the following equation:

              (%CO2)adj = (%CO2)di [(100 + %EAi)/(100 + %EAo)]

                where:

                (%CO2)adj = adjusted outlet CO2 concentration, percent dry basis.
                (%CO2)di = CO2 concentration at the inlet of the wet scrubber, percent dry basis.
                %EAi = excess air at the inlet of the scrubber, percent.
                %EAo = excess air at the outlet of the scrubber, percent.

              (i) A gas sample is collected as in paragraph (c)(1)(iii) of this section and the gas samples at both the inlet and outlet locations are analyzed for CO2, O2, and N2.
              (ii) Equation 3B-3 of Method 3B is used to compute the percentages of excess air at the inlet and outlet of the wet scrubber.
              [54 FR 6665, Feb. 14, 1989, as amended at 55 FR 5212, Feb. 14, 1990; 65 FR 61753, Oct. 17, 2000]

            Subpart Ea—Standards of Performance for Municipal Waste Combustors for Which Construction Is Commenced After December 20, 1989 and On or Before September 20, 1994

              Source:
              56 FR 5507, Feb. 11, 1991, unless otherwise noted.

              § 60.50a
              Applicability and delegation of authority.
              (a) The affected facility to which this subpart applies is each municipal waste combustor unit with a municipal waste combustor unit capacity greater than 225 megagrams per day (250 tons per day) of municipal solid waste for which construction, modification, or reconstruction is commenced as specified in paragraphs (a)(1) and (a)(2) of this section.
              (1) Construction is commenced after December 20, 1989 and on or before September 20, 1994.
              (2) Modification or reconstruction is commenced after December 20, 1989 and on or before June 19, 1996.
              (b) [Reserved]
              (c) Any unit combusting a single-item waste stream of tires is not subject to this subpart if the owner or operator of the unit:
              (1) Notifies the Administrator of an exemption claim; and
              (2) Provides data documenting that the unit qualifies for this exemption.
              (d) Any cofired combustor, as defined under § 60.51a, located at a plant that meets the capacity specifications in paragraph (a) of this section is not subject to this subpart if the owner or operator of the cofired combustor:

              (1) Notifies the Administrator of an exemption claim;

              (2) Provides a copy of the federally enforceable permit (specified in the definition of cofired combustor in this section); and
              (3) Keeps a record on a calendar quarter basis of the weight of municipal solid waste combusted at the cofired combustor and the weight of all other fuels combusted at the cofired combustor.
              (e) Any cofired combustor that is subject to a federally enforceable permit limiting the operation of the combustor to no more than 225 megagrams per day (250 tons per day) of municipal solid waste is not subject to this subpart.
              (f) Physical or operational changes made to an existing municipal waste combustor unit primarily for the purpose of complying with emission guidelines under subpart Cb are not considered a modification or reconstruction and do not result in an existing municipal waste combustor unit becoming subject to this subpart.
              (g) A qualifying small power production facility, as defined in section 3(17)(C) of the Federal Power Act (16 U.S.C. 796(17)(C)), that burns homogeneous waste (such as automotive tires or used oil, but not including refuse-derived fuel) for the production of electric energy is not subject to this subpart if the owner or operator of the facility notifies the Administrator of an exemption claim and provides data documenting that the facility qualifies for this exemption.
              (h) A qualifying cogeneration facility, as defined in section 3(18)(B) of the Federal Power Act (16 U.S.C. 796(18)(B)), that burns homogeneous waste (such as automotive tires or used oil, but not including refuse-derived fuel) for the production of electric energy and steam or forms of useful energy (such as heat) that are used for industrial, commercial, heating, or cooling purposes, is not subject to this subpart if the owner or operator of the facility notifies the Administrator of an exemption claim and provides data documenting that the facility qualifies for this exemption.
              (i) Any unit required to have a permit under section 3005 of the Solid Waste Disposal Act is not subject to this subpart.
              (j) Any materials recovery facility (including primary or secondary smelters) that combusts waste for the primary purpose of recovering metals is not subject to this subpart.
              (k) Pyrolysis/combustion units that are an integrated part of a plastics/rubber recycling unit (as defined in § 60.51a) are not subject to this subpart if the owner or operator of the plastics/rubber recycling unit keeps records of: the weight of plastics, rubber, and/or rubber tires processed on a calendar quarter basis; the weight of chemical plant feedstocks and petroleum refinery feedstocks produced and marketed on a calendar quarter basis; and the name and address of the purchaser of the feedstocks. The combustion of gasoline, diesel fuel, jet fuel, fuel oils, residual oil, refinery gas, petroleum coke, liquified petroleum gas, propane, or butane produced by chemical plants or petroleum refineries that use feedstocks produced by plastics/rubber recycling units are not subject to this subpart.
              (l) The following authorities shall be retained by the Administrator and not transferred to a State:
              None.
              (m) This subpart shall become effective on August 12, 1991.
              [56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65384, Dec. 19, 1995]

              § 60.51a
              Definitions.

                ASME means the American Society of Mechanical Engineers.

                Batch MWC means an MWC unit designed such that it cannot combust MSW continuously 24 hours per day because the design does not allow waste to be fed to the unit or ash to be removed while combustion is occurring.

                Bubbling fluidized bed combustor means a fluidized bed combustor in which the majority of the bed material remains in a fluidized state in the primary combustion zone.

                Calendar quarter means a consecutive 3-month period (nonoverlapping) beginning on January 1, April 1, July 1, and October 1.

                Chief facility operator means the person in direct charge and control of the operation of an MWC and who is responsible for daily on-site supervision, technical direction, management, and overall performance of the facility.

                Circulating fluidized bed combustor means a fluidized bed combustor in which the majority of the fluidized bed material is carried out of the primary combustion zone and is transported back to the primary zone through a recirculation loop.

                Clean wood means untreated wood or untreated wood products including clean untreated lumber, tree stumps (whole or chipped), and tree limbs (whole or chipped). Clean wood does not include yard waste, which is defined elsewhere in this section, or construction, renovation, and demolition wastes (which includes but is not limited to railroad ties and telephone poles), which are exempt from the definition of municipal solid waste in this section.

                Cofired combustor means a unit combusting municipal solid waste with nonmunicipal solid waste fuel (e.g., coal, industrial process waste) and subject to a federally enforceable permit limiting the unit to combusting a fuel feed stream, 30 percent or less of the weight of which is comprised, in aggregate, of municipal solid waste as measured on a calendar quarter basis.

                Continuous emission monitoring system or CEMS means a monitoring system for continuously measuring the emissions of a pollutant from an affected facility.

                Continuous monitoring system means the total equipment used to sample and condition (if applicable), to analyze, and to provide a permanent record of emissions or process parameters.

                Dioxin/furan means total tetra- through octachlorinated dibenzo-p-dioxins and dibenzofurans.

                Federally-enforceable means all limitations and conditions that are enforceable by the Administrator including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.

                Four-hour block average or 4-hour block average means the average of all hourly emission rates when the affected facility is operating and combusting MSW measured over 4-hour periods of time from 12 midnight to 4 a.m., 4 a.m. to 8 a.m., 8 a.m. to 12 noon, 12 noon to 4 p.m., 4 p.m. to 8 p.m., and 8 p.m. to 12 midnight.

                Large municipal waste combustor plant means a municipal waste combustor plant with a municipal waste combustor aggregate plant capacity for affected facilities that is greater than 225 megagrams per day (250 tons per day) of municipal solid waste.

                Mass burn refractory municipal waste combustor means a field-erected combustor that combusts municipal solid waste in a refractory wall furnace. Unless otherwise specified, this includes combustors with a cylindrical rotary refractory wall furnace.

                Mass burn rotary waterwall municipal waste combustor means a field-erected combustor that combusts municipal solid waste in a cylindrical rotary waterwall furnace.

                Mass burn waterwall municipal waste combustor means a field-erected combustor that combusts municipal solid waste in a waterwall furnace.

                Maximum demonstrated municipal waste combustor unit load means the highest 4-hour arithmetic average municipal waste combustor unit load achieved during four consecutive hours during the most recent dioxin/furan performance test demonstrating compliance with the applicable limit for municipal waste combustor organics specified under § 60.53a.

                Maximum demonstrated particulate matter control device temperature means the highest 4-hour arithmetic average flue gas temperature measured at the particulate matter control device inlet during four consecutive hours during the most recent dioxin/furan performance test demonstrating compliance with the applicable limit for municipal waste combustor organics specified under § 60.53a.

                Modification or modified municipal waste combustor unit means a municipal waste combustor unit to which changes have been made if the cumulative cost of the changes, over the life of the unit, exceed 50 percent of the original cost of construction and installation of the unit (not including the cost of any land purchased in connection with such construction or installation) updated to current costs; or any physical change in the municipal waste combustor unit or change in the method of operation of the municipal waste combustor unit increases the amount of any air pollutant emitted by the unit for which standards have been established under section 129 or section 111. Increases in the amount of any air pollutant emitted by the municipal waste combustor unit are determined at 100-percent physical load capability and downstream of all air pollution control devices, with no consideration given for load restrictions based on permits or other nonphysical operational restrictions.

                Modular excess air MWC means a combustor that combusts MSW and that is not field-erected and has multiple combustion chambers, all of which are designed to operate at conditions with combustion air amounts in excess of theoretical air requirements.

                Modular starved air MWC means a combustor that combusts MSW and that is not field-erected and has multiple combustion chambers in which the primary combustion chamber is designed to operate at substoichiometric conditions.

                Municipal solid waste or municipal-type solid waste or MSW means household, commercial/retail, and/or institutional waste. Household waste includes material discarded by single and multiple residential dwellings, hotels, motels, and other similar permanent or temporary housing establishments or facilities. Commercial/retail waste includes material discarded by stores, offices, restaurants, warehouses, nonmanufacturing activities at industrial facilities, and other similar establishments or facilities. Institutional waste includes material discarded by schools, nonmedical waste discarded by hospitals, material discarded by nonmanufacturing activities at prisons and government facilities, and material discarded by other similar establishments or facilities. Household, commercial/retail, and institutional waste does not include used oil; sewage sludge; wood pallets; construction, renovation, and demolition wastes (which includes but is not limited to railroad ties and telephone poles); clean wood; industrial process or manufacturing wastes; medical waste; or motor vehicles (including motor vehicle parts or vehicle fluff). Household, commercial/retail, and institutional wastes include:
              (1) Yard waste;
              (2) Refuse-derived fuel; and
              (3) Motor vehicle maintenance materials limited to vehicle batteries and tires except as specified in § 60.50a(c).

                Municipal waste combustor, MWC, or municipal waste combustor unit: (1) Means any setting or equipment that combusts solid, liquid, or gasified MSW including, but not limited to, field-erected incinerators (with or without heat recovery), modular incinerators (starved-air or excess-air), boilers (i.e., steam-generating units), furnaces (whether suspension-fired, grate-fired, mass-fired, air curtain incinerators, or fluidized bed-fired), and pyrolysis/combustion units. Municipal waste combustors do not include pyrolysis/combustion units located at plastics/ rubber recycling units (as specified in § 60.50a(k) of this section). Municipal waste combustors do not include internal combustion engines, gas turbines, or other combustion devices that combust landfill gases collected by landfill gas collection systems.
              (2) The boundaries of an MWC are defined as follows. The MWC unit includes, but is not limited to, the MSW fuel feed system, grate system, flue gas system, bottom ash system, and the combustor water system. The MWC boundary starts at the MSW pit or hopper and extends through:
              (i) The combustor flue gas system, which ends immediately following the heat recovery equipment or, if there is no heat recovery equipment, immediately following the combustion chamber;
              (ii) The combustor bottom ash system, which ends at the truck loading station or similar ash handling equipment that transfer the ash to final disposal, including all ash handling systems that are connected to the bottom ash handling system; and
              (iii) The combustor water system, which starts at the feed water pump and ends at the piping exiting the steam drum or superheater.

              (3) The MWC unit does not include air pollution control equipment, the stack, water treatment equipment, or the turbine generator set.

                Municipal waste combustor plant means one or more MWC units at the same location for which construction, modification, or reconstruction is commenced after December 20, 1989 and on or before September 20, 1994.

                Municipal waste combustor plant capacity means the aggregate MWC unit capacity of all MWC units at an MWC plant for which construction, modification, or reconstruction of the units commenced after December 20, 1989 and on or before September 20, 1994. Any MWC units for which construction, modification, or reconstruction is commenced on or before December 20, 1989 or after September 20, 1994 are not included for determining applicability under this subpart.

                Municipal waste combustor unit capacity means the maximum design charging rate of an MWC unit expressed in megagrams per day (tons per day) of MSW combusted, calculated according to the procedures under § 60.58a(j). Municipal waste combustor unit capacity is calculated using a design heating value of 10,500 kilojoules per kilogram (4,500 British thermal units per pound) for MSW. The calculational procedures under § 60.58a(j) include procedures for determining MWC unit capacity for continuous and batch feed MWC's.

                Municipal waste combustor unit load means the steam load of the MWC unit measured as specified in § 60.58a(h)(6).

                MWC acid gases means all acid gases emitted in the exhaust gases from MWC units including, but not limited to, sulfur dioxide and hydrogen chloride gases.

                MWC metals means metals and metal compounds emitted in the exhaust gases from MWC units.

                MWC organics means organic compounds emitted in the exhaust gases from MWC units and includes total tetra- through octa-chlorinated dibenzo-p-dioxins and dibenzofurans.

                Particulate matter means total particulate matter emitted from MWC units as measured by Method 5 (see § 60.58a).

                Plastics/rubber recycling unit means an integrated processing unit where plastics, rubber, and/or rubber tires are the only feed materials (incidental contaminants may be included in the feed materials) and they are processed into a chemical plant feedstock or petroleum refinery feedstock, where the feedstock is marketed to and used by a chemical plant or petroleum refinery as input feedstock. The combined weight of the chemical plant feedstock and petroleum refinery feedstock produced by the plastics/rubber recycling unit on a calendar quarter basis shall be more than 70 percent of the combined weight of the plastics, rubber, and rubber tires processed by the plastics/rubber recycling unit on a calendar quarter basis. The plastics, rubber, and/or rubber tire feed materials to the plastics/rubber recycling unit may originate from the separation or diversion of plastics, rubber, or rubber tires from MSW or industrial solid waste, and may include manufacturing scraps, trimmings, and off-specification plastics, rubber, and rubber tire discards. The plastics, rubber, and rubber tire feed materials to the plastics/rubber recycling unit may contain incidental contaminants (e.g., paper labels on plastic bottles, metal rings on plastic bottle caps, etc.).

                Potential hydrogen chloride emission rate means the hydrogen chloride emission rate that would occur from combustion of MSW in the absence of any hydrogen chloride emissions control.

                Potential sulfur dioxide emission rate means the sulfur dioxide emission rate that would occur from combustion of MSW in the absence of any sulfur dioxide emissions control.

                Pulverized coal/refuse-derived fuel mixed fuel-fired combustor or pulverized coal/RDF mixed fuel-fired combustor means a combustor that fires coal and RDF simultaneously, in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the unit where it is fired in suspension. This includes both conventional pulverized coal and micropulverized coal.

                Pyrolysis/combustion unit means a unit that produces gases, liquids, or solids through the heating of MSW, and the gases, liquids, or solids produced are combusted and emissions vented to the atmosphere.

                Reconstruction means rebuilding an MWC unit for which the cumulative costs of the construction over the life of the unit exceed 50 percent of the original cost of construction and installation of the unit (not including any cost of land purchased in connection with such construction or installation) updated to current costs (current dollars).

                Refractory unit or refractory wall furnace means a combustion unit having no energy recovery (e.g., via a waterwall) in the furnace (i.e., radiant heat transfer section) of the combustor.

                Refuse-derived fuel or RDF means a type of MSW produced by processing MSW through shredding and size classification.
              This includes all classes of RDF including low density fluff RDF through densified RDF and RDF fuel pellets.

                RDF stoker means a steam generating unit that combusts RDF in a semi-suspension firing mode using air-fed distributors.

                Same location means the same or contiguous property that is under common ownership or control, including properties that are separated only by a street, road, highway, or other public right-of-way. Common ownership or control includes properties that are owned, leased, or operated by the same entity, parent entity, subsidiary, subdivision, or any combination thereof, including any municipality or other governmental unit, or any quasigovernmental authority (e.g., a public utility district or regional waste disposal authority).

                Shift supervisor means the person in direct charge and control of the operation of an MWC and who is responsible for on-site supervision, technical direction, management, and overall performance of the facility during an assigned shift.

                Spreader stoker coal/refuse-derived fuel mixed fuel-fired combustor or spreader stoker coal/RDF mixed fuel-fired combustor means a combustor that fires coal and refuse-derived fuel simultaneously, in which coal is introduced to the combustion zone by a mechanism that throws the fuel onto a grate from above. Combustion takes place both in suspension and on the grate.

                Standard conditions means a temperature of 20 °C (68 °F) and a pressure of 101.3 kilopascals (29.92 inches of mercury).

                Twenty-four hour daily average or 24-hour daily average means the arithmetic or geometric mean (as specified in § 60.58a (e), (g), or (h) as applicable) of all hourly emission rates when the affected facility is operating and firing MSW measured over a 24-hour period between 12 midnight and the following midnight.

                Untreated lumber means wood or wood products that have been cut or shaped and include wet, air-dried, and kiln-dried wood products. Untreated lumber does not include wood products that have been painted, pigment-stained, or “pressure-treated.” Pressure-treating compounds include, but are not limited to, chromate copper arsenate, pentachlorophenol, and creosote.

                Waterwall furnace means a combustion unit having energy (heat) recovery in the furnace (i.e., radiant heat transfer section) of the combustor.

                Yard waste means grass, grass clippings, bushes, shrubs, and clippings from bushes and shrubs that are generated by residential, commercial/retail, institutional, and/or industrial sources as part of maintenance activities associated with yards or other private or public lands. Yard waste does not include construction, renovation, and demolition wastes, which are exempt from the definition of MSW in this section. Yard waste does not include clean wood, which is exempt from the definition of MSW in this section.
              [56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65384, Dec. 19, 1995; 65 FR 61753, Oct. 17, 2000]

              § 60.52a
              Standard for municipal waste combustor metals.
              (a) On and after the date on which the initial compliance test is completed or is required to be completed under § 60.8, no owner or operator of an affected facility located within a large MWC plant shall cause to be discharged into the atmosphere from that affected facility any gases that contain particulate matter in excess of 34 milligrams per dry standard cubic meter (0.015 grains per dry standard cubic foot), corrected to 7 percent oxygen (dry basis).

              (b) On and after the date on which the initial compliance test is completed or is required to be completed under § 60.8, no owner or operator of an affected facility subject to the particulate matter emission limit under paragraph (a) of this section shall cause to be discharged into the atmosphere from that affected facility any gases that exhibit greater than 10 percent opacity (6-minute average).
              (c) [Reserved]

              § 60.53a
              Standard for municipal waste combustor organics.
              (a) [Reserved]
              (b) On and after the date on which the initial compliance test is completed or is required to be completed under § 60.8, no owner or operator of an affected facility located within a large MWC plant shall cause to be discharged into the atmosphere from that affected facility any gases that contain dioxin/furan emissions that exceed 30 nanograms per dry standard cubic meter (12 grains per billion dry standard cubic feet), corrected to 7 percent oxygen (dry basis).

              § 60.54a
              Standard for municipal waste combustor acid gases.
              (a)-(b) [Reserved]
              (c) On and after the date on which the initial compliance test is completed or is required to be completed under § 60.8, no owner or operator of an affected facility located within a large MWC plant shall cause to be discharged into the atmosphere from that affected facility any gases that contain sulfur dioxide in excess of 20 percent of the potential sulfur dioxide emission rate (80 percent reduction by weight or volume) or 30 parts per million by volume, corrected to 7 percent oxygen (dry basis), whichever is less stringent. The averaging time is specified in § 60.58a(e).
              (d) On and after the date on which the initial compliance test is completed or is required to be completed under § 60.8, no owner or operator of an affected facility located within a large MWC plant shall cause to be discharged into the atmosphere from that affected facility any gases that contain hydrogen chloride in excess of 5 percent of the potential hydrogen chloride emission rate (95 percent reduction by weight or volume) or 25 parts per million by volume, corrected to 7 percent oxygen (dry basis), whichever is less stringent.

              § 60.55a
              Standard for nitrogen oxides.
              On and after the date on which the initial compliance test is completed or is required to be completed under § 60.8, no owner or operator of an affected facility located within a large MWC plant shall cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides in excess of 180 parts per million by volume, corrected to 7 percent oxygen (dry basis). The averaging time is specified under § 60.58a(g).

              § 60.56a
              Standards for municipal waste combustor operating practices.
              (a) On and after the date on which the initial compliance test is completed or is required to be completed under § 60.8, no owner or operator of an affected facility located within a large MWC plant shall cause such facility to exceed the carbon monoxide standards shown in table 1.

                Table 1—MWC Operating Standards

                  MWC technology
                  Carbon monoxide emission limit (parts per million by volume) 1

                  Mass burn waterwall
                  100

                  Mass burn refractory
                  100

                  Mass burn rotary waterwall
                  100

                  Modular starved air
                  50

                  Modular excess air
                  50

                  RDF stoker
                  150

                  Bubbling fluidized bed combustor
                  100

                  Circulating fluidized bed combustor
                  100

                  Pulverized coal/RDF mixed fuel-fired combustor
                  150

                  Spreader stoker coal/RDF mixed fuel-fird combustor
                  150

                  1 Measured at the combustor outlet in conjunction with a measurement of oxygen concentration, corrected to 7 percent oxygen (dry basis). The averaging times are specified in § 60.58a(h).

              (b) No owner or operator of an affected facility located within a large MWC plant shall cause such facility to operate at a load level greater than 110 percent of the maximum demonstrated MWC unit load as defined in § 60.51a. The averaging time is specified under § 60.58a(h).

              (c) No owner or operator of an affected facility located within a large MWC plant shall cause such facility to operate at a temperature, measured at the final particulate matter control device inlet, exceeding 17 °Centigrade (30 °Fahrenheit) above the maximum demonstrated particulate matter control device temperature as defined in § 60.51a. The averaging time is specified under § 60.58a(h).
              (d) Within 24 months from the date of start-up of an affected facility or before February 11, 1993, whichever is later, each chief facility operator and shift supervisor of an affected facility located within a large MWC plant shall obtain and keep current either a provisional or operator certification in accordance with ASME QRO-1-1994 (incorporated by reference, see § 60.17) or an equivalent State-approved certification program.
              (e) No owner or operator of an affected facility shall allow such affected facility located at a large MWC plant to operate at any time without a certified shift supervisor, as provided under paragraph (d) of this section, on duty at the affected facility. This requirement shall take effect 24 months after the date of start-up of the affected facility or on and after February 11, 1993, whichever is later.
              (f) The owner or operator of an affected facility located within a large MWC plant shall develop and update on a yearly basis a sitespecific operating manual that shall, at a minimum, address the following elements of MWC unit operation:
              (1) Summary of the applicable standards under this subpart;
              (2) Description of basic combustion theory applicable to an MWC unit;
              (3) Procedures for receiving, handling, and feeding MSW;
              (4) MWC unit start-up, shutdown, and malfunction procedures;
              (5) Procedures for maintaining proper combustion air supply levels;
              (6) Procedures for operating the MWC unit within the standards established under this subpart;
              (7) Procedures for responding to periodic upset or off-specification conditions;
              (8) Procedures for minimizing particulate matter carryover;
              (9) [Reserved]
              (10) Procedures for handling ash;
              (11) Procedures for monitoring MWC unit emissions; and
              (12) Reporting and recordkeeping procedures.
              (g) The owner or operator of an affected facility located within a large MWC plant shall establish a program for reviewing the operating manual annually with each person who has responsibilities affecting the operation of an affected facility including, but not limited to, chief facility operators, shift supervisors, control room operators, ash handlers, maintenance personnel, and crane/load handlers.
              (h) The initial review of the operating manual, as specified under paragraph (g) of this section, shall be conducted prior to assumption of responsibilities affecting MWC unit operation by any person required to undergo training under paragraph (g) of this section. Subsequent reviews of the manual shall be carried out annually by each such person.
              (i) The operating manual shall be kept in a readily accessible location for all persons required to undergo training under paragraph (g) of this section. The operating manual and records of training shall be available for inspection by EPA or its delegated enforcement agent upon request.
              (j)-(k) [Reserved]
              [56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65386, Dec. 19, 1995]

              § 60.57a
              [Reserved]

              § 60.58a
              Compliance and performance testing.
              (a) The standards under this subpart apply at all times, except during periods of start-up, shutdown, or malfunction; provided, however, that the duration of start-up, shutdown, or malfunction shall not exceed 3 hours per occurrence.
              (1) The start-up period commences when the affected facility begins the continuous burning of MSW and does not include any warm-up period when the affected facility is combusting only a fossil fuel or other non-MSW fuel and no MSW is being combusted.

              (2) Continuous burning is the continuous, semicontinuous, or batch feeding of MSW for purposes of waste disposal, energy production, or providing heat to the combustion system in preparation for waste disposal or energy production. The use of MSW solely to provide thermal protection of grate or hearth during the start-up period shall not be considered to be continuous burning.
              (b) The following procedures and test methods shall be used to determine compliance with the emission limits for particulate matter under § 60.52a:
              (1) Method 1 shall be used to select sampling site and number of traverse points.
              (2) Method 3 shall be used for gas analysis.
              (3) Method 5 shall be used for determining compliance with the particulate matter emission limit. The minimum sample volume shall be 1.7 cubic meters (60 cubic feet). The probe and filter holder heating systems in the sample train shall be set to provide a gas temperature of 160°±14 °Centigrade (320°±25 °Fahrenheit). An oxygen or carbon dioxide measurement shall be obtained simultaneously with each Method 5 run.
              (4) For each Method 5 run, the emission rate shall be determined using:
              (i) Oxygen or carbon dioxide measurements,
              (ii) Dry basis F factor, and
              (iii) Dry basis emission rate calculation procedures in Method 19.
              (5) An owner or operator may request that compliance be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
              (6) The owner or operator of an affected facility shall conduct an initial compliance test for particulate matter and opacity as required under § 60.8.
              (7) Method 9 shall be used for determining compliance with the opacity limit.
              (8) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous opacity monitoring system (COMS) and record the output of the system on a 6-minute average basis.
              (9) Following the date the initial compliance test for particulate matter is completed or is required to be completed under § 60.8 for an affected facility located within a large MWC plant, the owner or operator shall conduct a performance test for particulate matter on an annual basis (no more than 12 calendar months following the previous compliance test).
              (10) [Reserved]
              (c) [Reserved]
              (d) The following procedures and test methods shall be used to determine compliance with the limits for dioxin/furan emissions under § 60.53a:
              (1) Method 23 shall be used for determining compliance with the dioxin/furan emission limits. The minimum sample time shall be 4 hours per test run.
              (2) The owner or operator of an affected facility shall conduct an initial compliance test for dioxin/furan emissions as required under § 60.8.
              (3) Following the date of the initial compliance test or the date on which the initial compliance test is required to be completed under § 60.8, the owner or operator of an affected facility located within a large MWC plant shall conduct a performance test for dioxin/furan emissions on an annual basis (no more than 12 calendar months following the previous compliance test).
              (4) [Reserved]
              (5) An owner or operator may request that compliance with the dioxin/furan emissions limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
              (e) The following procedures and test methods shall be used for determining compliance with the sulfur dioxide limit under § 60.54a:
              (1) Method 19, section 5.4, shall be used to determine the daily geometric average percent reduction in the potential sulfur dioxide emission rate.
              (2) Method 19, section 4.3, shall be used to determine the daily geometric average sulfur dioxide emission rate.

              (3) An owner or operator may request that compliance with the sulfur dioxide emissions limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
              (4) The owner or operator of an affected facility shall conduct an initial compliance test for sulfur dioxide as required under § 60.8. Compliance with the sulfur dioxide emission limit and percent reduction is determined by using a CEMS to measure sulfur dioxide and calculating a 24-hour daily geometric mean emission rate and daily geometric mean percent reduction using Method 19 sections 4.3 and 5.4, as applicable, except as provided under paragraph (e)(5) of this section.
              (5) For batch MWC's or MWC units that do not operate continuously, compliance shall be determined using a daily geometric mean of all hourly average values for the hours during the day that the affected facility is combusting MSW.
              (6) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS for measuring sulfur dioxide emissions discharged to the atmosphere and record the output of the system.
              (7) Following the date of the initial compliance test or the date on which the initial compliance test is required to be completed under § 60.8, compliance with the sulfur dioxide emission limit or percent reduction shall be determined based on the geometric mean of the hourly arithmetic average emission rates during each 24-hour daily period measured between 12:00 midnight and the following midnight using: CEMS inlet and outlet data, if compliance is based on a percent reduction; or CEMS outlet data only if compliance is based on an emission limit.
              (8) At a minimum, valid CEMS data shall be obtained for 75 percent of the hours per day for 75 percent of the days per month the affected facility is operated and combusting MSW.
              (9) The 1-hour arithmetic averages required under paragraph (e)(7) of this section shall be expressed in parts per million (dry basis) and used to calculate the 24-hour daily geometric mean emission rates. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2). At least two data points shall be used to calculate each 1-hour arithmetic average.
              (10) All valid CEMS data shall be used in calculating emission rates and percent reductions even if the minimum CEMS data requirements of paragraph (e)(8) of this section are not met.
              (11) The procedures under § 60.1 3 shall be followed for installation, evaluation, and operation of the CEMS.
              (12) The CEMS shall be operated according to Performance Specifications 1, 2, and 3 (appendix B of part 60).
              (13) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 (appendix F of part 60).
              (14) The span value of the CEMS at the inlet to the sulfur dioxide control device is 125 percent of the maximum estimated hourly potential sulfur dioxide emissions of the MWC unit, and the span value of the CEMS at the outlet of the sulfur dioxide control device is 50 percent of the maximum estimated hourly potential sulfur dioxide emissions of the MWC unit.
              (15) When sulfur dioxide emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or Method 19 to provide as necessary valid emission data for a minimum of 75 percent of the hours per day for 75 percent of the days per month the unit is operated and combusting MSW.

              (16) Not operating a sorbent injection system for the sole purpose of testing in order to demonstrate compliance with the percent reduction standards for MWC acid gases shall not be considered a physical change in the method of operation under 40 CFR 52.21, or under regulations approved pursuant to 40 CFR 51.166 or 40 CFR 51.165 (a) and (b).
              (f) The following procedures and test methods shall be used for determining compliance with the hydrogen chloride limits under § 60.54a:

              (1) The percentage reduction in the potential hydrogen chloride emissions (%PHCl) is computed using the following formula:

                EC16NO91.003

                where:

                Ei is the potential hydrogen chloride emission rate.
                Eo is the hydrogen chloride emission rate measured at the outlet of the acid gas control device.

              (2) Method 26 or 26A shall be used for determining the hydrogen chloride emission rate. The minimum sampling time for Method 26 or 26A shall be 1 hour.
              (3) An owner or operator may request that compliance with the hydrogen chloride emissions limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
              (4) The owner or operator of an affected facility shall conduct an initial compliance test for hydrogen chloride as required under § 60.8.
              (5) Following the date of the initial compliance test or the date on which the initial compliance test is required under § 60.8, the owner or operator of an affected facility located within a large MWC plant shall conduct a performance test for hydrogen chloride on an annual basis (no more than 12 calendar months following the previous compliance test).
              (6) [Reserved]

              (7) Not operating a sorbent injection system for the sole purpose of testing in order to demonstrate compliance with the percent reduction standards for MWC acid gases shall not be considered a physical change in the method of operation under 40 CFR 52.21, or under regulations approved pursuant to 40 CFR 51.166 or 40 CFR 51.165 (a) and (b).
              (g) The following procedures and test methods shall be used to determine compliance with the nitrogen oxides limit under § 60.55a:
              (1) Method 19, section 4.1, shall be used for determining the daily arithmetic average nitrogen oxides emission rate.
              (2) An owner or operator may request that compliance with the nitrogen oxides emissions limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
              (3) The owner or operator of an affected facility subject to the nitrogen oxides limit under § 60.55a shall conduct an initial compliance test for nitrogen oxides as required under § 60.8. Compliance with the nitrogen oxides emission standard shall be determined by using a CEMS for measuring nitrogen oxides and calculating a 24-hour daily arithmetic average emission rate using Method 19, section 4.1, except as specified under paragraph (g)(4) of this section.
              (4) For batch MWC's or MWC's that do not operate continuously, compliance shall be determined using a daily arithmetic average of all hourly average values for the hours during the day that the affected facility is combusting MSW.
              (5) The owner or operator of an affected facility subject to the nitrogen oxides emissions limit under § 60.55a shall install, calibrate, maintain, and operate a CEMS for measuring nitrogen oxides discharged to the atmosphere and record the output of the system.
              (6) Following the initial compliance test or the date on which the initial compliance test is required to be completed under § 60.8, compliance with the emission limit for nitrogen oxides required under § 60.55a shall be determined based on the arithmetic average of the arithmetic average hourly emission rates during each 24-hour daily period measured between 12:00 midnight and the following midnight using CEMS data.
              (7) At a minimum valid CEMS data shall be obtained for 75 percent of the hours per day for 75 percent of the days per month the affected facility is operated and combusting MSW.

              (8) The 1-hour arithmetic averages required by paragraph (g)(6) of this section shall be expressed in parts per million volume (dry basis) and used to calculate the 24-hour daily arithmetic average emission rates. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(b). At least two data points shall be used to calculate each 1-hour arithmetic average.
              (9) All valid CEMS data must be used in calculating emission rates even if the minimum CEMS data requirements of paragraph (g)(7) of this section are not met.
              (10) The procedures under § 60.13 shall be followed for installation, evaluation, and operation of the CEMS.
              (11) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 (appendix F of part 60).
              (12) When nitrogen oxides emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emission data calculations to determine compliance shall be made using other monitoring systems as approved by the Administrator or Method 19 to provide as necessary valid emission data for a minimum of 75 percent of the hours per day for 75 percent of the days per month the unit is operated and combusting MSW.
              (h) The following procedures shall be used for determining compliance with the operating standards under § 60.56a:
              (1) Compliance with the carbon monoxide emission limits in § 60.56a(a) shall be determined using a 4-hour block arithmetic average for all types of affected facilities except mass burn rotary waterwall MWC's, RDF stokers, and spreader stoker/RDF mixed fuel-fired combustors.
              (2) For affected mass burn rotary waterwall MWC's, RDF stokers, and spreader stoker/RDF mixed fuel-fired combustors, compliance with the carbon monoxide emission limits in § 60.56a(a) shall be determined using a 24-hour daily arithmetic average.
              (3) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS for measuring carbon monoxide at the combustor outlet and record the output of the system.
              (4) The 4-hour and 24-hour daily arithmetic averages in paragraphs (h) (1) and (2) of this section shall be calculated from 1-hour arithmetic averages expressed in parts per million by volume (dry basis). The 1-hour arithmetic averages shall be calculated using the data points generated by the CEMS. At least two data points shall be used to calculate each 1-hour arithmetic average.
              (5) An owner or operator may request that compliance with the carbon monoxide emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established during the initial compliance test.
              (6) The following procedures shall be used to determine compliance with load level requirements under § 60.56a(b):
              (i) The owner or operator of an affected facility with steam generation capability shall install, calibrate, maintain, and operate a steam flow meter or a feedwater flow meter; measure steam or feedwater flow in kilograms per hour (pounds per hour) on a continuous basis; and record the output of the monitor. Steam or feedwater flow shall be calculated in 4-hour block arithmetic averages.
              (ii) The method included in “American Society of Mechanical Engineers Power Test Codes: Test Code for Steam Generating Units, Power Test Code 4.1—1964”, Section 4 (incorporated by reference, see § 60.17) shall be used for calculating the steam (or feedwater flow) required under paragraph (h)(6)(i) of this section. The recommendations of “American Society of Mechanical Engineers Interim Supplement 19.5 on Instruments and Apparatus: Application, Part II of Fluid Meters, 6th edition (1971),” chapter 4 (incorporated by reference, see § 60.17) shall be followed for design, construction, installation, calibration, and use of nozzles and orifices except as specified in (h)(6)(iii) of this section.
              (iii) Measurement devices such as flow nozzles and orifices are not required to be recalibrated after they are installed.

              (iv) All signal conversion elements associated with steam (or feedwater flow) measurements must be calibrated according to the manufacturer's instructions before each dioxin/furan compliance and performance test, and at least once per year.

              (v) The owner or operator of an affected facility without heat recovery shall:
              (A) [Reserved]
              (7) To determine compliance with the maximum particulate matter control device temperature requirements under § 60.56a(c), the owner or operator of an affected facility shall install, calibrate, maintain, and operate a device for measuring temperature of the flue gas stream at the inlet to the final particulate matter control device on a continuous basis and record the output of the device. Temperature shall be calculated in 4-hour block arithmetic averages.
              (8) Maximum demonstrated MWC unit load shall be determined during the initial compliance test for dioxins/furans and each subsequent performance test during which compliance with the dioxin/furan emission limit under § 60.53a is achieved. Maximum demonstrated MWC unit load shall be the maximum 4-hour arithmetic average load achieved during the most recent test during which compliance with the dioxin/furan limit was achieved.
              (9) The maximum demonstrated particulate matter control device temperature shall be determined during the initial compliance test for dioxins/furans and each subsequent performance test during which compliance with the dioxin/furan emission limit under § 60.53a is achieved. Maximum demonstrated particulate matter control device temperature shall be the maximum 4-hour arithmetic average temperature achieved at the final particulate matter control device inlet during the most recent test during which compliance with the dioxin/furan limit was achieved.
              (10) At a minimum, valid CEMS data for carbon monoxide, steam or feedwater flow, and particulate matter control device inlet temperature shall be obtained 75 percent of the hours per day for 75 percent of the days per month the affected facility is operated and combusting MSW.
              (11) All valid data must be used in calculating the parameters specified under paragraph (h) of this section even if the minimum data requirements of paragraph (h)(10) of this section are not met.
              (12) Quarterly accuracy determinations and daily calibration drift tests for carbon monoxide CEMS shall be performed in accordance with Procedure 1 (appendix F).
              (i) [Reserved]

              (j) The following procedures shall be used for calculating MWC unit capacity as defined under § 60.51a:
              (1) For MWC units capable of combusting MSW continuously for a 24-hour period, MWC unit capacity, in megagrams per day (tons per day) of MSW combusted, shall be calculated based on 24 hours of operation at the maximum design charging rate. The design heating values under paragraph (j)(4) of this section shall be used in calculating the design charging rate.
              (2) For batch MWC units, MWC unit capacity, in megagrams per day (tons per day) of MSW combusted, shall be calculated as the maximum design amount of MSW that can be charged per batch multiplied by the maximum number of batches that could be processed in a 24-hour period. The maximum number of batches that could be processed in a 24-hour period is calculated as 24 hours divided by the design number of hours required to process one batch of MSW, and may include fractional batches. 1
                 The design heating values under paragraph (j)(4) of this section shall be used in calculating the MWC unit capacity in megagrams per day (tons per day) of MSW.

                  1 For example, if one batch requires 16 hours, then 24/16, or 1.5 batches, could be combusted in a 24-hour period.

              (3) [Reserved]
              (4) The MWC unit capacity shall be calculated using a design heating value of 10,500 kilojoules per kilogram (4,500 British thermal units per pound) for all MSW.
              [56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65387, Dec. 19, 1995; 65 FR 61753, Oct. 17, 2000]

              § 60.59a
              Reporting and recordkeeping requirements.

              (a) The owner or operator of an affected facility located at an MWC plant with a capacity greater than 225 megagrams per day (250 tons per day) shall provide notification of intent to construct and of planned initial start-up date and the type(s) of fuels that they plan to combust in the affected facility. The MWC unit capacity and MWC plant capacity and supporting capacity calculations shall be provided at the time of the notification of construction.
              (b) The owner or operator of an affected facility located within a small or large MWC plant and subject to the standards under § 60.52a, § 60.53a, § 60.54a, § 60.55a, § 60.56a, or § 60.57a shall maintain records of the following information for each affected facility for a period of at least 2 years:
              (1) Calendar date.
              (2) The emission rates and parameters measured using CEMS as specified under (b)(2) (i) and (ii) of this section:
              (i) The following measurements shall be recorded in computer-readable format and on paper:
              (A) All 6-minute average opacity levels required under § 60.58a(b).
              (B) All 1 hour average sulfur dioxide emission rates at the inlet and outlet of the acid gas control device if compliance is based on a percent reduction, or at the outlet only if compliance is based on the outlet emission limit, as specified under § 60.58a(e).
              (C) All 1-hour average nitrogen oxides emission rates as specified under § 60.58a(g).
              (D) All 1-hour average carbon monoxide emission rates, MWC unit load measurements, and particulate matter control device inlet temperatures as specified under § 60.58a(h).
              (ii) The following average rates shall be computed and recorded:
              (A) All 24-hour daily geometric average percent reductions in sulfur dioxide emissions and all 24-hour daily geometric average sulfur dioxide emission rates as specified under § 60.58a(e).
              (B) All 24-hour daily arithmetic average nitrogen oxides emission rates as specified under § 60.58a(g).
              (C) All 4-hour block or 24-hour daily arithmetic average carbon monoxide emission rates, as applicable, as specified under § 60.58a(h).
              (D) All 4-hour block arithmetic average MWC unit load levels and particulate matter control device inlet temperatures as specified under § 60.58a(h).
              (3) Identification of the operating days when any of the average emission rates, percent reductions, or operating parameters specified under paragraph (b)(2)(ii) of this section or the opacity level exceeded the applicable limits, with reasons for such exceedances as well as a description of corrective actions taken.
              (4) Identification of operating days for which the minimum number of hours of sulfur dioxide or nitrogen oxides emissions or operational data (carbon monoxide emissions, unit load, particulate matter control device temperature) have not been obtained, including reasons for not obtaining sufficient data and a description of corrective actions taken.
              (5) Identification of the times when sulfur dioxide or nitrogen oxides emission or operational data (carbon monoxide emissions, unit load, particulate matter control device temperature) have been excluded from the calculation of average emission rates or parameters and the reasons for excluding data.
              (6) The results of daily sulfur dioxide, nitrogen oxides, and carbon monoxide CEMS drift tests and accuracy assessments as required under appendix F, Procedure 1.
              (7) The results of all annual performance tests conducted to determine compliance with the particulate matter, dioxin/furan and hydrogen chloride limits. For all annual dioxin/furan tests, the maximum demonstrated MWC unit load and maximum demonstrated particulate matter control device temperature shall be recorded along with supporting calculations.
              (8)-(15) [Reserved]
              (c) Following the initial compliance test as required under §§ 60.8 and 60.58a, the owner or operator of an affected facility located within a large MWC plant shall submit the initial compliance test data, the performance evaluation of the CEMS using the applicable performance specifications in appendix B, and the maximum demonstrated MWC unit load and maximum demonstrated particulate matter control device temperature established during the dioxin/furan compliance test.
              (d) [Reserved]

              (e)(1) The owner or operator of an affected facility located within a large MWC plant shall submit annual compliance reports for sulfur dioxide, nitrogen oxide (if applicable), carbon monoxide, load level, and particulate matter control device temperature to the Administrator containing the information recorded under paragraphs (b)(1), (2)(ii), (4), (5), and (6) of this section for each pollutant or parameter. The hourly average values recorded under paragraph (b)(2)(i) of this section are not required to be included in the annual reports. Combustors firing a mixture of medical waste and other MSW shall also provide the information under paragraph (b)(15) of this section, as applicable, in each annual report. The owner or operator of an affected facility must submit reports semiannually once the affected facility is subject to permitting requirements under Title V of the Act.
              (2) The owner or operator shall submit a semiannual report for any pollutant or parameter that does not comply with the pollutant or parameter limits specified in this subpart. Such report shall include the information recorded under paragraph (b)(3) of this section. For each of the dates reported, include the sulfur dioxide, nitrogen oxide, carbon monoxide, load level, and particulate matter control device temperature data, as applicable, recorded under paragraphs (b)(2)(ii)(A) through (D) of this section.
              (3) Reports shall be postmarked no later than the 30th day following the end of the annual or semiannual period, as applicable.
              (f)(1) The owner or operator of an affected facility located within a large MWC plant shall submit annual compliance reports, as applicable, for opacity. The annual report shall list the percent of the affected facility operating time for the reporting period that the opacity CEMS was operating and collecting valid data. Once the unit is subject to permitting requirements under Title V of the Act, the owner or operator of an affected facility must submit these reports semiannually.
              (2) The owner or operator shall submit a semiannual report for all periods when the 6-minute average levels exceeded the opacity limit under § 60.52a. The semiannual report shall include all information recorded under paragraph (b)(3) of this section which pertains to opacity, and a listing of the 6-minute average opacity levels recorded under paragraph (b)(2)(i)(A) of this section, which exceeded the opacity limit.
              (3) Reports shall be postmarked no later than the 30th day following the end of the annual of semiannual period, as applicable.
              (g)(1) The owner or operator of an affected facility located within a large MWC plant shall submit reports to the Administrator of all annual performance tests for particulate matter, dioxin/furan, and hydrogen chloride as recorded under paragraph (b)(7) of this section, as applicable, from the affected facility. For each annual dioxin/furan compliance test, the maximum demonstrated MWC unit load and maximum demonstrated particulate matter control device temperature shall be reported. Such reports shall be submitted when available and in no case later than the date of required submittal of the annual report specified under paragraphs (e) and (f) of this section, or within six months of the date the test was conducted, whichever is earlier.
              (2) The owner or operator shall submit a report of test results which document any particulate matter, dioxin/furan, and hydrogen chloride levels that were above the applicable pollutant limit. The report shall include a copy of the test report documenting the emission levels and shall include the corrective action taken. Such reports shall be submitted when available and in no case later than the date required for submittal of any semiannual report required in paragraphs (e) or (f) of this section, or within six months of the date the test was conducted, whichever is earlier.
              (h) [Reserved]
              (i) Records of CEMS data for opacity, sulfur dioxide, nitrogen oxides, and carbon monoxide, load level data, and particulate matter control device temperature data shall be maintained for at least 2 years after date of recordation and be made available for inspection upon request.

              (j) Records showing the names of persons who have completed review of the operating manual, including the date of the initial review and all subsequent annual reviews, shall be maintained for at least 2 years after date of review and be made available for inspection upon request.
              [56 FR 5507, Feb. 11, 1991, as amended at 60 FR 65387, Dec. 19, 1995; 64 FR 7465, Feb. 12, 1999]

            Subpart Eb—Standards of Performance for Large Municipal Waste Combustors for Which Construction is Commenced After September 20, 1994 or for Which Modification or Reconstruction is Commenced After June 19, 1996

              Source:
              60 FR 65419, Dec. 19, 1995, unless otherwise noted.

              § 60.50b
              Applicability and delegation of authority.
              (a) The affected facility to which this subpart applies is each municipal waste combustor unit with a combustion capacity greater than 250 tons per day of municipal solid waste for which construction, modification, or reconstruction is commenced after September 20, 1994.
              (b) Any waste combustion unit that is capable of combusting more than 250 tons per day of municipal solid waste and is subject to a federally enforceable permit limiting the maximum amount of municipal solid waste that may be combusted in the unit to less than or equal to 11 tons per day is not subject to this subpart if the owner or operator:
              (1) Notifies EPA of an exemption claim;
              (2) Provides a copy of the federally enforceable permit that limits the firing of municipal solid waste to less than 11 tons per day; and
              (3) Keeps records of the amount of municipal solid waste fired on a daily basis.
              (c) An affected facility to which this subpart applies is not subject to subpart E or Ea of this part.
              (d) Physical or operational changes made to an existing municipal waste combustor unit primarily for the purpose of complying with emission guidelines under subpart Cb are not considered a modification or reconstruction and do not result in an existing municipal waste combustor unit becoming subject to this subpart.
              (e) A qualifying small power production facility, as defined in section 3(17)(C) of the Federal Power Act (16 U.S.C. 796(17)(C)), that burns homogeneous waste (such as automotive tires or used oil, but not including refuse-derived fuel) for the production of electric energy is not subject to this subpart if the owner or operator of the facility notifies EPA of this exemption and provides data documenting that the facility qualifies for this exemption.
              (f) A qualifying cogeneration facility, as defined in section 3(18)(B) of the Federal Power Act (16 U.S.C. 796(18)(B)), that burns homogeneous waste (such as automotive tires or used oil, but not including refuse-derived fuel) for the production of electric energy and steam or forms of useful energy (such as heat) that are used for industrial, commercial, heating, or cooling purposes, is not subject to this subpart if the owner or operator of the facility notifies EPA of this exemption and provides data documenting that the facility qualifies for this exemption.
              (g) Any unit combusting a single-item waste stream of tires is not subject to this subpart if the owner or operator of the unit:
              (1) Notifies EPA of an exemption claim; and
              (2) [Reserved]
              (3) Provides data documenting that the unit qualifies for this exemption.
              (h) Any unit required to have a permit under section 3005 of the Solid Waste Disposal Act is not subject to this subpart.
              (i) Any materials recovery facility (including primary or secondary smelters) that combusts waste for the primary purpose of recovering metals is not subject to this subpart.
              (j) Any cofired combustor, as defined under § 60.51b, that meets the capacity specifications in paragraph (a) of this section is not subject to this subpart if the owner or operator of the cofired combustor:
              (1) Notifies EPA of an exemption claim;

              (2) Provides a copy of the federally enforceable permit (specified in the definition of cofired combustor in this section); and
              (3) Keeps a record on a calendar quarter basis of the weight of municipal solid waste combusted at the cofired combustor and the weight of all other fuels combusted at the cofired combustor.
              (k) Air curtain incinerators, as defined under § 60.51b, located at a plant that meet the capacity specifications in paragraph (a) of this section and that combust a fuel stream composed of 100 percent yard waste are exempt from all provisions of this subpart except the opacity limit under § 60.56b, the testing procedures under § 60.58b(l), and the reporting and recordkeeping provisions under § 60.59b (e) and (i).
              (l) Air curtain incinerators located at plants that meet the capacity specifications in paragraph (a) of this section combusting municipal solid waste other than yard waste are subject to all provisions of this subpart.
              (m) Pyrolysis/combustion units that are an integrated part of a plastics/rubber recycling unit (as defined in § 60.51b) are not subject to this subpart if the owner or operator of the plastics/rubber recycling unit keeps records of the weight of plastics, rubber, and/or rubber tires processed on a calendar quarter basis; the weight of chemical plant feedstocks and petroleum refinery feedstocks produced and marketed on a calendar quarter basis; and the name and address of the purchaser of the feedstocks. The combustion of gasoline, diesel fuel, jet fuel, fuel oils, residual oil, refinery gas, petroleum coke, liquified petroleum gas, propane, or butane produced by chemical plants or petroleum refineries that use feedstocks produced by plastics/rubber recycling units are not subject to this subpart.
              (n) The following authorities are retained by the Administrator of the U.S. EPA and are not transferred to a State:
              (1) Approval of exemption claims in paragraphs (b), (e), (f), (g) and (j) of this section;
              (2) Enforceability under Federal law of all Federally enforceable, as defined in § 60.51b, limitations and conditions;
              (3) Determination of compliance with the siting requirements as specified in § 60.57b(a);
              (4) Acceptance of relationship between carbon monoxide and oxygen as part of initial and annual performance tests as specified in § 60.58b(b)(7);
              (5) Approval of other monitoring systems used to obtain emissions data when data is not obtained by CEMS as specified in § 60.58b(e)(14), (h)(12), (i)(11), and (n)(14), and (p)(11);
              (6) Approval of a site-specific monitoring plan for the continuous emission monitoring system specified in “60.58b(n)(13) and (o) of this section or the continuous automated sampling system specified in § 60.58b(p)(10) and (q) of this section;
              (7) Approval of major alternatives to test methods;
              (8) Approval of major alternatives to monitoring;
              (9) Waiver of recordkeeping; and
              (10) Performance test and data reduction waivers under “608(b).
              (o) This subpart shall become effective June 19, 1996.
              (p) Cement kilns firing municipal solid waste are not subject to this subpart.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45120, 45125, Aug. 25, 1997; 71 FR 27335, May 10, 2006]

              § 60.51b
              Definitions.

                Administrator means:

              (1) For approved and effective State Section 111(d)/129 plans, the Director of the State air pollution control agency, or employee of the State air pollution control agency that is delegated the authority to perform the specified task;
              (2) For Federal Section 111(d)/129 plans, the Administrator of the EPA, an employee of the EPA, the Director of the State air pollution control agency, or employee of the State air pollution control agency to whom the authority has been delegated by the Administrator of the EPA to perform the specified task; and

              (3) For NSPS, the Administrator of the EPA, an employee of the EPA, the Director of the State air pollution control agency, or employee of the State air pollution control agency to whom the authority has been delegated by the Administrator of the EPA to perform the specified task.

                Air curtain incinerator means an incinerator that operates by forcefully projecting a curtain of air across an open chamber or pit in which burning occurs. Incinerators of this type can be constructed above or below ground and with or without refractory walls and floor.

                Batch municipal waste combustor means a municipal waste combustor unit designed so that it cannot combust municipal solid waste continuously 24 hours per day because the design does not allow waste to be fed to the unit or ash to be removed while combustion is occurring.

                Bubbling fluidized bed combustor means a fluidized bed combustor in which the majority of the bed material remains in a fluidized state in the primary combustion zone.

                Calendar quarter means a consecutive 3-month period (nonoverlapping) beginning on January 1, April 1, July 1, and October 1.

                Calendar year means the period including 365 days starting January 1 and ending on December 31.

                Chief facility operator means the person in direct charge and control of the operation of a municipal waste combustor and who is responsible for daily onsite supervision, technical direction, management, and overall performance of the facility.

                Circulating fluidized bed combustor means a fluidized bed combustor in which the majority of the fluidized bed material is carried out of the primary combustion zone and is transported back to the primary zone through a recirculation loop.

                Clean wood means untreated wood or untreated wood products including clean untreated lumber, tree stumps (whole or chipped), and tree limbs (whole or chipped). Clean wood does not include yard waste, which is defined elsewhere in this section, or construction, renovation, and demolition wastes (including but not limited to railroad ties and telephone poles), which are exempt from the definition of municipal solid waste in this section.

                Cofired combustor means a unit combusting municipal solid waste with nonmunicipal solid waste fuel (e.g., coal, industrial process waste) and subject to a federally enforceable permit limiting the unit to combusting a fuel feed stream, 30 percent or less of the weight of which is comprised, in aggregate, of municipal solid waste as measured on a calendar quarter basis.

                Continuous automated sampling system means the total equipment and procedures for automated sample collection and sample recovery/analysis to determine a pollutant concentration or emission rate by collecting a single or multiple integrated sample(s) of the pollutant (or diluent gas) for subsequent on-or off-site analysis; integrated sample(s) collected are representative of the emissions for the sample time as specified by the applicable requirement.

                Continuous emission monitoring system means a monitoring system for continuously measuring the emissions of a pollutant from an affected facility.

                Dioxin/furan means tetra- through octa- chlorinated dibenzo-p-dioxins and dibenzofurans.

                EPA means the Administrator of the U.S. EPA or employee of the U.S. EPA who is delegated to perform the specified task.

                Federally enforceable means all limitations and conditions that are enforceable by EPA including the requirements of 40 CFR part 60, 40 CFR part 61, and 40 CFR part 63, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.

                First calendar half means the period starting on January 1 and ending on June 30 in any year.

                Four-hour block average or 4-hour block average means the average of all hourly emission concentrations when the affected facility is operating and combusting municipal solid waste measured over 4-hour periods of time from 12:00 midnight to 4 a.m., 4 a.m. to 8 a.m., 8 a.m. to 12:00 noon, 12:00 noon to 4 p.m., 4 p.m. to 8 p.m., and 8 p.m. to 12:00 midnight.

                Mass burn refractory municipal waste combustor means a field-erected combustor that combusts municipal solid waste in a refractory wall furnace. Unless otherwise specified, this includes combustors with a cylindrical rotary refractory wall furnace.

                Mass burn rotary waterwall municipal waste combustor means a field-erected combustor that combusts municipal solid waste in a cylindrical rotary waterwall furnace or on a tumbling-tile grate.

                Mass burn waterwall municipal waste combustor means a field-erected combustor that combusts municipal solid waste in a waterwall furnace.

                Materials separation plan means a plan that identifies both a goal and an approach to separate certain components of municipal solid waste for a given service area in order to make the separated materials available for recycling. A materials separation plan may include elements such as dropoff facilities, buy-back or deposit-return incentives, curbside pickup programs, or centralized mechanical separation systems. A materials separation plan may include different goals or approaches for different subareas in the service area, and may include no materials separation activities for certain subareas or, if warranted, an entire service area.

                Maximum demonstrated municipal waste combustor unit load means the highest 4-hour arithmetic average municipal waste combustor unit load achieved during four consecutive hours during the most recent dioxin/furan performance test demonstrating compliance with the applicable limit for municipal waste combustor organics specified under § 60.52b(c).

                Maximum demonstrated particulate matter control device temperature means the highest 4-hour arithmetic average flue gas temperature measured at the particulate matter control device inlet during four consecutive hours during the most recent dioxin/furan performance test demonstrating compliance with the applicable limit for municipal waste combustor organics specified under § 60.52b(c).

                Modification or modified municipal waste combustor unit means a municipal waste combustor unit to which changes have been made after June 19, 1996 if the cumulative cost of the changes, over the life of the unit, exceed 50 percent of the original cost of construction and installation of the unit (not including the cost of any land purchased in connection with such construction or installation) updated to current costs; or any physical change in the municipal waste combustor unit or change in the method of operation of the municipal waste combustor unit increases the amount of any air pollutant emitted by the unit for which standards have been established under section 129 or section 111. Increases in the amount of any air pollutant emitted by the municipal waste combustor unit are determined at 100-percent physical load capability and downstream of all air pollution control devices, with no consideration given for load restrictions based on permits or other nonphysical operational restrictions.

                Modular excess-air municipal waste combustor means a combustor that combusts municipal solid waste and that is not field-erected and has multiple combustion chambers, all of which are designed to operate at conditions with combustion air amounts in excess of theoretical air requirements.

                Modular starved-air municipal waste combustor means a combustor that combusts municipal solid waste and that is not field-erected and has multiple combustion chambers in which the primary combustion chamber is designed to operate at substoichiometric conditions.

                Municipal solid waste or municipal-type solid waste or MSW means household, commercial/retail, and/or institutional waste. Household waste includes material discarded by single and multiple residential dwellings, hotels, motels, and other similar permanent or temporary housing establishments or facilities. Commercial/retail waste includes material discarded by stores, offices, restaurants, warehouses, nonmanufacturing activities at industrial facilities, and other similar establishments or facilities. Institutional waste includes material discarded by schools, nonmedical waste discarded by hospitals, material discarded by nonmanufacturing activities at prisons and government facilities, and material discarded by other similar establishments or facilities. Household, commercial/retail, and institutional waste does not include used oil; sewage sludge; wood pallets; construction, renovation, and demolition wastes (which includes but is not limited to railroad ties and telephone poles); clean wood; industrial process or manufacturing wastes; medical waste; or motor vehicles (including motor vehicle parts or vehicle fluff). Household, commercial/retail, and institutional wastes include:
              (1) Yard waste;
              (2) Refuse-derived fuel; and
              (3) Motor vehicle maintenance materials limited to vehicle batteries and tires except as specified in § 60.50b(g).

                Municipal waste combustor, MWC, or municipal waste combustor unit: (1) Means any setting or equipment that combusts solid, liquid, or gasified municipal solid waste including, but not limited to, field-erected incinerators (with or without heat recovery), modular incinerators (starved-air or excess-air), boilers (i.e., steam generating units), furnaces (whether suspension-fired, grate-fired, mass-fired, air curtain incinerators, or fluidized bed-fired), and pyrolysis/combustion units. Municipal waste combustors do not include pyrolysis/combustion units located at a plastics/rubber recycling unit (as specified in § 60.50b(m)). Municipal waste combustors do not include cement kilns firing municipal solid waste (as specified in § 60.50b(p)). Municipal waste combustors do not include internal combustion engines, gas turbines, or other combustion devices that combust landfill gases collected by landfill gas collection systems.
              (2) The boundaries of a municipal solid waste combustor are defined as follows. The municipal waste combustor unit includes, but is not limited to, the municipal solid waste fuel feed system, grate system, flue gas system, bottom ash system, and the combustor water system. The municipal waste combustor boundary starts at the municipal solid waste pit or hopper and extends through:
              (i) The combustor flue gas system, which ends immediately following the heat recovery equipment or, if there is no heat recovery equipment, immediately following the combustion chamber,
              (ii) The combustor bottom ash system, which ends at the truck loading station or similar ash handling equipment that transfer the ash to final disposal, including all ash handling systems that are connected to the bottom ash handling system; and
              (iii) The combustor water system, which starts at the feed water pump and ends at the piping exiting the steam drum or superheater.
              (3) The municipal waste combustor unit does not include air pollution control equipment, the stack, water treatment equipment, or the turbine-generator set.

                Municipal waste combustor acid gases means all acid gases emitted in the exhaust gases from municipal waste combustor units including, but not limited to, sulfur dioxide and hydrogen chloride gases.

                Municipal waste combustor metals means metals and metal compounds emitted in the exhaust gases from municipal waste combustor units.

                Municipal waste combustor organics means organic compounds emitted in the exhaust gases from municipal waste combustor units and includes tetra-through octa- chlorinated dibenzo-p-dioxins and dibenzofurans.

                Municipal waste combustor plant means one or more affected facilities (as defined in § 60.50b) at the same location.

                Municipal waste combustor unit capacity means the maximum charging rate of a municipal waste combustor unit expressed in tons per day of municipal solid waste combusted, calculated according to the procedures under § 60.58b(j). Section 60.58b(j) includes procedures for determining municipal waste combustor unit capacity for continuous and batch feed municipal waste combustors.

                Municipal waste combustor unit load means the steam load of the municipal waste combustor unit measured as specified in § 60.58b(i)(6).

                Particulate matter means total particulate matter emitted from municipal waste combustor units as measured by EPA Reference Method 5 (see § 60.58b(c)).

                Plastics/rubber recycling unit means an integrated processing unit where plastics, rubber, and/or rubber tires are the only feed materials (incidental contaminants may be included in the feed materials) and they are processed into a chemical plant feedstock or petroleum refinery feedstock, where the feedstock is marketed to and used by a chemical plant or petroleum refinery as input feedstock. The combined weight of the chemical plant feedstock and petroleum refinery feedstock produced by the plastics/rubber recycling unit on a calendar quarter basis shall be more than 70 percent of the combined weight of the plastics, rubber, and rubber tires processed by the plastics/rubber recycling unit on a calendar quarter basis. The plastics, rubber, and/or rubber tire feed materials to the plastics/rubber recycling unit may originate from the separation or diversion of plastics, rubber, or rubber tires from MSW or industrial solid waste, and may include manufacturing scraps, trimmings, and off-specification plastics, rubber, and rubber tire discards. The plastics, rubber, and rubber tire feed materials to the plastics/rubber recycling unit may contain incidental contaminants (e.g., paper labels on plastic bottles, metal rings on plastic bottle caps, etc.).

                Potential hydrogen chloride emission concentration means the hydrogen chloride emission concentration that would occur from combustion of municipal solid waste in the absence of any emission controls for municipal waste combustor acid gases.

                Potential mercury emission concentration means the mercury emission concentration that would occur from combustion of municipal solid waste in the absence of any mercury emissions control.

                Potential sulfur dioxide emissions means the sulfur dioxide emission concentration that would occur from combustion of municipal solid waste in the absence of any emission controls for municipal waste combustor acid gases.

                Pulverized coal/refuse-derived fuel mixed fuel-fired combustor means a combustor that fires coal and refuse-derived fuel simultaneously, in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the unit where it is fired in suspension. This includes both conventional pulverized coal and micropulverized coal.

                Pyrolysis/combustion unit means a unit that produces gases, liquids, or solids through the heating of municipal solid waste, and the gases, liquids, or solids produced are combusted and emissions vented to the atmosphere.

                Reconstruction means rebuilding a municipal waste combustor unit for which the reconstruction commenced after June 19, 1996, and the cumulative costs of the construction over the life of the unit exceed 50 percent of the original cost of construction and installation of the unit (not including any cost of land purchased in connection with such construction or installation) updated to current costs (current dollars).

                Refractory unit or refractory wall furnace means a combustion unit having no energy recovery (e.g., via a waterwall) in the furnace (i.e., radiant heat transfer section) of the combustor.

                Refuse-derived fuel means a type of municipal solid waste produced by processing municipal solid waste through shredding and size classification. This includes all classes of refuse-derived fuel including low-density fluff refuse-derived fuel through densified refuse-derived fuel and pelletized refuse-derived fuel.

                Refuse-derived fuel stoker means a steam generating unit that combusts refuse-derived fuel in a semisuspension firing mode using air-fed distributors.

                Same location means the same or contiguous property that is under common ownership or control including properties that are separated only by a street, road, highway, or other public right-of-way. Common ownership or control includes properties that are owned, leased, or operated by the same entity, parent entity, subsidiary, subdivision, or any combination thereof including any municipality or other governmental unit, or any quasi-governmental authority (e.g., a public utility district or regional waste disposal authority).

                Second calendar half means the period starting July 1 and ending on December 31 in any year.

                Shift supervisor means the person who is in direct charge and control of the operation of a municipal waste combustor and who is responsible for onsite supervision, technical direction, management, and overall performance of the facility during an assigned shift.

                Spreader stoker coal/refuse-derived fuel mixed fuel-fired combustor means a combustor that fires coal and refuse-derived fuel simultaneously, in which coal is introduced to the combustion zone by a mechanism that throws the fuel onto a grate from above. Combustion takes place both in suspension and on the grate.

