[Title 40 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2010 Edition]
[From the U.S. Government Printing Office]
[[Page 1]]
40
Part 60 (Sec. 60.1 to end of part 60 sections)
Revised as of July 1, 2010
Protection of Environment
________________________
Containing a codification of documents of general
applicability and future effect
As of July 1, 2010
With Ancillaries
Published by
Office of the Federal Register
National Archives and Records
Administration
A Special Edition of the Federal Register
[[Page ii]]
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[[Page iii]]
Table of Contents
Page
Explanation................................................. v
Title 40:
Chapter I--Environmental Protection Agency 3
Finding Aids:
Table of CFR Titles and Chapters........................ 1025
Alphabetical List of Agencies Appearing in the CFR...... 1045
List of CFR Sections Affected........................... 1055
[[Page iv]]
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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.
----------------------------
[[Page v]]
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
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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
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HOW TO USE THE CODE OF FEDERAL REGULATIONS
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collection request.
[[Page vi]]
Many agencies have begun publishing numerous OMB control numbers as
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OBSOLETE PROVISIONS
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(a) The incorporation will substantially reduce the volume of
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(c) The incorporating document is drafted and submitted for
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[[Page vii]]
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Raymond A. Mosley,
Director,
Office of the Federal Register.
July 1, 2010.
[[Page ix]]
THIS TITLE
Title 40--Protection of Environment is composed of thirty-two
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-end
of part 52), parts 53-59, part 60 (60.1-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
72-80, parts 81-84, part 85-Sec. 86.599-99, part 86 (86.600-1-end of
part 86), parts 87-99, 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 700-789, parts 790-999, and part 1000 to end.
The contents of these volumes represent all current regulations codified
under this title of the CFR as of July 1, 2010.
Chapter I--Environmental Protection Agency appears in all thirty-two
volumes. Regulations issued by the Council on Environmental Quality,
including an Index to Parts 1500 through 1508, appear in the volume
containing part 1000 to end. The OMB control numbers for title 40 appear
in Sec. 9.1 of this chapter.
For this volume, Jonn V. Lilyea was Chief Editor. The Code of
Federal Regulations publication program is under the direction of
Michael L. White, assisted by Ann Worley.
[[Page 1]]
TITLE 40--PROTECTION OF ENVIRONMENT
(This book contains part 60, Sec. 60.1 to end of part 60 sections)
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Part
chapter i--Environmental Protection Agency (Continued)...... 60
[[Page 3]]
CHAPTER I--ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)
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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
[[Page 5]]
SUBCHAPTER C_AIR PROGRAMS (CONTINUED)
PART 60_STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--Table of Contents
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 to 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 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.
[[Page 6]]
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 Sec.
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 Sec.
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 Sec. 60.33e(b)(1)
Table 2B to Subpart Ce of Part 60--Emissions Limits for Small HMIWI
Which Meet the Criteria Under Sec. 60.33e(b)(2)
Subpart D_Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17, 1971
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 for Which Construction is Commenced After September 18,
1978
60.40Da Applicability and designation of affected facility.
60.41Da Definitions.
60.42Da Standard for particulate matter (PM).
60.43Da Standard for sulfur dioxide (SO2).
60.44Da Standard for nitrogen oxides (NOX).
60.45Da Standard for mercury (Hg).
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.
[[Page 7]]
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 Hospital/Medical/Infectious
Waste Incinerators for Which Construction is Commenced After June 20,
1996
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--Emissions Limits for Small, Medium, and Large
HMIWI at Affected Facilities as Defined in Sec. 60.50c(a)(1)
and (2)
Table 1B to Subpart Ec--Emissions Limits for Small, Medium, and Large
HMIWI at Affected Facilities as Defined in Sec. 60.50c(a)(3)
and (4)
Table 2 to Subpart Ec--Toxic Equivalency Factors
Table 3 to Subpart Ec--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 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.
[[Page 8]]
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 Work practice 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.
60.108a Recordkeeping and reporting requirements.
60.109a Delegation of authority.
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.
[[Page 9]]
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.
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.
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.
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.
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.
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.
[[Page 10]]
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 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.
[[Page 11]]
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.
[[Page 12]]
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.
Subpart XX_Standards of Performance for Bulk Gasoline Terminals
60.500 Applicability and designation of affected facility.
60.501 Definitions.
60.502 Standards for Volatile Organic Compound (VOC) emissions from bulk
gasoline terminals.
60.503 Test methods and procedures.
60.504 [Reserved]
60.505 Reporting and recordkeeping.
60.506 Reconstruction.
Subpart AAA_Standards of Performance for New Residential Wood Heaters
60.530 Applicability and designation of affected facility.
60.531 Definitions.
60.532 Standards for particulate matter.
60.533 Compliance and certification.
60.534 Test methods and procedures.
60.535 Laboratory accreditation.
60.536 Permanent label, temporary label, and owner's manual.
60.537 Reporting and recordkeeping.
60.538 Prohibitions.
60.539 Hearing and appeal procedures.
60.539a Delegation of authority.
60.539b General provisions exclusions.
Subpart BBB_Standards of Performance for the Rubber Tire Manufacturing
Industry
60.540 Applicability and designation of affected facilities.
60.541 Definitions.
60.542 Standards for volatile organic compounds.
60.542a Alternate standard for volatile organic compounds.
60.543 Performance test and compliance provisions.
[[Page 13]]
60.544 Monitoring of operations.
60.545 Recordkeeping requirements.
60.546 Reporting requirements.
60.547 Test methods and procedures.
60.548 Delegation of authority.
Subpart CCC [Reserved]
Subpart DDD_Standards of Performance for Volatile Organic Compound (VOC)
Emissions from the Polymer Manufacturing Industry
60.560 Applicability and designation of affected facilities.
60.561 Definitions.
60.562-1 Standards: Process emissions.
60.562-2 Standards: Equipment leaks of VOC.
60.563 Monitoring requirements.
60.564 Test methods and procedures.
60.565 Reporting and recordkeeping requirements.
60.566 Delegation of authority.
Subpart EEE [Reserved]
Subpart FFF_Standards of Performance for Flexible Vinyl and Urethane
Coating and Printing
60.580 Applicability and designation of affected facility.
60.581 Definitions and symbols.
60.582 Standard for volatile organic compounds.
60.583 Test methods and procedures.
60.584 Monitoring of operations and recordkeeping requirements.
60.585 Reporting requirements.
Subpart GGG_Standards of Performance for Equipment Leaks of VOC in
Petroleum Refineries for Which Construction, Reconstruction, or
Modification Commenced After January 4, 1983, and on or Before November
7, 2006
60.590 Applicability and designation of affected facility.
60.591 Definitions.
60.592 Standards.
60.593 Exceptions.
Subpart GGGa_Standards of Performance for Equipment Leaks of VOC in
Petroleum Refineries for Which Construction, Reconstruction, or
Modification Commenced After November 7, 2006
60.590a Applicability and designation of affected facility.
60.591a Definitions.
60.592a Standards.
60.593a Exceptions.
Subpart HHH_Standards of Performance for Synthetic Fiber Production
Facilities
60.600 Applicability and designation of affected facility.
60.601 Definitions.
60.602 Standard for volatile organic compounds.
60.603 Performance test and compliance provisions.
60.604 Reporting requirements.
Subpart III_Standards of Performance for Volatile Organic Compound (VOC)
Emissions From the Synthetic Organic Chemical Manufacturing Industry
(SOCMI) Air Oxidation Unit Processes
60.610 Applicability and designation of affected facility.
60.611 Definitions.
60.612 Standards.
60.613 Monitoring of emissions and operations.
60.614 Test methods and procedures.
60.615 Reporting and recordkeeping requirements.
60.616 Reconstruction.
60.617 Chemicals affected by subpart III.
60.618 Delegation of authority.
Subpart JJJ_Standards of Performance for Petroleum Dry Cleaners
60.620 Applicability and designation of affected facility.
60.621 Definitions.
60.622 Standards for volatile organic compounds.
60.623 Equivalent equipment and procedures.
60.624 Test methods and procedures.
60.625 Recordkeeping requirements.
Subpart KKK_Standards of Performance for Equipment Leaks of VOC From
Onshore Natural Gas Processing Plants
60.630 Applicability and designation of affected facility.
60.631 Definitions.
60.632 Standards.
60.633 Exceptions.
60.634 Alternative means of emission limitation.
60.635 Recordkeeping requirements.
60.636 Reporting requirements.
Subpart LLL_Standards of Performance for Onshore Natural Gas Processing:
SO2 Emissions
60.640 Applicability and designation of affected facilities.
60.641 Definitions.
60.642 Standards for sulfur dioxide.
60.643 Compliance provisions.
[[Page 14]]
60.644 Test methods and procedures.
60.645 [Reserved]
60.646 Monitoring of emissions and operations.
60.647 Recordkeeping and reporting requirements.
60.648 Optional procedure for measuring hydrogen sulfide in acid gas--
Tutwiler Procedure.
Subpart MMM [Reserved]
Subpart NNN_Standards of Performance for Volatile Organic Compound (VOC)
Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI)
Distillation Operations
60.660 Applicability and designation of affected facility.
60.661 Definitions.
60.662 Standards.
60.663 Monitoring of emissions and operations.
60.664 Test methods and procedures.
60.665 Reporting and recordkeeping requirements.
60.666 Reconstruction.
60.667 Chemicals affected by subpart NNN.
60.668 Delegation of authority.
Subpart OOO_Standards of Performance for Nonmetallic Mineral Processing
Plants
60.670 Applicability and designation of affected facility.
60.671 Definitions.
60.672 Standard for particulate matter (PM).
60.673 Reconstruction.
60.674 Monitoring of operations.
60.675 Test methods and procedures.
60.676 Reporting and recordkeeping.
Table 1 to Subpart OOO--Exceptions to Applicability of Subpart A to
Subpart OOO
Table 2 to Subpart OOO--Stack Emission Limits for Affected Facilities
With Capture Systems
Table 3 to Subpart OOO--Fugitive Emission Limits
Subpart PPP_Standard of Performance for Wool Fiberglass Insulation
Manufacturing Plants
60.680 Applicability and designation of affected facility.
60.681 Definitions.
60.682 Standard for particulate matter.
60.683 Monitoring of operations.
60.684 Recordkeeping and reporting requirements.
60.685 Test methods and procedures.
Subpart QQQ_Standards of Performance for VOC Emissions From Petroleum
Refinery Wastewater Systems
60.690 Applicability and designation of affected facility.
60.691 Definitions.
60.692-1 Standards: General.
60.692-2 Standards: Individual drain systems.
60.692-3 Standards: Oil-water separators.
60.692-4 Standards: Aggregate facility.
60.692-5 Standards: Closed vent systems and control devices.
60.692-6 Standards: Delay of repair.
60.692-7 Standards: Delay of compliance.
60.693-1 Alternative standards for individual drain systems.
60.693-2 Alternative standards for oil-water separators.
60.694 Permission to use alternative means of emission limitation.
60.695 Monitoring of operations.
60.696 Performance test methods and procedures and compliance
provisions.
60.697 Recordkeeping requirements.
60.698 Reporting requirements.
60.699 Delegation of authority.
Subpart RRR_Standards of Performance for Volatile Organic Compound
Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI)
Reactor Processes
60.700 Applicability and designation of affected facility.
60.701 Definitions.
60.702 Standards.
60.703 Monitoring of emissions and operations.
60.704 Test methods and procedures.
60.705 Reporting and recordkeeping requirements.
60.706 Reconstruction.
60.707 Chemicals affected by subpart RRR.
60.708 Delegation of authority.
Subpart SSS_Standards of Performance for Magnetic Tape Coating
Facilities
60.710 Applicability and designation of affected facility.
60.711 Definitions, symbols, and cross-reference tables.
60.712 Standards for volatile organic compounds.
60.713 Compliance provisions.
60.714 Installation of monitoring devices and recordkeeping.
60.715 Test methods and procedures.
60.716 Permission to use alternative means of emission limitation.
60.717 Reporting and monitoring requirements.
[[Page 15]]
60.718 Delegation of authority.
Subpart TTT_Standards of Performance for Industrial Surface Coating:
Surface Coating of Plastic Parts for Business Machines
60.720 Applicability and designation of affected facility.
60.721 Definitions.
60.722 Standards for volatile organic compounds.
60.723 Performance test and compliance provisions.
60.724 Reporting and recordkeeping requirements.
60.725 Test methods and procedures.
60.726 Delegation of authority.
Subpart UUU_Standards of Performance for Calciners and Dryers in Mineral
Industries
60.730 Applicability and designation of affected facility.
60.731 Definitions.
60.732 Standards for particulate matter.
60.733 Reconstruction.
60.734 Monitoring of emissions and operations.
60.735 Recordkeeping and reporting requirements.
60.736 Test methods and procedures.
60.737 Delegation of authority.
Subpart VVV_Standards of Performance for Polymeric Coating of Supporting
Substrates Facilities
60.740 Applicability and designation of affected facility.
60.741 Definitions, symbols, and cross-reference tables.
60.742 Standards for violatile organic compounds.
60.743 Compliance provisions.
60.744 Monitoring requirements.
60.745 Test methods and procedures.
60.746 Permission to use alternative means of emission limitation.
60.747 Reporting and recordkeeping requirements.
60.748 Delegation of authority.
Subpart WWW_Standards of Performance for Municipal Solid Waste Landfills
60.750 Applicability, designation of affected facility, and delegation
of authority.
60.751 Definitions.
60.752 Standards for air emissions from municipal solid waste landfills.
60.753 Operational standards for collection and control systems.
60.754 Test methods and procedures.
60.755 Compliance provisions.
60.756 Monitoring of operations.
60.757 Reporting requirements.
60.758 Recordkeeping requirements.
60.759 Specifications for active collection systems.
Subpart AAAA_Standards of Performance for 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
Introduction
60.1000 What does this subpart do?
60.1005 When does this subpart become effective?
Applicability
60.1010 Does this subpart apply to my municipal waste combustion unit?
60.1015 What is a new municipal waste combustion unit?
60.1020 Does this subpart allow any exemptions?
60.1025 Do subpart E new source performance standards also apply to my
municipal waste combustion unit?
60.1030 Can the Administrator delegate authority to enforce these
Federal new source performance standards to a State agency?
60.1035 How are these new source performance standards structured?
60.1040 Do all five components of these new source performance standards
apply at the same time?
60.1045 Are there different subcategories of small municipal waste
combustion units within this subpart?
Preconstruction Requirements: Materials Separation Plan
60.1050 Who must submit a materials separation plan?
60.1055 What is a materials separation plan?
60.1060 What steps must I complete for my materials separation plan?
60.1065 What must I include in my draft materials separation plan?
60.1070 How do I make my draft materials separation plan available to
the public?
60.1075 When must I accept comments on the materials separation plan?
60.1080 Where and when must I hold a public meeting on my draft
materials separation plan?
60.1085 What must I do with any public comments I receive during the
public comment period on my draft materials separation plan?
60.1090 What must I do with my revised materials separation plan?
60.1095 What must I include in the public meeting on my revised
materials separation plan?
[[Page 16]]
60.1100 What must I do with any public comments I receive on my revised
materials separation plan?
60.1105 How do I submit my final materials separation plan?
Preconstruction Requirements: Siting Analysis
60.1110 Who must submit a siting analysis?
60.1115 What is a siting analysis?
60.1120 What steps must I complete for my siting analysis?
60.1125 What must I include in my siting analysis?
60.1130 How do I make my siting analysis available to the public?
60.1135 When must I accept comments on the siting analysis and revised
materials separation plan?
60.1140 Where and when must I hold a public meeting on the siting
analysis?
60.1145 What must I do with any public comments I receive during the
public comment period on my siting analysis?
60.1150 How do I submit my siting analysis?
Good Combustion Practices: Operator Training
60.1155 What types of training must I do?
60.1160 Who must complete the operator training course? By when?
60.1165 Who must complete the plant-specific training course?
60.1170 What plant-specific training must I provide?
60.1175 What information must I include in the plant-specific operating
manual?
60.1180 Where must I keep the plant-specific operating manual?
Good Combustion Practices: Operator Certification
60.1185 What types of operator certification must the chief facility
operator and shift supervisor obtain and by when must they
obtain it?
60.1190 After the required date for operator certification, who may
operate the municipal waste combustion unit?
60.1195 What if all the certified operators must be temporarily offsite?
Good Combustion Practices: Operating Requirements
60.1200 What are the operating practice requirements for my municipal
waste combustion unit?
60.1205 What happens to the operating requirements during periods of
startup, shutdown, and malfunction?
Emission Limits
60.1210 What pollutants are regulated by this subpart?
60.1215 What emission limits must I meet? By when?
60.1220 What happens to the emission limits during periods of startup,
shutdown, and malfunction?
Continuous Emission Monitoring
60.1225 What types of continuous emission monitoring must I perform?
60.1230 What continuous emission monitoring systems must I install for
gaseous pollutants?
60.1235 How are the data from the continuous emission monitoring systems
used?
60.1240 How do I make sure my continuous emission monitoring systems are
operating correctly?
60.1245 Am I exempt from any appendix B or appendix F requirements to
evaluate continuous emission monitoring systems?
60.1250 What is my schedule for evaluating continuous emission
monitoring systems?
60.1255 What must I do if I choose to monitor carbon dioxide instead of
oxygen as a diluent gas?
60.1260 What is the minimum amount of monitoring data I must collect
with my continuous emission monitoring systems and is the data
collection requirement enforceable?
60.1265 How do I convert my 1-hour arithmetic averages into the
appropriate averaging times and units?
60.1270 What is required for my continuous opacity monitoring system and
how are the data used?
60.1275 What additional requirements must I meet for the operation of my
continuous emission monitoring systems and continuous opacity
monitoring system?
60.1280 What must I do if any of my continuous emission monitoring
systems are temporarily unavailable to meet the data
collection requirements?
Stack Testing
60.1285 What types of stack tests must I conduct?
60.1290 How are the stack test data used?
60.1295 What schedule must I follow for the stack testing?
60.1300 What test methods must I use to stack test?
60.1305 May I conduct stack testing less often?
60.1310 May I deviate from the 13-month testing schedule if unforeseen
circumstances arise?
Other Monitoring Requirements
60.1315 Must I meet other requirements for continuous monitoring?
60.1320 How do I monitor the load of my municipal waste combustion unit?
[[Page 17]]
60.1325 How do I monitor the temperature of flue gases at the inlet of
my particulate matter control device?
60.1330 How do I monitor the injection rate of activated carbon?
60.1335 What is the minimum amount of monitoring data I must collect
with my continuous parameter monitoring systems and is the
data collection requirement enforceable?
Recordkeeping
60.1340 What records must I keep?
60.1345 Where must I keep my records and for how long?
60.1350 What records must I keep for the materials separation plan and
siting analysis?
60.1355 What records must I keep for operator training and
certification?
60.1360 What records must I keep for stack tests?
60.1365 What records must I keep for continuously monitored pollutants
or parameters?
60.1370 What records must I keep for municipal waste combustion units
that use activated carbon?
Reporting
60.1375 What reports must I submit before I submit my notice of
construction?
60.1380 What must I include in my notice of construction?
60.1385 What reports must I submit after I submit my notice of
construction and in what form?
60.1390 What are the appropriate units of measurement for reporting my
data?
60.1395 When must I submit the initial report?
60.1400 What must I include in my initial report?
60.1405 When must I submit the annual report?
60.1410 What must I include in my annual report?
60.1415 What must I do if I am out of compliance with the requirements
of this subpart?
60.1420 If a semiannual report is required, when must I submit it?
60.1425 What must I include in the semiannual out-of-compliance reports?
60.1430 Can reporting dates be changed?
Air Curtain Incinerators That Burn 100 Percent Yard Waste
60.1435 What is an air curtain incinerator?
60.1440 What is yard waste?
60.1445 What are the emission limits for air curtain incinerators that
burn 100 percent yard waste?
60.1450 How must I monitor opacity for air curtain incinerators that
burn 100 percent yard waste?
60.1455 What are the recordkeeping and reporting requirements for air
curtain incinerators that burn 100 percent yard waste?
Equations
60.1460 What equations must I use?
Definitions
60.1465 What definitions must I know?
Table 1 to Subpart AAAA of Part 60--Emission Limits For New Small
Municipal Waste Combustion Units
Table 2 to Subpart AAAA of Part 60--Carbon Monoxide Emission Limits For
New Small Municipal Waste Combustion Units
Table 3 to Subpart AAAA of Part 60--Requirements For Validating
Continuous Emission Monitoring Systems (CEMS)
Table 4 to Subpart AAAA of Part 60--Requirements For Continuous Emission
Monitoring Systems (CEMS)
Table 5 to Subpart AAAA of Part 60--Requirements For Stack Tests
Subpart BBBB_Emission Guidelines and Compliance Times for Small
Municipal Waste Combustion Units Constructed on or Before August 30,
1999
Introduction
60.1500 What is the purpose of this subpart?
60.1505 Am I affected by this subpart?
60.1510 Is a State plan required for all States?
60.1515 What must I include in my State plan?
60.1520 Is there an approval process for my State plan?
60.1525 What if my State plan is not approvable?
60.1530 Is there an approval process for a negative declaration letter?
60.1535 What compliance schedule must I include in my State plan?
60.1540 Are there any State plan requirements for this subpart that
supersede the requirements specified in subpart B?
60.1545 Does this subpart directly affect municipal waste combustion
unit owners and operators in my State?
Applicability of State Plans
60.1550 What municipal waste combustion units must I address in my State
plan?
60.1555 Are any small municipal waste combustion units exempt from my
State plan?
60.1560 Can an affected municipal waste combustion unit reduce its
capacity to less than 35 tons per day rather than comply with
my State plan?
[[Page 18]]
60.1565 What subcategories of small municipal waste combustion units
must I include in my State plan?
Use of Model Rule
60.1570 What is the ``model rule'' in this subpart?
60.1575 How does the model rule relate to the required elements of my
State plan?
60.1580 What are the principal components of the model rule?
Model Rule--Increments of Progress
60.1585 What are my requirements for meeting increments of progress and
achieving final compliance?
60.1590 When must I complete each increment of progress?
60.1595 What must I include in the notifications of achievement of my
increments of progress?
60.1600 When must I submit the notifications of achievement of
increments of progress?
60.1605 What if I do not meet an increment of progress?
60.1610 How do I comply with the increment of progress for submittal of
a control plan?
60.1615 How do I comply with the increment of progress for awarding
contracts?
60.1620 How do I comply with the increment of progress for initiating
onsite construction?
60.1625 How do I comply with the increment of progress for completing
onsite construction?
60.1630 How do I comply with the increment of progress for achieving
final compliance?
60.1635 What must I do if I close my municipal waste combustion unit and
then restart my municipal waste combustion unit?
60.1640 What must I do if I plan to permanently close my municipal waste
combustion unit and not restart it?
Model Rule--Good Combustion Practices: Operator Training
60.1645 What types of training must I do?
60.1650 Who must complete the operator training course? By when?
60.1655 Who must complete the plant-specific training course?
60.1660 What plant-specific training must I provide?
60.1665 What information must I include in the plant-specific operating
manual?
60.1670 Where must I keep the plant-specific operating manual?
Model Rule--Good Combustion Practices: Operator Certification
60.1675 What types of operator certification must the chief facility
operator and shift supervisor obtain and by when must they
obtain it?
60.1680 After the required date for operator certification, who may
operate the municipal waste combustion unit?
60.1685 What if all the certified operators must be temporarily offsite?
Model Rule--Good Combustion Practices: Operating Requirements
60.1690 What are the operating practice requirements for my municipal
waste combustion unit?
60.1695 What happens to the operating requirements during periods of
startup, shutdown, and malfunction?
Model Rule--Emission Limits
60.1700 What pollutants are regulated by this subpart?
60.1705 What emission limits must I meet? By when?
60.1710 What happens to the emission limits during periods of startup,
shutdown, and malfunction?
Model Rule--Continuous Emission Monitoring
60.1715 What types of continuous emission monitoring must I perform?
60.1720 What continuous emission monitoring systems must I install for
gaseous pollutants?
60.1725 How are the data from the continuous emission monitoring systems
used?
60.1730 How do I make sure my continuous emission monitoring systems are
operating correctly?
60.1735 Am I exempt from any appendix B or appendix F requirements to
evaluate continuous emission monitoring systems?
60.1740 What is my schedule for evaluating continuous emission
monitoring systems?
60.1745 What must I do if I choose to monitor carbon dioxide instead of
oxygen as a diluent gas?
60.1750 What is the minimum amount of monitoring data I must collect
with my continuous emission monitoring systems and is the data
collection requirement enforceable?
60.1755 How do I convert my 1-hour arithmetic averages into appropriate
averaging times and units?
60.1760 What is required for my continuous opacity monitoring system and
how are the data used?
60.1765 What additional requirements must I meet for the operation of my
continuous emission monitoring systems and continuous opacity
monitoring system?
60.1770 What must I do if any of my continuous emission monitoring
systems are
[[Page 19]]
temporarily unavailable to meet the data collection
requirements?
Model Rule--Stack Testing
60.1775 What types of stack tests must I conduct?
60.1780 How are the stack test data used?
60.1785 What schedule must I follow for the stack testing?
60.1790 What test methods must I use to stack test?
60.1795 May I conduct stack testing less often?
60.1800 May I deviate from the 13-month testing schedule if unforeseen
circumstances arise?
Model Rule--Other Monitoring Requirements
60.1805 Must I meet other requirements for continuous monitoring?
60.1810 How do I monitor the load of my municipal waste combustion unit?
60.1815 How do I monitor the temperature of flue gases at the inlet of
my particulate matter control device?
60.1820 How do I monitor the injection rate of activated carbon?
60.1825 What is the minimum amount of monitoring data I must collect
with my continuous parameter monitoring systems and is the
data collection requirement enforceable?
Model Rule--Recordkeeping
60.1830 What records must I keep?
60.1835 Where must I keep my records and for how long?
60.1840 What records must I keep for operator training and
certification?
60.1845 What records must I keep for stack tests?
60.1850 What records must I keep for continuously monitored pollutants
or parameters?
60.1855 What records must I keep for municipal waste combustion units
that use activated carbon?
Model Rule--Reporting
60.1860 What reports must I submit and in what form?
60.1865 What are the appropriate units of measurement for reporting my
data?
60.1870 When must I submit the initial report?
60.1875 What must I include in my initial report?
60.1880 When must I submit the annual report?
60.1885 What must I include in my annual report?
60.1890 What must I do if I am out of compliance with the requirements
of this subpart?
60.1895 If a semiannual report is required, when must I submit it?
60.1900 What must I include in the semiannual out-of-compliance reports?
60.1905 Can reporting dates be changed?
Model Rule--Air Curtain Incinerators That Burn 100 Percent Yard Waste
60.1910 What is an air curtain incinerator?
60.1915 What is yard waste?
60.1920 What are the emission limits for air curtain incinerators that
burn 100 percent yard waste?
60.1925 How must I monitor opacity for air curtain incinerators that
burn 100 percent yard waste?
60.1930 What are the recordkeeping and reporting requirements for air
curtain incinerators that burn 100 percent yard waste?
Equations
60.1935 What equations must I use?
Definitions
60.1940 What definitions must I know?
Table 1 to Subpart BBBB of Part 60--Model Rule--Compliance Schedules and
Increments of Progress
Table 2 to Subpart BBBB of Part 60--Model Rule--Class I Emission Limits
For Existing Small Municipal Waste Combustion Units
Table 3 to Subpart BBBB of Part 60--Model Rule--Class I Nitrogen Oxides
Emission Limits For Existing Small Municipal Waste Combustion
Units
Table 4 to Subpart BBBB of Part 60--Model Rule--Class II Emission Limits
For Existing Small Municipal Waste Combustion Units
Table 5 to Subpart BBBB of Part 60--Model Rule--Carbon Monoxide Emission
Limits For Existing Small Municipal Waste Combustion Units
Table 6 to Subpart BBBB of Part 60--Model Rule--Requirements for
Validating Continuous Emission Monitoring Systems (CEMS)
Table 7 to Subpart BBBB of Part 60--Model Rule--Requirements for
Continuous Emission Monitoring Systems (CEMS)
[[Page 20]]
Table 8 to Subpart BBBB of Part 60--Model Rule--Requirements for Stack
Tests
Subpart CCCC_Standards of Performance for 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
Introduction
60.2000 What does this subpart do?
60.2005 When does this subpart become effective?
Applicability
60.2010 Does this subpart apply to my incineration unit?
60.2015 What is a new incineration unit?
60.2020 What combustion units are exempt from this subpart?
60.2025 What if my chemical recovery unit is not listed in Sec.
60.2020(n)?
60.2030 Who implements and enforces this subpart?
60.2035 How are these new source performance standards structured?
60.2040 Do all eleven components of the new source performance standards
apply at the same time?
Preconstruction Siting Analysis
60.2045 Who must prepare a siting analysis?
60.2050 What is a siting analysis?
Waste Management Plan
60.2055 What is a waste management plan?
60.2060 When must I submit my waste management plan?
60.2065 What should I include in my waste management plan?
Operator Training and Qualification
60.2070 What are the operator training and qualification requirements?
60.2075 When must the operator training course be completed?
60.2080 How do I obtain my operator qualification?
60.2085 How do I maintain my operator qualification?
60.2090 How do I renew my lapsed operator qualification?
60.2095 What site-specific documentation is required?
60.2100 What if all the qualified operators are temporarily not
accessible?
Emission Limitations and Operating Limits
60.2105 What emission limitations must I meet and by when?
60.2110 What operating limits must I meet and by when?
60.2115 What if I do not use a wet scrubber to comply with the emission
limitations?
60.2120 What happens during periods of startup, shutdown, and
malfunction?
Performance Testing
60.2125 How do I conduct the initial and annual performance test?
60.2130 How are the performance test data used?
Initial Compliance Requirements
60.2135 How do I demonstrate initial compliance with the emission
limitations and establish the operating limits?
60.2140 By what date must I conduct the initial performance test?
Continuous Compliance Requirements
60.2145 How do I demonstrate continuous compliance with the emission
limitations and the operating limits?
60.2150 By what date must I conduct the annual performance test?
60.2155 May I conduct performance testing less often?
60.2160 May I conduct a repeat performance test to establish new
operating limits?
Monitoring
60.2165 What monitoring equipment must I install and what parameters
must I monitor?
60.2170 Is there a minimum amount of monitoring data I must obtain?
Recordkeeping and Reporting
60.2175 What records must I keep?
60.2180 Where and in what format must I keep my records?
60.2185 What reports must I submit?
60.2190 What must I submit prior to commencing construction?
60.2195 What information must I submit prior to initial startup?
60.2200 What information must I submit following my initial performance
test?
60.2205 When must I submit my annual report?
60.2210 What information must I include in my annual report?
60.2215 What else must I report if I have a deviation from the operating
limits or the emission limitations?
60.2220 What must I include in the deviation report?
60.2225 What else must I report if I have a deviation from the
requirement to have a qualified operator accessible?
60.2230 Are there any other notifications or reports that I must submit?
60.2235 In what form can I submit my reports?
60.2240 Can reporting dates be changed?
[[Page 21]]
Title V Operating Permits
60.2242 Am I required to apply for and obtain a title V operating permit
for my unit?
Air Curtain Incinerators
60.2245 What is an air curtain incinerator?
60.2250 What are the emission limitations for air curtain incinerators?
60.2255 How must I monitor opacity for air curtain incinerators?
60.2260 What are the recordkeeping and reporting requirements for air
curtain incinerators?
Definitions
60.2265 What definitions must I know?
Table 1 to Subpart CCCC--Emission Limitations
Table 2 to Subpart CCCC--Operating Limits for Wet Scrubbers
Table 3 to Subpart CCCC--Toxic Equivalency Factors
Table 4 to Subpart CCCC--Summary of Reporting Requirements
Subpart DDDD_Emissions Guidelines and Compliance Times for Commercial
and Industrial Solid Waste Incineration Units that Commenced
Construction On or Before November 30, 1999
Introduction
60.2500 What is the purpose of this subpart?
60.2505 Am I affected by this subpart?
60.2510 Is a State plan required for all States?
60.2515 What must I include in my State plan?
60.2520 Is there an approval process for my State plan?
60.2525 What if my State plan is not approvable?
60.2530 Is there an approval process for a negative declaration letter?
60.2535 What compliance schedule must I include in my State plan?
60.2540 Are there any State plan requirements for this subpart that
apply instead of the requirements specified in subpart B?
60.2545 Does this subpart directly affect CISWI unit owners and
operators in my State?
Applicability of State Plans
60.2550 What CISWI units must I address in my State plan?
60.2555 What combustion units are exempt from my State plan?
60.2558 What if a chemical recovery unit is not listed in Sec.
60.2555(n)?
Use of Model Rule
60.2560 What is the ``model rule'' in this subpart?
60.2565 How does the model rule relate to the required elements of my
State plan?
60.2570 What are the principal components of the model rule?
Model Rule--Increments of Progress
60.2575 What are my requirements for meeting increments of progress and
achieving final compliance?
60.2580 When must I complete each increment of progress?
60.2585 What must I include in the notifications of achievement of
increments of progress?
60.2590 When must I submit the notifications of achievement of
increments of progress?
60.2595 What if I do not meet an increment of progress?
60.2600 How do I comply with the increment of progress for submittal of
a control plan?
60.2605 How do I comply with the increment of progress for achieving
final compliance?
60.2610 What must I do if I close my CISWI unit and then restart it?
60.2615 What must I do if I plan to permanently close my CISWI unit and
not restart it?
Model Rule--Waste Management Plan
60.2620 What is a waste management plan?
60.2625 When must I submit my waste management plan?
60.2630 What should I include in my waste management plan?
Model Rule--Operator Training and Qualification
60.2635 What are the operator training and qualification requirements?
60.2640 When must the operator training course be completed?
60.2645 How do I obtain my operator qualification?
60.2650 How do I maintain my operator qualification?
60.2655 How do I renew my lapsed operator qualification?
60.2660 What site-specific documentation is required?
60.2665 What if all the qualified operators are temporarily not
accessible?
Model Rule--Emission Limitations and Operating Limits
60.2670 What emission limitations must I meet and by when?
60.2675 What operating limits must I meet and by when?
60.2680 What if I do not use a wet scrubber to comply with the emission
limitations?
[[Page 22]]
60.2685 What happens during periods of startup, shutdown, and
malfunction?
Model Rule--Performance Testing
60.2690 How do I conduct the initial and annual performance test?
60.2695 How are the performance test data used?
Model Rule--Initial Compliance Requirements
60.2700 How do I demonstrate initial compliance with the emission
limitations and establish the operating limits?
60.2705 By what date must I conduct the initial performance test?
Model Rule--Continuous Compliance Requirements
60.2710 How do I demonstrate continuous compliance with the emission
limitations and the operating limits?
60.2715 By what date must I conduct the annual performance test?
60.2720 May I conduct performance testing less often?
60.2725 May I conduct a repeat performance test to establish new
operating limits?
Model Rule--Monitoring
60.2730 What monitoring equipment must I install and what parameters
must I monitor?
60.2735 Is there a minimum amount of monitoring data I must obtain?
Model Rule--Recordkeeping and Reporting
60.2740 What records must I keep?
60.2745 Where and in what format must I keep my records?
60.2750 What reports must I submit?
60.2755 When must I submit my waste management plan?
60.2760 What information must I submit following my initial performance
test?
60.2765 When must I submit my annual report?
60.2770 What information must I include in my annual report?
60.2775 What else must I report if I have a deviation from the operating
limits or the emission limitations?
60.2780 What must I include in the deviation report?
60.2785 What else must I report if I have a deviation from the
requirement to have a qualified operator accessible?
60.2790 Are there any other notifications or reports that I must submit?
60.2795 In what form can I submit my reports?
60.2800 Can reporting dates be changed?
Model Rule--Title V Operating Permits
60.2805 Am I required to apply for and obtain a title V operating permit
for my unit?
Model Rule--Air Curtain Incinerators
60.2810 What is an air curtain incinerator?
60.2815 What are my requirements for meeting increments of progress and
achieving final compliance?
60.2820 When must I complete each increment of progress?
60.2825 What must I include in the notifications of achievement of
increments of progress?
60.2830 When must I submit the notifications of achievement of
increments of progress?
60.2835 What if I do not meet an increment of progress?
60.2840 How do I comply with the increment of progress for submittal of
a control plan?
