MEMORANDUM 

From: Office of Air Quality Planning and Standards 

 U.S. Environmental Protection Agency 

To: EGU NSPS Docket (EPA-HQ-OAR-2011-0044) 

Date: March, 2011 

Subject: Redline of Proposed Amendments to the Boiler NSPS (40 CFR Part 60, Subparts 

D, Da, Db, & Dc). 

Introduction 

For references purposes, EPA prepared a redline of the proposed amendments against the 

existing regulatory text. The redline documents only include edited sections and are only 

intended to assist interested parties to understand the proposed amendments. The redline 

documents and are not intended to supersede the amendments included in the FR package. 
§ 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 theFederal 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 §60.261. 

(2) ASTM A100–69, 74, 93, Standard Specification for Ferrosilicon, IBR approved for §60.261. 

(3) ASTM A101–73, 93, Standard Specification for Ferrochromium, IBR approved for §60.261. 

(4) ASTM A482–76, 93, Standard Specification for Ferrochromesilicon, IBR approved for 

§60.261. 

(5) ASTM A483–64, 74 (Reapproved 1988), Standard Specification for Silicomanganese, IBR 

approved for §60.261. 

(6) ASTM A495–76, 94, Standard Specification for Calcium-Silicon and Calcium ManganeseSilicon, IBR approved for §60.261. 

(7) ASTM D86–78, 82, 90, 93, 95, 96, Distillation of Petroleum Products, IBR approved for 

§§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 §§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 §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 §§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 §§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)ε

1

 , Standard Specification for 

Classification of Coals by Rank, IBR approved for §§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 

§§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 

§§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 §§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 §60.335(b)(10)(ii). 

(18) ASTM D1072–90 (Reapproved 1999), Standard Test Method for Total Sulfur in Fuel 

Gases, IBR approved for §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 §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 §§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 §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 §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 (HighTemperature Method), IBR approved for §§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 (HighTemperature Method), IBR approved for §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 §§60.45(f)(5)(ii), 60.46(c)(2), 

60.296(b)(3), 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 §§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 §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 §§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 §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 §§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 §§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 §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 §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 §§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 §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 

§§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 

§§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 §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 §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 Carbon and Hydrogen 

in the Analysis Sample of Coal and Coke, IBR approved for §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 §60.335(b)(10)(ii). 

(50) ASTM D3246–05, Standard Test Method for Sulfur in Petroleum Gas by Oxidative 

Microcoulometry, IBR approved for §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 

§60.564(j).

(54) ASTM D3699 - 08, Standard Specification for Kerosine, IBR approved for §§60.41b of 

subpart Db of this part and 60.41c of subpart Dc of this part.

(554) 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. 

(565) 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. 

(576) 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. 

(587) ASTM D4057–95 (Reapproved 2000), Standard Practice for Manual Sampling of 

Petroleum and Petroleum Products, IBR approved for §60.4415(a)(1). 

(589) ASTM D4084–82, 94, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous 

Fuels (Lead Acetate Reaction Rate Method), IBR approved for §60.334(h)(1). 

(6059) ASTM D4084–05, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous 

Fuels (Lead Acetate Reaction Rate Method), IBR approved for §§60.4360 and 60.4415(a)(1)(ii). 

(610) 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. 

(621) ASTM D4177–95 (Reapproved 2000), Standard Practice for Automatic Sampling of 

Petroleum and Petroleum Products, IBR approved for §60.4415(a)(1). 
(623) 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. 

(643) ASTM D4294–02, Standard Test Method for Sulfur in Petroleum and Petroleum Products 

by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §60.335(b)(10)(i). 

(645) ASTM D4294–03, Standard Test Method for Sulfur in Petroleum and Petroleum Products 

by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §60.4415(a)(1)(i). 

(665) 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. 

(676) 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. 

(687) 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. 

(698) ASTM D4468–85 (Reapproved 2000), Standard Test Method for Total Sulfur in Gaseous 

Fuels by Hydrogenolysis and Rateometric Colorimetry, IBR approved for §§60.335(b)(10)(ii) 

and 60.4415(a)(1)(ii). 

(7069) ASTM D4629–02, Standard Test Method for Trace Nitrogen in Liquid Petroleum 

Hydrocarbons by Syringe/Inlet Oxidative Combustion and Chemiluminescence Detection, IBR 

approved for §§60.49b(e) and 60.335(b)(9)(i). 

(701) ASTM D4809–95, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter (Precision Method), IBR approved for §§60.18(f)(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). 

(721) ASTM D4810–88 (Reapproved 1999), Standard Test Method for Hydrogen Sulfide in 

Natural Gas Using Length of Stain Detector Tubes, IBR approved for §§60.4360 and 

60.4415(a)(1)(ii). 