                Standard conditions means a temperature of 20 °C and a pressure of 101.3 kilopascals.

                Total mass dioxin/furan or total mass means the total mass of tetra- through octa- chlorinated dibenzo-p-dioxins and dibenzofurans, as determined using EPA Reference Method 23 and the procedures specified under § 60.58b(g).

                Tumbling-tile means a grate tile hinged at one end and attached to a ram at the other end. When the ram extends, the grate tile rotates around the hinged end.

                Twenty-four hour daily average or 24-hour daily average means either the arithmetic mean or geometric mean (as specified) of all hourly emission concentrations when the affected facility is operating and combusting municipal solid waste measured over a 24-hour period between 12:00 midnight and the following midnight.

                Untreated lumber means wood or wood products that have been cut or shaped and include wet, air-dried, and kiln-dried wood products. Untreated lumber does not include wood products that have been painted, pigment-stained, or “pressure-treated.” Pressure-treating compounds include, but are not limited to, chromate copper arsenate, pentachlorophenol, and creosote.

                Waterwall furnace means a combustion unit having energy (heat) recovery in the furnace (i.e., radiant heat transfer section) of the combustor.

                Yard waste means grass, grass clippings, bushes, shrubs, and clippings from bushes and shrubs that are generated by residential, commercial/retail, institutional, and/or industrial sources as part of maintenance activities associated with yards or other private or public lands. Yard waste does not include construction, renovation, and demolition wastes, which are exempt from the definition of municipal solid waste in this section. Yard waste does not include clean wood, which is exempt from the definition of municipal solid waste in this section.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45121, 45126, Aug. 25, 1997; 66 FR 36476, July 12, 2001; 71 FR 27335, May 10, 2006]

              § 60.52b
              Standards for municipal waste combustor metals, acid gases, organics, and nitrogen oxides.
              (a) The limits for municipal waste combustor metals are specified in paragraphs (a)(1) through (a)(5) of this section.
              (1) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain particulate matter in excess of the limits specified in paragraph (a)(1)(i) or (a)(1)(ii) of this section.
              (i) For affected facilities that commenced construction, modification, or reconstruction after September 20, 1994, and on or before December 19, 2005, the emission limit is 24 milligrams per dry standard cubic meter, corrected to 7 percent oxygen.
              (ii) For affected facilities that commenced construction, modification, or reconstruction after December 19, 2005, the emission limit is 20 milligrams per dry standard cubic meter, corrected to 7 percent oxygen.
              (2) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that exhibit greater than 10 percent opacity (6-minute average).

              (3) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain cadmium in excess of the limits specified in paragraph (a)(3)(i) or (a)(3)(ii) of this section.
              (i) For affected facilities that commenced construction, modification, or reconstruction after September 20, 1994, and on or before December 19, 2005, the emission limit is 20 micrograms per dry standard cubic meter, corrected to 7 percent oxygen.
              (ii) For affected facilities that commenced construction, modification, or reconstruction after December 19, 2005, the emission limit is 10 micrograms per dry standard cubic meter, corrected to 7 percent oxygen.
              (4) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from the affected facility any gases that contain lead in excess of the limits specified in paragraph (a)(4)(i) or (a)(4)(ii) of this section.
              (i) For affected facilities that commenced construction, modification, or reconstruction after September 20, 1994, and on or before December 19, 2005, the emission limit is 200 micrograms per dry standard cubic meter, corrected to 7 percent oxygen.
              (ii) For affected facilities that commenced construction, modification, or reconstruction after December 19, 2005, the emission limit is 140 micrograms per dry standard cubic meter, corrected to 7 percent oxygen.
              (5) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from the affected facility any gases that contain mercury in excess of the limits specified in paragraph (a)(5)(i) or (a)(5)(ii) of this section.
              (i) For affected facilities that commenced construction, modification, or reconstruction after September 20, 1994 and on or before December 19, 2005, the emission limit is 80 micrograms per dry standard cubic meter or 15 percent of the potential mercury emission concentration (85-percent reduction by weight), corrected to 7 percent oxygen, whichever is less stringent.
              (ii) For affected facilities that commenced construction, modification, or reconstruction after December 19, 2005, the emission limit is 50 micrograms per dry standard cubic meter, or 15 percent of the potential mercury emission concentration (85-percent reduction by weight), corrected to 7 percent oxygen, whichever is less stringent.
              (b) The limits for municipal waste combustor acid gases are specified in paragraphs (b)(1) and (b)(2) of this section.
              (1) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain sulfur dioxide in excess of 30 parts per million by volume or 20 percent of the potential sulfur dioxide emission concentration (80-percent reduction by weight or volume), corrected to 7 percent oxygen (dry basis), whichever is less stringent. The averaging time is specified under § 60.58b(e).
              (2) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain hydrogen chloride in excess of 25 parts per million by volume or 5 percent of the potential hydrogen chloride emission concentration (95-percent reduction by weight or volume), corrected to 7 percent oxygen (dry basis), whichever is less stringent.
              (c) The limits for municipal waste combustor organics are specified in paragraphs (c)(1) and (c)(2) of this section.

              (1) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility for which construction, modification or reconstruction commences on or before November 20, 1997 shall cause to be discharged into the atmosphere from that affected facility any gases that contain dioxin/furan emissions that exceed 30 nanograms per dry standard cubic meter (total mass), corrected to 7 percent oxygen, for the first 3 years following the date of initial startup. After the first 3 years following the date of initial startup, no owner or operator shall cause to be discharged into the atmosphere from that affected facility any gases that contain dioxin/furan total mass emissions that exceed 13 nanograms per dry standard cubic meter (total mass), corrected to 7 percent oxygen.
              (2) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility for which construction, modification, or reconstruction commences after November 20, 1997 shall cause to be discharged into the atmosphere from that affected facility any gases that contain dioxin/furan total mass emissions that exceed 13 nanograms per dry standard cubic meter (total mass), corrected to 7 percent oxygen.
              (d) The limits for nitrogen oxides are specified in paragraphs (d)(1) and (d)(2) of this section.
              (1) During the first year of operation after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides in excess of 180 parts per million by volume, corrected to 7 percent oxygen (dry basis). The averaging time is specified under § 60.58b(h).
              (2) After the first year of operation following the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides in excess of 150 parts per million by volume, corrected to 7 percent oxygen (dry basis). The averaging time is specified under § 60.58b(h).
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45121, 45126, Aug. 25, 1997; 71 FR 27336, May 10, 2006]

              § 60.53b
              Standards for municipal waste combustor operating practices.
              (a) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain carbon monoxide in excess of the emission limits specified in table 1 of this subpart.

                Table 1—Municipal Waste Combustor Operating Standards

                  Municipal waste combustor technology
                  Carbon monoxide emission limit (parts per million by volume) a

                  Averaging time (hours) b

                  Mass burn waterwall
                  100
                  4

                  Mass burn refractory
                  100
                  4

                  Mass burn rotary waterwall
                  100
                  24

                  Modular starved air
                  50
                  4

                  Modular excess air
                  50
                  4

                  Refuse-derived fuel stoker
                  150
                  24

                  Bubbling fluidized bed combustor
                  100
                  4

                  Circulating fluidized bed combustor
                  100
                  4

                  Pulverized coal/refuse-derived fuel mixed fuel-fired combustor
                  150
                  4

                  Spreader stoker coal/refuse-derived fuel mixed fuel-fired combustor
                  150
                  24

                  a Measured at the combustor outlet in conjunction with a measurement of oxygen concentration, corrected to 7 percent oxygen (dry basis). The averaging times are specified in greater detail in § 60.58b(i).

                  b Averaging times are 4-hour or 24-hour block averages.

              (b) No owner or operator of an affected facility shall cause such facility to operate at a load level greater than 110 percent of the maximum demonstrated municipal waste combustor unit load as defined in § 60.51b, except as specified in paragraphs (b)(1) and (b)(2) of this section. The averaging time is specified under § 60.58b(i).
              (1) During the annual dioxin/furan or mercury performance test and the 2 weeks preceding the annual dioxin/furan or mercury performance test, no municipal waste combustor unit load limit is applicable if the provisions of paragraph (b)(2) of this section are met.
              (2) The municipal waste combustor unit load limit may be waived in writing by the Administrator for the purpose of evaluating system performance, testing new technology or control technologies, diagnostic testing, or related activities for the purpose of improving facility performance or advancing the state-of-the-art for controlling facility emissions. The municipal waste combustor unit load limit continues to apply, and remains enforceable, until and unless the Administrator grants the waiver.
              (c) No owner or operator of an affected facility shall cause such facility to operate at a temperature, measured at the particulate matter control device inlet, exceeding 17 °C above the maximum demonstrated particulate matter control device temperature as defined in § 60.51b, except as specified in paragraphs (c)(1) and (c)(2) of this section. The averaging time is specified under § 60.58b(i). The requirements specified in this paragraph apply to each particulate matter control device utilized at the affected facility.
              (1) During the annual dioxin/furan or mercury performance test and the 2 weeks preceding the annual dioxin/furan or mercury performance test, no particulate matter control device temperature limitations are applicable if the provisions of paragraph (b)(2) of this section are met.
              (2) The particulate matter control device temperature limits may be waived in writing by the Administrator for the purpose of evaluating system performance, testing new technology or control technologies, diagnostic testing, or related activities for the purpose of improving facility performance or advancing the state-of-the-art for controlling facility emissions. The temperature limits continue to apply, and remain enforceable, until and unless the Administrator grants the waiver.
              (d) Paragraph (m)(2) of § 60.58b addresses treatment of activated carbon injection rate during dioxin/furan or mercury testing.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997; 71 FR 27336, May 10, 2006]

              § 60.54b
              Standards for municipal waste combustor operator training and certification.
              (a) No later than the date 6 months after the date of startup of an affected facility or on December 19, 1996, whichever is later, each chief facility operator and shift supervisor shall obtain and maintain a current provisional operator certification from either the American Society of Mechanical Engineers [QRO-1-1994 (incorporated by reference—see § 60.17 of subpart A of this part)] or a State certification program.
              (b) Not later than the date 6 months after the date of startup of an affected facility or on December 19, 1996, whichever is later, each chief facility operator and shift supervisor shall have completed full certification or shall have scheduled a full certification exam with either the American Society of Mechanical Engineers [QRO-1-1994 (incorporated by reference—see § 60.17 of subpart A of this part)] or a State certification program.
              (c) No owner or operator of an affected facility shall allow the facility to be operated at any time unless one of the following persons is on duty and at the affected facility: A fully certified chief facility operator, a provisionally certified chief facility operator who is scheduled to take the full certification exam according to the schedule specified in paragraph (b) of this section, a fully certified shift supervisor, or a provisionally certified shift supervisor who is scheduled to take the full certification exam according to the schedule specified in paragraph (b) of this section.

              (1) The requirement specified in paragraph (c) of this section shall take effect 6 months after the date of startup of the affected facility or on December 19, 1996, whichever is later.
              (2) If both the certified chief facility operator and certified shift supervisor are unavailable, a provisionally certified control room operator on site at the municipal waste combustion unit may fulfill the certified operator requirement. Depending on the length of time that a certified chief facility operator and certified shift supervisor are away, the owner or operator of the affected facility must meet one of three criteria:
              (i) When the certified chief facility operator and certified shift supervisor are both off site for 12 hours or less, and no other certified operator is on site, the provisionally certified control room operator may perform the duties of the certified chief facility operator or certified shift supervisor.
              (ii) When the certified chief facility operator and certified shift supervisor are off site for more than 12 hours, but for two weeks or less, and no other certified operator is on site, the provisionally certified control room operator may perform the duties of the certified chief facility operator or certified shift supervisor without notice to, or approval by, the Administrator. However, the owner or operator of the affected facility must record the period when the certified chief facility operator and certified shift supervisor are off site and include that information in the annual report as specified under § 60.59b(g)(5).
              (iii) When the certified chief facility operator and certified shift supervisor are off site for more than two weeks, and no other certified operator is on site, the provisionally certified control room operator may perform the duties of the certified chief facility operator or certified shift supervisor without approval by the Administrator. However, the owner or operator of the affected facility must take two actions:
              (A) Notify the Administrator in writing. In the notice, state what caused the absence and what actions are being taken by the owner or operator of the facility to ensure that a certified chief facility operator or certified shift supervisor is on site as expeditiously as practicable.
              (B) Submit a status report and corrective action summary to the Administrator every four weeks following the initial notification. If the Administrator provides notice that the status report or corrective action summary is disapproved, the municipal waste combustion unit may continue operation for 90 days, but then must cease operation. If corrective actions are taken in the 90-day period such that the Administrator withdraws the disapproval, municipal waste combustion unit operation may continue.
              (3) A provisionally certified operator who is newly promoted or recently transferred to a shift supervisor position or a chief facility operator position at the municipal waste combustion unit may perform the duties of the certified chief facility operator or certified shift supervisor without notice to, or approval by, the Administrator for up to six months before taking the ASME QRO certification exam.
              (d) All chief facility operators, shift supervisors, and control room operators at affected facilities must complete the EPA or State municipal waste combustor operator training course no later than the date 6 months after the date of startup of the affected facility or by December 19, 1996, whichever is later.
              (e) The owner or operator of an affected facility shall develop and update on a yearly basis a site-specific operating manual that shall, at a minimum, address the elements of municipal waste combustor unit operation specified in paragraphs (e)(1) through (e)(11) of this section.
              (1) A summary of the applicable standards under this subpart;
              (2) A description of basic combustion theory applicable to a municipal waste combustor unit;
              (3) Procedures for receiving, handling, and feeding municipal solid waste;
              (4) Municipal waste combustor unit startup, shutdown, and malfunction procedures;
              (5) Procedures for maintaining proper combustion air supply levels;

              (6) Procedures for operating the municipal waste combustor unit within the standards established under this subpart;

              (7) Procedures for responding to periodic upset or off-specification conditions;
              (8) Procedures for minimizing particulate matter carryover;
              (9) Procedures for handling ash;
              (10) Procedures for monitoring municipal waste combustor unit emissions; and
              (11) Reporting and recordkeeping procedures.
              (f) The owner or operator of an affected facility shall establish a training program to review the operating manual according to the schedule specified in paragraphs (f)(1) and (f)(2) of this section with each person who has responsibilities affecting the operation of an affected facility including, but not limited to, chief facility operators, shift supervisors, control room operators, ash handlers, maintenance personnel, and crane/load handlers.
              (1) Each person specified in paragraph (f) of this section shall undergo initial training no later than the date specified in paragraph (f)(1)(i), (f)(1)(ii), or (f)(1)(iii) of this section whichever is later.
              (i) The date 6 months after the date of startup of the affected facility;
              (ii) The date prior to the day the person assumes responsibilities affecting municipal waste combustor unit operation; or
              (iii) December 19, 1996.
              (2) Annually, following the initial review required by paragraph (f)(1) of this section.
              (g) The operating manual required by paragraph (e) of this section shall be kept in a readily accessible location for all persons required to undergo training under paragraph (f) of this section. The operating manual and records of training shall be available for inspection by the EPA or its delegated enforcement agency upon request.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997; 71 FR 27337, May 10, 2006]

              § 60.55b
              Standards for municipal waste combustor fugitive ash emissions.
              (a) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, no owner or operator of an affected facility shall cause to be discharged to the atmosphere visible emissions of combustion ash from an ash conveying system (including conveyor transfer points) in excess of 5 percent of the observation period (i.e., 9 minutes per 3-hour period), as determined by EPA Reference Method 22 observations as specified in § 60.58b(k), except as provided in paragraphs (b) and (c) of this section.
              (b) The emission limit specified in paragraph (a) of this section does not cover visible emissions discharged inside buildings or enclosures of ash conveying systems; however, the emission limit specified in paragraph (a) of this section does cover visible emissions discharged to the atmosphere from buildings or enclosures of ash conveying systems.
              (c) The provisions specified in paragraph (a) of this section do not apply during maintenance and repair of ash conveying systems.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997]

              § 60.56b
              Standards for air curtain incinerators.
              On and after the date on which the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, the owner or operator of an air curtain incinerator with the capacity to combust greater than 250 tons per day of municipal solid waste and that combusts a fuel feed stream composed of 100 percent yard waste and no other municipal solid waste materials shall at no time cause to be discharged into the atmosphere from that incinerator any gases that exhibit greater than 10-percent opacity (6-minute average), except that an opacity level of up to 35 percent (6-minute average) is permitted during startup periods during the first 30 minutes of operation of the unit.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997]

              § 60.57b
              Siting requirements.

              (a) The owner or operator of an affected facility shall prepare a materials separation plan, as defined in § 60.51b, for the affected facility and its service area, and shall comply with the requirements specified in paragraphs (a)(1) through (a)(10) of this section. The initial application is defined as representing a good faith submittal as determined by EPA.
              (1) The owner or operator shall prepare a preliminary draft materials separation plan and shall make the plan available to the public as specified in paragraphs (a)(1)(i) and (a)(1)(ii) of this section.
              (i) The owner or operator shall distribute the preliminary draft materials separation plan to the principal public libraries in the area where the affected facility is to be constructed.
              (ii) The owner or operator shall publish a notification of a public meeting in the principal newspaper(s) serving the area where the affected facility is to be constructed and where the waste treated by the affected facility will primarily be collected. As a minimum, the notification shall include the information specified in paragraphs (a)(1)(ii)(A) through (a)(1)(ii)(D) of this section.
              (A) The date, time, and location of the public meeting.
              (B) The location of the public libraries where the preliminary draft materials separation plan may be found, including normal business hours of the libraries.
              (C) An agenda of the issues to be discussed at the public meeting.
              (D) The dates that the public comment period on the preliminary draft materials separation plan begins and ends.
              (2) The owner or operator shall conduct a public meeting, accept comments on the preliminary draft materials separation plan, and comply with the requirements specified in paragraphs (a)(2)(i) through (a)(2)(iv) of this section.
              (i) The public meeting shall be conducted in the county where the affected facility is to be located.
              (ii) The public meeting shall be scheduled to occur 30 days or more after making the preliminary draft materials separation plan available to the public as specified under paragraph (a)(1) of this section.
              (iii) Suggested issues to be addressed at the public meeting are listed in paragraphs (a)(2)(iii)(A) through (a)(2)(iii)(H) of this section.
              (A) The expected size of the service area for the affected facility.
              (B) The amount of waste generation anticipated for the service area.
              (C) The types and estimated amounts of materials proposed for separation.
              (D) The methods proposed for materials separation.
              (E) The amount of residual waste to be disposed.
              (F) Alternate disposal methods for handling the residual waste.
              (G) Identification of the location(s) where responses to public comment on the preliminary draft materials separation plan will be available for inspection, as specified in paragraphs (a)(3) and (a)(4) of this section.
              (H) Identification of the locations where the final draft materials separation plan will be available for inspection, as specified in paragraph (a)(7).
              (iv) Nothing in this section shall preclude an owner or operator from combining this public meeting with any other public meeting required as part of any other Federal, State, or local permit review process except the public meeting required under paragraph (b)(4) of this section.
              (3) Following the public meeting required by paragraph (a)(2) of this section, the owner or operator shall prepare responses to the comments received at the public meeting.
              (4) The owner or operator shall make the document summarizing responses to public comments available to the public (including distribution to the principal public libraries used to announce the meeting) in the service area where the affected facility is to be located.
              (5) The owner or operator shall prepare a final draft materials separation plan for the affected facility considering the public comments received at the public meeting.

              (6) As required under § 60.59b(a), the owner or operator shall submit to EPA a copy of the notification of the public meeting, a transcript of the public meeting, the document summarizing responses to public comments, and copies of both the preliminary and final draft materials separation plans on or before the time the facility's application for a construction permit is submitted under 40 CFR part 51, subpart I, or part 52, as applicable.
              (7) As part of the distribution of the siting analysis required under paragraph (b)(3) of this section, the owner or operator shall make the final draft materials separation plan required under paragraph (a)(5) of this section available to the public, as specified in paragraph (b)(3) of this section.
              (8) As part of the public meeting for review of the siting analysis required under paragraph (b)(4) of this section, the owner or operator shall address questions concerning the final draft materials separation plan required by paragraph (a)(5) of this section including discussion of how the final draft materials separation plan has changed from the preliminary draft materials separation plan that was discussed at the first public meeting required by paragraph (a)(2) of this section.
              (9) If the owner or operator receives any comments on the final draft materials separation plan during the public meeting required in paragraph (b)(4) of this section, the owner or operator shall respond to those comments in the document prepared in accordance with paragraph (b)(5) of this section.
              (10) The owner or operator shall prepare a final materials separation plan and shall submit, as required under § 60.59b(b)(5)(ii), the final materials separation plan as part of the initial notification of construction.
              (b) The owner or operator of an affected facility for which the initial application for a construction permit under 40 CFR part 51, subpart I, or part 52, as applicable, is submitted after December 19, 1995 shall prepare a siting analysis in accordance with paragraphs (b)(1) and (b)(2) of this section and shall comply with the requirements specified in paragraphs (b)(3) through (b)(7) of this section.
              (1) The siting analysis shall be an analysis of the impact of the affected facility on ambient air quality, visibility, soils, and vegetation.
              (2) The analysis shall consider air pollution control alternatives that minimize, on a site-specific basis, to the maximum extent practicable, potential risks to the public health or the environment.
              (3) The owner or operator shall make the siting analysis and final draft materials separation plan required by paragraph (a)(5) of this section available to the public as specified in paragraphs (b)(3)(i) and (b)(3)(ii) of this section.
              (i) The owner or operator shall distribute the siting analysis and final draft materials separation plan to the principal public libraries in the area where the affected facility is to be constructed.
              (ii) The owner or operator shall publish a notification of a public meeting in the principal newspaper(s) serving the area where the affected facility is to be constructed and where the waste treated by the affected facility will primarily be collected. As a minimum, the notification shall include the information specified in paragraphs (b)(3)(ii)(A) through (b)(3)(ii)(D) of this section.
              (A) The date, time, and location of the public meeting.
              (B) The location of the public libraries where the siting analyses and final draft materials separation plan may be found, including normal business hours.
              (C) An agenda of the issues to be discussed at the public meeting.
              (D) The dates that the public comment period on the siting analyses and final draft materials separation plan begins and ends.
              (4) The owner or operator shall conduct a public meeting and accept comments on the siting analysis and the final draft materials separation plan required under paragraph (a)(5) of this section. The public meeting shall be conducted in the county where the affected facility is to be located and shall be scheduled to occur 30 days or more after making the siting analysis available to the public as specified under paragraph (b)(3) of this section.
              (5) The owner or operator shall prepare responses to the comments on the siting analysis and the final draft materials separation plan that are received at the public meeting.

              (6) The owner or operator shall make the document summarizing responses to public comments available to the public (including distribution to all public libraries) in the service area where the affected facility is to be located.
              (7) As required under § 60.59b(b)(5), the owner or operator shall submit a copy of the notification of the public meeting, a transcript of the public meeting, the document summarizing responses to public comments, and the siting analysis as part of the initial notification of construction.
              (c) The owner or operator of an affected facility for which construction is commenced after September 20, 1994 shall prepare a siting analysis in accordance with 40 CFR part 51, subpart I, or part 52, as applicable, and shall submit the siting analysis as part of the initial notification of construction. Affected facilities subject to paragraphs (a) and (b) of this section are not subject to this paragraph.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997; 71 FR 27337, May 10, 2006]

              § 60.58b
              Compliance and performance testing.
              (a) The provisions for startup, shutdown, and malfunction are provided in paragraphs (a)(1) and (a)(2) of this section.
              (1) Except as provided by § 60.56b, the standards under this subpart apply at all times except during periods of startup, shutdown, and malfunction. Duration of startup, shutdown, or malfunction periods are limited to 3 hours per occurrence, except as provided in paragraph (a)(1)(iii) of this section. During periods of startup, shutdown, or malfunction, monitoring data shall be dismissed or excluded from compliance calculations, but shall be recorded and reported in accordance with the provisions of 40 CFR 60.59b(d)(7).
              (i) The startup period commences when the affected facility begins the continuous burning of municipal solid waste and does not include any warmup period when the affected facility is combusting fossil fuel or other nonmunicipal solid waste fuel, and no municipal solid waste is being fed to the combustor.
              (ii) Continuous burning is the continuous, semicontinuous, or batch feeding of municipal solid waste for purposes of waste disposal, energy production, or providing heat to the combustion system in preparation for waste disposal or energy production. The use of municipal solid waste solely to provide thermal protection of the grate or hearth during the startup period when municipal solid waste is not being fed to the grate is not considered to be continuous burning.
              (iii) For the purpose of compliance with the carbon monoxide emission limits in § 60.53b(a), if a loss of boiler water level control (e.g., boiler waterwall tube failure) or a loss of combustion air control (e.g., loss of combustion air fan, induced draft fan, combustion grate bar failure) is determined to be a malfunction, the duration of the malfunction period is limited to 15 hours per occurrence. During such periods of malfunction, monitoring data shall be dismissed or excluded from compliance calculations, but shall be recorded and reported in accordance with the provisions of § 60.59b(d)(7).
              (2) The opacity limits for air curtain incinerators specified in § 60.56b apply at all times as specified under § 60.56b except during periods of malfunction. Duration of malfunction periods are limited to 3 hours per occurrence.
              (b) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous emission monitoring system for measuring the oxygen or carbon dioxide content of the flue gas at each location where carbon monoxide, sulfur dioxide, nitrogen oxides emissions, or particulate matter (if the owner or operator elects to continuously monitor emissions under paragraph (n) of this section) are monitored and record the output of the system and shall comply with the test procedures and test methods specified in paragraphs (b)(1) through (b)(8) of this section.
              (1) The span value of the oxygen (or 20 percent carbon dioxide) monitor shall be 25 percent oxygen (or 20 percent carbon dioxide).
              (2) The monitor shall be installed, evaluated, and operated in accordance with § 60.13 of subpart A of this part.

              (3) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part.
              (4) The monitor shall conform to Performance Specification 3 in appendix B of this part except for section 2.3 (relative accuracy requirement).
              (5) The quality assurance procedures of appendix F of this part except for section 5.1.1 (relative accuracy test audit) shall apply to the monitor.
              (6) If carbon dioxide is selected for use in diluent corrections, the relationship between oxygen and carbon dioxide levels shall be established during the initial performance test according to the procedures and methods specified in paragraphs (b)(6)(i) through (b)(6)(iv) of this section. This relationship may be reestablished during performance compliance tests.
              (i) The fuel factor equation in Method 3B shall be used to determine the relationship between oxygen and carbon dioxide at a sampling location. Method 3, 3A, or 3B, or as an alternative ASME PTC-19-10-1981—part10, as applicable, shall be used to determine the oxygen concentration at the same location as the carbon dioxide monitor.
              (ii) Samples shall be taken for at least 30 minutes in each hour.
              (iii) Each sample shall represent a 1-hour average.
              (iv) A minimum of three runs shall be performed.
              (7) The relationship between carbon dioxide and oxygen concentrations that is established in accordance with paragraph (b)(6) of this section shall be submitted to EPA as part of the initial performance test report and, if applicable, as part of the annual test report if the relationship is reestablished during the annual performance test.
              (8) During a loss of boiler water level control or loss of combustion air control malfunction period as specified in paragraph (a)(1)(iii) of this section, a diluent cap of 14 percent for oxygen or 5 percent for carbon dioxide may be used in the emissions calculations for sulfur dioxide and nitrogen oxides.
              (c) Except as provided in paragraph (c)(10) of this section, the procedures and test methods specified in paragraphs (c)(1) through (c)(11) of this section shall be used to determine compliance with the emission limits for particulate matter and opacity under § 60.52b(a)(1) and (a)(2).
              (1) The EPA Reference Method 1 shall be used to select sampling site and number of traverse points.
              (2) The EPA Reference Method 3, 3A or 3B, or as an alternative ASME PTC-19-10-1981—part10, as applicable, shall be used for gas analysis.
              (3) EPA Reference Method 5 shall be used for determining compliance with the particulate matter emission limit. The minimum sample volume shall be 1.7 cubic meters. The probe and filter holder heating systems in the sample train shall be set to provide a gas temperature no greater than 160 °C. An oxygen or carbon dioxide measurement shall be obtained simultaneously with each Method 5 run.
              (4) The owner or operator of an affected facility may request that compliance with the particulate matter emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (5) As specified under § 60.8 of subpart A of this part, all performance tests shall consist of three test runs. The average of the particulate matter emission concentrations from the three test runs is used to determine compliance.
              (6) In accordance with paragraphs (c)(7) and (c)(11) of this section, EPA Reference Method 9 shall be used for determining compliance with the opacity limit except as provided under § 60.11(e) of subpart A of this part.
              (7) The owner or operator of an affected facility shall conduct an initial performance test for particulate matter emissions and opacity as required under § 60.8 of subpart A of this part.
              (8) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous opacity monitoring system for measuring opacity and shall follow the methods and procedures specified in paragraphs (c)(8)(i) through (c)(8)(iv) of this section.

              (i) The output of the continuous opacity monitoring system shall be recorded on a 6-minute average basis.

              (ii) The continuous opacity monitoring system shall be installed, evaluated, and operated in accordance with § 60.13 of subpart A of this part.
              (iii) The continuous opacity monitoring system shall conform to Performance Specification 1 in appendix B of this part.
              (iv) The initial performance evaluation shall be completed no later than 180 days after the date of the initial startup of the municipal waste combustor unit, as specified under § 60.8 of subpart A of this part.
              (9) Following the date that the initial performance test for particulate matter is completed or is required to be completed under § 60.8 of subpart A of this part for an affected facility, the owner or operator shall conduct a performance test for particulate matter on a calendar year basis (no less than 9 calendar months and no more than 15 calendar months following the previous performance test; and must complete five performance tests in each 5-year calendar period).
              (10) In place of particulate matter testing with EPA Reference Method 5, an owner or operator may elect to install, calibrate, maintain, and operate a continuous emission monitoring system for monitoring particulate matter emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who elects to continuously monitor particulate matter emissions instead of conducting performance testing using EPA Method 5 shall install, calibrate, maintain, and operate a continuous emission monitoring system and shall comply with the requirements specified in paragraphs (c)(10)(i) through (c)(10)(xiv) of this section. The owner or operator who elects to continuously monitor particulate matter emissions instead of conducting performance testing using EPA Method 5 is not required to complete performance testing for particulate matter as specified in paragraph (c)(9) of this section and is not required to continuously monitor opacity as specified in paragraph (c)(8) of this section.
              (i) Notify the Administrator one month before starting use of the system.
              (ii) Notify the Administrator one month before stopping use of the system.
              (iii) The monitor shall be installed, evaluated, and operated in accordance with § 60.13 of subpart A of this part.
              (iv) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of the continuous monitoring system if the owner or operator was previously determining compliance by Method 5 performance tests, whichever is later.
              (v) The owner or operator of an affected facility may request that compliance with the particulate matter emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (vi) The owner or operator of an affected facility shall conduct an initial performance test for particulate matter emissions as required under § 60.8 of subpart A of this part. Compliance with the particulate matter emission limit shall be determined by using the continuous emission monitoring system specified in paragraph (c)(10) of this section to measure particulate matter and calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19, section 12.4.1.
              (vii) Compliance with the particulate matter emission limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emission concentrations using continuous emission monitoring system outlet data.

              (viii) After April 28, 2008, at a minimum, valid continuous monitoring system hourly averages shall be obtained as specified in paragraphs (c)(10)(viii)(A) and (c)(10)(viii)(B) for at least 90 percent of the operating hours per calendar quarter and 95 percent of the operating hours per calendar year that the affected facility is combusting municipal solid waste.

              (A) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
              (B) Each particulate matter 1-hour arithmetic average shall be corrected to 7 percent oxygen on an hourly basis using the 1-hour arithmetic average of the oxygen (or carbon dioxide) continuous emission monitoring system data.
              (ix) The 1-hour arithmetic averages required under paragraph (c)(10)(vii) of this section shall be expressed in milligrams per dry standard cubic meter corrected to 7 percent oxygen (dry basis) and shall be used to calculate the 24-hour daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
              (x) All valid continuous emission monitoring system data shall be used in calculating average emission concentrations even if the minimum continuous emission monitoring system data requirements of paragraph (c)(10)(viii) of this section are not met.
              (xi) The continuous emission monitoring system shall be operated according to Performance Specification 11 in appendix B of this part.
              (xii) During each relative accuracy test run of the continuous emission monitoring system required by Performance Specification 11 in appendix B of this part, particulate matter and oxygen (or carbon dioxide) data shall be collected concurrently (or within a 30- to 60-minute period) by both the continuous emission monitors and the test methods specified in paragraphs (c)(10)(xii)(A) and (c)(10)(xii)(B) of this section.
              (A) For particulate matter, EPA Reference Method 5 shall be used.
              (B) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or 3B, as applicable shall be used.
              (xiii) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part.
              (xiv) When particulate matter emissions data are not obtained because of continuous emission monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 to provide, as necessary, valid emissions data for a minimum of 90 percent of the hours per calendar quarter and 95 percent of the hours per calendar year that the affected facility is operated and combusting municipal solid waste.
              (11) Following the date that the initial performance test for opacity is completed or is required to be completed under § 60.8 of subpart A of this part for an affected facility, the owner or operator shall conduct a performance test for opacity on an annual basis (no less than 9 calendar months and no more than 15 calendar months following the previous performance test; and must complete five performance tests in each 5-year calendar period) using the test method specified in paragraph (c)(6) of this section.
              (d) The procedures and test methods specified in paragraphs (d)(1) and (d)(2) of this section shall be used to determine compliance with the emission limits for cadmium, lead, and mercury under § 60.52b(a).
              (1) The procedures and test methods specified in paragraphs (d)(1)(i) through (d)(1)(ix) of this section shall be used to determine compliance with the emission limits for cadmium and lead under § 60.52b(a) (3) and (4).
              (i) The EPA Reference Method 1 shall be used for determining the location and number of sampling points.
              (ii) The EPA Reference Method 3, 3A, or 3B, or as an alternative ASME PTC-19-10-1981—part10, as applicable, shall be used for flue gas analysis.
              (iii) The EPA Reference Method 29 shall be used for determining compliance with the cadmium and lead emission limits.
              (iv) An oxygen or carbon dioxide measurement shall be obtained simultaneously with each Method 29 test run for cadmium and lead required under paragraph (d)(1)(iii) of this section.

              (v) The owner or operator of an affected facility may request that compliance with the cadmium or lead emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (vi) All performance tests shall consist of a minimum of three test runs conducted under representative full load operating conditions. The average of the cadmium or lead emission concentrations from three test runs or more shall be used to determine compliance.
              (vii) Following the date of the initial performance test or the date on which the initial performance test is required to be completed under § 60.8 of subpart A of this part, the owner or operator of an affected facility shall conduct a performance test for compliance with the emission limits for cadmium and lead on a calendar year basis (no less than 9 calendar months and no more than 15 calendar months following the previous performance test; and must complete five performance tests in each 5-year calendar period).
              (viii)-(ix) [Reserved]
              (2) The procedures and test methods specified in paragraphs (d)(2)(i) through (d)(2)(xi) of this section shall be used to determine compliance with the mercury emission limit under § 60.52b(a)(5).
              (i) The EPA Reference Method 1 shall be used for determining the location and number of sampling points.
              (ii) The EPA Reference Method 3, 3A, or 3B, or as an alternative ASME PTC-19-10-1981—part10, as applicable, shall be used for flue gas analysis.
              (iii) The EPA Reference Method 29 or as an alternative ASTM D6784-02 shall be used to determine the mercury emission concentration. The minimum sample volume when using Method 29 as an alternative ASTM D6784-02 for mercury shall be 1.7 cubic meters.
              (iv) An oxygen (or carbon dioxide) measurement shall be obtained simultaneously with each Method 29 or as an alternative ASTM D6784-02 test run for mercury required under paragraph (d)(2)(iii) of this section.
              (v) The percent reduction in the potential mercury emissions (%PHg) is computed using equation 1:

                ER19de95.001

                where:

                %PHg = percent reduction of the potential mercury emissions achieved.
                Ei = potential mercury emission concentration measured at the control device inlet, corrected to 7 percent oxygen (dry basis).
                Eo = controlled mercury emission concentration measured at the mercury control device outlet, corrected to 7 percent oxygen (dry basis).

              (vi) All performance tests shall consist of a minimum of three test runs conducted under representative full load operating conditions. The average of the mercury emission concentrations or percent reductions from three test runs or more is used to determine compliance.
              (vii) The owner or operator of an affected facility may request that compliance with the mercury emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (viii) The owner or operator of an affected facility shall conduct an initial performance test for mercury emissions as required under § 60.8 of subpart A of this part.
              (ix) Following the date that the initial performance test for mercury is completed or is required to be completed under § 60.8 of subpart A of this part, the owner or operator of an affected facility shall conduct a performance test for mercury emissions on a calendar year basis (no less than 9 calendar months and no more than 15 calendar months from the previous performance test; and must complete five performance tests in each 5-year calendar period).
              (x) [Reserved]
              (xi) The owner or operator of an affected facility where activated carbon injection is used to comply with the mercury emission limit shall follow the procedures specified in paragraph (m) of this section for measuring and calculating carbon usage.

              (3) In place of cadmium and lead testing with EPA Reference Method 29 as an alternative ASTM D6784-02, an owner or operator may elect to install, calibrate, maintain, and operate a continuous emission monitoring system for monitoring cadmium and lead emissions discharged to the atmosphere and record the output of the system according to the provisions of paragraphs (n) and (o) of this section.
              (4) In place of mercury testing with EPA Reference Method 29 or as an alternative ASTM D6784-02, an owner or operator may elect to install, calibrate, maintain, and operate a continuous emission monitoring system or a continuous automated sampling system for monitoring mercury emissions discharged to the atmosphere and record the output of the system according to the provisions of paragraphs (n) and (o) of this section, or paragraphs (p) and (q) of this section, as appropriate. The owner or operator who elects to continuously monitor mercury in place of mercury testing with EPA Reference Method 29 or as an alternative ASTM D6784-02 is not required to complete performance testing for mercury as specified in paragraph (d)(2)(ix) of this section.
              (e) The procedures and test methods specified in paragraphs (e)(1) through (e)(14) of this section shall be used for determining compliance with the sulfur dioxide emission limit under § 60.52b(b)(1).
              (1) The EPA Reference Method 19, section 4.3, shall be used to calculate the daily geometric average sulfur dioxide emission concentration.
              (2) The EPA Reference Method 19, section 5.4, shall be used to determine the daily geometric average percent reduction in the potential sulfur dioxide emission concentration.
              (3) The owner or operator of an affected facility may request that compliance with the sulfur dioxide emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (4) The owner or operator of an affected facility shall conduct an initial performance test for sulfur dioxide emissions as required under § 60.8 of subpart A of this part. Compliance with the sulfur dioxide emission limit (concentration or percent reduction) shall be determined by using the continuous emission monitoring system specified in paragraph (e)(5) of this section to measure sulfur dioxide and calculating a 24-hour daily geometric average emission concentration or a 24-hour daily geometric average percent reduction using EPA Reference Method 19, sections 4.3 and 5.4, as applicable.
              (5) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous emission monitoring system for measuring sulfur dioxide emissions discharged to the atmosphere and record the output of the system.
              (6) Following the date that the initial performance test for sulfur dioxide is completed or is required to be completed under § 60.8 of subpart A of this part, compliance with the sulfur dioxide emission limit shall be determined based on the 24-hour daily geometric average of the hourly arithmetic average emission concentrations using continuous emission monitoring system outlet data if compliance is based on an emission concentration, or continuous emission monitoring system inlet and outlet data if compliance is based on a percent reduction.
              (7) At a minimum, valid continuous monitoring system hourly averages shall be obtained as specified in paragraphs (e)(7)(i) and (e)(7)(ii) for 90 percent of the operating hours per calendar quarter and 95 percent of the operating days per calendar year that the affected facility is combusting municipal solid waste.
              (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
              (ii) Each sulfur dioxide 1-hour arithmetic average shall be corrected to 7 percent oxygen on an hourly basis using the 1-hour arithmetic average of the oxygen (or carbon dioxide) continuous emission monitoring system data.

              (8) The 1-hour arithmetic averages required under paragraph (e)(6) of this section shall be expressed in parts per million corrected to 7 percent oxygen (dry basis) and used to calculate the 24-hour daily geometric average emission concentrations and daily geometric average emission percent reductions. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
              (9) All valid continuous emission monitoring system data shall be used in calculating average emission concentrations and percent reductions even if the minimum continuous emission monitoring system data requirements of paragraph (e)(7) of this section are not met.
              (10) The procedures under § 60.13 of subpart A of this part shall be followed for installation, evaluation, and operation of the continuous emission monitoring system.
              (11) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the municipal waste combustor as specified under § 60.8 of subpart A of this part.
              (12) The continuous emission monitoring system shall be operated according to Performance Specification 2 in appendix B of this part. For sources that have actual inlet emissions less than 100 parts per million dry volume, the relative accuracy criterion for inlet sulfur dioxide continuous emission monitoring systems should be no greater than 20 percent of the mean value of the reference method test data in terms of the units of the emission standard, or 5 parts per million dry volume absolute value of the mean difference between the reference method and the continuous emission monitoring systems, whichever is greater.
              (i) During each relative accuracy test run of the continuous emission monitoring system required by Performance Specification 2 in appendix B of this part, sulfur dioxide and oxygen (or carbon dioxide) data shall be collected concurrently (or within a 30- to 60-minute period) by both the continuous emission monitors and the test methods specified in paragraphs (e)(12)(i)(A) and (e)(12)(i)(B) of this section.
              (A) For sulfur dioxide, EPA Reference Method 6, 6A, or 6C, or as an alternative ASME PTC-19-10-1981—part10, shall be used.
              (B) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or 3B, or as an alternative ASME PTC-19-10-1981—part10, as applicable, shall be used.
              (ii) The span value of the continuous emissions monitoring system at the inlet to the sulfur dioxide control device shall be 125 percent of the maximum estimated hourly potential sulfur dioxide emissions of the municipal waste combustor unit. The span value of the continuous emission monitoring system at the outlet of the sulfur dioxide control device shall be 50 percent of the maximum estimated hourly potential sulfur dioxide emissions of the municipal waste combustor unit.
              (13) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 1 in appendix F of this part.
              (14) When sulfur dioxide emissions data are not obtained because of continuous emission monitoring system breakdowns, repairs, calibration checks, and/or zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by EPA or EPA Reference Method 19 to provide, as necessary, valid emissions data for a minimum of 90 percent of the hours per calendar quarter and 95 percent of the hours per calendar year that the affected facility is operated and combusting municipal solid waste.
              (f) The procedures and test methods specified in paragraphs (f)(1) through (f)(8) of this section shall be used for determining compliance with the hydrogen chloride emission limit under § 60.52b(b)(2).
              (1) The EPA Reference Method 26 or 26A, as applicable, shall be used to determine the hydrogen chloride emission concentration. The minimum sampling time shall be 1 hour.
              (2) An oxygen (or carbon dioxide) measurement shall be obtained simultaneously with each test run for hydrogen chloride required by paragraph (f)(1) of this section.

              (3) The percent reduction in potential hydrogen chloride emissions (% PHCl) is computed using equation 2:

                ER19de95.002

                where:

                %PHCl = percent reduction of the potential hydrogen chloride emissions achieved.

                Ei = potential hydrogen chloride emission concentration measured at the control device inlet, corrected to 7 percent oxygen (dry basis).

                Eo = controlled hydrogen chloride emission concentration measured at the control device outlet, corrected to 7 percent oxygen (dry basis).

              (4) The owner or operator of an affected facility may request that compliance with the hydrogen chloride emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (5) As specified under § 60.8 of subpart A of this part, all performance tests shall consist of three test runs. The average of the hydrogen chloride emission concentrations or percent reductions from the three test runs is used to determine compliance.
              (6) The owner or operator of an affected facility shall conduct an initial performance test for hydrogen chloride as required under § 60.8 of subpart A of this part.
              (7) Following the date that the initial performance test for hydrogen chloride is completed or is required to be completed under § 60.8 of subpart A of this part, the owner or operator of an affected facility shall conduct a performance test for hydrogen chloride emissions on an annual basis (no more than 12 calendar months following the previous performance test).
              (8) In place of hydrogen chloride testing with EPA Reference Method 26 or 26A, an owner or operator may elect to install, calibrate, maintain, and operate a continuous emission monitoring system for monitoring hydrogen chloride emissions discharged to the atmosphere and record the output of the system according to the provisions of paragraphs (n) and (o) of this section.
              (g) The procedures and test methods specified in paragraphs (g)(1) through (g)(9) of this section shall be used to determine compliance with the limits for dioxin/furan emissions under § 60.52b(c).
              (1) The EPA Reference Method 1 shall be used for determining the location and number of sampling points.
              (2) The EPA Reference Method 3, 3A, or 3B, or as an alternative ASME PTC-19-10-1981—part10, as applicable, shall be used for flue gas analysis.
              (3) The EPA Reference Method 23 shall be used for determining the dioxin/furan emission concentration.
              (i) The minimum sample time shall be 4 hours per test run.
              (ii) An oxygen (or carbon dioxide) measurement shall be obtained simultaneously with each Method 23 test run for dioxins/furans.
              (4) The owner or operator of an affected facility shall conduct an initial performance test for dioxin/furan emissions in accordance with paragraph (g)(3) of this section, as required under § 60.8 of subpart A of this part.
              (5) Following the date that the initial performance test for dioxins/furans is completed or is required to be completed under § 60.8 of subpart A of this part, the owner or operator of an affected facility shall conduct performance tests for dioxin/furan emissions in accordance with paragraph (g)(3) of this section, according to one of the schedules specified in paragraphs (g)(5)(i) through (g)(5)(iii) of this section.
              (i) For affected facilities, performance tests shall be conducted on a calendar year basis (no less than 9 calendar months and no more than 15 calendar months following the previous performance test; and must complete five performance tests in each 5-year calendar period).

              (ii) For the purpose of evaluating system performance to establish new operating parameter levels, testing new technology or control technologies, diagnostic testing, or related activities for the purpose of improving facility performance or advancing the state-of-the-art for controlling facility emissions, the owner or operator of an affected facility that qualifies for the performance testing schedule specified in paragraph (g)(5)(iii) of this section, may test one unit for dioxin/furan and apply the dioxin/furan operating parameters to similarly designed and equipped units on site by meeting the requirements specified in paragraphs (g)(5)(ii)(A) through (g)(5)(ii)(D) of this section.

              (A) Follow the testing schedule established in paragraph (g)(5)(iii) of this section. For example, each year a different affected facility at the municipal waste combustor plant shall be tested, and the affected facilities at the plant shall be tested in sequence (e.g., unit 1, unit 2, unit 3, as applicable).
              (B) Upon meeting the requirements in paragraph (g)(5)(iii) of this section for one affected facility, the owner or operator may elect to apply the average carbon mass feed rate and associated carbon injection system operating parameter levels for dioxin/furan as established in paragraph (m) of this section to similarly designed and equipped units on site.
              (C) Upon testing each subsequent unit in accordance with the testing schedule established in paragraph (g)(5)(iii) of this section, the dioxin/furan and mercury emissions of the subsequent unit shall not exceed the dioxin/furan and mercury emissions measured in the most recent test of that unit prior to the revised operating parameter levels.
              (D) The owner or operator of an affected facility that selects to follow the performance testing schedule specified in paragraph (g)(5)(iii) of this section and apply the carbon injection system operating parameters to similarly designed and equipped units on site shall follow the procedures specified in § 60.59b(g)(4) for reporting.
              (iii) Where all performance tests over a 2-year period indicate that dioxin/furan emissions are less than or equal to 7 nanograms per dry standard cubic meter (total mass) for all affected facilities located within a municipal waste combustor plant, the owner or operator of the municipal waste combustor plant may elect to conduct annual performance tests for one affected facility (i.e., unit) per year at the municipal waste combustor plant. At a minimum, a performance test for dioxin/furan emissions shall be conducted on a calendar year basis (no less than 9 calendar months and no more than 15 months following the previous performance test; and must complete five performance tests in each 5-year calendar period) for one affected facility at the municipal waste combustor plant. Each year a different affected facility at the municipal waste combustor plant shall be tested, and the affected facilities at the plant shall be tested in sequence (e.g., unit 1, unit 2, unit 3, as applicable). If each annual performance test continues to indicate a dioxin/furan emission level less than or equal to 7 nanograms per dry standard cubic meter (total mass), the owner or operator may continue conducting a performance test on only one affected facility per calendar year. If any annual performance test indicates either a dioxin/furan emission level greater than 7 nanograms per dry standard cubic meter (total mass), performance tests shall thereafter be conducted annually on all affected facilities at the plant until and unless all annual performance tests for all affected facilities at the plant over a 2-year period indicate a dioxin/furan emission level less than or equal to 7 nanograms per dry standard cubic meter (total mass).
              (6) The owner or operator of an affected facility that selects to follow the performance testing schedule specified in paragraph (g)(5)(iii) of this section shall follow the procedures specified in § 60.59b(g)(4) for reporting the selection of this schedule.
              (7) The owner or operator of an affected facility where activated carbon is used shall follow the procedures specified in paragraph (m) of this section for measuring and calculating the carbon usage rate.
              (8) The owner or operator of an affected facility may request that compliance with the dioxin/furan emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (9) As specified under § 60.8 of subpart A of this part, all performance tests shall consist of three test runs. The average of the dioxin/furan emission concentrations from the three test runs is used to determine compliance.

              (10) In place of dioxin/furan sampling and testing with EPA Reference Method 23, an owner or operator may elect to sample dioxin/furan by installing, calibrating, maintaining, and operating a continuous automated sampling system for monitoring dioxin/furan emissions discharged to the atmosphere, recording the output of the system, and analyzing the sample using EPA Method 23. This option to use a continuous automated sampling system takes effect on the date a final performance specification applicable to dioxin/furan from monitors is published in the Federal Register or the date of approval of a site-specific monitoring plan. The owner or operator of an affected facility who elects to continuously sample dioxin/furan emissions instead of sampling and testing using EPA Method 23 shall install, calibrate, maintain, and operate a continuous automated sampling system and shall comply with the requirements specified in paragraphs (p) and (q) of this section.
              (h) The procedures and test methods specified in paragraphs (h)(1) through (h)(12) of this section shall be used to determine compliance with the nitrogen oxides emission limit for affected facilities under § 60.52b(d).
              (1) The EPA Reference Method 19, section 4.1, shall be used for determining the daily arithmetic average nitrogen oxides emission concentration.
              (2) The owner or operator of an affected facility may request that compliance with the nitrogen oxides emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (3) The owner or operator of an affected facility subject to the nitrogen oxides limit under § 60.52b(d) shall conduct an initial performance test for nitrogen oxides as required under § 60.8 of subpart A of this part. Compliance with the nitrogen oxides emission limit shall be determined by using the continuous emission monitoring system specified in paragraph (h)(4) of this section for measuring nitrogen oxides and calculating a 24-hour daily arithmetic average emission concentration using EPA Reference Method 19, section 4.1.
              (4) The owner or operator of an affected facility subject to the nitrogen oxides emission limit under § 60.52b(d) shall install, calibrate, maintain, and operate a continuous emission monitoring system for measuring nitrogen oxides discharged to the atmosphere, and record the output of the system.
              (5) Following the date that the initial performance test for nitrogen oxides is completed or is required to be completed under § 60.8 of subpart A of this part, compliance with the emission limit for nitrogen oxides required under § 60.52b(d) shall be determined based on the 24-hour daily arithmetic average of the hourly emission concentrations using continuous emission monitoring system outlet data.
              (6) At a minimum, valid continuous emission monitoring system hourly averages shall be obtained as specified in paragraphs (h)(6)(i) and (h)(6)(ii) of this section for 90 percent of the operating hours per calendar quarter and for 95 percent of the operating hours per calendar year that the affected facility is combusting municipal solid waste.
              (i) At least 2 data points per hour shall be used to calculate each 1-hour arithmetic average.
              (ii) Each nitrogen oxides 1-hour arithmetic average shall be corrected to 7 percent oxygen on an hourly basis using the 1-hour arithmetic average of the oxygen (or carbon dioxide) continuous emission monitoring system data.
              (7) The 1-hour arithmetic averages required by paragraph (h)(5) of this section shall be expressed in parts per million by volume (dry basis) and used to calculate the 24-hour daily arithmetic average concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
              (8) All valid continuous emission monitoring system data must be used in calculating emission averages even if the minimum continuous emission monitoring system data requirements of paragraph (h)(6) of this section are not met.

              (9) The procedures under § 60.13 of subpart A of this part shall be followed for installation, evaluation, and operation of the continuous emission monitoring system. The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the municipal waste combustor unit, as specified under § 60.8 of subpart A of this part.
              (10) The owner or operator of an affected facility shall operate the continuous emission monitoring system according to Performance Specification 2 in appendix B of this part and shall follow the procedures and methods specified in paragraphs (h)(10)(i) and (h)(10)(ii) of this section.
              (i) During each relative accuracy test run of the continuous emission monitoring system required by Performance Specification 2 of appendix B of this part, nitrogen oxides and oxygen (or carbon dioxide) data shall be collected concurrently (or within a 30- to 60-minute period) by both the continuous emission monitors and the test methods specified in paragraphs (h)(10)(i)(A) and (h)(10)(i)(B) of this section.
              (A) For nitrogen oxides, EPA Reference Method 7, 7A, 7C, 7D, or 7E shall be used.
              (B) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or 3B, or as an alternative ASME PTC-19-10-1981—part10, as applicable, shall be used.
              (ii) The span value of the continuous emission monitoring system shall be 125 percent of the maximum estimated hourly potential nitrogen oxide emissions of the municipal waste combustor unit.
              (11) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 1 in appendix F of this part.
              (12) When nitrogen oxides continuous emission data are not obtained because of continuous emission monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained using other monitoring systems as approved by EPA or EPA Reference Method 19 to provide, as necessary, valid emissions data for a minimum of 90 percent of the hours per calendar quarter and 95 percent of the hours per calendar year the unit is operated and combusting municipal solid waste.
              (i) The procedures specified in paragraphs (i)(1) through (i)(12) of this section shall be used for determining compliance with the operating requirements under § 60.53b.
              (1) Compliance with the carbon monoxide emission limits in § 60.53b(a) shall be determined using a 4-hour block arithmetic average for all types of affected facilities except mass burn rotary waterwall municipal waste combustors and refuse-derived fuel stokers.
              (2) For affected mass burn rotary waterwall municipal waste combustors and refuse-derived fuel stokers, compliance with the carbon monoxide emission limits in § 60.53b(a) shall be determined using a 24-hour daily arithmetic average.
              (3) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous emission monitoring system for measuring carbon monoxide at the combustor outlet and record the output of the system and shall follow the procedures and methods specified in paragraphs (i)(3)(i) through (i)(3)(iii) of this section.
              (i) The continuous emission monitoring system shall be operated according to Performance Specification 4A in appendix B of this part.
              (ii) During each relative accuracy test run of the continuous emission monitoring system required by Performance Specification 4A in appendix B of this part, carbon monoxide and oxygen (or carbon dioxide) data shall be collected concurrently (or within a 30- to 60-minute period) by both the continuous emission monitors and the test methods specified in paragraphs (i)(3)(ii)(A) and (i)(3)(ii)(B) of this section. For affected facilities subject to the 100 parts per million dry volume carbon monoxide standard, the relative accuracy criterion of 5 parts per million dry volume is calculated as the absolute value of the mean difference between the reference method and continuous emission monitoring systems.
              (A) For carbon monoxide, EPA Reference Method 10, 10A, or 10B shall be used.

              (B) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or 3B, or ASME PTC-19-10-1981—part10 (incorporated by reference, see § 60.17 of subpart A of this part), as applicable, shall be used.

              (iii) The span value of the continuous emission monitoring system shall be 125 percent of the maximum estimated hourly potential carbon monoxide emissions of the municipal waste combustor unit.
              (4) The 4-hour block and 24-hour daily arithmetic averages specified in paragraphs (i)(1) and (i)(2) of this section shall be calculated from 1-hour arithmetic averages expressed in parts per million by volume corrected to 7 percent oxygen (dry basis). The 1-hour arithmetic averages shall be calculated using the data points generated by the continuous emission monitoring system. At least two data points shall be used to calculate each 1-hour arithmetic average.
              (5) The owner or operator of an affected facility may request that compliance with the carbon monoxide emission limit be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (6) The procedures specified in paragraphs (i)(6)(i) through (i)(6)(v) of this section shall be used to determine compliance with load level requirements under § 60.53b(b).
              (i) The owner or operator of an affected facility with steam generation capability shall install, calibrate, maintain, and operate a steam flow meter or a feedwater flow meter; measure steam (or feedwater) flow in kilograms per hour (or pounds per hour) on a continuous basis; and record the output of the monitor. Steam (or feedwater) flow shall be calculated in 4-hour block arithmetic averages.
              (ii) The method included in the “American Society of Mechanical Engineers Power Test Codes: Test Code for Steam Generating Units, Power Test Code 4.1—1964 (R1991)” section 4 (incorporated by reference, see § 60.17 of subpart A of this part) shall be used for calculating the steam (or feedwater) flow required under paragraph (i)(6)(i) of this section. The recommendations in “American Society of Mechanical Engineers Interim Supplement 19.5 on Instruments and Apparatus: Application, partII of Fluid Meters, 6th edition (1971),” chapter 4 (incorporated by reference—see § 60.17 of subpart A of this part) shall be followed for design, construction, installation, calibration, and use of nozzles and orifices except as specified in (i)(6)(iii) of this section.
              (iii) Measurement devices such as flow nozzles and orifices are not required to be recalibrated after they are installed.
              (iv) All signal conversion elements associated with steam (or feedwater flow) measurements must be calibrated according to the manufacturer's instructions before each dioxin/furan performance test, and at least once per year.
              (7) To determine compliance with the maximum particulate matter control device temperature requirements under § 60.53b(c), the owner or operator of an affected facility shall install, calibrate, maintain, and operate a device for measuring on a continuous basis the temperature of the flue gas stream at the inlet to each particulate matter control device utilized by the affected facility. Temperature shall be calculated in 4-hour block arithmetic averages.
              (8) The maximum demonstrated municipal waste combustor unit load shall be determined during the initial performance test for dioxins/furans and each subsequent performance test during which compliance with the dioxin/furan emission limit specified in § 60.52b(c) is achieved. The maximum demonstrated municipal waste combustor unit load shall be the highest 4-hour arithmetic average load achieved during four consecutive hours during the most recent test during which compliance with the dioxin/furan emission limit was achieved. If a subsequent dioxin/furan performance test is being performed on only one affected facility at the MWC plant, as provided in paragraph (g)(5)(iii) of this section, the owner or operator may elect to apply the same maximum municipal waste combustor unit load from the tested facility for all the similarly designed and operated affected facilities at the MWC plant.

              (9) For each particulate matter control device employed at the affected facility, the maximum demonstrated particulate matter control device temperature shall be determined during the initial performance test for dioxins/furans and each subsequent performance test during which compliance with the dioxin/furan emission limit specified in § 60.52b(c) is achieved. The maximum demonstrated particulate matter control device temperature shall be the highest 4-hour arithmetic average temperature achieved at the particulate matter control device inlet during four consecutive hours during the most recent test during which compliance with the dioxin/furan limit was achieved. If a subsequent dioxin/furan performance test is being performed on only one affected facility at the MWC plant, as provided in paragraph (g)(5)(iii) of this section, the owner or operator may elect to apply the same maximum particulate matter control device temperature from the tested facility for all the similarly designed and operated affected facilities at the MWC plant.
              (10) At a minimum, valid continuous emission monitoring system hourly averages shall be obtained as specified in paragraphs (i)(10)(i) and (i)(10)(ii) of this section for at least 90 percent of the operating hours per calendar quarter and 95 percent of the operating hours per calendar year that the affected facility is combusting municipal solid waste.
              (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
              (ii) At a minimum, each carbon monoxide 1-hour arithmetic average shall be corrected to 7 percent oxygen on an hourly basis using the 1-hour arithmetic average of the oxygen (or carbon dioxide) continuous emission monitoring system data.
              (11) All valid continuous emission monitoring system data must be used in calculating the parameters specified under paragraph (i) of this section even if the minimum data requirements of paragraph (i)(10) of this section are not met. When carbon monoxide continuous emission data are not obtained because of continuous emission monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained using other monitoring systems as approved by EPA or EPA Reference Method 10 to provide, as necessary, the minimum valid emission data.
              (12) Quarterly accuracy determinations and daily calibration drift tests for the carbon monoxide continuous emission monitoring system shall be performed in accordance with procedure 1 in appendix F of this part.
              (j) The procedures specified in paragraphs (j)(1) and (j)(2) of this section shall be used for calculating municipal waste combustor unit capacity as defined under § 60.51b.
              (1) For municipal waste combustor units capable of combusting municipal solid waste continuously for a 24-hour period, municipal waste combustor unit capacity shall be calculated based on 24 hours of operation at the maximum charging rate. The maximum charging rate shall be determined as specified in paragraphs (j)(1)(i) and (j)(1)(ii) of this section as applicable.
              (i) For combustors that are designed based on heat capacity, the maximum charging rate shall be calculated based on the maximum design heat input capacity of the unit and a heating value of 12,800 kilojoules per kilogram for combustors firing refuse-derived fuel and a heating value of 10,500 kilojoules per kilogram for combustors firing municipal solid waste that is not refuse-derived fuel.
              (ii) For combustors that are not designed based on heat capacity, the maximum charging rate shall be the maximum design charging rate.

              (2) For batch feed municipal waste combustor units, municipal waste combustor unit capacity shall be calculated as the maximum design amount of municipal solid waste that can be charged per batch multiplied by the maximum number of batches that could be processed in a 24-hour period. The maximum number of batches that could be processed in a 24-hour period is calculated as 24 hours divided by the design number of hours required to process one batch of municipal solid waste, and may include fractional batches (e.g., if one batch requires 16 hours, then 24/16, or 1.5 batches, could be combusted in a 24-hour period). For batch combustors that are designed based on heat capacity, the design heating value of 12,800 kilojoules per kilogram for combustors firing refuse-derived fuel and a heating value of 10,500 kilojoules per kilogram for combustors firing municipal solid waste that is not refuse-derived fuel shall be used in calculating the municipal waste combustor unit capacity in megagrams per day of municipal solid waste.
              (k) The procedures specified in paragraphs (k)(1) through (k)(4) of this section shall be used for determining compliance with the fugitive ash emission limit under § 60.55b.
              (1) The EPA Reference Method 22 shall be used for determining compliance with the fugitive ash emission limit under § 60.55b. The minimum observation time shall be a series of three 1-hour observations. The observation period shall include times when the facility is transferring ash from the municipal waste combustor unit to the area where ash is stored or loaded into containers or trucks.
              (2) The average duration of visible emissions per hour shall be calculated from the three 1-hour observations. The average shall be used to determine compliance with § 60.55b.
              (3) The owner or operator of an affected facility shall conduct an initial performance test for fugitive ash emissions as required under § 60.8 of subpart A of this part.
              (4) Following the date that the initial performance test for fugitive ash emissions is completed or is required to be completed under § 60.8 of subpart A of this part for an affected facility, the owner or operator shall conduct a performance test for fugitive ash emissions on an annual basis (no more than 12 calendar months following the previous performance test).
              (l) The procedures specified in paragraphs (l)(1) through (l)(3) of this section shall be used to determine compliance with the opacity limit for air curtain incinerators under § 60.56b.
              (1) The EPA Reference Method 9 shall be used for determining compliance with the opacity limit.
              (2) The owner or operator of the air curtain incinerator shall conduct an initial performance test for opacity as required under § 60.8 of subpart A of this part.
              (3) Following the date that the initial performance test is completed or is required to be completed under § 60.8 of subpart A of this part, the owner or operator of the air curtain incinerator shall conduct a performance test for opacity on an annual basis (no more than 12 calendar months following the previous performance test).
              (m) The owner or operator of an affected facility where activated carbon injection is used to comply with the mercury emission limit under § 60.52b(a)(5), and/or the dioxin/furan emission limits under § 60.52(b)(c), or the dioxin/furan emission level specified in paragraph (g)(5)(iii) of this section shall follow the procedures specified in paragraphs (m)(1) through (m)(4) of this section.
              (1) During the performance tests for dioxins/furans and mercury, as applicable, the owner or operator shall estimate an average carbon mass feed rate based on carbon injection system operating parameters such as the screw feeder speed, hopper volume, hopper refill frequency, or other parameters appropriate to the feed system being employed, as specified in paragraphs (m)(1)(i) and (m)(1)(ii) of this section.
              (i) An average carbon mass feed rate in kilograms per hour or pounds per hour shall be estimated during the initial performance test for mercury emissions and each subsequent performance test for mercury emissions.
              (ii) An average carbon mass feed rate in kilograms per hour or pounds per hour shall be estimated during the initial performance test for dioxin/furan emissions and each subsequent performance test for dioxin/furan emissions. If a subsequent dioxin/furan performance test is being performed on only one affected facility at the MWC plant, as provided in paragraph (g)(5)(iii) of this section, the owner or operator may elect to apply the same estimated average carbon mass feed rate from the tested facility for all the similarly designed and operated affected facilities at the MWC plant.