60.2845 How do I comply with the increment of progress for achieving
final compliance?
60.2850 What must I do if I close my air curtain incinerator and then
restart it?
60.2855 What must I do if I plan to permanently close my air curtain
incinerator and not restart it?
60.2860 What are the emission limitations for air curtain incinerators?
60.2865 How must I monitor opacity for air curtain incinerators?
60.2870 What are the recordkeeping and reporting requirements for air
curtain incinerators?
Model Rule--Definitions
60.2875 What definitions must I know?
Table 1 to Subpart DDDD--Model Rule--Increments of Progress and
Compliance Schedules
Table 2 to Subpart DDDD--Model Rule--Emission Limitations
Table 3 to Subpart DDDD--Model Rule--Operating Limits for Wet Scrubbers
Table 4 to Subpart DDDD--Model Rule--Toxic Equivalency Factors
Table 5 to Subpart DDDD--Model Rule--Summary of Reporting Requirements
Subpart EEEE_Standards of Performance for 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
Introduction
60.2880 What does this subpart do?
60.2881 When does this subpart become effective?
[[Page 23]]
Applicability
60.2885 Does this subpart apply to my incineration unit?
60.2886 What is a new incineration unit?
60.2887 What combustion units are excluded from this subpart?
60.2888 Are air curtain incinerators regulated under this subpart?
60.2889 Who implements and enforces this subpart?
60.2890 How are these new source performance standards structured?
60.2891 Do all components of these new source performance standards
apply at the same time?
Preconstruction Siting Analysis
60.2894 Who must prepare a siting analysis?
60.2895 What is a siting analysis?
Waste Management Plan
60.2899 What is a waste management plan?
60.2900 When must I submit my waste management plan?
60.2901 What should I include in my waste management plan?
Operator Training and Qualification
60.2905 What are the operator training and qualification requirements?
60.2906 When must the operator training course be completed?
60.2907 How do I obtain my operator qualification?
60.2908 How do I maintain my operator qualification?
60.2909 How do I renew my lapsed operator qualification?
60.2910 What site-specific documentation is required?
60.2911 What if all the qualified operators are temporarily not
accessible?
Emission Limitations and Operating Limits
60.2915 What emission limitations must I meet and by when?
60.2916 What operating limits must I meet and by when?
60.2917 What if I do not use a wet scrubber to comply with the emission
limitations?
60.2918 What happens during periods of startup, shutdown, and
malfunction?
Performance Testing
60.2922 How do I conduct the initial and annual performance test?
60.2923 How are the performance test data used?
Initial Compliance Requirements
60.2927 How do I demonstrate initial compliance with the emission
limitations and establish the operating limits?
60.2928 By what date must I conduct the initial performance test?
Continuous Compliance Requirements
60.2932 How do I demonstrate continuous compliance with the emission
limitations and the operating limits?
60.2933 By what date must I conduct the annual performance test?
60.2934 May I conduct performance testing less often?
60.2935 May I conduct a repeat performance test to establish new
operating limits?
Monitoring
60.2939 What continuous emission monitoring systems must I install?
60.2940 How do I make sure my continuous emission monitoring systems are
operating correctly?
60.2941 What is my schedule for evaluating continuous emission
monitoring systems?
60.2942 What is the minimum amount of monitoring data I must collect
with my continuous emission monitoring systems, and is the
data collection requirement enforceable?
60.2943 How do I convert my 1-hour arithmetic averages into the
appropriate averaging times and units?
60.2944 What operating parameter monitoring equipment must I install,
and what operating parameters must I monitor?
60.2945 Is there a minimum amount of operating parameter monitoring data
I must obtain?
Recordkeeping and Reporting
60.2949 What records must I keep?
60.2950 Where and in what format must I keep my records?
60.2951 What reports must I submit?
60.2952 What must I submit prior to commencing construction?
60.2953 What information must I submit prior to initial startup?
60.2954 What information must I submit following my initial performance
test?
60.2955 When must I submit my annual report?
60.2956 What information must I include in my annual report?
60.2957 What else must I report if I have a deviation from the operating
limits or the emission limitations?
60.2958 What must I include in the deviation report?
60.2959 What else must I report if I have a deviation from the
requirement to have a qualified operator accessible?
60.2960 Are there any other notifications or reports that I must submit?
60.2961 In what form can I submit my reports?
60.2962 Can reporting dates be changed?
[[Page 24]]
Title V Operating Permits
60.2966 Am I required to apply for and obtain a title V operating permit
for my unit?
60.2967 When must I submit a title V permit application for my new unit?
Temporary-Use Incinerators and Air Curtain Incinerators Used in Disaster
Recovery
60.2969 What are the requirements for temporary-use incinerators and air
curtain incinerators used in disaster recovery?
Air Curtain Incinerators That Burn Only Wood Waste, Clean Lumber, and
Yard Waste
60.2970 What is an air curtain incinerator?
60.2971 What are the emission limitations for air curtain incinerators
that burn only wood waste, clean lumber, and yard waste?
60.2972 How must I monitor opacity for air curtain incinerators that
burn only wood waste, clean lumber, and yard waste?
60.2973 What are the recordkeeping and reporting requirements for air
curtain incinerators that burn only wood waste, clean lumber,
and yard waste?
60.2974 Am I required to apply for and obtain a title V operating permit
for my air curtain incinerator that burns only wood waste,
clean lumber, and yard waste?
Equations
60.2975 What equations must I use?
Definitions
60.2977 What definitions must I know?
Tables to Subpart EEEE of Part 60
Table 1 to Subpart EEEE of Part 60--Emission Limitations
Table 2 to Subpart EEEE of Part 60--Operating Limits for Incinerators
and Wet Scrubbers
Table 3 to Subpart EEEE of Part 60--Requirements for Continuous Emission
Monitoring Systems (CEMS)
Table 4 to Subpart EEEE of Part 60--Summary of Reporting Requirements
Subpart FFFF_Emission Guidelines and Compliance Times for Other Solid
Waste Incineration Units That Commenced Construction On or Before
December 9, 2004
Introduction
60.2980 What is the purpose of this subpart?
60.2981 Am I affected by this subpart?
60.2982 Is a State plan required for all States?
60.2983 What must I include in my State plan?
60.2984 Is there an approval process for my State plan?
60.2985 What if my State plan is not approvable?
60.2986 Is there an approval process for a negative declaration letter?
60.2987 What compliance schedule must I include in my State plan?
60.2988 Are there any State plan requirements for this subpart that
apply instead of the requirements specified in subpart B of
this part?
60.2989 Does this subpart directly affect incineration unit owners and
operators in my State?
60.2990 What Authorities are withheld by EPA?
Applicability of State Plans
60.2991 What incineration units must I address in my State plan?
60.2992 What is an existing incineration unit?
60.2993 Are any combustion units excluded from my State plan?
60.2994 Are air curtain incinerators regulated under this subpart?
Model Rule--Use of Model Rule
60.2996 What is the purpose of the ``model rule'' in this subpart?
60.2997 How does the model rule relate to the required elements of my
State plan?
60.2998 What are the principal components of the model rule?
Model Rule--Compliance Schedule
60.3000 When must I comply?
60.3001 What must I do if I close my OSWI unit and then restart it?
60.3002 What must I do if I plan to permanently close my OSWI unit and
not restart it?
Model Rule--Waste Management Plan
60.3010 What is a waste management plan?
60.3011 When must I submit my waste management plan?
60.3012 What should I include in my waste management plan?
Model Rule--Operator Training and Qualification
60.3014 What are the operator training and qualification requirements?
60.3015 When must the operator training course be completed?
60.3016 How do I obtain my operator qualification?
60.3017 How do I maintain my operator qualification?
60.3018 How do I renew my lapsed operator qualification?
[[Page 25]]
60.3019 What site-specific documentation is required?
60.3020 What if all the qualified operators are temporarily not
accessible?
Model Rule--Emission Limitations and Operating Limits
60.3022 What emission limitations must I meet and by when?
60.3023 What operating limits must I meet and by when?
60.3024 What if I do not use a wet scrubber to comply with the emission
limitations?
60.3025 What happens during periods of startup, shutdown, and
malfunction?
Model Rule--Performance Testing
60.3027 How do I conduct the initial and annual performance test?
60.3028 How are the performance test data used?
Model Rule--Initial Compliance Requirements
60.3030 How do I demonstrate initial compliance with the emission
limitations and establish the operating limits?
60.3031 By what date must I conduct the initial performance test?
Model Rule--Continuous Compliance Requirements
60.3033 How do I demonstrate continuous compliance with the emission
limitations and the operating limits?
60.3034 By what date must I conduct the annual performance test?
60.3035 May I conduct performance testing less often?
60.3036 May I conduct a repeat performance test to establish new
operating limits?
Model Rule--Monitoring
60.3038 What continuous emission monitoring systems must I install?
60.3039 How do I make sure my continuous emission monitoring systems are
operating correctly?
60.3040 What is my schedule for evaluating continuous emission
monitoring systems?
60.3041 What is the minimum amount of monitoring data I must collect
with my continuous emission monitoring systems, and is the
data collection requirement enforceable?
60.3042 How do I convert my 1-hour arithmetic averages into the
appropriate averaging times and units?
60.3043 What operating parameter monitoring equipment must I install,
and what operating parameters must I monitor?
60.3044 Is there a minimum amount of operating parameter monitoring data
I must obtain?
Model Rule--Recordkeeping and Reporting
60.3046 What records must I keep?
60.3047 Where and in what format must I keep my records?
60.3048 What reports must I submit?
60.3049 What information must I submit following my initial performance
test?
60.3050 When must I submit my annual report?
60.3051 What information must I include in my annual report?
60.3052 What else must I report if I have a deviation from the operating
limits or the emission limitations?
60.3053 What must I include in the deviation report?
60.3054 What else must I report if I have a deviation from the
requirement to have a qualified operator accessible?
60.3055 Are there any other notifications or reports that I must submit?
60.3056 In what form can I submit my reports?
60.3057 Can reporting dates be changed?
Model Rule--Title V Operating Permits
60.3059 Am I required to apply for and obtain a title V operating permit
for my unit?
60.3060 When must I submit a title V permit application for my existing
unit?
Model Rule--Temporary-Use Incinerators and Air Curtain Incinerators Used
in Disaster Recovery
60.3061 What are the requirements for temporary-use incinerators and air
curtain incinerators used in disaster recovery?
Model Rule--Air Curtain Incinerators That Burn Only Wood Waste, Clean
Lumber, and Yard Waste
60.3062 What is an air curtain incinerator?
60.3063 When must I comply if my air curtain incinerator burns only wood
waste, clean lumber, and yard waste?
60.3064 What must I do if I close my air curtain incinerator that burns
only wood waste, clean lumber, and yard waste and then restart
it?
60.3065 What must I do if I plan to permanently close my air curtain
incinerator that burns only wood waste, clean lumber, and yard
waste and not restart it?
60.3066 What are the emission limitations for air curtain incinerators
that burn only wood waste, clean lumber, and yard waste?
60.3067 How must I monitor opacity for air curtain incinerators that
burn only wood waste, clean lumber, and yard waste?
60.3068 What are the recordkeeping and reporting requirements for air
curtain incinerators that burn only wood waste, clean lumber,
and yard waste?
[[Page 26]]
60.3069 Am I required to apply for and obtain a title V operating permit
for my air curtain incinerator that burns only wood waste,
clean lumber, and yard waste?
Model Rule--Equations
60.3076 What equations must I use?
Model Rule--Definitions
60.3078 What definitions must I know?
Tables to Subpart FFFF of Part 60
Table 1 to Subpart FFFF of Part 60--Model Rule--Compliance Schedule
Table 2 to Subpart FFFF of Part 60--Model Rule--Emission Limitations
Table 3 to Subpart FFFF of Part 60--Model Rule--Operating Limits for
Incinerators and Wet Scrubbers
Table 4 to Subpart FFFF of Part 60--Model Rule--Requirements for
Continuous Emission Monitoring Systems (CEMS)
Table 5 to Subpart FFFF of Part 60--Model Rule--Summary of Reporting
Requirements a
Subpart GGGG [Reserved]
Subpart HHHH_Emission Guidelines and Compliance Times for Coal-Fired
Electric Steam Generating Units
Hg Budget Trading Program General Provisions
60.4101 Purpose.
60.4102 Definitions.
60.4103 Measurements, abbreviations, and acronyms.
60.4104 Applicability.
60.4105 Retired unit exemption.
60.4106 Standard requirements.
60.4107 Computation of time.
60.4108 Appeal procedures.
Hg Designated Representative for Hg Budget Sources
60.4110 Authorization and responsibilities of Hg designated
representative.
60.4111 Alternate Hg designated representative.
60.4112 Changing Hg designated representative and alternate Hg
designated representative; changes in owners and operators.
60.4113 Certificate of representation.
60.4114 Objections concerning Hg designated representative.
Permits
60.4120 General Hg budget trading program permit requirements.
60.4121 Submission of Hg budget permit applications.
60.4122 Information requirements for Hg budget permit applications.
60.4123 Hg budget permit contents and term.
60.4124 Hg budget permit revisions.
60.4130 [Reserved]
Hg Allowance Allocations
60.4140 State trading budgets.
60.4141 Timing requirements for Hg allowance allocations.
60.4142 Hg allowance allocations.
Hg Allowance Tracking System
60.4150 [Reserved]
60.4151 Establishment of accounts.
60.4152 Responsibilities of Hg authorized account representative.
60.4153 Recordation of Hg allowance allocations.
60.4154 Compliance with Hg budget emissions limitation.
60.4155 Banking.
60.4156 Account error.
60.4157 Closing of general accounts.
Hg Allowance Transfers
60.4160 Submission of Hg allowance transfers.
60.4161 EPA recordation.
60.4162 Notification.
Monitoring and Reporting
60.4170 General requirements.
60.4171 Initial certification and recertification procedures.
60.4172 Out of control periods.
60.4173 Notifications.
60.4174 Recordkeeping and reporting.
60.4175 Petitions.
60.4176 Additional requirements to provide heat input data.
Subpart IIII_Standards of Performance for Stationary Compression
Ignition Internal Combustion Engines
What This Subpart Covers
60.4200 Am I subject to this subpart?
Emission Standards for Manufacturers
60.4201 What emission standards must I meet for non-emergency engines if
I am a stationary CI internal combustion engine manufacturer?
60.4202 What emission standards must I meet for emergency engines if I
am a stationary CI internal combustion engine manufacturer?
60.4203 How long must my engines meet the emission standards if I am a
stationary CI internal combustion engine manufacturer?
Emission Standards for Owners and Operators
60.4204 What emission standards must I meet for non-emergency engines if
I am
[[Page 27]]
an owner or operator of a stationary CI internal combustion
engine?
60.4205 What emission standards must I meet for emergency engines if I
am an owner or operator of a stationary CI internal combustion
engine?
60.4206 How long must I meet the emission standards if I am an owner or
operator of a stationary CI internal combustion engine?
Fuel Requirements for Owners and Operators
60.4207 What fuel requirements must I meet if I am an owner or operator
of a stationary CI internal combustion engine subject to this
subpart?
Other Requirements for Owners and Operators
60.4208 What is the deadline for importing and installing stationary CI
ICE produced in the previous model year?
60.4209 What are the monitoring requirements if I am an owner or
operator of a stationary CI internal combustion engine?
Compliance Requirements
60.4210 What are my compliance requirements if I am a stationary CI
internal combustion engine manufacturer?
60.4211 What are my compliance requirements if I am an owner or operator
of a stationary CI internal combustion engine?
Testing Requirements for Owners and Operators
60.4212 What test methods and other procedures must I use if I am an
owner or operator of a stationary CI internal combustion
engine with a displacement of less than 30 liters per
cylinder?
60.4213 What test methods and other procedures must I use if I am an
owner or operator of a stationary CI internal combustion
engine with a displacement of greater than or equal to 30
liters per cylinder?
Notification, Reports, and Records for Owners and Operators
60.4214 What are my notification, reporting, and recordkeeping
requirements if I am an owner or operator of a stationary CI
internal combustion engine?
Special Requirements
60.4215 What requirements must I meet for engines used in Guam, American
Samoa, or the Commonwealth of the Northern Mariana Islands?
60.4216 What requirements must I meet for engines used in Alaska?
60.4217 What emission standards must I meet if I am an owner or operator
of a stationary internal combustion engine using special
fuels?
General Provisions
60.4218 What parts of the General Provisions apply to me?
Definitions
60.4219 What definitions apply to this subpart?
Table 1 to Subpart IIII of Part 60--Emission Standards for Stationary
Pre-2007 Model Year Engines with a displacement of <10 liters
per cylinder and 2007-2010 Model Year Engines 2,237
KW (3,000 HP) and with a displacement of <10 liters per
cylinder
Table 2 to Subpart IIII of Part 60--Emission Standards for 2008 Model
Year and Later Emergency Stationary CI ICE <37 KW (50 HP) and
with a Displacement of <10 liters per cylinder
Table 3 to Subpart IIII of Part 60--Certification Requirements for
Stationary Fire Pump Engines
Table 4 to Subpart IIII of Part 60--Emission Standards for Stationary
Fire Pump Engines
Table 5 to Subpart IIII of Part 60--Labeling and Recordkeeping
Requirements for New Stationary Emergency Engines
Table 6 to Subpart IIII of Part 60--Optional 3-Mode Test Cycle for
Stationary Fire Pump Engines
Table 7 to Subpart IIII of Part 60--Requirements for Performance Tests
for Stationary CI ICE with a displacement of =30
liters per cylinder
Table 8 to Subpart IIII of Part 60--Applicability of General Provisions
to Subpart IIII
Subpart JJJJ_Standards of Performance for Stationary Spark Ignition
Internal Combustion Engines
What This Subpart Covers
60.4230 Am I subject to this subpart?
Emission Standards for Manufacturers
60.4231 What emission standards must I meet if I am a manufacturer of
stationary SI internal combustion engines or equipment
containing such engines?
60.4232 How long must my engines meet the emission standards if I am a
manufacturer of stationary SI internal combustion engines?
[[Page 28]]
Emission Standards for Owners and Operators
60.4233 What emission standards must I meet if I am an owner or operator
of a stationary SI internal combustion engine?
60.4234 How long must I meet the emission standards if I am an owner or
operator of a stationary SI internal combustion engine?
Other Requirements for Owners and Operators
60.4235 What fuel requirements must I meet if I am an owner or operator
of a stationary SI gasoline fired internal combustion engine
subject to this subpart?
60.4236 What is the deadline for importing or installing stationary SI
ICE produced in the previous model year?
60.4237 What are the monitoring requirements if I am an owner or
operator of an emergency stationary SI internal combustion
engine?
Compliance Requirements for Manufacturers
60.4238 What are my compliance requirements if I am a manufacturer of
stationary SI internal combustion engines <=19 KW (25 HP) or a
manufacturer of equipment containing such engines?
60.4239 What are my compliance requirements if I am a manufacturer of
stationary SI internal combustion engines 19 KW (25
HP) that use gasoline or a manufacturer of equipment
containing such engines?
60.4240 What are my compliance requirements if I am a manufacturer of
stationary SI internal combustion engines 19 KW (25
HP) that are rich burn engines that use LPG or a manufacturer
of equipment containing such engines?
60.4241 What are my compliance requirements if I am a manufacturer of
stationary SI internal combustion engines participating in the
voluntary certification program or a manufacturer of equipment
containing such engines?
60.4242 What other requirements must I meet if I am a manufacturer of
stationary SI internal combustion engines or equipment
containing stationary SI internal combustion engines or a
manufacturer of equipment containing such engines?
Compliance Requirements for Owners and Operators
60.4243 What are my compliance requirements if I am an owner or operator
of a stationary SI internal combustion engine?
Testing Requirements for Owners and Operators
60.4244 What test methods and other procedures must I use if I am an
owner or operator of a stationary SI internal combustion
engine?
Notification, Reports, and Records for Owners and Operators
60.4245 What are my notification, reporting, and recordkeeping
requirements if I am an owner or operator of a stationary SI
internal combustion engine?
General Provisions
60.4246 What parts of the General Provisions apply to me?
Mobile Source Provisions
60.4247 What parts of the mobile source provisions apply to me if I am a
manufacturer of stationary SI internal combustion engines or a
manufacturer of equipment containing such engines?
Definitions
60.4248 What definitions apply to this subpart?
Tables to Subpart JJJJ of Part 60
Table 1 to Subpart JJJJ of Part 60--NOX, CO, and VOC Emission
Standards for Stationary Non-Emergency SI Engines
=100 HP (Except Gasoline and Rich Burn LPG),
Stationary SI Landfill/Digester Gas Engines, and Stationary
Emergency Engines 25 HP
Table 2 to Subpart JJJJ of Part 60--Requirements for Performance Tests
Table 3 to Subpart JJJJ of Part 60--Applicability of General Provisions
to Subpart JJJJ
Table 4 to Subpart JJJJ of Part 60--Applicability of Mobile Source
Provisions for Manufacturers Participating in the Voluntary
Certification Program and Certifying Stationary SI ICE to
Emission Standards in Table 1 of Subpart JJJJ
Subpart KKKK_Standards of Performance for Stationary Combustion Turbines
Introduction
60.4300 What is the purpose of this subpart?
Applicability
60.4305 Does this subpart apply to my stationary combustion turbine?
60.4310 What types of operations are exempt from these standards of
performance?
[[Page 29]]
Emission Limits
60.4315 What pollutants are regulated by this subpart?
60.4320 What emission limits must I meet for nitrogen oxides
(NOX)?
60.4325 What emission limits must I meet for NOX if my
turbine burns both natural gas and distillate oil (or some
other combination of fuels)?
60.4330 What emission limits must I meet for sulfur dioxide
(SO2)?
General Compliance Requirements
60.4333 What are my general requirements for complying with this
subpart?
Monitoring
60.4335 How do I demonstrate compliance for NOX if I use
water or steam injection?
60.4340 How do I demonstrate continuous compliance for NOX if
I do not use water or steam injection?
60.4345 What are the requirements for the continuous emission monitoring
system equipment, if I choose to use this option?
60.4350 How do I use data from the continuous emission monitoring
equipment to identify excess emissions?
60.4355 How do I establish and document a proper parameter monitoring
plan?
60.4360 How do I determine the total sulfur content of the turbine's
combustion fuel?
60.4365 How can I be exempted from monitoring the total sulfur content
of the fuel?
60.4370 How often must I determine the sulfur content of the fuel?
Reporting
60.4375 What reports must I submit?
60.4380 How are excess emissions and monitor downtime defined for
NOX?
60.4385 How are excess emissions and monitoring downtime defined for
SO2?
60.4390 What are my reporting requirements if I operate an emergency
combustion turbine or a research and development turbine?
60.4395 When must I submit my reports?
Performance Tests
60.4400 How do I conduct the initial and subsequent performance tests,
regarding NOX?
60.4405 How do I perform the initial performance test if I have chosen
to install a NOX-diluent CEMS?
60.4410 How do I establish a valid parameter range if I have chosen to
continuously monitor parameters?
60.4415 How do I conduct the initial and subsequent performance tests
for sulfur?
Definitions
60.4420 What definitions apply to this subpart?
Table 1 to Subpart KKKK of Part 60-Nitrogen Oxide Emission Limits for
New Stationary Combustion Turbines
Authority: 42 U.S.C. 7401 et seq.
Source: 36 FR 24877, Dec. 23, 1971, unless otherwise noted.
Subpart A_General Provisions
Sec. 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
[[Page 30]]
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]
Sec. 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
[[Page 31]]
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 Sec. 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
[[Page 32]]
(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]
[[Page 33]]
Sec. 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
m\3\--cubic meter
mg--milligram--10 -3 gram
mm--millimeter--10 -3 meter
Mg--megagram--10\6\ gram
mol--mole
N--newton
ng--nanogram--10 -9 gram
nm--nanometer--10 -9 meter
Pa--pascal
s--second
V--volt
W--watt
[ohm]--ohm
[micro]g--microgram--10 -6 gram
(b) Other units of measure:
Btu--British thermal unit
[deg]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
[deg]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
[deg]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]
Sec. 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, Air Management Division, U.S. Environmental
Protection Agency, John F. Kennedy Federal Building, Boston, MA 02203.
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 and Waste Management
Division, U.S. Environmental Protection Agency, 345 Courtland Street,
NE., Atlanta, GA 30365.
Region V (Illinois, Indiana, Michigan, Minnesota, Ohio, Wisconsin),
Director, Air and Radiation Division, U.S. Environmental
[[Page 34]]
Protection Agency, 77 West Jackson Boulevard, Chicago, IL 60604-3590.
Region VI (Arkansas, Louisiana, New Mexico, Oklahoma, Texas); Director;
Air, Pesticides, and Toxics Division; U.S. Environmental Protection
Agency, 1445 Ross Avenue, Dallas, TX 75202.
Region VII (Iowa, Kansas, Missouri, Nebraska), Director, Air, RCRA, and
Toxics Division, U.S. Environmental Protection Agency, 901 N. 5th
Street, Kansas City, KS 66101.
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 (American Samoa, Arizona, California, Guam, Hawaii, Nevada,
Northern Mariana Islands), 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:
(A) [Reserved]
(B) State of Alabama: Alabama Department of Environmental
Management, P.O. Box 301463, Montgomery, Alabama 36130-1463.
(C) State of Alaska, Department of Environmental Conservation, Pouch
O, Juneau, AK 99811.
(D) Arizona:
Arizona Department of Environmental Quality, Office of Air Quality, P.O.
Box 600, Phoenix, AZ 85001-0600.
Maricopa County Air Pollution Control, 2406 S. 24th Street, Suite E-214,
Phoenix, AZ 85034.
Pima County Department of Environmental Quality, 130 West Congress
Street, 3rd Floor, Tucson, AZ 85701-1317.
Pinal County Air Quality Control District, Building F, 31 North Pinal
Street, Florence, AZ 85232.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(E) 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.
(F) California:
Amador County Air Pollution Control District, 500 Argonaut Lane,
Jackson, CA 95642.
Antelope Valley Air Pollution Control District, 43301 Division Street,
Suite 206, P.O. Box 4409, Lancaster, CA 93539-4409.
Bay Area Air Quality Management District, 939 Ellis Street, San
Francisco, CA 94109.
Butte County Air Pollution Control District, 2525 Dominic Drive, Suite
J, Chico, CA 95928-7184.
Calaveras County Air Pollution Control District, 891 Mountain Ranch Rd.,
San Andreas, CA 95249.
Colusa County Air Pollution Control District, 100 Sunrise Blvd., Suite
F, Colusa, CA 95932-3246.
El Dorado County Air Pollution Control District, 2850 Fairlane Court,
Bldg. C, Placerville, CA 95667-4100.
Feather River Air Quality Management District, 938 14th Street,
Marysville, CA 95901-4149.
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.
Kern County Air Pollution Control District (Southeast Desert), 2700 M.
Street, Suite 302, Bakersfield, CA 93301-2370.
Lake County Air Quality Management District, 885 Lakeport Blvd.,
Lakeport, CA 95453-5405.
Lassen County Air Pollution Control District, 175 Russell Avenue,
Susanville, CA 96130-4215.
Mariposa County Air Pollution Control District, P.O. Box 5, Mariposa, CA
95338.
Mendocino County Air Pollution Control District, 306 E. Gobbi Street,
Ukiah, CA 95482-5511.
Modoc County Air Pollution Control District, 202 W. 4th Street, Alturas,
CA 96101-3915.
Mojave Desert Air Quality Management District, 14306 Part Avenue,
Victorville, CA 92392-2310.
[[Page 35]]
Monterey Bay Unified Air Pollution Control District, 24580 Silver Cloud
Ct., Monterey, CA 93940-6536.
North Coast Unified Air Pollution Control District, 2300 Myrtle Avenue,
Eureka, CA 95501-3327.
Northern Sierra Air Quality Management District, 200 Litton Drive, 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, DeWitt Center, 11464 ``B''
Avenue, Auburn, CA 95603-2603.
Sacramento Metropolitan Air Quality Management District, 777 12th
Street, Third Floor, Sacramento, CA 95814-1908.
San Diego County Air Pollution Control District, 9150 Chesapeake Drive,
San Diego, CA 92123-1096.
San Joaquin Valley Unified Air Pollution Control District, 1999 Tuolumne
Street, 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, 26 Castilian Drive,
B-23, Goleta, CA 93117-3027.
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 E. Copley Drive,
Diamond Bar, CA 91765-4182.
Tehama County Air Pollution Control District, P.O. Box 38 (1750 Walnut
Street), Red Bluff, CA 96080-0038.
Tuolumne County Air Pollution Control District, 2 South Green Street,
Sonora, CA 95370-4618.
Ventura County Air Pollution Control District, 669 County Square Drive,
Ventura, CA 93003-5417.
Yolo-Solano Air Quality Management District, 1947 Galileo Ct., Suite
103, Davis, CA 95616-4882.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(G) 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.
(H) State of Connecticut, Bureau of Air Management, Department of
Environmental Protection, State Office Building, 165 Capitol Avenue,
Hartford, CT 06106.
(I) State of Delaware, Department of Natural Resources &
Environmental Control, 89 Kings Highway, P.O. Box 1401, Dover, Delaware
19903.
(J) District of Columbia, Department of Public Health, Air Quality
Division, 51 N Street, NE., Washington, DC 20002.
(K) State of Florida: Florida Department of Environmental
Protection, Division of Air Resources Management, 2600 Blair Stone Road,
MS 5500, Tallahassee, Florida 32399-2400.
(L) State of Georgia: Georgia Department of Natural Resources,
Environmental Protection Division, 2 Martin Luther King Jr. Drive, SE.,
Suite 1152 East Floyd Tower, Atlanta, Georgia 30334-9000.
(M) Hawaii:
Hawaii State Agency, Clean Air Branch, 919 Ala Moana Blvd., 3rd Floor,
Post Office Box 3378, Honolulu, HI 96814.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(N) State of Idaho, Department of Health and Welfare, Statehouse,
Boise, ID 83701.
(O) State of Illinois, Bureau of Air, Division of Air Pollution
Control, Illinois Environmental Protection Agency, 2200 Churchill Road,
Springfield, IL 62794-9276.
(P) State of Indiana, Indiana Department of Environmental
Management, 100 North Senate Avenue, P.O. Box 6015, Indianapolis,
Indiana 46206-6015.
(Q) State of Iowa: Iowa Department of Natural Resources,
Environmental Protection Division, Air Quality Bureau, 7900 Hickman
Road, Suite 1, Urbandale, IA 50322.
(R) State of Kansas: Kansas Department of Health and Environment,
Bureau of Air and Radiation, 1000 S.W. Jackson, Suite 310, Topeka, KS
66612-1366.
(S) Commonwealth of Kentucky: Commonwealth of Kentucky, Energy and
Environment Cabinet, Department of Environmental Protection, Division
for Air Quality, 200 Fair Oaks Lane, 1st Floor, Frankfort, Kentucky
40610-1403.
Louisville Metro Air Pollution Control District, 850 Barret Avenue,
Louisville, Kentucky 40204.
(T) State Louisiana: Louisiana Department of Environmental Quality,
P.O. Box 4301, Baton Rouge, Louisiana 70821-4301. For a list of
delegated standards for Louisiana (excluding Indian country), see
paragraph (e)(2) of this section.
(U) State of Maine, Bureau of Air Quality Control, Department of
Environmental Protection, State House, Station No. 17, Augusta, ME
04333.
(V) State of Maryland, Department of the Environment, 1800
Washington Boulevard, Suite 705, Baltimore, Maryland 21230.
(W) Commonwealth of Massachusetts, Division of Air Quality Control,
Department of
[[Page 36]]
Environmental Protection, One Winter Street, 7th floor, Boston, MA
02108.
(X) State of Michigan, Air Quality Division, Michigan Department of
Environmental Quality, P.O. Box 30260, Lansing, Michigan 48909.
(Y) Minnesota Pollution Control Agency, Division of Air Quality, 520
Lafayette Road, St. Paul, MN 55155.
(Z) State of Mississippi: Mississippi Department of Environmental
Quality, Office of Pollution Control, Air Division, 515 East Amite
Street, Jackson, Mississippi 39201.
(AA) State of Missouri: Missouri Department of Natural Resources,
Division of Environmental Quality, P.O. Box 176, Jefferson City, MO
65102.
(BB) 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.
(CC) 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
(DD) Nevada:
Nevada State Agency, Air Pollution Control, Bureau of Air Quality/
Division of Environmental Protection, 333 West Nye Lane, Carson City, NV
89710.
Clark County Department of Air Quality Management, 500 S. Grand Central
Parkway, First floor, Las Vegas, NV 89155-1776.
Washoe County Air Pollution Control, Washoe County District Air Quality
Management, P.O. Box 11130, 1001 E. Ninth Street, Reno, NV 89520.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(EE) State of New Hampshire, Air Resources Division, Department of
Environmental Services, 64 North Main Street, Caller Box 2033, Concord,
NH 03302-2033.
(FF) 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.
----------------------------------------------------------------------------------------------------------------
State
Subpart -----------------------------------------------------------------------
New Jersey New York Puerto Rico Virgin Islands
----------------------------------------------------------------------------------------------------------------
D Fossil-Fuel Fired Steam X............... X............... X............... X
Generators for Which
Construction Commenced
After August 17, 1971
(Steam Generators and
Lignite Fired Steam
Generators).
Da Electric Utility Steam X............... X...............
Generating Units for
Which Construction
Commenced After September
18, 1978.
Db Industrial-Commercial- X............... X............... X............... X
Institutional Steam
Generating Units.
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 X............... X............... X............... X
Categories).
K Storage Vessels for X............... X............... X............... X
Petroleum Liquids
Constructed After June
11, 1973, and prior to
May 19, 1978.
Ka Storage Vessels for X............... X............... X...............
Petroleum Liquids
Constructed After May 18,
1978.
L Secondary Lead Smelters... X............... X............... X............... X
M Secondary Brass and Bronze X............... X............... X............... X
Ingot Production Plants.
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 X............... X............... X............... X
Plants.
T Phosphate Fertilizer X............... X............... X............... X
Industry: Wet Process
Phosphoric Acid Plants.
U Phosphate Fertilizer X............... X............... X............... X
Industry: Superphosphoric
Acid Plants.
V Phosphate Fertilizer X............... X............... X............... X
Industry: Diammonium
Phosphate Plants.
W Phosphate Fertilizer X............... X............... X............... X
Industry: Triple
Superphosphate Plants.
X Phosphate Fertilizer X............... X............... X............... X
Industry: Granular Triple
Superphosphate.
Y Coal Preparation Plants... X............... X............... X............... X
Z Ferroally Production X............... X............... X............... X
Facilities.
AA Steel Plants: Electric Arc X............... X............... X............... X
Furnaces.
[[Page 37]]
AAa Electric Arc Furnaces and X............... X............... X...............
Argon-Oxygen
Decarburization Vessels
in Steel Plants.
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 X............... X............... X...............
Furniture.
GG Stationary Gas Turbines... X............... X............... X...............
HH Lime Plants............... X............... X............... X...............
KK Lead Acid Battery X............... X...............
Manufacturing Plants.
LL Metallic Mineral X............... X............... X...............
Processing Plants.
MM Automobile and Light-Duty X............... X...............
Truck Surface Coating
Operations.
NN Phosphate Rock Plants..... X............... X...............
PP Ammonium Sulfate X............... X...............
Manufacturing Plants.
QQ Graphic Art Industry X............... X............... X............... X
Publication Rotogravure
Printing.
RR Pressure Sensitive Tape X............... X............... X...............
and Label Surface Coating
Operations.
SS Industrial Surface X............... X............... X...............
Coating: Large Appliances.
TT Metal Coil Surface Coating X............... X............... X...............
UU Asphalt Processing and X............... X............... X...............
Asphalt Roofing
Manufacture.
VV Equipment Leaks of X............... X...............
Volatile Organic
Compounds in Synthetic
Organic Chemical
Manufacturing Industry.
WW Beverage Can Surface X............... X............... X...............
Coating Industry.
XX Bulk Gasoline Terminals... X............... X............... X...............
FFF Flexible Vinyl and X............... X............... X...............
Urethane Coating and
Printing.
GGG Equipment Leaks of VOC in X............... X...............
Petroleum Refineries.
HHH Synthetic Fiber Production X............... X...............
Facilities.
JJJ Petroleum Dry Clearners... X............... X............... X...............