(732) ASTM D5287–97 (Reapproved 2002), Standard Practice for Automatic Sampling of 

Gaseous Fuels, IBR approved for §60.4415(a)(1). 

(743) ASTM D5403–93, Standard Test Methods for Volatile Content of Radiation Curable 

Materials, IBR approved for appendix A: Method 24, Section 6.6. 

(754) ASTM D5453–00, Standard Test Method for Determination of Total Sulfur in Light 

Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for 

§60.335(b)(10)(i). 

(765) ASTM D5453–05, Standard Test Method for Determination of Total Sulfur in Light 

Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for 

§60.4415(a)(1)(i). 

(776) ASTM D5504–01, Standard Test Method for Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, IBR approved 

for §§60.334(h)(1) and 60.4360. 

(787) ASTM D5762–02, Standard Test Method for Nitrogen in Petroleum and Petroleum 

Products by Boat-Inlet Chemiluminescence, IBR approved for §60.335(b)(9)(i). 
(798) ASTM D5865–98, Standard Test Method for Gross Calorific Value of Coal and Coke, IBR 

approved for §60.45(f)(5)(ii), 60.46(c)(2), and appendix A: Method 19, Section 12.5.2.1.3. 

(8079) 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. 

(810) ASTM D6228–98, Standard Test Method for Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR 

approved for §60.334(h)(1). 

(821) ASTM D6228–98 (Reapproved 2003), Standard Test Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric 

Detection, IBR approved for §§60.4360 and 60.4415. 

(832) 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. 

(843) ASTM D6366–99, Standard Test Method for Total Trace Nitrogen and Its Derivatives in 

Liquid Aromatic Hydrocarbons by Oxidative Combustion and Electrochemical Detection, IBR 

approved for §60.335(b)(9)(i). 

(854) 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. 

(865) ASTM D6522–00, Standard Test Method for Determination of Nitrogen Oxides, Carbon 

Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating 

Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR 

approved for §60.335(a). 

(876) 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. 

(887) ASTM D6667–01, Standard Test Method for Determination of Total Volatile Sulfur in 

Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR 

approved for §60.335(b)(10)(ii). 

(898) ASTM D6667–04, Standard Test Method for Determination of Total Volatile Sulfur in 

Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR 

approved for §60.4415(a)(1)(ii). 

(90) ASTM D6751 – 11, Standard Specification for Biodiesel Fuel Blend Stock (B100) for 

Middle Distillate Fuels, IBR approved for §§60.41b of subpart Db of this part and 60.41c of 

subpart Dc of this part.

(8991) 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. 
(920) 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 §60.56c(b)(13) of subpart Ec of this part. 

(93) ASTM D7467 – 10, Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to 

B20), IBR approved for §§60.41b of subpart Db of this part and 60.41c of subpart Dc of this 

part.

(941) ASTM E169–63, 77, 93, General Techniques of Ultraviolet Quantitative Analysis, IBR 

approved for §§60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2), and 60.632(f). 

(952) ASTM E260–73, 91, 96, General Gas Chromatography Procedures, IBR approved for 

§§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 §§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 §§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 §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 °C, in Standard Methods for the Examination 

of Water and Wastewater, 15th Edition, 1980, IBR approved February 25, 1985 for §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, Factorybuilt, 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 §§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 §§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 §§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 §60.56c(b)(4) of subpart Ec, §60.63(f)(2) and (f)(4) of subpart F, 

§60.106(e)(2) of subpart J, §§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, §60.257(b)(3) of Subpart Y, tables 1 and 3 of 

subpart EEEE, tables 2 and 4 of subpart FFFF, table 2 of subpart JJJJ, and §60.4415(a)(2) and 

(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 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 §60.35e and 

§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 §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 

§§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 §60.4241(b). 

(2) [Reserved] 
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. 

(a) The affected facilities to which the provisions of this subpart apply are: 

(1) Each fossil-fuel-fired steam generating unit of more than 73 megawatts (MW) heat input rate (250 

million British thermal units per hour (MMBtu/hr)). 

(2) Each fossil-fuel and wood-residue-fired steam generating unit capable of firing fossil fuel at a heat 

input rate of more than 73 MW (250 MMBtu/hr). 

(b) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of 

combustible materials, other than fossil fuels as defined in this subpart, shall not bring that unit under 

the applicability of this subpart. 

(c) Except as provided in paragraph (d) of this section, any facility under paragraph (a) of this section 

that commenced construction or modification after August 17, 1971, is subject to the requirements of 

this subpart. 

(d) The requirements of §§60.44 (a)(4), (a)(5), (b) and (d), and 60.45(f)(4)(vi) are applicable to lignitefired steam generating units that commenced construction or modification after December 22, 1976. 