              (2) During operation of the affected facility, the carbon injection system operating parameter(s) that are the primary indicator(s) of the carbon mass feed rate (e.g., screw feeder setting) shall be averaged over a block 8-hour period, and the 8-hour block average must equal or exceed the level(s) documented during the performance tests specified under paragraphs (m)(1)(i) and (m)(1)(ii) of this section, except as specified in paragraphs (m)(2)(i) and (m)(2)(ii) of this section.
              (i) During the annual dioxin/furan or mercury performance test and the 2 weeks preceding the annual dioxin/furan or mercury performance test, no limit is applicable for average mass carbon feed rate if the provisions of paragraph (m)(2)(ii) of this section are met.
              (ii) The limit for average mass carbon feed rate may be waived in accordance with permission granted by the Administrator for the purpose of evaluating system performance, testing new technology or control technologies, diagnostic testing, or related activities for the purpose of improving facility performance or advancing the state-of-the-art for controlling facility emissions.
              (3) The owner or operator of an affected facility shall estimate the total carbon usage of the plant (kilograms or pounds) for each calendar quarter by two independent methods, according to the procedures in paragraphs (m)(3)(i) and (m)(3)(ii) of this section.
              (i) The weight of carbon delivered to the plant.
              (ii) Estimate the average carbon mass feed rate in kilograms per hour or pounds per hour for each hour of operation for each affected facility based on the parameters specified under paragraph (m)(1) of this section, and sum the results for all affected facilities at the plant for the total number of hours of operation during the calendar quarter.
              (4) Pneumatic injection pressure or other carbon injection system operational indicator shall be used to provide additional verification of proper carbon injection system operation. The operational indicator shall provide an instantaneous visual and/or audible alarm to alert the operator of a potential interruption in the carbon feed that would not normally be indicated by direct monitoring of carbon mass feed rate (e.g., continuous weight loss feeder) or monitoring of the carbon system operating parameter(s) that are the indicator(s) of carbon mass feed rate (e.g., screw feeder speed). The carbon injection system operational indicator used to provide additional verification of carbon injection system operation, including basis for selecting the indicator and operator response to the indicator alarm, shall be included in section (e)(6) of the site-specific operating manual required under § 60.54b(e) of this subpart.

              (n) In place of periodic manual testing of mercury, cadmium, lead, or hydrogen chloride with EPA Reference Method 26, 26A, 29, or as an alternative ASTM D6784-02 (as applicable), the owner or operator of an affected facility may elect to install, calibrate, maintain, and operate a continuous emission monitoring system for monitoring emissions discharged to the atmosphere and record the output of the system. The option to use a continuous emission monitoring system for mercury takes effect on the date of approval of the site-specific monitoring plan required in paragraph (n)(13) and (o) of this section. The option to use a continuous emission monitoring system for cadmium, lead, or hydrogen chloride takes effect on the date a final performance specification applicable to cadmium, lead, or hydrogen chloride monitor is published in the Federal Register or the date of approval of the site-specific monitoring plan required in paragraphs (n)(13) and (o) of this section. The owner or operator of an affected facility who elects to continuously monitor emissions instead of conducting manual performance testing shall install, calibrate, maintain, and operate a continuous emission monitoring system and shall comply with the requirements specified in paragraphs (n)(1) through (n)(13) of this section.
              (1) Notify the Administrator one month before starting use of the system.
              (2) Notify the Administrator one month before stopping use of the system.
              (3) The monitor shall be installed, evaluated, and operated in accordance with § 60.13 of subpart A of this part.

              (4) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of the continuous monitoring system if the owner or operator was previously determining compliance by Method 26, 26A, 29, or as an alternative ASTM D6784-02 (as applicable) performance tests, whichever is later.
              (5) The owner or operator may request that compliance with the emission limits be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.
              (6) The owner or operator shall conduct an initial performance test for emissions as required under § 60.8 of subpart A of this part. Compliance with the emission limits shall be determined by using the continuous emission monitoring system specified in paragraph (n) of this section to measure emissions and calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19, section 12.4.1.
              (7) Compliance with the emission limits shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emission concentrations using continuous emission monitoring system outlet data.

              (8) Beginning on April 28, 2008 for mercury and on the date two years after final performance specifications for cadmium, lead or hydrogen chloride monitors are published in the Federal Register or the date two years after approval of a site-specific monitoring plan, valid continuous monitoring system hourly averages shall be obtained as specified in paragraphs (n)(8)(i) and (n)(8)(ii) of this section for at least 90 percent of the operating hours per calendar quarter and 95 percent of the operating hours per calendar year that the affected facility is combusting municipal solid waste.
              (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
              (ii) Each 1-hour arithmetic average shall be corrected to 7 percent oxygen on an hourly basis using the 1-hour arithmetic average of the oxygen (or carbon dioxide) continuous emission monitoring system data.
              (9) The 1-hour arithmetic averages required under paragraph (n)(7) of this section shall be expressed in micrograms per dry standard cubic meter for mercury, cadmium, lead and parts per million dry volume for hydrogen chloride corrected to 7 percent oxygen (dry basis) and shall be used to calculate the 24-hour daily arithmetic (block) average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under § 60.13(e)(2) of subpart A of this part.
              (10) All valid continuous emission monitoring system data shall be used in calculating average emission concentrations even if the minimum continuous emission monitoring system data requirements of paragraph (n)(8) of this section are not met.
              (11) The continuous emission monitoring system shall be operated according to the performance specifications in paragraphs (n)(11)(i) through (n)(11)(iii) of this section or the approved site-specific monitoring plan.
              (i) For mercury, Performance Specification 12A in appendix B of this part.
              (ii)-(iii) [Reserved]
              (12) During each relative accuracy test run of the continuous emission monitoring system required by the performance specifications in paragraph (n)(11) of this section, mercury, cadmium, lead, hydrogen chloride, and oxygen (or carbon dioxide) data shall be collected concurrently (or within a 30- to 60-minute period) by both the continuous emission monitors and the test methods specified in paragraphs (n)(12)(i) through (n)(12)(iii) of this section.
              (i) For mercury, cadmium, and lead, EPA Reference Method 29 or as an alternative ASTM D6784-02 shall be used.
              (ii) For hydrogen chloride, EPA Reference Method 26 or 26A shall be used.
              (iii) For oxygen (or carbon dioxide), EPA Reference Method 3, 3A, or 3B, as applicable shall be used.

              (13) The owner or operator who elects to install, calibrate, maintain, and operate a continuous emission monitoring system for mercury, cadmium, lead, or hydrogen chloride must develop and implement a site-specific monitoring plan as specified in paragraph (o) of this section. The owner or operator who relies on a performance specification may refer to that document in addressing applicable procedures and criteria.
              (14) When emissions data are not obtained because of continuous emission monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments, parametric monitoring data shall be obtained by using other monitoring systems as approved by EPA.
              (o) The owner or operator who elects to install, calibrate, maintain, and operate a continuous emission monitoring system for mercury, cadmium, lead, or hydrogen chloride must develop and submit for approval by EPA, a site-specific mercury, cadmium, lead, or hydrogen chloride monitoring plan that addresses the elements and requirements in paragraphs (o)(1) through (o)(7) of this section.

              (1) Installation of the continuous emission monitoring system sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control device).
              (2) Performance and equipment specifications for the sample interface, the pollutant concentration analyzer, and the data collection and reduction system.

              (3) Performance evaluation procedures and acceptance criteria (e.g., calibrations).
              (4) Provisions for periods when the continuous emission monitoring system is out of control as described in paragraphs (o)(4)(i) through (o)(4)(iii) of this section.
              (i) A continuous emission monitoring system is out of control if either of the conditions in paragraphs (o)(4)(i)(A) or (o)(4)(ii)(B) of this section are met.
              (A) The zero (low-level), mid-level (if applicable), or high-level calibration drift exceeds two times the applicable calibration drift specification in the applicable performance specification or in the relevant standard; or

              (B) The continuous emission monitoring system fails a performance test audit (e.g., cylinder gas audit), relative accuracy audit, relative accuracy test audit, or linearity test audit.

              (ii) When the continuous emission monitoring system is out of control as defined in paragraph (o)(4)(i) of this section, the owner or operator of the affected source shall take the necessary corrective action and shall repeat all necessary tests that indicate that the system is out of control. The owner or operator shall take corrective action and conduct retesting until the performance requirements are below the applicable limits. The beginning of the out-of-control period is the hour the owner or operator conducts a performance check (e.g., calibration drift) that indicates an exceedance of the performance requirements established under this part. The end of the out-of-control period is the hour following the completion of corrective action and successful demonstration that the system is within the allowable limits. During the period the continuous emission monitoring system is out of control, recorded data shall not be used in data averages and calculations or to meet any data availability requirements in paragraph (n)(8) of this section.
              (iii) The owner or operator of a continuous emission monitoring system that is out of control as defined in paragraph (o)(4) of this section shall submit all information concerning out-of-control periods, including start and end dates and hours and descriptions of corrective actions taken in the annual or semiannual compliance reports required in § 60.59b(g) or (h).
              (5) Ongoing data quality assurance procedures for continuous emission monitoring systems as described in paragraphs (o)(5)(i) and (o)(5)(ii) of this section.

              (i) Develop and implement a continuous emission monitoring system quality control program. As part of the quality control program, the owner or operator shall develop and submit to EPA for approval, upon request, a site-specific performance evaluation test plan for the continuous emission monitoring system performance evaluation required in paragraph (o)(5)(ii) of this section. In addition, each quality control program shall include, at a minimum, a written protocol that describes procedures for each of the operations described in paragraphs (o)(7)(i)(A) through (o)(7)(i)(F) of this section.
              (A) Initial and any subsequent calibration of the continuous emission monitoring system;
              (B) Determination and adjustment of the calibration drift of the continuous emission monitoring system;
              (C) Preventive maintenance of the continuous emission monitoring system, including spare parts inventory;
              (D) Data recording, calculations, and reporting;
              (E) Accuracy audit procedures, including sampling and analysis methods; and
              (F) Program of corrective action for a malfunctioning continuous emission monitoring system.
              (ii) The performance evaluation test plan shall include the evaluation program objectives, an evaluation program summary, the performance evaluation schedule, data quality objectives, and both an internal and external quality assurance program. Data quality objectives are the pre-evaluation expectations of precision, accuracy, and completeness of data. The internal quality assurance program shall include, at a minimum, the activities planned by routine operators and analysts to provide an assessment of continuous emission monitoring system performance, for example, plans for relative accuracy testing using the appropriate reference method in § 60.58b(n)(12) of this section. The external quality assurance program shall include, at a minimum, systems audits that include the opportunity for on-site evaluation by the Administrator of instrument calibration, data validation, sample logging, and documentation of quality control data and field maintenance activities.
              (6) Conduct a performance evaluation of each continuous emission monitoring system in accordance with the site-specific monitoring plan.
              (7) Operate and maintain the continuous emission monitoring system in continuous operation according to the site-specific monitoring plan.

              (p) In place of periodic manual testing of dioxin/furan or mercury with EPA Reference Method 23, 29, or as an alternative ASTM D6784-02 (as applicable), the owner or operator of an affected facility may elect to install, calibrate, maintain, and operate a continuous automated sampling system for determining emissions discharged to the atmosphere. This option takes effect on the date a final performance specification applicable to such continuous automated sampling systems is published in the Federal Register or the date of approval of a site-specific monitoring plan required in paragraphs (p)(10) and (q) of this section. The owner or operator of an affected facility who elects to use a continuous automated sampling system to determine emissions instead of conducting manual performance testing shall install, calibrate, maintain, and operate the sampling system and conduct analyses in compliance with the requirements specified in paragraphs (p)(1) through (p)(12) of this section.
              (1) Notify the Administrator one month before starting use of the system.
              (2) Notify the Administrator one month before stopping use of the system.
              (3) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under § 60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of the continuous monitoring system if the owner or operator was previously determining compliance by manual performance testing using Method 23, 29, or as an alternative ASTM D6784-02 (as applicable), whichever is later.
              (4) The owner or operator may request that compliance with the emission limits be determined using carbon dioxide measurements corrected to an equivalent of 7 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall be established as specified in paragraph (b)(6) of this section.

              (5) The owner or operator shall conduct an initial performance test for emissions as required under § 60.8 of subpart A of this part. Compliance with the emission limits shall be determined by using the continuous automated sampling system specified in paragraph (p) of this section to collect integrated samples and analyze emissions for the time period specified in paragraphs (p)(5)(i) and (ii) of this section.
              (i) For dioxin/furan, the continuous automated sampling system shall collect an integrated sample over each 2-week period. The collected sample shall be analyzed using Method 23.
              (ii) For mercury, the continuous automated sampling system shall collect an integrated sample over each 24-hour daily period and the sample shall be analyzed according to the applicable final performance specification or the approved site-specific monitoring plan required by paragraph (q) of this section.
              (6) Compliance with the emission limits shall be determined based on 2-week emission concentrations for dioxin/furan and on the 24-hour daily emission concentrations for mercury using samples collected at the system outlet. The emission concentrations shall be expressed in nanograms per dry standard cubic meter (total mass) for dioxin/furan and micrograms per dry standard cubic meter for mercury, corrected to 7 percent oxygen (dry basis).

              (7) Beginning on the date two years after the respective final performance specification for continuous automated sampling systems for dioxin/furan or mercury is published in the Federal Register or two years after approval of a site-specific monitoring plan, the continuous automated sampling system must be operated and collect emissions for at least 90 percent of the operating hours per calendar quarter and 95 percent of the operating hours per calendar year that the affected facility is combusting municipal solid waste.
              (8) All valid data shall be used in calculating emission concentrations.
              (9) The continuous automated sampling system shall be operated according to the final performance specification in paragraphs (p)(9)(i) or (p)(9)(ii) of this section or the approved site-specific monitoring plan.
              (i)-(ii) [Reserved]
              (10) The owner or operator who elects to install, calibrate, maintain, and operate a continuous automated sampling system for dioxin/furan or mercury must develop and implement a site-specific monitoring plan as specified in paragraph (q) of this section. The owner or operator who relies on a performance specification may refer to that document in addressing applicable procedures and criteria.
              (11) When emissions data are not obtained because of continuous automated sampling system breakdowns, repairs, quality assurance checks, or adjustments, parametric monitoring data shall be obtained by using other monitoring systems as approved by EPA.
              (q) The owner or operator who elects to install, calibrate, maintain, and operate a continuous automated sampling system for dioxin/furan or mercury must develop and submit for approval by EPA, a site-specific monitoring plan that has sufficient detail to assure the validity of the continuous automated sampling system data and that addresses the elements and requirements in paragraphs (q)(1) through (q)(7) of this section.

              (1) Installation of the continuous automated sampling system sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control device).
              (2) Performance and equipment specifications for the sample interface, the pollutant concentration analytical method, and the data collection system.
              (3) Performance evaluation procedures and acceptance criteria.
              (4) Provisions for periods when the continuous automated sampling system is malfunctioning or is out of control as described in paragraphs (q)(4)(i) through (q)(4)(iii) of this section.

              (i) The site-specific monitoring plan shall identify criteria for determining that the continuous automated sampling system is out of control. This shall include periods when the sampling system is not collecting a representative sample or is malfunctioning, or when the analytical method does not meet site-specific quality criteria established in paragraph (q)(5) of this section.
              (ii) When the continuous automated sampling system is out of control as defined in paragraph (q)(4)(i) of this section, the owner or operator shall take the necessary corrective action and shall repeat all necessary tests that indicate that the system is out of control. The owner or operator shall take corrective action and conduct retesting until the performance requirements are within the applicable limits. The out-of-control period includes all hours that the sampling system was not collecting a representative sample or was malfunctioning, or hours represented by a sample for which the analysis did not meet the relevant quality criteria. Emissions data obtained during an out-of-control period shall not be used in determining compliance with the emission limits or to meet any data availability requirements in paragraph (p)(8) of this section.
              (iii) The owner or operator of a continuous automated sampling system that is out of control as defined in paragraph (q)(4) of this section shall submit all information concerning out-of-control periods, including start and end dates and hours and descriptions of corrective actions taken in the annual or semiannual compliance reports required in § 60.59b(g) or (h).
              (5) Ongoing data quality assurance procedures for continuous automated sampling systems as described in paragraphs (q)(5)(i) and (q)(5)(ii) of this section.
              (i) Develop and implement a continuous automated sampling system and analysis quality control program. As part of the quality control program, the owner or operator shall develop and submit to EPA for approval, upon request, a site-specific performance evaluation test plan for the continuous automated sampling system performance evaluation required in paragraph (q)(5)(ii) of this section. In addition, each quality control program shall include, at a minimum, a written protocol that describes procedures for each of the operations described in paragraphs (q)(7)(i)(A) through (q)(7)(i)(F) of this section.
              (A) Correct placement, installation of the continuous automated sampling system such that the system is collecting a representative sample of gas;
              (B) Initial and subsequent calibration of flow such that the sample collection rate of the continuous automated sampling system is known and verifiable;
              (C) Procedures to assure representative (e.g., proportional or isokinetic) sampling;
              (D) Preventive maintenance of the continuous automated sampling system, including spare parts inventory and procedures for cleaning equipment, replacing sample collection media, or other servicing at the end of each sample collection period;
              (E) Data recording and reporting, including an automated indicator and recording device to show when the continuous automated monitoring system is operating and collecting data and when it is not collecting data;
              (F) Accuracy audit procedures for analytical methods; and
              (G) Program of corrective action for a malfunctioning continuous automated sampling system.

              (ii) The performance evaluation test plan shall include the evaluation program objectives, an evaluation program summary, the performance evaluation schedule, data quality objectives, and both an internal and external quality assurance program. Data quality objectives are the pre-evaluation expectations of precision, accuracy, and completeness of data. The internal quality assurance program shall include, at a minimum, the activities planned by routine operators and analysts to provide an assessment of continuous automated sampling system performance, for example, plans for relative accuracy testing using the appropriate reference method in 60.58b(p)(3), and an assessment of quality of analysis results. The external quality assurance program shall include, at a minimum, systems audits that include the opportunity for on-site evaluation by the Administrator of instrument calibration, data validation, sample logging, and documentation of quality control data and field maintenance activities.

              (6) Conduct a performance evaluation of each continuous automated sampling system in accordance with the site-specific monitoring plan.
              (7) Operate and maintain the continuous automated sampling system in continuous operation according to the site-specific monitoring plan.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45126, Aug. 25, 1997; 65 FR 61753, Oct. 17, 2000; 66 FR 57827, Nov. 16, 2001; 71 FR 27337, May 10, 2006]

              § 60.59b
              Reporting and recordkeeping requirements.
              (a) The owner or operator of an affected facility with a capacity to combust greater than 250 tons per day shall submit, on or before the date the application for a construction permit is submitted under 40 CFR part 51, subpart I, or part 52, as applicable, the items specified in paragraphs (a)(1) through (a)(4) of this section.
              (1) The preliminary and final draft materials separation plans required by § 60.57b(a)(1) and (a)(5).
              (2) A copy of the notification of the public meeting required by § 60.57b(a)(1)(ii).
              (3) A transcript of the public meeting required by § 60.57b(a)(2).
              (4) A copy of the document summarizing responses to public comments required by § 60.57b(a)(3).
              (b) The owner or operator of an affected facility with a capacity to combust greater than 250 tons per day shall submit a notification of construction, which includes the information specified in paragraphs (b)(1) through (b)(5) of this section.
              (1) Intent to construct.
              (2) Planned initial startup date.
              (3) The types of fuels that the owner or operator plans to combust in the affected facility.
              (4) The municipal waste combustor unit capacity, and supporting capacity calculations prepared in accordance with § 60.58b(j).
              (5) Documents associated with the siting requirements under § 60.57b (a) and (b), as specified in paragraphs (b)(5)(i) through (b)(5)(v) of this section.
              (i) The siting analysis required by § 60.57b (b)(1) and (b)(2).
              (ii) The final materials separation plan for the affected facility required by § 60.57b(a)(10).
              (iii) A copy of the notification of the public meeting required by § 60.57b(b)(3)(ii).
              (iv) A transcript of the public meeting required by § 60.57b(b)(4).
              (v) A copy of the document summarizing responses to public comments required by § 60.57b (a)(9) and (b)(5).
              (c) The owner or operator of an air curtain incinerator subject to the opacity limit under § 60.56b shall provide a notification of construction that includes the information specified in paragraphs (b)(1) through (b)(4) of this section.
              (d) The owner or operator of an affected facility subject to the standards under §§ 60.52b, 60.53b, 60.54b, 60.55b, and 60.57b shall maintain records of the information specified in paragraphs (d)(1) through (d)(15) of this section, as applicable, for each affected facility for a period of at least 5 years.
              (1) The calendar date of each record.
              (2) The emission concentrations and parameters measured using continuous monitoring systems as specified under paragraphs (d)(2)(i) and (d)(2)(ii) of this section.
              (i) The measurements specified in paragraphs (d)(2)(i)(A) through (d)(2)(i)(F) of this section shall be recorded and be available for submittal to the Administrator or review on site by an EPA or State inspector.
              (A) All 6-minute average opacity levels as specified under § 60.58b(c).
              (B) All 1-hour average sulfur dioxide emission concentrations as specified under § 60.58b(e).
              (C) All 1-hour average nitrogen oxides emission concentrations as specified under § 60.58b(h).
              (D) All 1-hour average carbon monoxide emission concentrations, municipal waste combustor unit load measurements, and particulate matter control device inlet temperatures as specified under § 60.58b(i).

              (E) For owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, or hydrogen chloride emissions instead of conducting performance testing using EPA manual test methods, all 1-hour average particulate matter, cadmium, lead, mercury, or hydrogen chloride emission concentrations as specified under § 60.58b(n).
              (ii) The average concentrations and percent reductions, as applicable, specified in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(F) of this section shall be computed and recorded, and shall be available for submittal to the Administrator or review on-site by an EPA or State inspector.
              (A) All 24-hour daily geometric average sulfur dioxide emission concentrations and all 24-hour daily geometric average percent reductions in sulfur dioxide emissions as specified under § 60.58b(e).
              (B) All 24-hour daily arithmetic average nitrogen oxides emission concentrations as specified under § 60.58b(h).
              (C) All 4-hour block or 24-hour daily arithmetic average carbon monoxide emission concentrations, as applicable, as specified under § 60.58b(i).
              (D) All 4-hour block arithmetic average municipal waste combustor unit load levels and particulate matter control device inlet temperatures as specified under § 60.58b(i).
              (E) For owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, or hydrogen chloride emissions instead of conducting performance testing using EPA manual test methods, all 24-hour daily arithmetic average particulate matter, cadmium, lead, mercury, or hydrogen chloride emission concentrations as specified under § 60.58b(n).
              (F) For owners and operators who elect to use a continuous automated sampling system to monitor mercury or dioxin/furan instead of conducting performance testing using EPA manual test methods, all integrated 24-hour mercury concentrations or all integrated 2-week dioxin/furan concentrations as specified under § 60.586(p).
              (3) Identification of the calendar dates when any of the average emission concentrations, percent reductions, or operating parameters recorded under paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(F) of this section, or the opacity levels recorded under paragraph (d)(2)(i)(A) of this section are above the applicable limits, with reasons for such exceedances and a description of corrective actions taken.
              (4) For affected facilities that apply activated carbon for mercury or dioxin/furan control, the records specified in paragraphs (d)(4)(i) through (d)(4)(v) of this section.
              (i) The average carbon mass feed rate (in kilograms per hour or pounds per hour) estimated as required under § 60.58b(m)(1)(i) of this section during the initial mercury performance test and all subsequent annual performance tests, with supporting calculations.
              (ii) The average carbon mass feed rate (in kilograms per hour or pounds per hour) estimated as required under § 60.58b(m)(1)(ii) of this section during the initial dioxin/furan performance test and all subsequent annual performance tests, with supporting calculations.
              (iii) The average carbon mass feed rate (in kilograms per hour or pounds per hour) estimated for each hour of operation as required under § 60.58b(m)(3)(ii) of this section, with supporting calculations.
              (iv) The total carbon usage for each calendar quarter estimated as specified by paragraph 60.58b(m)(3) of this section, with supporting calculations.
              (v) Carbon injection system operating parameter data for the parameter(s) that are the primary indicator(s) of carbon feed rate (e.g., screw feeder speed).
              (5) [Reserved]
              (6) Identification of the calendar dates and times (hours) for which valid hourly data specified in paragraphs (d)(6)(i) through (d)(6)(vi) of this section have not been obtained, or continuous automated sampling systems were not operated as specified in paragraph (d)(6)(vii) of this section, including reasons for not obtaining the data and a description of corrective actions taken.
              (i) Sulfur dioxide emissions data;
              (ii) Nitrogen oxides emissions data;
              (iii) Carbon monoxide emissions data;
              (iv) Municipal waste combustor unit load data;
              (v) Particulate matter control device temperature data; and

              (vi) For owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, or hydrogen chloride emissions instead of performance testing by EPA manual test methods, particulate matter, cadmium, lead, mercury, or hydrogen chloride emissions data.
              (vii) For owners and operators who elect to use continuous automated sampling systems for dioxins/furans or mercury as allowed under “60.58b(p) and (q), dates and times when the sampling systems were not operating or were not collecting a valid sample.

              (7) Identification of each occurrence that sulfur dioxide emissions data, nitrogen oxides emissions data, particulate matter emissions data, cadmium emissions data, lead emissions data, mercury emissions data, hydrogen chloride emissions data, or dioxin/furan emissions data (for owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, or hydrogen chloride, or who elect to use continuous automated sampling systems for dioxin/furan or mercury emissions, instead of conducting performance testing using EPA manual test methods) or operational data (i.e., carbon monoxide emissions, unit load, and particulate matter control device temperature) have been excluded from the calculation of average emission concentrations or parameters, and the reasons for excluding the data.
              (8) The results of daily drift tests and quarterly accuracy determinations for sulfur dioxide, nitrogen oxides, and carbon monoxide continuous emission monitoring systems, as required under appendix F of this part, procedure 1.
              (9) The test reports documenting the results of the initial performance test and all annual performance tests listed in paragraphs (d)(9)(i) and (d)(9)(ii) of this section shall be recorded along with supporting calculations.
              (i) The results of the initial performance test and all annual performance tests conducted to determine compliance with the particulate matter, opacity, cadmium, lead, mercury, dioxins/furans, hydrogen chloride, and fugitive ash emission limits.
              (ii) For the initial dioxin/furan performance test and all subsequent dioxin/furan performance tests recorded under paragraph (d)(9)(i) of this section, the maximum demonstrated municipal waste combustor unit load and maximum demonstrated particulate matter control device temperature (for each particulate matter control device).
              (10) An owner or operator who elects to continuously monitor emissions instead of performance testing by EPA manual methods must maintain records specified in paragraphs (10)(i) through (iii) of this section.
              (i) For owners and operators who elect to continuously monitor particulate matter instead of conducting performance testing using EPA manual test methods), as required under appendix F of this part, procedure 2, the results of daily drift tests and quarterly accuracy determinations for particulate matter.
              (ii) For owners and operators who elect to continuously monitor cadmium, lead, mercury, or hydrogen chloride instead of conducting EPA manual test methods, the results of all quality evaluations, such as daily drift tests and periodic accuracy determinations, specified in the approved site-specific performance evaluation test plan required by § 60.58b(o)(5).
              (iii) For owners and operators who elect to use continuous automated sampling systems for dioxin/furan or mercury, the results of all quality evaluations specified in the approved site-specific performance evaluation test plan required by § 60.58b(q)(5).
              (11) For each affected facility subject to the siting provisions under § 60.57b, the siting analysis, the final materials separation plan, a record of the location and date of the public meetings, and the documentation of the responses to public comments received at the public meetings.
              (12) The records specified in paragraphs (d)(12)(i) through (d)(12)(iv) of this section.

              (i) Records showing the names of the municipal waste combustor chief facility operator, shift supervisors, and control room operators who have been provisionally certified by the American Society of Mechanical Engineers or an equivalent State-approved certification program as required by § 60.54b(a) including the dates of initial and renewal certifications and documentation of current certification.

              (ii) Records showing the names of the municipal waste combustor chief facility operator, shift supervisors, and control room operators who have been fully certified by the American Society of Mechanical Engineers or an equivalent State-approved certification program as required by § 60.54b(b) including the dates of initial and renewal certifications and documentation of current certification.
              (iii) Records showing the names of the municipal waste combustor chief facility operator, shift supervisors, and control room operators who have completed the EPA municipal waste combustor operator training course or a State-approved equivalent course as required by § 60.54b(d) including documentation of training completion.
              (iv) Records of when a certified operator is temporarily off site. Include two main items:
              (A) If the certified chief facility operator and certified shift supervisor are off site for more than 12 hours, but for 2 weeks or less, and no other certified operator is on site, record the dates that the certified chief facility operator and certified shift supervisor were off site.
              (B) When all certified chief facility operators and certified shift supervisors are off site for more than 2 weeks and no other certified operator is on site, keep records of four items:
              (1) Time of day that all certified persons are off site.
              (2) The conditions that cause those people to be off site.
              (3) The corrective actions taken by the owner or operator of the affected facility to ensure a certified chief facility operator or certified shift supervisor is on site as soon as practicable.
              (4) Copies of the written reports submitted every 4 weeks that summarize the actions taken by the owner or operator of the affected facility to ensure that a certified chief facility operator or certified shift supervisor will be on site as soon as practicable.
              (13) Records showing the names of persons who have completed a review of the operating manual as required by § 60.54b(f) including the date of the initial review and subsequent annual reviews.
              (14) For affected facilities that apply activated carbon, identification of the calendar dates when the average carbon mass feed rates recorded under paragraph (d)(4)(iii) of this section were less than either of the hourly carbon feed rates estimated during performance tests for mercury emissions and recorded under paragraphs (d)(4)(i) and (d)(4)(ii) of this section, respectively, with reasons for such feed rates and a description of corrective actions taken. For affected facilities that apply activated carbon, identification of the calendar dates when the average carbon mass feed rates recorded under paragraph (d)(4)(iii) of this section were less than either of the hourly carbon feed rates estimated during performance tests for dioxin/furan emissions and recorded under paragraphs (d)(4)(i) and (d)(4)(ii) of this section, respectively, with reasons for such feed rates and a description of corrective actions taken.
              (15) For affected facilities that apply activated carbon for mercury or dioxin/furan control, identification of the calendar dates when the carbon injection system operating parameter(s) that are the primary indicator(s) of carbon mass feed rate (e.g., screw feeder speed) recorded under paragraph (d)(4)(v) of this section are below the level(s) estimated during the performance tests as specified in § 60.58b(m)(1)(i) and § 60.58b(m)(1)(ii) of this section, with reasons for such occurrences and a description of corrective actions taken.
              (e) The owner or operator of an air curtain incinerator subject to the opacity limit under § 60.56b shall maintain records of results of the initial opacity performance test and subsequent performance tests required by § 60.58b(l) for a period of at least 5 years.
              (f) The owner or operator of an affected facility shall submit the information specified in paragraphs (f)(1) through (f)(6) of this section in the initial performance test report.

              (1) The initial performance test data as recorded under paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(D) of this section for the initial performance test for sulfur dioxide, nitrogen oxides, carbon monoxide, municipal waste combustor unit load level, and particulate matter control device inlet temperature.
              (2) The test report documenting the initial performance test recorded under paragraph (d)(9) of this section for particulate matter, opacity, cadmium, lead, mercury, dioxins/furans, hydrogen chloride, and fugitive ash emissions.
              (3) The performance evaluation of the continuous emission monitoring system using the applicable performance specifications in appendix B of this part.
              (4) The maximum demonstrated municipal waste combustor unit load and maximum demonstrated particulate matter control device inlet temperature(s) established during the initial dioxin/furan performance test as recorded under paragraph (d)(9) of this section.
              (5) For affected facilities that apply activated carbon injection for mercury control, the owner or operator shall submit the average carbon mass feed rate recorded under paragraph (d)(4)(i) of this section.
              (6) For those affected facilities that apply activated carbon injection for dioxin/furan control, the owner or operator shall submit the average carbon mass feed rate recorded under paragraph (d)(4)(ii) of this section.
              (g) Following the first year of municipal waste combustor operation, the owner or operator of an affected facility shall submit an annual report that includes the information specified in paragraphs (g)(1) through (g)(5) of this section, as applicable, no later than February 1 of each year following the calendar year in which the data were collected (once the unit is subject to permitting requirements under title V of the Act, the owner or operator of an affected facility must submit these reports semiannually).
              (1) A summary of data collected for all pollutants and parameters regulated under this subpart, which includes the information specified in paragraphs (g)(1)(i) through (g)(1)(v) of this section.
              (i) A list of the particulate matter, opacity, cadmium, lead, mercury, dioxins/furans, hydrogen chloride, and fugitive ash emission levels achieved during the performance tests recorded under paragraph (d)(9) of this section.
              (ii) A list of the highest emission level recorded for sulfur dioxide, nitrogen oxides, carbon monoxide, particulate matter, cadmium, lead, mercury, hydrogen chloride, and dioxin/furan (for owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, hydrogen chloride, and dioxin/furan emissions instead of conducting performance testing using EPA manual test methods), municipal waste combustor unit load level, and particulate matter control device inlet temperature based on the data recorded under paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(E) of this section.
              (iii) List the highest opacity level measured, based on the data recorded under paragraph (d)(2)(i)(A) of this section.
              (iv) Periods when valid data were not obtained as described in paragraphs (g)(1)(iv)(A) through (g)(1)(iv)(C) of this section.
              (A) The total number of hours per calendar quarter and hours per calendar year that valid data for sulfur dioxide, nitrogen oxides, carbon monoxide, municipal waste combustor unit load, or particulate matter control device temperature data were not obtained based on the data recorded under paragraph (d)(6) of this section.
              (B) For owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, and hydrogen chloride emissions instead of conducting performance testing using EPA manual test methods, the total number of hours per calendar quarter and hours per calendar year that valid data for particulate matter, cadmium, lead, mercury, and hydrogen chloride were not obtained based on the data recorded under paragraph (d)(6) of this section. For each continuously monitored pollutant or parameter, the hours of valid emissions data per calendar quarter and per calendar year expressed as a percent of the hours per calendar quarter or year that the affected facility was operating and combusting municipal solid waste.

              (C) For owners and operators who elect to use continuous automated sampling systems for dioxin/furan or mercury, the total number of hours per calendar quarter and hours per calendar year that the sampling systems were not operating or were not collecting a valid sample based on the data recorded under paragraph (d)(6)(vii) of this section. Also, the number of hours during which the continuous automated sampling system was operating and collecting a valid sample as a percent of hours per calendar quarter or year that the affected facility was operating and combusting municipal solid waste.
              (v) Periods when valid data were excluded from the calculation of average emission concentrations or parameters as described in paragraphs (g)(1)(v)(A) through (g)(1)(v)(C) of this section.
              (A) The total number of hours that data for sulfur dioxide, nitrogen oxides, carbon monoxide, municipal waste combustor unit load, and particulate matter control device temperature were excluded from the calculation of average emission concentrations or parameters based on the data recorded under paragraph (d)(7) of this section.
              (B) For owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, or hydrogen chloride emissions instead of conducting performance testing using EPA manual test methods, the total number of hours that data for particulate matter, cadmium, lead, mercury, or hydrogen chloride were excluded from the calculation of average emission concentrations or parameters based on the data recorded under paragraph (d)(7) of this section.
              (C) For owners and operators who elect to use continuous automated sampling systems for dioxin/furan or mercury, the total number of hours that data for mercury and dioxin/furan were excluded from the calculation of average emission concentrations or parameters based on the data recorded under paragraph (d)(7) of this section.
              (2) The summary of data reported under paragraph (g)(1) of this section shall also provide the types of data specified in paragraphs (g)(1)(i) through (g)(1)(vi) of this section for the calendar year preceding the year being reported, in order to provide the Administrator with a summary of the performance of the affected facility over a 2-year period.
              (3) The summary of data including the information specified in paragraphs (g)(1) and (g)(2) of this section shall highlight any emission or parameter levels that did not achieve the emission or parameter limits specified under this subpart.
              (4) A notification of intent to begin the reduced dioxin/furan performance testing schedule specified in § 60.58b(g)(5)(iii) of this section during the following calendar year and notification of intent to apply the average carbon mass feed rate and associated carbon injection system operating parameter levels as established in § 60.58b(m) to similarly designed and equipped units on site.
              (5) Documentation of periods when all certified chief facility operators and certified shift supervisors are off site for more than 12 hours.
              (h) The owner or operator of an affected facility shall submit a semiannual report that includes the information specified in paragraphs (h)(1) through (h)(5) of this section for any recorded pollutant or parameter that does not comply with the pollutant or parameter limit specified under this subpart, according to the schedule specified under paragraph (h)(6) of this section.
              (1) The semiannual report shall include information recorded under paragraph (d)(3) of this section for sulfur dioxide, nitrogen oxides, carbon monoxide, particulate matter, cadmium, lead, mercury, hydrogen chloride, dioxin/furan (for owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, or hydrogen chloride, or who elect to use continuous automated sampling systems for dioxin/furan or mercury emissions, instead of conducting performance testing using EPA manual test methods) municipal waste combustor unit load level, particulate matter control device inlet temperature, and opacity.

              (2) For each date recorded as required by paragraph (d)(3) of this section and reported as required by paragraph (h)(1) of this section, the semiannual report shall include the sulfur dioxide, nitrogen oxides, carbon monoxide, municipal waste combustor unit load level, particulate matter control device inlet temperature, or opacity data, as applicable, recorded under paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(D) and (d)(2)(i)(A) of this section, as applicable.
              (3) If the test reports recorded under paragraph (d)(9) of this section document any particulate matter, opacity, cadmium, lead, mercury, dioxins/furans, hydrogen chloride, and fugitive ash emission levels that were above the applicable pollutant limits, the semiannual report shall include a copy of the test report documenting the emission levels and the corrective actions taken.
              (4) The semiannual report shall include the information recorded under paragraph (d)(15) of this section for the carbon injection system operating parameter(s) that are the primary indicator(s) of carbon mass feed rate.
              (5) For each operating date reported as required by paragraph (h)(4) of this section, the semiannual report shall include the carbon feed rate data recorded under paragraph (d)(4)(iii) of this section.
              (6) Semiannual reports required by paragraph (h) of this section shall be submitted according to the schedule specified in paragraphs (h)(6)(i) and (h)(6)(ii) of this section.
              (i) If the data reported in accordance with paragraphs (h)(1) through (h)(5) of this section were collected during the first calendar half, then the report shall be submitted by August 1 following the first calendar half.
              (ii) If the data reported in accordance with paragraphs (h)(1) through (h)(5) of this section were collected during the second calendar half, then the report shall be submitted by February 1 following the second calendar half.
              (i) The owner or operator of an air curtain incinerator subject to the opacity limit under § 60.56b shall submit the results of the initial opacity performance test and all subsequent annual performance tests recorded under paragraph (e) of this section. Annual performance tests shall be submitted by February 1 of the year following the year of the performance test.
              (j) All reports specified under paragraphs (a), (b), (c), (f), (g), (h), and (i) of this section shall be submitted as a paper copy, postmarked on or before the submittal dates specified under these paragraphs, and maintained onsite as a paper copy for a period of 5 years.
              (k) All records specified under paragraphs (d) and (e) of this section shall be maintained onsite in either paper copy or computer-readable format, unless an alternative format is approved by the Administrator.
              (l) If the owner or operator of an affected facility would prefer a different annual or semiannual date for submitting the periodic reports required by paragraphs (g), (h) and (i) of this section, then the dates may be changed by mutual agreement between the owner or operator and the Administrator according to the procedures specified in § 60.19(c) of subpart A of this part.
              (m) Owners and operators who elect to continuously monitor particulate matter, cadmium, lead, mercury, or hydrogen chloride, or who elect to use continuous automated sampling systems for dioxin/furan or mercury emissions, instead of conducting performance testing using EPA manual test methods must notify the Administrator one month prior to starting or stopping use of the particulate matter, cadmium, lead, mercury, hydrogen chloride, and dioxin/furan continuous emission monitoring systems or continuous automated sampling systems.
              (n) Additional recordkeeping and reporting requirements for affected facilities with continuous cadmium, lead, mercury, or hydrogen chloride monitoring systems. In addition to complying with the requirements specified in paragraphs (a) through (m) of this section, the owner or operator of an affected source who elects to install a continuous emission monitoring system for cadmium, lead, mercury, or hydrogen chloride as specified in § 60.58b(n), shall maintain the records in paragraphs (n)(1) through (n)(10) of this section and report the information in paragraphs (n)(11) through (n)(12) of this section, relevant to the continuous emission monitoring system:

              (1) All required continuous emission monitoring measurements (including monitoring data recorded during unavoidable continuous emission monitoring system breakdowns and out-of-control periods);

              (2) The date and time identifying each period during which the continuous emission monitoring system was inoperative except for zero (low-level) and high-level checks;
              (3) The date and time identifying each period during which the continuous emission monitoring system was out of control, as defined in § 60.58b(o)(4);
              (4) The specific identification (i.e., the date and time of commencement and completion) of each period of excess emissions and parameter monitoring exceedances, as defined in the standard, that occurs during startups, shutdowns, and malfunctions of the affected source;
              (5) The specific identification (i.e., the date and time of commencement and completion) of each time period of excess emissions and parameter monitoring exceedances, as defined in the standard, that occurs during periods other than startups, shutdowns, and malfunctions of the affected source;
              (6) The nature and cause of any malfunction (if known);
              (7) The corrective action taken to correct any malfunction or preventive measures adopted to prevent further malfunctions;
              (8) The nature of the repairs or adjustments to the continuous emission monitoring system that was inoperative or out of control;
              (9) All procedures that are part of a quality control program developed and implemented for the continuous emission monitoring system under § 60.58b(o);

              (10) When more than one continuous emission monitoring system is used to measure the emissions from one affected source (e.g., multiple breechings, multiple outlets), the owner or operator shall report the results as required for each continuous emission monitoring system.

              (11) Submit to EPA for approval, the site-specific monitoring plan required by § 60.58b(n)(13) and § 60.58b(o), including the site-specific performance evaluation test plan for the continuous emission monitoring system required by § 60.58(b)(o)(5). The owner or operator shall maintain copies of the site-specific monitoring plan on record for the life of the affected source to be made available for inspection, upon request, by the Administrator. If the site-specific monitoring plan is revised and approved, the owner or operator shall keep previous (i.e., superseded) versions of the plan on record to be made available for inspection, upon request, by the Administrator, for a period of 5 years after each revision to the plan.
              (12) Submit information concerning all out-of-control periods for each continuous emission monitoring system, including start and end dates and hours and descriptions of corrective actions taken, in the annual or semiannual reports required in paragraphs (g) or (h) of this section.
              (o) Additional recordkeeping and reporting requirements for affected facilities with continuous automated sampling systems for dioxin/furan or mercury monitoring. In addition to complying with the requirements specified in paragraphs (a) through (m) of this section, the owner or operator of an affected source who elects to install a continuous automated sampling system for dioxin/furan or mercury, as specified in § 60.58b(p), shall maintain the records in paragraphs (o)(1) through (o)(10) of this section and report the information in (o)(11) and (o)(12) of this section, relevant to the continuous automated sampling system:
              (1) All required 24-hour integrated mercury concentration or 2-week integrated dioxin/furan concentration data (including any data obtained during unavoidable system breakdowns and out-of-control periods);
              (2) The date and time identifying each period during which the continuous automated sampling system was inoperative;
              (3) The date and time identifying each period during which the continuous automated sampling system was out of control, as defined in § 60.58b(q)(4);
              (4) The specific identification (i.e., the date and time of commencement and completion) of each period of excess emissions and parameter monitoring exceedances, as defined in the standard, that occurs during startups, shutdowns, and malfunctions of the affected source;

              (5) The specific identification (i.e., the date and time of commencement and completion) of each time period of excess emissions and parameter monitoring exceedances, as defined in the standard, that occurs during periods other than startups, shutdowns, and malfunctions of the affected source;
              (6) The nature and cause of any malfunction (if known);
              (7) The corrective action taken to correct any malfunction or preventive measures adopted to prevent further malfunctions;
              (8) The nature of the repairs or adjustments to the continuous automated sampling system that was inoperative or out of control;
              (9) All procedures that are part of a quality control program developed and implemented for the continuous automated sampling system under § 60.58b(q);

              (10) When more than one continuous automated sampling system is used to measure the emissions from one affected source (e.g., multiple breechings, multiple outlets), the owner or operator shall report the results as required for each system.

              (11) Submit to EPA for approval, the site-specific monitoring plan required by § 60.58b(p)(11) and § 60.58b(q) including the site-specific performance evaluation test plan for the continuous emission monitoring system required by § 60.58(b)(q)(5). The owner or operator shall maintain copies of the site-specific monitoring plan on record for the life of the affected source to be made available for inspection, upon request, by the Administrator. If the site-specific monitoring plan is revised and approved, the owner or operator shall keep previous (i.e., superseded) versions of the plan on record to be made available for inspection, upon request, by the Administrator, for a period of 5 years after each revision to the plan.
              (12) Submit information concerning all out-of-control periods for each continuous automated sampling system, including start and end dates and hours and descriptions of corrective actions taken in the annual or semiannual reports required in paragraphs (g) or (h) of this section.
              [60 FR 65419, Dec. 19, 1995, as amended at 62 FR 45121, 45127, Aug. 25, 1997; 71 FR 27345, May 10, 2006]

            Subpart Ec—Standards of Performance for New Stationary Sources: Hospital/Medical/Infectious Waste Incinerators

              Source:
              62 FR 48382, Sept. 15, 1997, unless otherwise noted.

              § 60.50c
              Applicability and delegation of authority.
              (a) Except as provided in paragraphs (b) through (h) of this section, the affected facility to which this subpart applies is each individual hospital/medical/infectious waste incinerator (HMIWI):
              (1) For which construction is commenced after June 20, 1996 but no later than December 1, 2008; or
              (2) For which modification is commenced after March 16, 1998 but no later than April 6, 2010.
              (3) For which construction is commenced after December 1, 2008; or
              (4) For which modification is commenced after April 6, 2010.
              (b) A combustor is not subject to this subpart during periods when only pathological waste, low-level radioactive waste, and/or chemotherapeutic waste (all defined in § 60.51c) is burned, provided the owner or operator of the combustor:
              (1) Notifies the Administrator of an exemption claim; and
              (2) Keeps records on a calendar quarter basis of the periods of time when only pathological waste, low-level radioactivewaste and/or chemotherapeutic waste is burned.
              (c) Any co-fired combustor (defined in § 60.51c) is not subject to this subpart if the owner or operator of the co-fired combustor:
              (1) Notifies the Administrator of an exemption claim;
              (2) Provides an estimate of the relative amounts of hospital waste, medical/infectious waste, and other fuels and wastes to be combusted; and

              (3) Keeps records on a calendar quarter basis of the weight of hospital waste and medical/infectious waste combusted, and the weight of all other fuels and wastes combusted at the co-fired combustor.
              (d) Any combustor required to have a permit under section 3005 of the Solid Waste Disposal Act is not subject to this subpart.
              (e) Any combustor which meets the applicability requirements under subpart Cb, Ea, or Eb of this part (standards or guidelines for certain municipal waste combustors) is not subject to this subpart.
              (f) Any pyrolysis unit (defined in § 60.51c) is not subject to this subpart.
              (g) Cement kilns firing hospital waste and/or medical/infectious waste are not subject to this subpart.
              (h) Physical or operational changes made to an existing HMIWI solely for the purpose of complying with emission guidelines under subpart Ce are not considered a modification and do not result in an existing HMIWI becoming subject to this subpart.
              (i) In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, the following authorities shall be retained by the Administrator and not transferred to a State:
              (1) The requirements of Sec. 60.56c(i) establishing operating parameters when using controls other than those listed in Sec. 60.56c(d).
              (2) Approval of alternative methods of demonstrating compliance under § 60.8 including:
              (i) Approval of CEMS for PM, HCl, multi-metals, and Hg where used for purposes of demonstrating compliance,
              (ii) Approval of continuous automated sampling systems for dioxin/furan and Hg where used for purposes of demonstrating compliance, and
              (iii) Approval of major alternatives to test methods;
              (3) Approval of major alternatives to monitoring;
              (4) Waiver of recordkeeping requirements; and
              (5) Performance test and data reduction waivers under § 60.8(b).
              (j) Affected facilities subject to this subpart are not subject to the requirements of 40 CFR part 64.
              (i) Approval of CEMS for PM, HCl, multi-metals, and Hg where used for purposes of demonstrating compliance,
              (ii) Approval of continuous automated sampling systems for dioxin/furan and Hg where used for purposes of demonstrating compliance, and
              (iii) Approval of major alternatives to test methods;
              (3) Approval of major alternatives to monitoring;
              (4) Waiver of recordkeeping requirements; and
              (5) Performance test and data reduction waivers under § 60.8(b).
              (k) The requirements of this subpart shall become effective March 16, 1998
              (l) Beginning September 15, 2000, or on the effective date of an EPA-approved operating permit program under Clean Air Act title V and the implementing regulations under 40 CFR part 70 in the State in which the unit is located, whichever date is later, affected facilities subject to this subpart shall operate pursuant to a permit issued under the EPA approved State operating permit program.

              (m) The requirements of this subpart as promulgated on September 15, 1997, shall apply to the affected facilities defined in paragraph (a)(1) and (2) of this section until the applicable compliance date of the requirements of subpart Ce of this part, as amended on October 6, 2009. Upon the compliance date of the requirements of the amended subpart Ce of this part, affected facilities as defined in paragraph (a) of this section are no longer subject to the requirements of this subpart, but are subject to the requirements of subpart Ce of this part, as amended on October 6, 2009, except where the emissions limits of this subpart as promulgated on September 15, 1997 are more stringent than the emissions limits of the amended subpart Ce of this part. Compliance with subpart Ce of this part, as amended on October 6, 2009 is required on or before the date 3 years after EPA approval of the State plan for States in which an affected facility as defined in paragraph (a) of this section is located (but not later than the date 5 years after promulgation of the amended subpart).

              (n) The requirements of this subpart, as amended on October 6, 2009, shall become effective April 6, 2010.
              [62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51408, Oct. 6, 2009]

              § 60.51c
              Definitions.

                Bag leak detection system means an instrument that is capable of monitoring PM loadings in the exhaust of a fabric filter in order to detect bag failures. A bag leak detection system includes, but is not limited to, an instrument that operates on triboelectric, light-scattering, light-transmittance, or other effects to monitor relative PM loadings.

                Batch HMIWI means an HMIWI that is designed such that neither waste charging nor ash removal can occur during combustion.

                Biologicals means preparations made from living organisms and their products, including vaccines, cultures, etc., intended for use in diagnosing, immunizing, or treating humans or animals or in research pertaining thereto.

                Blood products means any product derived from human blood, including but not limited to blood plasma, platelets, red or white blood corpuscles, and other derived licensed products, such as interferon, etc.

                Body fluids means liquid emanating or derived from humans and limited to blood; dialysate; amniotic, cerebrospinal, synovial, pleural, peritoneal and pericardial fluids; and semen and vaginal secretions.

                Bypass stack means a device used for discharging combustion gases to avoid severe damage to the air pollution control device or other equipment.

                Chemotherapeutic waste means waste material resulting from the production or use of antineoplastic agents used for the purpose of stopping or reversing the growth of malignant cells.

                Co-fired combustor means a unit combusting hospital waste and/or medical/infectious waste with other fuels or wastes (e.g., coal, municipal solid waste) and subject to an enforceable requirement limiting the unit to combusting a fuel feed stream, 10 percent or less of the weight of which is comprised, in aggregate, of hospital waste and medical/infectious waste as measured on a calendar quarter basis. For purposes of this definition, pathological waste, chemotherapeutic waste, and low-level radioactive waste are considered “other” wastes when calculating the percentage of hospital waste and medical/infectious waste combusted.

                Commercial HMIWI means a HMIWI which offers incineration services for hospital/medical/infectious waste generated offsite by firms unrelated to the firm that owns the HMIWI.

                Continuous emission monitoring system or CEMS means a monitoring system for continuously measuring and recording the emissions of a pollutant from an affected facility.

                Continuous HMIWI means an HMIWI that is designed to allow waste charging and ash removal during combustion.

                Dioxins/furans means the combined emissions of tetra-through octa-chlorinated dibenzo-para-dioxins and dibenzofurans, as measured by EPA Reference Method 23.

                Dry scrubber means an add-on air pollution control system that injects dry alkaline sorbent (dry injection) or sprays an alkaline sorbent (spray dryer) to react with and neutralize acid gases in the HMIWI exhaust stream forming a dry powder material.

                Fabric filter or baghouse means an add-on air pollution control system that removes particulate matter (PM) and nonvaporous metals emissions by passing flue gas through filter bags.

                Facilities manager means the individual in charge of purchasing, maintaining, and operating the HMIWI or the owner's or operator's representative responsible for the management of the HMIWI. Alternative titles may include director of facilities or vice president of support services.

                High-air phase means the stage of the batch operating cycle when the primary chamber reaches and maintains maximum operating temperatures.

                Hospital means any facility which has an organized medical staff, maintains at least six inpatient beds, and where the primary function of the institution is to provide diagnostic and therapeutic patient services and continuous nursing care primarily to human inpatients who are not related and who stay on average in excess of 24 hours per admission. This definition does not include facilities maintained for the sole purpose of providing nursing or convalescent care to human patients who generally are not acutely ill but who require continuing medical supervision.

                Hospital/medical/infectious waste incinerator or HMIWI or HMIWI unit means any device that combusts any amount of hospital waste and/or medical/infectious waste.

                Hospital/medical/infectious waste incinerator operator or HMIWI operator means any person who operates, controls or supervises the day-to-day operation of an HMIWI.

                Hospital waste means discards generated at a hospital, except unused items returned to the manufacturer. The definition of hospital waste does not include human corpses, remains, and anatomical parts that are intended for interment or cremation.

                Infectious agent means any organism (such as a virus or bacteria) that is capable of being communicated by invasion and multiplication in body tissues and capable of causing disease or adverse health impacts in humans.

                Intermittent HMIWI means an HMIWI that is designed to allow waste charging, but not ash removal, during combustion.

                Large HMIWI means:
              (1) Except as provided in (2);
              (i) An HMIWI whose maximum design waste burning capacity is more than 500 pounds per hour; or
              (ii) A continuous or intermittent HMIWI whose maximum charge rate is more than 500 pounds per hour; or
              (iii) A batch HMIWI whose maximum charge rate is more than 4,000 pounds per day.
              (2) The following are not large HMIWI:
              (i) A continuous or intermittent HMIWI whose maximum charge rate is less than or equal to 500 pounds per hour; or
              (ii) A batch HMIWI whose maximum charge rate is less than or equal to 4,000 pounds per day.

                Low-level radioactive waste means waste material which contains radioactive nuclides emitting primarily beta or gamma radiation, or both, in concentrations or quantities that exceed applicable federal or State standards for unrestricted release. Low-level radioactive waste is not high-level radioactive waste, spent nuclear fuel, or by-product material as defined by the Atomic Energy Act of 1954 (42 U.S.C. 2014(e)(2)).

                Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner. Failures that are caused, in part, by poor maintenance or careless operation are not malfunctions. During periods of malfunction the operator shall operate within established parameters as much as possible, and monitoring of all applicable operating parameters shall continue until all waste has been combusted or until the malfunction ceases, whichever comes first.

                Maximum charge rate means:
              (1) For continuous and intermittent HMIWI, 110 percent of the lowest 3-hour average charge rate measured during the most recent performance test demonstrating compliance with all applicable emission limits.
              (2) For batch HMIWI, 110 percent of the lowest daily charge rate measured during the most recent performance test demonstrating compliance with all applicable emission limits.

                Maximum design waste burning capacity means:
              (1) For intermittent and continuous HMIWI,

              C = PV × 15,000/8,500

                Where:

                C = HMIWI capacity, lb/hr
                PV = primary chamber volume, ft3

                15,000 = primary chamber heat release rate factor, Btu/ft3/hr
                8,500 = standard waste heating value, Btu/lb;

              (2) For batch HMIWI,

              C = PV × 4.5/8

                Where:

                C = HMIWI capacity, lb/hr
                PV = primary chamber volume, ft3

                4.5 = waste density, lb/ft3

                8 = typical hours of operation of a batch HMIWI, hours.

                Maximum fabric filter inlet temperature means 110 percent of the lowest 3-hour average temperature at the inlet to the fabric filter (taken, at a minimum, once every minute) measured during the most recent performance test demonstrating compliance with the dioxin/furan emission limit.

                Maximum flue gas temperature means 110 percent of the lowest 3-hour average temperature at the outlet from the wet scrubber (taken, at a minimum, once every minute) measured during the most recent performance test demonstrating compliance with the mercury (Hg) emission limit.

                Medical/infectious waste means any waste generated in the diagnosis, treatment, or immunization of human beings or animals, in research pertaining thereto, or in the production or testing of biologicals that are listed in paragraphs (1) through (7) of this definition. The definition of medical/infectious waste does not include hazardous waste identified or listed under the regulations in part 261 of this chapter; household waste, as defined in § 261.4(b)(1) of this chapter; ash from incineration of medical/infectious waste, once the incineration process has been completed; human corpses, remains, and anatomical parts that are intended for interment or cremation; and domestic sewage materials identified in § 261.4(a)(1) of this chapter.
              (1) Cultures and stocks of infectious agents and associated biologicals, including: Cultures from medical and pathological laboratories; cultures and stocks of infectious agents from research and industrial laboratories; wastes from the production of biologicals; discarded live and attenuated vaccines; and culture dishes and devices used to transfer, inoculate, and mix cultures.
              (2) Human pathological waste, including tissues, organs, and body parts and body fluids that are removed during surgery or autopsy, or other medical procedures, and specimens of body fluids and their containers.
              (3) Human blood and blood products including:
              (i) Liquid waste human blood;
              (ii) Products of blood;
              (iii) Items saturated and/or dripping with human blood; or
              (iv) Items that were saturated and/or dripping with human blood that are now caked with dried human blood; including serum, plasma, and other blood components, and their containers, which were used or intended for use in either patient care, testing and laboratory analysis or the development of pharmaceuticals. Intravenous bags are also included in this category.
              (4) Sharps that have been used in animal or human patient care or treatment or in medical, research, or industrial laboratories, including hypodermic needles, syringes (with or without the attached needle), pasteur pipettes, scalpel blades, blood vials, needles with attached tubing, and culture dishes (regardless of presence of infectious agents). Also included are other types of broken or unbroken glassware that were in contact with infectious agents, such as used slides and cover slips.
              (5) Animal waste including contaminated animal carcasses, body parts, and bedding of animals that were known to have been exposed to infectious agents during research (including research in veterinary hospitals), production of biologicals or testing of pharmaceuticals.
              (6) Isolation wastes including biological waste and discarded materials contaminated with blood, excretions, exudates, or secretions from humans who are isolated to protect others from certain highly communicable diseases, or isolated animals known to be infected with highly communicable diseases.
              (7) Unused sharps including the following unused, discarded sharps: hypodermic needles, suture needles, syringes, and scalpel blades.

                Medium HMIWI means:
              (1) Except as provided in paragraph (2);
              (i) An HMIWI whose maximum design waste burning capacity is more than 200 pounds per hour but less than or equal to 500 pounds per hour; or
              (ii) A continuous or intermittent HMIWI whose maximum charge rate is more than 200 pounds per hour but less than or equal to 500 pounds per hour; or
              (iii) A batch HMIWI whose maximum charge rate is more than 1,600 pounds per day but less than or equal to 4,000 pounds per day.
              (2) The following are not medium HMIWI:

              (i) A continuous or intermittent HMIWI whose maximum charge rate is less than or equal to 200 pounds per hour or more than 500 pounds per hour; or
              (ii) A batch HMIWI whose maximum charge rate is more than 4,000 pounds per day or less than or equal to 1,600 pounds per day.

                Minimum dioxin/furan sorbent flow rate means 90 percent of the highest 3-hour average dioxin/furan sorbent flow rate (taken, at a minimum, once every hour) measured during the most recent performance test demonstrating compliance with the dioxin/furan emission limit.

                Minimum Hg sorbent flow rate means 90 percent of the highest 3-hour average Hg sorbent flow rate (taken, at a minimum, once every hour) measured during the most recent performance test demonstrating compliance with the Hg emission limit.

                Minimum hydrogen chloride (HCl) sorbent flow rate means 90 percent of the highest 3-hour average HCl sorbent flow rate (taken, at a minimum, once every hour) measured during the most recent performance test demonstrating compliance with the HCl emission limit.

                Minimum horsepower or amperage means 90 percent of the highest 3-hour average horsepower or amperage to the wet scrubber (taken, at a minimum, once every minute) measured during the most recent performance test demonstrating compliance with the applicable emission limits.

                Minimum pressure drop across the wet scrubber means 90 percent of the highest 3-hour average pressure drop across the wet scrubber PM control device (taken, at a minimum, once every minute) measured during the most recent performance test demonstrating compliance with the PM emission limit.

                Minimum reagent flow rate means 90 percent of the highest 3-hour average reagent flow rate at the inlet to the selective noncatalytic reduction technology (taken, at a minimum, once every minute) measured during the most recent performance test demonstrating compliance with the NOX emissions limit.

                Minimum scrubber liquor flow rate means 90 percent of the highest 3-hour average liquor flow rate at the inlet to the wet scrubber (taken, at a minimum, once every minute) measured during the most recent performance test demonstrating compliance with all applicable emission limits.

                Minimum scrubber liquor pH means 90 percent of the highest 3-hour average liquor pH at the inlet to the wet scrubber (taken, at a minimum, once every minute) measured during the most recent performance test demonstrating compliance with the HCl emission limit.

                Minimum secondary chamber temperature means 90 percent of the highest 3-hour average secondary chamber temperature (taken, at a minimum, once every minute) measured during the most recent performance test demonstrating compliance with the PM, CO, dioxin/furan, and NOX emissions limits.

                Modification or Modified HMIWI means any change to an HMIWI unit after the effective date of these standards such that:
              (1) The cumulative costs of the modifications, over the life of the unit, exceed 50 per centum of the original cost of the construction and installation of the unit (not including the cost of any land purchased in connection with such construction or installation) updated to current costs, or
              (2) The change involves a physical change in or change in the method of operation of the unit which increases the amount of any air pollutant emitted by the unit for which standards have been established under section 129 or section 111.

                Operating day means a 24-hour period between 12:00 midnight and the following midnight during which any amount of hospital waste or medical/infectious waste is combusted at any time in the HMIWI.

                Operation means the period during which waste is combusted in the incinerator excluding periods of startup or shutdown.

                Particulate matter or PM means the total particulate matter emitted from an HMIWI as measured by EPA Reference Method 5 or EPA Reference Method 29.

                Pathological waste means waste material consisting of only human or animal remains, anatomical parts, and/or tissue, the bags/containers used to collect and transport the waste material, and animal bedding (if applicable).

                Primary chamber means the chamber in an HMIWI that receives waste material, in which the waste is ignited, and from which ash is removed.

                Pyrolysis means the endothermic gasification of hospital waste and/or medical/infectious waste using external energy.

                Secondary chamber means a component of the HMIWI that receives combustion gases from the primary chamber and in which the combustion process is completed.

                Shutdown means the period of time after all waste has been combusted in the primary chamber. For continuous HMIWI, shutdown shall commence no less than 2 hours after the last charge to the incinerator. For intermittent HMIWI, shutdown shall commence no less than 4 hours after the last charge to the incinerator. For batch HMIWI, shutdown shall commence no less than 5 hours after the high-air phase of combustion has been completed.

                Small HMIWI means:
              (1) Except as provided in (2);
              (i) An HMIWI whose maximum design waste burning capacity is less than or equal to 200 pounds per hour; or
              (ii) A continuous or intermittent HMIWI whose maximum charge rate is less than or equal to 200 pounds per hour; or
              (iii) A batch HMIWI whose maximum charge rate is less than or equal to 1,600 pounds per day.
              (2) The following are not small HMIWI:
              (i) A continuous or intermittent HMIWI whose maximum charge rate is more than 200 pounds per hour;
              (ii) A batch HMIWI whose maximum charge rate is more than 1,600 pounds per day.

                Standard conditions means a temperature of 20 °C and a pressure of 101.3 kilopascals.

                Startup means the period of time between the activation of the system and the first charge to the unit. For batch HMIWI, startup means the period of time between activation of the system and ignition of the waste.

                Wet scrubber means an add-on air pollution control device that utilizes an alkaline scrubbing liquor to collect particulate matter (including nonvaporous metals and condensed organics) and/or to absorb and neutralize acid gases.
              [62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51408, Oct. 6, 2009; 79 FR 11249, Feb. 27, 2014]

              § 60.52c
              Emission limits.
              (a) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility shall cause to be discharged into the atmosphere:
              (1) From an affected facility as defined in § 60.50c(a)(1) and (2), any gases that contain stack emissions in excess of the limits presented in Table 1A to this subpart.
              (2) From an affected facility as defined in § 60.50c(a)(3) and (4), any gases that contain stack emissions in excess of the limits presented in Table 1B to this subpart.
              (b) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility shall cause to be discharged into the atmosphere:
              (1) From an affected facility as defined in § 60.50c(a)(1) and (2), any gases that exhibit greater than 10 percent opacity (6-minute block average).
              (2) From an affected facility as defined in § 60.50c(a)(3) and (4), any gases that exhibit greater than 6 percent opacity (6-minute block average).