KKK Equipment Leaks of VOC
from Onshore Natural Gas
Processing Plants.
LLL Onshore Natural Gas X...............
Processing Plants; SO2
Emissions.
OOO Nonmetallic Mineral X............... X...............
Processing Plants.
PPP Wool Fiberglass Insulation X............... X...............
Manufacturing Plants.
----------------------------------------------------------------------------------------------------------------
(GG) State of New Mexico: New Mexico Environment Department, 1190
St. Francis Drive, P.O. Box 26110, Santa Fe, New Mexico 87502. Note: For
a list of delegated standards for New Mexico (excluding Bernalillo
County and Indian country), see paragraph (e)(1) of this section.
(i) Albuquerque-Bernalillo County Air Quality Control Board, c/o
Environmental Health Department, P.O. Box 1293, Albuquerque, New Mexico
87103.
(ii) [Reserved]
(HH) New York: New York State Department of Environmental
Conservation, 50 Wolf Road Albany, New York 12233, attention: Division
of Air Resources.
(II) State of North Carolina: North Carolina Department of
Environment and Natural Resources, Division of Air Quality, 1641 Mail
Service Center, Raleigh, North Carolina 27699-1641.
Forsyth County Environmental Affairs, 537 North Spruce Street, Winston-
Salem, North Carolina 27101.
Mecklenburg County Air Quality, 700 N. Tryon St., Suite 205, Charlotte,
North Carolina 28202-2236.
Western North Carolina Regional Air Quality Agency, 49 Mount Carmel
Road, Asheville, North Carolina 28806.
(JJ) State of North Dakota, Division of Air Quality, North Dakota
Department of Health, P.O. Box 5520, Bismarck, ND 58506-5520.
Note: For a table listing Region VIII's NSPS delegation status, see
paragraph (c) of this section.
(KK) State of Ohio:
(i) Medina, Summit and Portage Counties; Director, Akron Regional
Air Quality Management District, 177 South Broadway, Akron, OH 44308.
(ii) Stark County: Air Pollution Control Division, 420 Market Avenue
North, Canton, Ohio 44702-3335.
(iii) Butler, Clermont, Hamilton, and Warren Counties: Air Program
Manager, Hamilton County Department of Environmental Services, 1632
Central Parkway, Cincinnati, Ohio 45210.
[[Page 38]]
(iv) Cuyahoga County: Commissioner, Department of Public Health &
Welfare, Division of Air Pollution Control, 1925 Saint Clair, Cleveland,
Ohio 44114.
(v) Belmont, Carroll, Columbiana, Harrison, Jefferson, and Monroe
Counties: Director, North Ohio Valley Air Authority (NOVAA), 814 Adams
Street, Steubenville, OH 43952.
(vi) Clark, Darke, Greene, Miami, Montgomery, and Preble Counties:
Director, Regional Air Pollution Control Agency (RAPCA) 451 West Third
Street, Dayton, Ohio 45402.
(vii) Lucas County and the City of Rossford (in Wood County):
Director, Toledo Environmental Services Agency, 26 Main Street, Toledo,
OH 43605.
(viii) Adams, Brown, Lawrence, and Scioto Counties; Engineer-
Director, Air Division, Portsmouth City Health Department, 740 Second
Street, Portsmouth, OH 45662.
(ix) 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 Dunbridge Rd.,
Bowling Green, Ohio 43402.
(x) Ashtabula, Holmes, Lorain, and Wayne Counties: Ohio
Environmental Protection Agency, Northeast District Office, Air
Pollution Unit, 2110 East Aurora Road, Twinsburg, OH 44087.
(xi) Athens, Coshocton, Gallia, Guernsey, Hocking, Jackson, Meigs,
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.
(xii) 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.
(xiii) Delaware, Fairfield, Fayette, Franklin, Knox, Licking,
Madison, Morrow, Pickaway, and Union Counties: Ohio Environmental
Protection Agency, Central District Office, Air Pollution Control, 3232
Alum Creek Drive, Columbus, Ohio, 43207-3417.
(xiv) Geauga and Lake Counties: Lake County General Health District,
Air Pollution Control, 105 Main Street, Painesville, OH 44077.
(xv) Mahoning and Trumbull Counties: Mahoning-Trumbull Air Pollution
Control Agency, 9 West Front Street, Youngstown, OH 44503.
(LL) 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.
(MM) 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.
(NN)(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.
(OO) State of Rhode Island, Division of Air and Hazardous Materials,
Department of Environmental Management, 291 Promenade Street,
Providence, RI 02908.
(PP) State of South Carolina: South Carolina Department of Health
and Environmental Control, 2600 Bull Street, Columbia, South Carolina
29201.
(QQ) State of South Dakota, Air Quality Program, Department of
Environment and Natural Resources, Joe Foss Building, 523 East Capitol,
Pierre, SD 57501-3181.
[[Page 39]]
Note: For a table listing Region VIII's NSPS delegation status, see
paragragh (c) of this section.
(RR) State of Tennessee: Tennessee Department of Environment and
Conservation, Division of Air Pollution Control, 401 Church Street, 9th
Floor, L&C Annex, Nashville, Tennessee 37243-1531.
Knox County Air Quality Management--Department of Public Health, 140
Dameron Avenue, Knoxville, TN 37917.
Air Pollution Control Bureau, Metropolitan Health Department, 311 23rd
Avenue North, Nashville, TN 37203.
Chattanooga-Hamilton County Air Pollution Control Bureau, 6125
Preservation Drive, Chattanooga, TN 37416.
Memphis-Shelby County Health Department--Air Pollution Control Program,
814 Jefferson Avenue, Memphis, TN 38105.
(SS) State of Texas, Texas Air Control Board, 6330 Highway 290 East,
Austin, TX 78723.
(TT) 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.
(UU) State of Vermont, Air Pollution Control Division, Agency of
Natural Resources, Building 3 South, 103 South Main Street, Waterbury,
VT 05676.
(VV) Commonwealth of Virginia, Department of Environmental Quality,
629 East Main Street, Richmond, Virginia 23219.
(WW) 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
Washington
-----------------------------------------------------------------------------------------------
Subpart \1\ 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..............
[[Page 40]]
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 X X X X X X X X
Construction is Commenced after August 17, 1971........
Da Electric Utility Steam Generating Units for which X X X X X X X X
Construction is Commenced after September 18, 1978.....
Db Industrial-Commercial-Institutional Steam Generating X X X X X X X X
Units..................................................
Dc Small Industrial-Commercial-Institutional Steam X X X X X X X X
Generating Units.......................................
E Incinerators.......................................... X X X X X X X X
Ea Municipal Waste Combustors for which Construction is X X X X X X X X
Commenced after December 20, 1989 and on or before
September 20, 1994.....................................
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 X X X X X X X X
Construction, Reconstruction, or Modification Commenced
after June 11, 1973 and prior to May 19, 1978..........
Ka Storage Vessels for Petroleum Liquids for which X X X X X X X X
Construction, Reconstruction, or Modification Commenced
after May 18, 1978 and prior to July 23, 1984..........
Kb VOC Liquid Storage Vessels (including Petroleum X X X X X X X X
Liquid Storage Vessels) for which Construction,
Reconstruction, or Modification Commenced after July
23, 1984...............................................
[[Page 41]]
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 X X X X X X X X
for which Construction is Commenced after June 11, 1973
Na Secondary Emissions from Basic Oxygen Process Steel- X X X X X X X X
making Facilities for which Construction is Commenced
after January 20, 1983.................................
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 X X X X X X X X
Acid Plants............................................
U Phosphate Fertilizer Industry: Superphosphoric Acid X X X X X X X X
Plants.................................................
V Phosphate Fertilizer Industry: Diammonium Phosphate X X X X X X X X
Plants.................................................
W Phosphate Fertilizer Industry: Triple Superphosphate X X X X X X X X
Plants.................................................
X Phosphate Fertilizer Industry: Granular Triple X X X X X X X X
Superphosphate Storage Facilities......................
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 X X X X X X X X
October 21, 1974 and on or before August 17, 1983......
AAa Steel Plants: Electric Arc Furnaces and Argon-Oxygen X X X X X X X X
Decarburization Vessels Constructed after August 7,
1983...................................................
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 X X X X X X X X
Operations.............................................
NN Phosphate Rock Plants................................ X X X X X X X X
[[Page 42]]
PP Ammonium Sulfate Manufacture......................... X X X X X X X X
QQ Graphic Arts Industry: Publication Rotogravure X X X X X X X X
Printing...............................................
RR Pressure Sensitive Tape and Label Surface Coating X X X X X X X X
Standards..............................................
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 X X X X X X X X
Manufacturing Industry.................................
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 X X X X X X X X
Manufacturing Industry Air Oxidation Unit Processes....
JJJ Petroleum Dry Cleaners.............................. X X X X X X X X
KKK Equipment Leaks of VOC from Onshore Natural Gas X X X X X X X X
Processing Plants......................................
LLL Onshore Natural Gas Processing: SO2 Emissions....... X X X X X X X X
NNN VOC Emissions from Synthetic Organic Chemical X X X X X X X X
Manufacturing Industry Distillation Operations.........
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 X X X X X X X X
Systems................................................
RRR VOCs from Synthetic Organic Chemical Manufacturing X X X X X X X X
Industry Reactor Processes.............................
SSS Magnetic Tape Coating Facilities.................... X X X X X X X X
[[Page 43]]
TTT Industrial Surface Coating: Surface Coating of X X X X X X X X
Plastic Parts for Business Machines....................
UUU Calciners and Dryers in Mineral Industries.......... X X X X X X X X
VVV Polymeric Coating of Supporting Substrates X X X X X X X X
Facilities.............................................
WWW Municipal Solid Waste Landfills..................... X X X X X X X X
AAAA Small Municipal Waste Combustion Units for which X X .......... X X X .......... X
Construction is Commenced after August 30, 1999 or for
which Modification or Reconstruction is Commenced after
June 6, 2001...........................................
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 X X .......... X X X .......... X
Units for which Construction is Commenced after
November, 30, 1999 or for which Modification or
Reconstruction is Commenced on or after June 1, 2001...
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.
(XX) State of West Virginia, Department of Environmental Protection,
Division of Air Quality, 601 57th Street, SE., Charleston, West Virginia
25304.
[[Page 44]]
(YY) Wisconsin--Wisconsin Department of Natural Resources, P.O. Box
7921, Madison, WI 53707.
(ZZ) 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.
(AAA) Territory of Guam: Guam Environmental Protection Agency, Post
Office Box 2999, Agana, Guam 96910.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(BBB) 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 Sec.
60.4(b)(FF)(1)).
(CCC) U.S. Virgin Islands: U.S. Virgin Islands Department of
Conservation and Cultural Affairs, P.O. Box 578, Charlotte Amalie, St.
Thomas, VI 00801.
(DDD) American Samoa Environmental Protection Agency, Pago Pago,
American Samoa 96799.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(EEE) Commonwealth of the Northern Mariana Islands, Division of
Environmental Quality, P.O. Box 1304, Saipan, MP 96950.
Note: For tables listing the delegation status of agencies in Region
IX, see paragraph (d) of this section.
(c) The following is a table indicating the delegation status of New
Source Performance Standards for Region VIII.
Delegation Status of New Source Performance Standards
[(NSPS) for Region VIII]
----------------------------------------------------------------------------------------------------------------
Subpart CO MT ND SD UT WY
----------------------------------------------------------------------------------------------------------------
A--General Provisions......................... (*) (*) (*) (*) (*) (*)
D--Fossil Fuel Fired Steam Generators......... (*) (*) (*) (*) (*) (*)
Da--Electric Utility Steam Generators......... (*) (*) (*) (*) (*) (*)
Db--Industrial-Commercial--Institutional Steam (*) (*) (*) (*) (*) (*)
Generators...................................
Dc--Industrial-Commercial-Institutional Steam (*) (*) (*) (*) (*) (*)
Generators...................................
E--Incinerators............................... (*) (*) (*) (*) (*) (*)
Ea--Municipal Waste Combustors................ (*) (*) (*) (*) (*) (*)
Eb--Large Municipal Waste Combustors.......... ......... (*) ......... (*) (*) (*)
Ec--Hospital/Medical/Infectious Waste (*) (*) (*) (*) (*) (*)
Incinerators.................................
F--Portland Cement Plants..................... (*) (*) (*) (*) (*) (*)
G--Nitric Acid Plants......................... (*) (*) (*) (*) (*)
H--Sulfuric Acid Plants....................... (*) (*) (*) (*) (*)
I--Asphalt Concrete Plants.................... (*) (*) (*) (*) (*) (*)
J--Petroleum Refineries....................... (*) (*) (*) (*) (*)
K--Petroleum Storage Vessels (after 6/11/73 & (*) (*) (*) (*) (*) (*)
prior to.....................................
5/19/78).....................................
Ka--Petroleum Storage Vessels (after 5/18/78 & (*) (*) (*) (*) (*) (*)
prior to.....................................
7/23/84).....................................
Kb--Petroleum Storage Vessels (after 7/23/84). (*) (*) (*) (*) (*) (*)
L--Secondary Lead Smelters.................... (*) (*) (*) (*)
M--Secondary Brass and Bronze Production......
Plants........................................ (*) (*) (*) (*)
N--Primary Emissions from Basic Oxygen Process (*) (*) (*) (*)
Furnaces (after 6/11/73).....................
Na--Secondary Emissions from Basic Oxygen (*) (*) (*) (*)
Process Furnaces (after 1/20/83).............
O--Sewage Treatment Plants.................... (*) (*) (*) (*) (*) (*)
P--Primary Copper Smelters.................... (*) (*) (*) (*)
Q--Primary Zinc Smelters...................... (*) (*) (*) (*)
R--Primary Lead Smelters...................... (*) (*) (*) (*)
S--Primary Aluminum Reduction Plants.......... (*) (*) (*) (*)
T--Phosphate Fertilizer Industry: Wet Process (*) (*) (*) (*) (*)
Phosphoric Plants............................
U--Phosphate Fertilizer Industry: (*) (*) (*) (*) (*)
Superphosphoric Acid Plants..................
[[Page 45]]
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.................... (*) (*) (*) (*) (*) (*)
Z--Ferroalloy Production Facilities........... (*) (*) (*) (*) (*)
AA--Steel Plants: Electric Arc Furnaces (10/21/ (*) (*) (*) (*) (*)
74-8/17/83)..................................
AAa--Steel Plants: Electric Arc Furnaces and (*) (*) (*) (*) (*)
Argon-Oxygen Decarburization Vessels (after 8/
7/83)........................................
BB--Kraft Pulp Mills.......................... (*) (*) (*) (*)
CC--Glass Manufacturing Plants................ (*) (*) (*) (*) (*)
DD--Grain Elevator............................ (*) (*) (*) (*) (*) (*)
EE--Surface Coating of Metal Furniture........ (*) (*) (*) (*) (*)
GG--Stationary Gas Turbines................... (*) (*) (*) (*) (*) (*)
HH--Lime Manufacturing Plants................. (*) (*) (*) (*) (*) (*)
KK--Lead-Acid Battery Manufacturing Plants.... (*) (*) (*) (*) (*)
LL--Metallic Mineral Processing Plants........ (*) (*) (*) (*) (*) (*)
MM--Automobile & Light Duty Truck Surface (*) (*) (*) (*) (*)
Coating Operations...........................
NN--Phosphate Rock Plants..................... (*) (*) (*) (*) (*)
PP--Ammonium Sulfate Manufacturing............ (*) (*) (*) (*) (*)
QQ--Graphic Arts Industry: Publication (*) (*) (*) (*) (*) (*)
Rotogravure Printing.........................
RR--Pressure Sensitive Tape & Label Surface (*) (*) (*) (*) (*) (*)
Coating......................................
SS--Industrial Surface Coating: Large (*) (*) (*) (*) (*)
Applications.................................
TT--Metal Coil Surface Coating................ (*) (*) (*) (*) (*)
UU--Asphalt Processing & Asphalt Roofing (*) (*) (*) (*) (*)
Manufacture..................................
VV--Synthetic Organic Chemicals Manufacturing: (*) (*) (*) (*) (*) (*)
Equipment Leaks of VOC.......................
WW--Beverage Can Surface Coating Industry..... (*) (*) (*) (*) (*)
XX--Bulk Gasoline Terminals................... (*) (*) (*) (*) (*) (*)
AAA--Residential Wood Heaters................. (*) (*) (*) (*) (*) (*)
BBB--Rubber Tires............................. (*) (*) (*) (*) (*)
DDD--VOC Emissions from Polymer Manufacturing (*) (*) (*) (*) (*)
Industry.....................................
FFF--Flexible Vinyl & Urethane Coating & (*) (*) (*) (*) (*)
Printing.....................................
GGG--Equipment Leaks of VOC in Petroleum (*) (*) (*) (*) (*)
Refineries...................................
HHH--Synthetic Fiber Production............... (*) (*) (*) (*) (*)
III--VOC Emissions from the Synthetic Organic (*) (*) (*) (*)
Chemical Manufacturing Industry Air Oxidation
Unit Processes...............................
JJJ--Petroleum Dry Cleaners................... (*) (*) (*) (*) (*) (*)
KKK--Equipment Leaks of VOC from Onshore (*) (*) (*) (*) (*)
Natural Gas Processing Plants................
LLL--Onshore Natural Gas Processing: SO2 (*) (*) (*) (*) (*)
Emissions....................................
NNN--VOC Emissions from the Synthetic Organic (*) (*) (*) (*) (*) (*)
Chemical Manufacturing Industry Distillation
Operations...................................
OOO--Nonmetallic Mineral Processing Plants.... (*) (*) (*) (*) (*) (*)
PPP--Wool Fiberglass Insulation Manufacturing (*) (*) (*) (*) (*)
Plants.......................................
QQQ--VOC Emissions from Petroleum Refinery (*) (*) (*) (*) (*)
Wastewater Systems...........................
RRR--VOC Emissions from Synthetic Organic (*) (*) (*) (*) (*) (*)
Chemistry Manufacturing Industry (SOCMI)
Reactor Processes............................
SSS--Magnetic Tape Industry................... (*) (*) (*) (*) (*) (*)
TTT--Plastic Parts for Business Machine (*) (*) (*) ......... (*) (*)
Coatings.....................................
UUU--Calciners and Dryers in Mineral (*) (*) (*) (*) (*) (*)
Industries...................................
VVV--Polymeric Coating of Supporting (*) (*) (*) ......... (*) (*)
Substrates...................................
WWW--Municipal Solid Waste Landfills.......... (*) (*) (*) (*) (*) (*)
AAAA-Small Municipal Waste Combustors......... ......... (*) (*) ......... (*) (*)
CCCC-Commercial and Industrial Solid Waste ......... (*) (*) ......... (*) (*)
Incineration Units...........................
[[Page 46]]
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................................
----------------------------------------------------------------------------------------------------------------
(*) Indicates approval of State regulation.
(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: Sec. Sec. 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:
Delegation Status for New Source Performance Standards for Arizona
----------------------------------------------------------------------------------------------------------------
Air Pollution Control Agency
-----------------------------------------------
Subpart Arizona Maricopa Pima Pinal
DEQ County County County
----------------------------------------------------------------------------------------------------------------
A General Provisions................ X X X X
D Fossil-Fuel Fired Steam Generators X X X X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating X X X X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- X X X X
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating X X X X
Units.
E Incinerators...................... X X X X
Ea Municipal Waste Combustors X X X X
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Municipal Waste Combustors X X X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste X X X ..........
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants............ X X X X
G Nitric Acid Plants................ X X 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 X
Ja Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After May
14, 2007.
K Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X X X X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters........... X X X X
M Secondary Brass and Bronze X X X X
Production Plants.
N Primary Emissions from Basic X X X X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic X X X X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
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 X X X X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X X X X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X X X X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X X X X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X X X X
Granular Triple Superphosphate
Storage Facilities.
[[Page 47]]
Y Coal Preparation Plants........... X X X X
Z Ferroalloy Production Facilities.. X X X X
AA Steel Plants: Electric Arc X X X X
Furnaces Constructed After
October 21, 1974 and On or Before
August 17, 1983.
AAa Steel Plants: Electric Arc X X X X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
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 X X X X
Plants.
LL Metallic Mineral Processing Plants X X X X
MM Automobile and Light Duty Trucks X X X X
Surface Coating Operations.
NN Phosphate Rock Plants............. X X X X
PP Ammonium Sulfate Manufacture...... X X X X
QQ Graphic Arts Industry: Publication X X X X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label X X X X
Surface Coating Operations.
SS Industrial Surface Coating: Large X X X X
Appliances.
TT Metal Coil Surface Coating........ X X X X
UU Asphalt Processing and Asphalt X X X X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X X X X
Synthetic Organic Chemicals
Manufacturing Industry.
VVa Equipment Leaks of VOC in the X
Synthetic Organic Chemicals
Manufacturing Industry for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
WW Beverage Can Surface Coating X X X X
Industry.
XX Bulk Gasoline Terminals........... X X X X
AAA New Residential Wool Heaters...... X X X X
BBB Rubber Tire Manufacturing Industry X X X X
CCC (Reserved)........................
DDD Volatile Organic Compounds (VOC) X X X X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................
FFF Flexible Vinyl and Urethane X X X X
Coating and Printing.
GGG Equipment Leaks of VOC in X X X X
Petroleum Refineries.
GGGa Equipment Leaks of VOC in X
Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
HHH Synthetic Fiber Production X X X X
Facilities.
III Volatile Organic Compound (VOC) X X X X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ X X X X
KKK Equipment Leaks of VOC From X X X X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X X X X
SO2 Emissions.
MMM (Reserved)........................
NNN Volatile Organic Compound (VOC) X X X X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X X X X
Plants.
PPP Wool Fiberglass Insulation X X X X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X X X X
Refinery Wastewater Systems.
RRR Volatile Organic Compound X X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities.. X X X X
TTT Industrial Surface Coating: X X X X
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral X X X
Industries.
VVV Polymeric Coating of Supporting X X X X
Substrates Facilities.
WWW Municipal Solid Waste Landfills... X X X
AAAA Small Municipal Waste Combustion X X X
Units for Which Construction is
Commenced After August 30, 1999
or for Which Modification or
Reconstruction is Commended After
June 6, 2001.
[[Page 48]]
CCCC Commercial and Industrial Solid X X X
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.
EEEE Other Solid Waste Incineration X X
Units for Which Construction is
Commenced After December 9, 2004,
or for Which Modification or
Reconstruction is Commenced on or
After June 16, 2006.
IIII Stationary Compression Ignition X
Internal Combustion Engines.
JJJJ Stationary Spark Ignition Internal
Combustion Engines.
KKKK Stationary Combustion Turbines.... X
GGGG (Reserved)........................ ..........
----------------------------------------------------------------------------------------------------------------
(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 Pollution Control District, Bay Area Air Quality
Management District, and Butte County Air Pollution Control District are
shown in the following table:
Delegation Status for New Source Performance Standards for Amador County APCD, Antelope Valley APCD, Bay Area
AQMD, and Butte County AQMD
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Subpart Amador Antelope Butte
County Valley Bay Area County
APCD APCD AQMD APCD
----------------------------------------------------------------------------------------------------------------
A General Provisions...................
D Fossil-Fuel Fired Steam Generators .......... .......... X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating .......... .......... X
Units Constructed After September
18, 1978.
Db Industrial-Commercial-Institutional .......... .......... X
Steam Generating Units.
Dc Small Industrial Steam Generating .......... .......... X
Units.
E Incinerators......................... .......... .......... X
Ea Municipal Waste Combustors .......... .......... X
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................... .......... .......... X
H Sulfuric Acid Plants................. .......... .......... X
I Hot Mix Asphalt Facilities........... .......... .......... X
J Petroleum Refineries................. .......... .......... X
K Storage Vessels for Petroleum Liquids .......... .......... X
for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973, and
Prior to May 19, 1978.
Ka Storage Vessels for Petroleum Liquids .......... .......... X
for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage .......... .......... X
Vessels (Including Petroleum Liquid
Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters.............. .......... .......... X
M Secondary Brass and Bronze Production .......... .......... X
Plants.
N Primary Emissions from Basic Oxygen .......... .......... X
Process Furnaces for Which
Construction is Commenced After June
11, 1973.
Na Secondary Emissions from Basic Oxygen .......... .......... X
Process Steelmaking Facilities for
Which Construction is Commenced
After January 20, 1983.
O Sewage Treatment Plants.............. .......... .......... X
P Primary Copper Smelters.............. .......... .......... X
Q Primary Zinc Smelters................ .......... .......... X
[[Page 49]]
R Primary Lead Smelters................ .......... .......... X
S Primary Aluminum Reduction Plants.... .......... .......... X
T Phosphate Fertilizer Industry: Wet
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: .......... .......... X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: .......... .......... X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: Triple .......... .......... X
Superphosphate Plants.
X Phosphate Fertilizer Industry: .......... .......... X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants.............. .......... .......... X
Z Ferroalloy Production Facilities..... .......... .......... X
AA Steel Plants: Electric Arc Furnaces .......... .......... X
Constructed After October 21, 1974
and On or Before August 17, 1983.
AAa Steel Plants: Electric Arc Furnaces .......... .......... X
and Argon-Oxygen Decarburization
Vessels Constructed After August 7,
1983.
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 .......... .......... X
Plants.
LL Metallic Mineral Processing Plants... .......... .......... X
MM Automobile and Light Duty Trucks .......... .......... X
Surface Coating Operations.
NN Phosphate Rock Plants................ .......... .......... X
PP Ammonium Sulfate Manufacture......... .......... .......... X
QQ Graphic Arts Industry: Publication .......... .......... X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label .......... .......... X
Surface Coating Operations.
SS Industrial Surface Coating: Large .......... .......... X
Appliances.
TT Metal Coil Surface Coating........... .......... .......... X
UU Asphalt Processing and Asphalt .......... .......... X
Roofing Manufacture.
VV Equipment Leaks of VOC in the .......... .......... X
Synthetic Organic Chemicals
Manufacturing Industry.
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) .......... .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)...........................
FFF Flexible Vinyl and Urethane Coating .......... .......... X
and Printing.
GGG Equipment Leaks of VOC in Petroleum .......... .......... X
Refineries.
HHH Synthetic Fiber Production Facilities .......... .......... X
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 .......... .......... X
Natural Gas Processing Plants.
LLL Onshore Natural Gas Processing: SO2
Emissions.
MMM (Reserved)...........................
NNN Volatile Organic Compound (VOC) .......... .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing Plants .......... .......... X
PPP Wool Fiberglass Insulation .......... .......... X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum Refinery
Wastewater Systems.
RRR Volatile Organic Compound Emissions
from Synthetic Organic Chemical
Manufacturing Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating Facilities..... .......... .......... X
TTT Industrial Surface Coating: Surface .......... .......... X
Coating of Plastic Parts for
Business Machines.
UUU Calciners and Dryers in Mineral .......... .......... X
Industries.
VVV Polymeric Coating of Supporting .......... .......... X
Substrates Facilities.
WWW Municipal Solid Waste Landfills......
----------------------------------------------------------------------------------------------------------------
[[Page 50]]
(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
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Great
Subpart Glenn Basin Imperial Kern
County Unified County County
APCD APCD APCD APCD
----------------------------------------------------------------------------------------------------------------
A General Provisions................ .......... X .......... X
D Fossil-Fuel Fired Steam Generators .......... X .......... X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating .......... X .......... X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- .......... X .......... X
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating .......... X .......... X
Units.
E Incinerators...................... .......... X .......... X
Ea Municipal Waste Combustors .......... X
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 .......... 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 .......... X .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum .......... X .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage .......... X .......... X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters........... .......... X .......... X
M Secondary Brass and Bronze .......... X .......... X
Production Plants.
N Primary Emissions from Basic .......... X .......... X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic .......... X .......... X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
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 .......... X .......... X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: .......... X .......... X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: .......... X .......... X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: .......... X .......... X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: .......... X .......... X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants........... .......... X .......... X
Z Ferroalloy Production Facilities.. .......... X .......... X
AA Steel Plants: Electric Arc .......... X .......... X
Furnaces Constructed After
October 21, 1974 and On or Before
August 17, 1983.
AAa Steel Plants: Electric Arc .......... X .......... X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
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 .......... X .......... X
Plants.
LL Metallic Mineral Processing Plants .......... X .......... X
[[Page 51]]
MM Automobile and Light Duty Trucks .......... X .......... X
Surface Coating Operations.
NN Phosphate Rock Plants............. .......... X .......... X
PP Ammonium Sulfate Manufacture...... .......... X .......... X
QQ Graphic Arts Industry: Publication .......... X .......... X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label .......... X .......... X
Surface Coating Operations.
SS Industrial Surface Coating: Large .......... X .......... X
Appliances.
TT Metal Coil Surface Coating........ .......... X .......... X
UU Asphalt Processing and Asphalt .......... X .......... X
Roofing Manufacture.
VV Equipment Leaks of VOC in the .......... X .......... X
Synthetic Organic Chemicals
Manufacturing Industry.
WW Beverage Can Surface Coating .......... X .......... X
Industry.
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) .......... X .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................
FFF Flexible Vinyl and Urethane .......... X .......... X
Coating and Printing.
GGG Equipment Leaks of VOC in .......... X .......... X
Petroleum Refineries.
HHH Synthetic Fiber Production .......... X .......... X
Facilities.
III Volatile Organic Compound (VOC) .......... X .......... X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ .......... X .......... X
KKK Equipment Leaks of VOC From .......... X .......... X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: .......... .......... .......... X
SO2 Emissions.
MMM (Reserved)........................ .......... .......... .......... ..........
NNN Volatile Organic Compound (VOC) .......... X .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing .......... X .......... X
Plants.
PPP Wool Fiberglass Insulation .......... X .......... X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum .......... X .......... X
Refinery Wastewater Systems.
RRR Volatile Organic Compound .......... .......... .......... X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities.. .......... X .......... X
TTT Industrial Surface Coating: .......... X X ..........
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral .......... X .......... X
Industries.
VVV Polymeric Coating of Supporting .......... X .......... X
Substrates Facilities.
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
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Subpart Lake Lassen Mariposa Mendocino
County County County County
AQMD APCD AQMD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions................ X .......... .......... X
D Fossil-Fuel Fired Steam Generators X .......... .......... X
Constructed After August 17, 1971.
[[Page 52]]
Da Electric Utility Steam Generating X .......... .......... X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- X
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating X .......... .......... X
Units.
E Incinerators...................... X .......... .......... X
Ea Municipal Waste Combustors X .......... .......... X
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 .......... .......... 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 X .......... .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X .......... .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X .......... .......... X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters........... X .......... .......... X
M Secondary Brass and Bronze X .......... .......... X
Production Plants.
N Primary Emissions from Basic X .......... .......... X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic X .......... .......... X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
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 X .......... .......... X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X .......... .......... X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X .......... .......... X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X .......... .......... X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X .......... .......... X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants........... X .......... .......... X
Z Ferroalloy Production Facilities.. X .......... .......... X
AA Steel Plants: Electric Arc X .......... .......... X
Furnaces Constructed After
October 21, 1974 and On or Before
August 17, 1983.
AAa Steel Plants: Electric Arc X .......... .......... X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
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 X .......... .......... X
Plants.
LL Metallic Mineral Processing Plants X .......... .......... X
MM Automobile and Light Duty Trucks X .......... .......... X
Surface Coating Operations.
NN Phosphate Rock Plants............. X .......... .......... X
PP Ammonium Sulfate Manufacture...... X .......... .......... X
QQ Graphic Arts Industry: Publication X .......... .......... X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label X .......... .......... X
Surface Coating Operations.
SS Industrial Surface Coating: Large X .......... .......... X
Appliances.
TT Metal Coil Surface Coating........ X .......... .......... X
[[Page 53]]
UU Asphalt Processing and Asphalt X .......... .......... X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X .......... .......... X
Synthetic Organic Chemicals
Manufacturing Industry.
WW Beverage Can Surface Coating X .......... .......... X
Industry.
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) X .......... .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................
FFF Flexible Vinyl and Urethane X .......... .......... X
Coating and Printing.
GGG Equipment Leaks of VOC in X .......... .......... X
Petroleum Refineries.
HHH Synthetic Fiber Production X .......... .......... X
Facilities.
III Volatile Organic Compound (VOC) X .......... .......... X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ X .......... .......... X
KKK Equipment Leaks of VOC From X .......... .......... X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X .......... .......... X
SO2 Emissions.
MMM (Reserved)........................ .......... .......... .......... ..........
NNN Volatile Organic Compound (VOC) X .......... .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X .......... .......... X
Plants.
PPP Wool Fiberglass Insulation X .......... .......... X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X .......... .......... X
Refinery Wastewater Systems.
RRR Volatile Organic Compound X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
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 X .......... .......... X
Industries.
VVV Polymeric Coating of Supporting X .......... .......... X
Substrates Facilities.
WWW Municipal Solid Waste Landfills... X .......... .......... ..........
----------------------------------------------------------------------------------------------------------------
(v) Delegations for Modoc County Air Pollution Control District,
Mojave Desert Air Quality Management District, Monterey Bay Unified Air
Pollution Control District, and North Coast Unified Air Pollution
Control District are shown in the following table:
Delegation Status for New Source Performance Standards for Modoc County Air Pollution Control District, Mojave
Desert Air Quality Management District, Monterey Bay Unified Air Pollution Control District, and North Coast
Unified Air Pollution Control District
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-----------------------------------------------
Monterey North
Subpart Modoc Mojave Bay Coast
County Desert Unified Unified
APCD AQMD APCD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions................... X .......... X X
D Fossil-Fuel Fired Steam Generators X X X X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating X .......... X X
Units Constructed After September
18, 1978.
Db Industrial-Commercial-Institutional X .......... X X
Steam Generating Units.
Dc Small Industrial Steam Generating .......... .......... X
Units.
[[Page 54]]
E Incinerators......................... X X X X
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 X X X
G Nitric Acid Plants................... X X X X
H Sulfuric Acid Plants................. X X X X
I Hot Mix Asphalt Facilities........... X X X X
J Petroleum Refineries................. X X X X
K Storage Vessels for Petroleum Liquids X X X X
for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973, and
Prior to May 19, 1978.
Ka Storage Vessels for Petroleum Liquids X .......... X X
for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X .......... X X
Vessels (Including Petroleum Liquid
Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters.............. X X X X
M Secondary Brass and Bronze Production X X X X
Plants.
N Primary Emissions from Basic Oxygen X X X X
Process Furnaces for Which
Construction is Commenced After June
11, 1973.
Na Secondary Emissions from Basic Oxygen X .......... X X
Process Steelmaking Facilities for
Which Construction is Commenced
After January 20, 1983.
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 X X X X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X X X X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X X X X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: Triple X X X X
Superphosphate Plants.
X Phosphate Fertilizer Industry: X X X X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants.............. X X X X
Z Ferroalloy Production Facilities..... X .......... X X
AA Steel Plants: Electric Arc Furnaces X X X X
Constructed After October 21, 1974
and On or Before August 17, 1983.
AAa Steel Plants: Electric Arc Furnaces X .......... X X
and Argon-Oxygen Decarburization
Vessels Constructed After August 7,
1983.
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
FF (Reserved)...........................
GG Stationary Gas Turbines.............. X .......... X X
HH Lime Manufacturing Plants............ X .......... X X
KK Lead-Acid Battery Manufacturing X .......... X X
Plants.
LL Metallic Mineral Processing Plants... X .......... X X
MM Automobile and Light Duty Trucks X .......... X X
Surface Coating Operations.
NN Phosphate Rock Plants................ X .......... X X
PP Ammonium Sulfate Manufacture......... X .......... X X
QQ Graphic Arts Industry: Publication X .......... X X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label X .......... X X
Surface Coating Operations.
SS Industrial Surface Coating: Large X .......... X X
Appliances.
TT Metal Coil Surface Coating........... X .......... X X
UU Asphalt Processing and Asphalt X .......... X X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X .......... X X
Synthetic Organic Chemicals
Manufacturing Industry.
[[Page 55]]
WW Beverage Can Surface Coating Industry X .......... X X
XX Bulk Gasoline Terminals..............
AAA New Residential Wool Heaters......... X .......... X X
BBB Rubber Tire Manufacturing Industry... X .......... X X
CCC (Reserved)...........................
DDD Volatile Organic Compounds (VOC) X .......... X
Emissions from the Polymer
manufacturing Industry.
EEE (Reserved)...........................
FFF Flexible Vinyl and Urethane Coating X .......... X X
and Printing.
GGG Equipment Leaks of VOC in Petroleum X .......... X X
Refineries.
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.
JJJ Petroleum Dry Cleaners............... X .......... X X
KKK Equipment Leaks of VOC From Onshore X .......... X X
Natural Gas Processing Plants.
LLL Onshore Natural Gas Processing: SO2 X .......... X X
Emissions.
MMM (Reserved)...........................
NNN Volatile Organic Compound (VOC) X .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing Plants X .......... X X
PPP Wool Fiberglass Insulation X .......... X X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum Refinery X .......... X X
Wastewater Systems.
RRR Volatile Organic Compound Emissions
from Synthetic Organic Chemical
Manufacturing Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating Facilities..... X .......... X X
TTT Industrial Surface Coating: Surface X .......... X X
Coating of Plastic Parts for
Business Machines.
UUU Calciners and Dryers in Mineral .......... .......... X
Industries.
VVV Polymeric Coating of Supporting .......... .......... X X
Substrates Facilities.
WWW Municipal Solid Waste Landfills...... .......... .......... .......... ..........
----------------------------------------------------------------------------------------------------------------
(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
----------------------------------------------------------------------------------------------------------------
Air pollution control agency
-------------------------------------------------
Northern
Subpart Northern Sonoma Placer Sacramento
Sierra County County Metropolitan
AQMD APCD APCD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions.................. .......... X .......... X
D Fossil-Fuel Fired Steam Generators .......... X .......... X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating .......... X .......... X
Units Constructed After September
18, 1978.
Db Industrial-Commercial-Institutional .......... .......... .......... X
Steam Generating Units.
Dc Small Industrial Steam Generating .......... .......... .......... X
Units.
E Incinerators........................ .......... X .......... X
[[Page 56]]
Ea Municipal Waste Combustors .......... .......... .......... X
Constructed After December 20, 1989
and On or Before September 20, 1994.
Eb Municipal Waste Combustors .......... .......... .......... X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste .......... .......... .......... X
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 .......... X .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973, and
Prior to May 19, 1978.
Ka Storage Vessels for Petroleum .......... X .......... X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage .......... .......... .......... X
Vessels (Including Petroleum Liquid
Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters............. .......... X .......... X
M Secondary Brass and Bronze .......... X .......... X
Production Plants.
N Primary Emissions from Basic Oxygen .......... X .......... X
Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic .......... .......... .......... X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20, 1983.
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 .......... X .......... X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: .......... X .......... X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: .......... X .......... X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: .......... X .......... X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: .......... X .......... X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants............. .......... X .......... X
Z Ferroalloy Production Facilities.... .......... X .......... X
AA Steel Plants: Electric Arc Furnaces .......... X .......... X
Constructed After October 21, 1974
and On or Before August 17, 1983.
AAa Steel Plants: Electric Arc Furnaces .......... .......... .......... X
and Argon-Oxygen Decarburization
Vessels Constructed After August 7,
1983.
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 .......... .......... .......... X
Plants.
LL Metallic Mineral Processing Plants.. .......... .......... .......... X
MM Automobile and Light Duty Trucks .......... X .......... X
Surface Coating Operations.
NN Phosphate Rock Plants............... .......... .......... .......... X
PP Ammonium Sulfate Manufacture........ .......... X .......... X
QQ Graphic Arts Industry: Publication .......... .......... .......... X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label .......... .......... .......... X
Surface Coating Operations.
SS Industrial Surface Coating: Large .......... .......... .......... X
Appliances.
TT Metal Coil Surface Coating.......... .......... .......... .......... X
UU Asphalt Processing and Asphalt .......... .......... .......... X
Roofing Manufacture.
VV Equipment Leaks of VOC in the .......... .......... .......... X
Synthetic Organic Chemicals
Manufacturing Industry.
[[Page 57]]
WW Beverage Can Surface Coating .......... .......... .......... X
Industry.
XX Bulk Gasoline Terminals.............
AAA New Residential Wool Heaters........ .......... .......... .......... X
BBB Rubber Tire Manufacturing Industry.. .......... .......... .......... X
CCC (Reserved)..........................
DDD Volatile Organic Compounds (VOC) .......... .......... .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)..........................
FFF Flexible Vinyl and Urethane Coating .......... .......... .......... X
and Printing.
GGG Equipment Leaks of VOC in Petroleum .......... .......... .......... X
Refineries.
HHH Synthetic Fiber Production .......... .......... .......... X
Facilities.
III Volatile Organic Compound (VOC) .......... .......... .......... X
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 .......... .......... .......... X
Natural Gas Processing Plants.
LLL Onshore Natural Gas Processing: SO2 .......... .......... .......... X
Emissions.
MMM (Reserved)..........................
NNN Volatile Organic Compound (VOC) .......... .......... .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing .......... .......... .......... X
Plants.
PPP Wool Fiberglass Insulation .......... .......... .......... X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum .......... .......... .......... X
Refinery Wastewater Systems.
RRR Volatile Organic Compound Emissions .......... .......... .......... X
from Synthetic Organic Chemical
Manufacturing Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating Facilities.... .......... .......... .......... X
TTT Industrial Surface Coating: Surface .......... .......... .......... X
Coating of Plastic Parts for
Business Machines.
UUU Calciners and Dryers in Mineral .......... .......... .......... X
Industries.
VVV Polymeric Coating of Supporting .......... .......... .......... X
Substrates Facilities.
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 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
----------------------------------------------------------------------------------------------------------------
Air Pollution Control Agency
-----------------------------------------------
San
Subpart San Diego Joaquin San Luis Santa
County Valley Obispo Barbara
APCD Unified County County
APCD APCD APCD
----------------------------------------------------------------------------------------------------------------
A General Provisions................ X X X X
D Fossil-Fuel Fired Steam Generators X X X X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating X X X X
Units Constructed After September
18, 1978.
Db Industrial-Commercial- X X X X
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating X X X
Units.
[[Page 58]]
E Incinerators...................... X X X X
Ea Municipal Waste Combustors X X X
Constructed After December 20,
1989, and On or Before September
20, 1994.
Eb Municipal Waste Combustors X X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste X
Incinerators for Which
Construction is Commenced After
June 20, 1996.
F Portland Cement Plants............ X X X
G Nitric Acid Plants................ X X X
H Sulfuric Acid Plants.............. 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.
K Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X X X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X X X X
Vessels (Including Petroleum
Liquid Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters........... X X X X
M Secondary Brass and Bronze X X X X
Production Plants.
N Primary Emissions from Basic X X X
Oxygen Process Furnaces for Which
Construction is Commenced After
June 11, 1973.
Na Secondary Emissions from Basic X X X
Oxygen Process Steelmaking
Facilities for Which Construction
is Commenced After January 20,
1983.
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 X X X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: X X X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X X X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X X X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X X X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants........... X X X
Z Ferroalloy Production Facilities.. X X X
AA Steel Plants: Electric Arc X X X
Furnaces Constructed After
October 21, 1974, and On or
Before August 17, 1983.
AAa Steel Plants: Electric Arc X X X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
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 X X X
Plants.
LL Metallic Mineral Processing Plants X X X
MM Automobile and Light Duty Trucks X X X
Surface Coating Operations.
NN Phosphate Rock Plants............. X X X
PP Ammonium Sulfate Manufacture...... X X X
QQ Graphic Arts Industry: Publication X X X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label X X X
Surface Coating Operations.
SS Industrial Surface Coating: Large X X X
Appliances.
TT Metal Coil Surface Coating........ X X X
[[Page 59]]
UU Asphalt Processing and Asphalt X X X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X X X
Synthetic Organic Chemicals
Manufacturing Industry.
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 X X X
Industry.
XX Bulk Gasoline Terminals...........
AAA New Residential Wool Heaters...... X X X X
BBB Rubber Tire Manufacturing Industry X X X
CCC (Reserved)........................
DDD Volatile Organic Compounds (VOC) X X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)........................
FFF Flexible Vinyl and Urethane X X X
Coating and Printing.
GGG Equipment Leaks of VOC in X X X
Petroleum Refineries.
GGGa Equipment Leaks of VOC in
Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
HHH Synthetic Fiber Production X X X
Facilities.
III Volatile Organic Compound (VOC) X X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners............ X X X
KKK Equipment Leaks of VOC From X X X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X X X
SO2 Emissions.
MMM (Reserved)........................
NNN Volatile Organic Compound (VOC) X X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X X X X
Plants.
PPP Wool Fiberglass Insulation X X X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X X X
Refinery Wastewater Systems.
RRR Volatile Organic Compound X X X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities.. X X X
TTT Industrial Surface Coating: X X X
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral X X X X
Industries.
VVV Polymeric Coating of Supporting X X X X
Substrates Facilities.
WWW Municipal Solid Waste Landfills... X X X X
AAAA Small Municipal Waste Combustion X
Units for Which Construction is
Commenced After August 30, 1999,
or for Which Modification or
Reconstruction is Commenced After
June 6, 2001.
CCCC Commercial and Industrial Solid X
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.
EEEE Other Solid Waste Incineration X
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.... ..........
----------------------------------------------------------------------------------------------------------------
(viii) Delegations for Shasta County Air Quality Management
District, Siskiyou County Air Pollution Control
[[Page 60]]
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 Air Quality Management District,
Siskiyou County Air Pollution Control District, South Coast Air Quality Management District, and Tehama County
Air Pollution Control District
----------------------------------------------------------------------------------------------------------------
Air Pollution Control Agency
-----------------------------------------------
Subpart Shasta Siskiyou Tehama
County County South County
AQMD APCD Coast AQMD APCD
----------------------------------------------------------------------------------------------------------------
A General Provisions................... X X X X
D Fossil-Fuel Fired Steam Generators X X X X
Constructed After August 17, 1971.
Da Electric Utility Steam Generating X X X X
Units Constructed After September
18, 1978.
Db Industrial-Commercial-Institutional X X X X
Steam Generating Units.
Dc Small Industrial Steam Generating X X X X
Units.
E Incinerators......................... .......... X X X
Ea Municipal Waste Combustors .......... X X X
Constructed After December 20, 1989
and On or Before September 20, 1994.
Eb Municipal Waste Combustors X .......... X
Constructed After September 20, 1994.
Ec Hospital/Medical/Infectious Waste X
Incinerators for Which Construction
is Commenced After June 20, 1996.
F Portland Cement Plants............... .......... X X X
G Nitric Acid Plants................... .......... X X X
H Sulfuric Acid Plants................. .......... 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.
K Storage Vessels for Petroleum Liquids X X X X
for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973, and
Prior to May 19, 1978.
Ka Storage Vessels for Petroleum Liquids X X X X
for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978, and
Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X X X X
Vessels (Including Petroleum Liquid
Storage Vessels) for Which
Construction, Reconstruction, or
Modification Commenced After July
23, 1984.
L Secondary Lead Smelters.............. X X X X
M Secondary Brass and Bronze Production X X X X
Plants.
N Primary Emissions from Basic Oxygen .......... X X X
Process Furnaces for Which
Construction is Commenced After June
11, 1973.
Na Secondary Emissions from Basic Oxygen .......... X X X
Process Steelmaking Facilities for
Which Construction is Commenced
After January 20, 1983.
O Sewage Treatment Plants.............. X X X X
P Primary Copper Smelters.............. X 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 .......... X X X
Process Phosphoric Acid Plants.
U Phosphate Fertilizer Industry: .......... X X X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: .......... X X X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: Triple .......... X X X
Superphosphate Plants.
X Phosphate Fertilizer Industry: .......... X X X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants.............. .......... X X X
Z Ferroalloy Production Facilities..... .......... X X X
AA Steel Plants: Electric Arc Furnaces .......... X X X
Constructed After October 21, 1974
and On or Before August 17, 1983.
AAa Steel Plants: Electric Arc Furnaces .......... X X X
and Argon-Oxygen Decarburization
Vessels Constructed After August 7,
1983.
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 X
KK Lead-Acid Battery Manufacturing .......... X X X
Plants.
[[Page 61]]
LL Metallic Mineral Processing Plants... .......... X X X
MM Automobile and Light Duty Trucks .......... X X X
Surface Coating Operations.
NN Phosphate Rock Plants................ .......... X X X
PP Ammonium Sulfate Manufacture......... .......... X X X
QQ Graphic Arts Industry: Publication .......... X X X
Rotogravure Printing.
RR Pressure Sensitive Tape and Label .......... X X X
Surface Coating Operations.
SS Industrial Surface Coating: Large .......... X X X
Appliances.
TT Metal Coil Surface Coating........... .......... X X X
UU Asphalt Processing and Asphalt .......... X X X
Roofing Manufacture.
VV Equipment Leaks of VOC in the .......... X X X
Synthetic Organic Chemicals
Manufacturing Industry.
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 X X
XX Bulk Gasoline Terminals..............
AAA New Residential Wool Heaters......... X X X X
BBB Rubber Tire Manufacturing Industry... .......... X X X
CCC (Reserved)...........................
DDD Volatile Organic Compounds (VOC) .......... X .......... X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved)...........................
FFF Flexible Vinyl and Urethane Coating .......... X X X
and Printing.
GGG Equipment Leaks of VOC in Petroleum .......... X X X
Refineries.
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 X X
III Volatile Organic Compound (VOC) .......... X X X
Emissions From the Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Air Oxidation Unit Processes.
JJJ Petroleum Dry Cleaners............... .......... X X X
KKK Equipment Leaks of VOC From Onshore .......... X X X
Natural Gas Processing Plants.
LLL Onshore Natural Gas Processing: SO2 .......... X X X
Emissions.
MMM (Reserved)...........................
NNN Volatile Organic Compound (VOC) .......... X .......... X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing Plants X X X X
PPP Wool Fiberglass Insulation .......... X X X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum Refinery .......... X X X
Wastewater Systems.
RRR Volatile Organic Compound Emissions .......... X X X
from Synthetic Organic Chemical
Manufacturing Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating Facilities..... .......... X X X
TTT Industrial Surface Coating: Surface .......... X X X
Coating of Plastic Parts for
Business Machines.
UUU Calciners and Dryers in Mineral X X X X
Industries.
VVV Polymeric Coating of Supporting X X X X
Substrates Facilities.
WWW Municipal Solid Waste Landfills...... .......... X X X
AAAA Small Municipal Waste Combustion X
Units for Which Construction is
Commenced After August 30, 1999 or
for Which Modification or
Reconstruction is Commended After
June 6, 2001.
CCCC Commercial and Industrial Solid Waste X
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.
EEEE Other Solid Waste Incineration Units X
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.......
----------------------------------------------------------------------------------------------------------------
[[Page 62]]
(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
----------------------------------------------------------------------------------------------------------------
Air Pollution Control Agency
--------------------------------------------------
Subpart Tuolumne County Ventura County Yolo-Solano
APCD APCD AQMD
----------------------------------------------------------------------------------------------------------------
A General Provisions............... X X
D Fossil-Fuel Fired Steam X X
Generators Constructed After
August 17, 1971.
Da Electric Utility Steam Generating X
Units Constructed After
September 18, 1978.
Db Industrial-Commercial- X X
Institutional Steam Generating
Units.
Dc Small Industrial Steam Generating X
Units.
E Incinerators..................... X
Ea Municipal Waste Combustors X
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Municipal Waste Combustors X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious Waste X
Incinerators for Which
Construction is Commenced After
June 20, 1996.
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 X X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978,
and Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X
Vessels (Including Petroleum
Liquid Storage Vessels) for
Which Construction,
Reconstruction, or Modification
Commenced After July 23, 1984.
L Secondary Lead Smelters.......... X
M Secondary Brass and Bronze X
Production Plants.
N Primary Emissions from Basic X
Oxygen Process Furnaces for
Which Construction is Commenced
After June 11, 1973.
Na Secondary Emissions from Basic X
Oxygen Process Steelmaking
Facilities for Which
Construction is Commenced After
January 20, 1983.
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: X
Wet Process Phosphoric Acid
Plants.
U Phosphate Fertilizer Industry: X
Superphosphoric Acid Plants.
V Phosphate Fertilizer Industry: X
Diammonium Phosphate Plants.
W Phosphate Fertilizer Industry: X
Triple Superphosphate Plants.
X Phosphate Fertilizer Industry: X
Granular Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants.......... X
Z Ferroalloy Production Facilities. X
AA Steel Plants: Electric Arc X X
Furnaces Constructed After
October 21, 1974 and On or
Before August 17, 1983.
AAa Steel Plants: Electric Arc X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7, 1983.
BB Kraft pulp Mills................. X
CC Glass Manufacturing Plants....... X
DD Grain Elevators.................. X
EE Surface Coating of Metal X
Furniture.
FF (Reserved).......................
GG Stationary Gas Turbines.......... X
HH Lime Manufacturing Plants........ X
[[Page 63]]
KK Lead-Acid Battery Manufacturing X
Plants.
LL Metallic Mineral Processing X
Plants.
MM Automobile and Light Duty Trucks X
Surface Coating Operations.
NN Phosphate Rock Plants............ X
PP Ammonium Sulfate Manufacture..... X
QQ Graphic Arts Industry: X
Publication Rotogravure Printing.
RR Pressure Sensitive Tape and Label X
Surface Coating Operations.
SS Industrial Surface Coating: Large X
Appliances.
TT Metal Coil Surface Coating....... X
UU Asphalt Processing and Asphalt X
Roofing Manufacture.
VV Equipment Leaks of VOC in the X
Synthetic Organic Chemicals
Manufacturing Industry.
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 X
Industry.
XX Bulk Gasoline Terminals..........
AAA New Residential Wood Heaters..... X
BBB Rubber Tire Manufacturing X
Industry.
CCC (Reserved).......................
DDD Volatile Organic Compounds (VOC) X
Emissions from the Polymer
Manufacturing Industry.
EEE (Reserved).......................
FFF Flexible Vinyl and Urethane X
Coating and Printing.
GGG Equipment Leaks of VOC in X
Petroleum Refineries.
GGGa Equipment Leaks of VOC in
Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After
November 7, 2006.
HHH Synthetic Fiber Production X
Facilities.
III Volatile Organic Compound (VOC) X
Emissions From the Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Air Oxidation
Unit Processes.
JJJ Petroleum Dry Cleaners........... X
KKK Equipment Leaks of VOC From X
Onshore Natural Gas Processing
Plants.
LLL Onshore Natural Gas Processing: X
SO2 Emissions.
MMM (Reserved).......................
NNN Volatile Organic Compound (VOC) X
Emissions From Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Distillation Operations.
OOO Nonmetallic Mineral Processing X X
Plants.
PPP Wool Fiberglass Insulation X
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X
Refinery Wastewater Systems.
RRR Volatile Organic Compound X
Emissions from Synthetic Organic
Chemical Manufacturing Industry
(SOCMI) Reactor Processes.
SSS Magnetic Tape Coating Facilities. X
TTT Industrial Surface Coating: X
Surface Coating of Plastic Parts
for Business Machines.
UUU Calciners and Dryers in Mineral X
Industries.
VVV Polymeric Coating of Supporting X
Substrates Facilities.
WWW Municipal Solid Waste Landfills.. X X
AAAA Small Municipal Waste Combustion X
Units for Which Construction is
Commenced After August 30, 1999
or for Which Modification or
Reconstruction is Commenced
After June 6, 2001.
CCCC Commercial and Industrial Solid X
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.
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... ...............
----------------------------------------------------------------------------------------------------------------
[[Page 64]]
(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 X
Generators Constructed After
August 17, 1971.
Da Electric Utility Steam X
Generating Units Constructed
After September 18, 1978.
Db Industrial-Commercial- X
Institutional Steam Generating
Units.
Dc Small Industrial Steam X
Generating Units.
E Incinerators.................... X
Ea Municipal Waste Combustors X
Constructed After December 20,
1989 and On or Before September
20, 1994.
Eb Municipal Waste Combustors X
Constructed After September 20,
1994.
Ec Hospital/Medical/Infectious X
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
Ja Petroleum Refineries for Which
Construction, Reconstruction,
or Modification Commenced After
May 14, 2007.
K Storage Vessels for Petroleum X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
Ka Storage Vessels for Petroleum X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After May 18, 1978,
and Prior to July 23, 1984.
Kb Volatile Organic Liquid Storage X
Vessels (Including Petroleum
Liquid Storage Vessels) for
Which Construction,
Reconstruction, or Modification
Commenced After July 23, 1984.
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 X
Furnaces Constructed After
October 21, 1974 and On or
Before August 17, 1983.
AAa Steel Plants: Electric Arc X
Furnaces and Argon-Oxygen
Decarburization Vessels
Constructed After August 7,
1983.
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 X
Synthetic Organic Chemicals
Manufacturing Industry.
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 X
Industry.
XX Bulk Gasoline Terminals......... X
AAA New Residential Wool Heaters....
[[Page 65]]
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 X
Petroleum Refineries.
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) X
Emissions From Synthetic
Organic Chemical Manufacturing
Industry (SOCMI) Distillation
Operations.
OOO Nonmetallic Mineral Processing X
Plants.
PPP Wool Fiberglass Insulation
Manufacturing Plants.
QQQ VOC Emissions From Petroleum X
Refinery Wastewater.
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 X
Industries.
VVV Polymeric Coating of Supporting X
Substrates Facilities.
WWW Municipal Solid Waste Landfills. X
AAAA Small Municipal Waste Combustion X
Units for Which Construction is
Commenced After August 30, 1999
or for Which Modification or
Reconstruction is Commenced
After June 6, 2001.
CCCC Commercial and Industrial Solid X
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.
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:
Delegation Status for New Source Performance Standards for Nevada
------------------------------------------------------------------------
Air Pollution Control Agency
-----------------------------------
Subpart Nevada Clark Washoe
DEP County County
------------------------------------------------------------------------
A General Provisions..... X X X
D Fossil-Fuel Fired Steam X X X
Generators Constructed
After August 17, 1971.
Da Electric Utility Steam X
Generating Units
Constructed After
September 18, 1978.
Db Industrial-Commercial- X
Institutional Steam
Generating Units.
Dc Small Industrial Steam X
Generating Units.
E Incinerators........... X X X
Ea Municipal Waste X
Combustors Constructed
After December 20,
1989 and On or Before
September 20, 1994.
Eb Municipal Waste X
Combustors Constructed
After September 20,
1994.
Ec Hospital/Medical/ X
Infectious Waste
Incinerators for Which
Construction is
Commenced After June
20, 1996.
F Portland Cement Plants. X X X
G Nitric Acid Plants..... X X
H Sulfuric Acid Plants... X X
I Hot Mix Asphalt X X X
Facilities.
J Petroleum Refineries... X X
Ja Petroleum Refineries
for Which
Construction,
Reconstruction, or
Modification Commenced
After May 14, 2007.
K Storage Vessels for X X X
Petroleum Liquids for
Which Construction,
Reconstruction, or
Modification Commenced
After June 11, 1973,
and Prior to May 19,
1978.
Ka Storage Vessels for X X X
Petroleum Liquids for
Which Construction,
Reconstruction, or
Modification Commenced
After May 18, 1978,
and Prior to July 23,
1984.
[[Page 66]]
Kb Volatile Organic Liquid X
Storage Vessels
(Including Petroleum
Liquid Storage
Vessels) for Which
Construction,
Reconstruction, or
Modification Commenced
After July 23, 1984.
L Secondary Lead Smelters X X X
M Secondary Brass and X X
Bronze Production
Plants.
N Primary Emissions from X X
Basic Oxygen Process
Furnaces for Which
Construction is
Commenced After June
11, 1973.
Na Secondary Emissions X
from Basic Oxygen
Process Steelmaking
Facilities for Which
Construction is
Commenced After
January 20, 1983.
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 X X
Reduction Plants.
T Phosphate Fertilizer X X
Industry: Wet Process
Phosphoric Acid Plants.
U Phosphate Fertilizer X X
Industry:
Superphosphoric Acid
Plants.
V Phosphate Fertilizer X X
Industry: Diammonium
Phosphate Plants.
W Phosphate Fertilizer X X
Industry: Triple
Superphosphate Plants.
X Phosphate Fertilizer X X
Industry: Granular
Triple Superphosphate
Storage Facilities.
Y Coal Preparation Plants X X X
Z Ferroalloy Production X X
Facilities.
AA Steel Plants: Electric X X
Arc Furnaces
Constructed After
October 21, 1974 and
On or Before August
17, 1983.
AAa Steel Plants: Electric X
Arc Furnaces and Argon-
Oxygen Decarburization
Vessels Constructed
After August 7, 1983.
BB Kraft pulp Mills....... X X
CC Glass Manufacturing X X
Plants.
DD Grain Elevators........ X X X
EE Surface Coating of X X X
Metal Furniture.
FF (Reserved).............
GG Stationary Gas Turbines X X X
HH Lime Manufacturing X X X
Plants.
KK Lead-Acid Battery X X X
Manufacturing Plants.
LL Metallic Mineral X X X
Processing Plants.
MM Automobile and Light X X X
Duty Trucks Surface
Coating Operations.
NN Phosphate Rock Plants.. X X X
PP Ammonium Sulfate X X
Manufacture.
QQ Graphic Arts Industry: X X X
Publication
Rotogravure Printing.
RR Pressure Sensitive Tape X X
and Label Surface
Coating Operations.
SS Industrial Surface X X X
Coating: Large
Appliances.
TT Metal Coil Surface X X X
Coating.
UU Asphalt Processing and X X X
Asphalt Roofing
Manufacture.
VV Equipment Leaks of VOC X X X
in the Synthetic
Organic Chemicals
Manufacturing Industry.
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 X X
Coating Industry.
XX Bulk Gasoline Terminals X X
AAA New Residential Wool
Heaters.
BBB Rubber Tire X
Manufacturing Industry.
CCC (Reserved).............
DDD Volatile Organic X
Compounds (VOC)
Emissions from the
Polymer Manufacturing
Industry.
EEE (Reserved).............
FFF Flexible Vinyl and X X
Urethane Coating and
Printing.
GGG Equipment Leaks of VOC X X
in Petroleum
Refineries.
GGGa Equipment Leaks of VOC
in Petroleum
Refineries for Which
Construction,
Reconstruction, or
Modification Commenced
After November 7, 2006.
HHH Synthetic Fiber X X
Production Facilities.
III Volatile Organic X
Compound (VOC)
Emissions From the
Synthetic Organic
Chemical Manufacturing
Industry (SOCMI) Air
Oxidation Unit
Processes.
JJJ Petroleum Dry Cleaners. X X X
KKK Equipment Leaks of VOC X
From Onshore Natural
Gas Processing Plants.
LLL Onshore Natural Gas X
Processing: SO2
Emissions.
MMM (Reserved).............
NNN Volatile Organic X
Compound (VOC)
Emissions From
Synthetic Organic
Chemical Manufacturing
Industry (SOCMI)
Distillation
Operations.
OOO Nonmetallic Mineral X X
Processing Plants.
[[Page 67]]
PPP Wool Fiberglass X X
Insulation
Manufacturing Plants.
QQQ VOC Emissions From X
Petroleum Refinery
Wastewater Systems.
RRR Volatile Organic X
Compound Emissions
from Synthetic Organic
Chemical Manufacturing
Industry (SOCMI)
Reactor Processes.
SSS Magnetic Tape Coating X
Facilities.
TTT Industrial Surface X
Coating: Surface
Coating of Plastic
Parts for Business
Machines.
UUU Calciners and Dryers in X
Mineral Industries.
VVV Polymeric Coating of X
Supporting Substrates
Facilities.
WWW Municipal Solid Waste X
Landfills.
AAAA Small Municipal Waste X
Combustion Units for
Which Construction is
Commenced After August
30, 1999 or for Which
Modification or
Reconstruction is
Commended After June
6, 2001.
CCCC Commercial and X
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.
EEEE Other Solid Waste X
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 X
Ignition Internal
Combustion Engines.
JJJJ Stationary Spark X
Ignition Internal
Combustion Engines.
KKKK Stationary Combustion X ..........
Turbines.
------------------------------------------------------------------------
(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 X
Constructed After August 17, 1971.
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 X
Liquids for Which Construction,
Reconstruction, or Modification
Commenced After June 11, 1973,
and Prior to May 19, 1978.
----------------------------------------------------------------------------------------------------------------
(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 EPA, except subpart AAA--
Standards of Performance for New Residential Wood Heaters, as amended in
the Federal Register through September 1, 2002.
(2) Louisiana. The Louisiana Department of Environmental Quality has
been delegated all part 60 standards promulgated by EPA, except subpart
AAA--Standards for Performance for New Residential Wood Heaters, as
[[Page 68]]
amended in the Federal Register through July 1, 2008.
Delegation Status for Part 60 Standards--State of Louisiana
------------------------------------------------------------------------
Subpart Source category LDEQ\1\
------------------------------------------------------------------------
A...................... General Provisions.... Yes.
D...................... Fossil Fueled Steam Yes.
Generators (250 MM BTU/hr).
Including amendments
issued January 28,
2009. (74 FR 5072).
Da..................... Electric Utility Steam Yes.
Generating Units (250 MM BTU/
hr). Including
amendments issued
January 28, 2009. (74
FR 5072).
Db..................... Industrial-Commercial- Yes.
Institutional Steam
Generating Units (100
to 250 MM BTU/hr).
Including amendments
issued January 28,
2009. (74 FR 5072).
Dc..................... Industrial-Commercial- Yes.
Institutional Small
Steam Generating
Units (10 to 100 MM
BTU/hr). Including
amendments issued
January 28, 2009. (74
FR 5072).
E...................... Incinerators (50 tons per day).
Including amendments
issued January 28,
2009. (74 FR 5072).
Ea..................... Municipal Waste Yes.
Combustors.
Eb..................... Large Municipal Waste Yes.
Combustors.
Ec..................... Hospital/Medical/ Yes.
Infectious Waste
Incinerators.
F...................... Portland Cement Plants Yes.
G...................... Nitric Acid Plants.... Yes.
H...................... Sulfuric Acid Plants.. Yes.
I...................... Hot Mix Asphalt Yes.
Facilities.
J...................... Petroleum Refineries.. Yes.
Ja..................... Petroleum Refineries Yes.
(After May 14, 2007).
Including amendments
issued July 28, 2008.
(73 FR 43626).
K...................... Storage Vessels for Yes.
Petroleum Liquids
(After 6/11/73 &
Before 5/19/78).
Ka..................... Storage Vessels for Yes.
Petroleum Liquids
(After 6/11/73 &
Before 5/19/78).
Kb..................... Volatile Organic Yes.
Liquid Storage
Vessels (Including
Petroleum Liquid Stg/
Vessels) After 7/23/
84.
L...................... Secondary Lead Yes.
Smelters.
M...................... Secondary Brass and Yes.
Bronze Production
Plants.
N...................... Primary Emissions from Yes.
Basic Oxygen Process
Furnaces
(Construction
Commenced After June
11, 1973).
Na..................... Secondary Emissions Yes.
from Basic Oxygen
Process Steelmaking
Facilities
Construction is
Commenced After
January 20, 1983.
O...................... Sewage Treatment Yes.
Plants.
P...................... Primary Copper Yes.
Smelters.
Q...................... Primary Zinc Smelters. Yes.
R...................... Primary Lead Smelters. Yes.
S...................... Primary Aluminum Yes.
Reduction Plants.
T...................... Phosphate Fertilizer Yes.
Industry: Wet Process
Phosphoric Plants.
U...................... Phosphate Fertilizer Yes.
Industry:
Superphosphoric Acid
Plants.
V...................... Phosphate Fertilizer Yes.
Industry: Diammonium
Phosphate Plants.
W...................... Phosphate Fertilizer Yes.
Industry: Triple
Superphosphate Plants.
X...................... Phosphate Fertilizer Yes.
Industry: Granular
Triple Superphosphate
Storage Facilities.
Y...................... Coal Preparation Yes.
Plants.
Z...................... Ferroalloy Production Yes.
Facilities.
AA..................... Steel Plants: Electric Yes.
Arc Furnaces After 10/
21/74 & On or Before
8/17/83.
AAa.................... Steel Plants: Electric Yes.
Arc Furnaces & Argon-
Oxygen
Decarburization
Vessels After 8/07/83.
BB..................... Kraft Pulp Mills...... Yes.
CC..................... Glass Manufacturing Yes.
Plants.
DD..................... Grain Elevators....... Yes.
EE..................... Surface Coating of Yes.
Metal Furnature.
GG..................... Stationary Gas Yes.
Turbines.
HH..................... Lime Manufacturing Yes.
Plants.
KK..................... Lead-Acid Battery Yes.
Manufacturing Plants.
LL..................... Metallic Mineral Yes.
Processing Plants.
MM..................... Automobile & Light Yes.
Duty Truck Surface
Coating Operations.
NN..................... Phosphate Yes.
Manufacturing Plants.
PP..................... Ammonium Sulfate Yes.
Manufacture.
QQ..................... Graphic Arts Industry: Yes.
Publication
Rotogravure Printing.
RR..................... Pressure Sensitive Yes.
Tape and Label
Surface Coating
Operations.
SS..................... Industrial Surface Yes.
Coating: Large
Appliances.
TT..................... Metal Coil Surface Yes.
Coating.
UU..................... Asphalt Processing and Yes.
Asphalt Roofing
Manufacture.
VV..................... VOC Equipment Leaks in Yes.
the SOCMI Industry.
VVa.................... VOC Equipment Leaks in Yes.
the SOCMI Industry
(After November 7,
2006).
XX..................... Bulk Gasoline Yes.
Terminals.
AAA.................... New Residential Wood No
Heaters.
BBB.................... Rubber Tire Yes.
Manufacturing
Industry.
DDD.................... Volatile Organic Yes.
Compound (VOC)
Emissions from the
Polymer Manufacturing
Industry.
FFF.................... Flexible Vinyl and Yes.
Urethane Coating and
Printing.
[[Page 69]]
GGG.................... VOC Equipment Leaks in Yes.
Petroleum Refineries.
HHH.................... Synthetic Fiber Yes.
Production.
III.................... VOC Emissions from the Yes.
SOCMI Air Oxidation
Unit Processes.
JJJ.................... Petroleum Dry Cleaners Yes.
KKK.................... VOC Equipment Leaks Yes.
From Onshore Natural
Gas Processing Plants.
LLL.................... Onshore Natural Gas Yes.
Processing: SO2
Emissions.
NNN.................... VOC Emissions from Yes.
SOCMI Distillation
Operations.
OOO.................... Nonmetallic Mineral Yes.
Processing Plants.
PPP.................... Wool Fiberglass Yes.
Insulation
Manufacturing Plants.
QQQ.................... VOC Emissions From Yes.
Petroleum Refinery
Wastewater Systems.
RRR.................... VOC Emissions from Yes.
SOCMI Reactor
Processes.
SSS.................... Magnetic Tape Coating Yes.
Operations.
TTT.................... Industrial Surface Yes.
Coating: Plastic
Parts for Business
Machines.
UUU.................... Calciners and Dryers Yes.
in Mineral Industries.
VVV.................... Polymeric Coating of Yes.
Supporting Substrates
Facilities.
WWW.................... Municipal Solid Waste Yes.
Landfills.
AAAA................... Small Municipal Waste Yes.
Combustion Units
(Construction is
Commenced After 8/30/
99 or Modification/
Reconstruction is
Commenced After 6/06/
2001).
CCCC................... Commercial & Yes.
Industrial Solid
Waste Incineration
Units (Construction
is Commenced After 11/
30/1999 or
Modification/
Reconstruction is
Commenced on or After
6/01/2001).
EEEE................... Other Solid Waste Yes.
Incineration Units
(Constructed after 12/
09/2004 or
Modicatation/
Reconstruction is
commenced on or after
06/16/2004).
IIII................... Stationary Compression Yes.
Ignition Internal
Combustion Engines.
JJJJ................... Stationary Spark Yes.
Ignition Internal
Combustion Engines.
Including amendments
issued October 8,
2008. (73 FR 59175).
KKKK................... Stationary Combustion Yes
Turbines
(Construction
Commenced After 02/18/
2005).
------------------------------------------------------------------------
\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, 2008.
(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; Subpart WWW--
Standards of Performance for Municipal Solid Waste Landfills; Subpart
Cc--Emissions Guidelines and Compliance Times for Municipal Solid Waste
Landfills, as amended in the Federal Register through July 1, 2004.