              (c) On and after the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility as defined in § 60.50c(a)(1) and (2) and utilizing a large HMIWI, and in § 60.50c(a)(3) and (4), shall cause to be discharged into the atmosphere visible emissions of combustion ash from an ash conveying system (including conveyor transfer points) in excess of 5 percent of the observation period (i.e., 9 minutes per 3-hour period), as determined by EPA Reference Method 22 of appendix A-1 of this part, except as provided in paragraphs (d) and (e) of this section.
              (d) The emission limit specified in paragraph (c) of this section does not cover visible emissions discharged inside buildings or enclosures of ash conveying systems; however, the emission limit does cover visible emissions discharged to the atmosphere from buildings or enclosures of ash conveying systems.
              (e) The provisions specified in paragraph (c) of this section do not apply during maintenance and repair of ash conveying systems. Maintenance and/or repair shall not exceed 10 operating days per calendar quarter unless the owner or operator obtains written approval from the State agency establishing a date whereby all necessary maintenance and repairs of ash conveying systems shall be completed.
              [62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51409, Oct. 6, 2009]

              § 60.53c
              Operator training and qualification requirements.
              (a) No owner or operator of an affected facility shall allow the affected facility to operate at any time unless a fully trained and qualified HMIWI operator is accessible, either at the facility or available within 1 hour. The trained and qualified HMIWI operator may operate the HMIWI directly or be the direct supervisor of one or more HMIWI operators.
              (b) Operator training and qualification shall be obtained through a State-approved program or by completing the requirements included in paragraphs (c) through (g) of this section.
              (c) Training shall be obtained by completing an HMIWI operator training course that includes, at a minimum, the following provisions:
              (1) 24 hours of training on the following subjects:
              (i) Environmental concerns, including pathogen destruction and types of emissions;
              (ii) Basic combustion principles, including products of combustion;
              (iii) Operation of the type of incinerator to be used by the operator, including proper startup, waste charging, and shutdown procedures;
              (iv) Combustion controls and monitoring;
              (v) Operation of air pollution control equipment and factors affecting performance (if applicable);
              (vi) Methods to monitor pollutants (continuous emission monitoring systems and monitoring of HMIWI and air pollution control device operating parameters) and equipment calibration procedures (where applicable);
              (vii) Inspection and maintenance of the HMIWI, air pollution control devices, and continuous emission monitoring systems;
              (viii) Actions to correct malfunctions or conditions that may lead to malfunction;
              (ix) Bottom and fly ash characteristics and handling procedures;
              (x) Applicable Federal, State, and local regulations;
              (xi) Work safety procedures;
              (xii) Pre-startup inspections; and
              (xiii) Recordkeeping requirements.
              (2) An examination designed and administered by the instructor.
              (3) Reference material distributed to the attendees covering the course topics.
              (d) Qualification shall be obtained by:
              (1) Completion of a training course that satisfies the criteria under paragraph (c) of this section; and
              (2) Either 6 months experience as an HMIWI operator, 6 months experience as a direct supervisor of an HMIWI operator, or completion of at least two burn cycles under the observation of two qualified HMIWI operators.
              (e) Qualification is valid from the date on which the examination is passed or the completion of the required experience, whichever is later.
              (f) To maintain qualification, the trained and qualified HMIWI operator shall complete and pass an annual review or refresher course of at least 4 hours covering, at a minimum, the following:
              (1) Update of regulations;
              (2) Incinerator operation, including startup and shutdown procedures;
              (3) Inspection and maintenance;

              (4) Responses to malfunctions or conditions that may lead to malfunction; and
              (5) Discussion of operating problems encountered by attendees.
              (g) A lapsed qualification shall be renewed by one of the following methods:
              (1) For a lapse of less than 3 years, the HMIWI operator shall complete and pass a standard annual refresher course described in paragraph (f) of this section.
              (2) For a lapse of 3 years or more, the HMIWI operator shall complete and pass a training course with the minimum criteria described in paragraph (c) of this section.
              (h) The owner or operator of an affected facility shall maintain documentation at the facility that address the following:
              (1) Summary of the applicable standards under this subpart;
              (2) Description of basic combustion theory applicable to an HMIWI;
              (3) Procedures for receiving, handling, and charging waste;
              (4) HMIWI startup, shutdown, and malfunction procedures;
              (5) Procedures for maintaining proper combustion air supply levels;
              (6) Procedures for operating the HMIWI and associated air pollution control systems within the standards established under this subpart;
              (7) Procedures for responding to periodic malfunction or conditions that may lead to malfunction;
              (8) Procedures for monitoring HMIWI emissions;
              (9) Reporting and recordkeeping procedures; and
              (10) Procedures for handling ash.
              (i) The owner or operator of an affected facility shall establish a program for reviewing the information listed in paragraph (h) of this section annually with each HMIWI operator (defined in § 60.51c).
              (1) The initial review of the information listed in paragraph (h) of this section shall be conducted within 6 months after the effective date of this subpart or prior to assumption of responsibilities affecting HMIWI operation, whichever date is later.
              (2) Subsequent reviews of the information listed in paragraph (h) of this section shall be conducted annually.
              (j) The information listed in paragraph (h) of this section shall be kept in a readily accessible location for all HMIWI operators. This information, along with records of training shall be available for inspection by the EPA or its delegated enforcement agent upon request.

              § 60.54c
              Siting requirements.
              (a) The owner or operator of an affected facility for which construction is commenced after September 15, 1997 shall prepare an analysis of the impacts of the affected facility. The analysis shall consider air pollution control alternatives that minimize, on a site-specific basis, to the maximum extent practicable, potential risks to public health or the environment. In considering such alternatives, the analysis may consider costs, energy impacts, non-air environmental impacts, or any other factors related to the practicability of the alternatives.
              (b) Analyses of facility impacts prepared to comply with State, local, or other Federal regulatory requirements may be used to satisfy the requirements of this section, as long as they include the consideration of air pollution control alternatives specified in paragraph (a) of this section.
              (c) The owner or operator of the affected facility shall complete and submit the siting requirements of this section as required under § 60.58c(a)(1)(iii).

              § 60.55c
              Waste management plan.

              The owner or operator of an affected facility shall prepare a waste management plan. The waste management plan shall identify both the feasibility and the approach to separate certain components of solid waste from the health care waste stream in order to reduce the amount of toxic emissions from incinerated waste. A waste management plan may include, but is not limited to, elements such as segregation and recycling of paper, cardboard, plastics, glass, batteries, food waste, and metals (e.g., aluminum cans, metals-containing devices); segregation of non-recyclable wastes (e.g., polychlorinated biphenyl-containing waste, pharmaceutical waste, and mercury-containing waste, such as dental waste); and purchasing recycled or recyclable products. A waste management plan may include different goals or approaches for different areas or departments of the facility and need not include new waste management goals for every waste stream. It should identify, where possible, reasonably available additional waste management measures, taking into account the effectiveness of waste management measures already in place, the costs of additional measures, the emissions reductions expected to be achieved, and any other environmental or energy impacts they might have. The American Hospital Association publication entitled “An Ounce of Prevention: Waste Reduction Strategies for Health Care Facilities” (incorporated by reference, see § 60.17) shall be considered in the development of the waste management plan. The owner or operator of each commercial HMIWI company shall conduct training and education programs in waste segregation for each of the company's waste generator clients and ensure that each client prepares its own waste management plan that includes, but is not limited to, the provisions listed previously in this section.
              [74 FR 51409, Oct. 6, 2009]

              § 60.56c
              Compliance and performance testing.
              (a) The emissions limits apply at all times.
              (b) The owner or operator of an affected facility as defined in § 60.50c(a)(1) and (2), shall conduct an initial performance test as required under § 60.8 to determine compliance with the emissions limits using the procedures and test methods listed in paragraphs (b)(1) through (b)(6) and (b)(9) through (b)(14) of this section. The owner or operator of an affected facility as defined in § 60.50c(a)(3) and (4), shall conduct an initial performance test as required under § 60.8 to determine compliance with the emissions limits using the procedures and test methods listed in paragraphs (b)(1) through (b)(14). The use of the bypass stack during a performance test shall invalidate the performance test.
              (1) All performance tests shall consist of a minimum of three test runs conducted under representative operating conditions.
              (2) The minimum sample time shall be 1 hour per test run unless otherwise indicated.
              (3) EPA Reference Method 1 of appendix A of this part shall be used to select the sampling location and number of traverse points.

              (4) EPA Reference Method 3, 3A, or 3B of appendix A-2 of this part shall be used for gas composition analysis, including measurement of oxygen concentration. EPA Reference Method 3, 3A, or 3B of appendix A-2 of this part shall be used simultaneously with each of the other EPA reference methods. As an alternative to EPA Reference Method 3B, ASME PTC-19-10-1981-Part 10 may be used (incorporated by reference, see § 60.17).

              (5) The pollutant concentrations shall be adjusted to 7 percent oxygen using the following equation:

              Cadj = Cmeas (20.9−7)/(20.9−%O2)

                where:

                Cadj = pollutant concentration adjusted to 7 percent oxygen;
                Cmeas = pollutant concentration measured on a dry basis (20.9−7) = 20.9 percent oxygen—7 percent oxygen (defined oxygen correction basis);
                20.9 = oxygen concentration in air, percent; and
                %O2 = oxygen concentration measured on a dry basis, percent.

              (6) EPA Reference Method 5 of appendix A-3 or Method 26A or Method 29 of appendix A-8 of this part shall be used to measure the particulate matter emissions. As an alternative, PM CEMS may be used as specified in paragraph (c)(5) of this section.

              (7) EPA Reference Method 7 or 7E of appendix A-4 of this part shall be used to measure NOX emissions.

              (8) EPA Reference Method 6 or 6C of appendix A-4 of this part shall be used to measure SO2 emissions.

              (9) EPA Reference Method 9 of appendix A-4 of this part shall be used to measure stack opacity. As an alternative, demonstration of compliance with the PM standards using bag leak detection systems as specified in § 60.57c(h) or PM CEMS as specified in paragraph (c)(5) of this section is considered demonstrative of compliance with the opacity requirements.

              (10) EPA Reference Method 10 or 10B of appendix A-4 of this part shall be used to measure the CO emissions. As specified in paragraph (c)(4) of this section, use of CO CEMS are required for affected facilities under § 60.50c(a)(3) and (4).
              (11) EPA Reference Method 23 of appendix A-7 of this part shall be used to measure total dioxin/furan emissions. As an alternative, an owner or operator may elect to sample dioxins/furans by installing, calibrating, maintaining, and operating a continuous automated sampling system for monitoring dioxin/furan emissions as specified in paragraph (c)(6) of this section. For Method 23 of appendix A-7 sampling, the minimum sample time shall be 4 hours per test run. If the affected facility has selected the toxic equivalency standards for dioxins/furans, under § 60.52c, the following procedures shall be used to determine compliance:
              (i) Measure the concentration of each dioxin/furan tetra-through octa-congener emitted using EPA Reference Method 23.
              (ii) For each dioxin/furan congener measured in accordance with paragraph (b)(9)(i) of this section, multiply the congener concentration by its corresponding toxic equivalency factor specified in table 2 of this subpart.
              (iii) Sum the products calculated in accordance with paragraph (b)(9)(ii) of this section to obtain the total concentration of dioxins/furans emitted in terms of toxic equivalency.
              (12) EPA Reference Method 26 or 26A of appendix A-8 of this part shall be used to measure HCl emissions. As an alternative, HCl CEMS may be used as specified in paragraph (c)(5) of this section.

              (13) EPA Reference Method 29 of appendix A-8 of this part shall be used to measure Pb, Cd, and Hg emissions. As an alternative, Hg emissions may be measured using ASTM D6784-02 (incorporated by reference, see § 60.17). As an alternative for Pb, Cd, and Hg, multi-metals CEMS or Hg CEMS, may be used as specified in paragraph (c)(5) of this section. As an alternative, an owner or operator may elect to sample Hg by installing, calibrating, maintaining, and operating a continuous automated sampling system for monitoring Hg emissions as specified in paragraph (c)(7) of this section.
              (14) The EPA Reference Method 22 of appendix A-7 of this part shall be used to determine compliance with the fugitive ash emissions limit under § 60.52c(c). The minimum observation time shall be a series of three 1-hour observations.
              (c) Following the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected facility shall:
              (1) Determine compliance with the opacity limit by conducting an annual performance test (no more than 12 months following the previous performance test) using the applicable procedures and test methods listed in paragraph (b) of this section.
              (2) Except as provided in paragraphs (c)(4) and (c)(5) of this section, determine compliance with the PM, CO, and HCl emissions limits by conducting an annual performance test (no more than 12 months following the previous performance test) using the applicable procedures and test methods listed in paragraph (b) of this section. If all three performance tests over a 3-year period indicate compliance with the emissions limit for a pollutant (PM, CO, or HCl), the owner or operator may forego a performance test for that pollutant for the subsequent 2 years. At a minimum, a performance test for PM, CO, and HCl shall be conducted every third year (no more than 36 months following the previous performance test). If a performance test conducted every third year indicates compliance with the emissions limit for a pollutant (PM, CO, or HCl), the owner or operator may forego a performance test for that pollutant for an additional 2 years. If any performance test indicates noncompliance with the respective emissions limit, a performance test for that pollutant shall be conducted annually until all annual performance tests over a 3-year period indicate compliance with the emissions limit. The use of the bypass stack during a performance test shall invalidate the performance test.

              (3) For an affected facility as defined in § 60.50c(a)(1) and (2) and utilizing a large HMIWI, and in § 60.50c(a)(3) and (4), determine compliance with the visible emissions limits for fugitive emissions from flyash/bottom ash storage and handling by conducting a performance test using EPA Reference Method 22 of appendix A-7 on an annual basis (no more than 12 months following the previous performance test).
              (4) For an affected facility as defined in § 60.50c(a)(3) and (4), determine compliance with the CO emissions limit using a CO CEMS according to paragraphs (c)(4)(i) through (c)(4)(iii) of this section:
              (i) Determine compliance with the CO emissions limit using a 24-hour block average, calculated as specified in section 12.4.1 of EPA Reference Method 19 of appendix A-7 of this part.
              (ii) Operate the CO CEMS in accordance with the applicable procedures under appendices B and F of this part.
              (iii) Use of a CO CEMS may be substituted for the CO annual performance test and minimum secondary chamber temperature to demonstrate compliance with the CO emissions limit.
              (5) Facilities using CEMS to demonstrate compliance with any of the emissions limits under § 60.52c shall:
              (i) For an affected facility as defined in § 60.50c(a)(1) and (2), determine compliance with the appropriate emissions limit(s) using a 12-hour rolling average, calculated each hour as the average of the previous 12 operating hours.
              (ii) For an affected facility as defined in § 60.50c(a)(3) and (4), determine compliance with the appropriate emissions limit(s) using a 24-hour block average, calculated as specified in section 12.4.1 of EPA Reference Method 19 of appendix A-7 of this part.

              (iii) Operate all CEMS in accordance with the applicable procedures under appendices B and F of this part. For those CEMS for which performance specifications have not yet been promulgated (HCl, multi-metals), this option for an affected facility as defined in § 60.50c(a)(3) and (4) takes effect on the date a final performance specification is published in the Federal Register or the date of approval of a site-specific monitoring plan.
              (iv) For an affected facility as defined in § 60.50c(a)(3) and (4), be allowed to substitute use of an HCl CEMS for the HCl annual performance test, minimum HCl sorbent flow rate, and minimum scrubber liquor pH to demonstrate compliance with the HCl emissions limit.
              (v) For an affected facility as defined in § 60.50c(a)(3) and (4), be allowed to substitute use of a PM CEMS for the PM annual performance test and minimum pressure drop across the wet scrubber, if applicable, to demonstrate compliance with the PM emissions limit.

              (6) An affected facility as defined in § 60.50c(a)(3) and (4) using a continuous automated sampling system to demonstrate compliance with the dioxin/furan emissions limits under § 60.52c shall record the output of the system and analyze the sample according to EPA Reference Method 23 of appendix A-7 of this part. This option to use a continuous automated sampling system takes effect on the date a final performance specification applicable to dioxin/furan from monitors is published in the Federal Register or the date of approval of a site-specific monitoring plan. The owner or operator of an affected facility as defined in § 60.50c(a)(3) and (4) who elects to continuously sample dioxin/furan emissions instead of sampling and testing using EPA Reference Method 23 of appendix A-7 shall install, calibrate, maintain, and operate a continuous automated sampling system and shall comply with the requirements specified in § 60.58b(p) and (q) of subpart Eb of this part.

              (7) An affected facility as defined in § 60.50c(a)(3) and (4) using a continuous automated sampling system to demonstrate compliance with the Hg emissions limits under § 60.52c shall record the output of the system and analyze the sample at set intervals using any suitable determinative technique that can meet appropriate performance criteria. This option to use a continuous automated sampling system takes effect on the date a final performance specification applicable to Hg from monitors is published in the Federal Register or the date of approval of a site-specific monitoring plan. The owner or operator of an affected facility as defined in § 60.50c(a)(3) and (4) who elects to continuously sample Hg emissions instead of sampling and testing using EPA Reference Method 29 of appendix A-8 of this part, or an approved alternative method for measuring Hg emissions, shall install, calibrate, maintain, and operate a continuous automated sampling system and shall comply with the requirements specified in § 60.58b(p) and (q) of subpart Eb of this part.
              (d) Except as provided in paragraphs (c)(4) through (c)(7) of this section, the owner or operator of an affected facility equipped with a dry scrubber followed by a fabric filter, a wet scrubber, or a dry scrubber followed by a fabric filter and wet scrubber shall:
              (1) Establish the appropriate maximum and minimum operating parameters, indicated in table 3 of this subpart for each control system, as site specific operating parameters during the initial performance test to determine compliance with the emission limits; and
              (2) Following the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, ensure that the affected facility does not operate above any of the applicable maximum operating parameters or below any of the applicable minimum operating parameters listed in table 3 of this subpart and measured as 3-hour rolling averages (calculated each hour as the average of the previous 3 operating hours) at all times. Operating parameter limits do not apply during performance tests. Operation above the established maximum or below the established minimum operating parameter(s) shall constitute a violation of established operating parameter(s).
              (e) Except as provided in paragraph (i) of this section, for affected facilities equipped with a dry scrubber followed by a fabric filter:
              (1) Operation of the affected facility above the maximum charge rate and below the minimum secondary chamber temperature (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the CO emission limit.
              (2) Operation of the affected facility above the maximum fabric filter inlet temperature, above the maximum charge rate, and below the minimum dioxin/furan sorbent flow rate (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the dioxin/furan emission limit.
              (3) Operation of the affected facility above the maximum charge rate and below the minimum HCl sorbent flow rate (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the HCl emission limit.
              (4) Operation of the affected facility above the maximum charge rate and below the minimum Hg sorbent flow rate (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the Hg emission limit.
              (5) Use of the bypass stack shall constitute a violation of the PM, dioxin/furan, HCl, Pb, Cd and Hg emissions limits.
              (6) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the CO emissions limit as measured by the CO CEMS specified in paragraph (c)(4) of this section shall constitute a violation of the CO emissions limit.
              (7) For an affected facility as defined in § 60.50c(a)(3) and (4), failure to initiate corrective action within 1 hour of a bag leak detection system alarm; or failure to operate and maintain the fabric filter such that the alarm is not engaged for more than 5 percent of the total operating time in a 6-month block reporting period shall constitute a violation of the PM emissions limit. If inspection of the fabric filter demonstrates that no corrective action is required, no alarm time is counted. If corrective action is required, each alarm is counted as a minimum of 1 hour. If it takes longer than 1 hour to initiate corrective action, the alarm time is counted as the actual amount of time taken to initiate corrective action. If the bag leak detection system is used to demonstrate compliance with the opacity limit, this would also constitute a violation of the opacity emissions limit.

              (8) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the PM, HCl, Pb, Cd, and/or Hg emissions limit as measured by the CEMS specified in paragraph (c)(5) of this section shall constitute a violation of the applicable emissions limit.
              (9) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the dioxin/furan emissions limit as measured by the continuous automated sampling system specified in paragraph (c)(6) of this section shall constitute a violation of the dioxin/furan emissions limit.
              (10) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the Hg emissions limit as measured by the continuous automated sampling system specified in paragraph (c)(7) of this section shall constitute a violation of the Hg emissions limit.
              (f) Except as provided in paragraph (i) of this section, for affected facilities equipped with a wet scrubber:
              (1) Operation of the affected facility above the maximum charge rate and below the minimum pressure drop across the wet scrubber or below the minimum horsepower or amperage to the system (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the PM emission limit.
              (2) Operation of the affected facility above the maximum charge rate and below the minimum secondary chamber temperature (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the CO emission limit.
              (3) Operation of the affected facility above the maximum charge rate, below the minimum secondary chamber temperature, and below the minimum scrubber liquor flow rate (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the dioxin/furan emission limit.
              (4) Operation of the affected facility above the maximum charge rate and below the minimum scrubber liquor pH (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the HCl emission limit.
              (5) Operation of the affected facility above the maximum flue gas temperature and above the maximum charge rate (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the Hg emission limit.
              (6) Use of the bypass stack shall constitute a violation of the PM, dioxin/furan, HCl, Pb, Cd and Hg emissions limits.
              (7) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the CO emissions limit as measured by the CO CEMS specified in paragraph (c)(4) of this section shall constitute a violation of the CO emissions limit.
              (8) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the PM, HCl, Pb, Cd, and/or Hg emissions limit as measured by the CEMS specified in paragraph (c)(5) of this section shall constitute a violation of the applicable emissions limit.
              (9) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the dioxin/furan emissions limit as measured by the continuous automated sampling system specified in paragraph (c)(6) of this section shall constitute a violation of the dioxin/furan emissions limit.
              (10) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the Hg emissions limit as measured by the continuous automated sampling system specified in paragraph (c)(7) of this section shall constitute a violation of the Hg emissions limit.
              (g) Except as provided in paragraph (i) of this section, for affected facilities equipped with a dry scrubber followed by a fabric filter and a wet scrubber:
              (1) Operation of the affected facility above the maximum charge rate and below the minimum secondary chamber temperature (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the CO emission limit.
              (2) Operation of the affected facility above the maximum fabric filter inlet temperature, above the maximum charge rate, and below the minimum dioxin/furan sorbent flow rate (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the dioxin/furan emission limit.

              (3) Operation of the affected facility above the maximum charge rate and below the minimum scrubber liquor pH (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the HCl emission limit.

              (4) Operation of the affected facility above the maximum charge rate and below the minimum Hg sorbent flow rate (each measured on a 3-hour rolling average) simultaneously shall constitute a violation of the Hg emission limit.
              (5) Use of the bypass stack shall constitute a violation of the PM, dioxin/furan, HCl, Pb, Cd and Hg emissions limits.
              (6) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the CO emissions limit as measured by the CO CEMS specified in paragraph (c)(4) of this section shall constitute a violation of the CO emissions limit.
              (7) For an affected facility as defined in § 60.50c(a)(3) and (4), failure to initiate corrective action within 1 hour of a bag leak detection system alarm; or failure to operate and maintain the fabric filter such that the alarm is not engaged for more than 5 percent of the total operating time in a 6-month block reporting period shall constitute a violation of the PM emissions limit. If inspection of the fabric filter demonstrates that no corrective action is required, no alarm time is counted. If corrective action is required, each alarm is counted as a minimum of 1 hour. If it takes longer than 1 hour to initiate corrective action, the alarm time is counted as the actual amount of time taken to initiate corrective action. If the bag leak detection system is used to demonstrate compliance with the opacity limit, this would also constitute a violation of the opacity emissions limit.
              (8) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the PM, HCl, Pb, Cd, and/or Hg emissions limit as measured by the CEMS specified in paragraph (c)(5) of this section shall constitute a violation of the applicable emissions limit.
              (9) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the dioxin/furan emissions limit as measured by the continuous automated sampling system specified in paragraph (c)(6) of this section shall constitute a violation of the dioxin/furan emissions limit.
              (10) Operation of the affected facility as defined in § 60.50c(a)(3) and (4) above the Hg emissions limit as measured by the continuous automated sampling system specified in paragraph (c)(7) of this section shall constitute a violation of the Hg emissions limit.
              (h) The owner or operator of an affected facility as defined in § 60.50c(a)(3) and (4) equipped with selective noncatalytic reduction technology shall:
              (1) Establish the maximum charge rate, the minimum secondary chamber temperature, and the minimum reagent flow rate as site specific operating parameters during the initial performance test to determine compliance with the emissions limits;
              (2) Following the date on which the initial performance test is completed or is required to be completed under § 60.8, whichever date comes first, ensure that the affected facility does not operate above the maximum charge rate, or below the minimum secondary chamber temperature or the minimum reagent flow rate measured as 3-hour rolling averages (calculated each hour as the average of the previous 3 operating hours) at all times. Operating parameter limits do not apply during performance tests.

              (3) Except as provided in paragraph (i) of this section, operation of the affected facility above the maximum charge rate, below the minimum secondary chamber temperature, and below the minimum reagent flow rate simultaneously shall constitute a violation of the NOX emissions limit.
              (i) The owner or operator of an affected facility may conduct a repeat performance test within 30 days of violation of applicable operating parameter(s) to demonstrate that the affected facility is not in violation of the applicable emissions limit(s). Repeat performance tests conducted pursuant to this paragraph shall be conducted using the identical operating parameters that indicated a violation under paragraph (e), (f), (g), or (h) of this section.

              (j) The owner or operator of an affected facility using an air pollution control device other than a dry scrubber followed by a fabric filter, a wet scrubber, a dry scrubber followed by a fabric filter and a wet scrubber, or selective noncatalytic reduction technology to comply with the emissions limits under § 60.52c shall petition the Administrator for other site-specific operating parameters to be established during the initial performance test and continuously monitored thereafter. The owner or operator shall not conduct the initial performance test until after the petition has been approved by the Administrator.
              (k) The owner or operator of an affected facility may conduct a repeat performance test at any time to establish new values for the operating parameters. The Administrator may request a repeat performance test at any time.
              [62 FR 48382, Sept. 15, 1997, as amended at 65 FR 61753, Oct. 17, 2000; 74 FR 51409, Oct. 6, 2009; 78 FR 28066, May 13, 2013]

              § 60.57c
              Monitoring requirements.
              (a) Except as provided in § 60.56c(c)(4) through (c)(7), the owner or operator of an affected facility shall install, calibrate (to manufacturers' specifications), maintain, and operate devices (or establish methods) for monitoring the applicable maximum and minimum operating parameters listed in Table 3 to this subpart (unless CEMS are used as a substitute for certain parameters as specified) such that these devices (or methods) measure and record values for these operating parameters at the frequencies indicated in Table 3 of this subpart at all times.
              (b) The owner or operator of an affected facility as defined in § 60.50c(a)(3) and (4) that uses selective noncatalytic reduction technology shall install, calibrate (to manufacturers' specifications), maintain, and operate devices (or establish methods) for monitoring the operating parameters listed in § 60.56c(h) such that the devices (or methods) measure and record values for the operating parameters at all times. Operating parameter values shall be measured and recorded at the following minimum frequencies:
              (1) Maximum charge rate shall be measured continuously and recorded once each hour;
              (2) Minimum secondary chamber temperature shall be measured continuously and recorded once each minute; and
              (3) Minimum reagent flow rate shall be measured hourly and recorded once each hour.
              (c) The owner or operator of an affected facility shall install, calibrate (to manufacturers' specifications), maintain, and operate a device or method for measuring the use of the bypass stack including date, time, and duration.
              (d) The owner or operator of an affected facility using an air pollution control device other than a dry scrubber followed by a fabric filter, a wet scrubber, a dry scrubber followed by a fabric filter and a wet scrubber, or selective noncatalytic reduction technology to comply with the emissions limits under § 60.52c shall install, calibrate (to manufacturers' specifications), maintain, and operate the equipment necessary to monitor the site-specific operating parameters developed pursuant to § 60.56c(j).
              (e) The owner or operator of an affected facility shall obtain monitoring data at all times during HMIWI operation except during periods of monitoring equipment malfunction, calibration, or repair. At a minimum, valid monitoring data shall be obtained for 75 percent of the operating hours per day for 90 percent of the operating days per calendar quarter that the affected facility is combusting hospital waste and/or medical/infectious waste.
              (f) The owner or operator of an affected facility as defined in § 60.50c(a)(3) and (4) shall ensure that each HMIWI subject to the emissions limits in § 60.52c undergoes an initial air pollution control device inspection that is at least as protective as the following:
              (1) At a minimum, an inspection shall include the following:
              (i) Inspect air pollution control device(s) for proper operation, if applicable;
              (ii) Ensure proper calibration of thermocouples, sorbent feed systems, and any other monitoring equipment; and
              (iii) Generally observe that the equipment is maintained in good operating condition.

              (2) Within 10 operating days following an air pollution control device inspection, all necessary repairs shall be completed unless the owner or operator obtains written approval from the Administrator establishing a date whereby all necessary repairs of the designated facility shall be completed.
              (g) The owner or operator of an affected facility as defined in § 60.50c(a)(3) and (4) shall ensure that each HMIWI subject to the emissions limits under § 60.52c undergoes an air pollution control device inspection annually (no more than 12 months following the previous annual air pollution control device inspection), as outlined in paragraphs (f)(1) and (f)(2) of this section.
              (h) For affected facilities as defined in § 60.50c(a)(3) and (4) that use an air pollution control device that includes a fabric filter and are not demonstrating compliance using PM CEMS, determine compliance with the PM emissions limit using a bag leak detection system and meet the requirements in paragraphs (h)(1) through (h)(12) of this section for each bag leak detection system.
              (1) Each triboelectric bag leak detection system may be installed, calibrated, operated, and maintained according to the “Fabric Filter Bag Leak Detection Guidance,” (EPA-454/R-98-015, September 1997). This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality Planning and Standards; Sector Policies and Programs Division; Measurement Policy Group (D-243-02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emissions Measurement Center Continuous Emissions Monitoring. Other types of bag leak detection systems shall be installed, operated, calibrated, and maintained in a manner consistent with the manufacturer's written specifications and recommendations.
              (2) The bag leak detection system shall be certified by the manufacturer to be capable of detecting PM emissions at concentrations of 10 milligrams per actual cubic meter (0.0044 grains per actual cubic foot) or less.
              (3) The bag leak detection system sensor shall provide an output of relative PM loadings.
              (4) The bag leak detection system shall be equipped with a device to continuously record the output signal from the sensor.
              (5) The bag leak detection system shall be equipped with an audible alarm system that will sound automatically when an increase in relative PM emissions over a preset level is detected. The alarm shall be located where it is easily heard by plant operating personnel.
              (6) For positive pressure fabric filter systems, a bag leak detector shall be installed in each baghouse compartment or cell.
              (7) For negative pressure or induced air fabric filters, the bag leak detector shall be installed downstream of the fabric filter.
              (8) Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors.
              (9) The baseline output shall be established by adjusting the range and the averaging period of the device and establishing the alarm set points and the alarm delay time according to section 5.0 of the “Fabric Filter Bag Leak Detection Guidance.”
              (10) Following initial adjustment of the system, the sensitivity or range, averaging period, alarm set points, or alarm delay time may not be adjusted. In no case may the sensitivity be increased by more than 100 percent or decreased more than 50 percent over a 365-day period unless such adjustment follows a complete fabric filter inspection that demonstrates that the fabric filter is in good operating condition. Each adjustment shall be recorded.
              (11) Record the results of each inspection, calibration, and validation check.

              (12) Initiate corrective action within 1 hour of a bag leak detection system alarm; operate and maintain the fabric filter such that the alarm is not engaged for more than 5 percent of the total operating time in a 6-month block reporting period. If inspection of the fabric filter demonstrates that no corrective action is required, no alarm time is counted. If corrective action is required, each alarm is counted as a minimum of 1 hour. If it takes longer than 1 hour to initiate corrective action, the alarm time is counted as the actual amount of time taken to initiate corrective action.
              [62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51412, Oct. 6, 2009]

              § 60.58c
              Reporting and recordkeeping requirements.
              (a) The owner or operator of an affected facility shall submit notifications, as provided by § 60.7. In addition, the owner or operator shall submit the following information:
              (1) Prior to commencement of construction;
              (i) A statement of intent to construct;
              (ii) The anticipated date of commencement of construction; and
              (iii) All documentation produced as a result of the siting requirements of § 60.54c.
              (2) Prior to initial startup;
              (i) The type(s) of waste to be combusted;
              (ii) The maximum design waste burning capacity;
              (iii) The anticipated maximum charge rate; and
              (iv) If applicable, the petition for site-specific operating parameters under § 60.56c(j).
              (b) The owner or operator of an affected facility shall maintain the following information (as applicable) for a period of at least 5 years:
              (1) Calendar date of each record;
              (2) Records of the following data:
              (i) Concentrations of any pollutant listed in § 60.52c or measurements of opacity as determined by the continuous emission monitoring system (if applicable);
              (ii) Results of fugitive emissions (by EPA Reference Method 22) tests, if applicable;
              (iii) HMIWI charge dates, times, and weights and hourly charge rates;
              (iv) Fabric filter inlet temperatures during each minute of operation, as applicable;
              (v) Amount and type of dioxin/furan sorbent used during each hour of operation, as applicable;
              (vi) Amount and type of Hg sorbent used during each hour of operation, as applicable;
              (vii) Amount and type of HCl sorbent used during each hour of operation, as applicable;

              (viii) For affected facilities as defined in § 60.50c(a)(3) and (4), amount and type of NOX reagent used during each hour of operation, as applicable;
              (ix) Secondary chamber temperatures recorded during each minute of operation;
              (x) Liquor flow rate to the wet scrubber inlet during each minute of operation, as applicable;
              (xi) Horsepower or amperage to the wet scrubber during each minute of operation, as applicable;
              (xii) Pressure drop across the wet scrubber system during each minute of operation, as applicable,
              (xiii) Temperature at the outlet from the wet scrubber during each minute of operation, as applicable;
              (xiv) pH at the inlet to the wet scrubber during each minute of operation, as applicable,
              (xv) Records indicating use of the bypass stack, including dates, times, and durations, and
              (xvi) For affected facilities complying with § 60.56c(j) and § 60.57c(d), the owner or operator shall maintain all operating parameter data collected;
              (xvii) For affected facilities as defined in § 60.50c(a)(3) and (4), records of the annual air pollution control device inspections, any required maintenance, and any repairs not completed within 10 days of an inspection or the timeframe established by the Administrator.
              (xviii) For affected facilities as defined in § 60.50c(a)(3) and (4), records of each bag leak detection system alarm, the time of the alarm, the time corrective action was initiated and completed, and a brief description of the cause of the alarm and the corrective action taken, as applicable.
              (xix) For affected facilities as defined in § 60.50c(a)(3) and (4), concentrations of CO as determined by the continuous emissions monitoring system.

              (3) Identification of calendar days for which data on emission rates or operating parameters specified under paragraph (b)(2) of this section have not been obtained, with an identification of the emission rates or operating parameters not measured, reasons for not obtaining the data, and a description of corrective actions taken.

              (4) Identification of calendar days, times and durations of malfunctions, a description of the malfunction and the corrective action taken.
              (5) Identification of calendar days for which data on emission rates or operating parameters specified under paragraph (b)(2) of this section exceeded the applicable limits, with a description of the exceedances, reasons for such exceedances, and a description of corrective actions taken.
              (6) The results of the initial, annual, and any subsequent performance tests conducted to determine compliance with the emissions limits and/or to establish or re-establish operating parameters, as applicable, and a description, including sample calculations, of how the operating parameters were established or re-established, if applicable.
              (7) All documentation produced as a result of the siting requirements of § 60.54c;
              (8) Records showing the names of HMIWI operators who have completed review of the information in § 60.53c(h) as required by § 60.53c(i), including the date of the initial review and all subsequent annual reviews;
              (9) Records showing the names of the HMIWI operators who have completed the operator training requirements, including documentation of training and the dates of the training;
              (10) Records showing the names of the HMIWI operators who have met the criteria for qualification under § 60.53c and the dates of their qualification; and
              (11) Records of calibration of any monitoring devices as required under § 60.57c(a) through (d).
              (c) The owner or operator of an affected facility shall submit the information specified in paragraphs (c)(1) through (c)(4) of this section no later than 60 days following the initial performance test. All reports shall be signed by the facilities manager.
              (1) The initial performance test data as recorded under § 60.56c(b)(1) through (b)(14), as applicable.
              (2) The values for the site-specific operating parameters established pursuant to § 60.56c(d), (h), or (j), as applicable, and a description, including sample calculations, of how the operating parameters were established during the initial performance test.
              (3) The waste management plan as specified in § 60.55c.
              (4) For each affected facility as defined in § 60.50c(a)(3) and (4) that uses a bag leak detection system, analysis and supporting documentation demonstrating conformance with EPA guidance and specifications for bag leak detection systems in § 60.57c(h).
              (d) An annual report shall be submitted 1 year following the submissions of the information in paragraph (c) of this section and subsequent reports shall be submitted no more than 12 months following the previous report (once the unit is subject to permitting requirements under title V of the Clean Air Act, the owner or operator of an affected facility must submit these reports semiannually). The annual report shall include the information specified in paragraphs (d)(1) through (11) of this section. All reports shall be signed by the facilities manager.
              (1) The values for the site-specific operating parameters established pursuant to § 60.56c(d), (h), or (j), as applicable.
              (2) The highest maximum operating parameter and the lowest minimum operating parameter, as applicable, for each operating parameter recorded for the calendar year being reported, pursuant to § 60.56c(d), (h), or (j), as applicable.
              (3) The highest maximum operating parameter and the lowest minimum operating parameter, as applicable, for each operating parameter recorded pursuant to § 60.56c(d), (h), or (j) for the calendar year preceding the year being reported, in order to provide the Administrator with a summary of the performance of the affected facility over a 2-year period.
              (4) Any information recorded under paragraphs (b)(3) through (b)(5) of this section for the calendar year being reported.

              (5) Any information recorded under paragraphs (b)(3) through (b)(5) of this section for the calendar year preceding the year being reported, in order to provide the Administrator with a summary of the performance of the affected facility over a 2-year period.

              (6) If a performance test was conducted during the reporting period, the results of that test.
              (7) If no exceedances or malfunctions were reported under paragraphs (b)(3) through (b)(5) of this section for the calendar year being reported, a statement that no exceedances occurred during the reporting period.
              (8) Any use of the bypass stack, the duration, reason for malfunction, and corrective action taken.
              (9) For affected facilities as defined in § 60.50c(a)(3) and (4), records of the annual air pollution control device inspection, any required maintenance, and any repairs not completed within 10 days of an inspection or the timeframe established by the Administrator.
              (10) For affected facilities as defined in § 60.50c(a)(3) and (4), records of each bag leak detection system alarm, the time of the alarm, the time corrective action was initiated and completed, and a brief description of the cause of the alarm and the corrective action taken, as applicable.
              (11) For affected facilities as defined in § 60.50c(a)(3) and (4), concentrations of CO as determined by the continuous emissions monitoring system.
              (e) The owner or operator of an affected facility shall submit semiannual reports containing any information recorded under paragraphs (b)(3) through (b)(5) of this section no later than 60 days following the reporting period. The first semiannual reporting period ends 6 months following the submission of information in paragraph (c) of this section. Subsequent reports shall be submitted no later than 6 calendar months following the previous report. All reports shall be signed by the facilities manager.
              (f) All records specified under paragraph (b) of this section shall be maintained onsite in either paper copy or computer-readable format, unless an alternative format is approved by the Administrator.

              (g) For affected facilities, as defined in § 60.50c(a)(3) and (4), that choose to submit an electronic copy of stack test reports to EPA's WebFIRE data base, as of December 31, 2011, the owner or operator of an affected facility shall enter the test data into EPA's data base using the Electronic Reporting Tool located at http://www.epa.gov/ttn/chief/ert /ert__tool.html.

              [62 FR 48382, Sept. 15, 1997, as amended at 74 FR 51413, Oct. 6, 2009; 76 FR 18413, Apr. 4, 2011]

              Pt. 60, Subpt. Ec, Table 1A
              Table 1A to Subpart Ec of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Affected Facilities as Defined in § 60.50c(a)(1) and (2)

                  Pollutant
                  Units (7 percent oxygen, dry basis)
                  Emissions limits
                  HMIWI size
                  Small
                  Medium
                  Large
                  Averaging time 1

                  Methodfor
                    demonstrating
                    compliance 2

                  Particulate matter
                  Milligrams per dry standard cubic meter (grains per dry standard cubic foot)
                  69 (0.03)
                  34 (0.015)
                  34 (0.015)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 5 of appendix A-3 of part 60, or EPA Reference Method M 26A or 29 of appendix A-8 of part 60.

                  Carbon monoxide
                  Parts per million by volume
                  40
                  40
                  40
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 10 or 10B of appendix A-4 of part 60.

                  Dioxins/furans
                  Nanograms per dry standard cubic meter total dioxins/furans (grains per billion dry standard cubic feet) or nanograms per dry standard cubic meter TEQ (grains per billion dry standard cubic feet)
                  125 (55) or 2.3 (1.0)
                  25 (11) or 0.6 (0.26)
                  25 (11) or 0.6 (0.26)
                  3-run average (4-hour minimum sample time per run)
                  EPA Reference Method 23 of appendix A-7 of part 60.

                  Hydrogen chloride
                  Parts per million by volume or percent reduction
                  15 or 99%
                  15 or 99%
                  15 or 99%
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 26 or 26A of appendix A-8 of part 60.

                  Sulfur dioxide
                  Parts per million by volume
                  55
                  55
                  55
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 6 or 6C of appendix A-4 of part 60.

                  Nitrogen oxides
                  Parts per million by volume
                  250
                  250
                  250
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 7 or 7E of appendix A-4 of part 60.

                  Lead
                  Milligrams per dry standard cubic meter (grains per thousand dry standard cubic feet) or percent reduction
                  1.2 (0.52) or 70%
                  0.07 (0.03) or 98%
                  0.07 (0.03) or 98%
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Cadmium
                  Milligrams per dry standard cubic meter (grains per thousand dry standard cubic feet) or percent reduction
                  0.16 (0.07) or 65%
                  0.04 (0.02) or 90%
                  0.04 (0.02) or 90%
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Mercury
                  Milligrams per dry standard cubic meter (grains per thousand dry standard cubic feet) or percent reduction
                  0.55 (0.24) or 85%
                  0.55 (0.24) or 85%
                  0.55 (0.24) or 85%
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  1 Except as allowed under § 60.56c(c) for HMIWI equipped with CEMS.

                  2 Does not include CEMS and approved alternative non-EPA test methods allowed under § 60.56c(b).

              [74 FR 51414, Oct. 6, 2009, as amended at 76 FR 18414, Apr. 4, 2011]

              Pt. 60, Subpt. Ec, Table 1B
              Table 1B to Subpart Ec of Part 60—Emissions Limits for Small, Medium, and Large HMIWI at Affected Facilities as Defined in § 60.50c(a)(3) and (4)

                  Pollutant
                  Units(7 percent oxygen,
                    dry basis)

                  Emissions limits
                  HMIWI size
                  Small
                  Medium
                  Large
                  Averaging time 1

                  Method fordemonstrating
                    compliance 2

                  Particulate matter
                  Milligrams per dry standard cubic meter (grains per dry standard cubic foot)
                  66 (0.029)
                  22 (0.0095)
                  18 (0.0080)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 5 of appendix A-3 of part 60, or EPA Reference Method M 26A or 29 of appendix A-8 of part 60.

                  Carbon monoxide
                  Parts per million by volume
                  20
                  1.8
                  11
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 10 or 10B of appendix A-4 of part 60.

                  Dioxins/furans
                  Nanograms per dry standard cubic meter total dioxins/furans (grains per billion dry standard cubic feet) or nanograms per dry standard cubic meter TEQ (grains per billion dry standard cubic feet)
                  16 (7.0) or 0.013 (0.0057)
                  0.47 (0.21) or 0.014 (0.0061)
                  9.3 (4.1) or 0.035 (0.015)
                  3-run average (4-hour minimum sample time per run)
                  EPA Reference Method 23 of appendix A-7 of part 60.

                  Hydrogen chloride
                  Parts per million by volume
                  15
                  7.7
                  5.1
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 26 or 26A of appendix A-8 of part 60.

                  Sulfur dioxide
                  Parts per million by volume
                  1.4
                  1.4
                  8.1
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 6 or 6C of appendix A-4 of part 60.

                  Nitrogen oxides
                  Parts per million by volume
                  67
                  67
                  140
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 7 or 7E of appendix A-4 of part 60.

                  Lead
                  Milligrams per dry standard cubic meter (grains per thousand dry standard cubic feet)
                  0.31 (0.14)
                  0.018 (0.0079)
                  0.00069 (0.00030)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Cadmium
                  Milligrams per dry standard cubic meter (grains per thousand dry standard cubic feet)
                  0.017 (0.0074)
                  0.0098 (0.0043)
                  0.00013 (0.000057)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  Mercury
                  Milligrams per dry standard cubic meter (grains per thousand dry standard cubic feet)
                  0.014 (0.0061)
                  0.0035 (0.0015)
                  0.0013 (0.00057)
                  3-run average (1-hour minimum sample time per run)
                  EPA Reference Method 29 of appendix A-8 of part 60.

                  1 Except as allowed under § 60.56c(c) for HMIWI equipped with CEMS.

                  2 Does not include CEMS and approved alternative non-EPA test methods allowed under § 60.56c(b).

              [74 FR 51414, Oct. 6, 2009, as amended at 76 FR 18414, Apr. 4, 2011]

              Pt. 60, Subpt. Ec, Table 2
              Table 2 to Subpart Ec of Part 60—Toxic Equivalency Factors

                  Dioxin/furan congener
                  Toxic equivalency factor

                  2,3,7,8-tetrachlorinated dibenzo-p-dioxin
                  1

                  1,2,3,7,8-pentachlorinated dibenzo-p-dioxin
                  0.5

                  1,2,3,4,7,8-hexachlorinated dibenzo-p-dioxin
                  0.1

                  1,2,3,7,8,9-hexachlorinated dibenzo-p-dioxin
                  0.1

                  1,2,3,6,7,8-hexachlorinated dibenzo-p-dioxin
                  0.1

                  1,2,3,4,6,7,8-heptachlorinated dibenzo-p-dioxin
                  0.01

                  octachlorinated dibenzo-p-dioxin
                  0.001

                  2,3,7,8-tetrachlorinated dibenzofuran
                  0.1

                  2,3,4,7,8-pentachlorinated dibenzofuran
                  0.5

                  1,2,3,7,8-pentachlorinated dibenzofuran
                  0.05

                  1,2,3,4,7,8-hexachlorinated dibenzofuran
                  0.1

                  1,2,3,6,7,8-hexachlorinated dibenzofuran
                  0.1

                  1,2,3,7,8,9-hexachlorinated dibenzofuran
                  0.1

                  2,3,4,6,7,8-hexachlorinated dibenzofuran
                  0.1

                  1,2,3,4,6,7,8-heptachlorinated dibenzofuran
                  0.01

                  1,2,3,4,7,8,9-heptachlorinated dibenzofuran
                  0.01

                  Octachlorinated dibenzofuran
                  0.001

              Pt. 60, Subpt. Ec, Table 3
              Table 3 to Subpart Ec of Part 60—Operating Parameters To Be Monitored and Minimum Measurement and Recording Frequencies

                  Operating parameters to be monitored
                  Minimum frequency
                  Data measurement
                  Data recording
                  Control system
                  Dry scrubber followed by fabric filter
                  Wet scrubber
                  Dry scrubber followed by fabric filter and wet scrubber

                  Maximum operating parameters:

                  Maximum charge rate
                  Continuous
                  1 × hour
                  ✔
                  ✔
                  ✔

                  Maximum fabric filter inlet temperature
                  Continuous
                  1 × minute
                  ✔

                  ✔

                  Maximum flue gas temperature
                  Continuous
                  1 × minute
                  ✔
                  ✔

                  Minimum operating parameters:

                  Minimum secondary chamber temperature
                  Continuous
                  1 × minute
                  ✔
                  ✔
                  ✔

                  Minimum dioxin/furan sorbent flow rate
                  Hourly
                  1 × hour
                  ✔

                  ✔

                  Minimum HCI sorbent flow rate
                  Hourly
                  1 × hour
                  ✔

                  ✔

                  Minimum mercury (Hg) sorbent flow rate
                  Hourly
                  1 × hour
                  ✔

                  ✔

                  Minimum pressure drop across the wet scrubber or minimum horsepower or amperage to wet scrubber
                  Continuous
                  1 × minute

                  ✔
                  ✔

                  Minimum scrubber liquor flow rate
                  Continuous
                  1 × minute

                  ✔
                  ✔

                  Minimum scrubber liquor pH
                  Continuous
                  1 × minute

                  ✔
                  ✔

            Subpart F—Standards of Performance for Portland Cement Plants

              § 60.60
              Applicability and designation of affected facility.
              (a) The provisions of this subpart are applicable to the following affected facilities in portland cement plants: Kiln, clinker cooler, raw mill system, finish mill system, raw mill dryer, raw material storage, clinker storage, finished product storage, conveyor transfer points, bagging and bulk loading and unloading systems.
              (b) Any facility under paragraph (a) of this section that commences construction or modification after August 17, 1971, is subject to the requirements of this subpart.
              [42 FR 37936, July 25, 1977]

              § 60.61
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.
              (a) Portland cement plant means any facility manufacturing portland cement by either the wet or dry process.
              (b) Bypass means any system that prevents all or a portion of the kiln or clinker cooler exhaust gases from entering the main control device and ducts the gases through a separate control device. This does not include emergency systems designed to duct exhaust gases directly to the atmosphere in the event of a malfunction of any control device controlling kiln or clinker cooler emissions.
              (c) Bypass stack means the stack that vents exhaust gases to the atmosphere from the bypass control device.
              (d) Monovent means an exhaust configuration of a building or emission control device (e.g., positive-pressure fabric filter) that extends the length of the structure and has a width very small in relation to its length (i.e., length to width ratio is typically greater than 5:1). The exhaust may be an open vent with or without a roof, louvered vents, or a combination of such features.

              (e) Excess emissions means, with respect to this subpart, results of any required measurements outside the applicable range (e.g., emissions limitations, parametric operating limits) that is permitted by this subpart. The values of measurements will be in the same units and averaging time as the values specified in this subpart for the limitations.
              (f) Operating day means a 24-hour period beginning at 12:00 midnight during which the kiln produces clinker at any time. For calculating 30 day rolling average emissions, an operating day does not include the hours of operation during startup or shutdown.
              (g) Rolling average means the weighted average of all data, meeting QA/QC requirements or otherwise normalized, collected during the applicable averaging period. The period of a rolling average stipulates the frequency of data averaging and reporting. To demonstrate compliance with an operating parameter a 30-day rolling average period requires calculation of a new average value each operating day and shall include the average of all the hourly averages of the specific operating parameter. For demonstration of compliance with an emissions limit based on pollutant concentration, a 30-day rolling average is comprised of the average of all the hourly average concentrations over the previous 30 operating days. For demonstration of compliance with an emissions limit based on lbs-pollutant per production unit, the 30-day rolling average is calculated by summing the hourly mass emissions over the previous 30 operating days, then dividing that sum by the total production during the same period.
              (h) Run average means the average of the recorded parameter values for a run.
              [36 FR 24877, Dec. 23, 1971, as amended at 39 FR 20793, June 13, 1974; 53 FR 50363, Dec. 14, 1988; 78 FR 10032, Feb. 12, 2013; 80 FR 44776, July 27, 2015]

              § 60.62
              Standards.
              (a) On and after the date on which the performance test required to be conducted by § 60.8 is completed, you may not discharge into the atmosphere from any kiln any gases which:
              (1) Contain particulate matter (PM) in excess of:
              (i) 0.30 pounds per ton of feed (dry basis) to the kiln for kilns constructed, reconstructed, or modified after August 17, 1971 but on or before June 16, 2008.
              (ii) 0.02 pound per ton of clinker if construction or reconstruction of the kiln commenced after June 16, 2008.
              (iii) Kilns that have undergone a modification may not discharge into the atmosphere any gases which contain PM in excess of 0.07 pound per ton of clinker.
              (2) Exhibit greater than 20 percent opacity for kilns constructed, reconstructed, or modified after August 17, 1971 but on or before June 16, 2008, except that this opacity limit does not apply to any kiln subject to a PM limit in paragraph (a)(1) of this section that uses a PM continuous parametric monitoring system (CPMS).
              (3) Exceed 1.50 pounds of nitrogen oxide (NOX) per ton of clinker on a 30-operating day rolling average if construction, reconstruction, or modification of the kiln commences after June 16, 2008, except this limit does not apply to any alkali bypass installed on the kiln. An operating day includes all valid data obtained in any daily 24-hour period during which the kiln operates and excludes any measurements made during the daily 24-hour period when the kiln was not operating.
              (4) Exceed 0.4 pounds of sulfur dioxide (SO2) per ton of clinker on a 30-operating day rolling average if construction, reconstruction, or modification commences after June 16, 2008, unless you are demonstrating a 90 percent SO2 emissions reduction measured across the SO2 control device. An operating day includes all valid data obtained in any daily 24-hour period during which the kiln operates, and excludes any measurements made during the daily 24-hour period when the kiln was not operating.
              (b) On and after the date on which the performance test required to be conducted by § 60.8 is completed, you may not discharge into the atmosphere from any clinker cooler any gases which:
              (1) Contain PM in excess of:

              (i) 0.02 pound per ton of clinker if construction or reconstruction of the clinker cooler commences after June 16, 2008.
              (ii) 0.07 pound per ton of clinker if the clinker cooler has undergone a modification.
              (iii) 0.10 lb per ton of feed (dry basis) for clinker coolers constructed, reconstructed, or modified after August 17, 1971, but on or before June 16, 2008.
              (iv) 10 percent opacity for clinker coolers constructed, reconstructed, or modified after August 17, 1971, but on or before June 16, 2008, except that this opacity limit does not apply to any clinker cooler subject to a PM limit in paragraph (b)(1) of this section that uses a PM continuous parametric monitoring system (CPMS).
              (2) If the kiln and clinker cooler exhaust are combined for energy efficiency purposes and sent to a single control device, the appropriate kiln PM limit may be adjusted using the procedures in § 63.1343(b) of this chapter.
              (3) If the kiln has a separated alkali bypass stack and/or an inline coal mill with a separate stack, you must combine the PM emissions from the bypass stack and/or the inline coal mill stack with the PM emissions from the main kiln exhaust to determine total PM emissions.
              (c) On and after the date on which the performance test required to be conducted by § 60.8 is completed, you may not discharge into the atmosphere from any affected facility other than the kiln and clinker cooler any gases which exhibit 10 percent opacity, or greater.
              (d) If you have an affected source subject to this subpart with a different emissions limit or requirement for the same pollutant under another regulation in title 40 of this chapter, once you are in compliance with the most stringent emissions limit or requirement, you are not subject to the less stringent requirement. Until you are in compliance with the more stringent limit, the less stringent limit continues to apply.
              (e) The compliance date for all revised monitoring and recordkeeping requirements contained in this rule will be the same as listed in 63.1351(c) unless you commenced construction as of June 16, 2008, at which time the compliance date is November 8, 2010 or upon startup, whichever is later.
              [75 FR 55034, Sept. 9, 2010, as amended at 78 FR 10032, Feb. 12, 2013; 80 FR 44777, July 27, 2015]

              § 60.63
              Monitoring of operations.
              (a) [Reserved]
              (b) Clinker production monitoring requirements. For any kiln subject to an emissions limitation on PM, NOX, or SO2 emissions (lb/ton of clinker), you must:
              (1) Determine hourly clinker production by one of two methods:
              (i) Install, calibrate, maintain, and operate a permanent weigh scale system to measure and record weight rates of the amount of clinker produced in tons of mass per hour. The system of measuring hourly clinker production must be maintained within ±5 percent accuracy or
              (ii) Install, calibrate, maintain, and operate a permanent weigh scale system to measure and record weight rates of the amount of feed to the kiln in tons of mass per hour. The system of measuring feed must be maintained within ±5 percent accuracy. Calculate your hourly clinker production rate using a kiln specific feed-to-clinker ratio based on reconciled clinker production rates determined for accounting purposes and recorded feed rates. This ratio should be updated monthly. Note that if this ratio changes at clinker reconciliation, you must use the new ratio going forward, but you do not have to retroactively change clinker production rates previously estimated.
              (iii) For each kiln operating hour for which you do not have data on clinker production or the amount of feed to the kiln, use the value from the most recent previous hour for which valid data are available.

              (2) Determine, record, and maintain a record of the accuracy of the system of measuring hourly clinker production rates or feed rates before initial use (for new sources) or by the effective compliance date of this rule (for existing sources). During each quarter of source operation, you must determine, record, and maintain a record of the ongoing accuracy of the system of measuring hourly clinker production rates or feed rates.
              (3) If you measure clinker production directly, record the daily clinker production rates; if you measure the kiln feed rates and calculate clinker production, record the daily kiln feed and clinker production rates.
              (c) PM Emissions Monitoring Requirements. (1) For each kiln or clinker cooler subject to a PM emissions limit in §§ 60.62(a)1(ii) and 60.62(a)1(iii) or §§ 60.62(b)(1)(i) and 60.62(b)(1)(ii), you must demonstrate compliance through an initial performance test. You will conduct your performance test using Method 5 or Method 5I at appendix A-3 to part 60 of this chapter. You must also monitor continuous performance through use of a PM CPMS.
              (2) For your PM CPMS, you will establish a site-specific operating limit. If your PM performance test demonstrates your PM emission levels to be below 75 percent of your emission limit you will use the average PM CPMS value recorded during the PM compliance test, the milliamp equivalent of zero output from your PM CPMS, and the average PM result of your compliance test to establish your operating limit equivalent to 75 percent of the standard. If your PM compliance test demonstrates your PM emission levels to be at or above 75 percent of your emission limit you will use the average PM CPMS value recorded during the PM compliance test demonstrating compliance with the PM limit to establish your operating limit. You will use the PM CPMS to demonstrate continuous compliance with your operating limit. You must repeat the performance test annually and reassess and adjust the site-specific operating limit in accordance with the results of the performance test.
              (i) Your PM CPMS must provide a 4-20 milliamp or digital signal output and the establishment of its relationship to manual reference method measurements must be determined in units of milliamps or the monitors digital equivalent.
              (ii) Your PM CPMS operating range must be capable of reading PM concentrations from zero to a level equivalent to two times your allowable emission limit. If your PM CPMS is an auto-ranging instrument capable of multiple scales, the primary range of the instrument must be capable of reading PM concentration from zero to a level equivalent to two times your allowable emission limit.

              (iii) During the initial performance test or any such subsequent performance test that demonstrates compliance with the PM limit, record and average all milliamp or digital output values from the PM CPMS for the periods corresponding to the compliance test runs (e.g., average all your PM CPMS output values for three corresponding 2-hour Method 5I test runs).
              (3) Determine your operating limit as specified in paragraphs (c)(4)(i) through (c)(5) of this section. If your PM performance test demonstrates your PM emission levels to be below 75 percent of your emission limit, you will use the average PM CPMS value recorded during the PM compliance test, the milliamp or digital equivalent of zero output from your PM CPMS, and the average PM result of your compliance test to establish your operating limit. If your PM compliance test demonstrates your PM emission levels to be at or above 75 percent of your emission limit, you will use the average PM CPMS value recorded during the PM compliance test to establish your operating limit. You must verify an existing or establish a new operating limit after each repeated performance test. You must repeat the performance test at least annually and reassess and adjust the site-specific operating limit in accordance with the results of the performance test.
              (4) If the average of your three Method 5 or 5I compliance test runs are below 75 percent of your PM emission limit, you must calculate an operating limit by establishing a relationship of PM CPMS signal to PM concentration using the PM CPMS instrument zero, the average PM CPMS values corresponding to the three compliance test runs, and the average PM concentration from the Method 5 or 5I compliance test with the procedures in (c)(4)(i)(A) through (D) of this section.

              (i) Determine your PM CPMS instrument zero output with one of the following procedures.

              (A) Zero point data for in-situ instruments should be obtained by removing the instrument from the stack and monitoring ambient air on a test bench.
              (B) Zero point data for extractive instruments should be obtained by removing the extractive probe from the stack and drawing in clean ambient air.
              (C) The zero point can also can be obtained by performing manual reference method measurements when the flue gas is free of PM emissions or contains very low PM concentrations (e.g., when your process is not operating, but the fans are operating or your source is combusting only natural gas) and plotting these with the compliance data to find the zero intercept.
              (D) If none of the steps in paragraphs (c)(4)(i)(A) through (C) of this section are possible, you must use a zero output value provided by the manufacturer.
              (ii) Determine your PM CPMS instrument average in milliamps or digital equivalent and the average of your corresponding three PM compliance test runs, using equation 1.

                ER27JY15.006

                Where:

                X1 = The PM CPMS data points for the three runs constituting the performance test,
                Y1 = The PM concentration value for the three runs constituting the performance test, and
                n = The number of data points.

              (iii) With your PM CPMS instrument zero expressed in milliamps or a digital value, your three run average PM CPMS milliamp or digital signal value, and your three run average PM concentration from your three PM performance test runs, determine a relationship of lb/ton-clinker per milliamp or digital signal with equation 2.

                ER27JY15.007

                Where:

                R = The relative lb/ton clinker per milliamp or digital equivalent for your PM CPMS.
                Y1 = The three run average PM lb/ton clinker.
                X1 = The three run average milliamp or digital signal output from your PM CPMS.
                z = The milliamp or digital equivalent of your instrument zero determined from (c)(4)(i) of this section.

              (iv) Determine your source specific 30-day rolling average operating limit using the lb/ton-clinker per milliamp or digital signal value from Equation 2 above in Equation 3, below. This sets your operating limit at the PM CPMS output value corresponding to 75 percent of your emission limit.

                ER27JY15.008

                Where:

                Ol = The operating limit for your PM CPMS on a 30-day rolling average, in milliamps or the digital equivalent.

                L = Your source emission limit expressed in lb/ton clinker.
                z = Your instrument zero in milliamps or a digital equivalent, determined from (1)(i).
                R = The relative lb/ton-clinker per milliamp or digital equivalent, for your PM CPMS, from Equation 2.

              (5) If the average of your three PM compliance test runs is at or above 75 percent of your PM emission limit, you must determine your operating limit by averaging the PM CPMS milliamp or digital equivalent output corresponding to your three PM performance test runs that demonstrate compliance with the emission limit using Equation 4.

                ER27JY15.009

                Where:

                X1 = The PM CPMS data points for all runs i.
                n = The number of data points.
                Oh = Your site specific operating limit, in milliamps or digital equivalent.

              (6) To determine continuous compliance, you must record the PM CPMS output data for all periods when the process is operating, and use all the PM CPMS data for calculations when the source is not out-of-control. You must demonstrate continuous compliance by using all quality-assured hourly average data collected by the PM CPMS for all operating hours to calculate the arithmetic average operating parameter in units of the operating limit (milliamps or the digital equivalent) on a 30 operating day rolling average basis, updated at the end of each new kiln operating day. Use Equation 5 to determine the 30 kiln operating day average.

                ER27JY15.010

                Where:

                Hpvi = The hourly parameter value for hour i.
                n = The number of valid hourly parameter values collected over the previous 30 kiln operating days.

              (7) Use EPA Method 5 or Method 5I of appendix A to part 60 of this chapter to determine PM emissions. For each performance test, conduct at least three separate runs each while the mill is on and the mill is off under the conditions that exist when the affected source is operating at the level reasonably expected to occur. Conduct each test run to collect a minimum sample volume of 2 dscm for determining compliance with a new source limit and 1 dscm for determining compliance with an existing source limit. Calculate the time weighted average of the results from three consecutive runs to determine compliance. You need not determine the particulate matter collected in the impingers (“back half”) of the Method 5 or Method 5I particulate sampling train to demonstrate compliance with the PM standards of this subpart. This shall not preclude the permitting authority from requiring a determination of the “back half” for other purposes.

              (8) For PM performance test reports used to set a PM CPMS operating limit, the electronic submission of the test report must also include the make and model of the PM CPMS instrument, serial number of the instrument, analytical principle of the instrument (e.g. beta attenuation), span of the instruments primary analytical range, milliamp or digital signal value equivalent to the instrument zero output, technique by which this zero value was determined, and the average milliamp or digital equivalent signals corresponding to each PM compliance test run.

              (d) You must install, operate, calibrate, and maintain a CEMS continuously monitoring and recording the concentration by volume of NOX emissions into the atmosphere for any kiln subject to the NOX emissions limit in § 60.62(a)(3). If the kiln has an alkali bypass, NOX emissions from the alkali bypass do not need to be monitored, and NOX emission monitoring of the kiln exhaust may be done upstream of any commingled alkali bypass gases.

              (e) You must install, operate, calibrate, and maintain a CEMS for continuously monitoring and recording the concentration by volume of SO2 emissions into the atmosphere for any kiln subject to the SO2 emissions limit in § 60.62(a)(4). If you are complying with the alternative 90 percent SO2 emissions reduction emissions limit, you must also continuously monitor and record the concentration by volume of SO2 present at the wet scrubber inlet.
              (f) The NOX and SO2 CEMS required under paragraphs (d) and (e) of this section must be installed, operated and maintained according to Performance Specification 2 of appendix B of this part and the requirements in paragraphs (f)(1) through (5) of this section.
              (1) The span value of each NOX CEMS monitor must be set at 125 percent of the maximum estimated hourly potential NOX emission concentration that translates to the applicable emissions limit at full clinker production capacity.

              (2) You must conduct performance evaluations of each NOX CEMS monitor according to the requirements in § 60.13(c) and Performance Specification 2 of appendix B to this part. You must use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to this part for conducting the relative accuracy evaluations. The method ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to Method 7 or 7C of appendix A-4 to this part.
              (3) The span value for the SO2 CEMS monitor is the SO2 emission concentration that corresponds to 125 percent of the applicable emissions limit at full clinker production capacity and the expected maximum fuel sulfur content.

              (4) You must conduct performance evaluations of each SO2 CEMS monitor according to the requirements in § 60.13(c) and Performance Specification 2 of appendix B to this part. You must use Methods 6, 6A, or 6C of appendix A-4 to this part for conducting the relative accuracy evaluations. The method ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to Method 6 or 6A of appendix A-4 to this part.

              (5) You must comply with the quality assurance requirements in Procedure 1 of appendix F to this part for each NOX and SO2 CEMS, including quarterly accuracy determinations for monitors, and daily calibration drift tests.
              (g) For each CPMS or CEMS required under paragraphs (c) through (e) of this section:
              (1) You must operate the monitoring system and collect data at all required intervals at all times the affected source is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments).
              (2) You may not use data recorded during the monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or control activities in calculations used to report emissions or operating levels. A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. An owner or operator must use all the data collected during all other periods in reporting emissions or operating levels.