[40 FR 18169, Apr. 25, 1975]
Editorial Note: For Federal Register citations affecting Sec. 60.4
see the List of CFR Sections Affected which appears in the Finding Aids
section of the printed volume and on GPO Access.
Sec. 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]
Sec. 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
[[Page 70]]
(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]
Sec. 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 Sec. 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 Sec. 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
Sec. 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 Sec. 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 Sec. 60.8 in lieu of
Method 9 observation data as allowed by Sec. 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
Sec. 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
[[Page 71]]
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 Sec. 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
Sec. 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\_____________________
------------------------------------------------------------------------
CMS performance
Emission data summary \1\ summary \1\
------------------------------------------------------------------------
1. Duration of excess ........ 1. CMS downtime in
emissions in reporting reporting period due
period due to: to:
a. Startup/shutdown........ ........ a. Monitor equipment
malfunctions.
b. Control equipment ........ b. Non-Monitor
problems. 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 ........ 2. Total CMS Downtime
emission.
3. Total duration of excess % \2\ 3. [Total CMS % \2\
emissions x (100) [Total Downtime] x (100)
source operating time]. [Total source
operating time].
------------------------------------------------------------------------
\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 Sec.
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
[[Page 72]]
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
[[Page 73]]
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]
Sec. 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)
[[Page 74]]
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. 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.
[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]
Sec. 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 Sec. Sec. 60.5 and 60.6 is
governed by Sec. Sec. 2.201 through 2.213 of this chapter and not by
Sec. 2.301 of this chapter.)
Sec. 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
[[Page 75]]
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.
Sec. 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 Sec. 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 Sec. 60.8 unless one of the following
conditions apply. If no performance test under Sec. 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 Sec. 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 Sec.
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 Sec. 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
[[Page 76]]
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
Sec. 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 Sec. 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 Sec. 60.8 and
shall furnish the Administrator a written report of the monitoring
results along with Method 9 and Sec. 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 Sec. 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
Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 60.8, the opacity
observation results and observer certification required by Sec.
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 Sec. 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
Sec. 60.8 of this part but during the time such performance tests are
being conducted fails to meet any
[[Page 77]]
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]
Sec. 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]
Sec. 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
Sec. 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 Sec. 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 Sec. 60.8 is conducted. Otherwise, the owner or operator
of an affected facility shall conduct a performance evaluation of the
[[Page 78]]
COMS or continuous emission monitoring system (CEMS) during any
performance test required under Sec. 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
Sec. 60.8 and as described in Sec. 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 Sec. 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 daily in accordance with a
written procedure. The zero and span must, as 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 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
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.
[[Page 79]]
(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 Sec. 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 Sec.
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
Sec. 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
[[Page 80]]
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 Sec. 60.8 of this subpart or other tests performed
following the criteria in Sec. 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
[[Page 81]]
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., Sec. 60.45(g) (2)
and (3), Sec. 60.73(e), and Sec. 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; 40 FR 59205, Dec. 22, 1975, as amended at 41
FR 35185, Aug. 20, 1976; 48 FR 13326, Mar. 30, 1983; 48 FR 23610, May
25, 1983; 48 FR 32986, July 20, 1983; 52 FR 9782, Mar. 26, 1987; 52 FR
17555, May 11, 1987; 52 FR 21007, June 4, 1987; 64 FR 7463, Feb. 12,
1999; 65 FR 48920, Aug. 10, 2000; 65 FR 61749, Oct. 17, 2000; 66 FR
44980, Aug. 27, 2001; 71 FR 31102, June 1, 2006; 72 FR 32714, June 13,
2007]
Editorial Note: At 65 FR 61749, Oct. 17, 2000, Sec. 60.13 was
amended by revising the words ``ng/J of pollutant'' to read ``ng of
pollutant per J of heat input'' in the sixth sentence of paragraph (h).
However, the amendment could not be incorporated because the words ``ng/
J of pollutant'' do not exist in the sixth sentence of paragraph (h).
Sec. 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
[[Page 82]]
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 Sec. 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 Sec. 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
[[Page 83]]
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]
Sec. 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]
Sec. 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
[[Page 84]]
(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]
Sec. 60.17 Incorporations by reference.
The materials listed below are incorporated by reference in the
corresponding sections noted. These incorporations by reference were
approved by the Director of the Federal Register on the date listed.
These materials are incorporated as they exist on the date of the
approval, and a notice of any change in these materials will be
published in the Federal Register. The materials are available for
purchase at the corresponding address noted below, and all are available
for inspection at the Library (C267-01), U.S. EPA, Research Triangle
Park, NC or 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.
(a) The following materials are available for purchase from at least
one of the following addresses: American Society for Testing and
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann
Arbor, MI 48106.
(1) ASTM A99-76, 82 (Reapproved 1987), Standard Specification for
Ferromanganese, incorporation by reference (IBR) approved for Sec.
60.261.
(2) ASTM A100-69, 74, 93, Standard Specification for Ferrosilicon,
IBR approved for Sec. 60.261.
(3) ASTM A101-73, 93, Standard Specification for Ferrochromium, IBR
approved for Sec. 60.261.
(4) ASTM A482-76, 93, Standard Specification for Ferrochromesilicon,
IBR approved for Sec. 60.261.
(5) ASTM A483-64, 74 (Reapproved 1988), Standard Specification for
Silicomanganese, IBR approved for Sec. 60.261.
[[Page 85]]
(6) ASTM A495-76, 94, Standard Specification for Calcium-Silicon and
Calcium Manganese-Silicon, IBR approved for Sec. 60.261.
(7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum
Products, IBR approved for Sec. Sec. 60.562-2(d), 60.593(d),
60.593a(d), and 60.633(h).
(8) ASTM D129-64, 78, 95, 00, Standard Test Method for Sulfur in
Petroleum Products (General Bomb Method), IBR approved for Sec. Sec.
60.106(j)(2), 60.335(b)(10)(i), and appendix A: Method 19, 12.5.2.2.3.
(9) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur
in Petroleum Products (General Bomb Method), IBR approved for Sec.
60.4415(a)(1)(i).
(10) ASTM D240-76, 92, Standard Test Method for Heat of Combustion
of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for
Sec. Sec. 60.46(c), 60.296(b), and appendix A: Method 19, Section
12.5.2.2.3.
(11) ASTM D270-65, 75, Standard Method of Sampling Petroleum and
Petroleum Products, IBR approved for appendix A: Method 19, Section
12.5.2.2.1.
(12) ASTM D323-82, 94, Test Method for Vapor Pressure of Petroleum
Products (Reid Method), IBR approved for Sec. Sec. 60.111(l),
60.111a(g), 60.111b(g), and 60.116b(f)(2)(ii).
(13) ASTM D388-77, 90, 91, 95, 98a, 99 (Reapproved 2004)[egr]\1\,
Standard Specification for Classification of Coals by Rank, IBR approved
for Sec. Sec. 60.24(h)(8), 60.41 of subpart D of this part,
60.45(f)(4)(i), 60.45(f)(4)(ii), 60.45(f)(4)(vi), 60.41Da of subpart Da
of this part, 60.41b of subpart Db of this part, 60.41c of subpart Dc of
this part, 60.251 of subpart Y of this part, and 60.4102.
(14) ASTM D396-78, 89, 90, 92, 96, 98, Standard Specification for
Fuel Oils, IBR approved for Sec. Sec. 60.41b of subpart Db of this
part, 60.41c of subpart Dc of this part, 60.111(b) of subpart K of this
part, and 60.111a(b) of subpart Ka of this part.
(15) ASTM D975-78, 96, 98a, Standard Specification for Diesel Fuel
Oils, IBR approved for Sec. Sec. 60.111(b) of subpart K of this part
and 60.111a(b) of subpart Ka of this part.
(16) ASTM D975-08a, Standard Specification for Diesel Fuel Oils, IBR
approved for Sec. Sec. 60.41b of subpart Db of this part and 60.41c of
subpart Dc of this part.
(17) ASTM D1072-80, 90 (Reapproved 1994), Standard Test Method for
Total Sulfur in Fuel Gases, IBR approved for Sec. 60.335(b)(10)(ii).
(18) ASTM D1072-90 (Reapproved 1999), Standard Test Method for Total
Sulfur in Fuel Gases, IBR approved for Sec. 60.4415(a)(1)(ii).
(19) ASTM D1137-53, 75, Standard Method for Analysis of Natural
Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer,
IBR approved for Sec. 60.45(f)(5)(i).
(20) ASTM D1193-77, 91, Standard Specification for Reagent Water,
IBR approved for appendix A: Method 5, Section 7.1.3; Method 5E, Section
7.2.1; Method 5F, Section 7.2.1; 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; Method 11, Section 7.1.3; Method 12, Section
7.1.3; Method 13A, Section 7.1.2; Method 26, Section 7.1.2; Method 26A,
Section 7.1.2; and Method 29, Section 7.2.2.
(21) ASTM D1266-87, 91, 98, Standard Test Method for Sulfur in
Petroleum Products (Lamp Method), IBR approved for Sec. Sec.
60.106(j)(2) and 60.335(b)(10)(i).
(22) ASTM D1266-98 (Reapproved 2003)e1, Standard Test Method for
Sulfur in Petroleum Products (Lamp Method), IBR approved for Sec.
60.4415(a)(1)(i).
(23) ASTM D1475-60 (Reapproved 1980), 90, Standard Test Method for
Density of Paint, Varnish Lacquer, and Related Products, IBR approved
for Sec. 60.435(d)(1), appendix A: Method 24, Section 6.1; and Method
24A, Sections 6.5 and 7.1.
(24) ASTM D1552-83, 95, 01, Standard Test Method for Sulfur in
Petroleum Products (High-Temperature Method), IBR approved for
Sec. Sec. 60.106(j)(2), 60.335(b)(10)(i), and appendix A: Method 19,
Section 12.5.2.2.3.
(25) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum
Products (High-Temperature Method), IBR approved for Sec.
60.4415(a)(1)(i).
(26) ASTM D1826-77, 94, Standard Test Method for Calorific Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR
approved for Sec. Sec. 60.45(f)(5)(ii), 60.46(c)(2), 60.296(b)(3),
[[Page 86]]
and appendix A: Method 19, Section 12.3.2.4.
(27) ASTM D1835-87, 91, 97, 03a, Standard Specification for
Liquefied Petroleum (LP) Gases, IBR approved for Sec. Sec. 60.41Da of
subpart Da of this part, 60.41b of subpart Db of this part, and 60.41c
of subpart Dc of this part.
(28) ASTM D1945-64, 76, 91, 96, Standard Method for Analysis of
Natural Gas by Gas Chromatography, IBR approved for Sec.
60.45(f)(5)(i).
(29) ASTM D1946-77, 90 (Reapproved 1994), Standard Method for
Analysis of Reformed Gas by Gas Chromatography, IBR approved for
Sec. Sec. 60.18(f)(3), 60.45(f)(5)(i), 60.564(f)(1), 60.614(e)(2)(ii),
60.614(e)(4), 60.664(e)(2)(ii), 60.664(e)(4), 60.704(d)(2)(ii), and
60.704(d)(4).
(30) ASTM D2013-72, 86, Standard Method of Preparing Coal Samples
for Analysis, IBR approved for appendix A: Method 19, Section
12.5.2.1.3.
(31) ASTM D2015-77 (Reapproved 1978), 96, Standard Test Method for
Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter,
IBR approved for Sec. 60.45(f)(5)(ii), 60.46(c)(2), and appendix A:
Method 19, Section 12.5.2.1.3.
(32) ASTM D2016-74, 83, Standard Test Methods for Moisture Content
of Wood, IBR approved for appendix A: Method 28, Section 16.1.1.
(33) ASTM D2234-76, 96, 97b, 98, Standard Methods for Collection of
a Gross Sample of Coal, IBR approved for appendix A: Method 19, Section
12.5.2.1.1.
(34) ASTM D2369-81, 87, 90, 92, 93, 95, Standard Test Method for
Volatile Content of Coatings, IBR approved for appendix A: Method 24,
Section 6.2.
(35) ASTM D2382-76, 88, Heat of Combustion of Hydrocarbon Fuels by
Bomb Calorimeter (High-Precision Method), IBR approved for Sec. Sec.
60.18(f)(3), 60.485(g)(6), 60.485a(g)(6), 60.564(f)(3), 60.614(e)(4),
60.664(e)(4), and 60.704(d)(4).
(36) ASTM D2504-67, 77, 88 (Reapproved 1993), Noncondensable Gases
in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR
approved for Sec. Sec. 60.485(g)(5) and 60.485a(g)(5).
(37) ASTM D2584-68 (Reapproved 1985), 94, Standard Test Method for
Ignition Loss of Cured Reinforced Resins, IBR approved for Sec.
60.685(c)(3)(i).
(38) 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 Sec.
60.335(b)(9)(i).
(39) ASTM D2622-87, 94, 98, Standard Test Method for Sulfur in
Petroleum Products by Wavelength Dispersive X-Ray Fluorescence
Spectrometry, IBR approved for Sec. Sec. 60.106(j)(2) and
60.335(b)(10)(i).
(40) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR
approved for Sec. 60.4415(a)(1)(i).
(41) ASTM D2879-83, 96, 97, Test Method for Vapor Pressure-
Temperature Relationship and Initial Decomposition Temperature of
Liquids by Isoteniscope, IBR approved for Sec. Sec. 60.111b(f)(3),
60.116b(e)(3)(ii), 60.116b(f)(2)(i), 60.485(e)(1), and 60.485a(e)(1).
(42) ASTM D2880-78, 96, Standard Specification for Gas Turbine Fuel
Oils, IBR approved for Sec. Sec. 60.111(b), 60.111a(b), and 60.335(d).
(43) ASTM D2908-74, 91, Standard Practice for Measuring Volatile
Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR
approved for Sec. 60.564(j).
(44) ASTM D2986-71, 78, 95a, Standard Method for Evaluation of Air,
Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR
approved for appendix A: Method 5, Section 7.1.1; Method 12, Section
7.1.1; and Method 13A, Section 7.1.1.2.
(45) ASTM D3173-73, 87, Standard Test Method for Moisture in the
Analysis Sample of Coal and Coke, IBR approved for appendix A: Method
19, Section 12.5.2.1.3.
(46) ASTM D3176-74, 89, Standard Method for Ultimate Analysis of
Coal and Coke, IBR approved for Sec. 60.45(f)(5)(i) and appendix A:
Method 19, Section 12.3.2.3.
(47) ASTM D3177-75, 89, Standard Test Method for Total Sulfur in the
Analysis Sample of Coal and Coke, IBR approved for appendix A: Method
19, Section 12.5.2.1.3.
(48) ASTM D3178-73 (Reapproved 1979), 89, Standard Test Methods for
[[Page 87]]
Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR
approved for Sec. 60.45(f)(5)(i).
(49) ASTM D3246-81, 92, 96, Standard Test Method for Sulfur in
Petroleum Gas by Oxidative Microcoulometry, IBR approved for Sec.
60.335(b)(10)(ii).
(50) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum Gas
by Oxidative Microcoulometry, IBR approved for Sec. 60.4415(a)(1)(ii).
(51) ASTM D3270-73T, 80, 91, 95, Standard Test Methods for Analysis
for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated
Method), IBR approved for appendix A: Method 13A, Section 16.1.
(52) ASTM D3286-85, 96, Standard Test Method for Gross Calorific
Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved
for appendix A: Method 19, Section 12.5.2.1.3.
(53) ASTM D3370-76, 95a, Standard Practices for Sampling Water, IBR
approved for Sec. 60.564(j).
(54) ASTM D3792-79, 91, Standard Test Method for Water Content of
Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR
approved for appendix A: Method 24, Section 6.3.
(55) ASTM D4017-81, 90, 96a, Standard Test Method for Water in
Paints and Paint Materials by the Karl Fischer Titration Method, IBR
approved for appendix A: Method 24, Section 6.4.
(56) ASTM D4057-81, 95, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products, IBR approved for appendix A: Method
19, Section 12.5.2.2.3.
(57) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, IBR approved for Sec.
60.4415(a)(1).
(58) ASTM D4084-82, 94, Standard Test Method for Analysis of
Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method),
IBR approved for Sec. 60.334(h)(1).
(59) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR
approved for Sec. Sec. 60.4360 and 60.4415(a)(1)(ii).
(60) ASTM D4177-95, Standard Practice for Automatic Sampling of
Petroleum and Petroleum Products, IBR approved for appendix A: Method
19, Section 12.5.2.2.1.
(61) ASTM D4177-95 (Reapproved 2000), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, IBR approved for
Sec. 60.4415(a)(1).
(62) ASTM D4239-85, 94, 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: Method 19, Section
12.5.2.1.3.
(63) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum and
Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry,
IBR approved for Sec. 60.335(b)(10)(i).
(64) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum and
Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry,
IBR approved for Sec. 60.4415(a)(1)(i).
(65) ASTM D4442-84, 92, Standard Test Methods for Direct Moisture
Content Measurement in Wood and Wood-base Materials, IBR approved for
appendix A: Method 28, Section 16.1.1.
(66) ASTM D4444-92, Standard Test Methods for Use and Calibration of
Hand-Held Moisture Meters, IBR approved for appendix A: Method 28,
Section 16.1.1.
(67) 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:
Method 24, Section 6.5.
(68) ASTM D4468-85 (Reapproved 2000), Standard Test Method for Total
Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry,
IBR approved for Sec. Sec. 60.335(b)(10)(ii) and 60.4415(a)(1)(ii).
(69) ASTM D4629-02, Standard Test Method for Trace Nitrogen in
Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and
Chemiluminescence Detection, IBR approved for Sec. Sec. 60.49b(e) and
60.335(b)(9)(i).
(70) ASTM D4809-95, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec. Sec. 60.18(f)(3), 60.485(g)(6), 60.485a(g)(6),
60.564(f)(3), 60.614(d)(4), 60.664(e)(4), and 60.704(d)(4).
[[Page 88]]
(71) ASTM D4810-88 (Reapproved 1999), Standard Test Method for
Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes,
IBR approved for Sec. Sec. 60.4360 and 60.4415(a)(1)(ii).
(72) ASTM D5287-97 (Reapproved 2002), Standard Practice for
Automatic Sampling of Gaseous Fuels, IBR approved for Sec.
60.4415(a)(1).
(73) ASTM D5403-93, Standard Test Methods for Volatile Content of
Radiation Curable Materials, IBR approved for appendix A: Method 24,
Section 6.6.
(74) ASTM D5453-00, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec. 60.335(b)(10)(i).
(75) ASTM D5453-05, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet
Fluorescence, IBR approved for Sec. 60.4415(a)(1)(i).
(76) 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 Sec. Sec. 60.334(h)(1) and 60.4360.
(77) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum
and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved for
Sec. 60.335(b)(9)(i).
(78) ASTM D5865-98, Standard Test Method for Gross Calorific Value
of Coal and Coke, IBR approved for Sec. 60.45(f)(5)(ii), 60.46(c)(2),
and appendix A: Method 19, Section 12.5.2.1.3.
(79) ASTM D6216-98, Standard Practice for Opacity Monitor
Manufacturers to Certify Conformance with Design and Performance
Specifications, IBR approved for appendix B, Performance Specification
1.
(80) 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 Sec. 60.334(h)(1).
(81) 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
Sec. Sec. 60.4360 and 60.4415.
(82) ASTM D6348-03, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, IBR approved for table 7 of subpart IIII
of this part and table 2 of subpart JJJJ of this part.
(83) 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 Sec.
60.335(b)(9)(i).
(84) ASTM D6420-99 (Reapproved 2004) Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry, IBR approved for table 2 of subpart
JJJJ of this part.
(85) 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
Sec. 60.335(a).
(86) 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, IBR approved for table 2 of subpart JJJJ of this
part.
(87) 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 Sec. 60.335(b)(10)(ii).
(88) 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 Sec. 60.4415(a)(1)(ii).
(89) 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 appendix B
to part 60, Performance Specification 12A, Section 8.6.2.
[[Page 89]]
(90) 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 Appendix B
to part 60, Performance Specification 12A, Section 8.6.2 and Sec.
60.56c(b)(13) of subpart Ec of this part.
(91) ASTM E169-63, 77, 93, General Techniques of Ultraviolet
Quantitative Analysis, IBR approved for Sec. Sec. 60.485a(d)(1),
60.593(b)(2), 60.593a(b)(2), and 60.632(f).
(92) ASTM E260-73, 91, 96, General Gas Chromatography Procedures,
IBR approved for Sec. Sec. 60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2),
and 60.632(f).
(b) The following material is available for purchase from the
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, 11th edition, 1970, pp. 11-12, IBR
approved January 27, 1983 for Sec. Sec. 60.204(b)(3), 60.214(b)(3),
60.224(b)(3), 60.234(b)(3).
(c) The following material is available for purchase from the
American Petroleum Institute, 1220 L Street NW., Washington, DC 20005.
(1) API Publication 2517, Evaporation Loss from External Floating
Roof Tanks, Second Edition, February 1980, IBR approved January 27,
1983, for Sec. Sec. 60.111(i), 60.111a(f), 60.111a(f)(1) and
60.116b(e)(2)(i).
(d) The following material is available for purchase from the
Technical Association of the Pulp and Paper Industry (TAPPI), Dunwoody
Park, Atlanta, GA 30341.
(1) TAPPI Method T624 os-68, IBR approved January 27, 1983 for Sec.
60.285(d)(3).
(e) The following material is available for purchase from the Water
Pollution Control Federation (WPCF), 2626 Pennsylvania Avenue NW.,
Washington, DC 20037.
(1) Method 209A, Total Residue Dried at 103-105 [deg]C, in Standard
Methods for the Examination of Water and Wastewater, 15th Edition, 1980,
IBR approved February 25, 1985 for Sec. 60.683(b).
(f) The following material is available for purchase from the
following address: 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.
(g) The following material is available for purchase from the
following address: West Coast Lumber Inspection Bureau, 6980 SW. Barnes
Road, Portland, OR 97223.
(1) West Coast Lumber Standard Grading Rules No. 16, pages 5-21 and
90 and 91, September 3, 1970, revised 1984.
(h) The following material is available for purchase from the
American Society of Mechanical Engineers (ASME), Three Park Avenue, New
York, NY 10016-5990.
(1) ASME QRO-1-1994, Standard for the Qualification and
Certification of Resource Recovery Facility Operators, IBR approved for
Sec. Sec. 60.56a, 60.54b(a), 60.54b(b), 60.1185(a), 60.1185(c)(2),
60.1675(a), and 60.1675(c)(2).
(2) ASME PTC 4.1-1964 (Reaffirmed 1991), Power Test Codes: Test Code
for Steam Generating Units (with 1968 and 1969 Addenda), IBR approved
for Sec. Sec. 60.46b of subpart Db of this part, 60.58a(h)(6)(ii),
60.58b(i)(6)(ii), 60.1320(a)(3) and 60.1810(a)(3).
(3) ASME Interim Supplement 19.5 on Instruments and Apparatus:
Application, Part II of Fluid Meters, 6th Edition (1971), IBR approved
for Sec. Sec. 60.58a(h)(6)(ii), 60.58b(i)(6)(ii), 60.1320(a)4), and
60.1810(a)(4).
(4) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], IBR approved for Sec. 60.56c(b)(4) of
subpart Ec, Sec. 60.106(e)(2) of subpart J, Sec. Sec. 60.104a(d)(3),
(d)(5), (d)(6), (h)(3), (h)(4), (h)(5), (i)(3), (i)(4), (i)(5), (j)(3),
and (j)(4), 60.105a(d)(4), (f)(2), (f)(4), (g)(2), and (g)(4),
60.106a(a)(1)(iii), (a)(2)(iii), (a)(2)(v), (a)(2)(viii), (a)(3)(ii),
and (a)(3)(v), and 60.107a(a)(1)(ii), (a)(1)(iv), (a)(2)(ii), (c)(2),
(c)(4), and (d)(2) of subpart Ja, tables 1 and 3 of subpart EEEE, tables
2 and 4 of subpart FFFF, table 2 of subpart JJJJ, and Sec. Sec.
60.4415(a)(2) and 60.4415(a)(3) of subpart KKKK of this part.
(j) ``Standard Methods for the Examination of Water and
Wastewater,'' 16th edition, 1985. Method 303F: ``Determination of
Mercury by the Cold Vapor
[[Page 90]]
Technique.'' This document may be obtained from the American Public
Health Association, 1015 18th Street, NW., Washington, DC 20036, and is
incorporated by reference for appendix A to part 60, Method 29, Sections
9.2.3; 10.3; and 11.1.3.
(k) This material is available for purchase from the American
Hospital Association (AHA) Service, Inc., Post Office Box 92683,
Chicago, Illinois 60675-2683. You may inspect a copy at 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.
(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 Sec. 60.35e
and Sec. 60.55c.
(l) This material is available for purchase from the National
Technical Information Services, 5285 Port Royal Road, Springfield,
Virginia 22161. You may inspect a copy at 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.
(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 Sec. 60.31e.
(2) [Reserved]
(m) This material is available for purchase from at least one of the
following addresses: The Gas Processors Association, 6526 East 60th
Street, Tulsa, OK, 74145; or Information Handling Services, 15 Inverness
Way East, PO Box 1154, Englewood, CO 80150-1154. You may inspect a copy
at EPA's Air and Radiation Docket and Information Center, Room B108,
1301 Constitution Ave., NW., Washington, DC 20460. You may inspect a
copy at EPA's Air and Radiation Docket and Information Center, Room
3334, 1301 Constitution Ave., NW., Washington, DC 20460.
(1) 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 Sec. Sec. 60.105(b)(1)(iv),
60.107a(b)(1)(iv), 60.334(h)(1), 60.4360, and 60.4415(a)(1)(ii).
(2) [Reserved]
(n) This material is available for purchase from IHS Inc., 15
Inverness Way East, Englewood, CO 80112.
(1) International Organization for Standards 8178-4: 1996(E),
Reciprocating Internal Combustion Engines--Exhaust Emission
Measurement--part 4: Test Cycles for Different Engine Applications, IBR
approved for Sec. 60.4241(b).
(2) [Reserved]
[48 FR 3735, Jan. 27, 1983]
Editorial Note: For Federal Register citations affecting Sec.
60.17, see the List of CFR Sections Affected, which appears in the
Finding Aids section of the printed volume and on GPO Access.
Sec. 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)
[[Page 91]]
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 Sec.
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:
[GRAPHIC] [TIFF OMITTED] TC01JN92.008
where:
HT=Net heating value of the sample, MJ/scm; where the net
enthalpy per mole of offgas is based on combustion at 25 [deg]C and 760
mm Hg, but the standard temperature for determining the volume
corresponding to one mole is 20 [deg]C;
[[Page 92]]
[GRAPHIC] [TIFF OMITTED] TC01JN92.009
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 Sec. 60.17); and
Hi=Net heat of combustion of sample component i, kcal/g mole
at 25 [deg]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 Sec. 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;
[[Page 93]]
(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.
[[Page 94]]
(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.
[GRAPHIC] [TIFF OMITTED] TR22DE08.007
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
Sec. 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.
[[Page 95]]
(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]
Sec. 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
[[Page 96]]
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]
Table 1 to Subpart A to Part 60-Detection Sensitivity Levels (grams per
hour)
------------------------------------------------------------------------
Detection
Monitoring frequency per subpart \a\ 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.
Sec. 60.20 Applicability.
The provisions of this subpart apply to States upon publication of a
final guideline document under Sec. 60.22(a).
Sec. 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
[[Page 97]]
which air quality criteria have not been issued and that is not included
on a list published under section 108(a) of the Act. Designated
pollutant also means any air pollutant, the emissions of which are
subject to a standard of performance for new stationary sources, that is
on the section 112(b)(1) list and is emitted from a facility that is not
part of a source category regulated under section 112. Designated
pollutant does not include pollutants on the section 112(b)(1) list that
are emitted from a facility that is part of a source category regulated
under section 112.
(b) Designated facility means any existing facility (see Sec.
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 Sec. 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 Sec. 60.27(b) or promulgated under Sec.
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 Sec.
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.
(k) Allowance system means a control program under which the owner
or operator of each designated facility is required to hold an
authorization for each specified unit of a designated pollutant emitted
from that facility during a specified period and which limits the total
amount of such authorizations available to be held for a designated
pollutant for a specified period and allows the transfer of such
authorizations not used to meet the authorization-holding requirement.
[40 FR 53346, Nov. 17, 1975, as amended at 70 FR 28649, May 18, 2005]
Sec. 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
[[Page 98]]
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]
Sec. 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 Sec. 60.22(a), each State shall adopt and submit to
the Administrator, in accordance with Sec. 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 Sec.
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
[[Page 99]]
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 Sec. 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]
Sec. 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.
(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 Sec.
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
[[Page 100]]
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 Sec. 60.22(b) and to information presented at the public
hearing(s) conducted under Sec. 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
Sec. 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 Sec. 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 Sec. 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.
(h) Each of the States identified in paragraph (h)(1) of this
section shall be subject to the requirements of paragraphs (h)(2)
through (7) of this section.
(1) Alaska, Alabama, Arkansas, Arizona, California, Colorado,
Connecticut, Delaware, Florida, Georgia, Hawaii, Idaho, Illinois,
Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, Maryland,
Massachusetts, Michigan, Minnesota, Mississippi, Missouri, Montana,
Nebraska, Nevada, New Hampshire, New Jersey, New Mexico, New York, North
Carolina, North Dakota, Ohio, Oklahoma, Oregon, Pennsylvania, Rhode
Island, South Carolina, South Dakota, Tennessee, Texas, Utah, Vermont,
Virginia, Washington, West Virginia, Wisconsin, Wyoming, and the
District of Columbia shall each, and, if approved for treatment as a
State under part 49 of this chapter, the Navajo Nation and the Ute
Indian Tribe may each, submit a State plan meeting the requirements of
paragraphs (h)(2) through (7) of this section and the other applicable
requirements for a State plan under this subpart.
(2) The State's State plan under paragraph (h)(1) of this section
must be submitted to the Administrator by no later than November 17,
2006. The State shall deliver five copies of the State plan to the
appropriate Regional Office, with a letter giving notice of such action.
(3) The State's State plan under paragraph (h)(1) of this section
shall contain emission standards and compliance schedules and
demonstrate that they will result in compliance with the State's annual
electrical generating unit (EGU) mercury (Hg) budget for the
[[Page 101]]
appropriate periods. The amount of the annual EGU Hg budget, in tons of
Hg per year, shall be as follows, for the indicated State for the
indicated period:
------------------------------------------------------------------------
Annual EGU Hg budget
(tons)
State -------------------------
2018 and
2010-2017 thereafter
------------------------------------------------------------------------
Alaska........................................ 0.010 0.004
Alabama....................................... 1.289 0.509
Arkansas...................................... 0.516 0.204
Arizona....................................... 0.454 0.179
California.................................... 0.041 0.016
Colorado...................................... 0.706 0.279
Connecticut................................... 0.053 0.021
Delaware...................................... 0.072 0.028
Florida....................................... 1.232 0.487
Georgia....................................... 1.227 0.484
Hawaii........................................ 0.024 0.009
Iowa.......................................... 0.727 0.287
Illinois...................................... 1.594 0.629
Indiana....................................... 2.097 0.828
Kansas........................................ 0.723 0.285
Kentucky...................................... 1.525 0.602
Louisiana..................................... 0.601 0.237
Massachusetts................................. 0.172 0.068
Maryland...................................... 0.490 0.193
Maine......................................... 0.001 0.001
Michigan...................................... 1.303 0.514
Minnesota..................................... 0.695 0.274
Missouri...................................... 1.393 0.550
Mississippi................................... 0.291 0.115
Montana....................................... 0.377 0.149
Navajo Nation................................. 0.600 0.237
North Carolina................................ 1.133 0.447
North Dakota.................................. 1.564 0.617
Nebraska...................................... 0.421 0.166
New Hampshire................................. 0.063 0.025
New Jersey.................................... 0.153 0.060
New Mexico.................................... 0.299 0.118
Nevada........................................ 0.285 0.112
New York...................................... 0.393 0.155
Ohio.......................................... 2.056 0.812
Oklahoma...................................... 0.721 0.285
Oregon........................................ 0.076 0.030
Pennsylvania.................................. 1.779 0.702
South Carolina................................ 0.580 0.229
South Dakota.................................. 0.072 0.029
Tennessee..................................... 0.944 0.373
Texas......................................... 4.656 1.838
Utah.......................................... 0.506 0.200
Ute Indian Tribe.............................. 0.060 0.024
Virginia...................................... 0.592 0.234
Washington.................................... 0.198 0.078
Wisconsin..................................... 0.890 0.351
West Virginia................................. 1.394 0.550
Wyoming....................................... 0.952 0.376
-------------------------
Total..................................... 38.000 15.000
------------------------------------------------------------------------
(4) Each State plan under paragraph (h)(1) of this section shall
require EGUs to comply with the monitoring, record keeping, and
reporting provisions of part 75 of this chapter with regard to Hg mass
emissions.
(5) In addition to meeting the requirements of Sec. 60.26, each
State plan under paragraph (h)(1) of this section must show that the
State has legal authority to:
(i) Adopt emissions standards and compliance schedules necessary for
attainment and maintenance of the State's relevant annual EGU Hg budget
under paragraph (h)(3) of this section; and
(ii) Require owners or operators of EGUs in the State to meet the
monitoring, record keeping, and reporting requirements described in
paragraph (h)(4) of this section.
(6)(i) Notwithstanding the provisions of paragraphs (h)(3) and
(5)(i) of this section, if a State adopts regulations substantively
identical to subpart HHHH of this part (Hg Budget Trading Program),
incorporates such subpart by reference into its regulations, or adopts
regulations that differ substantively from such subpart only as set
forth in paragraph (h)(6)(ii) of this section, then such allowance
system in the State's State plan is automatically approved as meeting
the requirements of paragraph (h)(3) of this section, provided that the
State demonstrates that it has the legal authority to take such action
and to implement its responsibilities under such regulations. Before
January 1, 2009, a State's regulations shall be considered to be
substantively identical to subpart HHHH of this part, or differing
substantively only as set forth in paragraph (h)(6)(ii) of this section,
regardless of whether the State's regulations include the definition of
``Biomass'', paragraph (3) of the definition of ``Cogeneration unit'',
and the second sentence of the definition of ``Total energy input'' in
Sec. 60.4102 of this chapter promulgated on October 19, 2007, provided
that the State timely submits to the Administrator a State plan that
revises the State's regulations to include such provisions. Submission
to the Administrator of a State plan that revises the State's
regulations to include such provisions shall be considered timely if the
submission is made by January 1, 2010.
(ii) If a State adopts an allowance system that differs
substantively from subpart HHHH of this part only as follows, then the
emissions trading program is approved as set forth in paragraph
(h)(6)(i) of this section.
[[Page 102]]
(A) The State may decline to adopt the allocation provisions set
forth in Sec. Sec. 60.4141 and 60.4142 and may instead adopt any
methodology for allocating Hg allowances.
(B) The State's methodology under paragraph (h)(6)(ii)(A) of this
section must not allow the State to allocate Hg allowances for a year in
excess of the amount in the State's annual EGU Hg budget for such year
under paragraph (h)(3) of this section;
(C) The State's methodology under paragraph (h)(6)(ii)(A) of this
section must require that, for EGUs commencing operation before January
1, 2001, the State will determine, and notify the Administrator of, each
unit's allocation of Hg allowances by November 17, 2006 for 2010, 2011,
and 2012 and by October 31, 2009 and October 31 of each year thereafter
for the fourth year after the year of the notification deadline; and
(D) The State's methodology under paragraph (h)(6)(ii)(A) of this
section must require that, for EGUs commencing operation on or after
January 1, 2001, the State will determine, and notify the Administrator
of, each unit's allocation of Hg allowances by October 31 of the year
for which the Hg allowances are allocated.
(7) If a State adopts an allowance system that differs substantively
from subpart HHHH of this part, other than as set forth in paragraph
(h)(6)(ii) of this section, then such allowance system is not
automatically approved as set forth in paragraph (h)(6)(i) or (ii) of
this section and will be reviewed by the Administrator for approvability
in accordance with the other provisions of paragraphs (h)(2) through (5)
of this section and the other applicable requirements for a State plan
under this subpart, provided that the Hg allowances issued under such
allowance system shall not, and the State plan under paragraph (h)(1) of
this section shall state that such Hg allowances shall not, qualify as
Hg allowances under any allowance system approved under paragraph
(h)(6)(i) or (ii) of this section.