              (3) You must meet the requirements of § 60.13(h) when determining the 1-hour averages of emissions data.

              (h) You must install, operate, calibrate, and maintain instruments for continuously measuring and recording the stack gas flow rate to allow determination of the pollutant mass emissions rate to the atmosphere for each kiln subject to the PM emissions limits in § 60.62(a)(1)(ii) and (iii) and (b)(1)(i) and (ii), the NOX emissions limit in § 60.62(a)(3), or the SO2 emissions limit in § 60.62(a)(4) according to the requirements in paragraphs (h)(1) through (10), where appropriate, of this section.

              (1) The owner or operator must install each sensor of the flow rate monitoring system in a location that provides representative measurement of the exhaust gas flow rate at the sampling location of the NOX and/or SO2 CEMS, taking into account the manufacturer's recommendations. The flow rate sensor is that portion of the system that senses the volumetric flow rate and generates an output proportional to that flow rate.
              (2) The flow rate monitoring system must be designed to measure the exhaust gas flow rate over a range that extends from a value of at least 20 percent less than the lowest expected exhaust flow rate to a value of at least 20 percent greater than the highest expected exhaust gas flow rate.
              (3) The flow rate monitoring system must have a minimum accuracy of 5 percent of the flow rate.
              (4) The flow rate monitoring system must be equipped with a data acquisition and recording system that is capable of recording values over the entire range specified in paragraph (h)(2) of this section.
              (5) The signal conditioner, wiring, power supply, and data acquisition and recording system for the flow rate monitoring system must be compatible with the output signal of the flow rate sensors used in the monitoring system.
              (6) The flow rate monitoring system must be designed to measure a minimum of one cycle of operational flow for each successive 15-minute period.
              (7) The flow rate sensor must be able to determine the daily zero and upscale calibration drift (CD) (see sections 3.1 and 8.3 of Performance Specification 2 in appendix B to this part for a discussion of CD).
              (i) Conduct the CD tests at two reference signal levels, zero (e.g., 0 to 20 percent of span) and upscale (e.g., 50 to 70 percent of span).
              (ii) The absolute value of the difference between the flow monitor response and the reference signal must be equal to or less than 3 percent of the flow monitor span.
              (8) You must perform an initial relative accuracy test of the flow rate monitoring system according to section 8.2 of Performance Specification 6 of appendix B to this part, with the exceptions noted in paragraphs (h)(8)(i) and (ii) of this section.
              (i) The relative accuracy test is to evaluate the flow rate monitoring system alone rather than a continuous emission rate monitoring system.
              (ii) The relative accuracy of the flow rate monitoring system shall be no greater than 10 percent of the mean value of the reference method data.
              (9) You must verify the accuracy of the flow rate monitoring system at least once per year by repeating the relative accuracy test specified in paragraph (h)(8) of this section.
              (10) You must operate the flow rate monitoring system and record data during all periods of operation of the affected facility including periods of startup, shutdown, and malfunction, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments.
              (i) Development and Submittal (Upon Request) of Monitoring Plans. To demonstrate compliance with any applicable emissions limit through performance stack testing or other emissions monitoring (including PM CPMS), you must develop a site-specific monitoring plan according to the requirements in paragraphs (i)(1) through (4) of this section. This requirement also applies to you if you petition the EPA Administrator for alternative monitoring parameters under § 60.13(3)(i). If you use a bag leak detector system (BLDS), you must also meet the requirements specified in paragraph § 63.1350(m)(10) of this chapter.

              (1) For each continuous monitoring system (CMS) required in this section, you must develop, and submit to the permitting authority for approval upon request, a site-specific monitoring plan that addresses paragraphs (i)(1)(i) through (iii) of this section. You must submit this site-specific monitoring plan, if requested, at least 30 days before the initial performance evaluation of your CMS.
              (i) Installation of the CMS sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control device);
              (ii) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems; and
              (iii) Performance evaluation procedures and acceptance criteria (e.g., calibrations).
              (2) In your site-specific monitoring plan, you must also address paragraphs (i)(2)(i) through (iii) of this section.
              (i) Ongoing operation and maintenance procedures in accordance with the general requirements of § 63.8(c)(1), (c)(3), and (c)(4)(ii);
              (ii) Ongoing data quality assurance procedures in accordance with the general requirements of § 63.8(d); and
              (iii) Ongoing recordkeeping and reporting procedures in accordance with the general requirements of § 63.10(c), (e)(1), and (e)(2)(i).
              (3) You must conduct a performance evaluation of each CMS in accordance with your site-specific monitoring plan.
              (4) You must operate and maintain the CMS in continuous operation according to the site-specific monitoring plan.
              [75 FR 55035, Sept. 9, 2010, as amended at 78 FR 10032, Feb. 12, 2013; 80 FR 44777, July 27, 2015]

              § 60.64
              Test methods and procedures.
              (a) In conducting the performance tests and relative accuracy tests required in § 60.8, you must use reference methods and procedures and the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b).
              (b)(1)You must demonstrate compliance with the PM standards in § 60.62 using EPA method 5 or method 5I.
              (2) Use Method 9 and the procedures in § 60.11 to determine opacity.
              (3) Any sources other than kilns (including associated alkali bypass and clinker cooler) that are subject to the 10 percent opacity limit must follow the appropriate monitoring procedures in § 63.1350(f), (m)(1)through (4), (10) and (11), (o), and (p) of this chapter.

              (c) Calculate and record the rolling 30 kiln operating day average emission rate daily of NOX and SO2 according to the procedures in paragraph (c)(1) of this section.
              (1) Calculate the rolling 30 kiln operating day average emissions according to equation 6:

                ER12FE13.005

                Where:

                E30D = 30 kiln operating day average emission rate of NOX or SO2, lb/ton of clinker.
                Ci = Concentration of NOX or SO2 for hour i, ppm.
                Qi = Volumetric flow rate of effluent gas for hour i, where
                Ci and Qi are on the same basis (either wet or dry), scf/hr.

                P = 30 days of clinker production during the same time period as the NOX or SO2 emissions measured, tons.
                k = Conversion factor, 1.194 × 10−7 for NOX and 1.660 × 10−7 for SO2, lb/scf/ppm.
                n = Number of kiln operating hours over 30 kiln operating days.

              (2) [Reserved]

              (d)(1) Within 60 days after the date of completing each performance test (see § 60.8) as required by this subpart you must submit the results of the performance tests conducted to demonstrate compliance under this subpart to the EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through the EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx). Performance test data must be submitted in the file format generated through use of the EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief /ert/index.html). Only data collected using test methods on the ERT Web site are subject to this requirement for submitting reports electronically to WebFIRE. Owners or operators who claim that some of the information being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk, flash drive or other commonly used electronic storage media to the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to the EPA via CDX as described earlier in this paragraph. At the discretion of the delegated authority, you must also submit these reports, including the CBI, to the delegated authority in the format specified by the delegated authority. For any performance test conducted using test methods that are not listed on the ERT Web site, you must submit the results of the performance test to the Administrator at the appropriate address listed in § 63.13.
              (2) Within 60 days after the date of completing each CEMS performance evaluation test as defined in § 63.2, you must submit relative accuracy test audit (RATA) data to the EPA's CDX by using CEDRI in accordance with paragraph (d)(1) of this section. Only RATA pollutants that can be documented with the ERT (as listed on the ERT Web site) are subject to this requirement. For any performance evaluations with no corresponding RATA pollutants listed on the ERT Web site, you must submit the results of the performance evaluation to the Administrator at the appropriate address listed in § 63.13.
              (3) For PM performance test reports used to set a PM CPMS operating limit, the electronic submission of the test report must also include the make and model of the PM CPMS instrument, serial number of the instrument, analytical principle of the instrument (e.g. beta attenuation), span of the instruments primary analytical range, milliamp value equivalent to the instrument zero output, technique by which this zero value was determined, and the average milliamp signals corresponding to each PM compliance test run.
              (4) All reports required by this subpart not subject to the requirements in paragraphs (d)(1) and (2) of this section must be sent to the Administrator at the appropriate address listed in § 63.13. The Administrator or the delegated authority may request a report in any form suitable for the specific case (e.g., by commonly used electronic media such as Excel spreadsheet, on CD or hard copy). The Administrator retains the right to require submittal of reports subject to paragraph (d)(1) and (2) of this section in paper format.
              [78 FR 10035, Feb. 12, 2013, as amended at 80 FR 44778, July 27, 2015]

              § 60.65
              Recordkeeping and reporting requirements.
              (a) Each owner or operator required to install a CPMS or CEMS under sections § 60.63(c) through (e) shall submit reports of excess emissions. The content of these reports must comply with the requirements in § 60.7(c). Notwithstanding the provisions of § 60.7(c), such reports shall be submitted semiannually.

              (b) Each owner or operator of facilities subject to the provisions of § 60.63(c) through (e) shall submit semiannual reports of the malfunction information required to be recorded by § 60.7(b). These reports shall include the frequency, duration, and cause of any incident resulting in deenergization of any device controlling kiln emissions or in the venting of emissions directly to the atmosphere.
              (c) The requirements of this section remain in force until and unless the Agency, in delegating enforcement authority to a State under section 111(c) of the Clean Air Act, 42 U.S.C. 7411, approves reporting requirements or an alternative means of compliance surveillance adopted by such States. In that event, affected sources within the State will be relieved of the obligation to comply with this section, provided that they comply with the requirements established by the State.
              [78 FR 10035, Feb. 12, 2013]

              § 60.66
              Delegation of authority.
              (a) This subpart can be implemented and enforced by the U.S. EPA or a delegated authority such as a State, local, or Tribal agency. You should contact your U.S. EPA Regional Office to find out if this subpart is delegated to a State, local, or Tribal agency within your State.
              (b) In delegating implementation and enforcement authority to a State, local, or Tribal agency, the approval authorities contained paragraphs (b)(1) through (4) of this section are retained by the Administrator of the U.S EPA and are not transferred to the State, local, or Tribal agency.
              (1) Approval of an alternative to any non-opacity emissions standard.
              (2) Approval of a major change to test methods under § 60.8(b). A “major change to test method” is defined in 40 CFR 63.90.
              (3) Approval of a major change to monitoring under § 60.13(i). A “major change to monitoring” is defined in 40 CFR 63.90.
              (4) Approval of a major change to recordkeeping/reporting under § 60.7(b) through (f). A “major change to recordkeeping/reporting” is defined in 40 CFR 63.90.
              [75 FR 55037, Sept. 9, 2010]

            Subpart G—Standards of Performance for Nitric Acid Plants

              § 60.70
              Applicability and designation of affected facility.
              (a) The provisions of this subpart are applicable to each nitric acid production unit, which is the affected facility.
              (b) Any facility under paragraph (a) of this section that commences construction or modification after August 17, 1971, and on or before October 14, 2011 is subject to the requirements of this subpart. Any facility that commences construction or modification after October 14, 2011 is subject to subpart Ga of this part.
              [42 FR 37936, July 25, 1977, as amended at 77 FR 48445, Aug. 14, 2012]

              § 60.71
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.
              (a) Nitric acid production unit means any facility producing weak nitric acid by either the pressure or atmospheric pressure process.
              (b) Weak nitric acid means acid which is 30 to 70 percent in strength.

              § 60.72
              Standard for nitrogen oxides.
              (a) On and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases which:
              (1) Contain nitrogen oxides, expressed as NO2, in excess of 1.5 kg per metric ton of acid produced (3.0 lb per ton), the production being expressed as 100 percent nitric acid.
              (2) Exhibit 10 percent opacity, or greater.
              [39 FR 20794, June 14, 1974, as amended at 40 FR 46258, Oct. 6, 1975]

              § 60.73
              Emission monitoring.

              (a) The source owner or operator shall install, calibrate, maintain, and operate a continuous monitoring system for measuring nitrogen oxides (NOX). The pollutant gas mixtures under Performance Specification 2 and for calibration checks under § 60.13(d) of this part shall be nitrogen dioxide (NO2). The span value shall be 500 ppm of NO2. Method 7 shall be used for the performance evaluations under § 60.13(c). Acceptable alternative methods to Method 7 are given in § 60.74(c).
              (b) The owner or operator shall establish a conversion factor for the purpose of converting monitoring data into units of the applicable standard (kg/metric ton, lb/ton). The conversion factor shall be established by measuring emissions with the continuous monitoring system concurrent with measuring emissions with the applicable reference method tests. Using only that portion of the continuous monitoring emission data that represents emission measurements concurrent with the reference method test periods, the conversion factor shall be determined by dividing the reference method test data averages by the monitoring data averages to obtain a ratio expressed in units of the applicable standard to units of the monitoring data, i.e., kg/metric ton per ppm (lb/ton per ppm). The conversion factor shall be reestablished during any performance test under § 60.8 or any continuous monitoring system performance evaluation under § 60.13(c).
              (c) The owner or operator shall record the daily production rate and hours of operation.
              (d) [Reserved]
              (e) For the purpose of reports required under § 60.7(c), periods of excess emissions that shall be reported are defined as any 3-hour period during which the average nitrogen oxides emissions (arithmetic average of three contiguous 1-hour periods) as measured by a continuous monitoring system exceed the standard under § 60.72(a).
              [39 FR 20794, June 14, 1974, as amended at 40 FR 46258, Oct. 6, 1975; 50 FR 15894, Apr. 22, 1985; 54 FR 6666, Feb. 14, 1989]

              § 60.74
              Test methods and procedures.
              (a) In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b). Acceptable alternative methods and procedures are given in paragraph (c) of this section.

              (b) The owner or operator shall determine compliance with the NOX standard in § 60.72 as follows:
              (1) The emission rate (E) of NOX shall be computed for each run using the following equation:

              E = (Cs Qsd)/(P K)

                where:

                E = emission rate of NOX as NO2, kg/metric ton (lb/ton) of 100 percent nitric acid.
                Cs = concentration of NOX as NO2, g/dscm (lb/dscf).
                Qsd = volumetric flow rate of effluent gas, dscm/hr (dscf/hr).
                P = acid production rate, metric ton/hr (ton/hr) or 100 percent nitric acid.
                K = conversion factor, 1000 g/kg (1.0 lb/lb).

              (2) Method 7 shall be used to determine the NOX concentration of each grab sample. Method 1 shall be used to select the sampling site, and the sampling point shall be the centroid of the stack or duct or at a point no closer to the walls than 1 m (3.28 ft). Four grab samples shall be taken at approximately 15-minute intervals. The arithmetic mean of the four sample concentrations shall constitute the run value (Cs).

              (3) Method 2 shall be used to determine the volumetric flow rate (Qsd) of the effluent gas. The measurement site shall be the same as for the NOX sample. A velocity traverse shall be made once per run within the hour that the NOX samples are taken.
              (4) The methods of § 60.73(c) shall be used to determine the production rate (P) of 100 percent nitric acid for each run. Material balance over the production system shall be used to confirm the production rate.
              (c) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section:
              (1) For Method 7, Method 7A, 7B, 7C, or 7D may be used. If Method 7C or 7D is used, the sampling time shall be at least 1 hour.
              (d) The owner or operator shall use the procedure in § 60.73(b) to determine the conversion factor for converting the monitoring data to the units of the standard.
              [54 FR 6666, Feb. 14, 1989]

            Subpart Ga—Standards of Performance for Nitric Acid Plants for Which Construction, Reconstruction, or Modification Commenced After October 14, 2011

              Source:
              77 FR 48445, Aug. 14, 2012, unless otherwise noted.

              § 60.70a
              Applicability and designation of affected facility.
              (a) The provisions of this subpart are applicable to each nitric acid production unit, which is the affected facility.
              (b) This subpart applies to any nitric acid production unit that commences construction or modification after October 14, 2011.

              § 60.71a
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.

                Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.

                Monitoring system malfunction means a sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. You are required to implement monitoring system repairs in response to monitoring system malfunctions or out-of-control periods, and to return the monitoring system to operation as expeditiously as practicable.

                Nitric acid production unit means any facility producing weak nitric acid by either the pressure or atmospheric pressure process.

                Operating day means a 24-hour period beginning at 12:00 a.m. during which the nitric acid production unit operated at any time during this period.

                Weak nitric acid means acid which is 30 to 70 percent in strength.

              § 60.72a
              Standards.

                Nitrogen oxides. On and after the date on which the performance test required to be conducted by § 60.73a(e) is completed, you may not discharge into the atmosphere from any affected facility any gases which contain NOX, expressed as NO2, in excess of 0.50 pounds (lb) per ton of nitric acid produced, as a 30-day emission rate calculated based on 30 consecutive operating days, the production being expressed as 100 percent nitric acid. The emission standard applies at all times.

              § 60.73a
              Emissions testing and monitoring.
              (a) General emissions monitoring requirements. You must install and operate a NOX concentration (ppmv) continuous emissions monitoring system (CEMS). You must also install and operate a stack gas flow rate monitoring system. With measurements of stack gas NOX concentration and stack gas flow rate, you will determine hourly NOX emissions rate (e.g., lb/hr) and with measured data of the hourly nitric acid production (tons), calculate emissions in units of the applicable emissions limit (lb/ton of 100 percent acid produced). You must operate the monitoring system and report emissions during all operating periods including unit startup and shutdown, and malfunction.
              (b) Nitrogen oxides concentration continuous emissions monitoring system. (1) You must install, calibrate, maintain, and operate a CEMS for measuring and recording the concentration of NOX emissions in accordance with the provisions of § 60.13 and Performance Specification 2 of appendix B and Procedure 1 of appendix F of this part. You must use cylinder gas audits to fulfill the quarterly auditing requirement at section 5.1 of Procedure 1 of appendix F of this part for the NOX concentration CEMS.
              (2) For the NOX concentration CEMS, use a span value, as defined in Performance Specification 2, section 3.11, of appendix B of this part, of 500 ppmv (as NO2). If you emit NOX at concentrations higher than 600 ppmv (e.g., during startup or shutdown periods), you must apply a second CEMS or dual range CEMS and a second span value equal to 125 percent of the maximum estimated NOX emission concentration to apply to the second CEMS or to the higher of the dual analyzer ranges during such periods.
              (3) For conducting the relative accuracy test audits, per Performance Specification 2, section 8.4, of appendix B of this part and Procedure 1, section 5.1.1, of appendix F of this part, use either EPA Reference Method 7, 7A, 7C, 7D, or 7E of appendix A-4 of this part; EPA Reference Method 320 of appendix A of part 63 of this chapter; or ASTM D6348-03 (incorporated by reference, see § 60.17). To verify the operation of the second CEMS or the higher range of a dual analyzer CEMS described in paragraph (b)(2) of this section, you need not conduct a relative accuracy test audit but only the calibration drift test initially (found in Performance Specification 2, section 8.3.1, of appendix B of this part) and the cylinder gas audit thereafter (found in Procedure 1, section 5.1.2, of appendix F of this part).

              (4) If you use EPA Reference Method 7E of appendix A-4 of this part, you must mitigate loss of NO2 in water according to the requirements in paragraphs (b)(4)(i), (ii), or (iii) of this section and verify performance by conducting the system bias checks required in EPA Reference Method 7E, section 8, of appendix A-4 of this part according to (b)(4)(iv) of this section, or follow the dynamic spike procedure according to paragraph (b)(4)(v) of this section.
              (i) For a wet-basis measurement system, you must measure and report temperature of sample line and components (up to analyzer inlet) to demonstrate that the temperatures remain above the sample gas dew point at all times during the sampling.
              (ii) You may use a dilution probe to reduce the dew point of the sample gas.
              (iii) You may use a refrigerated-type condenser or similar device (e.g., permeation dryer) to remove condensate continuously from sample gas while maintaining minimal contact between condensate and sample gas.

              (iv) If your analyzer measures nitric oxide (NO) and nitrogen dioxide (NO2) separately, you must use both NO and NO2 calibration gases. Otherwise, you must substitute NO2 calibration gas for NO calibration gas in the performance of system bias checks.

              (v) You must conduct dynamic spiking according to EPA Reference Method 7E, section 16.1, of appendix A-4 of this part using NO2 as the spike gas.
              (5) Instead of a NOX concentration CEMS meeting Performance Specification 2, you may apply an FTIR CEMS meeting the requirements of Performance Specification 15 of appendix B of this part to measure NOX concentrations. Should you use an FTIR CEMS, you must replace the Relative Accuracy Test Audit requirements of Procedure 1 of appendix F of this part with the validation requirements and criteria of Performance Specification 15, sections 11.1.1 and 12.0, of appendix B of this part.
              (c) Determining NO
                X
                mass emissions rate values. You must use the NOX concentration CEMS, acid production, gas flow rate monitor and other monitoring data to calculate emissions data in units of the applicable limit (lb NOX/ton of acid produced expressed as 100 percent nitric acid).

              (1) You must install, calibrate, maintain, and operate a CEMS for measuring and recording the stack gas flow rates to use in combination with data from the CEMS for measuring emissions concentrations of NOX to produce data in units of mass rate (e.g., lb/hr) of NOX on an hourly basis. You will operate and certify the continuous emissions rate monitoring system (CERMS) in accordance with the provisions of § 60.13 and Performance Specification 6 of appendix B of this part. You must comply with the following provisions in (c)(1)(i) through (iii) of this section.
              (i) You must use a stack gas flow rate sensor with a full scale output of at least 125 percent of the maximum expected exhaust volumetric flow rate (see Performance Specification 6, section 8, of appendix B of this part).

              (ii) For conducting the relative accuracy test audits, per Performance Specification 6, section 8.2 of appendix B of this part and Procedure 1, section 5.1.1, of appendix F of this part, you must use either EPA Reference Method 2, 2F, or 2G of appendix A-4 of this part. You may also apply Method 2H in conjunction with other velocity measurements.

              (iii) You must verify that the CERMS complies with the quality assurance requirements in Procedure 1 of appendix F of this part. You must conduct relative accuracy testing to provide for calculating the relative accuracy for RATA and RAA determinations in units of lb/hour.
              (2) You must determine the nitric acid production parameters (production rate and concentration) by installing, calibrating, maintaining, and operating a permanent monitoring system (e.g., weigh scale, volume flow meter, mass flow meter, tank volume) to measure and record the weight rates of nitric acid produced in tons per hour. If your nitric acid production rate measurements are for periods longer than hourly (e.g., daily values), you will determine average hourly production values, tons acid/hr, by dividing the total acid production by the number of hours of process operation for the subject measurement period. You must comply with the following provisions in (c)(2)(i) through (iv) of this section.
              (i) You must verify that each component of the monitoring system has an accuracy and precision of no more than ±5 percent of full scale.
              (ii) You must analyze product concentration via titration or by determining the temperature and specific gravity of the nitric acid. You may also use ASTM E1584-11 (incorporated by reference, see § 60.17), for determining the concentration of nitric acid in percent. You must determine product concentration daily.
              (iii) You must use the acid concentration to express the nitric acid production as 100 percent nitric acid.
              (iv) You must record the nitric acid production, expressed as 100 percent nitric acid, and the hours of operation.
              (3) You must calculate hourly NOX emissions rates in units of the standard (lb/ton acid) for each hour of process operation. For process operating periods for which there is little or no acid production (e.g., startup or shutdown), you must use the average hourly acid production rate determined from the data collected over the previous 30 days of normal acid production periods (see § 60.75a).
              (d) Continuous monitoring system. For each continuous monitoring system, including NOX concentration measurement, volumetric flow rate measurement, and nitric acid production measurement equipment, you must meet the requirements in paragraphs (d)(1) through (3) of this section.
              (1) You must operate the monitoring system and collect data at all required intervals at all times the affected facility is operating except for periods of monitoring system malfunctions or out-of-control periods as defined in appendix F, sections 4 and 5, of this part, repairs associated with monitoring system malfunctions or out-of-control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments.
              (2) You may not use data recorded during monitoring system malfunctions or out-of-control periods, repairs associated with monitoring system malfunctions or out-of-control periods, or required monitoring system quality assurance or control activities in calculations used to report emissions or operating levels. You must use all the data collected during all other periods in calculating emissions and the status of compliance with the applicable emissions limit in accordance with § 60.72a(a).
              (e) Initial performance testing. You must conduct an initial performance test to demonstrate compliance with the NOX emissions limit under § 60.72a(a) beginning in the calendar month following initial certification of the NOX and flow rate monitoring CEMS. The initial performance test consists of collection of hourly NOX average concentration, mass flow rate recorded with the certified NOX concentration and flow rate CEMS and the corresponding acid generation (tons) data for all of the hours of operation for the first 30 days beginning on the first day of the first month following completion of the CEMS installation and certification as described above. You must assure that the CERMS meets all of the data quality assurance requirements as per § 60.13 and appendix F, Procedure 1, of this part and you must use the data from the CERMS for this compliance determination.

              § 60.74a
              Affirmative defense for violations of emission standards during malfunction.
              In response to an action to enforce the standards set forth in § 60.72a, you may assert an affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.
              (a) To establish the affirmative defense in any action to enforce such a standard, you must timely meet the reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that:
              (1) The violation:
              (i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner; and
              (ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and
              (iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and
              (iv) Was not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and
              (2) Repairs were made as expeditiously as possible when a violation occurred. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and
              (3) The frequency, amount, and duration of the violation (including any bypass) were minimized to the maximum extent practicable; and
              (4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and
              (5) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment, and human health; and
              (6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and
              (7) All of the actions in response to the violation were documented by properly signed, contemporaneous operating logs; and
              (8) At all times, the affected facility was operated in a manner consistent with good practices for minimizing emissions; and
              (9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of any emissions that were the result of the malfunction.
              (b) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report to the Administrator with all necessary supporting documentation, that it has met the requirements set forth in paragraph (a) of this section. This affirmative defense report shall be included in the first periodic compliance, deviation report or excess emission report otherwise required after the initial occurrence of the violation of the relevant standard (which may be the end of any applicable averaging period). If such compliance, deviation report or excess emission report is due less than 45 days after the initial occurrence of the violation, the affirmative defense report may be included in the second compliance, deviation report or excess emission report due after the initial occurrence of the violation of the relevant standard.

              § 60.75a
              Calculations.

              (a) You must calculate the 30 operating day rolling arithmetic average emissions rate in units of the applicable emissions standard (lb NOX/ton 100 percent acid produced) at the end of each operating day using all of the quality assured hourly average CEMS data for the previous 30 operating days.
              (b) You must calculate the 30 operating day average emissions rate according to Equation 1:

                ER06MY14.000

                Where:

                E30 = 30 operating day average emissions rate of NOX, lb NOX/ton of 100 percent HNO3;
                Ci = concentration of NOX for hour i, ppmv;
                Qi = volumetric flow rate of effluent gas for hour i, where Ci and Qi are on the same basis (either wet or dry), scf/hr;
                Pi = total acid produced during production hour i, tons 100 percent HNO3;
                k = conversion factor, 1.194 × 10−7 for NOX; and
                n = number of operating hours in the 30 operating day period, i.e., n is between 30 and 720.

              [77 FR 48445, Aug. 14, 2012; 79 FR 25681, May 6, 2014]

              § 60.76a
              Recordkeeping.
              (a) For the NOX emissions rate, you must keep records for and results of the performance evaluations of the continuous emissions monitoring systems.
              (b) You must maintain records of the following information for each 30 operating day period:
              (1) Hours of operation.
              (2) Production rate of nitric acid, expressed as 100 percent nitric acid.
              (3) 30 operating day average NOX emissions rate values.
              (c) You must maintain records of the following time periods:
              (1) Times when you were not in compliance with the emissions standards.

              (2) Times when the pollutant concentration exceeded full span of the NOX monitoring equipment.
              (3) Times when the volumetric flow rate exceeded the high value of the volumetric flow rate monitoring equipment.
              (d) You must maintain records of the reasons for any periods of noncompliance and description of corrective actions taken.
              (e) You must maintain records of any modifications to CEMS which could affect the ability of the CEMS to comply with applicable performance specifications.
              (f) For each malfunction, you must maintain records of the following information:
              (1) Records of the occurrence and duration of each malfunction of operation (i.e., process equipment) or the air pollution control and monitoring equipment.
              (2) Records of actions taken during periods of malfunction to minimize emissions in accordance with § 60.11(d), including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation.

              § 60.77a
              Reporting.
              (a) The performance test data from the initial and subsequent performance tests and from the performance evaluations of the continuous monitors must be submitted to the Administrator at the appropriate address as shown in 40 CFR 60.4.
              (b) The following information must be reported to the Administrator for each 30 operating day period where you were not in compliance with the emissions standard:
              (1) Time period;
              (2) NOX emission rates (lb/ton of acid produced);
              (3) Reasons for noncompliance with the emissions standard; and
              (4) Description of corrective actions taken.
              (c) You must also report the following whenever they occur:

              (1) Times when the pollutant concentration exceeded full span of the NOX pollutant monitoring equipment.

              (2) Times when the volumetric flow rate exceeded the high value of the volumetric flow rate monitoring equipment.

              (d) You must report any modifications to CERMS which could affect the ability of the CERMS to comply with applicable performance specifications.

              (e) Within 60 days of completion of the relative accuracy test audit (RATA) required by this subpart, you must submit the data from that audit to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/SSL/cdx/EPA__Home.asp). You must submit performance test data in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (http://www.epa.gov/ttn/chief /ert/index.html). Only data collected using test methods listed on the ERT Web site are subject to this requirement for submitting reports electronically to WebFIRE. Owners or operators who claim that some of the information being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) by registered letter to EPA and the same ERT file with the CBI omitted to EPA via CDX as described earlier in this paragraph. Mark the compact disk or other commonly used electronic storage media clearly as CBI and mail to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. At the discretion of the delegated authority, you must also submit these reports to the delegated authority in the format specified by the delegated authority. You must submit the other information as required in the performance evaluation as described in § 60.2 and as required in this chapter.
              (f) If a malfunction occurred during the reporting period, you must submit a report that contains the following:
              (1) The number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded.
              (2) A description of actions taken by an owner or operator during a malfunction of an affected facility to minimize emissions in accordance with § 60.11(d), including actions taken to correct a malfunction.

            Subpart H—Standards of Performance for Sulfuric Acid Plants

              § 60.80
              Applicability and designation of affected facility.
              (a) The provisions of this subpart are applicable to each sulfuric acid production unit, which is the affected facility.
              (b) Any facility under paragraph (a) of this section that commences construction or modification after August 17, 1971, is subject to the requirements of this subpart.
              [42 FR 37936, July 25, 1977]

              § 60.81
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.
              (a) Sulfuric acid production unit means any facility producing sulfuric acid by the contact process by burning elemental sulfur, alkylation acid, hydrogen sulfide, organic sulfides and mercaptans, or acid sludge, but does not include facilities where conversion to sulfuric acid is utilized primarily as a means of preventing emissions to the atmosphere of sulfur dioxide or other sulfur compounds.
              (b) Acid mist means sulfuric acid mist, as measured by Method 8 of appendix A to this part or an equivalent or alternative method.
              [36 FR 24877, Dec. 23, 1971, as amended at 39 FR 20794, June 14, 1974]

              § 60.82
              Standard for sulfur dioxide.

              (a) On and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases which contain sulfur dioxide in excess of 2 kg per metric ton of acid produced (4 lb per ton), the production being expressed as 100 percent H2SO4.
              [39 FR 20794, June 14, 1974]

              § 60.83
              Standard for acid mist.
              (a) On and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases which:
              (1) Contain acid mist, expressed as H2SO4, in excess of 0.075 kg per metric ton of acid produced (0.15 lb per ton), the production being expressed as 100 percent H2SO4.
              (2) Exhibit 10 percent opacity, or greater.
              [39 FR 20794, June 14, 1974, as amended at 40 FR 46258, Oct. 6, 1975]

              § 60.84
              Emission monitoring.

              (a) A continuous monitoring system for the measurement of sulfur dioxide shall be installed, calibrated, maintained, and operated by the owner or operator. The pollutant gas used to prepare calibration gas mixtures under Performance Specification 2 and for calibration checks under § 60.13(d), shall be sulfur dioxide (SO2). Method 8 shall be used for conducting monitoring system performance evaluations under § 60.13(c) except that only the sulfur dioxide portion of the Method 8 results shall be used. The span value shall be set at 1000 ppm of sulfur dioxide.

              (b) The owner or operator shall establish a conversion factor for the purpose of converting monitoring data into units of the applicable standard (kg/metric ton, lb/ton). The conversion factor shall be determined, as a minimum, three times daily by measuring the concentration of sulfur dioxide entering the converter using suitable methods (e.g., the Reich test, National Air Pollution Control Administration Publication No. 999-AP-13) and calculating the appropriate conversion factor for each eight-hour period as follows:

              CF = k[(1.000−0.015r)/(r−s)]

                where:

                CF = conversion factor (kg/metric ton per ppm, lb/ton per ppm).
                k = constant derived from material balance. For determining CF in metric units, k = 0.0653. For determining CF in English units, k = 0.1306.
                r = percentage of sulfur dioxide by volume entering the gas converter. Appropriate corrections must be made for air injection plants subject to the Administrator's approval.
                s = percentage of sulfur dioxide by volume in the emissions to the atmosphere determined by the continuous monitoring system required under paragraph (a) of this section.

              (c) The owner or operator shall record all conversion factors and values under paragraph (b) of this section from which they were computed (i.e., CF, r, and s).

              (d) Alternatively, a source that processes elemental sulfur or an ore that contains elemental sulfur and uses air to supply oxygen may use the following continuous emission monitoring approach and calculation procedures in determining SO2 emission rates in terms of the standard. This procedure is not required, but is an alternative that would alleviate problems encountered in the measurement of gas velocities or production rate. Continuous emission monitoring systems for measuring SO2, O2, and CO2 (if required) shall be installed, calibrated, maintained, and operated by the owner or operator and subjected to the certification procedures in Performance Specifications 2 and 3. The calibration procedure and span value for the SO2 monitor shall be as specified in paragraph (b) of this section. The span value for CO2 (if required) shall be 10 percent and for O2 shall be 20.9 percent (air). A conversion factor based on process rate data is not necessary. Calculate the SO2 emission rate as follows:

              Es = (Cs S)/[0.265 − (0.0126 %O2) − (A %CO2)]

                where:

                Es = emission rate of SO2, kg/metric ton (lb/ton) of 100 percent of H2SO4 produced.
                Cs = concentration of SO2, kg/dscm (lb/dscf).

                S = acid production rate factor, 368 dscm/metric ton (11,800 dscf/ton) of 100 percent H2SO4 produced.
                %O2 = oxygen concentration, percent dry basis.
                A = auxiliary fuel factor,
                 = 0.00 for no fuel.
                 = 0.0226 for methane.
                 = 0.0217 for natural gas.

                 = 0.0196 for propane.
                 = 0.0172 for No 2 oil.
                 = 0.0161 for No 6 oil.
                 = 0.0148 for coal.
                 = 0.0126 for coke.
                %CO2 = carbon dioxide concentration, percent dry basis.

                  Note:

                  It is necessary in some cases to convert measured concentration units to other units for these calculations:

                  Use the following table for such conversions:

                    From—
                    To—
                    Multiply by—

                    g/scm
                    kg/scm
                    10−3

                    mg/scm
                    kg/scm
                    10−6

                    ppm (SO2)
                    kg/scm
                    2.660 × 10−6

                    ppm (SO2)
                    lb/scf
                    1.660 × 10−7

              (e) For the purpose of reports under § 60.7(c), periods of excess emissions shall be all three-hour periods (or the arithmetic average of three consecutive one-hour periods) during which the integrated average sulfur dioxide emissions exceed the applicable standards under § 60.82.
              [39 FR 20794, June 14, 1974, as amended at 40 FR 46258, Oct. 6, 1975; 48 FR 23611, May 25, 1983; 48 FR 4700, Sept. 29, 1983; 48 FR 48669, Oct. 20, 1983; 54 FR 6666, Feb. 14, 1989; 65 FR 61753, Oct. 17, 2000; 79 FR 11250, Feb. 27, 2014]

              § 60.85
              Test methods and procedures.
              (a) In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b). Acceptable alternative methods and procedures are given in paragraph (c) of this section.

              (b) The owner or operator shall determine compliance with the SO2 acid mist, and visible emission standards in §§ 60.82 and 60.83 as follows:
              (1) The emission rate (E) of acid mist or SO2 shall be computed for each run using the following equation:

              E = (CQsd) / (PK)

                where:

                E = emission rate of acid mist or SO2 kg/metric ton (lb/ton) of 100 percent H2SO4 produced.
                C = concentration of acid mist or SO2, g/dscm (lb/dscf).
                Qsd = volumetric flow rate of the effluent gas, dscm/hr (dscf/hr).
                P = production rate of 100 percent H2SO4, metric ton/hr (ton/hr).
                K = conversion factor, 1000 g/kg (1.0 lb/lb).

              (2) Method 8 shall be used to determine the acid mist and SO2 concentrations (C's) and the volumetric flow rate (Qsd) of the effluent gas. The moisture content may be considered to be zero. The sampling time and sample volume for each run shall be at least 60 minutes and 1.15 dscm (40.6 dscf).

              (3) Suitable methods shall be used to determine the production rate (P) of 100 percent H2SO4 for each run. Material balance over the production system shall be used to confirm the production rate.
              (4) Method 9 and the procedures in § 60.11 shall be used to determine opacity.
              (c) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section:
              (1) If a source processes elemental sulfur or an ore that contains elemental sulfur and uses air to supply oxygen, the following procedure may be used instead of determining the volumetric flow rate and production rate:

              (i) The integrated technique of Method 3 is used to determine the O2 concentration and, if required, CO2 concentration.
              (ii) The SO2 or acid mist emission rate is calculated as described in § 60.84(d), substituting the acid mist concentration for Cs as appropriate.
              [54 FR 6666, Feb. 14, 1989]

            Subpart I—Standards of Performance for Hot Mix Asphalt Facilities

              § 60.90
              Applicability and designation of affected facility.

              (a) The affected facility to which the provisions of this subpart apply is each hot mix asphalt facility. For the purpose of this subpart, a hot mix asphalt facility is comprised only of any combination of the following: dryers; systems for screening, handling, storing, and weighing hot aggregate; systems for loading, transferring, and storing mineral filler, systems for mixing hot mix asphalt; and the loading, transfer, and storage systems associated with emission control systems.
              (b) Any facility under paragraph (a) of this section that commences construction or modification after June 11, 1973, is subject to the requirements of this subpart.
              [42 FR 37936, July 25, 1977, as amended at 51 FR 12325, Apr. 10, 1986]

              § 60.91
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.
              (a) Hot mix asphalt facility means any facility, as described in § 60.90, used to manufacture hot mix asphalt by heating and drying aggregate and mixing with asphalt cements.
              [51 FR 12325, Apr. 10, 1986]

              § 60.92
              Standard for particulate matter.
              (a) On and after the date on which the performance test required to be conducted by § 60.8 is completed, no owner or operator subject to the provisions of this subpart shall discharge or cause the discharge into the atmosphere from any affected facility any gases which:
              (1) Contain particulate matter in excess of 90 mg/dscm (0.04 gr/dscf).
              (2) Exhibit 20 percent opacity, or greater.
              [39 FR 9314, Mar. 8, 1974, as amended at 40 FR 46259, Oct. 6, 1975]

              § 60.93
              Test methods and procedures.
              (a) In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b).
              (b) The owner or operator shall determine compliance with the particulate matter standards in § 60.92 as follows:
              (1) Method 5 shall be used to determine the particulate matter concentration. The sampling time and sample volume for each run shall be at least 60 minutes and 0.90 dscm (31.8 dscf).
              (2) Method 9 and the procedures in § 60.11 shall be used to determine opacity.
              [54 FR 6667, Feb. 14, 1989]

            Subpart J—Standards of Performance for Petroleum Refineries

              § 60.100
              Applicability, designation of affected facility, and reconstruction.
              (a) The provisions of this subpart are applicable to the following affected facilities in petroleum refineries: fluid catalytic cracking unit catalyst regenerators, fuel gas combustion devices, and all Claus sulfur recovery plants except Claus plants with a design capacity for sulfur feed of 20 long tons per day (LTD) or less. The Claus sulfur recovery plant need not be physically located within the boundaries of a petroleum refinery to be an affected facility, provided it processes gases produced within a petroleum refinery.
              (b) Any fluid catalytic cracking unit catalyst regenerator or fuel gas combustion device under paragraph (a) of this section other than a flare which commences construction, reconstruction or modification after June 11, 1973, and on or before May 14, 2007, or any fuel gas combustion device under paragraph (a) of this section that is also a flare which commences construction, reconstruction or modification after June 11, 1973, and on or before June 24, 2008, or any Claus sulfur recovery plant under paragraph (a) of this section which commences construction, reconstruction or modification after October 4, 1976, and on or before May 14, 2007, is subject to the requirements of this subpart except as provided under paragraphs (c) through (e) of this section.
              (c) Any fluid catalytic cracking unit catalyst regenerator under paragraph (b) of this section which commences construction, reconstruction, or modification on or before January 17, 1984, is exempted from § 60.104(b).

              (d) Any fluid catalytic cracking unit in which a contact material reacts with petroleum derivatives to improve feedstock quality and in which the contact material is regenerated by burning off coke and/or other deposits and that commences construction, reconstruction, or modification on or before January 17, 1984, is exempt from this subpart.
              (e) Owners or operators may choose to comply with the applicable provisions of subpart Ja of this part to satisfy the requirements of this subpart for an affected facility.
              (f) For purposes of this subpart, under § 60.15, the “fixed capital cost of the new components” includes the fixed capital cost of all depreciable components which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following January 17, 1984. For purposes of this paragraph, “commenced” means that an owner or operator has undertaken a continuous program of component replacement or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of component replacement.
              [43 FR 10868, Mar. 15, 1978, as amended at 44 FR 61543, Oct. 25, 1979; 54 FR 34026, Aug. 17, 1989; 73 FR 35865, June 24, 2008; 77 FR 56463, Sep. 12, 2012]

              § 60.101
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A.
              (a) Petroleum refinery means any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, or other products through distillation of petroleum or through redistillation, cracking or reforming of unfinished petroleum derivatives.
              (b) Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal.
              (c) Process gas means any gas generated by a petroleum refinery process unit, except fuel gas and process upset gas as defined in this section.
              (d) Fuel gas means any gas which is generated at a petroleum refinery and which is combusted. Fuel gas includes natural gas when the natural gas is combined and combusted in any proportion with a gas generated at a refinery. Fuel gas does not include gases generated by catalytic cracking unit catalyst regenerators and fluid coking burners. Fuel gas does not include vapors that are collected and combusted in a thermal oxidizer or flare installed to control emissions from wastewater treatment units or marine tank vessel loading operations.
              (e) Process upset gas means any gas generated by a petroleum refinery process unit as a result of start-up, shut-down, upset or malfunction.
              (f) Refinery process unit means any segment of the petroleum refinery in which a specific processing operation is conducted.
              (g) Fuel gas combustion device means any equipment, such as process heaters, boilers and flares used to combust fuel gas, except facilities in which gases are combusted to produce sulfur or sulfuric acid.
              (h) Coke burn-off means the coke removed from the surface of the fluid catalytic cracking unit catalyst by combustion in the catalyst regenerator. The rate of coke burn-off is calculated by the formula specified in § 60.106.
              (i) Claus sulfur recovery plant means a process unit which recovers sulfur from hydrogen sulfide by a vapor-phase catalytic reaction of sulfur dioxide and hydrogen sulfide.
              (j) Oxidation control system means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to sulfur dioxide.
              (k) Reduction control system means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to hydrogen sulfide.
              (l) Reduced sulfur compounds means hydrogen sulfide (H2S), carbonyl sulfide (COS) and carbon disulfide (CS2).
              (m) Fluid catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged; hydrocarbon molecules in the presence of a catalyst suspended in a fluidized bed are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing; and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and regenerator equipment for controlling air pollutant emissions and for heat recovery.
              (n) Fluid catalytic cracking unit catalyst regenerator means one or more regenerators (multiple regenerators) which comprise that portion of the fluid catalytic cracking unit in which coke burn-off and catalyst or contact material regeneration occurs, and includes the regenerator combustion air blower(s).
              (o) Fresh feed means any petroleum derivative feedstock stream charged directly into the riser or reactor of a fluid catalytic cracking unit except for petroleum derivatives recycled within the fluid catalytic cracking unit, fractionator, or gas recovery unit.
              (p) Contact material means any substance formulated to remove metals, sulfur, nitrogen, or any other contaminant from petroleum derivatives.
              (q) Valid day means a 24-hour period in which at least 18 valid hours of data are obtained. A “valid hour” is one in which at least 2 valid data points are obtained.
              [39 FR 9315, Mar. 8, 1974, as amended at 43 FR 10868, Mar. 15, 1978; 44 FR 13481, Mar. 12, 1979; 45 FR 79453, Dec. 1, 1980; 54 FR 34027, Aug. 17, 1989; 73 FR 35865, June 24, 2008; 77 FR 56463, Sep. 12, 2012]

              § 60.102
              Standard for particulate matter.
              Each owner or operator of any fluid catalytic cracking unit catalyst regenerator that is subject to the requirements of this subpart shall comply with the emission limitations set forth in this section on and after the date on which the initial performance test, required by § 60.8, is completed, but not later than 60 days after achieving the maximum production rate at which the fluid catalytic cracking unit catalyst regenerator will be operated, or 180 days after initial startup, whichever comes first.
              (a) No owner or operator subject to the provisions of this subpart shall discharge or cause the discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator:
              (1) Particulate matter in excess of 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in the catalyst regenerator.
              (2) Gases exhibiting greater than 30 percent opacity, except for one six-minute average opacity reading in any one hour period.
              (b) Where the gases discharged by the fluid catalytic cracking unit catalyst regenerator pass through an incinerator or waste heat boiler in which auxiliary or supplemental liquid or solid fossil fuel is burned, particulate matter in excess of that permitted by paragraph (a)(1) of this section may be emitted to the atmosphere, except that the incremental rate of particulate matter emissions shall not exceed 43 grams per Gigajoule (g/GJ) (0.10 lb/million British thermal units (Btu)) of heat input attributable to such liquid or solid fossil fuel.
              [39 FR 9315, Mar. 8, 1974, as amended at 42 FR 32427, June 24, 1977; 42 FR 39389, Aug. 4, 1977; 43 FR 10868, Feb. 15, 1978; 54 FR 34027, Aug. 17, 1989; 65 FR 61753, Oct. 17, 2000; 73 FR 35866, June 24, 2008]

              § 60.103
              Standard for carbon monoxide.
              Each owner or operator of any fluid catalytic cracking unit catalyst regenerator that is subject to the requirements of this subpart shall comply with the emission limitations set forth in this section on and after the date on which the initial performance test, required by § 60.8, is completed, but not later than 60 days after achieving the maximum production rate at which the fluid catalytic cracking unit catalyst regenerator will be operated, or 180 days after initial startup, whichever comes first.
              (a) No owner or operator subject to the provisions of this subpart shall discharge or cause the discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator any gases that contain carbon monoxide (CO) in excess of 500 ppm by volume (dry basis).
              [54 FR 34027, Aug. 17, 1989, as amended at 55 FR 40175, Oct. 2, 1990]

              § 60.104
              Standards for sulfur oxides.

              Each owner or operator that is subject to the requirements of this subpart shall comply with the emission limitations set forth in this section on and after the date on which the initial performance test, required by § 60.8, is completed, but not later than 60 days after achieving the maximum production rate at which the affected facility will be operated, or 180 days after initial startup, whichever comes first.
              (a) No owner or operator subject to the provisions of this subpart shall:

              (1) Burn in any fuel gas combustion device any fuel gas that contains hydrogen sulfide (H2S) in excess of 230 mg/dscm (0.10 gr/dscf). The combustion in a flare of process upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other emergency malfunctions is exempt from this paragraph.
              (2) Discharge or cause the discharge of any gases into the atmosphere from any Claus sulfur recovery plant containing in excess of:

              (i) For an oxidation control system or a reduction control system followed by incineration, 250 ppm by volume (dry basis) of sulfur dioxide (SO2) at zero percent excess air.

              (ii) For a reduction control system not followed by incineration, 300 ppm by volume of reduced sulfur compounds and 10 ppm by volume of hydrogen sulfide (H2S), each calculated as ppm SO2 by volume (dry basis) at zero percent excess air.
              (b) Each owner or operator that is subject to the provisions of this subpart shall comply with one of the following conditions for each affected fluid catalytic cracking unit catalyst regenerator:
              (1) With an add-on control device, reduce SO2 emissions to the atmosphere by 90 percent or maintain SO2 emissions to the atmosphere less than or equal to 50 ppm by volume (ppmv), whichever is less stringent; or

              (2) Without the use of an add-on control device to reduce SO2 emission, maintain sulfur oxides emissions calculated as SO2 to the atmosphere less than or equal to 9.8 kg/Mg (20 lb/ton) coke burn-off; or
              (3) Process in the fluid catalytic cracking unit fresh feed that has a total sulfur content no greater than 0.30 percent by weight.
              (c) Compliance with paragraph (b)(1), (b)(2), or (b)(3) of this section is determined daily on a 7-day rolling average basis using the appropriate procedures outlined in § 60.106.
              (d) A minimum of 22 valid days of data shall be obtained every 30 rolling successive calendar days when complying with paragraph (b)(1) of this section.
              [43 FR 10869, Mar. 15, 1978, as amended at 54 FR 34027, Aug. 17, 1989; 55 FR 40175, Oct. 2, 1990; 65 FR 61754, Oct. 17, 2000; 73 FR 35866, June 24, 2008]

              § 60.105
              Monitoring of emissions and operations.
              (a) Continuous monitoring systems shall be installed, calibrated, maintained, and operated by the owner or operator subject to the provisions of this subpart as follows:
              (1) For fluid catalytic cracking unit catalyst regenerators subject to § 60.102(a)(2), an instrument for continuously monitoring and recording the opacity of emissions into the atmosphere. The instrument shall be spanned at 60, 70, or 80 percent opacity.
              (2) For fluid catalytic cracking unit catalyst regenerators subject to § 60.103(a), an instrument for continuously monitoring and recording the concentration by volume (dry basis) of CO emissions into the atmosphere, except as provided in paragraph (a)(2) (ii) of this section.
              (i) The span value for this instrument is 1,000 ppm CO.

              (ii) A CO continuous monitoring system need not be installed if the owner or operator demonstrates that the average CO emissions are less than 50 ppm (dry basis) and also files a written request for exemption to the Administrator and receives such an exemption. The demonstration shall consist of continuously monitoring CO emissions for 30 days using an instrument that shall meet the requirements of Performance Specification 4 of appendix B of this part. The span value shall be 100 ppm CO instead of 1,000 ppm, and the relative accuracy limit shall be 10 percent of the average CO emissions or 5 ppm CO, whichever is greater. For instruments that are identical to Method 10 and employ the sample conditioning system of Method 10A, the alternative relative accuracy test procedure in § 10.1 of Performance Specification 2 may be used in place of the relative accuracy test.

              (3) For fuel gas combustion devices subject to § 60.104(a)(1), either an instrument for continuously monitoring and recording the concentration by volume (dry basis, zero percent excess air) of SO2 emissions into the atmosphere or monitoring as provided in paragraph (a)(4) of this section). The monitor shall include an oxygen monitor for correcting the data for excess.
              (i) The span values for this monitor are 50 ppm SO2 and 25 percent oxygen (O2).
              (ii) The SO2 monitoring level equivalent to the H2S standard under § 60.104(a)(1) shall be 20 ppm (dry basis, zero percent excess air).
              (iii) The performance evaluations for this SO2 monitor under § 60.13(c) shall use Performance Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy evaluations. Method 6 samples shall be taken at a flow rate of approximately 2 liters/min for at least 30 minutes. The relative accuracy limit shall be 20 percent or 4 ppm, whichever is greater, and the calibration drift limit shall be 5 percent of the established span value.

              (iv) Fuel gas combustion devices having a common source of fuel gas may be monitored at only one location (i.e., after one of the combustion devices), if monitoring at this location accurately represents the SO2 emissions into the atmosphere from each of the combustion devices.
              (4) Instead of the SO2 monitor in paragraph (a)(3) of this section for fuel gas combustion devices subject to § 60.104(a)(1), an instrument for continuously monitoring and recording the concentration (dry basis) of H2S in fuel gases before being burned in any fuel gas combustion device.

              (i) The span value for this instrument is 425 mg/dscm H2S.

              (ii) Fuel gas combustion devices having a common source of fuel gas may be monitored at only one location, if monitoring at this location accurately represents the concentration of H2S in the fuel gas being burned.
              (iii) The performance evaluations for this H2S monitor under § 60.13(c) shall use Performance Specification 7. Method 11, 15, 15A, or 16 shall be used for conducting the relative accuracy evaluations.
              (iv) The owner or operator of a fuel gas combustion device is not required to comply with paragraph (a)(3) or (4) of this section for fuel gas streams that are exempt under § 60.104(a)(1) and fuel gas streams combusted in a fuel gas combustion device that are inherently low in sulfur content. Fuel gas streams meeting one of the requirements in paragraphs (a)(4)(iv)(A) through (D) of this section will be considered inherently low in sulfur content. If the composition of a fuel gas stream changes such that it is no longer exempt under § 60.104(a)(1) or it no longer meets one of the requirements in paragraphs (a)(4)(iv)(A) through (D) of this section, the owner or operator must begin continuous monitoring under paragraph (a)(3) or (4) of this section within 15 days of the change.
              (A) Pilot gas for heaters and flares.
              (B) Fuel gas streams that meet a commercial-grade product specification for sulfur content of 30 ppmv or less. In the case of a liquefied petroleum gas (LPG) product specification in the pressurized liquid state, the gas phase sulfur content should be evaluated assuming complete vaporization of the LPG and sulfur containing-compounds at the product specification concentration.
              (C) Fuel gas streams produced in process units that are intolerant to sulfur contamination, such as fuel gas streams produced in the hydrogen plant, the catalytic reforming unit, the isomerization unit, and HF alkylation process units.
              (D) Other fuel gas streams that an owner or operator demonstrates are low-sulfur according to the procedures in paragraph (b) of this section.

              (5) For Claus sulfur recovery plants with oxidation control systems or reduction control systems followed by incineration subject to § 60.104(a)(2)(i), an instrument for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of SO2 emissions into the atmosphere. The monitor shall include an oxygen monitor for correcting the data for excess air.

              (i) The span values for this monitor are 500 ppm SO2 and 25 percent O2.
              (ii) The performance evaluations for this SO2 monitor under § 60.13(c) shall use Performance Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy evaluations.

              (6) For Claus sulfur recovery plants with reduction control systems not followed by incineration subject to § 60.104(a)(2)(ii), an instrument for continuously monitoring and recording the concentration of reduced sulfur and O2 emissions into the atmosphere. The reduced sulfur emissions shall be calculated as SO2 (dry basis, zero percent excess air).

              (i) The span values for this monitor are 450 ppm reduced sulfur and 25 percent O2.

              (ii) The performance evaluations for this reduced sulfur (and O2) monitor under § 60.13(c) shall use Performance Specification 5 of appendix B of this part(and Performance Specification 3 of appendix B of this partfor the O2 analyzer). Methods 15 or 15A and Method 3 shall be used for conducting the relative accuracy evaluations. If Method 3 yields O2 concentrations below 0.25 percent during the performance specification test, the O2 concentration may be assumed to be zero and the reduced sulfur CEMS need not include an O2 monitor.

              (7) In place of the reduced sulfur monitor under paragraph (a)(6) of this section, an instrument using an air or O2 dilution and oxidation system to convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of the resultant SO2. The monitor shall include an oxygen monitor for correcting the data for excess oxygen.
              (i) The span values for this monitor are 375 ppm SO2 and 25 percent O2.
              (ii) For reporting purposes, the SO2 exceedance level for this monitor is 250 ppm (dry basis, zero percent excess air).
              (iii) The performance evaluations for this SO2 (and O2) monitor under § 60.13(c) shall use Performance Specification 5. Methods 15 or 15A and Method 3 shall be used for conducting the relative accuracy evaluations.

              (8) An instrument for continuously monitoring and recording concentrations of SO2 in the gases at both the inlet and outlet of the SO2 control device from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator seeks to comply specifically with the 90 percent reduction option under § 60.104(b)(1).

              (i) The span value of the inlet monitor shall be set at 125 percent of the maximum estimated hourly potential SO2 emission concentration entering the control device, and the span value of the outlet monitor shall be set at 50 percent of the maximum estimated hourly potential SO2 emission concentration entering the control device.
              (ii) The performance evaluations for these SO2 monitors under § 60.13(c) shall use Performance Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy evaluations.

              (9) An instrument for continuously monitoring and recording concentrations of SO2 in the gases discharged into the atmosphere from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator seeks to comply specifically with the 50 ppmv emission limit under § 60.104 (b)(1).

              (i) The span value of the monitor shall be set at 50 percent of the maximum hourly potential SO2 emission concentration of the control device.
              (ii) The performance evaluations for this SO2 monitor under § 60.13 (c) shall use Performance Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy evaluations.

              (10) An instrument for continuously monitoring and recording concentrations of oxygen (O2) in the gases at both the inlet and outlet of the sulfur dioxide control device (or the outlet only if specifically complying with the 50 ppmv standard) from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator has elected to comply with § 60.104(b)(1). The span of this continuous monitoring system shall be set at 10 percent.

              (11) The continuous monitoring systems under paragraphs (a)(8), (a)(9), and (a)(10) of this section are operated and data recorded during all periods of operation of the affected facility including periods of startup, shutdown, or malfunction, except for continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments.
              (12) The owner or operator shall use the following procedures to evaluate the continuous monitoring systems under paragraphs (a)(8), (a)(9), and (a)(10) of this section.
              (i) Method 3 or 3A and Method 6 or 6C for the relative accuracy evaluations under the § 60.13(e) performance evaluation.
              (ii) Appendix F, Procedure 1, including quarterly accuracy determinations and daily calibration drift tests.
              (13) When seeking to comply with § 60.104(b)(1), when emission data are not obtained because of continuous monitoring system breakdowns, repairs, calibration checks and zero and span adjustments, emission data will be obtained by using one of the following methods to provide emission data for a minimum of 18 hours per day in at least 22 out of 30 rolling successive calendar days.
              (i) The test methods as described in § 60.106(k);
              (ii) A spare continuous monitoring system; or
              (iii) Other monitoring systems as approved by the Administrator.
              (b) An owner or operator may demonstrate that a fuel gas stream combusted in a fuel gas combustion device subject to § 60.104(a)(1) that is not specifically exempted in § 60.105(a)(4)(iv) is inherently low in sulfur. A fuel gas stream that is determined to be low-sulfur is exempt from the monitoring requirements in paragraphs (a)(3) and (4) of this section until there are changes in operating conditions or stream composition.
              (1) The owner or operator shall submit to the Administrator a written application for an exemption from monitoring. The application must contain the following information:
              (i) A description of the fuel gas stream/system to be considered, including submission of a portion of the appropriate piping diagrams indicating the boundaries of the fuel gas stream/system, and the affected fuel gas combustion device(s) to be considered;

              (ii) A statement that there are no crossover or entry points for sour gas (high H2S content) to be introduced into the fuel gas stream/system (this should be shown in the piping diagrams);
              (iii) An explanation of the conditions that ensure low amounts of sulfur in the fuel gas stream (i.e., control equipment or product specifications) at all times;

              (iv) The supporting test results from sampling the requested fuel gas stream/system demonstrating that the sulfur content is less than 5 ppmv. Sampling data must include, at minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be collected unless other additional information would support reduced sampling. The owner or operator shall use detector tubes (“length-of-stain tube” type measurement) following the “Gas Processors Association Standard 2377-86 (incorporated by reference—see § 60.17), using tubes with a maximum span between 10 and 40 ppmv inclusive when 1≤N≤10, where N = number of pump strokes, to test the applicant fuel gas stream for H2S; and

              (v) A description of how the 2 weeks (or seven samples for infrequently operated fuel gas streams/systems) of monitoring results compares to the typical range of H2S concentration (fuel quality) expected for the fuel gas stream/system going to the affected fuel gas combustion device (e.g., the 2 weeks of daily detector tube results for a frequently operated loading rack included the entire range of products loaded out, and, therefore, should be representative of typical operating conditions affecting H2S content in the fuel gas stream going to the loading rack flare).
              (2) The effective date of the exemption is the date of submission of the information required in paragraph (b)(1) of this section).

              (3) No further action is required unless refinery operating conditions change in such a way that affects the exempt fuel gas stream/system (e.g., the stream composition changes). If such a change occurs, the owner or operator will follow the procedures in paragraph (b)(3)(i), (b)(3)(ii), or (b)(3)(iii) of this section.

              (i) If the operation change results in a sulfur content that is still within the range of concentrations included in the original application, the owner or operator shall conduct an H2S test on a grab sample and record the results as proof that the concentration is still within the range.
              (ii) If the operation change results in a sulfur content that is outside the range of concentrations included in the original application, the owner or operator may submit new information following the procedures of paragraph (b)(1) of this section within 60 days (or within 30 days after the seventh grab sample is tested for infrequently operated process units).

              (iii) If the operation change results in a sulfur content that is outside the range of concentrations included in the original application and the owner or operator chooses not to submit new information to support an exemption, the owner or operator must begin H2S monitoring using daily stain sampling to demonstrate compliance using length-of stain tubes with a maximum span between 200 and 400 ppmv inclusive when 1≤N≤5, where N = number of pump strokes. The owner or operator must begin monitoring according to the requirements in paragraph (a)(1) or (2) of this section as soon as practicable but in no case later than 180 days after the operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv is an exceedance of the 3-hour H2S concentration limit.
              (c) The average coke burn-off rate (Mg (tons) per hour) and hours of operation shall be recorded daily for any fluid catalytic cracking unit catalyst regenerator subject to § 60.102, § 60.103, or § 60.104(b)(2).
              (d) For any fluid catalytic cracking unit catalyst regenerator under § 60.102 that uses an incinerator-waste heat boiler to combust the exhaust gases from the catalyst regenerator, the owner or operator shall record daily the rate of combustion of liquid or solid fossil-fuels and the hours of operation during which liquid or solid fossil-fuels are combusted in the incinerator-waste heat boiler.

              (e) For the purpose of reports under § 60.7(c), periods of excess emissions that shall be determined and reported are defined as follows:

                Note:
                All averages, except for opacity, shall be determined as the arithmetic average of the applicable 1-hour averages, e.g., the rolling 3-hour average shall be determined as the arithmetic average of three contiguous 1-hour averages.

              (1) Opacity. All 1-hour periods that contain two or more 6-minute periods during which the average opacity as measured by the continuous monitoring system under § 60.105(a)(1) exceeds 30 percent.
              (2) Carbon monoxide. All 1-hour periods during which the average CO concentration as measured by the CO continuous monitoring system under § 60.105(a)(2) exceeds 500 ppm.
              (3) Sulfur dioxide from fuel gas combustion. (i) All rolling 3-hour periods during which the average concentration of SO2 as measured by the SO2 continuous monitoring system under § 60.105(a)(3) exceeds 20 ppm (dry basis, zero percent excess air); or

              (ii) All rolling 3-hour periods during which the average concentration of H2S as measured by the H2S continuous monitoring system under § 60.105(a)(4) exceeds 230 mg/dscm (0.10 gr/dscf).
              (4) Sulfur dioxide from Claus sulfur recovery plants. (i) All 12-hour periods during which the average concentration of SO2 as measured by the SO2 continuous monitoring system under § 60.105(a)(5) exceeds 250 ppm (dry basis, zero percent excess air); or

              (ii) All 12-hour periods during which the average concentration of reduced sulfur (as SO2) as measured by the reduced sulfur continuous monitoring system under § 60.105(a)(6) exceeds 300 ppm; or

              (iii) All 12-hour periods during which the average concentration of SO2 as measured by the SO2 continuous monitoring system under § 60.105(a)(7) exceeds 250 ppm (dry basis, zero percent excess air).
              [39 FR 9315, Mar. 8, 1974, as amended at 40 FR 46259, Oct. 6, 1975; 42 FR 32427, June 24, 1977; 42 FR 39389, Aug. 4, 1977; 43 FR 10869, Mar. 15, 1978; 48 FR 23611, May 25, 1983; 50 FR 31701, Aug. 5, 1985; 54 FR 34028, Aug. 17, 1989; 55 FR 40175, Oct. 2, 1990; 65 FR 61754, Oct. 17, 2000; 73 FR 35866, June 24, 2008; 80 FR 75229, Dec. 1, 2015]

              § 60.106
              Test methods and procedures.
              (a) In conducting the performance tests required in § 60.8, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b).
              (b) The owner or operator shall determine compliance with the particulate matter (PM) standards in § 60.102(a) as follows:
              (1) The emission rate (E) of PM shall be computed for each run using the following equation:

                ER17OC00.000

                Where:

                E = Emission rate of PM, kg/Mg (lb/ton) of coke burn-off.
                cs = Concentration of PM, g/dscm (gr/dscf).
                Qsd = Volumetric flow rate of effluent gas, dscm/hr (dscf/hr).
                Rc = Coke burn-off rate, Mg/hr (ton/hr) coke.
                K = Conversion factor, 1,000 g/kg (7,000 gr/lb).

              (2) Method 5B or 5F is to be used to determine particulate matter emissions and associated moisture content from affected facilities without wet FGD systems; only Method 5B is to be used after wet FGD systems. The sampling time for each run shall be at least 60 minutes and the sampling rate shall be at least 0.015 dscm/min (0.53 dscf/min), except that shorter sampling times may be approved by the Administrator when process variables or other factors preclude sampling for at least 60 minutes.
              (3) The coke burn-off rate (Rc) shall be computed for each run using the following equation:

               Rc = K1Qr (%CO2 + %CO) + K2Qa−K3Qr (%CO/2 + %CO2 + %O2) + K3Qoxy (%Ooxy)

                Where:

                Rc = Coke burn-off rate, kilograms per hour (kg/hr) (lb/hr).
                Qr = Volumetric flow rate of exhaust gas from fluid catalytic cracking unit regenerator before entering the emission control system, dscm/min (dscf/min).
                Qa = Volumetric flow rate of air to fluid catalytic cracking unit regenerator, as determined from the fluid catalytic cracking unit control room instrumentation, dscm/min (dscf/min).
                Qoxy = Volumetric flow rate of O2 enriched air to fluid catalytic cracking unit regenerator, as determined from the fluid catalytic cracking unit control room instrumentation, dscm/min (dscf/min).
                %CO2 = Carbon dioxide concentration in fluid catalytic cracking unit regenerator exhaust, percent by volume (dry basis).
                %CO = CO concentration in FCCU regenerator exhaust, percent by volume (dry basis).
                %O2 = O2 concentration in fluid catalytic cracking unit regenerator exhaust, percent by volume (dry basis).
                %Ooxy = O2 concentration in O2 enriched air stream inlet to the fluid catalytic cracking unit regenerator, percent by volume (dry basis).
                K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)].
                K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)].
                K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].

              (i) Method 2 shall be used to determine the volumetric flow rate (Qr).

              (ii) The emission correction factor, integrated sampling and analysis procedure of Method 3B shall be used to determine CO2, CO, and O2 concentrations.
              (4) Method 9 and the procedures of § 60.11 shall be used to determine opacity.
              (c) If auxiliary liquid or solid fossil-fuels are burned in an incinerator-waste heat boiler, the owner or operator shall determine the emission rate of PM permitted in § 60.102(b) as follows:
              (1) The allowable emission rate (Es) of PM shall be computed for each run using the following equation:

              Es = F + A (H/Rc)

                Where:

                Es = Emission rate of PM allowed, kg/Mg (lb/ton) of coke burn-off in catalyst regenerator.
                F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in catalyst regenerator.
                A = Allowable incremental rate of PM emissions, 43 g/GJ (0.10 lb/million Btu).
                H = Heat input rate from solid or liquid fossil fuel, GJ/hr (million Btu/hr).
                Rc = Coke burn-off rate, Mg coke/hr (ton coke/hr).

              (2) Procedures subject to the approval of the Administrator shall be used to determine the heat input rate.

              (3) The procedure in paragraph (b)(3) of this section shall be used to determine the coke burn-off rate (Rc).
              (d) The owner or operator shall determine compliance with the CO standard in § 60.103(a) by using the integrated sampling technique of Method 10 to determine the CO concentration (dry basis). The sampling time for each run shall be 60 minutes.

              (e)(1) The owner or operator shall determine compliance with the H2S standard in § 60.104(a)(1) as follows: Method 11, 15, 15A, or 16 shall be used to determine the H2S concentration. The gases entering the sampling train should be at about atmospheric pressure. If the pressure in the refinery fuel gas lines is relatively high, a flow control valve may be used to reduce the pressure. If the line pressure is high enough to operate the sampling train without a vacuum pump, the pump may be eliminated from the sampling train. The sample shall be drawn from a point near the centroid of the fuel gas line.

              (i) For Method 11, the sampling time and sample volume shall be at least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal sampling times shall be taken at about 1-hour intervals. The arithmetic average of these two samples shall constitute a run. For most fuel gases, sampling times exceeding 20 minutes may result in depletion of the collection solution, although fuel gases containing low concentrations of H2S may necessitate sampling for longer periods of time.
              (ii) For Method 15 or 16, at least three injects over a 1-hour period shall constitute a run.
              (iii) For Method 15A, a 1-hour sample shall constitute a run.
              (2) Where emissions are monitored by § 60.105(a)(3), compliance with § 60.104(a)(1) shall be determined using Method 6 or 6C and Method 3 or 3A. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6. A 1-hour sample shall constitute a run. Method 6 samples shall be taken at a rate of approximately 2 liters/min. The ppm correction factor (Method 6) and the sampling location in paragraph (f)(1) of this section apply. Method 4 shall be used to determine the moisture content of the gases. The sampling point for Method 4 shall be adjacent to the sampling point for Method 6 or 6C.

              (f) The owner or operator shall determine compliance with the SO2 and the H2S and reduced sulfur standards in § 60.104(a)(2) as follows:
              (1) Method 6 shall be used to determine the SO2 concentration. The concentration in mg/dscm obtained by Method 6 or 6C is multiplied by 0.3754 to obtain the concentration in ppm. The sampling point in the duct shall be the centroid of the cross section if the cross-sectional area is less than 5.00 m2 (53.8 ft2) or at a point no closer to the walls than 1.00 m (39.4 in.) if the cross-sectional area is 5.00 m2 or more and the centroid is more than 1 m from the wall. The sampling time and sample volume shall be at least 10 minutes and 0.010 dscm (0.35 dscf) for each sample. Eight samples of equal sampling times shall be taken at about 30-minute intervals. The arithmetic average of these eight samples shall constitute a run. For Method 6C, a run shall consist of the arithmetic average of four 1-hour samples. Method 4 shall be used to determine the moisture content of the gases. The sampling point for Method 4 shall be adjacent to the sampling point for Method 6 or 6C. The sampling time for each sample shall be equal to the time it takes for two Method 6 samples. The moisture content from this sample shall be used to correct the corresponding Method 6 samples for moisture. For documenting the oxidation efficiency of the control device for reduced sulfur compounds, Method 15 shall be used following the procedures of paragraph (f)(2) of this section.

              (2) Method 15 shall be used to determine the reduced sulfur and H2 S concentrations. Each run shall consist of 16 samples taken over a minimum of 3 hours. The sampling point shall be the same as that described for Method 6 in paragraph (f)(1) of this section. To ensure minimum residence time for the sample inside the sample lines, the sampling rate shall be at least 3.0 lpm (0.10 cfm). The SO2 equivalent for each run shall be calculated after being corrected for moisture and oxygen as the arithmetic average of the SO2 equivalent for each sample during the run. Method 4 shall be used to determine the moisture content of the gases as the paragraph (f)(1) of this section. The sampling time for each sample shall be equal to the time it takes for four Method 15 samples.

              (3) The oxygen concentration used to correct the emission rate for excess air shall be obtained by the integrated sampling and analysis procedure of Method 3 or 3A. The samples shall be taken simultaneously with the SO2, reduced sulfur and H2S, or moisture samples. The SO2, reduced sulfur, and H2S samples shall be corrected to zero percent excess air using the equation in paragraph (h)(6) of this section.
              (g) Each performance test conducted for the purpose of determining compliance under § 60.104(b) shall consist of all testing performed over a 7-day period using Method 6 or 6C and Method 3 or 3A. To determine compliance, the arithmetic mean of the results of all the tests shall be compared with the applicable standard.
              (h) For the purpose of determining compliance with § 60.104(b)(1), the following calculation procedures shall be used:
              (1) Calculate each 1-hour average concentration (dry, zero percent oxygen, ppmv) of sulfur dioxide at both the inlet and the outlet to the add-on control device as specified in § 60.13(h). These calculations are made using the emission data collected under § 60.105(a).
              (2) Calculate a 7-day average (arithmetic mean) concentration of sulfur dioxide for the inlet and for the outlet to the add-on control device using all of the 1-hour average concentration values obtained during seven successive 24-hour periods.

              (3) Calculate the 7-day average percent reduction using the following equation:

              Rso2 = 100(Cso2(i) − Cso2(o)) / Cso2(i)

                where:

                Rso2 = 7-day average sulfur dioxide emission reduction, percent
                Cso2(i) = sulfur dioxide emission concentration determined in § 60.106(h)(2) at the inlet to the add-on control device, ppmv
                Cso2(o) = sulfur dioxide emission concentration determined in § 60.106(h)(2) at the outlet to the add-on control device, ppmv
                100 = conversion factor, decimal to percent

              (4) Outlet concentrations of sulfur dioxide from the add-on control device for compliance with the 50 ppmv standard, reported on a dry, O2-free basis, shall be calculated using the procedures outlined in § 60.106(h)(1) and (2) above, but for the outlet monitor only.
              (5) If supplemental sampling data are used for determining the 7-day averages under paragraph (h) of this section and such data are not hourly averages, then the value obtained for each supplemental sample shall be assumed to represent the hourly average for each hour over which the sample was obtained.

              (6) For the purpose of adjusting pollutant concentrations to zero percent oxygen, the following equation shall be used:

              Cadj = Cmeas[20.9c/(20.9−%O2)]

                where:

                Cadj = pollutant concentration adjusted to zero percent oxygen, ppm or g/dscm
                Cmeas = pollutant concentration measured on a dry basis, ppm or g/dscm
                20.9c = 20.9 percent oxygen−0.0 percent oxygen (defined oxygen correction basis), percent
                20.9 = oxygen concentration in air, percent
                %O2 = oxygen concentration measured on a dry basis, percent

              (i) For the purpose of determining compliance with § 60.104(b)(2), the following reference methods and calculation procedures shall be used except as provided in paragraph (i)(12) of this section:

              (1) One 3-hour test shall be performed each day.

              (2) For gases released to the atmosphere from the fluid catalytic cracking unit catalyst regenerator:
              (i) Method 8 as modified in § 60.106(i)(3) for moisture content and for the concentration of sulfur oxides calculated as sulfur dioxide,
              (ii) Method 1 for sample and velocity traverses,
              (iii) Method 2 calculation procedures (data obtained from Methods 3 and 8) for velocity and volumetric flow rate, and
              (iv) Method 3 for gas analysis.
              (3) Method 8 shall be modified by the insertion of a heated glass fiber filter between the probe and first impinger. The probe liner and glass fiber filter temperature shall be maintained above 160 °C (320 °F). The isopropanol impinger shall be eliminated. Sample recovery procedures described in Method 8 for container No. 1 shall be eliminated. The heated glass fiber filter also shall be excluded; however, rinsing of all connecting glassware after the heated glass fiber filter shall be retained and included in container No. 2. Sampled volume shall be at least 1 dscm.
              (4) For Method 3, the integrated sampling technique shall be used.
              (5) Sampling time for each run shall be at least 3 hours.

              (6) All testing shall be performed at the same location. Where the gases discharged by the fluid catalytic cracking unit catalyst regenerator pass through an incinerator-waste heat boiler in which auxiliary or supplemental gaseous, liquid, or solid fossil fuel is burned, testing shall be conducted at a point between the regenerator outlet and the incinerator-waste heat boiler. An alternative sampling location after the waste heat boiler may be used if alternative coke burn-off rate equations, and, if requested, auxiliary/supplemental fuel SOX credits, have been submitted to and approved by the Administrator prior to sampling.
              (7) Coke burn-off rate shall be determined using the procedures specified under paragraph (b)(3) of this section, unless paragraph (i)(6) of this section applies.

              (8) Calculate the concentration of sulfur oxides as sulfur dioxide using equation 8-3 in Section 6.5 of Method 8 to calculate and report the total concentration of sulfur oxides as sulfur dioxide (Cso x).
              (9) Sulfur oxides emission rate calculated as sulfur dioxide shall be determined for each test run by the following equation:

                ER17OC00.003

                Where:

                ESOx = sulfur oxides emission rate calculated as sulfur dioxide, kg/hr (lb/hr)
                CSOx = sulfur oxides emission concentration calculated as sulfur dioxide, g/dscm (gr/dscf)
                Qsd = dry volumetric stack gas flow rate corrected to standard conditions, dscm/hr (dscf/hr)
                K = 1,000 g/kg (7,000 gr/lb)

              (10) Sulfur oxides emissions calculated as sulfur dioxide shall be determined for each test run by the following equation:

                ER17OC00.004

                Where:

                RSOx = Sulfur oxides emissions calculated as kg sulfur dioxide per Mg (lb/ton) coke burn-off.
                ESOx = Sulfur oxides emission rate calculated as sulfur dioxide, kg/hr (lb/hr).
                Rc = Coke burn-off rate, Mg/hr (ton/hr).

              (11) Calculate the 7-day average sulfur oxides emission rate as sulfur dioxide per Mg (ton) of coke burn-off by dividing the sum of the individual daily rates by the number of daily rates summed.
              (12) An owner or operator may, upon approval by the Administrator, use an alternative method for determining compliance with § 60.104(b)(2), as provided in § 60.8(b). Any requests for approval must include data to demonstrate to the Administrator that the alternative method would produce results adequate for the determination of compliance.
              (j) For the purpose of determining compliance with § 60.104(b)(3), the following analytical methods and calculation procedures shall be used:
              (1) One fresh feed sample shall be collected once per 8-hour period.

              (2) Fresh feed samples shall be analyzed separately by using any one of the following applicable analytical test methods: ASTM D129-64, 78, or 95, ASTM D1552-83 or 95, ASTM D2622-87, 94, or 98, or ASTM D1266-87, 91, or 98. (These methods are incorporated by reference: see § 60.17.) The applicable range of some of these ASTM methods is not adequate to measure the levels of sulfur in some fresh feed samples. Dilution of samples prior to analysis with verification of the dilution ratio is acceptable upon prior approval of the Administrator.
              (3) If a fresh feed sample cannot be collected at a single location, then the fresh feed sulfur content shall be determined as follows:
              (i) Individual samples shall be collected once per 8-hour period for each separate fresh feed stream charged directly into the riser or reactor of the fluid catalytic cracking unit. For each sample location the fresh feed volumetric flow rate at the time of collecting the fresh feed sample shall be measured and recorded. The same method for measuring volumetric flow rate shall be used at all locations.
              (ii) Each fresh feed sample shall be analyzed separately using the methods specified under paragraph (j)(2) of this section.
              (iii) Fresh feed sulfur content shall be calculated for each 8-hour period using the following equation:

                EC16NO91.005

                where:

                Sf = fresh feed sulfur content expressed in percent by weight of fresh feed.
                n = number of separate fresh feed streams charged directly to the riser or reactor of the fluid catalytic cracking unit.
                Qf = total volumetric flow rate of fresh feed charged to the fluid catalytic cracking unit.
                Si = fresh feed sulfur content expressed in percent by weight of fresh feed for the “ith” sampling location.
                Qi = volumetric flow rate of fresh feed stream for the “ith” sampling location.

              (4) Calculate a 7-day average (arithmetic mean) sulfur content of the fresh feed using all of the fresh feed sulfur content values obtained during seven successive 24-hour periods.
              (k) The test methods used to supplement continuous monitoring system data to meet the minimum data requirements in § 60.104(d) will be used as described below or as otherwise approved by the Administrator.
              (1) Methods 6, 6B, or 8 are used. The sampling location(s) are the same as those specified for the monitor.
              (2) For Method 6, the minimum sampling time is 20 minutes and the minimum sampling volume is 0.02 dscm (0.71 dscf) for each sample. Samples are taken at approximately 60-minute intervals. Each sample represents a 1-hour average. A minimum of 18 valid samples is required to obtain one valid day of data.
              (3) For Method 6B, collection of a sample representing a minimum of 18 hours is required to obtain one valid day of data.
              (4) For Method 8, the procedures as outlined in this section are used. The equivalent of 16 hours of sampling is required to obtain one valid day of data.
              [39 FR 9315, Mar. 8, 1974, as amended at 43 FR 10869, Mar. 15, 1978; 51 FR 42842, Nov. 26, 1986; 52 FR 20392, June 1, 1987; 53 FR 41333, Oct. 21, 1988; 54 FR 34028, Aug. 17, 1989; 55 FR 40176, Oct. 2, 1990; 56 FR 4176, Feb. 4, 1991; 65 FR 61754, Oct. 17, 2000; 71 FR 55127, Sept. 21, 2006; 73 FR 35867, June 24, 2008; 77 FR 56463, Sep. 12, 2012]

              § 60.107
              Reporting and recordkeeping requirements.
              (a) Each owner or operator subject to § 60.104(b) shall notify the Administrator of the specific provisions of § 60.104(b) with which the owner or operator seeks to comply. Notification shall be submitted with the notification of initial startup required by § 60.7(a)(3). If an owner or operator elects at a later date to comply with an alternative provision of § 60.104(b), then the Administrator shall be notified by the owner or operator in the report described in paragraph (c) of this section.
              (b) Each owner or operator subject to § 60.104(b) shall record and maintain the following information:
              (1) If subject to § 60.104(b)(1),
              (i) All data and calibrations from continuous monitoring systems located at the inlet and outlet to the control device, including the results of the daily drift tests and quarterly accuracy assessments required under appendix F, Procedure 1;

              (ii) Measurements obtained by supplemental sampling (refer to § 60.105(a)(13) and § 60.106(k)) for meeting minimum data requirements; and
              (iii) The written procedures for the quality control program required by appendix F, Procedure 1.
              (2) If subject to § 60.104(b)(2), measurements obtained in the daily Method 8 testing, or those obtained by alternative measurement methods, if § 60.106(i)(12) applies.
              (3) If subject to § 60.104(b)(3), data obtained from the daily feed sulfur tests.
              (4) Each 7-day rolling average compliance determination.
              (c) Each owner or operator subject to § 60.104(b) shall submit a report except as provided by paragraph (d) of this section. The following information shall be contained in the report:
              (1) Any 7-day period during which:

              (i) The average percent reduction and average concentration of sulfur dioxide on a dry, O2-free basis in the gases discharged to the atmosphere from any fluid cracking unit catalyst regenerator for which the owner or operator seeks to comply with § 60.104(b)(1) is below 90 percent and above 50 ppmv, as measured by the continuous monitoring system prescribed under § 60.105(a)(8), or above 50 ppmv, as measured by the outlet continuous monitoring system prescribed under § 60.105(a)(9). The average percent reduction and average sulfur dioxide concentration shall be determined using the procedures specified under § 60.106(h);

              (ii) The average emission rate of sulfur dioxide in the gases discharged to the atmosphere from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator seeks to comply with § 60.104(b)(2) exceeds 9.8 kg SOX per 1,000 kg coke burn-off, as measured by the daily testing prescribed under § 60.106(i). The average emission rate shall be determined using the procedures specified under § 60.106(i); and
              (iii) The average sulfur content of the fresh feed for which the owner or operator seeks to comply with § 60.104(b)(3) exceeds 0.30 percent by weight. The fresh feed sulfur content, a 7-day rolling average, shall be determined using the procedures specified under § 60.106(j).
              (2) Any 30-day period in which the minimum data requirements specified in § 60.104(d) are not obtained.
              (3) For each 7-day period during which an exceedance has occurred as defined in paragraphs (c)(1)(i) through (c)(1)(iii) and (c)(2) of this section:
              (i) The date that the exceedance occurred;
              (ii) An explanation of the exceedance;
              (iii) Whether the exceedance was concurrent with a startup, shutdown, or malfunction of the fluid catalytic cracking unit or control system; and
              (iv) A description of the corrective action taken, if any.
              (4) If subject to § 60.104(b)(1),
              (i) The dates for which and brief explanations as to why fewer than 18 valid hours of data were obtained for the inlet continuous monitoring system;
              (ii) The dates for which and brief explanations as to why fewer than 18 valid hours of data were obtained for the outlet continuous monitoring system;
              (iii) Identification of times when hourly averages have been obtained based on manual sampling methods;
              (iv) Identification of the times when the pollutant concentration exceeded full span of the continuous monitoring system; and
              (v) Description of any modifications to the continuous monitoring system that could affect the ability of the continuous monitoring system to comply with Performance Specifications 2 or 3.
              (vi) Results of daily drift tests and quarterly accuracy assessments as required under appendix F, Procedure 1.
              (5) If subject to § 60.104(b)(2), for each day in which a Method 8 sample result required by § 60.106(i) was not obtained, the date for which and brief explanation as to why a Method 8 sample result was not obtained, for approval by the Administrator.
              (6) If subject to § 60.104(b)(3), for each 8-hour period in which a feed sulfur measurement required by § 60.106(j) was not obtained, the date for which and brief explanation as to why a feed sulfur measurement was not obtained, for approval by the Administrator.

              (d) For any periods for which sulfur dioxide or oxides emissions data are not available, the owner or operator of the affected facility shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability which could affect the ability of the system to meet the applicable emission limit. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability.
              (e) For each fuel gas stream combusted in a fuel gas combustion device subject to § 60.104(a)(1), if an owner or operator determines that one of the exemptions listed in § 60.105(a)(4)(iv) applies to that fuel gas stream, the owner or operator shall maintain records of the specific exemption chosen for each fuel gas stream. If the owner or operator applies for the exemption described in § 60.105(a)(4)(iv)(D), the owner or operator must keep a copy of the application as well as the letter from the Administrator granting approval of the application.
              (f) The owner or operator of an affected facility shall submit the reports required under this subpart to the Administrator semiannually for each six-month period. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period.
              (g) The owner or operator of the affected facility shall submit a signed statement certifying the accuracy and completeness of the information contained in the report.
              [54 FR 34029, Aug. 17, 1989, as amended at 55 FR 40178, Oct. 2, 1990; 64 FR 7465, Feb. 12, 1999; 65 FR 61755, Oct. 17, 2000; 73 FR 35867, June 24, 2008]

              § 60.108
              Performance test and compliance provisions.
              (a) Section 60.8(d) shall apply to the initial performance test specified under paragraph (c) of this section, but not to the daily performance tests required thereafter as specified in § 60.108(d). Section 60.8(f) does not apply when determining compliance with the standards specified under § 60.104(b). Performance tests conducted for the purpose of determining compliance under § 60.104(b) shall be conducted according to the applicable procedures specified under § 60.106.
              (b) Owners or operators who seek to comply with § 60.104(b)(3) shall meet that standard at all times, including periods of startup, shutdown, and malfunctions.
              (c) The initial performance test shall consist of the initial 7-day average calculated for compliance with § 60.104(b)(1), (b)(2), or (b)(3).
              (d) After conducting the initial performance test prescribed under § 60.8, the owner or operator of a fluid catalytic cracking unit catalyst regenerator subject to § 60.104(b) shall conduct a performance test for each successive 24-hour period thereafter. The daily performance tests shall be conducted according to the appropriate procedures specified under § 60.106. In the event that a sample collected under § 60.106(i) or (j) is accidentally lost or conditions occur in which one of the samples must be discontinued because of forced shutdown, failure of an irreplaceable portion of the sample train, extreme meteorological conditions, or other circumstances, beyond the owner or operators' control, compliance may be determined using available data for the 7-day period.
              (e) Each owner or operator subject to § 60.104(b) who has demonstrated compliance with one of the provisions of § 60.104(b) but a later date seeks to comply with another of the provisions of § 60.104(b) shall begin conducting daily performance tests as specified under paragraph (d) of this section immediately upon electing to become subject to one of the other provisions of § 60.104(b). The owner or operator shall furnish the Administrator with a written notification of the change in the semiannual report required by § 60.107(f).
              [54 FR 34030, Aug. 17, 1989, as amended at 55 FR 40178, Oct. 2, 1990; 64 FR 7466, Feb. 12, 1999; 73 FR 35867, June 24, 2008]

              § 60.109
              Delegation of authority.

              (a) In delegating implementation and enforcement authority to a State under section 111(c) of the Act, the authorities contained in paragraph (b) of this section shall be retained by the Administrator and not transferred to a State.

              (b) Authorities which shall not be delegated to States:
              (1) Section 60.105(a)(13)(iii),
              (2) Section 60.106(i)(12).
              [54 FR 34031, Aug. 17, 1989, as amended at 55 FR 40178, Oct. 2, 1990]

            Subpart Ja—Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

              Source:
              73 FR 35867, June 24, 2008, unless otherwise noted.

              § 60.100a
              Applicability, designation of affected facility, and reconstruction.
              (a) The provisions of this subpart apply to the following affected facilities in petroleum refineries: fluid catalytic cracking units (FCCU), fluid coking units (FCU), delayed coking units, fuel gas combustion devices (including process heaters), flares and sulfur recovery plants. The sulfur recovery plant need not be physically located within the boundaries of a petroleum refinery to be an affected facility, provided it processes gases produced within a petroleum refinery.
              (b) Except for flares and delayed coking units, the provisions of this subpart apply only to affected facilities under paragraph (a) of this section which either commence construction, modification or reconstruction after May 14, 2007, or elect to comply with the provisions of this subpart in lieu of complying with the provisions in subpart J of this part. For flares, the provisions of this subpart apply only to flares which commence construction, modification or reconstruction after June 24, 2008. For the purposes of this subpart, a modification to a flare commences when a project that includes any of the activities in paragraphs (c)(1) or (2) of this section is commenced. For delayed coking units, the provisions of this subpart apply to delayed coking units that commence construction, reconstruction or modification on the earliest of the following dates:
              (1) May 14, 2007, for such activities that involve a “delayed coking unit” defined as follows: one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors;
              (2) December 22, 2008, for such activities that involve a “delayed coking unit” defined as follows: a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit consists of the coke drums and associated fractionator;
              (3) September 12, 2012, for such activities that involve a “delayed coking unit” as defined in § 60.101a.
              (c) For all affected facilities other than flares, the provisions in § 60.14 regarding modification apply. As provided in § 60.14(f), the special provisions set forth under this subpart shall supersede the provisions in § 60.14 with respect to flares. For the purposes of this subpart, a modification to a flare occurs as provided in paragraphs (c)(1) or (2) of this section.

              (1) Any new piping from a refinery process unit, including ancillary equipment, or a fuel gas system is physically connected to the flare (e.g., for direct emergency relief or some form of continuous or intermittent venting). However, the connections described in paragraphs (c)(1)(i) through (vii) of this section are not considered modifications of a flare.
              (i) Connections made to install monitoring systems to the flare.

              (ii) Connections made to install a flare gas recovery system or connections made to upgrade or enhance components of a flare gas recovery system (e.g., addition of compressors or recycle lines).
              (iii) Connections made to replace or upgrade existing pressure relief or safety valves, provided the new pressure relief or safety valve has a set point opening pressure no lower and an internal diameter no greater than the existing equipment being replaced or upgraded.

              (iv) Connections made for flare gas sulfur removal.

              (v) Connections made to install back-up (redundant) equipment associated with the flare (such as a back-up compressor) that does not increase the capacity of the flare.
              (vi) Replacing piping or moving an existing connection from a refinery process unit to a new location in the same flare, provided the new pipe diameter is less than or equal to the diameter of the pipe/connection being replaced/moved.
              (vii) Connections that interconnect two or more flares.
              (2) A flare is physically altered to increase the flow capacity of the flare.
              (d) For purposes of this subpart, under § 60.15, the “fixed capital cost of the new components” includes the fixed capital cost of all depreciable components which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following the relevant applicability date specified in paragraph (b) of this section.
              [73 FR 35867, June 24, 2008, as amended at 77 FR 56464, Sep. 12, 2012; 80 FR 75230, Dec. 1, 2015]

              § 60.101a
              Definitions.
              Terms used in this subpart are defined in the Clean Air Act (CAA), in § 60.2 and in this section.

                Air preheat means a device used to heat the air supplied to a process heater generally by use of a heat exchanger to recover the sensible heat of exhaust gas from the process heater.

                Ancillary equipment means equipment used in conjunction with or that serve a refinery process unit. Ancillary equipment includes, but is not limited to, storage tanks, product loading operations, wastewater treatment systems, steam- or electricity-producing units (including coke gasification units), pressure relief valves, pumps, sampling vents and continuous analyzer vents.

                Cascaded flare system means a series of flares connected to one flare gas header system arranged with increasing pressure set points so that discharges will be initially directed to the first flare in the series (i.e., the primary flare). If the discharge pressure exceeds a set point at which the flow to the primary flare would exceed the primary flare's capacity, flow will be diverted to the second flare in the series. Similarly, flow would be diverted to a third (or fourth) flare if the pressure in the flare gas header system exceeds a threshold where the flow to the first two (or three) flares would exceed their capacities.

                Co-fired process heater means a process heater that employs burners that are designed to be supplied by both gaseous and liquid fuels on a routine basis. Process heaters that have gas burners with emergency oil back-up burners are not considered co-fired process heaters.

                Coke burn-off means the coke removed from the surface of the FCCU catalyst by combustion in the catalyst regenerator. The rate of coke burn-off is calculated by the formula specified in § 60.104a.

                Contact material means any substance formulated to remove metals, sulfur, nitrogen, or any other contaminant from petroleum derivatives.

                Corrective action means the design, operation and maintenance changes that one takes consistent with good engineering practice to reduce or eliminate the likelihood of the recurrence of the primary cause and any other contributing cause(s) of an event identified by a root cause analysis as having resulted in a discharge of gases from an affected facility in excess of specified thresholds.

                Corrective action analysis means a description of all reasonable interim and long-term measures, if any, that are available, and an explanation of why the selected corrective action(s) is/are the best alternative(s), including, but not limited to, considerations of cost effectiveness, technical feasibility, safety and secondary impacts.

                Delayed coking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit includes, but is not limited to, all of the coke drums associated with a single fractionator; the fractionator, including the bottoms receiver and the overhead condenser; the coke drum cutting water and quench system, including the jet pump and coker quench water tank; and the coke drum blowdown recovery compressor system.

                Emergency flare means a flare that combusts gas exclusively released as a result of malfunctions (and not startup, shutdown, routine operations or any other cause) on four or fewer occasions in a rolling 365-day period. For purposes of this rule, a flare cannot be categorized as an emergency flare unless it maintains a water seal.

                Flare means a combustion device that uses an uncontrolled volume of air to burn gases. The flare includes the foundation, flare tip, structural support, burner, igniter, flare controls, including air injection or steam injection systems, flame arrestors and the flare gas header system. In the case of an interconnected flare gas header system, the flare includes each individual flare serviced by the interconnected flare gas header system and the interconnected flare gas header system.

                Flare gas header system means all piping and knockout pots, including those in a subheader system, used to collect and transport gas to a flare either from a process unit or a pressure relief valve from the fuel gas system, regardless of whether or not a flare gas recovery system draws gas from the flare gas header system. The flare gas header system includes piping inside the battery limit of a process unit if the purpose of the piping is to transport gas to a flare or knockout pot that is part of the flare.

                Flare gas recovery system means a system of one or more compressors, piping and the associated water seal, rupture disk or similar device used to divert gas from the flare and direct the gas to the fuel gas system or to a fuel gas combustion device.

                Flexicoking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced and then gasified to produce a synthetic fuel gas.

                Fluid catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst suspended in a fluidized bed are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and regenerator equipment for controlling air pollutant emissions and for heat recovery. When fluid catalyst cracking unit regenerator exhaust from two separate fluid catalytic cracking units share a common exhaust treatment (e.g., CO boiler or wet scrubber), the fluid catalytic cracking unit is a single affected facility.

                Fluid coking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed system. The fluid coking unit includes the coking reactor, the coking burner, and equipment for controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent.

                Forced draft process heater means a process heater in which the combustion air is supplied under positive pressure produced by a fan at any location in the inlet air line prior to the point where the combustion air enters the process heater or air preheat. For the purposes of this subpart, a process heater that uses fans at both the inlet air side and the exhaust air side (i.e., balanced draft system) is considered to be a forced draft process heater.

                Fuel gas means any gas which is generated at a petroleum refinery and which is combusted. Fuel gas includes natural gas when the natural gas is combined and combusted in any proportion with a gas generated at a refinery. Fuel gas does not include gases generated by catalytic cracking unit catalyst regenerators, coke calciners (used to make premium grade coke) and fluid coking burners, but does include gases from flexicoking unit gasifiers and other gasifiers. Fuel gas does not include vapors that are collected and combusted in a thermal oxidizer or flare installed to control emissions from wastewater treatment units other than those processing sour water, marine tank vessel loading operations or asphalt processing units (i.e., asphalt blowing stills).

                Fuel gas combustion device means any equipment, such as process heaters and boilers, used to combust fuel gas. For the purposes of this subpart, fuel gas combustion device does not include flares or facilities in which gases are combusted to produce sulfur or sulfuric acid.

                Fuel gas system means a system of compressors, piping, knock-out pots, mix drums, and units used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects refinery fuel gas from one or more sources for treatment as necessary prior to combusting in process heaters or boilers. A fuel gas system may have an overpressure vent to a flare but the primary purpose for a fuel gas system is to provide fuel to the refinery.

                Natural draft process heater means any process heater in which the combustion air is supplied under ambient or negative pressure without the use of an inlet air (forced draft) fan. For the purposes of this subpart, a natural draft process heater is any process heater that is not a forced draft process heater, including induced draft systems.

                Non-emergency flare means any flare that is not an emergency flare as defined in this subpart.

                Oxidation control system means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to sulfur dioxide (SO2) and recycling the SO2 to the reactor furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or converting the SO2 to a sulfur product.

                Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal.

                Petroleum refinery means any facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of petroleum or through redistillation, cracking or reforming of unfinished petroleum derivatives. A facility that produces only oil shale or tar sands-derived crude oil for further processing at a petroleum refinery using only solvent extraction and/or distillation to recover diluent is not a petroleum refinery.

                Primary flare means the first flare in a cascaded flare system.

                Process heater means an enclosed combustion device used to transfer heat indirectly to process stream materials (liquids, gases, or solids) or to a heat transfer material for use in a process unit instead of steam.

                Process upset gas means any gas generated by a petroleum refinery process unit or by ancillary equipment as a result of startup, shutdown, upset or malfunction.

                Purge gas means gas introduced between a flare's water seal and a flare's tip to prevent oxygen infiltration (backflow) into the flare tip. For flares with no water seals, the function of purge gas is performed by sweep gas (i.e., flares without water seals do not use purge gas).

                Reduced sulfur compounds means hydrogen sulfide (H2S), carbonyl sulfide, and carbon disulfide.

                Reduction control system means an emission control system which reduces emissions from sulfur recovery plants by converting these emissions to H2S and either recycling the H2S to the reactor furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or converting the H2S to a sulfur product.

                Refinery process unit means any segment of the petroleum refinery in which a specific processing operation is conducted.

                Root cause analysis means an assessment conducted through a process of investigation to determine the primary cause, and any other contributing cause(s), of a discharge of gases in excess of specified thresholds.

                Secondary flare means a flare in a cascaded flare system that provides additional flare capacity and pressure relief to a flare gas system when the flare gas flow exceeds the capacity of the primary flare. For purposes of this subpart, a secondary flare is characterized by infrequent use and must maintain a water seal.

                Sour water means water that contains sulfur compounds (usually H2S) at concentrations of 10 parts per million by weight or more.

                Sulfur pit means the storage vessel in which sulfur that is condensed after each Claus catalytic reactor is initially accumulated and stored. A sulfur pit does not include secondary sulfur storage vessels downstream of the initial Claus reactor sulfur pits.

                Sulfur recovery plant means all process units which recover sulfur from H2S and/or SO2 from a common source of sour gas produced at a petroleum refinery. The sulfur recovery plant also includes sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes: Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits and, if present, oxidation or reduction control systems or incinerator, thermal oxidizer or similar combustion device. Multiple sulfur recovery units are a single affected facility only when the units share the same source of sour gas. Sulfur recovery plants that receive source gas from completely segregated sour gas treatment systems are separate affected facilities.

                Sweep gas means the gas introduced in a flare gas header system to maintain a constant flow of gas to prevent oxygen buildup in the flare header. For flares with no water seals, sweep gas also performs the function of preventing oxygen infiltration (backflow) into the flare tip.
              [73 FR 35867, June 24, 2008, as amended at 77 FR 56464, Sep. 12, 2012; 78 FR 76756, Dec. 19, 2013; 80 FR 75230, Dec. 1, 2015]

              § 60.102a
              Emissions limitations.
              (a) Each owner or operator that is subject to the requirements of this subpart shall comply with the emissions limitations in paragraphs (b) through (i) of this section on and after the date on which the initial performance test, required by § 60.8, is completed, but not later than 60 days after achieving the maximum production rate at which the affected facility will be operated or 180 days after initial startup, whichever comes first.
              (b) An owner or operator subject to the provisions of this subpart shall not discharge or cause the discharge into the atmosphere from any FCCU or FCU:
              (1) Particulate matter (PM) in excess of the limits in paragraphs (b)(1)(i), (ii), or (iii) of this section.
              (i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke burn-off or, if a PM continuous emission monitoring system (CEMS) is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each modified or reconstructed FCCU.
              (ii) 0.5 gram per kilogram (g/kg) coke burn-off (0.5 lb PM/1,000 lb coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0 percent excess air for each newly constructed FCCU.
              (iii) 1.0 g/kg (1 lb/1,000 lb) coke burn-off or, if a PM CEMS is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each affected FCU.
              (2) Nitrogen oxides (NOX) in excess of 80 parts per million by volume (ppmv), dry basis corrected to 0 percent excess air, on a 7-day rolling average basis.
              (3) Sulfur dioxide (SO2) in excess of 50 ppmv dry basis corrected to 0 percent excess air, on a 7-day rolling average basis and 25 ppmv, dry basis corrected to 0 percent excess air, on a 365-day rolling average basis.
              (4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected to 0 percent excess air, on an hourly average basis.
              (c) The owner or operator of a FCCU or FCU that uses a continuous parameter monitoring system (CPMS) according to § 60.105a(b)(1) shall comply with the applicable control device parameter operating limit in paragraph (c)(1) or (2) of this section.
              (1) If the FCCU or FCU is controlled using an electrostatic precipitator:
              (i) The 3-hour rolling average total power and secondary current to the entire system must not fall below the level established during the most recent performance test; and
              (ii) The daily average exhaust coke burn-off rate must not exceed the level established during the most recent performance test.
              (2) If the FCCU or FCU is controlled using a wet scrubber:

              (i) The 3-hour rolling average pressure drop must not fall below the level established during the most recent performance test; and
              (ii) The 3-hour rolling average liquid-to-gas ratio must not fall below the level established during the most recent performance test.
              (d) If an FCCU or FCU uses a continuous opacity monitoring system (COMS) according to the alternative monitoring option in § 60.105a(e), the 3-hour rolling average opacity of emissions from the FCCU or FCU as measured by the COMS must not exceed the site-specific opacity limit established during the most recent performance test.
              (e) The owner or operator of a FCCU or FCU that is exempted from the requirement for a CO continuous emissions monitoring system under § 60.105a(h)(3) shall comply with the parameter operating limits in paragraph (e)(1) or (2) of this section.
              (1) For a FCCU or FCU with no post-combustion control device:
              (i) The hourly average temperature of the exhaust gases exiting the FCCU or FCU must not fall below the level established during the most recent performance test.
              (ii) The hourly average oxygen (O2) concentration of the exhaust gases exiting the FCCU or FCU must not fall below the level established during the most recent performance test.
              (2) For a FCCU or FCU with a post-combustion control device:
              (i) The hourly average temperature of the exhaust gas vent stream exiting the control device must not fall below the level established during the most recent performance test.
              (ii) The hourly average O2 concentration of the exhaust gas vent stream exiting the control device must not fall below the level established during the most recent performance test.
              (f) Except as provided in paragraph (f)(3) of this section, each owner or operator of an affected sulfur recovery plant shall comply with the applicable emission limits in paragraph (f)(1) or (2) of this section.

              (1) For a sulfur recovery plant with a design production capacity greater than 20 long tons per day (LTD), the owner or operator shall comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) of this section. If the sulfur recovery plant consists of multiple process trains or release points, the owner or operator shall comply with the applicable emission limit for each process train or release point individually or comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) as a flow rate weighted average for a group of release points from the sulfur recovery plant provided that flow is monitored as specified in § 60.106a(a)(7); if flow is not monitored as specified in § 60.106a(a)(7), the owner or operator shall comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) for each process train or release point individually. For a sulfur recovery plant with a design production capacity greater than 20 long LTD and a reduction control system not followed by incineration, the owner or operator shall also comply with the H2S emission limit in paragraph (f)(1)(iii) of this section for each individual release point.

              (i) For a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases containing SO2 into the atmosphere in excess of the emission limit calculated using Equation 1 of this section. For Claus units that use only ambient air in the Claus burner or that elect not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, this SO2 emissions limit is 250 ppmv (dry basis) at zero percent excess air.

                ER01DE15.000

                Where:

                ELS = Emission limit for large sulfur recovery plant, ppmv (as SO2, dry basis at zero percent excess air);
                k1 = Constant factor for emission limit conversion: k1 = 1 for converting to the SO2 limit for a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration and k1 = 1.2 for converting to the reduced sulfur compounds limit for a sulfur recovery plant with a reduction control system not followed by incineration; and
                %O2 = O2 concentration of the air/oxygen mixture supplied to the Claus burner, percent by volume (dry basis). If only ambient air is used for the Claus burner or if the owner or operator elects not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, use 20.9% for %O2.

              (ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing reduced sulfur compounds in excess of the emission limit calculated using Equation 1 of this section. For Claus units that use only ambient air in the Claus burner or for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is 300 ppmv calculated as ppmv SO2 (dry basis) at 0-percent excess air.

              (iii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing hydrogen sulfide (H2S) in excess of 10 ppmv calculated as ppmv SO2 (dry basis) at zero percent excess air.

              (2) For a sulfur recovery plant with a design production capacity of 20 LTD or less, the owner or operator shall comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) of this section. If the sulfur recovery plant consists of multiple process trains or release points, the owner or operator may comply with the applicable emission limit for each process train or release point individually or comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) as a flow rate weighted average for a group of release points from the sulfur recovery plant provided that flow is monitored as specified in § 60.106a(a)(7); if flow is not monitored as specified in § 60.106a(a)(7), the owner or operator shall comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) for each process train or release point individually. For a sulfur recovery plant with a design production capacity of 20 LTD or less and a reduction control system not followed by incineration, the owner or operator shall also comply with the H2S emission limit in paragraph (f)(2)(iii) of this section for each individual release point.

              (i) For a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing SO2 in excess of the emission limit calculated using Equation 2 of this section. For Claus units that use only ambient air in the Claus burner or that elect not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, this SO2 emission limit is 2,500 ppmv (dry basis) at zero percent excess air.

                ER01DE15.001

                Where:

                ESS = Emission limit for small sulfur recovery plant, ppmv (as SO2, dry basis at zero percent excess air);
                k1 = Constant factor for emission limit conversion: k1 = 1 for converting to the SO2 limit for a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration and k1 = 1.2 for converting to the reduced sulfur compounds limit for a sulfur recovery plant with a reduction control system not followed by incineration; and
                %O2 = O2 concentration of the air/oxygen mixture supplied to the Claus burner, percent by volume (dry basis). If only ambient air is used in the Claus burner or if the owner or operator elects not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, use 20.9% for %O2.

              (ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing reduced sulfur compounds in excess of the emission limit calculated using Equation 2 of this section. For Claus units that use only ambient air in the Claus burner or for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is 3,000 ppmv calculated as ppmv SO2 (dry basis) at zero percent excess air.

              (iii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing H2S in excess of 100 ppmv calculated as ppmv SO2 (dry basis) at zero percent excess air.
              (3) The emission limits in paragraphs (f)(1) and (2) of this section shall not apply during periods of maintenance of the sulfur pit, which shall not exceed 240 hours per year. The owner or operator must document the time periods during which the sulfur pit vents were not controlled and measures taken to minimize emissions during these periods. Examples of these measures include not adding fresh sulfur or shutting off vent fans.
              (g) Each owner or operator of an affected fuel gas combustion device shall comply with the emissions limits in paragraphs (g)(1) and (2) of this section.
              (1) Except as provided in (g)(1)(iii) of this section, for each fuel gas combustion device, the owner or operator shall comply with either the emission limit in paragraph (g)(1)(i) of this section or the fuel gas concentration limit in paragraph (g)(1)(ii) of this section. For CO boilers or furnaces that are part of a fluid catalytic cracking unit or fluid coking unit affected facility, the owner or operator shall comply with the fuel gas concentration limit in paragraph (g)(1)(ii) for all fuel gas streams combusted in these units.

              (i) The owner or operator shall not discharge or cause the discharge of any gases into the atmosphere that contain SO2 in excess of 20 ppmv (dry basis, corrected to 0-percent excess air) determined hourly on a 3-hour rolling average basis and SO2 in excess of 8 ppmv (dry basis, corrected to 0-percent excess air), determined daily on a 365 successive calendar day rolling average basis; or

              (ii) The owner or operator shall not burn in any fuel gas combustion device any fuel gas that contains H2S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis and H2S in excess of 60 ppmv determined daily on a 365 successive calendar day rolling average basis.
              (iii) The combustion in a portable generator of fuel gas released as a result of tank degassing and/or cleaning is exempt from the emissions limits in paragraphs (g)(1)(i) and (ii) of this section.

              (2) For each process heater with a rated capacity of greater than 40 million British thermal units per hour (MMBtu/hr) on a higher heating value basis, the owner or operator shall not discharge to the atmosphere any emissions of NOX in excess of the applicable limits in paragraphs (g)(2)(i) through (iv) of this section.
              (i) For each natural draft process heater, comply with the limit in either paragraph (g)(2)(i)(A) or (B) of this section. The owner or operator may comply with either limit at any time, provided that the appropriate parameters for each alternative are monitored as specified in § 60.107a; if fuel gas composition is not monitored as specified in § 60.107a(d), the owner or operator must comply with the concentration limits in paragraph (g)(2)(i)(A) of this section.
              (A) 40 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30-day rolling average basis; or
              (B) 0.040 pounds per million British thermal units (lb/MMBtu) higher heating value basis determined daily on a 30-day rolling average basis.

              (ii) For each forced draft process heater, comply with the limit in either paragraph (g)(2)(ii)(A) or (B) of this section. The owner or operator may comply with either limit at any time, provided that the appropriate parameters for each alternative are monitored as specified in § 60.107a; if fuel gas composition is not monitored as specified in § 60.107a(d), the owner or operator must comply with the concentration limits in paragraph (g)(2)(ii)(A) of this section.
              (A) 60 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30-day rolling average basis; or
              (B) 0.060 lb/MMBtu higher heating value basis determined daily on a 30-day rolling average basis.
              (iii) For each co-fired natural draft process heater, comply with the limit in either paragraph (g)(2)(iii)(A) or (B) of this section. The owner or operator must choose one of the emissions limits with which to comply at all times:
              (A) 150 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30 successive operating day rolling average basis; or
              (B) The daily average emissions limit calculated using Equation 3 of this section:

                ER12SE12.001

                Where:

                ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu (higher heating value basis);
                Qgas = Daily average volumetric flow rate of fuel gas, standard cubic feet per day (scf/day);
                Qoil = Daily average volumetric flow rate of fuel oil, scf/day;
                HHVgas = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and
                HHVoil = Daily average higher heating value of fuel oil fired to the process heater, MMBtu/scf.

              (iv) For each co-fired forced draft process heater, comply with the limit in either paragraph (g)(2)(iv)(A) or (B) of this section. The owner or operator must choose one of the emissions limits with which to comply at all times:
              (A) 150 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30 successive operating day rolling average basis; or
              (B) The daily average emissions limit calculated using Equation 4 of this section:

                ER12SE12.002

                Where:

                ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu (higher heating value basis);
                Qgas = Daily average volumetric flow rate of fuel gas, scf/day;
                Qoil = Daily average volumetric flow rate of fuel oil, scf/day;
                HHVgas = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and
                HHVoil = Daily average higher heating value of fuel oil fired to the process heater, MMBtu/scf.

              (h) [Reserved]

              (i) For a process heater that meets any of the criteria of paragraphs (i)(1)(i) through (iv) of this section, an owner or operator may request approval from the Administrator for a NOX emissions limit which shall apply specifically to that affected facility. The request shall include information as described in paragraph (i)(2) of this section. The request shall be submitted and followed as described in paragraph (i)(3) of this section.

              (1) A process heater that meets one of the criteria in paragraphs (i)(1)(i) through (iv) of this section may apply for a site-specific NOX emissions limit:

              (i) A modified or reconstructed process heater that lacks sufficient space to accommodate installation and proper operation of combustion modification-based technology (e.g., ultra-low NOX burners); or
              (ii) A modified or reconstructed process heater that has downwardly firing induced draft burners; or
              (iii) A co-fired process heater; or

              (iv) A process heater operating at reduced firing conditions for an extended period of time (i.e., operating in turndown mode). The site-specific NOX emissions limit will only apply for those operating conditions.

              (2) The request shall include sufficient and appropriate data, as determined by the Administrator, to allow the Administrator to confirm that the process heater is unable to comply with the applicable NOX emissions limit in paragraph (g)(2) of this section. At a minimum, the request shall contain the information described in paragraphs (i)(2)(i) through (iv) of this section.
              (i) The design and dimensions of the process heater, evaluation of available combustion modification-based technology, description of fuel gas and, if applicable, fuel oil characteristics, information regarding the combustion conditions (temperature, oxygen content, firing rates) and other information needed to demonstrate that the process heater meets one of the four classes of process heaters listed in paragraph (i)(1) of this section.

              (ii) An explanation of how the data in paragraph (i)(2)(i) demonstrate that ultra-low NOX burners, flue gas recirculation, control of excess air or other combustion modification-based technology (including combinations of these combustion modification-based technologies) cannot be used to meet the applicable emissions limit in paragraph (g)(2) of this section.

              (iii) Results of a performance test conducted under representative conditions using the applicable methods specified in § 60.104a(i) to demonstrate the performance of the technology the owner or operator will use to minimize NOX emissions.
              (iv) The means by which the owner or operator will document continuous compliance with the site-specific emissions limit.
              (3) The request shall be submitted and followed as described in paragraphs (i)(3)(i) through (iii) of this section.

              (i) The owner or operator of a process heater that meets one of the criteria in paragraphs (i)(1)(i) through (iv) of this section may request approval from the Administrator within 180 days after initial startup of the process heater for a NOX emissions limit which shall apply specifically to that affected facility.
              (ii) The request must be submitted to the Administrator for approval. The owner or operator must comply with the request as submitted until it is approved.

              (iii) The request shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov.

              (4) The approval process for a request for a facility-specific NOX emissions limit is described in paragraphs (i)(4)(i) through (iii) of this section.

              (i) Approval by the Administrator of a facility-specific NOX emissions limit request will be based on the completeness, accuracy and reasonableness of the request. Factors that the EPA will consider in reviewing the request for approval include, but are not limited to, the following:
              (A) A demonstration that the process heater meets one of the four classes of process heaters outlined in paragraphs (i)(1) of this section;
              (B) A description of the low-NOX burner designs and other combustion modifications considered for reducing NOX emissions;
              (C) The combustion modification option selected; and

              (D) The operating conditions (firing rate, heater box temperature and excess oxygen concentration) at which the NOX emission level was established.

              (ii) If the request is approved by the Administrator, a facility-specific NOX emissions limit will be established at the NOX emission level demonstrated in the approved request.
              (iii) If the Administrator finds any deficiencies in the request, the request must be revised to address the deficiencies and be re-submitted for approval.
              [73 FR 35867, June 24, 2008, as amended at 77 FR 56466, Sep. 12, 2012; 80 FR 75230, Dec. 1, 2015; 81 FR 45240, July 13, 2016]

              § 60.103a
              Design, equipment, work practice or operational standards.
              (a) Except as provided in paragraph (g) of this section, each owner or operator that operates a flare that is subject to this subpart shall develop and implement a written flare management plan no later than the date specified in paragraph (b) of this section. The flare management plan must include the information described in paragraphs (a)(1) through (7) of this section.
              (1) A listing of all refinery process units, ancillary equipment, and fuel gas systems connected to the flare for each affected flare.
              (2) An assessment of whether discharges to affected flares from these process units, ancillary equipment and fuel gas systems can be minimized. The flare minimization assessment must (at a minimum) consider the items in paragraphs (a)(2)(i) through (iv) of this section. The assessment must provide clear rationale in terms of costs (capital and annual operating), natural gas offset credits (if applicable), technical feasibility, secondary environmental impacts and safety considerations for the selected minimization alternative(s) or a statement, with justifications, that flow reduction could not be achieved. Based upon the assessment, each owner or operator of an affected flare shall identify the minimization alternatives that it has implemented by the due date of the flare management plan and shall include a schedule for the prompt implementation of any selected measures that cannot reasonably be completed as of that date.
              (i) Elimination of process gas discharge to the flare through process operating changes or gas recovery at the source.
              (ii) Reduction of the volume of process gas to the flare through process operating changes.
              (iii) Installation of a flare gas recovery system or, for facilities that are fuel gas rich, a flare gas recovery system and a co-generation unit or combined heat and power unit.
              (iv) Minimization of sweep gas flow rates and, for flares with water seals, purge gas flow rates.
              (3) A description of each affected flare containing the information in paragraphs (a)(3)(i) through (vii) of this section.
              (i) A general description of the flare, including the information in paragraphs (a)(3)(i)(A) through (G) of this section.
              (A) Whether it is a ground flare or elevated (including height).
              (B) The type of assist system (e.g., air, steam, pressure, non-assisted).
              (C) Whether it is simple or complex flare tip (e.g., staged, sequential).
              (D) Whether the flare is part of a cascaded flare system (and if so, whether the flare is primary or secondary).
              (E) Whether the flare serves as a backup to another flare.
              (F) Whether the flare is an emergency flare or a non-emergency flare.
              (G) Whether the flare is equipped with a flare gas recovery system.
              (ii) Description and simple process flow diagram showing the interconnection of the following components of the flare: flare tip (date installed, manufacturer, nominal and effective tip diameter, tip drawing); knockout or surge drum(s) or pot(s) (including dimensions and design capacities); flare header(s) and subheader(s); assist system; and ignition system.
              (iii) Flare design parameters, including the maximum vent gas flow rate; minimum sweep gas flow rate; minimum purge gas flow rate (if any); maximum supplemental gas flow rate; maximum pilot gas flow rate; and, if the flare is steam-assisted, minimum total steam rate.

              (iv) Description and simple process flow diagram showing all gas lines (including flare, purge (if applicable), sweep, supplemental and pilot gas) that are associated with the flare. For purge, sweep, supplemental and pilot gas, identify the type of gas used. Designate which lines are exempt from sulfur, H2S or flow monitoring and why (e.g., natural gas, inherently low sulfur, pilot gas). Designate which lines are monitored and identify on the process flow diagram the location and type of each monitor.
              (v) For each flow rate, H2S, sulfur content, pressure or water seal monitor identified in paragraph (a)(3)(iv) of this section, provide a detailed description of the manufacturer's specifications, including, but not limited to, make, model, type, range, precision, accuracy, calibration, maintenance and quality assurance procedures.
              (vi) For emergency flares, secondary flares and flares equipped with a flare gas recovery system designed, sized and operated to capture all flows except those resulting from startup, shutdown or malfunction:
              (A) Description of the water seal, including the operating range for the liquid level.
              (B) Designation of the monitoring option elected (flow and sulfur monitoring or pressure and water seal liquid level monitoring).
              (vii) For flares equipped with a flare gas recovery system:
              (A) A description of the flare gas recovery system, including number of compressors and capacity of each compressor.
              (B) A description of the monitoring parameters used to quantify the amount of flare gas recovered.
              (C) For systems with staged compressors, the maximum time period required to begin gas recovery with the secondary compressor(s), the monitoring parameters and procedures used to minimize the duration of releases during compressor staging and a justification for why the maximum time period cannot be further reduced.

              (4) An evaluation of the baseline flow to the flare. The baseline flow to the flare must be determined after implementing the minimization assessment in paragraph (a)(2) of this section. Baseline flows do not include pilot gas flow or purge gas flow (i.e., gas introduced after the flare's water seal) provided these gas flows remain reasonably constant (i.e., separate flow monitors for these streams are not required). Separate baseline flow rates may be established for different operating conditions provided that the management plan includes:
              (i) A primary baseline flow rate that will be used as the default baseline for all conditions except those specifically delineated in the plan;
              (ii) A description of each special condition for which an alternate baseline is established, including the rationale for each alternate baseline, the daily flow for each alternate baseline and the expected duration of the special conditions for each alternate baseline; and
              (iii) Procedures to minimize discharges to the affected flare during each special condition described in paragraph (a)(4)(ii) of this section, unless procedures are already developed for these cases under paragraph (a)(5) through (7) of this section, as applicable.
              (5) Procedures to minimize or eliminate discharges to the flare during the planned startup and shutdown of the refinery process units and ancillary equipment that are connected to the affected flare, together with a schedule for the prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan.

              (6) Procedures to reduce flaring in cases of fuel gas imbalance (i.e., excess fuel gas for the refinery's energy needs), together with a schedule for the prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan.
              (7) For flares equipped with flare gas recovery systems, procedures to minimize the frequency and duration of outages of the flare gas recovery system and procedures to minimize the volume of gas flared during such outages, together with a schedule for the prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan.

              (b) Except as provided in paragraph (g) of this section, each owner or operator required to develop and implement a written flare management plan as described in paragraph (a) of this section must submit the plan to the Administrator as described in paragraphs (b)(1) through (3) of this section.
              (1) The owner or operator of a newly constructed or reconstructed flare must develop and implement the flare management plan by no later than the date that the flare becomes an affected facility subject to this subpart, except for the selected minimization alternatives in paragraph (a)(2) and/or the procedures in paragraphs (a)(5) though (a)(7) of this section that cannot reasonably be implemented by that date, which the owner or operator must implement in accordance with the schedule in the flare management plan. The owner or operator of a modified flare must develop and implement the flare management plan by no later than November 11, 2015 or upon startup of the modified flare, whichever is later.
              (2) The owner or operator must comply with the plan as submitted by the date specified in paragraph (b)(1) of this section. The plan should be updated periodically to account for changes in the operation of the flare, such as new connections to the flare or the installation of a flare gas recovery system, but the plan need be re-submitted to the Administrator only if the owner or operator adds an alternative baseline flow rate, revises an existing baseline as described in paragraph (a)(4) of this section, installs a flare gas recovery system or is required to change flare designations and monitoring methods as described in § 60.107a(g). The owner or operator must comply with the updated plan as submitted.

              (3) All versions of the plan submitted to the Administrator shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov.

              (c) Except as provided in paragraphs (f) and (g) of this section, each owner or operator that operates a fuel gas combustion device, flare or sulfur recovery plant subject to this subpart shall conduct a root cause analysis and a corrective action analysis for each of the conditions specified in paragraphs (c)(1) through (3) of this section.
              (1) For a flare:
              (i) Any time the SO2 emissions exceed 227 kilograms (kg) (500 lb) in any 24-hour period; or
              (ii) Any discharge to the flare in excess of 14,160 standard cubic meters (m3) (500,000 standard cubic feet (scf)) above the baseline, determined in paragraph (a)(4) of this section, in any 24-hour period; or
              (iii) If the monitoring alternative in § 60.107a(g) is elected, any period when the flare gas line pressure exceeds the water seal liquid depth, except for periods attributable to compressor staging that do not exceed the staging time specified in paragraph (a)(3)(vii)(C) of this section.

              (2) For a fuel gas combustion device, each exceedance of an applicable short-term emissions limit in § 60.102a(g)(1) if the SO2 discharge to the atmosphere is 227 kg (500 lb) greater than the amount that would have been emitted if the emissions limits had been met during one or more consecutive periods of excess emissions or any 24-hour period, whichever is shorter.
              (3) For a sulfur recovery plant, each time the SO2 emissions are more than 227 kg (500 lb) greater than the amount that would have been emitted if the SO2 or reduced sulfur concentration was equal to the applicable emissions limit in § 60.102a(f)(1) or (2) during one or more consecutive periods of excess emissions or any 24-hour period, whichever is shorter.
              (d) Except as provided in paragraphs (f) and (g) of this section, a root cause analysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a discharge meeting one of the conditions specified in paragraphs (c)(1) through (3) of this section. Special circumstances affecting the number of root cause analyses and/or corrective action analyses are provided in paragraphs (d)(1) through (5) of this section.

              (1) If a single continuous discharge meets any of the conditions specified in paragraphs (c)(1) through (3) of this section for 2 or more consecutive 24-hour periods, a single root cause analysis and corrective action analysis may be conducted.
              (2) If a single discharge from a flare triggers a root cause analysis based on more than one of the conditions specified in paragraphs (c)(1)(i) through (iii) of this section, a single root cause analysis and corrective action analysis may be conducted.
              (3) If the discharge from a flare is the result of a planned startup or shutdown of a refinery process unit or ancillary equipment connected to the affected flare and the procedures in paragraph (a)(5) of this section were followed, a root cause analysis and corrective action analysis is not required; however, the discharge must be recorded as described in § 60.108a(c)(6) and reported as described in § 60.108a(d)(5).
              (4) If both the primary and secondary flare in a cascaded flare system meet any of the conditions specified in paragraphs (c)(1)(i) through (iii) of this section in the same 24-hour period, a single root cause analysis and corrective action analysis may be conducted.
              (5) Except as provided in paragraph (d)(4) of this section, if discharges occur that meet any of the conditions specified in paragraphs (c)(1) through (3) of this section for more than one affected facility in the same 24-hour period, initial root cause analyses shall be conducted for each affected facility. If the initial root cause analyses indicate that the discharges have the same root cause(s), the initial root cause analyses can be recorded as a single root cause analysis and a single corrective action analysis may be conducted.
              (e) Except as provided in paragraphs (f) and (g) of this section, each owner or operator of a fuel gas combustion device, flare or sulfur recovery plant subject to this subpart shall implement the corrective action(s) identified in the corrective action analysis conducted pursuant to paragraph (d) of this section in accordance with the applicable requirements in paragraphs (e)(1) through (3) of this section.
              (1) All corrective action(s) must be implemented within 45 days of the discharge for which the root cause and corrective action analyses were required or as soon thereafter as practicable. If an owner or operator concludes that corrective action should not be conducted, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the discharge as specified in § 60.108a(c)(6)(ix).
              (2) For corrective actions that cannot be fully implemented within 45 days following the discharge for which the root cause and corrective action analyses were required, the owner or operator shall develop an implementation schedule to complete the corrective action(s) as soon as practicable.
              (3) No later than 45 days following the discharge for which a root cause and corrective action analyses were required, the owner or operator shall record the corrective action(s) completed to date, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates as specified in § 60.108a(c)(6)(x).
              (f) Modified flares shall comply with the requirements of paragraphs (c) through (e) of this section by November 11, 2015 or at startup of the modified flare, whichever is later. Modified flares that were not affected facilities subject to subpart J of this part prior to becoming affected facilities under § 60.100a shall comply with the requirements of paragraph (h) of this section and the requirements of § 60.107a(a)(2) by November 11, 2015 or at startup of the modified flare, whichever is later. Modified flares that were affected facilities subject to subpart J of this part prior to becoming affected facilities under § 60.100a shall comply with the requirements of paragraph (h) of this section and the requirements of § 60.107a(a)(2) by November 13, 2012 or at startup of the modified flare, whichever is later, except that modified flares that have accepted applicability of subpart J under a federal consent decree shall comply with the subpart J requirements as specified in the consent decree, but shall comply with the requirements of paragraph (h) of this section and the requirements of § 60.107a(a)(2) by no later than November 11, 2015.

              (g) An affected flare subject to this subpart located in the Bay Area Air Quality Management District (BAAQMD) may elect to comply with both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of paragraphs (a) through (e) of this section. An affected flare subject to this subpart located in the South Coast Air Quality Management District (SCAQMD) may elect to comply with SCAQMD Rule 1118 as an alternative to complying with the requirements of paragraphs (a) through (e) of this section. The owner or operator of an affected flare must notify the Administrator that the flare is in compliance with BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 or SCAQMD Rule 1118. The owner or operator of an affected flare shall also submit the existing flare management plan to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov.

              (h) Each owner or operator shall not burn in any affected flare any fuel gas that contains H2S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis. The combustion in a flare of process upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other emergency malfunctions is exempt from this limit.
              (i) Each owner or operator of a delayed coking unit shall depressure each coke drum to 5 lb per square inch gauge (psig) or less prior to discharging the coke drum steam exhaust to the atmosphere. Until the coke drum pressure reaches 5 psig, the coke drum steam exhaust must be managed in an enclosed blowdown system and the uncondensed vapor must either be recovered (e.g., sent to the delayed coking unit fractionators) or vented to the fuel gas system, a fuel gas combustion device or a flare.
              (j) Alternative means of emission limitation. (1) Each owner or operator subject to the provisions of this section may apply to the Administrator for a determination of equivalence for any means of emission limitation that achieves a reduction in emissions of a specified pollutant at least equivalent to the reduction in emissions of that pollutant achieved by the controls required in this section.
              (2) Determination of equivalence to the design, equipment, work practice or operational requirements of this section will be evaluated by the following guidelines:
              (i) Each owner or operator applying for a determination of equivalence shall be responsible for collecting and verifying test data to demonstrate the equivalence of the alternative means of emission limitation.
              (ii) For each affected facility for which a determination of equivalence is requested, the emission reduction achieved by the design, equipment, work practice or operational requirements shall be demonstrated.
              (iii) For each affected facility for which a determination of equivalence is requested, the emission reduction achieved by the alternative means of emission limitation shall be demonstrated.
              (iv) Each owner or operator applying for a determination of equivalence to a work practice standard shall commit in writing to work practice(s) that provide for emission reductions equal to or greater than the emission reductions achieved by the required work practice.
              (v) The Administrator will compare the demonstrated emission reduction for the alternative means of emission limitation to the demonstrated emission reduction for the design, equipment, work practice or operational requirements and, if applicable, will consider the commitment in paragraph (j)(2)(iv) of this section.
              (vi) The Administrator may condition the approval of the alternative means of emission limitation on requirements that may be necessary to ensure operation and maintenance to achieve the same emissions reduction as the design, equipment, work practice or operational requirements.
              (3) An owner or operator may offer a unique approach to demonstrate the equivalence of any equivalent means of emission limitation.

              (4) Approval of the application for equivalence to the design, equipment, work practice or operational requirements of this section will be evaluated by the following guidelines:

              (i) After a request for determination of equivalence is received, the Administrator will publish a notice in the Federal Register and provide the opportunity for public hearing if the Administrator judges that the request may be approved.