(8) The terms used in this paragraph (h) shall have the following
meanings:
Administrator means the Administrator of the United States
Environmental Protection Agency or the Administrator's duly authorized
representative.
Allocate or allocation means, with regard to Hg allowances, the
determination of the amount of Hg allowances to be initially credited to
a source.
Biomass means--(1) Any organic material grown for the purpose of
being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into
energy; or
(3) Any material that can be converted into energy and is
nonmerchantable for other purposes, that is segregated from other
nonmerchantable material, and that is;
(i) A forest-related organic resource, including mill residues,
precommercial thinnings, slash, brush, or byproduct from conversion of
trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage,
manufacturing and construction materials (other than pressure-treated,
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
Boiler means an enclosed fossil-or other fuel-fired combustion
device used to produce heat and to transfer heat to recirculating water,
steam, or other medium.
Bottoming-cycle cogeneration unit means a cogeneration unit in which
the energy input to the unit is first used to produce useful thermal
energy and at least some of the reject heat from the useful thermal
energy application or process is then used for electricity production.
Coal means any solid fuel classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials (ASTM) Standard Specification for Classification of Coals by
Rank D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004) [egr]\1\
(incorporated by reference, see Sec. 60.17).
Coal-derived fuel means any fuel (whether in a solid, liquid, or
gaseous state) produced by the mechanical, thermal, or chemical
processing of coal.
Coal-fired means combusting any amount of coal or coal-derived fuel,
alone or in combination with any
[[Page 103]]
amount of any other fuel, during any year.
Cogeneration unit means a stationary, coal-fired boiler or
stationary, coal-fired combustion turbine:
(1) Having equipment used to produce electricity and useful thermal
energy for industrial, commercial, heating, or cooling purposes through
the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the
unit first produces electricity and during any calendar year after which
the unit first produces electricity:
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy
output; and
(B) Useful power that, when added to one-half of useful thermal
energy produced, is not less then 42.5 percent of total energy input, if
useful thermal energy produced is 15 percent or more of total energy
output, or not less than 45 percent of total energy input, if useful
thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle cogeneration unit, useful power not less
than 45 percent of total energy input;
(3) Provided that the total energy input under paragraphs (2)(i)(B)
and (2)(ii) of this definition shall equal the unit's total energy input
from all fuel except biomass if the unit is a boiler.
Combustion turbine means:
(1) An enclosed device comprising a compressor, a combustion, and a
turbine and in which the flue gas resulting from the combustion of fuel
in the combustion passes through the turbine, rotating the turbine; and
(2) If the enclosed device under paragraph (1) of this definition is
combined cycle, any associated heat recovery steam generator and steam
turbine.
Commence operation means to have begun any mechanical, chemical, or
electronic process, including, with regard to a unit, start-up of a
unit's combustion chamber.
Electric generating unit or EGU means:
(1)(i) Except as provided in paragraphs (2) and (3) of this
definition, a stationary, coal-fired boiler or stationary, coal-fired
combustion turbine in the State serving at any time, since the later of
November 15, 1990 or the start-up of the unit's combustion chamber, a
generator with nameplate capacity of more than 25 megawatts electric
(MWe) producing electricity for sale.
(ii) If a stationary boiler or stationary combustion turbine that,
under paragraph (1)(i) of this definition, is not an electric generating
unit begins to combust coal or coal-derived fuel or to serve a generator
with nameplate capacity of more than 25 MWe producing electricity for
sale, the unit shall become an electric generating unit as provided in
paragraph (1)(i) of this definition on the first date on which it both
combusts coal or coal-derived fuel and serves such generator.
(2) A unit that meets the requirements set forth in paragraph
(2)(i)(A) of this definition shall not be an electric generating unit:
(i)(A) A unit that is an electric generating unit under paragraph
(1)(i) or (ii) of this definition:
(1) Qualifying as a cogeneration unit during the 12-month period
starting on the date the unit first produces electricity and continuing
to qualify as a cogeneration unit; and
(2) Not serving at any time, since the later of November 15, 1990 or
the start-up of the unit's combustion chamber, a generator with
nameplate capacity of more than 25 MWe supplying in any calendar year
more than one-third of the unit's potential electric output capacity or
219,000 megawatt-hours (MWh), whichever is greater, to any utility power
distribution system for sale.
(B) If a unit qualifies as a cogeneration unit during the 12-month
period starting on the date the unit first produces electricity and
meets the requirements of paragraph (2)(i)(A) of this definition for at
least one calendar year, but subsequently no longer meets all such
requirements, the unit shall become an electric generating unit starting
on the earlier of January 1 after the first calendar year during which
the unit first no longer qualifies as a cogeneration unit or January 1
after the first calendar year during which the unit no longer meets the
requirements of paragraph (2)(i)(A)(2) of this definition.
[[Page 104]]
(3) A ``solid waste incineration unit'' as defined in Clean Air Act
section 129(g)(1) combusting ``municipal waste'' as defined in Clean Air
Act section 129(g)(5) shall not be an electric generating unit if it is
subject to one of the following rules:
(i) An EPA-approved State plan for implementing subpart Cb of part
60 of this chapter, ``Emissions Guidelines and Compliance Times for
Large Municipal Waste Combustors That Are Constructed On or Before
September 20, 1994'';
(ii) Subpart Eb of part 60 of this chapter, ``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'';
(iii) Subpart AAAA of part 60 of this chapter, ``Standards of
Performance for Small Municipal Waste Combustors for Which Construction
is Commenced After August 30, 1999 or for Which Modification or
Reconstruction is Commenced After June 6, 2001'';
(iv) An EPA-approved State Plan for implementing subpart BBBB of
part 60 of this chapter, ``Emission Guidelines and Compliance Times for
Small Municipal Waste Combustion Units Constructed On or Before August
30, 1999'';
(v) Subpart FFF of part 62 of this chapter, ``Federal Plan
Requirements for Large Municipal Waste Combustors Constructed On or
Before September 20, 1994; or
(vi) Subpart JJJ of 40 CFR part 62, ``Federal Plan Requirements for
Small Municipal Waste Combustion Units Constructed On or Before August
30, 1999''.
Generator means a device that produces electricity.
Gross electrical output means, with regard to a cogeneration unit,
electricity made available for use, including any such electricity used
in the power production process (which process includes, but is not
limited to, any on-site processing or treatment of fuel combusted at the
unit and any on-site emission controls).
Gross thermal energy means, with regard to a cogeneration unit,
useful thermal energy output plus, where such output is made available
for an industrial or commercial process, any heat contained in
condensate return or makeup water.
Heat input means, with regard to a specified period of time, the
product (in million British thermal units per unit time, MMBTU/time) of
the gross calorific value of the fuel (in Btu per pound, Btu/lb) divided
by 1,000,000 Btu/MMBTU and multiplied by the fuel feed rate into a
combustion device (in lb of fuel/time), as measured, recorded, and
reported to the Administrator by the Hg designated representative and
determined by the Administrator in accordance with Sec. Sec. 60.4170
through 60.4176 and excluding the heat derived from preheated combustion
air, reticulated flue gases, or exhaust from other sources.
Hg allowance means a limited authorization issued by the permitting
authority to emit one ounce of Hg during a control period of the
specified calendar year for which the authorization is allocated or of
any calendar year thereafter.
Life-of-the-unit, firm power contractual arrangement means a unit
participation power sales agreement under which a customer reserves, or
is entitled to receive, a specified amount or percentage of nameplate
capacity and associated energy generated by any specified unit and pays
its proportional amount of such unit's total costs, pursuant to a
contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including
contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic
useful life of the unit determined as of the time the unit is built,
with option rights to purchase or release some portion of the nameplate
capacity and associated energy generated by the unit at the end of the
period.
Maximum design heat input means, starting from the initial
installation of a unit, the maximum amount of fuel per hour (in Btu/hr)
that a unit is capable of combusting on a steady-state basis as
specified by the manufacturer of the unit, or, starting from the
completion of any subsequent physical
[[Page 105]]
change in the unit resulting in a decrease in the maximum amount of fuel
per hour (in Btu per hour, Btu/hr) that a unit is capable of combusting
on a steady-state basis, such decreased maximum amount as specified by
the person conducting the physical change.
Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MW) that the
generator is capable of producing on a steady-state basis and during
continuous operation (when not restricted by seasonal or other derates)
as specified by the manufacturer of the generator or, starting from the
completion of any subsequent physical change in the generator resulting
in an increase in the maximum electrical generating output (in MW) that
the generator is capable of producing on a steady-state basis and during
continuous operation (when not restricted by seasonal or other derates),
such increased maximum amount as specified by the person conducting the
physical change.
Operator means any person who operates, controls, or supervises an
EGU or a source that includes an EGU and shall include, but not be
limited to, any holding company, utility system, or plant manager of
such EGU or source.
Ounce means 2.84 x 10\7\ micrograms.
Owner means any of the following persons:
(1) With regard to a Hg Budget source or a Hg Budget unit at a
source, respectively:
(i) Any holder of any portion of the legal or equitable title in a
Hg Budget unit at the source or the Hg Budget unit;
(ii) Any holder of a leasehold interest in a Hg Budget unit at the
source or the Hg Budget unit; or
(iii) Any purchaser of power from a Hg Budget unit at the source or
the Hg Budget unit under a life-of-the-unit, firm power contractual
arrangement; provided that, unless expressly provided for in a leasehold
agreement, owner shall not include a passive lessor, or a person who has
an equitable interest through such lessor, whose rental payments are not
based (either directly or indirectly) on the revenues or income from
such Hg Budget unit; or
(2) With regard to any general account, any person who has an
ownership interest with respect to the Hg allowances held in the general
account and who is subject to the binding agreement for the Hg
authorized account representative to represent the person's ownership
interest with respect to Hg allowances.
Potential electrical output capacity means 33 percent of a unit's
maximum design heat input, divided by 3,413 Btu per kilowatt-hour (Btu/
kWh), divided by 1,000 kWh per megawatt-hour (kWh/MWh), and multiplied
by 8,760 hr/yr.
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat
from electricity production in a useful thermal energy application or
process; or
(2) For a bottoming-cycle cogeneration unit, the use of reject heat
from seful thermal energy application or process in electricity
production.
Source means all buildings, structures, or installations located in
one or more contiguous or adjacent properties under common control of
the same person or persons.
State means:
(1) For purposes of referring to a governing entity, one of the
States in the United States, the District of Columbia, or, if approved
for treatment as a State under part 49 of this chapter, the Navajo
Nation or Ute Indian Tribe that adopts the Hg Budget Trading Program
pursuant to Sec. 60.24(h)(6); or
(2) For purposes of referring to a geographic area, one of the
States in the United States, the District of Columbia, the Navajo Nation
Indian country, or the Ute Tribe Indian country.
Topping-cycle cogeneration unit means a cogeneration unit in which
the energy input to the unit is first used to produce useful power,
including electricity, and at least some of the reject heat from the
electricity production is then used to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total
energy of all forms supplied to the cogeneration unit, excluding energy
produced by the cogeneration unit itself. Each form of energy supplied
shall be measured by
[[Page 106]]
the lower heating value of that form of energy calculated as follows:
LHV = HHV - 10.55(W + 9H)
Where:
LHV = lower heating value of fuel in Btu/lb,
HHV = higher heating value of fuel in Btu/lb,
W = Weight % of moisture in fuel, and
H = Weight % of hydrogen in fuel.
Total energy output means, with regard to a cogeneration unit, the
sum of useful power and useful thermal energy produced by the
cogeneration unit.
Unit means a stationary coal-fired boiler or a stationary coal-fired
combustion turbine.
Useful power means, with regard to a cogeneration unit, electricity
or mechanical energy made available for use, excluding any such energy
used in the power production process (which process includes, but is not
limited to, any on-site processing or treatment of fuel combusted at the
unit and any on-site emission controls).
Useful thermal energy means, with regard to a cogeneration unit,
thermal energy that is:
(1) Made available to an industrial or commercial process (not a
power production process), excluding any heat contained in condensate
return or makeup water;
(2) Used in a heat application (e.g., space heating or domestic hot
water heating); or
(3) Used in a space cooling application (i.e., thermal energy used
by an absorption chiller).
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
[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]
Sec. 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 Sec. 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 Sec. 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
[[Page 107]]
included in the annual report required by Sec. 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]
Sec. 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.
Sec. 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
[[Page 108]]
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 Sec.
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 Sec. 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 Sec. 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
Sec. 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]
Sec. 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.
Sec. 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 C_Emission Guidelines and Compliance Times
Sec. 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.
[[Page 109]]
(d) Subpart Cd--Sulfuric Acid Production Plants.
(e) Subpart Ce--Hospital/Medical/Infectious Waste Incinerators.
[62 FR 48379, Sept. 15, 1997]
Sec. 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.
Sec. 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 Sec.
60.24(f) of subpart B of this part.
(b) The following authorities are retained by EPA:
(1) Approval of exemption claims in Sec. 60.32b(b)(1), (d), (e),
(f)(1), (i)(1);
(2) Approval of a nitrogen oxides trading program under Sec.
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 Sec. 608(b).
[71 FR 27332, May 10, 2006]
Sec. 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 Sec. 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]
Sec. 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,
[[Page 110]]
(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 Sec. 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 Sec. 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 Sec. 60.37b, the testing procedures
under Sec. 60.38b, and the reporting and recordkeeping provisions under
Sec. 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 Sec. 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
[[Page 111]]
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]
Sec. 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
[[Page 112]]
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
[[Page 113]]
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 Sec. 60.59b(f) or in the annual report specified in
Sec. 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.
[GRAPHIC] [TIFF OMITTED] TR19DE95.000
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 Sec. 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 Sec. 60.38b(a) and specified under Sec. 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.
[[Page 114]]
(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 Sec. 60.38b(a) and specified under Sec. 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]
Sec. 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 Sec. 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]
Sec. 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
Sec. 60.54b of subpart Eb of this part. The State plan shall require
compliance with these requirements
[[Page 115]]
according to the schedule specified in Sec. 60.39b(c)(4).
[60 FR 65415, Dec. 19, 1995, as amended at 62 FR 45120, Aug. 25, 1997]
Sec. 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 Sec. 60.55b of subpart Eb of this part.
Sec. 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
Sec. 60.56b of subpart Eb of this part.
Sec. 60.38b Compliance and performance testing.
(a) For approval, a State plan shall include the performance testing
methods listed in Sec. 60.58b of subpart Eb of this part, as
applicable, except as provided for under Sec. 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 Sec. 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]
Sec. 60.39b Reporting and recordkeeping guidelines and compliance schedules.
(a) For approval, a State plan shall include the reporting and
recordkeeping provisions listed in Sec. 60.59b of subpart Eb of this
part, as applicable, except for the siting requirements under Sec.
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 Sec. 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 Sec. 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. [Sec. 60.21 (h)(1) of subpart B of this part.];
(E) Date for ordering the air pollution control device(s);
[[Page 116]]
(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 Sec. 60.38b.
(3) [Reserved]
(4) A State plan shall require compliance with the municipal waste
combustor operator training and certification requirements under Sec.
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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec.
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
Sec. 60.33b(a)(3) and the emission limit for dioxins/furans specified
in Sec. 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 Sec. 60.32b shall be in compliance with all of the
guidelines, except those specified under Sec. 60.33b (a)(4), (b)(3),
and (d)(3), no later than December 19, 2000.
[[Page 117]]
(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 Sec. 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 Sec. 60.32b shall be in compliance with all of the
guidelines, including those specified under Sec. 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 Sec. 60.33b(a), (c), and (d) and the revised testing
provisions in Sec. 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 Sec. 60.32b shall be in compliance with all of the
guidelines, including the revised April 28, 2009 emission limits in
Sec. 60.33b(a), (b), (c), (d), and Sec. 60.34b(a), and the revised
testing provisions in Sec. 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]
Sec. Table 1 to Subpart Cb of part 60--Nitrogen Oxides Guidelines for
Designated Facilities
------------------------------------------------------------------------
Before April 28, On and after April
2009, nitrogen 28, 2009,
Municipal waste combustor oxides emission nitrogen oxides
technology limit (parts per emission limit
million by volume) (parts per million
\a\ 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]
Sec. 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
------------------------------------------------------------------------
On and after
Before April 28, April 28, 2009,
2009, nitrogen nitrogen oxides
Municipal waste combustor oxides emission emission limit
technology limit (parts per (parts per
million by million by
volume) \b\ 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]
[[Page 118]]
Sec. Table 3 to Subpart Cb of Part 60--Municipal Waste Combustor
Operating Guidelines
------------------------------------------------------------------------
Carbon monoxide
emissions levels
Municipal waste combustor (parts per Averaging time
technology million by (hrs) \b\
volume) \a\
------------------------------------------------------------------------
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/ 200 \c\ 24
refuse-derived fuel).............
Bubbling fluidized bed combustor.. 100 4
Circulating fluidized bed 100 4
combustor........................
Pulverized coal/refuse-derived 150 4
fuel mixed fuel-fired combustor..
Spreader stoker coal/refuse- 200 24
derived fuel mixed fuel-fired
combustor........................
Semi-suspension refuse-derived 250 \c\ 24
fuel-fired combustor/wet refuse-
derived fuel process conversion..
Spreader stoker fixed floor refuse- 250 \c\ 24
derived fuel-fired combustor/100
percent coal capable.............
------------------------------------------------------------------------
\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.
Sec. 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.
Sec. 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.
Sec. 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 Sec. 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
[[Page 119]]
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 Sec. Sec. 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 Sec. 60.33c(c) of this subpart; or
(2) The owner or operator meets the conditions for control system
removal specified in Sec. 60.752(b)(2)(v) of subpart WWW.
[61 FR 9919, Mar. 12, 1996, as amended at 63 FR 32750, June 16, 1998]
Sec. 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 Sec.
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 Sec. 60.24.
(1) An open flare designed and operated in accordance with the
parameters established in Sec. 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 Sec.
60.757(a)(2) of subpart WWW by the date specified in Sec. 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 Sec. 60.757(a)(3) of subpart WWW. [Guidance: Note
that if the design capacity increase is the result of a modification, as
defined in Sec. 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
[[Page 120]]
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 Sec. 60.752(b)(2) of subpart WWW or calculate an initial
NMOC emission rate for the landfill using the procedures specified in
Sec. 60.34c of this subpart and Sec. 60.754 of subpart WWW. The NMOC
emission rate shall be recalculated annually, except as provided in
Sec. 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
Sec. 60.757(b)(1)(ii); and
(ii) Recalculate the NMOC emission rate annually using the
procedures specified in Sec. 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 Sec. 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 Sec. 60.35c of
this subpart and Sec. 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]
Sec. 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 Sec. 60.754,
as applicable, to determine whether the landfill meets the condition in
Sec. 60.33c(a)(3); the operational standards in Sec. 60.753; the
compliance provisions in Sec. 60.755; and the monitoring provisions in
Sec. 60.756.
Sec. 60.35c Reporting and recordkeeping guidelines.
For approval, a State plan shall include the recordkeeping and
reporting provisions listed in Sec. Sec. 60.757 and 60.758, as
applicable, except as provided under Sec. 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]
Sec. 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 Sec. 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 Sec.
60.33c(a)(1) and Sec. 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 Sec. 60.33c shall be accomplished within
30 months of the date when the condition in
[[Page 121]]
Sec. 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.
Sec. 60.30d Designated facilities.
Sulfuric acid production units. The designated facility to which
Sec. Sec. 60.31d and 60.32d apply is each existing ``sulfuric acid
production unit'' as defined in Sec. 60.81(a) of subpart H of this
part.
Sec. 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.
Sec. 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 Sec. 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.
Sec. 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 Sec. 60.24(f)
of subpart B of this part.
Sec. 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 Sec. 60.17).
Sec. 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 Sec. 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 Sec. 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
[[Page 122]]
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 Sec. 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 Sec. 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.
[60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51402, Oct. 6, 2009]
Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 60.32e(a)(1)
subject to the emissions guidelines as promulgated on September 15,
1997, the requirements in Sec. 60.52c(b)(1) of subpart Ec of this part.
(2) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions guidelines as amended on October 6, 2009 and a
designated facility
[[Page 123]]
as defined in Sec. 60.32e(a)(2), the requirements in Sec. 60.52c(b)(2)
of subpart Ec of this part.
[74 FR 51403, Oct. 6, 2009]
Sec. 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 Sec. 60.53c of subpart Ec of this part. The
State plan shall require compliance with these requirements according to
the schedule specified in Sec. 60.39e(e).
Sec. 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 Sec. 60.55c of subpart Ec of this part.
Sec. 60.36e Inspection guidelines.
(a) For approval, a State plan shall require each small HMIWI
subject to the emissions limits under Sec. 60.33e(b) and each HMIWI
subject to the emissions limits under Sec. 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 Sec. 60.33e(b) and each HMIWI
subject to the emissions limits under Sec. 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 Sec. 60.33e(b)(2) and each HMIWI
subject to the emissions limits under Sec. 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;
[[Page 124]]
(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 Sec. 60.33e(b)(2) and each HMIWI
subject to the emissions limits under Sec. 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]
Sec. 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 Sec. 60.56c of subpart Ec of this part,
with the following exclusions:
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions limits in Sec. 60.33e(a)(1), the test methods
listed in Sec. 60.56c(b)(7) and (8), the fugitive emissions testing
requirements under Sec. 60.56c(b)(14) and (c)(3), the CO CEMS
requirements under Sec. 60.56c(c)(4), and the compliance requirements
for monitoring listed in Sec. 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 Sec. 60.32e(a)(1) and
(a)(2) subject to the emissions limits in Sec. 60.33e(a)(2) and (a)(3),
the annual fugitive emissions testing requirements under Sec.
60.56c(c)(3), the CO CEMS requirements under Sec. 60.56c(c)(4), and the
compliance requirements for monitoring listed in Sec. 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
Sec. 60.33e(a)(2) and (a)(3) may, however, elect to use CO CEMS as
specified under Sec. 60.56c(c)(4) or bag leak detection systems as
specified under Sec. 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 Sec. 60.33e(b) to meet the
performance testing requirements listed in Sec. 60.56c of subpart Ec of
this part. The 2,000 lb/week limitation under Sec. 60.33e(b) does not
apply during performance tests.
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to the emissions limits under Sec. 60.33e(b)(1), the test
methods listed in Sec. 60.56c(b)(7), (8), (12), (13) (Pb and Cd), and
(14), the annual PM, CO, and HCl emissions testing requirements under
Sec. 60.56c(c)(2), the annual fugitive emissions testing requirements
under Sec. 60.56c(c)(3), the CO CEMS requirements under Sec.
60.56c(c)(4), and the compliance requirements for monitoring listed in
Sec. 60.56c(c)(5) through (7), and (d) through (k) do not apply.
(2) For a designated facility as defined in Sec. 60.32e(a)(2)
subject to the emissions limits under Sec. 60.33e(b)(2), the annual
fugitive emissions testing requirements under Sec. 60.56c(c)(3), the CO
CEMS requirements under Sec. 60.56c(c)(4), and the compliance
requirements for monitoring listed in Sec. 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 Sec. 60.33e(b)(2) may, however, elect to use CO CEMS as
specified under Sec. 60.56c(c)(4) or bag leak detection systems as
specified under Sec. 60.57c(h).
(c) For approval, a State plan shall require each small HMIWI
subject to the emissions limits under Sec. 60.33e(b) that is not
equipped with an air pollution control device to meet the following
compliance and performance testing requirements:
[[Page 125]]
(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 Sec. 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 Sec. 60.57c of subpart Ec of this part for HMIWI
subject to the emissions limits under Sec. 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 Sec. 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
Sec. 60.32e(a)(1) or (a)(2) subject to emissions limits under Sec.
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 Sec. 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).
[[Page 126]]
(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]
Sec. 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 Sec. 60.58c(b) through (g) of
subpart Ec of this part.
(1) For a designated facility as defined in Sec. 60.32e(a)(1)
subject to emissions limits under Sec. 60.33e(a)(1) or (b)(1),
excluding Sec. 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 Sec. 60.32e(a)(1) or
(a)(2) subject to emissions limits under Sec. 60.33e(a)(2), (a)(3), or
(b)(2), excluding Sec. 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 Sec. 60.33e to:
(1) As specified in Sec. 60.36e, maintain records of the annual
equipment inspections that are required for each HMIWI subject to the
emissions limits under Sec. 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 Sec. 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]
Sec. 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 Sec. 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 Sec. 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);
[[Page 127]]
(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 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 Sec.
60.34e--Operator training and qualification guidelines and Sec.
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]
Sec. Table 1A to Subpart Ce of Part 60--Emissions Limits for Small,
Medium, and Large HMIWI at Designated Facilities as Defined in Sec.
60.32e(a)(1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions limits
--------------------------------------------------------------- Method for
Pollutant Units (7 percent HMIWI size Averaging time demonstrating
oxygen, dry basis) --------------------------------------------------------------- \1\ compliance \2\
Small Medium Large
--------------------------------------------------------------------------------------------------------------------------------------------------------
Particulate matter............. Milligrams per dry 115 (0.05)......... 69 (0.03)......... 34 (0.015).......... 3-run average (1- EPA Reference
standard cubic hour minimum Method 5 of
meter (mg/dscm) sample time per appendix A-3 of
(grains per dry run). part 60, or EPA
standard cubic Reference Method
foot (gr/dscf)). 26A or 29 of
appendix A-8 of
part 60.
[[Page 128]]
Carbon monoxide................ Parts per million 40................. 40................ 40.................. 3-run average (1- EPA Reference
by volume (ppmv). hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
Dioxins/furans................. Nanograms per dry 125 (55) or 2.3 125 (55) or 2.3 125 (55) or 2.3 3-run average (4- EPA Reference
standard cubic (1.0). (1.0). (1.0). hour minimum Method 23 of
meter total sample time per appendix A-7 of
dioxins/furans run). part 60.
(ng/dscm) (grains
per billion dry
standard cubic
feet (gr/10\9\
dscf)) or ng/dscm
TEQ (gr/10\9\
dscf).
Hydrogen chloride.............. ppmv.............. 100 or 93%......... 100 or 93%........ 100 or 93%.......... 3-run average (1- EPA Reference
hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide................. ppmv.............. 55................. 55................ 55.................. 3-run average (1- EPA Reference
hour minimum Method 6 or 6C
sample time per of appendix A-4
run). of part 60.
Nitrogen oxides................ ppmv.............. 250................ 250............... 250................. 3-run average (1- EPA Reference
hour minimum Method 7 or 7E
sample time per of appendix A-4
run). of part 60.
Lead........................... mg/dscm (grains 1.2 (0.52) or 70%.. 1.2 (0.52) or 70%. 1.2 (0.52) or 70%... 3-run average (1- EPA Reference
per thousand dry hour minimum Method 29 of
standard cubic sample time per appendix A-8 of
feet (gr/10\3\ run). part 60.
dscf)).
Cadmium........................ mg/dscm (gr/10\3\ 0.16 (0.07) or 65%. 0.16 (0.07) or 65% 0.16 (0.07) or 65%.. 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
[[Page 129]]
Mercury........................ mg/dscm (gr/10\3\ 0.55 (0.24) or 85%. 0.55 (0.24) or 85% 0.55 (0.24) or 85%.. 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[60 FR 65414, Dec. 19, 1995, as amended at 74 FR 51405, Oct. 6, 2009]
Sec. Table 1B to Subpart Ce of Part 60--Emissions Limits for Small,
Medium, and Large HMIWI at Designated Facilities as Defined in Sec.
60.32e(a)(1) and (a)(2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions limits
--------------------------------------------------------------- Method for
Pollutant Units (7 percent HMIWI size Averaging time demonstrating
oxygen, dry basis) --------------------------------------------------------------- \1\ compliance \2\
Small Medium Large
--------------------------------------------------------------------------------------------------------------------------------------------------------
Particulate matter............. Milligrams per dry 66 (0.029)......... 46 (0.020)......... 25 (0.011)......... 3-run average (1- EPA Reference
standard cubic hour minimum Method 5 of
meter (mg/dscm) sample time per appendix A-3 of
(grains per dry run). part 60, or EPA
standard cubic Reference Method
foot (gr/dscf)). 26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide................ Parts per million 20................. 5.5................ 11................. 3-run average (1- EPA Reference
by volume (ppmv). hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
Dioxins/furans................. Nanograms per dry 16 (7.0) or 0.013 0.85 (0.37) or 9.3 (4.1) or 0.054 3-run average (4- EPA Reference
standard cubic (0.0057). 0.020 (0.0087). (0.024). hour minimum Method 23 of
meter total sample time per appendix A-7 of
dioxins/furans run). part 60.
(ng/dscm) (grains
per billion dry
standard cubic
feet (gr/10\9\
dscf)) or ng/dscm
TEQ (gr/10\9\
dscf).
Hydrogen chloride.............. ppmv.............. 44................. 7.7................ 6.6................ 3-run average (1- EPA Reference
hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide................. ppmv.............. 4.2................ 4.2................ 9.0................ 3-run average (1- EPA Reference
hour minimum Method 6 or 6C
sample time per of appendix A-4
run). of part 60.
[[Page 130]]
Nitrogen oxides................ ppmv.............. 190................ 190................ 140................ 3-run average (1- EPA Reference
hour minimum Method 7 or 7E
sample time per of appendix A-4
run). of part 60.
Lead........................... mg/dscm (grains 0.31 (0.14)........ 0.018 (0.0079)..... 0.036 (0.016)...... 3-run average (1- EPA Reference
per thousand dry hour minimum Method 29 of
standard cubic sample time per appendix A-8 of
feet (gr/10\3\ run). part 60.
dscf)).
Cadmium........................ mg/dscm (gr/10\3\ 0.017 (0.0074)..... 0.013 (0.0057)..... 0.0092 (0.0040).... 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
Mercury........................ mg/dscm (gr/10\3\ 0.014 (0.0061)..... 0.025 (0.011)...... 0.018 (0.0079)..... 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[74 FR 51406, Oct. 6, 2009]
Sec. Table 2A to Subpart Ce of Part 60--Emissions Limits for Small
HMIWI Which Meet the Criteria Under Sec. 60.33e(b)(1)
----------------------------------------------------------------------------------------------------------------
Units (7 percent Method for
Pollutant oxygen, dry HMIWI emissions limits Averaging time demonstrating
basis) \1\ compliance \2\
----------------------------------------------------------------------------------------------------------------
Particulate matter............ mg/dscm (gr/dscf) 197 (0.086)............ 3-run average (1- EPA Reference
hour minimum Method 5 of
sample time per appendix A-3 of
run). part 60, or EPA
Reference Method
26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide............... ppmv............. 40..................... 3-run average (1- EPA Reference
hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
Dioxins/furans................ ng/dscm total 800 (350) or 15 (6.6).. 3-run average (4- EPA Reference
dioxins/furans hour minimum Method 23 of
(gr/10\9\ dscf) sample time per appendix A-7 of
or ng/dscm TEQ run). part 60.
(gr/10\9\ dscf).
Hydrogen chloride............. ppmv............. 3,100.................. 3-run average (1- EPA Reference
hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide................ ppmv............. 55..................... 3-run average (1- EPA Reference
hour minimum Method 6 or 6C
sample time per of appendix A-4
run). of part 60.
Nitrogen oxides............... ppmv............. 250.................... 3-run average (1- EPA Reference
hour minimum Method 7 or 7E
sample time per of appendix A-4
run). of part 60.
Lead.......................... mg/dscm (gr/10\3\ 10 (4.4)............... 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
Cadmium....................... mg/dscm (gr/10\3\ 4 (1.7)................ 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
[[Page 131]]
Mercury....................... mg/dscm (gr/10\3\ 7.5 (3.3).............. 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
----------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[74 FR 51407, Oct. 6, 2009]
Sec. Table 2B to Subpart Ce of Part 60--Emissions Limits for Small HMIWI
Which Meet the Criteria Under Sec. 60.33e(b)(2)
----------------------------------------------------------------------------------------------------------------
Units (7 percent Method for
Pollutant oxygen, dry HMIWI Emissions limits Averaging time demonstrating
basis) \1\ compliance \2\
----------------------------------------------------------------------------------------------------------------
Particulate matter............ mg/dscm (gr/dscf) 87 (0.038)............. 3-run average (1- EPA Reference
hour minimum Method 5 of
sample time per appendix A-3 of
run). part 60, or EPA
Reference Method
26A or 29 of
appendix A-8 of
part 60.
Carbon monoxide............... ppmv............. 20..................... 3-run average (1- EPA Reference
hour minimum Method 10 or 10B
sample time per of appendix A-4
run). of part 60.
Dioxins/furans................ ng/dscm total 240 (100) or 5.1 (2.2). 3-run average (4- EPA Reference
dioxins/furans hour minimum Method 23 of
(gr/10\9\ dscf) sample time per appendix A-7 of
or ng/dscm TEQ run). part 60.
(gr/10\9\ dscf).
Hydrogen chloride............. ppmv............. 810.................... 3-run average (1- EPA Reference
hour minimum Method 26 or 26A
sample time per of appendix A-8
run). of part 60.
Sulfur dioxide................ ppmv............. 55..................... 3-run average (1- EPA Reference
hour minimum Method 6 or 6C
sample time per of appendix A-4
run). of part 60.
Nitrogen oxides............... ppmv............. 130.................... 3-run average (1- EPA Reference
hour minimum Method 7 or 7E
sample time per of appendix A-4
run). of part 60.
Lead.......................... mg/dscm (gr/10\3\ 0.50 (0.22)............ 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
Cadmium....................... mg/dscm (gr/10\3\ 0.11 (0.048)........... 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
Mercury....................... mg/dscm (gr/10\3\ 0.0051 (0.0022)........ 3-run average (1- EPA Reference
dscf). hour minimum Method 29 of
sample time per appendix A-8 of
run). part 60.
----------------------------------------------------------------------------------------------------------------
\1\ Except as allowed under Sec. 60.56c(c) for HMIWI equipped with CEMS.
\2\ Does not include CEMS and approved alternative non-EPA test methods allowed under Sec. 60.56c(b).
[74 FR 51407, Oct. 6, 2009]
Subpart D_Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17, 1971
Source: 72 FR 32717, June 13, 2007, unless otherwise noted.
Sec. 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
[[Page 132]]
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 Sec. Sec. 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 covered under subpart Da is not covered under this
subpart.
Sec. 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
Sec. 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.
Wood residue means bark, sawdust, slabs, chips, shavings, mill trim,
and other wood products derived from wood processing and forest
management operations.
Sec. 60.42 Standard for particulate matter (PM).
(a) On and after the date on which the performance test required to
be conducted by Sec. 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 Sec. 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 Sec. 60.43Da(a) of subpart Da of this part.
[60 FR 65415, Dec. 19, 1995, as amended at 74 FR 5077, Jan. 28, 2009]
Sec. 60.43 Standard for sulfur dioxide (SO[bdi2]).
(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
Sec. 60.8 is
[[Page 133]]
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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.000
Where:
PSSO2 = 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 Sec. 60.43Da(i)(3) of subpart
Da of this part or comply with Sec. 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
Sec. 60.43Da(i)(3) of subpart Da of this part or Sec. 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]
Sec. 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
Sec. 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:
[[Page 134]]
[GRAPHIC] [TIFF OMITTED] TR13JN07.001
Where:
PSNOX = 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 Sec. 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 Sec. 60.44Da(e)(3) of
subpart Da of this part.
Sec. 60.45 Emissions and fuel monitoring.
(a) Each owner or operator shall install, calibrate, maintain, and
operate continuous opacity monitoring system (COMS) for measuring
opacity and a 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 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 burns 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, CEMS
for measuring the opacity of emissions and 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 Sec. 60.13(b), installation of a CEMS for
NOX may be delayed until after the initial performance tests
under Sec. 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
Sec. 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
Sec. 60.8 and comply with all other applicable monitoring requirements
under this part.
(4) If an owner or operator does not install any CEMS for sulfur
oxides and NOX, as provided under paragraphs (b)(1) and
(b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for
measuring either O2 or CO2 is not required.
(5) An owner or operator may petition the Administrator (in writing)
to install a PM CEMS as an alternative to the CEMS for monitoring
opacity emissions.
(6) A CEMS for measuring the opacity of emissions is not required
for a
[[Page 135]]
fossil fuel-fired steam generator 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 Sec. 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 Sec. 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) The owner or operator of an affected facility subject to an
opacity standard under Sec. 60.42 and that elects to not install 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 Sec. 60.11 to demonstrate compliance with the applicable
limit in Sec. 60.42 and shall comply with either paragraphs (b)(7)(i),
(b)(7)(ii), or (b)(7)(iii) of this section. If during the initial 60
minutes of observation all 6-minute averages are less than 10 percent
and all individual 15-second observations are less than or equal to 20
percent, the observation period may be reduced from 3 hours to 60
minutes.
(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.
[[Page 136]]
(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;
(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;
(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
(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 30 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 30
calendar days according to the requirements in Sec. 60.46(b)(3).
(B) If no visible emissions are observed for 30 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.
(c) For performance evaluations under Sec. 60.13(c) and calibration
checks under Sec. 60.13(d), the following procedures shall be used:
[[Page 137]]
(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
Sec. 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:
----------------------------------------------------------------------------------------------------------------
In parts per million
Fossil fuel ---------------------------------------------------------------------------
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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.002
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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.003
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).
[[Page 138]]
(2) C = pollutant concentration, ng/dscm (lb/dscf), determined by
multiplying the average concentration (ppm) for each one-hour period by
4.15 x 10\4\ M ng/dscm per ppm (2.59 x 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 Sec. 60.17), F = 2,723 x
10-17 dscm/J (10,140 dscf/MMBtu) and Fc = 0.532 x
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 Sec. 60.17), F = 2.637 x
10-7 dscm/J (9,820 dscf/MMBtu) and Fc = 0.486 x
10-7 scm CO2/J (1,810 scf CO2/MMBtu).
(iii) For liquid fossil fuels including crude, residual, and
distillate oils, F = 2.476 x 10-7 dscm/J (9,220 dscf/MMBtu)
and Fc = 0.384 x 10-7 scm CO2/J (1,430
scf CO2/MMBtu).
(iv) For gaseous fossil fuels, F = 2.347 x 10-7 dscm/J
(8,740 dscf/MMBtu). For natural gas, propane, and butane fuels,
Fc = 0.279 x 10-7 scm CO2/J (1,040 scf
CO2/MMBtu) for natural gas, 0.322 x 10-7 scm
CO2/J (1,200 scf CO2/MMBtu) for propane, and 0.338
x 10-7 scm CO2/J (1,260 scf CO2/MMBtu)
for butane.
(v) For bark F = 2.589 x 10-7 dscm/J (9,640 dscf/MMBtu)
and Fc = 0.500 x 10-7 scm CO2/J (1,840
scf CO2/MMBtu). For wood residue other than bark F = 2.492 x
10-7 dscm/J (9,280 dscf/MMBtu) and Fc = 0.494 x
10-7 scm CO2/J (1,860 scf CO2/MMBtu).
(vi) For lignite coal as classified according to ASTM D388
(incorporated by reference, see Sec. 60.17), F = 2.659 x
10-7 dscm/J (9,900 dscf/MMBtu) and Fc = 0.516 x
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:
[[Page 139]]
[GRAPHIC] [TIFF OMITTED] TR13JN07.004
(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
Sec. 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 Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.005
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 Sec.
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 Sec.
60.42(b)(1), excess emissions are defined as any six-minute period
during which the average opacity
[[Page 140]]
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 Sec.
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 Sec.
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
Sec. 60.43; or
(ii) For affected facilities electing to comply with Sec. 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 Sec. 60.43. Facilities complying with the 30-day
SO2 standard shall use the most current associated
SO2 compliance and monitoring requirements in Sec. Sec.
60.48Da and 60.49Da of subpart Da of this part or Sec. Sec. 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 Sec.
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 Sec. 60.44; or
(ii) For affected facilities electing to comply with Sec. 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 Sec. 60.44. Facilities complying with the 30-day
NOX standard shall use the most current associated
NOX compliance and monitoring requirements in Sec. Sec.
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 Sec.
60.42. Affected facilities using PM CEMS must follow the most current
applicable compliance and monitoring provisions in Sec. Sec. 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 Sec. 60.42 that elects to monitor emissions according
to the requirements in Sec. 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
[[Page 141]]
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]
Sec. 60.46 Test methods and procedures.
(a) In conducting the performance tests required in Sec. 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 Sec. 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 Sec. Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.006
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 16014 [deg]C (32025 [deg]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 Sec.
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
[[Page 142]]
(%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 Sec. Sec. 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 Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.007
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 [deg]C (320 [deg]F). The
procedures of sections 8.1 and 11.1 of Method 5B of appendix A-3 of this
part
[[Page 143]]
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 for Which Construction is Commenced After September 18,
1978
Source: 72 FR 32722, June 13, 2007, unless otherwise noted.
Sec. 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/hr) heat input of fossil fuel
(either alone or in combination with any other fuel); 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 the requirement 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) and (2) of
this section.
(1) Heat recovery steam generators used with duct burners and
associated with an electric utility combined cycle gas turbine that are
capable of combusting more than 73 MW (250 MMBtu/hr) heat input of
fossil fuel are subject to this subpart except in cases when
[[Page 144]]
the heat recovery steam generator meets the applicability requirements
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 KKK, as applicable, of this part).
[72 FR 32722, June 13, 2007, as amended at 74 FR 5078, Jan. 28, 2009]
Sec. 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.
Anthracite means coal that is classified as anthracite according to
the American Society of Testing and Materials in ASTM D388 (incorporated
by reference, see Sec. 60.17).
Available purchase power means the lesser of the following:
(a) The sum of available system capacity in all neighboring
companies.
(b) The sum of the rated capacities of the power interconnection
devices between the principal company and all neighboring companies,
minus the sum of the electric power load on these interconnections.
(c) The rated capacity of the power transmission lines between the
power interconnection devices and the electric generating units (the
unit in the principal company that has the malfunctioning flue gas
desulfurization system and the unit(s) in the neighboring company
supplying replacement electrical power) less the electric power load on
these transmission lines.
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 Sec. 60.17).
Boiler operating day for units constructed, reconstructed, or
modified on or before February 28, 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 Sec. 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 (not meeting the definition of natural gas), 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.
Cogeneration, also known as ``combined heat and power,'' means a
steam-generating unit that simultaneously produces both electric (or
mechanical) and useful thermal energy from the same primary energy
source.
Combined cycle gas turbine means a stationary turbine combustion
system where heat from the turbine exhaust gases is recovered by a steam
generating unit.
Dry flue gas desulfurization technology or dry FGD means a sulfur
dioxide control system that is located downstream of the steam
generating unit and removes sulfur oxides (SO2) from the
[[Page 145]]
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 FGD 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 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 company means the largest interconnected
organization, business, or governmental entity that generates electric
power for sale (e.g., a holding company with operating subsidiary
companies).
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.
Emergency condition means that period of time when:
(1) The electric generation output of an affected facility with a
malfunctioning flue gas desulfurization system cannot be reduced or
electrical output must be increased because:
(i) All available system capacity in the principal company
interconnected with the affected facility is being operated, and
(ii) All available purchase power interconnected with the affected
facility is being obtained, or
(2) The electric generation demand is being shifted as quickly as
possible from an affected facility with a malfunctioning flue gas
desulfurization system to one or more electrical generating units held
in reserve by the principal company or by a neighboring company, or
(3) An affected facility with a malfunctioning flue gas
desulfurization system becomes the only available unit to maintain a
part or all of the principal company's system emergency reserves and the
unit is operated in spinning reserve at the lowest practical electric
generation load consistent with not causing significant physical damage
to the unit. If the unit is operated at a higher load to meet load
demand, an emergency condition would not exist unless the conditions
under paragraph (1) of this definition apply.
Emission limitation means any emissions limit or operating limit.
Emission rate period means any calendar month included in a 12-month
rolling average period.
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
[[Page 146]]
material for the purpose of creating useful heat.
Gaseous fuel means any fuel derived from coal or petroleum that is
present as a gas at standard conditions and includes, but is not limited
to, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and
gasified coal.
Gross output means the gross useful work performed by the steam
generated and, for an IGCC electric utility steam generating unit, the
work performed by the stationary combustion turbines. For a unit
generating only electricity, the gross useful work performed is the
gross electrical output from the unit's turbine/generator sets. For a
cogeneration unit, 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).
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. No solid fuel is directly
burned in the unit during operation.
Interconnected means that two or more electric generating units are
electrically tied together by a network of power transmission lines, and
other power transmission equipment.
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 Sec. 60.17).
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) Liquid petroleum gas, as defined by the American Society of
Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec. 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).
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 system capacity means the sum of the net electric generating
capability (not necessarily equal to rated capacity) of all electric
generating equipment owned by an electric utility company (including
steam generating units, internal combustion engines, gas turbines,
nuclear units, hydroelectric units, and all other electric generating
equipment) plus firm contractual purchases that are interconnected to
the affected facility that has the malfunctioning flue gas
desulfurization system. The electric generating capability of equipment
under multiple ownership is prorated based on ownership unless the
proportional entitlement to electric output is otherwise established by
contractual arrangement.
Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Petroleum means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate oil, and residual oil.
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
[[Page 147]]
state without emission control systems) and:
(1) For particulate matter (PM) is:
(i) 3,000 ng/J (7.0 lb/MMBtu) heat input for solid fuel; and
(ii) 73 ng/J (0.17 lb/MMBtu) heat input for liquid fuels.
(2) For sulfur dioxide (SO2) is determined under Sec.
60.50Da(c).
(3) For nitrogen oxides (NOX) is:
(i) 290 ng/J (0.67 lb/MMBtu) heat input for gaseous fuels;
(ii) 310 ng/J (0.72 lb/MMBtu) heat input for liquid fuels; and
(iii) 990 ng/J (2.30 lb/MMBtu) heat input for solid fuels.
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.
Principal company means the electric utility company or companies
which own the affected facility.
Resource recovery unit means a facility that combusts more than 75
percent non-fossil fuel on a quarterly (calendar) heat input basis.
Responsible official means responsible official as defined in 40 CFR
70.2.
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.
Spare flue gas desulfurization system module means a separate system
of SO2 emission control equipment capable of treating an
amount of flue gas equal to the total amount of flue gas generated by an
affected facility when operated at maximum capacity divided by the total
number of nonspare flue gas desulfurization modules in the system.
Spinning reserve means the sum of the unutilized net generating
capability of all units of the electric utility company that are
synchronized to the power distribution system and that are capable of
immediately accepting additional load. The electric generating
capability of equipment under multiple ownership is prorated based on
ownership unless the proportional entitlement to electric output is
otherwise established by contractual arrangement.
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).
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 Sec. 60.17).
System emergency reserves means an amount of electric generating
capacity equivalent to the rated capacity of the single largest electric
generating unit in the electric utility company (including steam
generating units, internal combustion engines, gas turbines, nuclear
units, hydroelectric units, and all other electric generating equipment)
which is interconnected with the affected facility that has the
malfunctioning flue gas desulfurization system. The electric generating
capability of equipment under multiple ownership is prorated based on
ownership unless the proportional entitlement to electric output is
otherwise established by contractual arrangement.
System load means the entire electric demand of an electric utility
company's service area interconnected with the affected facility that
has the malfunctioning flue gas desulfurization system plus firm
contractual sales to other electric utility companies. Sales to other
electric utility companies (e.g., emergency power) not on a firm
contractual basis may also be included in the system load when no
available system capacity exists in the electric utility company to
which the power is supplied for sale.
Wet flue gas desulfurization technology or wet FGD means a
SO2 control system that is located downstream of the
[[Page 148]]
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]
Sec. 60.42Da 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 Sec. 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 or on February 28, 2005, any gases that
contain PM in excess of:
(1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel;
(2) 1 percent of the potential combustion concentration (99 percent
reduction) when combusting solid fuel; and
(3) 30 percent of potential combustion concentration (70 percent
reduction) when combusting liquid fuel.
(b) On and after the date the initial PM performance test is
completed or required to be completed under Sec. 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 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. 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 are exempt from the
opacity standard specified in this paragraph b.
(c) Except as provided in paragraph (d) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, reconstruction, or 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 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, 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 Sec. 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 for which
construction, reconstruction, or modification commenced after February
28, 2005, any gases that contain PM in excess of:
(1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion
of solid, liquid, or gaseous fuel, and
(2) 0.1 percent of the combustion concentration determined according
to the procedure in Sec. 60.48Da(o)(5) (99.9 percent reduction) for an
affected facility for which construction or reconstruction commenced
after February 28, 2005 when combusting solid, liquid, or gaseous fuel,
or
(3) 0.2 percent of the combustion concentration determined according
to the procedure in Sec. 60.48Da(o)(5) (99.8 percent reduction) for an
affected facility for which modification commenced after February 28,
2005 when combusting solid, liquid, or gaseous fuel.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5079, Jan. 28, 2009]
[[Page 149]]
Sec. 60.43Da Standard for sulfur dioxide (SO[bdi2]).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 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); or
(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.
(b) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 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 Sec. 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 emission reduction requirements under this section do not
apply to any affected facility that is operated under an SO2
commercial demonstration permit issued by the Administrator in
accordance with the provisions of Sec. 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
[GRAPHIC] [TIFF OMITTED] TR13JN07.008
(2) If emissions of SO2 to the atmosphere are equal to or
less than 260 ng/J (0.60 lb/MMBtu) heat input:
[[Page 150]]
[GRAPHIC] [TIFF OMITTED] TR13JN07.009
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 Sec. 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 shall cause 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 (i)(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) 5 percent of the potential combustion concentration (95 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) 5 percent of the potential combustion concentration (95
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.
(j) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 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:
[[Page 151]]
(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 Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area that commenced construction, reconstruction, or
modification commenced after February 28, 2005, shall cause 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 (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 on a 30-day rolling average basis.
(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
if the affected facility or 230 ng/J (0.54 lb/MMBtu) heat input on a 30-
day rolling average basis.
Sec. 60.44Da Standard for nitrogen oxides (NOX).
(a) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 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, except as provided under paragraphs (b), (d), (e),
and (f) of this section, any gases that contain NOX
(expressed as NO2) in excess of the following emission
limits, based on a 30-day rolling average basis, except as provided
under Sec. 60.48Da(j)(1):
(1) NOX emission limits.
------------------------------------------------------------------------
Emission limit for
heat input
Fuel type ---------------------
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, \(1)\ \(1)\
coal refuse..................................
Any fuel containing more than 25%, by weight, 340 0.80
lignite if the lignite is mined in North
Dakota, South Dakota, or Montana, and is
combusted in a slag tap furnace \2\..........
Any fuel containing more than 25%, by weight, 260 0.60
lignite not subject to the 340 ng/J heat
input emission limit \2\.....................
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) NOX reduction requirement.
------------------------------------------------------------------------
Percent
reduction of
Fuel type potential
combustion
concentration
------------------------------------------------------------------------
Gaseous fuels......................................... 25
Liquid fuels.......................................... 30
Solid fuels........................................... 65
------------------------------------------------------------------------
(b) The emission limitations under paragraph (a) of this section do
not apply to any affected facility which is combusting coal-derived
liquid fuel and is operating under a commercial demonstration permit
issued by the Administrator in accordance with the provisions of Sec.
60.47Da.
(c) Except as provided under paragraphs (d), (e), and (f) of this
section, when two or more fuels are combusted simultaneously, the
applicable standard is determined by proration using the following
formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.010
Where:
[[Page 152]]
En = Applicable standard for NOX 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.
(d)(1) On and after the date on which the initial performance test
is completed or required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commenced construction after July 9, 1997, but before or on February 28,
2005 shall cause to be discharged into the atmosphere any gases that
contain NOX (expressed as NO2) in excess of 200
ng/J (1.6 lb/MWh) gross energy output, based on a 30-day rolling average
basis, except as provided under Sec. 60.48Da(k).
(2) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 60.8, whichever date
comes first, no owner or operator of affected facility for which
reconstruction commenced after July 9, 1997, but before or on February
28, 2005 shall cause to be discharged into the atmosphere any gases that
contain NOX (expressed as NO2) in excess of 65 ng/
J (0.15 lb/MMBtu) heat input, based on a 30-day rolling average basis.
(e) Except for an IGCC electric utility steam generating unit
meeting the requirements of paragraph (f) of this section, on and after
the date on which the initial performance test is completed or required
to be completed under Sec. 60.8, whichever date comes first, no owner
or operator of an affected facility that commenced construction,
reconstruction, or modification after February 28, 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 emission limitation specified in paragraphs (e)(1)
through (3) of this section.
(1) For an affected facility for which construction commenced after
February 28, 2005, 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 on a 30-day rolling average basis, except as provided
under Sec. 60.48Da(k).
(2) For an affected facility for which reconstruction commenced
after February 28, 2005, the owner or operator shall not cause to be
discharged into the atmosphere any gases that contain NOX
(expressed as NO2) in excess of either:
(i) 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling
average basis; or
(ii) 47 ng/J (0.11 lb/MMBtu) heat input on a 30-day rolling average
basis.
(3) For an affected facility for which modification commenced after
February 28, 2005, the owner or operator shall not cause to be
discharged into the atmosphere any gases that contain NOX
(expressed as NO2) in excess of either:
(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling
average basis; or
(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average
basis.
(f) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 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, 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
on a 30-day rolling average basis.
(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
[[Page 153]]
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 on a 30-day rolling average
basis.
(3) In cases when during a 30-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 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.
Sec. 60.45Da Standard for mercury (Hg).
(a) For each coal-fired electric utility steam generating unit other
than an IGCC electric utility steam generating unit, on and after the
date on which the initial performance test is completed or required to
be completed under Sec. 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, modification, or reconstruction commenced after January
30, 2004, any gases that contain mercury (Hg) emissions in excess of
each Hg emissions limit in paragraphs (a)(1) through (5) of this section
that applies to you. The Hg emissions limits in paragraphs (a)(1)
through (5) of this section are based on a 12-month rolling average
basis using the procedures in Sec. 60.50Da(h).
(1) For each coal-fired electric utility steam generating unit that
burns only bituminous coal, you must not discharge into the atmosphere
any gases from a new affected source that contain Hg in excess of 20 x
10-\6\ pound per megawatt hour (lb/MWh) or 0.020 lb/gigawatt-
hour (GWh) on an output basis. The International System of Units (SI)
equivalent is 0.0025 ng/J.
(2) For each coal-fired electric utility steam generating unit that
burns only subbituminous coal:
(i) If your unit is located in a county-level geographical area
receiving greater than 25 inches per year (in/yr) mean annual
precipitation, based on the most recent publicly available U.S.
Department of Agriculture 30-year data, you must not discharge into the
atmosphere any gases from a new affected source that contain Hg in
excess of 66 x 10-\6\ lb/MWh or 0.066 lb/GWh on an output
basis. The SI equivalent is 0.0083 ng/J.
(ii) If your unit is located in a county-level geographical area
receiving less than or equal to 25 in/yr mean annual precipitation,
based on the most recent publicly available U.S. Department of
Agriculture 30-year data, you must not discharge into the atmosphere any
gases from a new affected source that contain Hg in excess of 97 x
10-\6\ lb/MWh or 0.097 lb/GWh on an output basis. The SI
equivalent is 0.0122 ng/J.
(3) For each coal-fired electric utility steam generating unit that
burns only lignite, you must not discharge into the atmosphere any gases
from a new affected source that contain Hg in excess of 175 x
10-\6\ lb/MWh or 0.175 lb/GWh on an output basis. The SI
equivalent is 0.0221 ng/J.
(4) For each coal-burning electric utility steam generating unit
that burns only coal refuse, you must not discharge into the atmosphere
any gases from a new affected source that contain Hg in excess of 16 x
10-\6\ lb/MWh or 0.016 lb/GWh on an output basis. The SI
equivalent is 0.0020 ng/J.
(5) For each coal-fired electric utility steam generating unit that
burns a blend of coals from different coal ranks (i.e., bituminous coal,
subbituminous coal, lignite) or a blend of coal and coal refuse, you
must not discharge into the atmosphere any gases from a new affected
source that contain Hg in excess of the unit-specific Hg emissions limit
established according to paragraph (a)(5)(i) or (ii) of this section, as
applicable to the affected unit.
(i) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend of
coal and coal
[[Page 154]]
refuse, you must not discharge into the atmosphere any gases from a new
affected source that contain Hg in excess of the computed weighted Hg
emissions limit based on the Btu, MWh, or MJ) contributed by each coal
rank burned during the compliance period and its applicable Hg emissions
limit in paragraphs (a)(1) through (4) of this section as determined
using Equation 1 in this section. For each affected source, you must
comply with the weighted Hg emissions limit calculated using Equation 1
in this section based on the total Hg emissions from the unit and the
total Btu, MWh, or MJ contributed by all fuels burned during the
compliance period.
[GRAPHIC] [TIFF OMITTED] TR13JN07.011
Where:
ELb = Total allowable Hg in lb/MWh that can be emitted to the
atmosphere from any affected source being averaged according to this
paragraph.
ELi = Hg emissions limit for the subcategory i (coal rank)
that applies to affected source, lb/MWh;
HHi = For each affected source, the Btu, MWh, or MJ
contributed by the corresponding subcategory i (coal rank) burned during
the compliance period; and
n = Number of subcategories (coal ranks) being averaged for an affected
source.
(ii) If you operate a coal-fired electric utility steam generating
unit that burns a blend of coals from different coal ranks or a blend of
coal and coal refuse together with one or more non-regulated,
supplementary fuels, you must not discharge into the atmosphere any
gases from a new affected source that contain Hg in excess of the
computed weighted Hg emission limit based on the Btu, MWh, or MJ
contributed by each coal rank burned during the compliance period and
its applicable Hg emissions limit in paragraphs (a)(1) through (4) of
this section as determined using Equation 1 in this section. For each
affected source. You must comply with the weighted Hg emissions limit
calculated using Equation 1 in this section based on the total Hg
emissions from the unit contributed by both regulated and nonregulated
fuels burned during the compliance period and the total Btu, MWh, or MJ
contributed by both regulated and nonregulated fuels burned during the
compliance period.
(b) For each IGCC electric utility steam generating unit, on and
after the date on which the initial performance test required to be
conducted under Sec. 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 for which construction,
modification, or reconstruction commenced after January 30, 2004, any
gases that contain Hg emissions in excess of 20 x 10-\6\ lb/
MWh or 0.020 lb/GWh on an output basis. The SI equivalent is 0.0025 ng/
J. This Hg emissions limit is based on a 12-month rolling average basis
using the procedures in Sec. 60.50Da(h).
Sec. 60.46Da [Reserved]
Sec. 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 Sec. 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 a fluidized bed combustion electric
utility steam generator (atmospheric or pressurized) who is issued a
commercial
[[Page 155]]
demonstration permit by the Administrator is not subject to the
SO2 emission reduction requirements under Sec. 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 Sec.
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.
------------------------------------------------------------------------
Equivalent
electrical
Technology Pollutant 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
------------------------------------------------------------------------
Sec. 60.48Da Compliance provisions.
(a) Compliance with the PM emission limitation under Sec.
60.42Da(a)(1) constitutes compliance with the percent reduction
requirements for PM under Sec. 60.42Da(a)(2) and (3).
(b) Compliance with the NOX emission limitation under
Sec. 60.44Da(a)(1) constitutes compliance with the percent reduction
requirements under Sec. 60.44Da(a)(2).
(c) The PM emission standards under Sec. 60.42Da, the
NOX emission standards under Sec. 60.44Da, and the Hg
emission standards under Sec. 60.45Da apply at all times except during
periods of startup, shutdown, or malfunction.
(d) During emergency conditions in the principal company, an
affected facility with a malfunctioning flue gas desulfurization system
may be operated if SO2 emissions are minimized by:
(1) Operating all operable flue gas desulfurization system modules,
and bringing back into operation any malfunctioned module as soon as
repairs are completed,
(2) Bypassing flue gases around only those flue gas desulfurization
system modules that have been taken out of operation because they were
incapable of any SO2 emission reduction or which would have
suffered significant physical damage if they had remained in operation,
and
(3) Designing, constructing, and operating a spare flue gas
desulfurization system module for an affected facility larger than 365
MW (1,250 MMBtu/hr) heat input (approximately 125 MW electrical output
capacity). The Administrator may at his discretion require the owner or
operator within 60 days of notification to demonstrate spare module
capability. To demonstrate this capability, the owner or operator must
demonstrate compliance with the appropriate requirements under paragraph
under Sec. 60.43Da(a), (b), (d), (e), and (h) for any period of
operation lasting from 24 hours to 30 days when:
(i) Any one flue gas desulfurization module is not operated,
(ii) The affected facility is operating at the maximum heat input
rate,
(iii) The fuel fired during the 24-hour to 30-day period is
representative of the type and average sulfur content of fuel used over
a typical 30-day period, and
(iv) The owner or operator has given the Administrator at least 30
days notice of the date and period of time over which the demonstration
will be performed.
[[Page 156]]
(e) After the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limitations and percentage
reduction requirements under Sec. 60.43Da and the NOX
emission limitations under Sec. 60.44Da 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 day average emission
rate for both SO2 and NOX and a new percent
reduction for SO2 are calculated to show compliance with the
standards.
(f) For the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limitations and percent
reduction requirements under Sec. 60.43Da and the NOX
emission limitation under Sec. 60.44Da is based on the average emission
rates for SO2, NOX, 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.
(g) The owner or operator of an affected facility subject to
emission limitations in this subpart shall determine compliance as
follows:
(1) Compliance with applicable 30-day rolling average SO2
and NOX emission limitations 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, malfunction (NOX
only), or emergency conditions (SO2 only).
(2) 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.
(3) Compliance with applicable daily average PM emission limitations
is determined by calculating the arithmetic average of all hourly
emission rates for PM each boiler operating day, except for data
obtained during startup, shutdown, and malfunction. Averages are only
calculated for boiler operating days that have valid data for at least
18 hours of unit operation during which the standard applies. Instead,
all of the valid hourly emission rates of the operating day(s) not
meeting the minimum 18 hours valid data daily average requirement are
averaged with all of the valid hourly emission rates of the next boiler
operating day with 18 hours or more of valid PM CEMS data to determine
compliance.
(h) If an owner or operator has not obtained the minimum quantity of
emission data as required under Sec. 60.49Da of this subpart,
compliance of the affected facility with the emission requirements under
Sec. Sec. 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 Sec.
60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f). The owner or
operator of an affected facility subject to Sec. 60.44Da(d)(1), (e)(1),
(e)(2)(i), (e)(3)(i), or (f) shall calculate NOX emissions as
1.194 x 10-\7\ lb/scf-ppm times the average hourly
NOX output concentration in ppm (measured according to the
provisions of Sec. 60.49Da(c)), times the average hourly flow rate
(measured in scfh, according to the provisions of Sec. 60.49Da(l) or
Sec. 60.49Da(m)), divided by the average hourly gross energy output
(measured according to the provisions of Sec. 60.49Da(k)).
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
Sec. Sec. 60.49Da(c) and (d)), by the hourly heat input rate (measured
according to the provisions of Sec. 60.49Da(n)), and dividing the
result by the average gross energy output (measured according to the
provisions of Sec. 60.49Da(k)).
(j) Compliance provisions for duct burners subject to Sec.
60.44Da(a)(1). To determine compliance with the emissions limits for
NOX required by Sec. 60.44Da(a) for duct burners used in
combined cycle systems, either of the procedures
[[Page 157]]
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 Sec. 60.8 using the appropriate
methods in appendix A of this part. Compliance with the emissions limits
under Sec. 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 Sec. 60.49Da for
measuring NOX and oxygen (O2) (or carbon dioxide
(CO2)) and meet the requirements of Sec. 60.49Da.
Alternatively, data from a NOX emission rate (i.e.,
NOX-diluent) CEMS certified according to the provisions of
Sec. 75.20(c) of this chapter and appendix A to part 75 of this
chapter, and meeting the quality assurance requirements of Sec. 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 Sec.
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 Sec.
60.44Da(d)(1) or (e)(1). To determine compliance with the emission
limitation for NOX required by Sec. 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 Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.012
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/MWh)
gross 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/hr (dscf/hr);
Qte = Average hourly volumetric flow rate of exhaust gas from
combustion turbine, dscm/hr (dscf/hr);
Osg = Average hourly gross energy output from steam
generating unit, J (MWh); 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 Sec. 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.
[[Page 158]]
(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 Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.013
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/MWh)
gross 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/hr (dscf/hr); and
Occ = Average hourly gross energy output from entire combined
cycle unit, J (MWh).
(ii) The CEMS specified under Sec. 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
Sec. 60.49Da(l) or Sec. 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 Sec. 60.49Da(m) is selected, the
flow rate data used to meet the requirements of Sec. 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 Sec.
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 Sec. 60.49Da(l), determine the mass rate (lb/hr) 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.014
Where:
E = Emission rate of NOX from the duct burner, ng/J (lb/MWh)
gross 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/hr (MMBtu/hr); and
Occ = Average hourly gross energy output from entire combined
cycle unit, J (MWh).
(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) Compliance provisions for sources subject to Sec. 60.45Da. The
owner or operator of an affected facility subject to Sec. 60.45Da (new
sources constructed or reconstructed after January 30, 2004) shall
calculate the Hg emission rate (lb/MWh) for each calendar month of
[[Page 159]]
the year, using hourly Hg concentrations measured according to the
provisions of Sec. 60.49Da(p) in conjunction with hourly stack gas
volumetric flow rates measured according to the provisions of Sec.
60.49Da(l) or (m), and hourly gross electrical outputs, determined
according to the provisions in Sec. 60.49Da(k). Compliance with the
applicable standard under Sec. 60.45Da is determined on a 12-month
rolling average basis.
(m) Compliance provisions for sources subject to Sec.
60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or
(j)(3)(i). The owner or operator of an affected facility subject to
Sec. 60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or
(j)(3)(i) shall calculate SO2 emissions as 1.660 x
10-7 lb/scf-ppm times the average hourly SO2
output concentration in ppm (measured according to the provisions of
Sec. 60.49Da(b)), times the average hourly flow rate (measured
according to the provisions of Sec. 60.49Da(l) or Sec. 60.49Da(m)),
divided by the average hourly gross energy output (measured according to
the provisions of Sec. 60.49Da(k)). 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 Sec. 60.49Da, by the hourly heat
input rate (measured according to the provisions of Sec. 60.49Da(n)),
and dividing the result by the average gross energy output (measured
according to the provisions of Sec. 60.49Da(k)).
(n) Compliance provisions for sources subject to Sec.
60.42Da(c)(1). The owner or operator of an affected facility subject to
Sec. 60.42Da(c)(1) shall calculate PM emissions by multiplying the
average hourly PM output concentration (measured according to the
provisions of Sec. 60.49Da(t)), by the average hourly flow rate
(measured according to the provisions of Sec. 60.49Da(l) or Sec.
60.49Da(m)), and divided by the average hourly gross energy output
(measured according to the provisions of Sec. 60.49Da(k)). Compliance
with the emission limit is determined by calculating the arithmetic
average of the hourly emission rates computed for each boiler operating
day.
(o) Compliance provisions for sources subject to Sec. 60.42Da(c)(2)
or (d). Except as provided for in paragraph (p) of this section, the
owner or operator of an affected facility for which construction,
reconstruction, or modification commenced after February 28, 2005, shall
demonstrate compliance with each applicable emission 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 Sec. 60.42Da(c)(2)
or (d) by the applicable date specified in Sec. 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 Sec. 60.8 using the test methods and procedures in
Sec. 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 Sec. 60.42Da(c)(2) or (d) 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
[[Page 160]]
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.
[[Page 161]]
(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 Sec. 60.42Da(c)(2)
or (d) 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 Sec.
60.42Da(c)(2) or (d) 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 Sec. 60.42Da(c)(2) or (d) 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.)
[[Page 162]]
(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;
[[Page 163]]
(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 Sec. 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 Sec. 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 Sec. 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, valid CEMS hourly averages shall be obtained for
75 percent of all operating hours on a 30-day rolling average basis.
Beginning on January 1, 2012, valid CEMS hourly averages shall be
obtained for 90 percent of all operating hours on a 30-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 Sec. 60.13(e)(2) of subpart A of this part.
(7) All valid CEMS data shall be used in calculating average
emission concentrations even if the minimum
[[Page 164]]
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, valid emissions data for a
minimum of 90 percent (only 75 percent is required prior to January 1,
2012) of all operating hours per 30-day rolling average.
(q) Compliance provisions for sources subject to Sec. 60.42Da(b).
An owner or operator of an affected facility subject to the opacity
standard in Sec. 60.42Da(b) shall monitor the opacity of emissions
discharged from the affected facility to the atmosphere according to the
requirements in Sec. 60.49Da(a), as applicable to the affected
facility.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5079, Jan. 28, 2009]
Sec. 60.49Da Emission monitoring.
(a) An owner or operator of an affected facility subject to the
opacity standard in Sec. 60.42Da(b) shall monitor the opacity of
emissions discharged from the affected facility to the atmosphere
according to the applicable requirements in paragraphs (a)(1) through
(3) of this section.
(1) Except as provided for in paragraph (a)(2) of this section, the
owner or operator of an affected facility, 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), or (iii)
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 Sec. 60.42Da and a bag leak detection system is
installed and operated according to the requirements in paragraphs Sec.
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; or
(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 carbon monoxide (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.
(3) The owner or operators of an affected facility that meets the
conditions in paragraph (a)(2) of this section may, as an alternative to
COMS, elect to monitor visible emissions using the applicable procedures
specified in paragraphs (a)(3)(i) through (iv) of this section.
(i) The owner or operator shall conduct a performance test using
Method 9 of appendix A-4 of this part and the procedures in Sec. 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
[[Page 165]]
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)(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;
(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;
(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
(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 30 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 30
calendar days according to the requirements in Sec. 60.50Da(b)(3).
(B) If no visible emissions are observed for 30 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 shall 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
[[Page 166]]
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) 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 SO2 emissions, except where natural gas
is the only fuel 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 Sec. 60.43Da(d), (i), (j), or (k) 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 Sec. 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 Sec.
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 Sec. 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 Sec. 60.51Da are met. The
SO2 and, if required, CO2 (or O2) data
reported to meet the requirements of Sec. 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 Sec.
60.51Da. Data reported to meet the requirements of Sec. 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 Sec. 60.43Da, if the owner or
operator has installed and certified a CO2 or O2
monitoring system according to Sec. 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 Sec.
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
[[Page 167]]
emission rate in lb/MMBtu. SO2 data used to meet the
requirements of Sec. 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, malfunction or
emergency conditions, 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 Sec. 60.13(h) are
expressed in ng/J (lb/MMBtu) heat input and used to calculate the
average emission rates under Sec. 60.48Da. The 1-hour averages are
calculated using the data points required under Sec. 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
Sec. 60.13(c) and calibration checks under Sec. 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:
[[Page 168]]
------------------------------------------------------------------------
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 Sec.
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 output for sources
demonstrating compliance with the output-based standard under Sec. Sec.
60.42Da(c), 60.43Da(i), 60.43Da(j), 60.44Da(d)(1), and 60.44Da(e).
(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 affected facilities generating process steam in combination
with electrical generation, the gross energy output is determined from
the gross electrical output measured in accordance with paragraph (k)(1)
of this section plus 75 percent of the gross thermal output (measured
relative to ISO conditions) of the process steam measured in accordance
with paragraph (k)(2) of this section.
(l) The owner or operator of an affected facility demonstrating
compliance with an output-based standard under Sec. 60.42Da, Sec.
60.43Da, Sec. 60.44Da, or Sec. 60.45Da 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 CD
[[Page 169]]
assessment, 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 Sec. 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 Sec. 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 Sec. 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 Sec.
60.41Da, which is subject to the NOX standards of Sec.
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) The owner or operator of an affected facility demonstrating
compliance with an Hg limit in Sec. 60.45Da shall install and operate a
CEMS to measure and record the concentration of Hg in the exhaust gases
from each stack according to the requirements in paragraphs (p)(1)
through (p)(3) of this section. Alternatively, for an affected facility
that is also subject to the requirements of subpart I of part 75 of this
chapter, the owner or operator may install, certify, maintain, operate
and quality-assure the data from a Hg CEMS according to Sec. 75.10 of
this chapter and appendices A and B to part 75 of this chapter, in lieu
of following the procedures in paragraphs (p)(1) through (p)(3) of this
section.
(1) The owner or operator must install, operate, and maintain each
CEMS according to Performance Specification 12A in appendix B to this
part.