              (ii) After notice and opportunity for public hearing, the Administrator will determine the equivalence of a means of emission limitation and will publish the determination in the Federal Register.

              (iii) Any equivalent means of emission limitations approved under this section shall constitute a required work practice, equipment, design or operational standard within the meaning of section 111(h)(1) of the CAA.
              (5) Manufacturers of equipment used to control emissions may apply to the Administrator for determination of equivalence for any alternative means of emission limitation that achieves a reduction in emissions achieved by the equipment, design and operational requirements of this section. The Administrator will make an equivalence determination according to the provisions of paragraphs (j)(2) through (4) of this section.
              [77 FR 56467, Sep. 12, 2012]

              § 60.104a
              Performance tests.

              (a) The owner or operator shall conduct a performance test for each FCCU, FCU, sulfur recovery plant and fuel gas combustion device to demonstrate initial compliance with each applicable emissions limit in § 60.102a and conduct a performance test for each flare to demonstrate initial compliance with the H2S concentration requirement in § 60.103a(h) according to the requirements of § 60.8. The notification requirements of § 60.8(d) apply to the initial performance test and to subsequent performance tests required by paragraph (b) of this section (or as required by the Administrator), but does not apply to performance tests conducted for the purpose of obtaining supplemental data because of continuous monitoring system breakdowns, repairs, calibration checks and zero and span adjustments.

              (b) The owner or operator of a FCCU or FCU that elects to monitor control device operating parameters according to the requirements in § 60.105a(b), to use bag leak detectors according to the requirements in § 60.105a(c), or to use COMS according to the requirements in § 60.105a(e) shall conduct a PM performance test at least annually (i.e., once per calendar year, with an interval of at least 8 months but no more than 16 months between annual tests) and furnish the Administrator a written report of the results of each test.
              (c) In conducting the performance tests required by this subpart (or as requested by the Administrator), the owner or operator shall use the test methods in 40 CFR part 60, Appendices A-1 through A-8 or other methods as specified in this section, except as provided in § 60.8(b).

              (d) The owner or operator shall determine compliance with the PM, NOX, SO2, and CO emissions limits in § 60.102a(b) for FCCU and FCU using the following methods and procedures:
              (1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses.
              (2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate.
              (3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.
              (4) Method 5, 5B, or 5F of appendix A-3 to part 60 for determining PM emissions and associated moisture content from a FCCU or FCU without a wet scrubber subject to the emissions limit in § 63.102a(b)(1). Use Method 5 or 5B of appendix A-3 to part 60 for determining PM emissions and associated moisture content from a FCCU or FCU with a wet scrubber subject to the emissions limit in § 63.102a(b)(1).
              (i) The PM performance test consists of 3 valid test runs; the duration of each test run must be no less than 60 minutes.
              (ii) The emissions rate of PM (EPM) is computed for each run using Equation 5 of this section:

                ER12SE12.003

                Where:

                E = Emission rate of PM, g/kg (lb/1,000 lb) of coke burn-off;
                cs = Concentration of total PM, grams per dry standard cubic meter (g/dscm) (gr/dscf);
                Qsd = Volumetric flow rate of effluent gas, dry standard cubic meters per hour (dry standard cubic feet per hour);
                Rc = Coke burn-off rate, kilograms per hour (kg/hr) [lb per hour (lb/hr)] coke; and
                K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).

              (iii) The coke burn-off rate (Rc) is computed for each run using Equation 6 of this section:

                ER12SE12.004

                Where:

                Rc = Coke burn-off rate, kg/hr (lb/hr);
                Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emissions control or energy recovery system that burns auxiliary fuel, dry standard cubic meters per minute (dscm/min) [dry standard cubic feet per minute (dscf/min)];
                Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
                Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
                %CO2 = Carbon dioxide (CO2) concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
                %CO = CO concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
                %O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
                %Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis);
                K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];
                K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and
                K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].

              (iv) During the performance test, the volumetric flow rate of exhaust gas from catalyst regenerator (Qr) before any emission control or energy recovery system that burns auxiliary fuel is measured using Method 2 of appendix A-1 to part 60.

              (v) For subsequent calculations of coke burn-off rates or exhaust gas flow rates, the volumetric flow rate of Qr is calculated using average exhaust gas concentrations as measured by the monitors required in § 60.105a(b)(2), if applicable, using Equation 7 of this section:

                ER12SE12.005

                Where:

                Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emission control or energy recovery system that burns auxiliary fuel, dscm/min (dscf/min);
                Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
                Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
                %CO2 = Carbon dioxide concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
                %CO = CO concentration FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis). When no auxiliary fuel is burned and a continuous CO monitor is not required in accordance with § 60.105a(h)(3), assume %CO to be zero;
                %O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); and
                %Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis).

              (5) Method 6, 6A, or 6C of appendix A-4 to part 60 for moisture content and for the concentration of SO2; the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.

              (6) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the concentration of NOX calculated as nitrogen dioxide (NO2); the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.
              (7) Method 10, 10A, or 10B of appendix A-4 to part 60 for moisture content and for the concentration of CO. The sampling time for each run must be 60 minutes.
              (8) The owner or operator shall adjust PM, NOX, SO2 and CO pollutant concentrations to 0-percent excess air or 0-percent O2 using Equation 8 of this section:

                ER12SE12.006

                Where:

                Cadj = pollutant concentration adjusted to 0-percent excess air or O2, parts per million (ppm) or g/dscm;
                Cmeas = pollutant concentration measured on a dry basis, ppm or g/dscm;
                20.9c = 20.9 percent O2−0.0 percent O2 (defined O2 correction basis), percent;
                20.9 = O2 concentration in air, percent; and
                %O2 = O2 concentration measured on a dry basis, percent.

              (e) The owner or operator of a FCCU or FCU that is controlled by an electrostatic precipitator or wet scrubber and that is subject to control device operating parameter limits in § 60.102a(c) shall establish the limits based on the performance test results according to the following procedures:
              (1) Reduce the parameter monitoring data to hourly averages for each test run;
              (2) Determine the hourly average operating limit for each required parameter as the average of the three test runs.
              (f) The owner or operator of an FCCU or FCU that uses cyclones to comply with the PM per coke burn-off emissions limit in § 60.102a(b)(1) shall establish a site-specific opacity operating limit according to the procedures in paragraphs (f)(1) through (3) of this section.
              (1) Collect COMS data every 10 seconds during the entire period of the PM performance test and reduce the data to 6-minute averages.
              (2) Determine and record the hourly average opacity from all the 6-minute averages.
              (3) Compute the site-specific limit using Equation 9 of this section:

                ER12SE12.007

                Where:

                Opacity limit = Maximum permissible 3-hour average opacity, percent, or 10 percent, whichever is greater;
                Opacityst = Hourly average opacity measured during the source test, percent; and
                PMEmRst = PM emission rate measured during the source test, lb/1,000 lb coke burn.

              (g) The owner or operator of a FCCU or FCU that is exempt from the requirement to install and operate a CO CEMS pursuant to § 60.105a(h)(3) and that is subject to control device operating parameter limits in § 60.102a(c) shall establish the limits based on the performance test results using the procedures in paragraphs (g)(1) and (2) of this section.
              (1) Reduce the temperature and O2 concentrations from the parameter monitoring systems to hourly averages for each test run.

              (2) Determine the operating limit for temperature and O2 concentrations as the average of the average temperature and O2 concentration for the three test runs.

              (h) The owner or operator shall determine compliance with the SO2 emissions limits for sulfur recovery plants in § 60.102a(f)(1)(i) and (f)(2)(i) and the reduced sulfur compounds and H2S emissions limits for sulfur recovery plants in § 60.102a(f)(1)(ii), (f)(1)(iii), (f)(2)(ii), and (f)(2)(iii) using the following methods and procedures:
              (1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses.
              (2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate.
              (3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

              (4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 concentration. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.

              (5) Method 15 or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 to determine the reduced sulfur compounds and H2S concentrations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.
              (i) Each run consists of 16 samples taken over a minimum of 3 hours.

              (ii) The owner or operator shall calculate the average H2S concentration after correcting for moisture and O2 as the arithmetic average of the H2S concentration for each sample during the run (ppmv, dry basis, corrected to 0 percent excess air).
              (iii) The owner or operator shall calculate the SO2 equivalent for each run after correcting for moisture and O2 as the arithmetic average of the SO2 equivalent of reduced sulfur compounds for each sample during the run (ppmv, dry basis, corrected to 0 percent excess air).

              (iv) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 0-percent O2 or 0- percent excess air.

              (6) If oxygen or oxygen-enriched air is used in the Claus burner and either Equation 1 or 2 of this subpart is used to determine the applicable emissions limit, determine the average O2 concentration of the air/oxygen mixture supplied to the Claus burner, in percent by volume (dry basis), for the performance test using all hourly average O2 concentrations determined during the test runs using the procedures in § 60.106a(a)(5) or (6).

              (i) The owner or operator shall determine compliance with the SO2 and NOX emissions limits in § 60.102a(g) for a fuel gas combustion device according to the following test methods and procedures:

              (1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses;

              (2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate;
              (3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60;

              (4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 concentration. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.
              (i) The performance test consists of 3 valid test runs; the duration of each test run must be no less than 1 hour.
              (ii) If a single fuel gas combustion device having a common source of fuel gas is monitored as allowed under § 60.107a(a)(1)(v), only one performance test is required. That is, performance tests are not required when a new affected fuel gas combustion device is added to a common source of fuel gas that previously demonstrated compliance.

              (5) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the concentration of NOX calculated as NO2; the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.

              (6) For process heaters with a rated heat capacity between 40 and 100 MMBtu/hr that elect to demonstrate continuous compliance with a maximum excess oxygen limit as provided in § 60.107a(c)(6) or (d)(8), the owner or operator shall establish the O2 operating limit or O2 operating curve based on the performance test results according to the requirements in paragraph (i)(6)(i) or (ii) of this section, respectively.
              (i) If a single O2 operating limit will be used:
              (A) Conduct the performance test following the methods provided in paragraphs (i)(1), (2), (3) and (5) of this section when the process heater is firing at no less than 70 percent of the rated heat capacity. For co-fired process heaters, conduct at least one of the test runs while the process heater is being supplied by both fuel gas and fuel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas.

              (B) Each test will consist of three test runs. Calculate the NOX concentration for the performance test as the average of the NOX concentrations from each of the three test runs. If the NOX concentration for the performance test is less than or equal to the numerical value of the applicable NOX emissions limit (regardless of averaging time), then the test is considered to be a valid test.
              (C) Determine the average O2 concentration for each test run of a valid test.
              (D) Calculate the O2 operating limit as the average O2 concentration of the three test runs from a valid test.
              (ii) If an O2 operating curve will be used:

              (A) Conduct a performance test following the methods provided in paragraphs (i)(1), (2), (3) and (5) of this section at a representative condition for each operating range for which different O2 operating limits will be established. Different operating conditions may be defined as different firing rates (e.g., above 50 percent of rated heat capacity and at or below 50 percent of rated heat capacity) and/or, for co-fired process heaters, different fuel mixtures (e.g., primarily gas fired, primarily oil fired, and equally co-fired, i.e., approximately 50 percent of the input heating value is from fuel gas and approximately 50 percent of the input heating value is from fuel oil). Performance tests for different operating ranges may be conducted at different times.

              (B) Each test will consist of three test runs. Calculate the NOX concentration for the performance test as the average of the NOX concentrations from each of the three test runs. If the NOX concentration for the performance test is less than or equal to the numerical value of the applicable NOX emissions limit (regardless of averaging time), then the test is considered to be a valid test.

              (C) If an operating curve is developed for different firing rates, conduct at least one test when the process heater is firing at no less than 70 percent of the rated heat capacity and at least one test under turndown conditions (i.e., when the process heater is firing at 50 percent or less of the rated heat capacity). If O2 operating limits are developed for co-fired process heaters based only on overall firing rates (and not by fuel mixtures), conduct at least one of the test runs for each test while the process heater is being supplied by both fuel gas and fuel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas.
              (D) Determine the average O2 concentration for each test run of a valid test.
              (E) Calculate the O2 operating limit for each operating range as the average O2 concentration of the three test runs from a valid test conducted at the representative conditions for that given operating range.

              (F) Identify the firing rates for which the different operating limits apply. If only two operating limits are established based on firing rates, the O2 operating limits established when the process heater is firing at no less than 70 percent of the rated heat capacity must apply when the process heater is firing above 50 percent of the rated heat capacity and the O2 operating limits established for turndown conditions must apply when the process heater is firing at 50 percent or less of the rated heat capacity.
              (G) Operating limits associated with each interval will be valid for 2 years or until another operating limit is established for that interval based on a more recent performance test specific for that interval, whichever occurs first. Owners and operators must use the operating limits determined for a given interval based on the most recent performance test conducted for that interval.

              (7) The owner or operator of a process heater complying with a NOX limit in terms of lb/MMBtu as provided in § 60.102a(g)(2)(i)(B), (g)(2)(ii)(B), (g)(2)(iii)(B) or (g)(2)(iv)(B) or a process heater with a rated heat capacity between 40 and 100 MMBtu/hr that elects to demonstrate continuous compliance with a maximum excess O2 limit, as provided in § 60.107a(c)(6) or (d)(8), shall determine heat input to the process heater in MMBtu/hr during each performance test run by measuring fuel gas flow rate, fuel oil flow rate (as applicable) and heating value content according to the methods provided in § 60.107a(d)(5), (d)(6), and (d)(4) or (d)(7), respectively.

              (8) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 0-percent O2 or 0- percent excess air.

              (j) The owner or operator shall determine compliance with the applicable H2S emissions limit in § 60.102a(g)(1) for a fuel gas combustion device or the concentration requirement in § 60.103a(h) for a flare according to the following test methods and procedures:
              (1)—(3) [Reserved]

              (4) EPA Method 11, 15 or 15A of appendix A-5 to part 60 or EPA Method 16 of appendix A-6 to part 60 for determining the H2S concentration for affected facilities using an H2S monitor as specified in § 60.107a(a)(2). The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. The owner or operator may demonstrate compliance based on the mixture used in the fuel gas combustion device or flare or for each individual fuel gas stream used in the fuel gas combustion device or flare.

              (i) For Method 11 of appendix A-5 to part 60, the sampling time and sample volume must be at least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal sampling times must be taken at about 1-hour intervals. The arithmetic average of these two samples constitutes a run. For most fuel gases, sampling times exceeding 20 minutes may result in depletion of the collection solution, although fuel gases containing low concentrations of H2S may necessitate sampling for longer periods of time.

              (ii) For Method 15 of appendix A-5 to part 60, at least three injects over a 1-hour period constitutes a run.

              (iii) For Method 15A of appendix A-5 to part 60, a 1-hour sample constitutes a run. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.
              (iv) If monitoring is conducted at a single point in a common source of fuel gas as allowed under § 60.107a(a)(2)(iv), only one performance test is required. That is, performance tests are not required when a new affected fuel gas combustion device or flare is added to a common source of fuel gas that previously demonstrated compliance.
              [73 FR 35867, June 24, 2008, as amended at 77 FR 56470, Sep. 12, 2012; 80 FR 75231, Dec. 1, 2015]

              § 60.105a
              Monitoring of emissions and operations for fluid catalytic cracking units (FCCU) and fluid coking units (FCU).
              (a) FCCU and FCU subject to PM emissions limit. Each owner or operator subject to the provisions of this subpart shall monitor each FCCU and FCU subject to the PM emissions limit in § 60.102a(b)(1) according to the requirements in paragraph (b), (c), (d), or (e) of this section.
              (b) Control device operating parameters. Each owner or operator of a FCCU or FCU subject to the PM per coke burn-off emissions limit in § 60.102a(b)(1) that uses a control device other than fabric filter or cyclone shall comply with the requirements in paragraphs (b)(1) and (2) of this section.
              (1) The owner or operator shall install, operate and maintain continuous parameter monitor systems (CPMS) to measure and record operating parameters for each control device according to the applicable requirements in paragraphs (b)(1)(i) through (v) of this section.
              (i) For units controlled using an electrostatic precipitator, the owner or operator shall use CPMS to measure and record the hourly average total power input and secondary current to the entire system.
              (ii) For units controlled using a wet scrubber, the owner or operator shall use CPMS to measure and record the hourly average pressure drop, liquid feed rate, and exhaust gas flow rate. As an alternative to a CPMS, the owner or operator must comply with the requirements in either paragraph (b)(1)(ii)(A) or (B) of this section.

              (A) As an alternative to pressure drop, the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles must conduct a daily check of the air or water pressure to the spray nozzles and record the results of each check. Faulty (e.g., leaking or plugged) air or water lines must be repaired within 12 hours of identification of an abnormal pressure reading.
              (B) As an alternative to exhaust gas flow rate, the owner or operator shall comply with the approved alternative for monitoring exhaust gas flow rate in 40 CFR 63.1573(a) of the National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units.
              (iii) The owner or operator shall install, operate, and maintain each CPMS according to the manufacturer's specifications and requirements.
              (iv) The owner or operator shall determine and record the average coke burn-off rate and hours of operation for each FCCU or FCU using the procedures in § 60.104a(d)(4)(iii).
              (v) If you use a control device other than an electrostatic precipitator, wet scrubber, fabric filter, or cyclone, you may request approval to monitor parameters other than those required in paragraph (b)(1) of this section by submitting an alternative monitoring plan to the Administrator. The request must include the information in paragraphs (b)(1)(v)(A) through (E) of this section.
              (A) A description of each affected facility and the parameter(s) to be monitored to determine whether the affected facility will continuously comply with the emission limitations and an explanation of the criteria used to select the parameter(s).

              (B) A description of the methods and procedures that will be used to demonstrate that the parameter(s) can be used to determine whether the affected facility will continuously comply with the emission limitations and the schedule for this demonstration. The owner or operator must certify that an operating limit will be established for the monitored parameter(s) that represents the conditions in existence when the control device is being properly operated and maintained to meet the emission limitation.
              (C) The frequency and content of the recordkeeping, recording, and reporting, if monitoring and recording are not continuous. The owner or operator also must include the rationale for the proposed monitoring, recording, and reporting requirements.
              (D) Supporting calculations.
              (E) Averaging time for the alternative operating parameter.

              (2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring the concentrations of CO2, O2 (dry basis), and if needed, CO in the exhaust gases prior to any control or energy recovery system that burns auxiliary fuels. A CO monitor is not required for determining coke burn-off rate when no auxiliary fuel is burned and a continuous CO monitor is not required in accordance with paragraph (h)(3) of this section.

              (i) The owner or operator shall install, operate, and maintain each CO2 and O2 monitor according to Performance Specification 3 of appendix B to this part.

              (ii) The owner or operator shall conduct performance evaluations of each CO2 and O2 monitor according to the requirements in § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Method 3, 3A or 3B of appendix A-2 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.
              (iii) If a CO monitor is required, the owner or operator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to this part. If this CO monitor also serves to demonstrate compliance with the CO emissions limit in § 60.102a(b)(4), the span value for this instrument is 1,000 ppm; otherwise, the span value for this instrument should be set at approximately 2 times the typical CO concentration expected in the FCCU of FCU flue gas prior to any emission control or energy recovery system that burns auxiliary fuels.
              (iv) If a CO monitor is required, the owner or operator shall conduct performance evaluations of each CO monitor according to the requirements in § 60.13(c) and Performance Specification 4 of appendix B to this part. The owner or operator shall use Method 10, 10A, or 10B of appendix A-3 to this part for conducting the relative accuracy evaluations.

              (v) The owner or operator shall comply with the quality assurance requirements of procedure 1 of appendix F to this part, including quarterly accuracy determinations for CO2 and CO monitors, annual accuracy determinations for O2 monitors, and daily calibration drift tests.
              (c) Bag leak detection systems. Each owner or operator shall install, operate, and maintain a bag leak detection system for each baghouse or similar fabric filter control device that is used to comply with the PM per coke burn-off emissions limit in § 60.102a(b)(1) for an FCCU or FCU according to paragraph (c)(1) of this section; prepare and operate by a site-specific monitoring plan according to paragraph (c)(2) of this section; take action according to paragraph (c)(3) of this section; and record information according to paragraph (c)(4) of this section.
              (1) Each bag leak detection system must meet the specifications and requirements in paragraphs (c)(1)(i) through (viii) of this section.
              (i) The bag leak detection system must be certified by the manufacturer to be capable of detecting PM emissions at concentrations of 0.00044 grains per actual cubic foot or less.

              (ii) The bag leak detection system sensor must provide output of relative PM loadings. The owner or operator shall continuously record the output from the bag leak detection system using electronic or other means (e.g., using a strip chart recorder or a data logger).
              (iii) The bag leak detection system must be equipped with an alarm system that will sound when the system detects an increase in relative particulate loading over the alarm set point established according to paragraph (c)(1)(iv) of this section, and the alarm must be located such that it can be heard by the appropriate plant personnel.
              (iv) In the initial adjustment of the bag leak detection system, the owner or operator must establish, at a minimum, the baseline output by adjusting the sensitivity (range) and the averaging period of the device, the alarm set points, and the alarm delay time.
              (v) Following initial adjustment, the owner or operator shall not adjust the averaging period, alarm set point, or alarm delay time without approval from the Administrator or delegated authority except as provided in paragraph (c)(1)(vi) of this section.
              (vi) Once per quarter, the owner or operator may adjust the sensitivity of the bag leak detection system to account for seasonal effects, including temperature and humidity, according to the procedures identified in the site-specific monitoring plan required by paragraph (c)(2) of this section.
              (vii) The owner or operator shall install the bag leak detection sensor downstream of the baghouse and upstream of any wet scrubber.
              (viii) Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors.
              (2) The owner or operator shall develop and submit to the Administrator for approval a site-specific monitoring plan for each baghouse and bag leak detection system. The owner or operator shall operate and maintain each baghouse and bag leak detection system according to the site-specific monitoring plan at all times. Each monitoring plan must describe the items in paragraphs (c)(2)(i) through (vii) of this section.
              (i) Installation of the bag leak detection system;
              (ii) Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point will be established;
              (iii) Operation of the bag leak detection system, including quality assurance procedures;
              (iv) How the bag leak detection system will be maintained, including a routine maintenance schedule and spare parts inventory list;
              (v) How the bag leak detection system output will be recorded and stored;
              (vi) Procedures as specified in paragraph (c)(3) of this section. In approving the site-specific monitoring plan, the Administrator or delegated authority may allow owners and operators more than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation of this condition as expeditiously as practicable; and
              (vii) How the baghouse system will be operated and maintained, including monitoring of pressure drop across baghouse cells and frequency of visual inspections of the baghouse interior and baghouse components such as fans and dust removal and bag cleaning mechanisms.
              (3) For each bag leak detection system, the owner or operator shall initiate procedures to determine the cause of every alarm within 1 hour of the alarm. Except as provided in paragraph (c)(2)(vi) of this section, the owner or operator shall alleviate the cause of the alarm within 3 hours of the alarm by taking whatever action(s) are necessary. Actions may include, but are not limited to the following:
              (i) Inspecting the baghouse for air leaks, torn or broken bags or filter media, or any other condition that may cause an increase in particulate emissions;
              (ii) Sealing off defective bags or filter media;
              (iii) Replacing defective bags or filter media or otherwise repairing the control device;

              (iv) Sealing off a defective baghouse compartment;

              (v) Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection system; or
              (vi) Shutting down the process producing the particulate emissions.
              (4) The owner or operator shall maintain records of the information specified in paragraphs (c)(4)(i) through (iii) of this section for each bag leak detection system.
              (i) Records of the bag leak detection system output;
              (ii) Records of bag leak detection system adjustments, including the date and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings; and
              (iii) The date and time of all bag leak detection system alarms, the time that procedures to determine the cause of the alarm were initiated, the cause of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was alleviated, and whether the alarm was alleviated within 3 hours of the alarm.
              (d) Continuous emissions monitoring systems (CEMS). An owner or operator subject to the PM concentration emission limit (in gr/dscf) in § 60.102a(b)(1) for an FCCU or FCU shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration (0 percent excess air) of PM in the exhaust gases prior to release to the atmosphere. The monitor must include an O2 monitor for correcting the data for excess air.
              (1) The owner or operator shall install, operate, and maintain each PM monitor according to Performance Specification 11 of appendix B to part 60. The span value of this PM monitor is 0.08 gr/dscf PM.
              (2) The owner or operator shall conduct performance evaluations of each PM monitor according to the requirements in § 60.13(c) and Performance Specification 11 of appendix B to part 60. The owner or operator shall use EPA Methods 5 or 5I of appendix A-3 to part 60 or Method 17 of appendix A-6 to part 60 for conducting the relative accuracy evaluations.

              (3) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be selected between 10 and 25 percent, inclusive.

              (4) The owner or operator shall conduct performance evaluations of each O2 monitor according to the requirements in § 60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

              (5) The owner or operator shall comply with the quality assurance requirements of Procedure 2 of appendix B to part 60 for each PM CEMS and Procedure 1 of appendix F to part 60 for each O2 monitor, including quarterly accuracy determinations for each PM monitor, annual accuracy determinations for each O2 monitor, and daily calibration drift tests.
              (e) Alternative monitoring option for FCCU and FCU—COMS. Each owner or operator of an FCCU or FCU that uses cyclones to comply with the PM emission limit in § 60.102a(b)(1) shall monitor the opacity of emissions according to the requirements in paragraphs (e)(1) through (3) of this section.
              (1) The owner or operator shall install, operate, and maintain an instrument for continuously monitoring and recording the opacity of emissions from the FCCU or the FCU exhaust vent.
              (2) The owner or operator shall install, operate, and maintain each COMS according to Performance Specification 1 of appendix B to part 60. The instrument shall be spanned at 20 to 60 percent opacity.
              (3) The owner or operator shall conduct performance evaluations of each COMS according to § 60.13(c) and Performance Specification 1 of appendix B to part 60.
              (f) FCCU and FCU subject to NO
                X
                limit. Each owner or operator subject to the NOX emissions limit in § 60.102a(b)(2) for an FCCU or FCU shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis, 0 percent excess air) of NOX
                emissions into the atmosphere. The monitor must include an O2 monitor for correcting the data for excess air.

              (1) The owner or operator shall install, operate, and maintain each NOX monitor according to Performance Specification 2 of appendix B to part 60. The span value of this NOX monitor is 200 ppmv NOX.

              (2) The owner or operator shall conduct performance evaluations of each NOX monitor according to the requirements in § 60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.

              (3) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be selected between 10 and 25 percent, inclusive.

              (4) The owner or operator shall conduct performance evaluations of each O2 monitor according to the requirements in § 60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

              (5) The owner or operator shall comply with the quality assurance requirements of Procedure 1 of appendix F to part 60 for each NOX and O2 monitor, including quarterly accuracy determinations for NOX monitors, annual accuracy determinations for O2 monitors, and daily calibration drift tests.
              (g) FCCU and FCU subject to SO
                2
                limit. The owner or operator subject to the SO2 emissions limit in § 60.102a(b)(3) for an FCCU or an FCU shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis, corrected to 0 percent excess air) of SO2 emissions into the atmosphere. The monitor shall include an O2 monitor for correcting the data for excess air.

              (1) The owner or operator shall install, operate, and maintain each SO2 monitor according to Performance Specification 2 of appendix B to part 60. The span value of this SO2 monitor is 200 ppmv SO2.

              (2) The owner or operator shall conduct performance evaluations of each SO2 monitor according to the requirements in § 60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the relative accuracy evaluations. The method ANSI / ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.

              (3) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be selected between 10 and 25 percent, inclusive.

              (4) The owner or operator shall conduct performance evaluations of each O2 monitor according to the requirements in § 60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

              (5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 of appendix F to part 60 for each SO2 and O2 monitor, including quarterly accuracy determinations for SO2 monitors, annual accuracy determinations for O2 monitors, and daily calibration drift tests.
              (h) FCCU and fluid coking units subject to CO emissions limit. Except as specified in paragraph (h)(3) of this section, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis) of CO emissions into the atmosphere from each FCCU and FCU subject to the CO emissions limit in § 60.102a(b)(4).
              (1) The owner or operator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to this part. The span value for this instrument is 1,000 ppmv CO.
              (2) The owner or operator shall conduct performance evaluations of each CO monitor according to the requirements in § 60.13(c) and Performance Specification 4 or 4A of appendix B to part 60. The owner or operator shall use Methods 10, 10A, or 10B of appendix A-4 to part 60 for conducting the relative accuracy evaluations.
              (3) A CO CEMS need not be installed if the owner or operator demonstrates that all hourly average CO emissions are and will remain less than 50 ppmv (dry basis) corrected to 0 percent excess air. The Administrator may revoke this exemption from monitoring upon a determination that CO emissions on an hourly average basis have exceeded 50 ppmv (dry basis) corrected to 0 percent excess air, in which case a CO CEMS shall be installed within 180 days.
              (i) The demonstration shall consist of continuously monitoring CO emissions for 30 days using an instrument that meets the requirements of Performance Specification 4 or 4A of appendix B to this part. The span value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative accuracy limit shall be 10 percent of the average CO emissions or 5 ppmv CO, whichever is greater. For instruments that are identical to Method 10 of appendix A-4 to this part and employ the sample conditioning system of Method 10A of appendix A-4 to this part, the alternative relative accuracy test procedure in section 10.1 of Performance Specification 2 of appendix B to this part may be used in place of the relative accuracy test.
              (ii) The owner or operator must submit the following information to the Administrator:
              (A) The measurement data specified in paragraph (h)(3)(i) of this section along with all other operating data known to affect CO emissions; and

              (B) Descriptions of the CPMS for exhaust gas temperature and O2 monitor required in paragraph (h)(4) of this section and operating limits for those parameters to ensure combustion conditions remain similar to those that exist during the demonstration period.
              (iii) The effective date of the exemption from installation and operation of a CO CEMS is the date of submission of the information and data required in paragraph (h)(3)(ii) of this section.
              (4) The owner or operator of a FCCU or FCU that is exempted from the requirement to install and operate a CO CEMS in paragraph (h)(3) of this section shall install, operate, calibrate, and maintain CPMS to measure and record the operating parameters in paragraph (h)(4)(i) or (ii) of this section. The owner or operator shall install, operate, and maintain each CPMS according to the manufacturer's specifications.

              (i) For a FCCU or FCU with no post-combustion control device, the temperature and O2 concentration of the exhaust gas stream exiting the unit.

              (ii) For a FCCU or FCU with a post-combustion control device, the temperature and O2 concentration of the exhaust gas stream exiting the control device.
              (i) Excess emissions. For the purpose of reports required by § 60.7(c), periods of excess emissions for a FCCU or FCU subject to the emissions limitations in § 60.102a(b) are defined as specified in paragraphs (i)(1) through (6) of this section. Note: Determine all averages, except for opacity, as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 3-hour average as the arithmetic average of three contiguous 1-hour averages.

              (1) If a CPMS is used according to paragraph (b)(1) of this section, all 3-hour periods during which the average PM control device operating characteristics, as measured by the continuous monitoring systems under paragraph (b)(1), fall below the levels established during the performance test. If the alternative to pressure drop CPMS is used for the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, each day in which abnormal pressure readings are not corrected within 12 hours of identification.
              (2) If a bag leak detection system is used according to paragraph (c) of this section, each day in which the cause of an alarm is not alleviated within the time period specified in paragraph (c)(3) of this section.
              (3) If a PM CEMS is used according to § 60.105a(d), all 7-day periods during which the average PM emission rate, as measured by the continuous PM monitoring system under § 60.105a(d) exceeds 0.040 gr/dscf corrected to 0 percent excess air for a modified or reconstructed FCCU, 0.020 gr/dscf corrected to 0 percent excess air for a newly constructed FCCU, or 0.040 gr/dscf for an affected fluid coking unit.
              (4) If a COMS is used according to § 60.105a(e), all 3-hour periods during which the average opacity, as measured by the COMS under § 60.105a(e), exceeds the site-specific limit established during the most recent performance test.

              (5) All rolling 7-day periods during which the average concentration of NOX as measured by the NOX CEMS under § 60.105a(f) exceeds 80 ppmv for an affected FCCU or FCU.

              (6) All rolling 7-day periods during which the average concentration of SO2 as measured by the SO2 CEMS under § 60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which the average concentration of SO2 as measured by the SO2 CEMS exceeds 25 ppmv.

              (7) All 1-hour periods during which the average CO concentration as measured by the CO continuous monitoring system under paragraph (h) of this section exceeds 500 ppmv or, if applicable, all 1-hour periods during which the average temperature and O2 concentration as measured by the continuous monitoring systems under paragraph (h)(4) of this section fall below the operating limits established during the performance test.
              [73 FR 35867, June 24, 2008, as amended at 77 FR 56473, Sep. 12, 2012; 80 FR 75232, Dec. 1, 2015; 83 FR 60713, Nov. 26, 2018]

              § 60.106a
              Monitoring of emissions and operations for sulfur recovery plants.
              (a) The owner or operator of a sulfur recovery plant that is subject to the emissions limits in § 60.102a(f)(1) or § 60.102a(f)(2) shall:
              (1) For sulfur recovery plants subject to the SO2 emission limit in § 60.102a(f)(1)(i) or § 60.102a(f)(2)(i), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of any SO2 emissions into the atmosphere. The monitor shall include an oxygen monitor for correcting the data for excess air.
              (i) The span value for the SO2 monitor is two times the applicable SO2 emission limit at the highest O2 concentration in the air/oxygen stream used in the Claus burner, if applicable.

              (ii) The owner or operator shall install, operate, and maintain each SO2 CEMS according to Performance Specification 2 of appendix B to part 60.

              (iii) The owner or operator shall conduct performance evaluations of each SO2 monitor according to the requirements in § 60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Method 6 or 6C of appendix A-4 to part 60. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6.

              (iv) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to this part.
              (v) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive.

              (vi) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to this part.

              (vii) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O2 monitor, and daily calibration drift determinations.

              (2) For sulfur recovery plants that are subject to the reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or (f)(2)(ii), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of reduced sulfur compounds and O2 emissions into the atmosphere. The reduced sulfur compounds emissions shall be calculated as SO2 (dry basis, zero percent excess air).

              (i) The span value for the reduced sulfur compounds monitor is two times the applicable reduced sulfur compounds emission limit as SO2 at the highest O2 concentration in the air/oxygen stream used in the Claus burner, if applicable.
              (ii) The owner or operator shall install, operate, and maintain each reduced sulfur compounds CEMS according to Performance Specification 5 of appendix B to this part.
              (iii) The owner or operator shall conduct performance evaluations of each reduced sulfur compounds monitor according to the requirements in § 60.13(c) and Performance Specification 5 of appendix B to this part. The owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.

              (iv) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to part 60.
              (v) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive.

              (vi) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

              (vii) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, including annual accuracy determinations for each O2 monitor, and daily calibration drift determinations.

              (3) In place of the reduced sulfur compounds monitor required in paragraph (a)(2) of this section, the owner or operator may install, calibrate, operate, and maintain an instrument using an air or O2 dilution and oxidation system to convert any reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis, 0 percent excess air) of the total resultant SO2. The monitor must include an O2 monitor for correcting the data for excess O2.

              (i) The span value for this monitor is two times the applicable reduced sulfur compounds emission limit as SO2 at the highest O2 concentration in the air/oxygen stream used in the Claus burner, if applicable.

              (ii) The owner or operator shall conduct performance evaluations of each SO2 monitor according to the requirements in § 60.13(c) and Performance Specification 5 of appendix B to part 60. The owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.

              (iii) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to part 60.
              (iv) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive.

              (v) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

              (vi) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to part 60 for each monitor, including quarterly accuracy determinations for each SO2 monitor, annual accuracy determinations for each O2 monitor, and daily calibration drift determinations.

              (4) For sulfur recovery plants that are subject to the H2S emission limit in § 60.102a(f)(1)(iii) or (f)(2)(iii), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of H2S, and O2 emissions into the atmosphere. The H2S emissions shall be calculated as SO2 (dry basis, zero percent excess air).

              (i) The span value for this monitor is two times the applicable H2S emission limit.

              (ii) The owner or operator shall install, operate, and maintain each H2S CEMS according to Performance Specification 7 of appendix B to this part.

              (iii) The owner or operator shall conduct performance evaluations for each H2S monitor according to the requirements of § 60.13(c) and Performance Specification 7 of appendix B to this part. The owner or operator shall use Methods 11 or 15 of appendix A-5 to this part or Method 16 of appendix A-6 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to this part.

              (iv) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to this part.
              (v) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive.

              (vi) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to this part.

              (vii) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O2 monitor, and daily calibration drift determinations.

              (5) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner and that elects to monitor O2 concentration of the air/oxygen mixture supplied to the Claus burner, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the O2 concentration of the air/oxygen mixture supplied to the Claus burner in order to determine the allowable emissions limit.

              (i) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to this part.
              (ii) The span value for the O2 monitor shall be 100 percent.

              (iii) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to this part.

              (iv) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O2 monitor, and daily calibration drift determinations.

              (v) The owner or operator shall use the hourly average O2 concentration from this monitor for use in Equation 1 or 2 of § 60.102a(f), as applicable, for each hour and determine the allowable emission limit as the arithmetic average of 12 contiguous 1-hour averages (i.e., the rolling 12-hour average).
              (6) As an alternative to the O2 monitor required in paragraph (a)(5) of this section, the owner or operator may install, calibrate, operate, and maintain a CPMS to measure and record the volumetric gas flow rate of ambient air and oxygen-enriched gas supplied to the Claus burner and calculate the hourly average O2 concentration of the air/oxygen mixture used in the Claus burner as specified in paragraphs (a)(6)(i) through (iv) of this section in order to determine the allowable emissions limit as specified in paragraphs (a)(6)(v) of this section.
              (i) The owner or operator shall install, calibrate, operate and maintain each flow monitor according to the manufacturer's procedures and specifications and the following requirements.
              (A) Locate the monitor in a position that provides a representative measurement of the total gas flow rate.
              (B) Use a flow sensor meeting an accuracy requirement of ±5 percent over the normal range of flow measured or 10 cubic feet per minute, whichever is greater.
              (C) Use a flow monitor that is maintainable online, is able to continuously correct for temperature, pressure and, for ambient air flow monitor, moisture content, and is able to record dry flow in standard conditions (as defined in § 60.2) over one-minute averages.
              (D) At least quarterly, perform a visual inspection of all components of the monitor for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor.
              (E) Recalibrate the flow monitor in accordance with the manufacturer's procedures and specifications biennially (every two years) or at the frequency specified by the manufacturer.
              (ii) The owner or operator shall use 20.9 percent as the oxygen content of the ambient air.

              (iii) The owner or operator shall use product specifications (e.g., as reported in material safety data sheets) for percent oxygen for purchased oxygen. For oxygen produced onsite, the percent oxygen shall be determined by periodic measurements or process knowledge.

              (iv) The owner or operator shall calculate the hourly average O2 concentration of the air/oxygen mixture used in the Claus burner using Equation 10 of this section:

                ER01DE15.002

                Where:

                %O2 = O2 concentration of the air/oxygen mixture used in the Claus burner, percent by volume (dry basis);
                20.9 = O2 concentration in air, percent dry basis;
                Qair = Volumetric flow rate of ambient air used in the Claus burner, dscfm;
                %O2,oxy = O2 concentration in the enriched oxygen stream, percent dry basis; and
                Qoxy = Volumetric flow rate of enriched oxygen stream used in the Claus burner, dscfm.

              (v) The owner or operator shall use the hourly average O2 concentration determined using Equation 8 of § 60.104a(d)(8) for use in Equation 1 or 2 of § 60.102a(f), as applicable, for each hour and determine the allowable emission limit as the arithmetic average of 12 contiguous 1-hour averages (i.e., the rolling 12-hour average).

              (7) Owners or operators of a sulfur recovery plant that elects to comply with the SO2 emission limit in § 60.102a(f)(1)(i) or (f)(2)(i) or the reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or (f)(2)(ii) as a flow rate weighted average for a group of release points from the sulfur recovery plant rather than for each process train or release point individually shall install, calibrate, operate, and maintain a CPMS to measure and record the volumetric gas flow rate of each release point within the group of release points from the sulfur recovery plant as specified in paragraphs (a)(7)(i) through (iv) of this section.
              (i) The owner or operator shall install, calibrate, operate and maintain each flow monitor according to the manufacturer's procedures and specifications and the following requirements.
              (A) Locate the monitor in a position that provides a representative measurement of the total gas flow rate.
              (B) Use a flow sensor meeting an accuracy requirement of ±5 percent over the normal range of flow measured or 10 cubic feet per minute, whichever is greater.
              (C) Use a flow monitor that is maintainable online, is able to continuously correct for temperature, pressure, and moisture content, and is able to record dry flow in standard conditions (as defined in § 60.2) over one-minute averages.
              (D) At least quarterly, perform a visual inspection of all components of the monitor for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor.
              (E) Recalibrate the flow monitor in accordance with the manufacturer's procedures and specifications biennially (every two years) or at the frequency specified by the manufacturer.
              (ii) The owner or operator shall correct the flow to 0 percent excess air using Equation 11 of this section:

                ER01DE15.003

                Where:

                Qadj = Volumetric flow rate adjusted to 0 percent excess air, dry standard cubic feet per minute (dscfm);
                Cmeas = Volumetric flow rate measured by the flow meter corrected to dry standard conditions, dscfm;
                20.9c = 20.9 percent O2−0.0 percent O2 (defined O2 correction basis), percent;
                20.9 = O2 concentration in air, percent; and
                %O2 = O2 concentration measured on a dry basis, percent.

              (iii) The owner or operator shall calculate the flow weighted average SO2 or reduced sulfur compounds concentration for each hour using Equation 12 of this section:

                ER01DE15.004

                Where:

                Cave = Flow weighted average concentration of the pollutant, ppmv (dry basis, zero percent excess air). The pollutant is either SO2 (if complying with the SO2 emission limit in § 60.102a(f)(1)(i) or (f)(2)(i)) or reduced sulfur compounds (if complying with the reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or (f)(2)(ii));
                N = Number of release points within the group of release points from the sulfur recovery plant for which emissions averaging is elected;
                Cn = Pollutant concentration in the nth release point within the group of release points from the sulfur recovery plant for which emissions averaging is elected, ppmv (dry basis, zero percent excess air);
                Qadj,n = Volumetric flow rate of the nth release point within the group of release points from the sulfur recovery plant for which emissions averaging is elected, dry standard cubic feet per minute (dscfm, adjusted to 0 percent excess air).

              (iv) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner, the owner or operator shall use Equation 10 of this section and the hourly emission limits determined in paragraph (a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant concentration to determine the flow weighted average hourly emission limit for each hour. The allowable emission limit shall be calculated as the arithmetic average of 12 contiguous 1-hour averages (i.e., the rolling 12-hour average).
              (b) Excess emissions. For the purpose of reports required by § 60.7(c), periods of excess emissions for sulfur recovery plants subject to the emissions limitations in § 60.102a(f) are defined as specified in paragraphs (b)(1) through (3) of this section.

                Note:
                Determine all averages as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 12-hour average as the arithmetic average of 12 contiguous 1-hour averages.

              (1) All 12-hour periods during which the average concentration of SO2 as measured by the SO2 continuous monitoring system required under paragraph (a)(1) of this section exceeds the applicable emission limit (dry basis, zero percent excess air); or

              (2) All 12-hour periods during which the average concentration of reduced sulfur compounds (as SO2) as measured by the reduced sulfur compounds continuous monitoring system required under paragraph (a)(2) or (3) of this section exceeds the applicable emission limit; or

              (3) All 12-hour periods during which the average concentration of H2S as measured by the H2S continuous monitoring system required under paragraph (a)(4) of this section exceeds the applicable emission limit (dry basis, 0 percent excess air).
              [73 FR 35867, June 24, 2008, as amended at 80 FR 75232, Dec. 1, 2015; 83 FR 60713, Nov. 26, 2018]

              § 60.107a
              Monitoring of emissions and operations for fuel gas combustion devices and flares.
              (a) Fuel gas combustion devices subject to SO2 or H2S limit and flares subject to H2S concentration requirements. The owner or operator of a fuel gas combustion device that is subject to § 60.102a(g)(1) and elects to comply with the SO2 emission limits in § 60.102a(g)(1)(i) shall comply with the requirements in paragraph (a)(1) of this section. The owner or operator of a fuel gas combustion device that is subject to § 60.102a(g)(1) and elects to comply with the H2S concentration limits in § 60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration requirement in § 60.103a(h) shall comply with paragraph (a)(2) of this section.

              (1) The owner or operator of a fuel gas combustion device that elects to comply with the SO2 emissions limits in § 60.102a(g)(1)(i) shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of SO2 emissions into the atmosphere. The monitor must include an O2 monitor for correcting the data for excess air.

              (i) The owner or operator shall install, operate, and maintain each SO2 monitor according to Performance Specification 2 of appendix B to this part. The span value for the SO2 monitor is 50 ppmv SO2.

              (ii) The owner or operator shall conduct performance evaluations for the SO2 monitor according to the requirements of § 60.13(c) and Performance Specification 2 of appendix B to this part. The owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to this part. Samples taken by Method 6 of appendix A-4 to this part shall be taken at a flow rate of approximately 2 liters/min for at least 30 minutes. The relative accuracy limit shall be 20 percent or 4 ppmv, whichever is greater, and the calibration drift limit shall be 5 percent of the established span value.

              (iii) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to part 60. The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive.

              (iv) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

              (v) The owner or operator shall comply with the applicable quality assurance procedures in appendix F to part 60, including quarterly accuracy determinations for SO2 monitors, annual accuracy determinations for O2 monitors, and daily calibration drift tests.

              (vi) Fuel gas combustion devices having a common source of fuel gas may be monitored at only one location (i.e., after one of the combustion devices), if monitoring at this location accurately represents the SO2 emissions into the atmosphere from each of the combustion devices.

              (2) The owner or operator of a fuel gas combustion device that elects to comply with the H2S concentration limits in § 60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration requirement in § 60.103a(h) shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration by volume (dry basis) of H2S in the fuel gases before being burned in any fuel gas combustion device or flare.

              (i) The owner or operator shall install, operate and maintain each H2S monitor according to Performance Specification 7 of appendix B to part 60. The span value for this instrument is 300 ppmv H2S.

              (ii) The owner or operator shall conduct performance evaluations for each H2S monitor according to the requirements of § 60.13(c) and Performance Specification 7 of appendix B to part 60. The owner or operator shall use Method 11, 15, or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.

              (iii) The owner or operator shall comply with the applicable quality assurance procedures in appendix F to part 60 for each H2S monitor.

              (iv) Fuel gas combustion devices or flares having a common source of fuel gas may be monitored at only one location, if monitoring at this location accurately represents the concentration of H2S in the fuel gas being burned in the respective fuel gas combustion devices or flares.

              (v) The owner or operator of a flare subject to § 60.103a(c) through (e) may use the instrument required in paragraph (e)(1) of this section to demonstrate compliance with the H2S concentration requirement in § 60.103a(h) if the owner or operator complies with the requirements of paragraph (e)(1)(i) through (iv) and if the instrument has a span (or dual span, if necessary) capable of accurately measuring concentrations between 20 and 300 ppmv. If the instrument required in paragraph (e)(1) of this section is used to demonstrate compliance with the H2S concentration requirement, the concentration directly measured by the instrument must meet the numeric concentration in § 60.103a(h).
              (vi) The owner or operator of modified flare that meets all three criteria in paragraphs (a)(2)(vi)(A) through (C) of this section shall comply with the requirements of paragraphs (a)(2)(i) through (v) of this section no later than November 11, 2015. The owner or operator shall comply with the approved alternative monitoring plan or plans pursuant to § 60.13(i) until the flare is in compliance with requirements of paragraphs (a)(2)(i) through (v) of this section.

              (A) The flare was an affected facility subject to subpart J of this part prior to becoming an affected facility under § 60.100a.

              (B) The owner or operator had an approved alternative monitoring plan or plans pursuant to § 60.13(i) for all fuel gases combusted in the flare.

              (C) The flare did not have in place on or before September 12, 2012 an instrument for continuously monitoring and recording the concentration by volume (dry basis) of H2S in the fuel gases that is capable of complying with the requirements of paragraphs (a)(2)(i) through (v) of this section.
              (3) The owner or operator of a fuel gas combustion device or flare is not required to comply with paragraph (a)(1) or (2) of this section for fuel gas streams that are exempt under §§ 60.102a(g)(1)(iii) or 60.103a(h) or, for fuel gas streams combusted in a process heater, other fuel gas combustion device or flare that are inherently low in sulfur content. Fuel gas streams meeting one of the requirements in paragraphs (a)(3)(i) through (iv) of this section will be considered inherently low in sulfur content.
              (i) Pilot gas for heaters and flares.
              (ii) Fuel gas streams that meet a commercial-grade product specification for sulfur content of 30 ppmv or less. In the case of a liquefied petroleum gas (LPG) product specification in the pressurized liquid state, the gas phase sulfur content should be evaluated assuming complete vaporization of the LPG and sulfur containing-compounds at the product specification concentration.
              (iii) Fuel gas streams produced in process units that are intolerant to sulfur contamination, such as fuel gas streams produced in the hydrogen plant, catalytic reforming unit, isomerization unit, and HF alkylation process units.
              (iv) Other fuel gas streams that an owner or operator demonstrates are low-sulfur according to the procedures in paragraph (b) of this section.
              (4) If the composition of an exempt fuel gas stream changes, the owner or operator must follow the procedures in paragraph (b)(3) of this section.
              (b) Exemption from H
                2
                S monitoring requirements for low-sulfur fuel gas streams. The owner or operator of a fuel gas combustion device or flare may apply for an exemption from the H2S monitoring requirements in paragraph (a)(2) of this section for a fuel gas stream that is inherently low in sulfur content. A fuel gas stream that is demonstrated to be low-sulfur is exempt from the monitoring requirements of paragraphs (a)(1) and (2) of this section until there are changes in operating conditions or stream composition.
              (1) The owner or operator shall submit to the Administrator a written application for an exemption from monitoring. The application must contain the following information:
              (i) A description of the fuel gas stream/system to be considered, including submission of a portion of the appropriate piping diagrams indicating the boundaries of the fuel gas stream/system and the affected fuel gas combustion device(s) or flare(s) to be considered;

              (ii) A statement that there are no crossover or entry points for sour gas (high H2S content) to be introduced into the fuel gas stream/system (this should be shown in the piping diagrams);
              (iii) An explanation of the conditions that ensure low amounts of sulfur in the fuel gas stream (i.e., control equipment or product specifications) at all times;

              (iv) The supporting test results from sampling the requested fuel gas stream/system demonstrating that the sulfur content is less than 5 ppmv H2S. Sampling data must include, at minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be collected unless other additional information would support reduced sampling. The owner or operator shall use detector tubes (“length-of-stain tube” type measurement) following the “Gas Processors Association Standard 2377-86 (incorporated by reference—see § 60.17), using tubes with a maximum span between 10 and 40 ppmv inclusive when 1≤N≤10, where N = number of pump strokes, to test the applicant fuel gas stream for H2S; and

              (v) A description of how the 2 weeks (or seven samples for infrequently operated fuel gas streams/systems) of monitoring results compares to the typical range of H2S concentration (fuel quality) expected for the fuel gas stream/system going to the affected fuel gas combustion device or flare (e.g., the 2 weeks of daily detector tube results for a frequently operated loading rack included the entire range of products loaded out and, therefore, should be representative of typical operating conditions affecting H2S content in the fuel gas stream going to the loading rack flare).
              (2) The effective date of the exemption is the date of submission of the information required in paragraph (b)(1) of this section.
              (3) No further action is required unless refinery operating conditions change in such a way that affects the exempt fuel gas stream/system (e.g., the stream composition changes). If such a change occurs, the owner or operator shall follow the procedures in paragraph (b)(3)(i), (b)(3)(ii), or (b)(3)(iii) of this section.

              (i) If the operation change results in a sulfur content that is still within the range of concentrations included in the original application, the owner or operator shall conduct an H2S test on a grab sample and record the results as proof that the concentration is still within the range.
              (ii) If the operation change results in a sulfur content that is outside the range of concentrations included in the original application, the owner or operator may submit new information following the procedures of paragraph (b)(1) of this section within 60 days (or within 30 days after the seventh grab sample is tested for infrequently operated process units).

              (iii) If the operation change results in a sulfur content that is outside the range of concentrations included in the original application and the owner or operator chooses not to submit new information to support an exemption, the owner or operator must begin H2S monitoring using daily stain sampling to demonstrate compliance using length-of-stain tubes with a maximum span between 200 and 400 ppmv inclusive when 1≤N≤5, where N = number of pump strokes. The owner or operator must begin monitoring according to the requirements in paragraphs (a)(1) or (a)(2) of this section as soon as practicable, but in no case later than 180 days after the operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv is an exceedance of the 3-hour H2S concentration limit. The owner or operator of a fuel gas combustion device must also determine a rolling 365-day average using the stain sampling results; an average H2S concentration of 5 ppmv must be used for days within the rolling 365-day period prior to the operation change.
              (c) Process heaters complying with the NO
                X
                concentration-based limit. The owner or operator of a process heater subject to the NOX emissions limit in § 60.102a(g)(2) and electing to comply with the applicable emissions limit in § 60.102a(g)(2)(i)(A), (g)(2)(ii)(A), (g)(2)(iii)(A) or (g)(2)(iv)(A) shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of NOX emissions into the atmosphere according to the requirements in paragraphs (c)(1) through (5) of this section, except as provided in paragraph (c)(6) of this section. The monitor must include an O2 monitor for correcting the data for excess air.

              (1) Except as provided in paragraph (c)(6) of this section, the owner or operator shall install, operate and maintain each NOX monitor according to Performance Specification 2 of appendix B to part 60. The span value of this NOX monitor must be between 2 and 3 times the applicable emissions limit, inclusive.

              (2) The owner or operator shall conduct performance evaluations of each NOX monitor according to the requirements in § 60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.

              (3) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be selected between 10 and 25 percent, inclusive.

              (4) The owner or operator shall conduct performance evaluations of each O2 monitor according to the requirements in § 60.13(c) and Performance Specification 3 of appendix B to part 60. Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

              (5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 of appendix F to part 60 for each NOX and O2 monitor, including quarterly accuracy determinations for NOX monitors, annual accuracy determinations for O2 monitors, and daily calibration drift tests.

              (6) The owner or operator of a process heater that has a rated heating capacity of less than 100 MMBtu and is equipped with combustion modification-based technology to reduce NOX emissions (i.e., low-NOX burners, ultra-low-NOX burners) may elect to comply with the monitoring requirements in paragraphs (c)(1) through (5) of this section or, alternatively, the owner or operator of such a process heater shall conduct biennial performance tests according to the requirements in § 60.104a(i), establish a maximum excess O2 operating limit or operating curve according to the requirements in § 60.104a(i)(6) and comply with the O2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O2 operating curve is used (i.e., if different O2 operating limits are established for different operating ranges), the owner or operator of the process heater must also monitor fuel gas flow rate, fuel oil flow rate (as applicable) and heating value content according to the methods provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section, respectively.
              (d) Process heaters complying with the NO
                X
                heating value-based or mass-based limit. The owner or operator of a process heater subject to the NOX emissions limit in § 60.102a(g)(2) and electing to comply with the applicable emissions limit in § 60.102a(g)(2)(i)(B) or (g)(2)(ii)(B) shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of NOX emissions into the atmosphere and shall determine the F factor of the fuel gas stream no less frequently than once per day according to the monitoring requirements in paragraphs (d)(1) through (4) of this section. The owner or operator of a co-fired process heater subject to the NOX emissions limit in § 60.102a(g)(2) and electing to comply with the heating value-based limit in § 60.102a(g)(2)(iii)(B) or (g)(2)(iv)(B) shall install, operate, calibrate and maintain an instrument for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of NOX emissions into the atmosphere according to the monitoring requirements in paragraph (d)(1) of this section; install, operate, calibrate and maintain an instrument for continuously monitoring and recording the flow rate of the fuel gas and fuel oil fed to the process heater according to the monitoring requirements in paragraph (d)(5) and (6) of this section; for fuel gas streams, determine gas composition according to the requirements in paragraph (d)(4) of this section or the higher heating value according to the requirements in paragraph (d)(7) of this section; and for fuel oil streams, determine the heating value according to the monitoring requirements in paragraph (d)(7) of this section.

              (1) Except as provided in paragraph (d)(8) of this section, the owner or operator shall install, operate and maintain each NOX monitor according to the requirements in paragraphs (c)(1) through (5) of this section. The monitor must include an O2 monitor for correcting the data for excess air.

              (2) Except as provided in paragraph (d)(3) of this section, the owner or operator shall sample and analyze each fuel stream fed to the process heater using the methods and equations in section 12.3.2 of EPA Method 19 of appendix A-7 to part 60 to determine the F factor on a dry basis. If a single fuel gas system provides fuel gas to several process heaters, the F factor may be determined at a single location in the fuel gas system provided it is representative of the fuel gas fed to the affected process heater(s).
              (3) As an alternative to the requirements in paragraph (d)(2) of this section, the owner or operator of a gas-fired process heater shall install, operate and maintain a gas composition analyzer and determine the average F factor of the fuel gas using the factors in Table 1 of this subpart and Equation 13 of this section. If a single fuel gas system provides fuel gas to several process heaters, the F factor may be determined at a single location in the fuel gas system provided it is representative of the fuel gas fed to the affected process heater(s).

                ER01DE15.005

                Where:

                Fd = F factor on dry basis at 0% excess air, dscf/MMBtu.
                Xi = mole or volume fraction of each component in the fuel gas.
                MEVi = molar exhaust volume, dry standard cubic feet per mole (dscf/mol).
                MHCi = molar heat content, Btu per mole (Btu/mol).
                1,000,000 = unit conversion, Btu per MMBtu.

              (4) The owner or operator shall conduct performance evaluations of each compositional monitor according to the requirements in Performance Specification 9 of appendix B to part 60. Any of the following methods shall be used for conducting the relative accuracy evaluations:
              (i) EPA Method 18 of appendix A-6 to part 60;
              (ii) ASTM D1945-03 (Reapproved 2010)(incorporated by reference-see § 60.17);
              (iii) ASTM D1946-90 (Reapproved 2006)(incorporated by reference-see § 60.17);
              (iv) ASTM D6420-99 (Reapproved 2004)(incorporated by reference-see § 60.17);
              (v) GPA 2261-00 (incorporated by reference-see § 60.17); or
              (vi) ASTM UOP539-97 (incorporated by reference-see § 60.17).

              (5) The owner or operator shall install, operate and maintain fuel gas flow monitors according to the manufacturer's recommendations. For volumetric flow meters, temperature and pressure monitors must be installed in conjunction with the flow meter or in a representative location to correct the measured flow to standard conditions (i.e., 68 °F and 1 atmosphere). For mass flow meters, use gas compositions determined according to paragraph (d)(4) of this section to determine the average molecular weight of the fuel gas and convert the mass flow to a volumetric flow at standard conditions (i.e., 68 °F and 1 atmosphere). The owner or operator shall conduct performance evaluations of each fuel gas flow monitor according to the requirements in § 60.13 and Performance Specification 6 of appendix B to part 60. Any of the following methods shall be used for conducting the relative accuracy evaluations:
              (i) EPA Method 2, 2A, 2B, 2C or 2D of appendix A-2 to part 60;
              (ii) ASME MFC-3M-2004 (incorporated by reference-see § 60.17);
              (iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) (incorporated by reference-see § 60.17);
              (iv) ASME MFC-6M-1998 (Reaffirmed 2005) (incorporated by reference-see § 60.17);
              (v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006) (incorporated by reference-see § 60.17);
              (vi) ASME MFC-11M-2006 (incorporated by reference-see § 60.17);
              (vii) ASME MFC-14M-2003 (incorporated by reference-see § 60.17);
              (viii) ASME MFC-18M-2001 (incorporated by reference-see § 60.17);
              (ix) AGA Report No. 3, Part 1 (incorporated by reference-see § 60.17);
              (x) AGA Report No. 3, Part 2 (incorporated by reference-see § 60.17);

              (xi) AGA Report No. 11 (incorporated by reference-see § 60.17);

              (xii) AGA Report No. 7 (incorporated by reference-see § 60.17); and
              (xiii) API Manual of Petroleum Measurement Standards, Chapter 22, Section 2 (incorporated by reference-see § 60.17).
              (6) The owner or operator shall install, operate and maintain each fuel oil flow monitor according to the manufacturer's recommendations. The owner or operator shall conduct performance evaluations of each fuel oil flow monitor according to the requirements in § 60.13 and Performance Specification 6 of appendix B to part 60. Any of the following methods shall be used for conducting the relative accuracy evaluations:

              (i) Any one of the methods listed in paragraph (d)(5) of this section that are applicable to fuel oil (i.e., “fluids”);
              (ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006) (incorporated by reference-see § 60.17);
              (iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006) (incorporated by reference-see § 60.17);
              (iv) ASME MFC-16-2007 (incorporated by reference-see § 60.17);
              (v) ASME MFC-22-2007 (incorporated by reference-see § 60.17); or
              (vi) ISO 8316 (incorporated by reference-see § 60.17).
              (7) The owner or operator shall determine the higher heating value of each fuel fed to the process heater using any of the applicable methods included in paragraphs (d)(7)(i) through (ix) of this section. If a common fuel supply system provides fuel gas or fuel oil to several process heaters, the higher heating value of the fuel in each fuel supply system may be determined at a single location in the fuel supply system provided it is representative of the fuel fed to the affected process heater(s). The higher heating value of each fuel fed to the process heater must be determined no less frequently than once per day except as provided in paragraph (d)(7)(x) of this section.
              (i) ASTM D240-02 (Reapproved 2007) (incorporated by reference-see § 60.17).
              (ii) ASTM D1826-94 (Reapproved 2003) (incorporated by reference-see § 60.17).
              (iii) ASTM D1945-03 (Reapproved 2010) (incorporated by reference-see § 60.17).
              (iv) ASTM D1946-90 (Reapproved 2006) (incorporated by reference-see § 60.17).
              (v) ASTM D3588-98 (Reapproved 2003) (incorporated by reference-see § 60.17).
              (vi) ASTM D4809-06 (incorporated by reference-see § 60.17).
              (vii) ASTM D4891-89 (Reapproved 2006) (incorporated by reference-see § 60.17).
              (viii) GPA 2172-09 (incorporated by reference-see § 60.17).
              (ix) Any of the methods specified in section 2.2.7 of appendix D to part 75.
              (x) If the fuel oil supplied to the affected co-fired process heater originates from a single storage tank, the owner or operator may elect to use the storage tank sampling method in section 2.2.4.2 of appendix D to part 75 instead of daily sampling, except that the most recent value for heating content must be used.

              (8) The owner or operator of a process heater that has a rated heating capacity of less than 100 MMBtu and is equipped with combustion modification based technology to reduce NOX emissions (i.e., low-NOX burners or ultra-low NOX burners) may elect to comply with the monitoring requirements in paragraphs (d)(1) through (7) of this section or, alternatively, the owner or operator of such a process heater shall conduct biennial performance tests according to the requirements in § 60.104a(i), establish a maximum excess O2 operating limit or operating curve according to the requirements in § 60.104a(i)(6) and comply with the O2 monitoring requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O2 operating curve is used (i.e., if different O2 operating limits are established for different operating ranges), the owner or operator of the process heater must also monitor fuel gas flow rate, fuel oil flow rate (as applicable) and heating value content according to the methods provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section, respectively.
              (e) Sulfur monitoring for assessing root cause analysis threshold for affected flares. Except as described in paragraphs (e)(4) and (h) of this section, the owner or operator of an affected flare subject to § 60.103a(c) through (e) shall determine the total reduced sulfur concentration for each gas line directed to the affected flare in accordance with either paragraph (e)(1), (e)(2) or (e)(3) of this section. Different options may be elected for different gas lines. If a monitoring system is in place that is capable of complying with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or operator of a modified flare must comply with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section upon startup of the modified flare. If a monitoring system is not in place that is capable of complying with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or operator of a modified flare must comply with the requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section no later than November 11, 2015 or upon startup of the modified flare, whichever is later.
              (1) Total reduced sulfur monitoring requirements. The owner or operator shall install, operate, calibrate and maintain an instrument or instruments for continuously monitoring and recording the concentration of total reduced sulfur in gas discharged to the flare.
              (i) The owner or operator shall install, operate and maintain each total reduced sulfur monitor according to Performance Specification 5 of appendix B to part 60. The span value should be determined based on the maximum sulfur content of gas that can be discharged to the flare (e.g., roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. A single dual range monitor may be used to comply with the requirements of this paragraph and paragraph (a)(2) of this section provided the applicable span specifications are met.
              (ii) The owner or operator shall conduct performance evaluations of each total reduced sulfur monitor according to the requirements in § 60.13(c) and Performance Specification 5 of appendix B to this part. The owner or operator of each total reduced sulfur monitor shall use EPA Method 15A of appendix A-5 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference-see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to this part. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of appendix B to this part (cylinder gas audits) may be used for conducting the relative accuracy evaluations, except that it is not necessary to include as much of the sampling probe or sampling line as practical.
              (iii) The owner or operator shall comply with the applicable quality assurance procedures in appendix F to part 60 for each total reduced sulfur monitor.
              (2) H
                2
                S monitoring requirements. The owner or operator shall install, operate, calibrate, and maintain an instrument or instruments for continuously monitoring and recording the concentration of H2S in gas discharged to the flare according to the requirements in paragraphs (e)(2)(i) through (iii) of this section and shall collect and analyze samples of the gas and calculate total sulfur concentrations as specified in paragraphs (e)(2)(iv) through (ix) of this section.

              (i) The owner or operator shall install, operate and maintain each H2S monitor according to Performance Specification 7 of appendix B to part 60. The span value should be determined based on the maximum sulfur content of gas that can be discharged to the flare (e.g., roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. A single dual range H2S monitor may be used to comply with the requirements of this paragraph and paragraph (a)(2) of this section provided the applicable span specifications are met.