(2) The owner or operator must conduct a performance evaluation of
each CEMS according to the requirements of Sec. 60.13 and Performance
Specification 12A in appendix B to this part.
(3) The owner or operator must operate each CEMS according to the
requirements in paragraphs (p)(3)(i) through (iv) of this section.
(i) As specified in Sec. 60.13(e)(2), each CEMS must complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period.
(ii) The owner or operator must reduce CEMS data as specified in
Sec. 60.13(h).
(iii) The owner or operator shall use all valid data points
collected during the hour to calculate the hourly average Hg
concentration.
(iv) The owner or operator must record the results of each required
certification and quality assurance test of the CEMS.
(4) Mercury CEMS data collection must conform to paragraphs
(p)(4)(i) through (iv) of this section.
(i) For each calendar month in which the affected unit operates,
valid hourly Hg concentration data, stack gas volumetric flow rate data,
moisture data (if required), and electrical output data (i.e., valid
data for all of these parameters) shall be obtained for at least 75
percent of the unit operating hours in the month.
(ii) Data reported to meet the requirements of this subpart shall
not include hours of unit startup, shutdown, or malfunction. In
addition, for an affected facility that is also subject to subpart I of
part 75 of this chapter, data reported to meet the requirements of this
subpart 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.
[[Page 170]]
(iii) If valid data are obtained for less than 75 percent of the
unit operating hours in a month, you must discard the data collected in
that month and replace the data with the mean of the individual monthly
emission rate values determined in the last 12 months. In the 12-month
rolling average calculation, this substitute Hg emission rate shall be
weighted according to the number of unit operating hours in the month
for which the data capture requirement of Sec. 60.49Da(p)(4)(i) was not
met.
(iv) Notwithstanding the requirements of paragraph (p)(4)(iii) of
this section, if valid data are obtained for less than 75 percent of the
unit operating hours in another month in that same 12-month rolling
average cycle, discard the data collected in that month and replace the
data with the highest individual monthly emission rate determined in the
last 12 months. In the 12-month rolling average calculation, this
substitute Hg emission rate shall be weighted according to the number of
unit operating hours in the month for which the data capture requirement
of Sec. 60.49Da(p)(4)(i) was not met.
(q) As an alternative to the CEMS required in paragraph (p) of this
section, the owner or operator may use a sorbent trap monitoring system
(as defined in Sec. 72.2 of this chapter) to monitor Hg concentration,
according to the procedures described in Sec. 75.15 of this chapter and
appendix K to part 75 of this chapter.
(r) For Hg CEMS that measure Hg concentration on a dry basis or for
sorbent trap monitoring systems, the emissions data must be corrected
for the stack gas moisture content. A certified continuous moisture
monitoring system that meets the requirements of Sec. 75.11(b) of this
chapter is acceptable for this purpose. Alternatively, the appropriate
default moisture value, as specified in Sec. 75.11(b) or Sec. 75.12(b)
of this chapter, may be used.
(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 Sec. 60.13(d) or part 75 of this chapter
(as applicable);
(5) Ongoing data quality assurance procedures in accordance with the
general requirements of Sec. 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 limitation under Sec.
60.42Da(c)(1) shall install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v) of
this section. An owner or operator of an affected facility demonstrating
compliance with the input-based emission limitation in Sec.
60.42Da(a)(1) or Sec. 60.42Da(c)(2) 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.
[[Page 171]]
(i) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec. 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 Sec. 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 Sec. 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) After July 1, 2010 or after Method 202 of appendix M of part 51
has been revised to minimize artifact measurement and notice of that
change has been published in the Federal Register, whichever is later,
for condensable PM emissions, Method 202 of appendix M of part 51 shall
be used; and
(iii) 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) After July 1, 2011, within 90 days after the date of completing
each performance evaluation required by paragraph (v) of this section,
the owner or operator of the affected facility must either submit the
test data to EPA by successfully entering the data electronically into
EPA's WebFIRE data base available at http://cfpub.epa.gov/oarweb/
index.cfm?action=fire.main or
[[Page 172]]
mail a copy to: United States Environmental Protection Agency; Energy
Strategies Group; 109 TW Alexander DR; Mail Code: D243-01; RTP, NC
27711.
(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 Sec. 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
[[Page 173]]
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]
Sec. 60.50Da Compliance determination procedures and methods.
(a) In conducting the performance tests required in Sec. 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 Sec. 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) The owner or operator shall determine compliance with the PM
standards in Sec. 60.42Da as follows:
(1) 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.
(2) For the particular matter concentration, Method 5 of appendix A
of this part shall be used at affected facilities without wet FGD
systems and Method 5B of appendix A of this part shall be used after wet
FGD systems.
(i) 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 16014 [deg]C
(32025 [deg]F).
(ii) 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.
(3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
(c) The owner or operator shall determine compliance with the
SO2 standards in Sec. 60.43Da as follows:
(1) The percent of potential SO2 emissions (%Ps) to the
atmosphere shall be computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TR13JN07.015
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
[[Page 174]]
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 Sec. 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 Sec. 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 Sec. 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 [deg]C (320 [deg]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 Sec. 60.46(d)(1). The CO2
shall be determined in the same manner as the O2
concentration.
(f) Electric utility combined cycle gas turbines that are not
designed to burn fuels containing 50 percent (by heat input) or more
solid derived fuel not meeting the definition of natural gas are
performance tested 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.
(g) For the purposes of determining compliance with the emission
limits in Sec. 60.45Da, the owner or operator of an electric utility
steam generating unit which is also a cogeneration unit shall use the
procedures in paragraphs (g)(1) and (2) of this section to calculate
emission rates based on electrical output to the grid plus 75 percent of
the equivalent electrical energy (measured relative to ISO conditions)
in the unit's process stream.
(1) All conversions from Btu/hr unit input to MW unit output must
use equivalents found in 40 CFR 60.40(a)(1) for electric utilities
(i.e., 250 MMBtu/hr input to an electric utility steam generating unit
is equivalent to 73 MW input to the electric utility steam generating
unit); 73 MW input to the electric utility steam generating unit is
equivalent to 25 MW output from the boiler electric utility steam
generating unit; therefore, 250 MMBtu input to the electric utility
steam generating unit is equivalent to 25 MW output from the electric
utility steam generating unit).
(2) Use the Equation 5 in this section to determine the cogeneration
Hg emission rate over a specific compliance period.
[GRAPHIC] [TIFF OMITTED] TR13JN07.016
[[Page 175]]
Where:
ERcogen = Cogeneration Hg emission rate over a compliance
period in lb/MWh;
E = Mass of Hg emitted from the stack over the same compliance period
(lb);
Vgrid = Amount of energy sent to the grid over the same
compliance period (MWh); and
Vprocess = Amount of energy converted to steam for process
use over the same compliance period (MWh).
(h) The owner or operator shall determine compliance with the Hg
limit in Sec. 60.45Da according to the procedures in paragraphs (h)(1)
through (3) of this section.
(1) The initial performance test shall be commenced by the
applicable date specified in Sec. 60.8(a). The required CEMS must be
certified prior to commencing the test. The performance test consists of
collecting hourly Hg emission data (lb/MWh) with the CEMS for 12
successive months of unit operation (excluding hours of unit startup,
shutdown and malfunction). The average Hg emission rate is calculated
for each month, and then the weighted, 12-month average Hg emission rate
is calculated according to paragraph (h)(2) or (h)(3) of this section,
as applicable. If, for any month in the initial performance test, the
minimum data capture requirement in Sec. 60.49Da(p)(4)(i) is not met,
the owner or operator shall report a substitute Hg emission rate for
that month, as follows. For the first such month, the substitute monthly
Hg emission rate shall be the arithmetic average of all valid hourly Hg
emission rates recorded to date. For any subsequent month(s) with
insufficient data capture, the substitute monthly Hg emission rate shall
be the highest valid hourly Hg emission rate recorded to date. When the
12-month average Hg emission rate for the initial performance test is
calculated, for each month in which there was insufficient data capture,
the substitute monthly Hg emission rate shall be weighted according to
the number of unit operating hours in that month. Following the initial
performance test, the owner or operator shall demonstrate compliance by
calculating the weighted average of all monthly Hg emission rates (in
lb/MWh) for each 12 successive calendar months, excluding data obtained
during startup, shutdown, or malfunction.
(2) If a CEMS is used to demonstrate compliance, follow the
procedures in paragraphs (h)(2)(i) through (iii) of this section to
determine the 12-month rolling average.
(i) Calculate the total mass of Hg emissions over a month (M), in
lb, using either Equation 6 in paragraph (h)(2)(i)(A) of this section or
Equation 7 in paragraph (h)(2)(i)(B) of this section, in conjunction
with Equation 8 in paragraph (h)(2)(i)(C) of this section.
(A) If the Hg CEMS measures Hg concentration on a wet basis, use
Equation 6 below to calculate the Hg mass emissions for each valid hour:
[GRAPHIC] [TIFF OMITTED] TR13JN07.017
Where:
Eh = Hg mass emissions for the hour, (lb);
K = Units conversion constant, 6.24 x 10-\11\ lb-scm/
[micro]gm-scf;
Ch = Hourly Hg concentration, wet basis,
([micro]gm/scm);
Qh = Hourly stack gas volumetric flow rate, (scfh); and
th = Unit operating time, i.e., the fraction of the hour for
which the unit operated. For example, th = 0.50 for a half-hour of unit
operation and 1.00 for a full hour of operation.
(B) If the Hg CEMS measures Hg concentration on a dry basis, use
Equation 7 below to calculate the Hg mass emissions for each valid hour:
[GRAPHIC] [TIFF OMITTED] TR13JN07.018
Where:
Eh = Hg mass emissions for the hour, (lb);
K = Units conversion constant, 6.24 x 10-11 lb-scm/[micro]gm-
scf;
Ch = Hourly Hg concentration, dry basis, ([micro]gm/dscm);
Qh = Hourly stack gas volumetric flow rate, (scfh);
th = Unit operating time, i.e., the fraction of the hour for
which the unit operated; and
Bws = Stack gas moisture content, expressed as a decimal
fraction (e.g., for 8 percent H2O, Bws = 0.08).
(C) Use Equation 8, below, to calculate M, the total mass of Hg
emitted for the month, by summing the hourly masses derived from
Equation 6 or 7 (as applicable):
[[Page 176]]
[GRAPHIC] [TIFF OMITTED] TR13JN07.019
Where:
M = Total Hg mass emissions for the month, (lb);
Eh = Hg mass emissions for hour ``h'', from Equation 6 or 7
of this section, (lb); and
n = Number of unit operating hours in the month with valid CE and
electrical output data, excluding hours of unit startup, shutdown and
malfunction.
(ii) Calculate the monthly Hg emission rate on an output basis (lb/
MWh) using Equation 9, below. For a cogeneration unit, use Equation 5 in
paragraph (g) of this section instead.
[GRAPHIC] [TIFF OMITTED] TR13JN07.020
Where:
ER = Monthly Hg emission rate, (lb/MWh);
M = Total mass of Hg emissions for the month, from Equation 8, above,
(lb); and
P = Total electrical output for the month, for the hours used to
calculate M, (MWh).
(iii) Until 12 monthly Hg emission rates have been accumulated,
calculate and report only the monthly averages. Then, for each
subsequent calendar month, use Equation 10 below to calculate the 12-
month rolling average as a weighted average of the Hg emission rate for
the current month and the Hg emission rates for the previous 11 months,
with one exception. Calendar months in which the unit does not operate
(zero unit operating hours) shall not be included in the 12-month
rolling average.
[GRAPHIC] [TIFF OMITTED] TR13JN07.021
Where:
Eavg = Weighted 12-month rolling average Hg emission rate,
(lb/MWh);
ERi = Monthly Hg emission rate, for month ``i'', (lb/MWh);
and
n = Number of unit operating hours in month ``i'' with valid CEM and
electrical output data, excluding hours of unit startup, shutdown, and
malfunction.
(3) If a sorbent trap monitoring system is used in lieu of a Hg
CEMS, as described in Sec. 75.15 of this chapter and in appendix K to
part 75 of this chapter, calculate the monthly Hg emission rates using
Equations 7 through 9 of this section, except that for a particular pair
of sorbent traps, Ch in Equation 7 shall be the flow-
proportional average Hg concentration measured over the data collection
period.
(i) Daily calibration drift (CD) tests and quarterly accuracy
determinations shall be performed for Hg CEMS in accordance with
Procedure 1 of appendix F to this part. For the CD assessments, you may
use either elemental mercury or mercuric chloride (Hg[deg]
HgCl2) standards. The four quarterly accuracy determinations
shall consist of one RATA and three measurement error (ME) tests using
HgCl2 standards, as described in section 8.3 of Performance
Specification 12-A in appendix B to this part (note: Hg[deg] standards
may be used if the Hg monitor does not have a converter). Alternatively,
the owner or operator may implement the applicable daily, weekly,
quarterly, and annual quality assurance (QA) requirements for Hg CEMS in
appendix B to part 75 of this chapter, in lieu of the QA procedures in
appendices B and F to this part. Annual RATA of sorbent trap monitoring
systems shall be performed in accordance with appendices A and B to part
75 of this chapter, and all other quality assurance requirements
specified in appendix K to part 75 of this chapter shall be met for
sorbent trap monitoring systems.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009]
Sec. 60.51Da Reporting requirements.
(a) For SO2, NOX, PM, and Hg emissions, the
performance test data from the initial and subsequent performance test
and from the performance evaluation of the continuous monitors
(including the transmissometer) are submitted 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
[[Page 177]]
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, malfunction (NOX only), emergency
conditions (SO2 only), or other reasons, and justification
for excluding data for reasons other than startup, shutdown,
malfunction, or emergency conditions.
(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 Sec.
60.49Da is not obtained for any 30 successive boiler operating days, the
following information obtained under the requirements of Sec.
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) If any standards under Sec. 60.43Da are exceeded during
emergency conditions because of control system malfunction, the owner or
operator of the affected facility shall submit a signed statement:
(1) Indicating if emergency conditions existed and requirements
under Sec. 60.48Da(d) were met during each period, and
(2) Listing the following information:
(i) Time periods the emergency condition existed;
(ii) Electrical output and demand on the owner or operator's
electric utility system and the affected facility;
(iii) Amount of power purchased from interconnected neighboring
utility companies during the emergency period;
(iv) Percent reduction in emissions achieved;
(v) Atmospheric emission rate (ng/J) of the pollutant discharged;
and
(vi) Actions taken to correct control system malfunction.
(e) If fuel pretreatment credit toward the SO2 emission
standard under Sec. 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 Sec. 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
[[Page 178]]
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) For Hg, the following information shall be reported to the
Administrator:
(1) Company name and address;
(2) Date of report and beginning and ending dates of the reporting
period;
(3) The applicable Hg emission limit (lb/MWh); and
(4) For each month in the reporting period:
(i) The number of unit operating hours;
(ii) The number of unit operating hours with valid data for Hg
concentration, stack gas flow rate, moisture (if required), and
electrical output;
(iii) The monthly Hg emission rate (lb/MWh);
(iv) The number of hours of valid data excluded from the calculation
of the monthly Hg emission rate, due to unit startup, shutdown and
malfunction; and
(v) The 12-month rolling average Hg emission rate (lb/MWh); and
(5) The data assessment report (DAR) required by appendix F to this
part, or an equivalent summary of QA test results if the QA of part 75
of this chapter are implemented.
(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 Sec. 60.7,
periods of excess emissions are defined as all 6-minute periods during
which the average opacity exceeds the applicable opacity standards under
Sec. 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 and/or Hg in lieu of submitting the written reports
required under paragraphs (b), (g), 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. 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.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009]
Sec. 60.52Da Recordkeeping requirements.
(a) The owner or operator of an affected facility subject to the
emissions limitations in Sec. 60.45Da shall provide notifications in
accordance with Sec. 60.7(a) and shall maintain records of all
information needed to demonstrate compliance including performance
tests, monitoring data, fuel analyses, and calculations, consistent with
the requirements of Sec. 60.7(f).
(b) The owner or operator of an affected facility subject to the
opacity
[[Page 179]]
limits in Sec. 60.42Da(b) that elects to monitor emissions according to
the requirements in Sec. 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]
Subpart Db_Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units
Source: 72 FR 32742, June 13, 2007, unless otherwise noted.
Sec. 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; Sec. 60.40) are subject to the PM and
NOX standards under this subpart and to the sulfur dioxide
(SO2) standards under subpart D (Sec. 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; Sec. 60.40) are also subject to the
NOX standards under this subpart and the PM and
SO2 standards under subpart D (Sec. 60.42 and Sec. 60.43).
[[Page 180]]
(c) Affected facilities that also meet the applicability
requirements under subpart J (Standards of performance for petroleum
refineries; Sec. 60.104) are subject to the PM and NOX
standards under this subpart and the SO2 standards under
subpart J (Sec. 60.104).
(d) Affected facilities that also meet the applicability
requirements under subpart E (Standards of performance for incinerators;
Sec. 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; Sec. 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 Sec. 60.281 is not considered a modification under Sec.
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, or subpart AAAA of this part
is not covered by this subpart.
(i) Heat recovery steam generators that are associated with combined
cycle gas 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 heat recovery steam generators that
are capable of combusting more than 29 MW (100 MMBtu/hr) heat input of
fossil fuel. If the 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 gas 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, Sec. 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.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009]
Sec. 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 Sec. 60.42b(a),
Sec. 60.43b(a), or Sec. 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,
[[Page 181]]
see Sec. 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 Sec. 60.17) or diesel fuel
oil numbers 1 and 2, as defined by the American Society for Testing and
Materials in ASTM D975 (incorporated by reference, see Sec. 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 Sec. 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
[[Page 182]]
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-m\3\ (70,000 Btu/hr-ft\3\).
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 Sec. 60.17).
Low heat release rate means a heat release rate of 730,000 J/sec-
m\3\ (70,000 Btu/hr-ft\3\) 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
Sec. 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.
[[Page 183]]
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 Sec. 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.
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]
Sec. 60.42b Standard for sulfur dioxide (SO[bdi2]).
(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 Sec. 60.8, whichever comes
first, no owner or operator of an
[[Page 184]]
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:
[GRAPHIC] [TIFF OMITTED] TR28JA09.003
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 Sec. 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 Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR28JA09.004
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 Sec. 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),
[[Page 185]]
(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 Sec.
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 Sec.
60.45b(c) or Sec. 60.45b(d), and following the monitoring procedures as
described in Sec. 60.47b(a) or Sec. 60.47b(b) to determine
SO2 emission rate or fuel oil sulfur content; or (2)
maintaining fuel records as described in Sec. 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 Sec. 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
[[Page 186]]
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.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009]
Sec. 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 Sec. 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 Sec.
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 Sec. 60.43b(a).
(b) On and after the date on which the performance test is completed
or required to be completed under Sec. 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
[[Page 187]]
under Sec. 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 Sec. 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 Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that can
combust 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. 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.
(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 Sec. 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
[[Page 188]]
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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec.
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]
Sec. 60.44b Standard for nitrogen oxides (NOX).
(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 Sec. 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:
[[Page 189]]
------------------------------------------------------------------------
Nitrogen oxide emission
limits (expressed as
Fuel/steam generating unit type 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 260 0.60
combustion...............................
(iii) Pulverized coal..................... 300 0.70
(iv) Lignite, except (v).................. 260 0.60
(v) Lignite mined in North Dakota, South 340 0.80
Dakota, or Montana and combusted in a
slag tap furnace.........................
(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 Sec. 60.8, whichever date comes
first, no owner or operator of an affected facility that simultaneously
combusts mixtures of 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.024
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 (l) of this section, on and
after the date on which the initial performance test is completed or is
required to be completed under Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that simultaneously
combusts coal or oil, or a mixture of these fuels with natural gas, and
wood, municipal-type solid waste, 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 or oil, or mixtures of these
fuels with natural gas combusted in the affected facility, as determined
pursuant to paragraph (a) or (b) of this section, unless the affected
facility has an annual capacity factor for coal or oil, or mixture of
these fuels with 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 for coal, oil, or a mixture of these fuels with natural gas.
(d) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts natural gas 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 of
10 percent (0.10) or less and is
[[Page 190]]
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.
(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 Sec. 60.8, whichever date comes first,
no owner or operator of an affected facility that simultaneously
combusts 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.025
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, distillate
oil and gaseous byproduct/waste, J (MMBtu);
ELro = Appropriate emission limit from paragraph (a)(2) for
combustion of residual oil and/or byproduct/waste, 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).
(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 Sec. 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
[[Page 191]]
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 Sec. 60.8, whichever
date comes first, no owner or operator of an affected facility that
commenced construction or reconstruction 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) If the affected facility combusts coal, oil, natural gas, a
mixture of these fuels, or a mixture of these fuels with any other
fuels: A limit of 86 ng/J (0.20 lb/MMBtu) heat input unless the affected
facility has an annual capacity factor for coal, oil, and natural gas
[[Page 192]]
of 10 percent (0.10) or less and is subject to 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
(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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.026
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 Sec.
60.48Da(i) of subpart Da of this part, and must monitor emissions
according to Sec. 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]
Sec. 60.45b Compliance and performance test methods and procedures for sulfur dioxide.
(a) The SO2 emission standards in Sec. 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 Sec. 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 Sec.
60.8(b). Section 60.8(f) does not apply to this section. The 30-day
notice required in Sec. 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 Sec. 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 Sec. 60.47b(a) or (b).
(ii) The percent of potential SO2 emission rate
(%Ps) emitted to the atmosphere is computed using the
following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.027
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:
[[Page 193]]
(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[deg] is computed using the following
formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.028
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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.029
To compute Eai\o\, an adjusted hourly SO2
inlet rate (Ehi\o\) is used. The Ehi\o\ is
computed using the following formula:
[GRAPHIC] [TIFF OMITTED] TR13JN07.030
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 Sec. 60.42b.
(5) The owner or operator of an affected facility that qualifies
under the provisions of Sec. 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 Sec.
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
[[Page 194]]
design capacity provided by the manufacturer is used.
(f) For the initial performance test required under Sec. 60.8,
compliance with the SO2 emission limits and percent reduction
requirements under Sec. 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 Sec. 60.8,
compliance with the SO2 emission limits and percent reduction
requirements under Sec. 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 Sec. 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
Sec. 60.42b(i), emission data are not used to calculate %Ps
or Es under Sec. 60.42b(a), (b) or (c), however, the
emissions data are used to determine compliance with the emission limit
under Sec. 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 Sec.
60.49b(r).
(k) The owner or operator of an affected facility seeking to
demonstrate compliance in Sec. Sec. 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 Sec. 60.49b(r).
[72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009]
Sec. 60.46b Compliance and performance test methods and procedures for particulate matter and nitrogen oxides.
(a) The PM emission standards and opacity limits under Sec. 60.43b
apply at all times except during periods of startup, shutdown, or
malfunction. The NOX emission standards under Sec. 60.44b
apply at all times.
(b) Compliance with the PM emission standards under Sec. 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
Sec. 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 Sec. 60.43b, the owner or operator of an affected facility
shall conduct an initial performance test as required under Sec. 60.8,
and shall conduct subsequent performance tests as requested
[[Page 195]]
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 [deg]C (320 [deg]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 16014 [deg]C (32025
[deg]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 Sec. 60.44b, the owner or operator of an
affected facility shall conduct the performance test as required under
Sec. 60.8 using the continuous system for monitoring NOX
under Sec. 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 Sec.
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 Sec. 60.8, whichever date
comes first, the owner or operator of an affected facility which
combusts coal (except as specified under Sec. 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 Sec. 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 Sec. 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
[[Page 196]]
NOX standards under Sec. 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 Sec. 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 Sec. 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 Sec. 60.48b(g)(1) or Sec. 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 Sec. 60.49b(e), the requirements of Sec.
60.48b(g)(1) apply and the provisions of Sec. 60.48b(g)(2) are
inapplicable.
(f) To determine compliance with the emissions limits for
NOX required by Sec. 60.44b(a)(4) or Sec. 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 Sec. 60.8 as follows:
(i) The emissions rate (E) of NOX shall be computed using
Equation 1 in this section:
[GRAPHIC] [TIFF OMITTED] TR13JN07.031
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 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 Sec. 60.44b(a)(4)
or Sec. 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 Sec. 60.48b for measuring NOX and
O2 and meet the requirements of Sec. 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 Sec.
60.44b(j) or Sec. 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
[[Page 197]]
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 Sec. 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 Sec. 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 Sec.
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 Sec.
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 Sec. 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 Sec. 60.44b using Method 7, 7A,
7E of appendix A of this part, 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 Sec. 60.44b
over a minimum of 3 consecutive steam generating unit operating hours at
maximum heat input capacity using Method 7, 7A, 7E of appendix A of this
part, or other approved reference methods.
(i) The owner or operator of an affected facility seeking to
demonstrate compliance with the PM limit in paragraphs Sec.
60.43b(a)(4) or Sec. 60.43b(h)(5) shall follow the applicable
procedures in Sec. 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 Sec. 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 Sec. 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 Sec. 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.
[[Page 198]]
(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 Sec. 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) After July 1, 2010 or after Method 202 of appendix M of part 51
has been revised to minimize artifact measurement and notice of that
change has been published in the Federal Register, whichever is later,
for condensable PM emissions, Method 202 of appendix M of part 51 shall
be used; and
(iii) 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) After July 1, 2011, within 90 days after completing a
correlation testing run, the owner or operator of an affected facility
shall either successfully enter the test data into EPA's WebFIRE data
base located at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main
or mail a copy to: United States Environmental Protection Agency; Energy
Strategies Group; 109 TW Alexander DR; Mail Code: D243-01; RTP, NC
27711.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009]
Sec. 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 Sec. 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 Sec. 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 Sec.
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
[[Page 199]]
(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 Sec. 60.49b are met.
SO2 and CO2 (or O2) data used to meet
the requirements of Sec. 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
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 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 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 Sec.
60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used to
calculate the average emission rates under Sec. 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 Sec. 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 Sec. 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
[[Page 200]]
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 Sec. 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 Sec. 60.49b(r).
[72 FR 32742, June 13, 2007, as amended at 74 FR 5087, Jan. 28, 2009]
[[Page 201]]
Sec. 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 Sec. 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 Sec. 60.43b and meeting the conditions under
paragraphs (j)(1), (2), (3), (4), or (5) of this section who elects not
to install a COMS shall conduct a performance test using Method 9 of
appendix A-4 of this part and the procedures in Sec. 60.11 to
demonstrate compliance with the applicable limit in Sec. 60.43b and
shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this
section. If during the initial 60 minutes of observation all 6-minute
averages are less than 10 percent and all individual 15-second
observations are less than or equal to 20 percent, the observation
period may be reduced from 3 hours to 60 minutes.
(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;
(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;
(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
(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 30 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 30 calendar
days according to the requirements in Sec. 60.46d(d)(7).
(ii) If no visible emissions are observed for 30 operating days
during which an opacity standard is applicable, observations can be
reduced to
[[Page 202]]
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 Sec. 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 Sec.
60.49b. Data reported to meet the requirements of Sec. 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 Sec. 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 Sec. 60.44b. The 1-hour averages shall be calculated using
the data points required under Sec. 60.13(h)(2).
(e) The procedures under Sec. 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
[[Page 203]]
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 Sec. 60.49b(c).
(h) The owner or operator of a duct burner, as described in Sec.
60.41b, that is subject to the NOX standards in Sec.
60.44b(a)(4), Sec. 60.44b(e), or Sec. 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 Sec.
60.44b(j) or Sec. 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), or (6) 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 Sec. 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 Sec. 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 Sec. 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
[[Page 204]]
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 recent requirements in section Sec. 60.48Da of this part; or
(6) 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 Sec. 60.46b(j). The CEMS specified in paragraph Sec. 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.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5087, Jan. 28, 2009]
Sec. 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 Sec. 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 Sec. Sec. 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
Sec. 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
Sec. Sec. 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
[[Page 205]]
each affected facility described in Sec. 60.44b(j) or Sec. 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 Sec. 60.44b who seeks to demonstrate
compliance with those standards through the monitoring of steam
generating unit operating conditions in the provisions of Sec.
60.48b(g)(2) shall submit to the Administrator for approval a plan that
identifies the operating conditions to be monitored in Sec.
60.48b(g)(2) and the records to be maintained in Sec. 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 Sec. 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 Sec. 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 Sec. Sec. 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 Sec. 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
Sec. 60.43b, the owner or operator shall maintain
[[Page 206]]
records of opacity. In addition, an owner or operator that elects to
monitor emissions according to the requirements in Sec. 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 Sec. 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 Sec. 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 Sec.
60.43b(f) or to the operating parameter monitoring requirements in Sec.
60.13(i)(1).
(2) Any affected facility that is subject to the NOX
standard of Sec. 60.44b, and that:
[[Page 207]]
(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 Sec. 60.48b(g)(1) or steam generating unit operating conditions
under Sec. 60.48b(g)(2).
(3) For the purpose of Sec. 60.43b, excess emissions are defined as
all 6-minute periods during which the average opacity exceeds the
opacity standards under Sec. 60.43b(f).
(4) For purposes of Sec. 60.48b(g)(1), excess emissions are defined
as any calculated 30-day rolling average NOX emission rate,
as determined under Sec. 60.46b(e), that exceeds the applicable
emission limits in Sec. 60.44b.
(i) The owner or operator of any affected facility subject to the
continuous monitoring requirements for NOX under Sec.
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 Sec. 60.42b shall submit reports.
(k) For each affected facility subject to the compliance and
performance testing requirements of Sec. 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 Sec. 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;
[[Page 208]]
(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 Sec. Sec. 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 Sec. Sec. 60.47b(e)(4)(i)
through (e)(4)(iii).
(m) For each affected facility subject to the SO2
standards in Sec. 60.42(b) for which the minimum amount of data
required in Sec. 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 Sec. 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 Sec.
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.
[[Page 209]]
(q) The owner or operator of an affected facility described in Sec.
60.44b(j) or Sec. 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 Sec.
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 Sec. 60.42b or Sec. 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 Sec. 60.42b(j) or
Sec. 60.42b(k) shall obtain and maintain at the affected facility fuel
receipts 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 Sec. 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 Sec. 60.42b or Sec.
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 Sec.
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
[[Page 210]]
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 Sec. 60.46b(i).
(iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec. 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 Sec.
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 Sec. 60.46b.
(iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec. 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 Sec. 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 Sec. 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
Sec. Sec. 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
[[Page 211]]
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 Sec.
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 Sec. 60.46b.
(ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec. 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 Sec.
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 Sec.
60.49b.
(y) Facility-specific NOX standard for INEOS USA's AOGI
located in Lima, Ohio:
(1) Standard for NOX. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
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 NOX. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec. 60.46b.
(ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec. 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]
Subpart Dc_Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units
Source: 72 FR 32759, June 13, 2007, unless otherwise noted.
[[Page 212]]
Sec. 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/hr)) or less, but greater than or equal to
2.9 MW (10 MMBtu/hr).
(b) In delegating implementation and enforcement authority to a
State under section 111(c) of the Clean Air Act, Sec. 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
(Sec. Sec. 60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c) during
periods of combustion research, as defined in Sec. 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 Sec. 60.14.
(e) Heat recovery steam generators that are associated with combined
cycle gas 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 that are
capable of combusting more than or equal to 2.9 MW (10 MMBtu/hr) heat
input of fossil fuel but less than or equal to 29 MW (100 MMBtu/hr) heat
input of fossil fuel. If the 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 gas turbine
emissions are subject to subpart GG or KKKK, as applicable, of this
part).
(f) Any facility covered by subpart AAAA of this part is not subject
by this subpart.
(g) Any facility covered by an EPA approved State or Federal section
111(d)/129 plan implementing subpart BBBB of this part is not subject by
this subpart.
[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009]
Sec. 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 Sec. 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.
Cogeneration steam generating unit means a steam generating unit
that simultaneously produces both electrical (or mechanical) and thermal
energy from the same primary energy source.
Combined cycle system means a system in which a separate source
(such as a
[[Page 213]]
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 Sec.
60.17) or diesel fuel oil numbers 1 or 2, as defined by the American
Society for Testing and Materials in ASTM D975 (incorporated by
reference, see Sec. 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 Sec. 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:
[[Page 214]]
(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
Sec. 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 Sec. 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.
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]
Sec. 60.42c Standard for sulfur dioxide (SO[bdi2]).
(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 Sec. 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
[[Page 215]]
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 Sec. 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 Sec. 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/hr) 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.
(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 Sec. 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; 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.
[[Page 216]]
(e) On and after the date on which the initial performance test is
completed or required to be completed under Sec. 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/hr); 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:
[GRAPHIC] [TIFF OMITTED] TR28JA09.005
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), or
(3) 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 Sec.
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 facilities with heat input capacities between 2.9 and
8.7 MW (10 and 30 MMBtu/hr).
(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]
Sec. 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 Sec. 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
[[Page 217]]
other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/hr) 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 Sec. 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/hr) 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 Sec. 60.8, whichever date
comes first, no owner or operator of an affected facility that can
combust coal, wood, or oil and has a heat input capacity of 8.7 MW (30
MMBtu/hr) 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.
(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 Sec. 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/hr) 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 Sec. 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
[[Page 218]]
(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 Sec. 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/hr) 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) On and after the date on which the initial performance test is
completed or is required to be completed under Sec. 60.8, whichever
date comes first, 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 Sec. 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]
Sec. 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
Sec. 60.8(b), performance tests required under Sec. 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 Sec. 60.8(d)
applies only to the initial performance test unless otherwise specified
by the Administrator.
(b) The initial performance test required under Sec. 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 Sec. 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 Sec. 60.8, compliance with the percent reduction
requirements and SO2 emission limits under Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.033
Where:
Ehoo = Adjusted Eho, ng/J (lb/MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/MMBtu);
[[Page 219]]
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 Sec. 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 Sec. 60.42c(a) or (b) shall determine compliance
with the SO2 emission limits under Sec. 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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.034
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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.035
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:
[GRAPHIC] [TIFF OMITTED] TR13JN07.036
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
Sec. 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 Sec.
60.46c(d)(2).
(h) For affected facilities subject to Sec. 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 Sec. 60.48c(f), as applicable.
(i) The owner or operator of an affected facility seeking to
demonstrate
[[Page 220]]
compliance with the SO2 standards under Sec. 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
Sec. 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]
Sec. 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 Sec. 60.43c shall conduct an initial
performance test as required under Sec. 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 [deg]C (320 [deg]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 [deg]C (32025 [deg]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.
[[Page 221]]
(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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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.
[[Page 222]]
(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) After July 1, 2010 or after Method 202 of appendix M of part 51
has been revised to minimize artifact measurement and notice of that
change has been published in the Federal Register, whichever is later,
for condensable PM emissions, Method 202 of appendix M of part 51 shall
be used; and
(iii) 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) After July 1, 2011, within 90 days after the date of completing
each performance evaluation required by paragraph (c)(11) of this
section, the owner or operator of the affected facility must either
submit the test data to EPA by successfully entering the data
electronically into EPA's WebFIRE data base available at http://
cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to:
United States Environmental Protection Agency; Energy Strategies Group;
109 TW Alexander DR; Mail Code: D243-01; RTP, NC 27711.
(d) The owner or operator of an affected facility seeking to
demonstrate compliance under Sec. 60.43c(e)(4) shall follow the
applicable procedures under Sec. 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/hr).
[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009]
Sec. 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 Sec. 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
Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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,
[[Page 223]]
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 Sec. 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 Sec. 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 Sec.
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 Sec.
60.48c(f), as applicable.
[[Page 224]]
(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.
Sec. 60.47c Emission monitoring for particulate matter.
(a) Except as provided in paragraphs (c), (d), (e), (f), and (g) of
this section, the owner or operator of an affected facility combusting
coal, oil, or wood that is subject to the opacity standards under Sec.
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 Sec. 60.43c(c) and that is not required to install
a COMS due to paragraphs (c), (d), (e), or (f) of this section that
elects not to install a COMS shall conduct a performance test using
Method 9 of appendix A-4 of this part and the procedures in Sec. 60.11
to demonstrate compliance with the applicable limit in Sec. 60.43c and
shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this
section. If during the initial 60 minutes of observation all 6-minute
averages are less than 10 percent and all individual 15-second
observations are less than or equal to 20 percent, the observation
period may be reduced from 3 hours to 60 minutes.
(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;
(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;
(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
(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 comp