              (ii) The owner or operator shall conduct performance evaluations of each H2S monitor according to the requirements in § 60.13(c) and Performance Specification 7 of appendix B to this part. The owner or operator shall use EPA Method 11, 15 or 15A of appendix A-5 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to this part. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of appendix B to this part (cylinder gas audits) may be used for conducting the relative accuracy evaluations, except that it is not necessary to include as much of the sampling probe or sampling line as practical.

              (iii) The owner or operator shall comply with the applicable quality assurance procedures in appendix F to part 60 for each H2S monitor.
              (iv) In the first 10 operating days after the date the flare must begin to comply with § 60.103a(c)(1), the owner or operator shall collect representative daily samples of the gas discharged to the flare. The samples may be grab samples or integrated samples. The owner or operator shall take subsequent representative daily samples at least once per week or as required in paragraph (e)(2)(ix) of this section.
              (v) The owner or operator shall analyze each daily sample for total sulfur using either EPA Method 15A of appendix A-5 to part 60, EPA Method 16A of appendix A-6 to part 60, ASTM Method D4468-85 (Reapproved 2006) (incorporated by reference—see § 60.17) or ASTM Method D5504-08 (incorporated by reference—see § 60.17).

              (vi) The owner or operator shall develop a 10-day average total sulfur-to-H2S ratio and 95-percent confidence interval as follows:

              (A) Calculate the ratio of the total sulfur concentration to the H2S concentration for each day during which samples are collected.
              (B) Determine the 10-day average total sulfur-to-H2S ratio as the arithmetic average of the daily ratios calculated in paragraph (e)(2)(vi)(A) of this section.
              (C) Determine the acceptable range for subsequent weekly samples based on the 95-percent confidence interval for the distribution of daily ratios based on the 10 individual daily ratios using Equation 14 of this section.

                ER01DE15.006

                Where:

                AR = Acceptable range of subsequent ratio determinations, unitless.
                RatioAvg = 10-day average total sulfur-to-H2S concentration ratio, unitless.
                2.262 = t-distribution statistic for 95-percent 2-sided confidence interval for 10 samples (9 degrees of freedom).

                SDev = Standard deviation of the 10 daily average total sulfur-to-H2S concentration ratios used to develop the 10-day average total sulfur-to-H2S concentration ratio, unitless.

              (vii) For each day during the period when data are being collected to develop a 10-day average, the owner or operator shall estimate the total sulfur concentration using the measured total sulfur concentration measured for that day.

              (viii) For all days other than those during which data are being collected to develop a 10-day average, the owner or operator shall multiply the most recent 10-day average total sulfur-to-H2S ratio by the daily average H2S concentrations obtained using the monitor as required by paragraph (e)(2)(i) through (iii) of this section to estimate total sulfur concentrations.
              (ix) If the total sulfur-to-H2S ratio for a subsequent weekly sample is outside the acceptable range for the most recent distribution of daily ratios, the owner or operator shall develop a new 10-day average ratio and acceptable range based on data for the outlying weekly sample plus data collected over the following 9 operating days.
              (3) SO
                2
                monitoring requirements. The owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of SO2 from a process heater or other fuel gas combustion device that is combusting gas representative of the fuel gas in the flare gas line according to the requirements in paragraph (a)(1) of this section, determine the F factor of the fuel gas at least daily according to the requirements in paragraphs (d)(2) through (4) of this section, determine the higher heating value of the fuel gas at least daily according to the requirements in paragraph (d)(7) of this section, and calculate the total sulfur content (as SO2) in the fuel gas using Equation 15 of this section.

                ER01DE15.007

                Where:

                TSFG = Total sulfur concentration, as SO2, in the fuel gas, ppmv.
                CSO2 = Concentration of SO2 in the exhaust gas, ppmv (dry basis at 0-percent excess air).
                Fd = F factor gas on dry basis at 0-percent excess air, dscf/MMBtu.
                HHVFG = Higher heating value of the fuel gas, MMBtu/scf.

              (4) Exemptions from sulfur monitoring requirements. Flares identified in paragraphs (e)(4)(i) through (iv) of this section are exempt from the requirements in paragraphs (e)(1) through (3) of this section. For each such flare, except as provided in paragraph (e)(4)(iv), engineering calculations shall be used to calculate the SO2 emissions in the event of a discharge that may trigger a root cause analysis under § 60.103a(c)(1).
              (i) Flares that can only receive:
              (A) Fuel gas streams that are inherently low in sulfur content as described in paragraph (a)(3)(i) through (iv) of this section; and/or

              (B) Fuel gas streams that are inherently low in sulfur content for which the owner or operator has applied for an exemption from the H2S monitoring requirements as described in paragraph (b) of this section.
              (ii) Emergency flares, provided that for each such flare, the owner or operator complies with the monitoring alternative in paragraph (g) of this section.
              (iii) Flares equipped with flare gas recovery systems designed, sized and operated to capture all flows except those resulting from startup, shutdown or malfunction, provided that for each such flare, the owner or operator complies with the monitoring alternative in paragraph (g) of this section.

              (iv) Secondary flares that receive gas diverted from the primary flare. In the event of a discharge from the secondary flare, the sulfur content measured by the sulfur monitor on the primary flare should be used to calculate SO2 emissions, regardless of whether or not the monitoring alternative in paragraph (g) of this section is selected for the secondary flare.
              (f) Flow monitoring for flares. Except as provided in paragraphs (f)(2) and (h) of this section, the owner or operator of an affected flare subject to § 60.103a(c) through (e) shall install, operate, calibrate and maintain, in accordance with the specifications in paragraph (f)(1) of this section, a CPMS to measure and record the flow rate of gas discharged to the flare. If a flow monitor is not already in place, the owner or operator of a modified flare shall comply with the requirements of this paragraph by no later than November 11, 2015 or upon startup of the modified flare, whichever is later.
              (1) The owner or operator shall install, calibrate, operate and maintain each flow monitor according to the manufacturer's procedures and specifications and the following requirements.
              (i) Locate the monitor in a position that provides a representative measurement of the total gas flow rate.
              (ii) Use a flow sensor meeting an accuracy requirement of ±20 percent of the flow rate at velocities ranging from 0.1 to 1 feet per second and an accuracy of ±5 percent of the flow rate for velocities greater than 1 feet per second.
              (iii) Use a flow monitor that is maintainable online, is able to continuously correct for temperature and pressure and is able to record flow in standard conditions (as defined in § 60.2) over one-minute averages.
              (iv) At least quarterly, perform a visual inspection of all components of the monitor for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor.

              (v) Recalibrate the flow monitor in accordance with the manufacturer's procedures and specifications biennially (every two years) or at the frequency specified by the manufacturer.
              (2) Emergency flares, secondary flares and flares equipped with flare gas recovery systems designed, sized and operated to capture all flows except those resulting from startup, shutdown or malfunction are not required to install continuous flow monitors; provided, however, that for any such flare, the owner or operator shall comply with the monitoring alternative in paragraph (g) of this section.
              (g) Alternative monitoring for certain flares equipped with water seals. The owner or operator of an affected flare subject to § 60.103a(c) through (e) that can be classified as either an emergency flare, a secondary flare or a flare equipped with a flare gas recovery system designed, sized and operated to capture all flows except those resulting from startup, shutdown or malfunction may, as an alternative to the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this section, install, operate, calibrate and maintain, in accordance with the requirements in paragraphs (g)(1) through (7) of this section, a CPMS to measure and record the pressure in the flare gas header between the knock-out pot and water seal and to measure and record the water seal liquid level. If the required monitoring systems are not already in place, the owner or operator of a modified flare shall comply with the requirements of this paragraph by no later than November 11, 2015 or upon startup of the modified flare, whichever is later.
              (1) Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure and locate the liquid seal level monitor in a position that provides a representative measurement of the water column height.
              (2) Minimize or eliminate pulsating pressure, vibration and internal and external corrosion.
              (3) Use a pressure sensor and level monitor with a minimum tolerance of 1.27 centimeters of water.
              (4) Using a manometer, check pressure sensor calibration quarterly.
              (5) Conduct calibration checks any time the pressure sensor exceeds the manufacturer's specified maximum operating pressure range or install a new pressure sensor.

              (6) In a cascaded flare system that employs multiple secondary flares, pressure and liquid level monitoring is required only on the first secondary flare in the system (i.e., the secondary flare with the lowest pressure release set point).
              (7) This alternative monitoring option may be elected only for flares with four or fewer pressure exceedances required to be reported under § 60.108a(d)(5) (“reportable pressure exceedances”) in any 365 consecutive calendar days. Following the fifth reportable pressure exceedance in a 365-day period, the owner or operator must comply with the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this section as soon as practical, but no later than 180 days after the fifth reportable pressure exceedance in a 365-day period.
              (h) Alternative monitoring for flares located in the BAAQMD or SCAQMD. An affected flare subject to this subpart located in the BAAQMD may elect to comply with the monitoring requirements in both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of paragraphs (e) and (f) of this section. An affected flare subject to this subpart located in the SCAQMD may elect to comply with the monitoring requirements in SCAQMD Rule 1118 as an alternative to complying with the requirements of paragraphs (e) and (f) of this section.
              (i) Excess emissions. For the purpose of reports required by § 60.7(c), periods of excess emissions for fuel gas combustion devices subject to the emissions limitations in § 60.102a(g) and flares subject to the concentration requirement in § 60.103a(h) are defined as specified in paragraphs (i)(1) through (5) of this section. Determine a rolling 3-hour or a rolling daily average as the arithmetic average of the applicable 1-hour averages (e.g., a rolling 3-hour average is the arithmetic average of three contiguous 1-hour averages). Determine a rolling 30-day or a rolling 365-day average as the arithmetic average of the applicable daily averages (e.g., a rolling 30-day average is the arithmetic average of 30 contiguous daily averages).
              (1) SO 2
                or H2
                S limits for fuel gas combustion devices. (i) If the owner or operator of a fuel gas combustion device elects to comply with the SO2 emission limits in § 60.102a(g)(1)(i), each rolling 3-hour period during which the average concentration of SO2 as measured by the SO2 continuous monitoring system required under paragraph (a)(1) of this section exceeds 20 ppmv, and each rolling 365-day period during which the average concentration of SO2 as measured by the SO2 continuous monitoring system required under paragraph (a)(1) of this section exceeds 8 ppmv.

              (ii) If the owner or operator of a fuel gas combustion device elects to comply with the H2S concentration limits in § 60.102a(g)(1)(ii), each rolling 3-hour period during which the average concentration of H2S as measured by the H2S continuous monitoring system required under paragraph (a)(2) of this section exceeds 162 ppmv and each rolling 365-day period during which the average concentration as measured by the H2S continuous monitoring system under paragraph (a)(2) of this section exceeds 60 ppmv.

              (iii) If the owner or operator of a fuel gas combustion device becomes subject to the requirements of daily stain tube sampling in paragraph (b)(3)(iii) of this section, each day during which the daily concentration of H2S exceeds 162 ppmv and each rolling 365-day period during which the average concentration of H2S exceeds 60 ppmv.
              (2) H2S concentration limits for flares. (i) Each rolling 3-hour period during which the average concentration of H2S as measured by the H2S continuous monitoring system required under paragraph (a)(2) of this section exceeds 162 ppmv.

              (ii) If the owner or operator of a flare becomes subject to the requirements of daily stain tube sampling in paragraph (b)(3)(iii) of this section, each day during which the daily concentration of H2S exceeds 162 ppmv.
              (3) Rolling 30-day average NO
                X
                limits for fuel gas combustion devices. Each rolling 30-day period during which the average concentration of NOX as measured by the NOX continuous monitoring system required under paragraph (c) or (d) of this section exceeds:
              (i) For a natural draft process heater, 40 ppmv and, if monitored according to § 60.107a(d), 0.040 lb/MMBtu;
              (ii) For a forced draft process heater, 60 ppmv and, if monitored according to § 60.107a(d), 0.060 lb/MMBtu; and

              (iii) For a co-fired process heater electing to comply with the NOX limit in § 60.102a(g)(2)(iii)(A) or (g)(2)(iv)(A), 150 ppmv.
              (iv) The site-specific limit determined by the Administrator under § 60.102a(i).
              (4) Daily NO
                X
                limits for fuel gas combustion devices. Each day during which the concentration of NOX as measured by the NOX continuous monitoring system required under paragraph (d) of this section exceeds the daily average emissions limit calculated using Equation 3 in § 60.102a(g)(2)(iii)(B) or Equation 4 in § 60.102a(g)(2)(iv)(B).
              (5) Daily O
                2
                limits for fuel gas combustion devices. Each day during which the concentration of O2 as measured by the O2 continuous monitoring system required under paragraph (c)(6) or (d)(8) of this section exceeds the O2 operating limit or operating curve determined during the most recent biennial performance test.
              [73 FR 35867, June 24, 2008, as amended at 77 FR 56473, Sep. 12, 2012; 80 FR 75235, Dec. 1, 2015]

              § 60.108a
              Recordkeeping and reporting requirements.
              (a) Each owner or operator subject to the emissions limitations in § 60.102a shall comply with the notification, recordkeeping, and reporting requirements in § 60.7 and other requirements as specified in this section.

              (b) Each owner or operator subject to an emissions limitation in § 60.102a shall notify the Administrator of the specific monitoring provisions of §§ 60.105a, 60.106a and 60.107a with which the owner or operator intends to comply. Each owner or operator of a co-fired process heater subject to an emissions limitation in § 60.102a(g)(2)(iii) or (iv) shall submit to the Administrator documentation showing that the process heater meets the definition of a co-fired process heater in § 60.101a. Notifications required by this paragraph shall be submitted with the notification of initial startup required by § 60.7(a)(3).
              (c) The owner or operator shall maintain the following records:
              (1) A copy of the flare management plan.
              (2) Records of information to document conformance with bag leak detection system operation and maintenance requirements in § 60.105a(c).
              (3) Records of bag leak detection system alarms and actions according to § 60.105a(c).
              (4) For each FCCU and fluid coking unit subject to the monitoring requirements in § 60.105a(b)(1), records of the average coke burn-off rate and hours of operation.
              (5) For each fuel gas stream to which one of the exemptions listed in § 60.107a(a)(3) applies, records of the specific exemption determined to apply for each fuel stream. If the owner or operator applies for the exemption described in § 60.107a(a)(3)(iv), the owner or operator must keep a copy of the application as well as the letter from the Administrator granting approval of the application.
              (6) Records of discharges greater than 500 lb SO2 in any 24-hour period from any affected flare, discharges greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion device or sulfur recovery plant and discharges to an affected flare in excess of 500,000 scf above baseline in any 24-hour period as required by § 60.103a(c). If the monitoring alternative provided in § 60.107a(g) is selected, the owner or operator shall record any instance when the flare gas line pressure exceeds the water seal liquid depth, except for periods attributable to compressor staging that do not exceed the staging time specified in § 60.103a(a)(3)(vii)(C). The following information shall be recorded no later than 45 days following the end of a discharge exceeding the thresholds:
              (i) A description of the discharge.
              (ii) The date and time the discharge was first identified and the duration of the discharge.
              (iii) The measured or calculated cumulative quantity of gas discharged over the discharge duration. If the discharge duration exceeds 24 hours, record the discharge quantity for each 24-hour period. For a flare, record the measured or calculated cumulative quantity of gas discharged to the flare over the discharge duration. If the discharge duration exceeds 24 hours, record the quantity of gas discharged to the flare for each 24-hour period. Engineering calculations are allowed for fuel gas combustion devices, but are not allowed for flares, except for those complying with the alternative monitoring requirements in § 60.107a(g).
              (iv) For each discharge greater than 500 lb SO2 in any 24-hour period from a flare, the measured total sulfur concentration or both the measured H2S concentration and the estimated total sulfur concentration in the fuel gas at a representative location in the flare inlet.
              (v) For each discharge greater than 500 lb SO2 in excess of the applicable short-term emissions limit in § 60.102a(g)(1) from a fuel gas combustion device, either the measured concentration of H2S in the fuel gas or the measured concentration of SO2 in the stream discharged to the atmosphere. Process knowledge can be used to make these estimates for fuel gas combustion devices, but cannot be used to make these estimates for flares, except as provided in § 60.107a(e)(4).
              (vi) For each discharge greater than 500 lb SO2 in excess of the allowable limits from a sulfur recovery plant, either the measured concentration of reduced sulfur or SO2 discharged to the atmosphere.
              (vii) For each discharge greater than 500 lb SO2 in any 24-hour period from any affected flare or discharge greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion device or sulfur recovery plant, the cumulative quantity of H2S and SO2 released into the atmosphere. For releases controlled by flares, assume 99-percent conversion of reduced sulfur or total sulfur to SO2. For fuel gas combustion devices, assume 99-percent conversion of H2S to SO2.

              (viii) The steps that the owner or operator took to limit the emissions during the discharge.

              (ix) The root cause analysis and corrective action analysis conducted as required in § 60.103a(d), including an identification of the affected facility, the date and duration of the discharge, a statement noting whether the discharge resulted from the same root cause(s) identified in a previous analysis and either a description of the recommended corrective action(s) or an explanation of why corrective action is not necessary under § 60.103a(e).
              (x) For any corrective action analysis for which corrective actions are required in § 60.103a(e), a description of the corrective action(s) completed within the first 45 days following the discharge and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates.
              (xi) For each discharge from any affected flare that is the result of a planned startup or shutdown of a refinery process unit or ancillary equipment connected to the affected flare, a statement that a root cause analysis and corrective action analysis are not necessary because the owner or operator followed the flare management plan.

              (7) If the owner or operator elects to comply with § 60.107a(e)(2) for a flare, records of the H2S and total sulfur analyses of each grab or integrated sample, the calculated daily total sulfur-to-H2S ratios, the calculated 10-day average total sulfur-to-H2S ratios and the 95-percent confidence intervals for each 10-day average total sulfur-to-H2S ratio.
              (d) Each owner or operator subject to this subpart shall submit an excess emissions report for all periods of excess emissions according to the requirements of § 60.7(c) except that the report shall contain the information specified in paragraphs (d)(1) through (7) of this section.
              (1) The date that the exceedance occurred;
              (2) An explanation of the exceedance;
              (3) Whether the exceedance was concurrent with a startup, shutdown, or malfunction of an affected facility or control system; and
              (4) A description of the action taken, if any.
              (5) The information described in paragraph (c)(6) of this section for all discharges listed in paragraph (c)(6) of this section. For a flare complying with the monitoring alternative under § 60.107a(g), following the fifth discharge required to be recorded under paragraph (c)(6) of this section and reported under this paragraph, the owner or operator shall include notification that monitoring systems will be installed according to § 60.107a(e) and (f) within 180 days following the fifth discharge.
              (6) For any periods for which monitoring data are not available, any changes made in operation of the emission control system during the period of data unavailability which could affect the ability of the system to meet the applicable emission limit. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability.
              (7) A written statement, signed by a responsible official, certifying the accuracy and completeness of the information contained in the report.
              [73 FR 35867, June 24, 2008, as amended at 77 FR 56479, Sep. 12, 2012]

              § 60.109a
              Delegation of authority.
              (a) This subpart can be implemented and enforced by the U.S. EPA or a delegated authority such as a State, local, or tribal agency. You should contact your U.S. EPA Regional Office to find out if this subpart is delegated to a State, local, or tribal agency within your State.
              (b) In delegating implementation and enforcement authority of this subpart to a state, local or tribal agency, the approval authorities contained in paragraphs (b)(1) through (4) of this section are retained by the Administrator of the U.S. EPA and are not transferred to the state, local or tribal agency.
              (1) Approval of a major change to test methods under § 60.8(b). A “major change to test method” is defined in 40 CFR 63.90.
              (2) Approval of a major change to monitoring under § 60.13(i). A “major change to monitoring” is defined in 40 CFR 63.90.

              (3) Approval of a major change to recordkeeping/reporting under § 60.7(b) through (f). A “major change to recordkeeping/reporting” is defined in 40 CFR 63.90.
              (4) Approval of an application for an alternative means of emission limitation under § 60.103a(j) of this subpart.
              [73 FR 35867, June 24, 2008, as amended at 77 FR 56480, Sep. 12, 2012]

              Pt. 60, Subpt. Ja, Table 1
              Table 1 to Subpart Ja of Part 60—Molar Exhaust Volumes and Molar Heat Content of Fuel Gas Constituents

                  Constituent
                  MEVa
                    dscf/mol

                  MHCb
                    Btu/mol

                  Methane (CH4)
                  7.29
                  842

                  Ethane (C2H6)
                  12.96
                  1,475

                  Hydrogen (H2)
                  1.61
                  269

                  Ethene (C2H4)
                  11.34
                  1,335

                  Propane (C3H8)
                  18.62
                  2,100

                  Propene (C3H6)
                  17.02
                  1,947

                  Butane (C4H10)
                  24.30
                  2,717

                  Butene (C4H8)
                  22.69
                  2,558

                  Inerts
                  0.85
                  0

                  a MEV = molar exhaust volume, dry standard cubic feet per gram-mole (dscf/g-mol) at standard conditions of 68  °F and 1 atmosphere.

                  b MHC = molar heat content (higher heating value basis), Btu per gram-mole (Btu/g-mol).

              [77 FR 56480, Sep. 12, 2012]

            Subpart K—Standards of Performance for Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978

              § 60.110
              Applicability and designation of affected facility.
              (a) Except as provided in § 60.110(b), the affected facility to which this subpart applies is each storage vessel for petroleum liquids which has a storage capacity greater than 151,412 liters (40,000 gallons).
              (b) This subpart does not apply to storage vessels for petroleum or condensate stored, processed, and/or treated at a drilling and production facility prior to custody transfer.
              (c) Subject to the requirements of this subpart is any facility under paragraph (a) of this section which:
              (1) Has a capacity greater than 151, 416 liters (40,000 gallons), but not exceeding 246,052 liters (65,000 gallons), and commences construction or modification after March 8, 1974, and prior to May 19, 1978.
              (2) Has a capacity greater than 246,052 liters (65,000 gallons) and commences construction or modification after June 11, 1973, and prior to May 19, 1978.
              [42 FR 37937, July 25, 1977, as amended at 45 FR 23379, Apr. 4, 1980]

              § 60.111
              Definitions.
              As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.
              (a) Storage vessel means any tank, reservoir, or container used for the storage of petroleum liquids, but does not include:
              (1) Pressure vessels which are designed to operate in excess of 15 pounds per square inch gauge without emissions to the atmosphere except under emergency conditions,
              (2) Subsurface caverns or porous rock reservoirs, or
              (3) Underground tanks if the total volume of petroleum liquids added to and taken from a tank annually does not exceed twice the volume of the tank.
              (b) Petroleum liquids means petroleum, condensate, and any finished or intermediate products manufactured in a petroleum refinery but does not mean Nos. 2 through 6 fuel oils as specified in ASTM D396-78, 89, 90, 92, 96, or 98, gas turbine fuel oils Nos. 2-GT through 4-GT as specified in ASTM D2880-78 or 96, or diesel fuel oils Nos. 2-D and 4-D as specified in ASTM D975-78, 96, or 98a. (These three methods are incorporated by reference—see § 60.17.)
              (c) Petroleum refinery means each facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, or other products through distillation of petroleum or through redistillation, cracking, extracting, or reforming of unfinished petroleum derivatives.
              (d) Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal.
              (e) Hydrocarbon means any organic compound consisting predominantly of carbon and hydrogen.
              (f) Condensate means hydrocarbon liquid separated from natural gas which condenses due to changes in the temperature and/or pressure and remains liquid at standard conditions.
              (g) Custody transfer means the transfer of produced petroleum and/or condensate, after processing and/or treating in the producing operations, from storage tanks or automatic transfer facilities to pipelines or any other forms of transportation.
              (h) Drilling and production facility means all drilling and servicing equipment, wells, flow lines, separators, equipment, gathering lines, and auxiliary nontransportation-related equipment used in the production of petroleum but does not include natural gasoline plants.
              (i) True vapor pressure means the equilibrium partial pressure exerted by a petroleum liquid as determined in accordance with methods described in American Petroleum Institute Bulletin 2517, Evaporation Loss from External Floating-Roof Tanks, Second Edition, February 1980 (incorporated by reference—see § 60.17).
              (j) Floating roof means a storage vessel cover consisting of a double deck, pontoon single deck, internal floating cover or covered floating roof, which rests upon and is supported by the petroleum liquid being contained, and is equipped with a closure seal or seals to close the space between the roof edge and tank wall.
              (k) Vapor recovery system means a vapor gathering system capable of collecting all hydrocarbon vapors and gases discharged from the storage vessel and a vapor disposal system capable of processing such hydrocarbon vapors and gases so as to prevent their emission to the atmosphere.
              (l) Reid vapor pressure is the absolute vapor pressure of volatile crude oil and volatile nonviscous petroleum liquids, except liquified petroleum gases, as determined by ASTM D323-82 or 94 (incorporated by reference—see § 60.17).
              [39 FR 9317, Mar. 8, 1974; 39 FR 13776, Apr. 17, 1974, as amended at 39 FR 20794, June 14, 1974; 45 FR 23379, Apr. 4, 1980; 48 FR 3737, Jan. 27, 1983; 52 FR 11429, Apr. 8, 1987; 65 FR 61755, Oct. 17, 2000]

              § 60.112
              Standard for volatile organic compounds (VOC).
              (a) The owner or operator of any storage vessel to which this subpart applies shall store petroleum liquids as follows:
              (1) If the true vapor pressure of the petroleum liquid, as stored, is equal to or greater than 78 mm Hg (1.5 psia) but not greater than 570 mm Hg (11.1 psia), the storage vessel shall be equipped with a floating roof, a vapor recovery system, or their equivalents.
              (2) If the true vapor pressure of the petroleum liquid as stored is greater than 570 mm Hg (11.1 psia), the storage vessel shall be equipped with a vapor recovery system or its equivalent.
              [39 FR 9317, Mar. 8, 1974; 39 FR 13776, Apr. 17, 1974, as amended at 45 FR 23379, Apr. 4, 1980]

              § 60.113
              Monitoring of operations.
              (a) Except as provided in paragraph (d) of this section, the owner or operator subject to this subpart shall maintain a record of the petroleum liquid stored, the period of storage, and the maximum true vapor pressure of that liquid during the respective storage period.
              (b) Available data on the typical Reid vapor pressure and the maximum expected storage temperature of the stored product may be used to determine the maximum true vapor pressure from nomographs contained in API Bulletin 2517, unless the Administrator specifically requests that the liquid be sampled, the actual storage temperature determined, and the Reid vapor pressure determined from the sample(s).
              (c) The true vapor pressure of each type of crude oil with a Reid vapor pressure less than 13.8 kPa (2.0 psia) or whose physical properties preclude determination by the recommended method is to be determined from available data and recorded if the estimated true vapor pressure is greater than 6.9 kPa (1.0 psia).
              (d) The following are exempt from the requirements of this section:
              (1) Each owner or operator of each affected facility which stores petroleum liquids with a Reid vapor pressure of less than 6.9 kPa (1.0 psia) provided the maximum true vapor pressure does not exceed 6.9 kPa (1.0 psia).

              (2) Each owner or operator of each affected facility equipped with a vapor recovery and return or disposal system in accordance with the requirements of § 60.112.
              [45 FR 23379, Apr. 4, 1980]

            Subpart Ka—Standards of Performance for Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984

              § 60.110a
              Applicability and designation of affected facility.
              (a) Affected facility. Except as provided in paragraph (b) of this section, the affected facility to which this subpart applies is each storage vessel with a storage capacity greater than 151,416 liters (40,000 gallons) that is used to store petroleum liquids for which construction is commenced after May 18, 1978.
              (b) Each petroleum liquid storage vessel with a capacity of less than 1,589,873 liters (420,000 gallons) used for petroleum or condensate stored, processed, or treated prior to custody transfer is not an affected facility and, therefore, is exempt from the requirements of this subpart.
              (c) Alternative means of compliance—(1) Option to comply with part 65. Owners or operators may choose to comply with 40 CFR part 65, subpart C, to satisfy the requirements of §§ 60.112a through 60.114a for storage vessels that are subject to this subpart that store petroleum liquids that, as stored, have a maximum true vapor pressure equal to or greater than 10.3 kPa (1.5 psia). Other provisions applying to owners or operators who choose to comply with 40 CFR part 65 are provided in 40 CFR 65.1.
              (2) Part 60, subpart A. Owners or operators who choose to comply with 40 CFR part 65, subpart C, must also comply with §§ 60.1, 60.2, 60.5, 60.6, 60.7(a)(1) and (4), 60.14, 60.15, and 60.16 for those storage vessels. All sections and paragraphs of subpart A of this part that are not mentioned in this paragraph (c)(2) do not apply to owners or operators of storage vessels complying with 40 CFR part 65, subpart C, except that provisions required to be met prior to implementing 40 CFR part 65 still apply. Owners and operators who choose to comply with 40 CFR part 65, subpart C, must comply with 40 CFR part 65, subpart A.
              [45 FR 23379, Apr. 4, 1980, as amended at 65 FR 78275, Dec. 14, 2000]

              § 60.111a
              Definitions.
              In addition to the terms and their definitions listed in the Act and subpart A of this part the following definitions apply in this subpart:
              (a) Storage vessel means each tank, reservoir, or container used for the storage of petroleum liquids, but does not include:
              (1) Pressure vessels which are designed to operate in excess of 204.9 kPa (15 psig) without emissions to the atmosphere except under emergency conditions.
              (2) Subsurface caverns or porous rock reservoirs, or
              (3) Underground tanks if the total volume of petroleum liquids added to and taken from a tank annually does not exceed twice the volume of the tank.
              (b) Petroleum liquids means petroleum, condensate, and any finished or intermediate products manufactured in a petroleum refinery but does not mean Nos. 2 through 6 fuel oils as specified in ASTM D396-78, 89, 90, 92, 96, or 98, gas turbine fuel oils Nos. 2-GT through 4-GT as specified in ASTM D2880-78 or 96, gas turbine fuel oils Nos. 2-GT through 4-GT as specified in ASTM D2880-78 or 96, or diesel fuel oils Nos. 2-D and 4-D as specified in ASTM D975-78, 96, or 98a. (These three methods are incorporated by reference—see § 60.17.)
              (c) Petroleum refinery means each facility engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants, or other products through distillation of petroleum or through redistillation, cracking, extracting, or reforming of unfinished petroleum derivatives.
              (d) Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal.
              (e) Condensate means hydrocarbon liquid separated from natural gas which condenses due to changes in the temperature or pressure, or both, and remains liquid at standard conditions.

              (f) True vapor pressure means the equilibrium partial pressure exerted by a petroleum liquid such as determined in accordance with methods described in American Petroleum Institute Bulletin 2517, Evaporation Loss from External Floating-Roof Tanks, Second Edition, February 1980 (incorporated by reference—see § 60.17).
              (g) Reid vapor pressure is the absolute vapor pressure of volatile crude oil and nonviscous petroleum liquids, except liquified petroleum gases, as determined by ASTM D323-82 or 94 (incorporated by reference—see § 60.17).
              (h) Liquid-mounted seal means a foam or liquid-filled primary seal mounted in contact with the liquid between the tank wall and the floating roof continuously around the circumference of the tank.
              (i) Metallic shoe seal includes but is not limited to a metal sheet held vertically against the tank wall by springs or weighted levers and is connected by braces to the floating roof. A flexible coated fabric (envelope) spans the annular space between the metal sheet and the floating roof.
              (j) Vapor-mounted seal means a foam-filled primary seal mounted continuously around the circumference of the tank so there is an annular vapor space underneath the seal. The annular vapor space is bounded by the bottom of the primary seal, the tank wall, the liquid surface, and the floating roof.
              (k) Custody transfer means the transfer of produced petroleum and/or condensate, after processing and/or treating in the producing operations, from storage tanks or automatic transfer facilities to pipelines or any other forms of transportation.
              [45 FR 23379, Apr. 4, 1980, as amended at 48 FR 3737, Jan. 27, 1983; 52 FR 11429, Apr. 8, 1987; 65 FR 61756, Oct. 17, 2000]

              § 60.112a
              Standard for volatile organic compounds (VOC).
              (a) The owner or operator of each storage vessel to which this subpart applies which contains a petroleum liquid which, as stored, has a true vapor pressure equal to or greater than 10.3 kPa (1.5 psia) but not greater than 76.6 kPa (11.1 psia) shall equip the storage vessel with one of the following:
              (1) An external floating roof, consisting of a pontoon-type or double-deck-type cover that rests on the surface of the liquid contents and is equipped with a closure device between the tank wall and the roof edge. Except as provided in paragraph (a)(1)(ii)(D) of this section, the closure device is to consist of two seals, one above the other. The lower seal is referred to as the primary seal and the upper seal is referred to as the secondary seal. The roof is to be floating on the liquid at all times (i.e., off the roof leg supports) except during initial fill and when the tank is completely emptied and subsequently refilled. The process of emptying and refilling when the roof is resting on the leg supports shall be continuous and shall be accomplished as rapidly as possible.
              (i) The primary seal is to be either a metallic shoe seal, a liquid-mounted seal, or a vapor-mounted seal. Each seal is to meet the following requirements:
              (A) The accumulated area of gaps between the tank wall and the metallic shoe seal or the liquid-mounted seal shall not exceed 212 cm2 per meter of tank diameter (10.0 in 2 per ft of tank diameter) and the width of any portion of any gap shall not exceed 3.81 cm (11/2 in).
              (B) The accumulated area of gaps between the tank wall and the vapor-mounted seal shall not exceed 21.2 cm2 per meter of tank diameter (1.0 in2 per ft of tank diameter) and the width of any portion of any gap shall not exceed 1.27 cm (1/2 in).
              (C) One end of the metallic shoe is to extend into the stored liquid and the other end is to extend a minimum vertical distance of 61 cm (24 in) above the stored liquid surface.
              (D) There are to be no holes, tears, or other openings in the shoe, seal fabric, or seal envelope.
              (ii) The secondary seal is to meet the following requirements:
              (A) The secondary seal is to be installed above the primary seal so that it completely covers the space between the roof edge and the tank wall except as provided in paragraph (a)(1)(ii)(B) of this section.

              (B) The accumulated area of gaps between the tank wall and the secondary seal used in combination with a metallic shoe or liquid-mounted primary seal shall not exceed 21.2 cm2 per meter of tank diameter (1.0 in2 per ft. of tank diameter) and the width of any portion of any gap shall not exceed 1.27 cm (1/2 in.). There shall be no gaps between the tank wall and the secondary seal used in combination with a vapor-mounted primary seal.
              (C) There are to be no holes, tears or other openings in the seal or seal fabric.
              (D) The owner or operator is exempted from the requirements for secondary seals and the secondary seal gap criteria when performing gap measurements or inspections of the primary seal.
              (iii) Each opening in the roof except for automatic bleeder vents and rim space vents is to provide a projection below the liquid surface. Each opening in the roof except for automatic bleeder vents, rim space vents and leg sleeves is to be equipped with a cover, seal or lid which is to be maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use or as described in pargraph (a)(1)(iv) of this section. Automatic bleeder vents are to be closed at all times when the roof is floating, except when the roof is being floated off or is being landed on the roof leg supports. Rim vents are to be set to open when the roof is being floated off the roof legs supports or at the manufacturer's recommended setting.
              (iv) Each emergency roof drain is to be provided with a slotted membrane fabric cover that covers at least 90 percent of the area of the opening.
              (2) A fixed roof with an internal floating type cover equipped with a continuous closure device between the tank wall and the cover edge. The cover is to be floating at all times, (i.e., off the leg supports) except during initial fill and when the tank is completely emptied and subsequently refilled. The process of emptying and refilling when the cover is resting on the leg supports shall be continuous and shall be accomplished as rapidly as possible. Each opening in the cover except for automatic bleeder vents and the rim space vents is to provide a projection below the liquid surface. Each opening in the cover except for automatic bleeder vents, rim space vents, stub drains and leg sleeves is to be equipped with a cover, seal, or lid which is to be maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use. Automatic bleeder vents are to be closed at all times when the cover is floating except when the cover is being floated off or is being landed on the leg supports. Rim vents are to be set to open only when the cover is being floated off the leg supports or at the manufacturer's recommended setting.
              (3) A vapor recovery system which collects all VOC vapors and gases discharged from the storage vessel, and a vapor return or disposal system which is designed to process such VOC vapors and gases so as to reduce their emission to the atmosphere by at least 95 percent by weight.
              (4) A system equivalent to those described in paragraphs (a)(1), (a)(2), or (a)(3) of this section as provided in § 60.114a.
              (b) The owner or operator of each storage vessel to which this subpart applies which contains a petroleum liquid which, as stored, has a true vapor pressure greater than 76.6 kPa (11.1 psia), shall equip the storage vessel with a vapor recovery system which collects all VOC vapors and gases discharged from the storage vessel, and a vapor return or disposal system which is designed to process such VOC vapors and gases so as to reduce their emission to the atmosphere by at least 95 percent by weight.
              [45 FR 23379, Apr. 4, 1980, as amended at 45 FR 83229, Dec. 18, 1980]

              § 60.113a
              Testing and procedures.
              (a) Except as provided in § 60.8(b) compliance with the standard prescribed in § 60.112a shall be determined as follows or in accordance with an equivalent procedure as provided in § 60.114a.

              (1) The owner or operator of each storage vessel to which this subpart applies which has an external floating roof shall meet the following requirements:

              (i) Determine the gap areas and maximum gap widths between the primary seal and the tank wall and between the secondary seal and the tank wall according to the following frequency:
              (A) For primary seals, gap measurements shall be performed within 60 days of the initial fill with petroleum liquid and at least once every five years thereafter. All primary seal inspections or gap measurements which require the removal or dislodging of the secondary seal shall be accomplished as rapidly as possible and the secondary seal shall be replaced as soon as possible.
              (B) For secondary seals, gap measurements shall be performed within 60 days of the initial fill with petroleum liquid and at least once every year thereafter.
              (C) If any storage vessel is out of service for a period of one year or more, subsequent refilling with petroleum liquid shall be considered initial fill for the purposes of paragraphs (a)(1)(i)(A) and (a)(1)(i)(B) of this section.
              (D) Keep records of each gap measurement at the plant for a period of at least 2 years following the date of measurement. Each record shall identify the vessel on which the measurement was performed and shall contain the date of the seal gap measurement, the raw data obtained in the measurement process required by paragraph (a)(1)(ii) of this section and the calculation required by paragraph (a)(1)(iii) of this section.
              (E) If either the seal gap calculated in accord with paragraph (a)(1)(iii) of this section or the measured maximum seal gap exceeds the limitations specified by § 60.112a of this subpart, a report shall be furnished to the Administrator within 60 days of the date of measurements. The report shall identify the vessel and list each reason why the vessel did not meet the specifications of § 60.112a. The report shall also describe the actions necessary to bring the storage vessel into compliance with the specifications of § 60.112a.
              (ii) Determine gap widths in the primary and secondary seals individually by the following procedures:
              (A) Measure seal gaps, if any, at one or more floating roof levels when the roof is floating off the roof leg supports.
              (B) Measure seal gaps around the entire circumference of the tank in each place where a 1/8″ diameter uniform probe passes freely (without forcing or binding against seal) between the seal and the tank wall and measure the circumferential distance of each such location.
              (C) The total surface area of each gap described in paragraph (a)(1)(ii)(B) of this section shall be determined by using probes of various widths to accurately measure the actual distance from the tank wall to the seal and multiplying each such width by its respective circumferential distance.
              (iii) Add the gap surface area of each gap location for the primary seal and the secondary seal individually. Divide the sum for each seal by the nominal diameter of the tank and compare each ratio to the appropriate ratio in the standard in § 60.112a(a)(1)(i) and § 60.112a(a)(1)(ii).
              (iv) Provide the Administrator 30 days prior notice of the gap measurement to afford the Administrator the opportunity to have an observer present.
              (2) The owner or operator of each storage vessel to which this subpart applies which has a vapor recovery and return or disposal system shall provide the following information to the Administrator on or before the date on which construction of the storage vessel commences:
              (i) Emission data, if available, for a similar vapor recovery and return or disposal system used on the same type of storage vessel, which can be used to determine the efficiency of the system. A complete description of the emission measurement method used must be included.
              (ii) The manufacturer's design specifications and estimated emission reduction capability of the system.
              (iii) The operation and maintenance plan for the system.
              (iv) Any other information which will be useful to the Administrator in evaluating the effectiveness of the system in reducing VOC emissions.
              [45 FR 23379, Apr. 4, 1980, as amended at 52 FR 11429, Apr. 8, 1987]

              § 60.114a
              Alternative means of emission limitation.

              (a) If, in the Administrator's judgment, an alternative means of emission limitation will achieve a reduction in emissions at least equivalent to the reduction in emissions achieved by any requirement in § 60.112a, the Administrator will publish in the Federal Register a notice permitting the use of the alternative means for purposes of compliance with that requirement.
              (b) Any notice under paragraph (a) of this section will be published only after notice and an opportunity for a hearing.
              (c) Any person seeking permission under this section shall submit to the Administrator a written application including:
              (1) An actual emissions test that uses a full-sized or scale-model storage vessel that accurately collects and measures all VOC emissions from a given control device and that accurately simulates wind and accounts for other emission variables such as temperature and barometric pressure.
              (2) An engineering evaluation that the Administrator determines is an accurate method of determining equivalence.
              (d) The Administrator may condition the permission on requirements that may be necessary to ensure operation and maintenance to achieve the same emissions reduction as specified in § 60.112a.
              (e) The primary vapor-mounted seal in the “Volume-Maximizing Seal” manufactured by R.F.I. Services Corporation is approved as equivalent to the vapor-mounted seal required by § 60.112a(a)(1)(i) and must meet the gap criteria specified in § 60.112a(a)(1)(i)(B). There shall be no gaps between the tank wall and any secondary seal used in conjunction with the primary seal in the “Volume-Maximizing Seal”.
              [52 FR 11429, Apr. 8, 1987]

              § 60.115a
              Monitoring of operations.
              (a) Except as provided in paragraph (d) of this section, the owner or operator subject to this subpart shall maintain a record of the petroleum liquid stored, the period of storage, and the maximum true vapor pressure of that liquid during the respective storage period.
              (b) Available data on the typical Reid vapor pressure and the maximum expected storage temperature of the stored product may be used to determine the maximum true vapor pressure from nomographs contained in API Bulletin 2517, unless the Administrator specifically requests that the liquid be sampled, the actual storage temperature determined, and the Reid vapor pressure determined from the sample(s).
              (c) The true vapor pressure of each type of crude oil with a Reid vapor pressure less than 13.8 kPa (2.0 psia) or whose physical properties preclude determination by the recommended method is to be determined from available data and recorded if the estimated true vapor pressure is greater than 6.9 kPa (1.0 psia).
              (d) The following are exempt from the requirements of this section:
              (1) Each owner or operator of each storage vessel storing a petroleum liquid with a Reid vapor pressure of less than 6.9 kPa (1.0 psia) provided the maximum true vapor pressure does not exceed 6.9 kPa (1.0 psia).
              (2) The owner or operator of each storage vessel equipped with a vapor recovery and return or disposal system in accordance with the requirements of § 60.112a(a)(3) and (b), or a closed vent system and control device meeting the specifications of 40 CFR 65.42(b)(4), (b)(5), or (c).
              [45 FR 23379, Apr. 4, 1980, as amended at 65 FR 78275, Dec. 14, 2000]

            Subpart Kb—Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984

              Source:
              52 FR 11429, Apr. 8, 1987, unless otherwise noted.

              § 60.110b
              Applicability and designation of affected facility.

              (a) Except as provided in paragraph (b) of this section, the affected facility to which this subpart applies is each storage vessel with a capacity greater than or equal to 75 cubic meters (m3) that is used to store volatile organic liquids (VOL) for which construction, reconstruction, or modification is commenced after July 23, 1984.
              (b) This subpart does not apply to storage vessels with a capacity greater than or equal to 151 m3 storing a liquid with a maximum true vapor pressure less than 3.5 kilopascals (kPa) or with a capacity greater than or equal to 75 m3 but less than 151 m3 storing a liquid with a maximum true vapor pressure less than 15.0 kPa.
              (c) [Reserved]
              (d) This subpart does not apply to the following:
              (1) Vessels at coke oven by-product plants.
              (2) Pressure vessels designed to operate in excess of 204.9 kPa and without emissions to the atmosphere.
              (3) Vessels permanently attached to mobile vehicles such as trucks, railcars, barges, or ships.
              (4) Vessels with a design capacity less than or equal to 1,589.874 m3 used for petroleum or condensate stored, processed, or treated prior to custody transfer.
              (5) Vessels located at bulk gasoline plants.
              (6) Storage vessels located at gasoline service stations.
              (7) Vessels used to store beverage alcohol.
              (8) Vessels subject to subpart GGGG of 40 CFR part 63.
              (e) Alternative means of compliance—(1) Option to comply with part 65. Owners or operators may choose to comply with 40 CFR part 65, subpart C, to satisfy the requirements of §§ 60.112b through 60.117b for storage vessels that are subject to this subpart that meet the specifications in paragraphs (e)(1)(i) and (ii) of this section. When choosing to comply with 40 CFR part 65, subpart C, the monitoring requirements of § 60.116b(c), (e), (f)(1), and (g) still apply. Other provisions applying to owners or operators who choose to comply with 40 CFR part 65 are provided in 40 CFR 65.1.
              (i) A storage vessel with a design capacity greater than or equal to 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 5.2 kPa; or
              (ii) A storage vessel with a design capacity greater than 75 m3 but less than 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 27.6 kPa.
              (2) Part 60, subpart A. Owners or operators who choose to comply with 40 CFR part 65, subpart C, must also comply with §§ 60.1, 60.2, 60.5, 60.6, 60.7(a)(1) and (4), 60.14, 60.15, and 60.16 for those storage vessels. All sections and paragraphs of subpart A of this part that are not mentioned in this paragraph (e)(2) do not apply to owners or operators of storage vessels complying with 40 CFR part 65, subpart C, except that provisions required to be met prior to implementing 40 CFR part 65 still apply. Owners and operators who choose to comply with 40 CFR part 65, subpart C, must comply with 40 CFR part 65, subpart A.
              (3) Internal floating roof report. If an owner or operator installs an internal floating roof and, at initial startup, chooses to comply with 40 CFR part 65, subpart C, a report shall be furnished to the Administrator stating that the control equipment meets the specifications of 40 CFR 65.43. This report shall be an attachment to the notification required by 40 CFR 65.5(b).
              (4) External floating roof report. If an owner or operator installs an external floating roof and, at initial startup, chooses to comply with 40 CFR part 65, subpart C, a report shall be furnished to the Administrator stating that the control equipment meets the specifications of 40 CFR 65.44. This report shall be an attachment to the notification required by 40 CFR 65.5(b).
              [52 FR 11429, Apr. 8, 1987, as amended at 54 FR 32973, Aug. 11, 1989; 65 FR 78275, Dec. 14, 2000; 68 FR 59332, Oct. 15, 2003]

              § 60.111b
              Definitions.
              Terms used in this subpart are defined in the Act, in subpart A of this part, or in this subpart as follows:

                Bulk gasoline plant means any gasoline distribution facility that has a gasoline throughput less than or equal to 75,700 liters per day. Gasoline throughput shall be the maximum calculated design throughput as may be limited by compliance with an enforceable condition under Federal requirement or Federal, State or local law, and discoverable by the Administrator and any other person.

                Condensate means hydrocarbon liquid separated from natural gas that condenses due to changes in the temperature or pressure, or both, and remains liquid at standard conditions.

                Custody transfer means the transfer of produced petroleum and/or condensate, after processing and/or treatment in the producing operations, from storage vessels or automatic transfer facilities to pipelines or any other forms of transportation.

                Fill means the introduction of VOL into a storage vessel but not necessarily to complete capacity.

                Gasoline service station means any site where gasoline is dispensed to motor vehicle fuel tanks from stationary storage tanks.

                Maximum true vapor pressure means the equilibrium partial pressure exerted by the volatile organic compounds (as defined in 40 CFR 51.100) in the stored VOL at the temperature equal to the highest calendar-month average of the VOL storage temperature for VOL's stored above or below the ambient temperature or at the local maximum monthly average temperature as reported by the National Weather Service for VOL's stored at the ambient temperature, as determined:
              (1) In accordance with methods described in American Petroleum institute Bulletin 2517, Evaporation Loss From External Floating Roof Tanks, (incorporated by reference—see § 60.17); or
              (2) As obtained from standard reference texts; or
              (3) As determined by ASTM D2879-83, 96, or 97 (incorporated by reference—see § 60.17);
              (4) Any other method approved by the Administrator.

                Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal.

                Petroleum liquids means petroleum, condensate, and any finished or intermediate products manufactured in a petroleum refinery.

                Process tank means a tank that is used within a process (including a solvent or raw material recovery process) to collect material discharged from a feedstock storage vessel or equipment within the process before the material is transferred to other equipment within the process, to a product or by-product storage vessel, or to a vessel used to store recovered solvent or raw material. In many process tanks, unit operations such as reactions and blending are conducted. Other process tanks, such as surge control vessels and bottoms receivers, however, may not involve unit operations.

                Reid vapor pressure means the absolute vapor pressure of volatile crude oil and volatile nonviscous petroleum liquids except liquified petroleum gases, as determined by ASTM D323-82 or 94 (incorporated by reference—see § 60.17).

                Storage vessel means each tank, reservoir, or container used for the storage of volatile organic liquids but does not include:
              (1) Frames, housing, auxiliary supports, or other components that are not directly involved in the containment of liquids or vapors;
              (2) Subsurface caverns or porous rock reservoirs; or
              (3) Process tanks.

                Volatile organic liquid (VOL) means any organic liquid which can emit volatile organic compounds (as defined in 40 CFR 51.100) into the atmosphere.

                Waste means any liquid resulting from industrial, commercial, mining or agricultural operations, or from community activities that is discarded or is being accumulated, stored, or physically, chemically, or biologically treated prior to being discarded or recycled.
              [52 FR 11429, Apr. 8, 1987, as amended at 54 FR 32973, Aug. 11, 1989; 65 FR 61756, Oct. 17, 2000; 68 FR 59333, Oct. 15, 2003]

              § 60.112b
              Standard for volatile organic compounds (VOC).

              (a) The owner or operator of each storage vessel either with a design capacity greater than or equal to 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 5.2 kPa but less than 76.6 kPa or with a design capacity greater than or equal to 75 m3 but less than 151 m3 containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 27.6 kPa but less than 76.6 kPa, shall equip each storage vessel with one of the following:
              (1) A fixed roof in combination with an internal floating roof meeting the following specifications:
              (i) The internal floating roof shall rest or float on the liquid surface (but not necessarily in complete contact with it) inside a storage vessel that has a fixed roof. The internal floating roof shall be floating on the liquid surface at all times, except during initial fill and during those intervals when the storage vessel is completely emptied or subsequently emptied and refilled. When the roof is resting on the leg supports, the process of filling, emptying, or refilling shall be continuous and shall be accomplished as rapidly as possible.
              (ii) Each internal floating roof shall be equipped with one of the following closure devices between the wall of the storage vessel and the edge of the internal floating roof:
              (A) A foam- or liquid-filled seal mounted in contact with the liquid (liquid-mounted seal). A liquid-mounted seal means a foam- or liquid-filled seal mounted in contact with the liquid between the wall of the storage vessel and the floating roof continuously around the circumference of the tank.
              (B) Two seals mounted one above the other so that each forms a continuous closure that completely covers the space between the wall of the storage vessel and the edge of the internal floating roof. The lower seal may be vapor-mounted, but both must be continuous.
              (C) A mechanical shoe seal. A mechanical shoe seal is a metal sheet held vertically against the wall of the storage vessel by springs or weighted levers and is connected by braces to the floating roof. A flexible coated fabric (envelope) spans the annular space between the metal sheet and the floating roof.
              (iii) Each opening in a noncontact internal floating roof except for automatic bleeder vents (vacuum breaker vents) and the rim space vents is to provide a projection below the liquid surface.
              (iv) Each opening in the internal floating roof except for leg sleeves, automatic bleeder vents, rim space vents, column wells, ladder wells, sample wells, and stub drains is to be equipped with a cover or lid which is to be maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use. The cover or lid shall be equipped with a gasket. Covers on each access hatch and automatic gauge float well shall be bolted except when they are in use.
              (v) Automatic bleeder vents shall be equipped with a gasket and are to be closed at all times when the roof is floating except when the roof is being floated off or is being landed on the roof leg supports.
              (vi) Rim space vents shall be equipped with a gasket and are to be set to open only when the internal floating roof is not floating or at the manufacturer's recommended setting.
              (vii) Each penetration of the internal floating roof for the purpose of sampling shall be a sample well. The sample well shall have a slit fabric cover that covers at least 90 percent of the opening.
              (viii) Each penetration of the internal floating roof that allows for passage of a column supporting the fixed roof shall have a flexible fabric sleeve seal or a gasketed sliding cover.
              (ix) Each penetration of the internal floating roof that allows for passage of a ladder shall have a gasketed sliding cover.
              (2) An external floating roof. An external floating roof means a pontoon-type or double-deck type cover that rests on the liquid surface in a vessel with no fixed roof. Each external floating roof must meet the following specifications:
              (i) Each external floating roof shall be equipped with a closure device between the wall of the storage vessel and the roof edge. The closure device is to consist of two seals, one above the other. The lower seal is referred to as the primary seal, and the upper seal is referred to as the secondary seal.

              (A) The primary seal shall be either a mechanical shoe seal or a liquid-mounted seal. Except as provided in § 60.113b(b)(4), the seal shall completely cover the annular space between the edge of the floating roof and tank wall.
              (B) The secondary seal shall completely cover the annular space between the external floating roof and the wall of the storage vessel in a continuous fashion except as allowed in § 60.113b(b)(4).
              (ii) Except for automatic bleeder vents and rim space vents, each opening in a noncontact external floating roof shall provide a projection below the liquid surface. Except for automatic bleeder vents, rim space vents, roof drains, and leg sleeves, each opening in the roof is to be equipped with a gasketed cover, seal, or lid that is to be maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use. Automatic bleeder vents are to be closed at all times when the roof is floating except when the roof is being floated off or is being landed on the roof leg supports. Rim vents are to be set to open when the roof is being floated off the roof legs supports or at the manufacturer's recommended setting. Automatic bleeder vents and rim space vents are to be gasketed. Each emergency roof drain is to be provided with a slotted membrane fabric cover that covers at least 90 percent of the area of the opening.
              (iii) The roof shall be floating on the liquid at all times (i.e., off the roof leg supports) except during initial fill until the roof is lifted off leg supports and when the tank is completely emptied and subsequently refilled. The process of filling, emptying, or refilling when the roof is resting on the leg supports shall be continuous and shall be accomplished as rapidly as possible.
              (3) A closed vent system and control device meeting the following specifications:
              (i) The closed vent system shall be designed to collect all VOC vapors and gases discharged from the storage vessel and operated with no detectable emissions as indicated by an instrument reading of less than 500 ppm above background and visual inspections, as determined in part 60, subpart VV, § 60.485(b).
              (ii) The control device shall be designed and operated to reduce inlet VOC emissions by 95 percent or greater. If a flare is used as the control device, it shall meet the specifications described in the general control device requirements (§ 60.18) of the General Provisions.
              (4) A system equivalent to those described in paragraphs (a)(1), (a)(2), or (a)(3) of this section as provided in § 60.114b of this subpart.
              (b) The owner or operator of each storage vessel with a design capacity greater than or equal to 75 m3 which contains a VOL that, as stored, has a maximum true vapor pressure greater than or equal to 76.6 kPa shall equip each storage vessel with one of the following:
              (1) A closed vent system and control device as specified in § 60.112b(a)(3).
              (2) A system equivalent to that described in paragraph (b)(1) as provided in § 60.114b of this subpart.
              (c) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia. This paragraph applies only to the pharmaceutical manufacturing facility, commonly referred to as the Stonewall Plant, located at Route 340 South, in Elkton, Virginia (“site”).
              (1) For any storage vessel that otherwise would be subject to the control technology requirements of paragraphs (a) or (b) of this section, the site shall have the option of either complying directly with the requirements of this subpart, or reducing the site-wide total criteria pollutant emissions cap (total emissions cap) in accordance with the procedures set forth in a permit issued pursuant to 40 CFR 52.2454. If the site chooses the option of reducing the total emissions cap in accordance with the procedures set forth in such permit, the requirements of such permit shall apply in lieu of the otherwise applicable requirements of this subpart for such storage vessel.
              (2) For any storage vessel at the site not subject to the requirements of 40 CFR 60.112b (a) or (b), the requirements of 40 CFR 60.116b (b) and (c) and the General Provisions (subpart A of this part) shall not apply.
              [52 FR 11429, Apr. 8, 1987, as amended at 62 FR 52641, Oct. 8, 1997]

              § 60.113b
              Testing and procedures.

              The owner or operator of each storage vessel as specified in § 60.112b(a) shall meet the requirements of paragraph (a), (b), or (c) of this section. The applicable paragraph for a particular storage vessel depends on the control equipment installed to meet the requirements of § 60.112b.
              (a) After installing the control equipment required to meet § 60.112b(a)(1) (permanently affixed roof and internal floating roof), each owner or operator shall:
              (1) Visually inspect the internal floating roof, the primary seal, and the secondary seal (if one is in service), prior to filling the storage vessel with VOL. If there are holes, tears, or other openings in the primary seal, the secondary seal, or the seal fabric or defects in the internal floating roof, or both, the owner or operator shall repair the items before filling the storage vessel.
              (2) For Vessels equipped with a liquid-mounted or mechanical shoe primary seal, visually inspect the internal floating roof and the primary seal or the secondary seal (if one is in service) through manholes and roof hatches on the fixed roof at least once every 12 months after initial fill. If the internal floating roof is not resting on the surface of the VOL inside the storage vessel, or there is liquid accumulated on the roof, or the seal is detached, or there are holes or tears in the seal fabric, the owner or operator shall repair the items or empty and remove the storage vessel from service within 45 days. If a failure that is detected during inspections required in this paragraph cannot be repaired within 45 days and if the vessel cannot be emptied within 45 days, a 30-day extension may be requested from the Administrator in the inspection report required in § 60.115b(a)(3). Such a request for an extension must document that alternate storage capacity is unavailable and specify a schedule of actions the company will take that will assure that the control equipment will be repaired or the vessel will be emptied as soon as possible.
              (3) For vessels equipped with a double-seal system as specified in § 60.112b(a)(1)(ii)(B):
              (i) Visually inspect the vessel as specified in paragraph (a)(4) of this section at least every 5 years; or
              (ii) Visually inspect the vessel as specified in paragraph (a)(2) of this section.
              (4) Visually inspect the internal floating roof, the primary seal, the secondary seal (if one is in service), gaskets, slotted membranes and sleeve seals (if any) each time the storage vessel is emptied and degassed. If the internal floating roof has defects, the primary seal has holes, tears, or other openings in the seal or the seal fabric, or the secondary seal has holes, tears, or other openings in the seal or the seal fabric, or the gaskets no longer close off the liquid surfaces from the atmosphere, or the slotted membrane has more than 10 percent open area, the owner or operator shall repair the items as necessary so that none of the conditions specified in this paragraph exist before refilling the storage vessel with VOL. In no event shall inspections conducted in accordance with this provision occur at intervals greater than 10 years in the case of vessels conducting the annual visual inspection as specified in paragraphs (a)(2) and (a)(3)(ii) of this section and at intervals no greater than 5 years in the case of vessels specified in paragraph (a)(3)(i) of this section.
              (5) Notify the Administrator in writing at least 30 days prior to the filling or refilling of each storage vessel for which an inspection is required by paragraphs (a)(1) and (a)(4) of this section to afford the Administrator the opportunity to have an observer present. If the inspection required by paragraph (a)(4) of this section is not planned and the owner or operator could not have known about the inspection 30 days in advance or refilling the tank, the owner or operator shall notify the Administrator at least 7 days prior to the refilling of the storage vessel. Notification shall be made by telephone immediately followed by written documentation demonstrating why the inspection was unplanned. Alternatively, this notification including the written documentation may be made in writing and sent by express mail so that it is received by the Administrator at least 7 days prior to the refilling.

              (b) After installing the control equipment required to meet § 60.112b(a)(2) (external floating roof), the owner or operator shall:
              (1) Determine the gap areas and maximum gap widths, between the primary seal and the wall of the storage vessel and between the secondary seal and the wall of the storage vessel according to the following frequency.
              (i) Measurements of gaps between the tank wall and the primary seal (seal gaps) shall be performed during the hydrostatic testing of the vessel or within 60 days of the initial fill with VOL and at least once every 5 years thereafter.
              (ii) Measurements of gaps between the tank wall and the secondary seal shall be performed within 60 days of the initial fill with VOL and at least once per year thereafter.
              (iii) If any source ceases to store VOL for a period of 1 year or more, subsequent introduction of VOL into the vessel shall be considered an initial fill for the purposes of paragraphs (b)(1)(i) and (b)(1)(ii) of this section.
              (2) Determine gap widths and areas in the primary and secondary seals individually by the following procedures:
              (i) Measure seal gaps, if any, at one or more floating roof levels when the roof is floating off the roof leg supports.
              (ii) Measure seal gaps around the entire circumference of the tank in each place where a 0.32-cm diameter uniform probe passes freely (without forcing or binding against seal) between the seal and the wall of the storage vessel and measure the circumferential distance of each such location.
              (iii) The total surface area of each gap described in paragraph (b)(2)(ii) of this section shall be determined by using probes of various widths to measure accurately the actual distance from the tank wall to the seal and multiplying each such width by its respective circumferential distance.
              (3) Add the gap surface area of each gap location for the primary seal and the secondary seal individually and divide the sum for each seal by the nominal diameter of the tank and compare each ratio to the respective standards in paragraph (b)(4) of this section.
              (4) Make necessary repairs or empty the storage vessel within 45 days of identification in any inspection for seals not meeting the requirements listed in (b)(4) (i) and (ii) of this section:
              (i) The accumulated area of gaps between the tank wall and the mechanical shoe or liquid-mounted primary seal shall not exceed 212 cm2 per meter of tank diameter, and the width of any portion of any gap shall not exceed 3.81 cm.
              (A) One end of the mechanical shoe is to extend into the stored liquid, and the other end is to extend a minimum vertical distance of 61 cm above the stored liquid surface.
              (B) There are to be no holes, tears, or other openings in the shoe, seal fabric, or seal envelope.
              (ii) The secondary seal is to meet the following requirements:
              (A) The secondary seal is to be installed above the primary seal so that it completely covers the space between the roof edge and the tank wall except as provided in paragraph (b)(2)(iii) of this section.
              (B) The accumulated area of gaps between the tank wall and the secondary seal shall not exceed 21.2 cm2 per meter of tank diameter, and the width of any portion of any gap shall not exceed 1.27 cm.
              (C) There are to be no holes, tears, or other openings in the seal or seal fabric.
              (iii) If a failure that is detected during inspections required in paragraph (b)(1) of § 60.113b(b) cannot be repaired within 45 days and if the vessel cannot be emptied within 45 days, a 30-day extension may be requested from the Administrator in the inspection report required in § 60.115b(b)(4). Such extension request must include a demonstration of unavailability of alternate storage capacity and a specification of a schedule that will assure that the control equipment will be repaired or the vessel will be emptied as soon as possible.
              (5) Notify the Administrator 30 days in advance of any gap measurements required by paragraph (b)(1) of this section to afford the Administrator the opportunity to have an observer present.

              (6) Visually inspect the external floating roof, the primary seal, secondary seal, and fittings each time the vessel is emptied and degassed.

              (i) If the external floating roof has defects, the primary seal has holes, tears, or other openings in the seal or the seal fabric, or the secondary seal has holes, tears, or other openings in the seal or the seal fabric, the owner or operator shall repair the items as necessary so that none of the conditions specified in this paragraph exist before filling or refilling the storage vessel with VOL.
              (ii) For all the inspections required by paragraph (b)(6) of this section, the owner or operator shall notify the Administrator in writing at least 30 days prior to the filling or refilling of each storage vessel to afford the Administrator the opportunity to inspect the storage vessel prior to refilling. If the inspection required by paragraph (b)(6) of this section is not planned and the owner or operator could not have known about the inspection 30 days in advance of refilling the tank, the owner or operator shall notify the Administrator at least 7 days prior to the refilling of the storage vessel. Notification shall be made by telephone immediately followed by written documentation demonstrating why the inspection was unplanned. Alternatively, this notification including the written documentation may be made in writing and sent by express mail so that it is received by the Administrator at least 7 days prior to the refilling.
              (c) The owner or operator of each source that is equipped with a closed vent system and control device as required in § 60.112b (a)(3) or (b)(2) (other than a flare) is exempt from § 60.8 of the General Provisions and shall meet the following requirements.
              (1) Submit for approval by the Administrator as an attachment to the notification required by § 60.7(a)(1) or, if the facility is exempt from § 60.7(a)(1), as an attachment to the notification required by § 60.7(a)(2), an operating plan containing the information listed below.
              (i) Documentation demonstrating that the control device will achieve the required control efficiency during maximum loading conditions. This documentation is to include a description of the gas stream which enters the control device, including flow and VOC content under varying liquid level conditions (dynamic and static) and manufacturer's design specifications for the control device. If the control device or the closed vent capture system receives vapors, gases, or liquids other than fuels from sources that are not designated sources under this subpart, the efficiency demonstration is to include consideration of all vapors, gases, and liquids received by the closed vent capture system and control device. If an enclosed combustion device with a minimum residence time of 0.75 seconds and a minimum temperature of 816 °C is used to meet the 95 percent requirement, documentation that those conditions will exist is sufficient to meet the requirements of this paragraph.
              (ii)
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