(e) Any facility covered under either subpart Da or KKKK is not covered under this subpart. 

§60.41 Definitions. 

As used in this subpart, all terms not defined herein shall have the meaning given them in the Act, and 

in subpart A of this part. 

Boiler operating day means a 24-hour period between 12 midnight and the following midnight during 

which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be 

combusted the entire 24-hour period. 

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM 

D388 (incorporated by reference, see §60.17). 

Coal refuse means waste-products of coal mining, cleaning, and coal preparation operations (e.g. culm, 

gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. 

Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived 

from such materials for the purpose of creating useful heat. 

Fossil fuel and wood residue-fired steam generating unit means a furnace or boiler used in the process 

of burning fossil fuel and wood residue for the purpose of producing steam by heat transfer. 

Fossil-fuel-fired steam generating unit means a furnace or boiler used in the process of burning fossil 

fuel for the purpose of producing steam by heat transfer. 

Natural gas means:

Comment [CF1]: Simplify title

Comment [CF2]: Adjusting applicability since

heat recovery steam generators covered under Da

reverted to D after they were exempted from Da.  

The intent of KKKK is to cover the HRSG in combined

cycle and CHP facilities and to exempt them from all

boiler NSPS

Comment [CF3]: Do we need to add pollutant

by pollutant exemptions for Db?

Comment [CF4]: Need definition for PM

exemption
(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 §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).

Wood residue means bark, sawdust, slabs, chips, shavings, mill trim, and other wood products derived 

from wood processing and forest management operations. 

§60.42 Standard for particulate matter (PM). 

(a) Except as provided under paragraphs (b), (c), (d), and (e) of this section, oOn and after the date on 

which the performance test required to be conducted by §60.8 is completed, no owner or operator 

subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any 

affected facility any gases that: 

(1) Contain PM in excess of 43 nanograms per joule (ng/J) heat input (0.10 lb/MMBtu) derived from 

fossil fuel or fossil fuel and wood residue. 

(2) Exhibit greater than 20 percent opacity except for one six-minute period per hour of not more than 

27 percent opacity. 

(b)(1) On or after December 28, 1979, no owner or operator shall cause to be discharged into the 

atmosphere from the Southwestern Public Service Company's Harrington Station #1, in Amarillo, TX, 

any gases which exhibit greater than 35 percent opacity, except that a maximum or 42 percent opacity 

shall be permitted for not more than 6 minutes in any hour. 

(2) Interstate Power Company shall not cause to be discharged into the atmosphere from its Lansing 

Station Unit No. 4 in Lansing, IA, any gases which exhibit greater than 32 percent opacity, except that 

a maximum of 39 percent opacity shall be permitted for not more than six minutes in any hour. 

(c) As an alternate to meeting the requirements of paragraph (a) of this section, an owner or operator 

that elects to install, calibrate, maintain, and operate a continuous emissions monitoring systems 

(CEMS) for measuring PM emissions can petition the Administrator (in writing) to comply with 

§60.42Da(a) of subpart Da of this part. If the Administrator grants the petition, the source will from 

then on (unless the unit is modified or reconstructed in the future) have to comply with the 

requirements in §60.42Da(a) of subpart Da of this part.

(d) An owner and operator of an affected facility that combusts only natural gas and that is subject to a 

federally enforceable permit limiting fuel use to natural gas is exempt from the PM and opacity 

standards specified in paragraph a of this section.

(e) An owner or operator of an affected facility that combusts only gaseous or liquid fossil fuel 

(excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and 

that does not use post-combustion technology to reduce emissions of SO2 or PM is exempt from the 

PM standards specified in paragraph a of this section.

Comment [CF5]: Owner/operators of natural

gas‐fired facilities also presently subject to the

opacity & PM standard.

Comment [CF6]: Exempt owners/operators of

facilities burning natural gas from the PM & opacity

standards

Comment [CF7]: Exempt owners/operators of

facilities burning  natural gas and low sulfur oil from

the PM standard.
§60.43 Standard for sulfur dioxide (SO2). 

(a) Except as provided under paragraph (d) of this section, on and after the date on which the 

performance test required to be conducted by §60.8 is completed, no owner or operator subject to the 

provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility 

any gases that contain SO2in 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: 

Where: 

PSSO2= Prorated standard for SO2when burning different fuels simultaneously, in ng/J heat input 

derived from all fossil fuels or from all fossil fuels and wood residue fired; 

y = Percentage of total heat input derived from liquid fossil fuel; and 

z = Percentage of total heat input derived from solid fossil fuel. 

(c) Compliance shall be based on the total heat input from all fossil fuels burned, including gaseous 

fuels. 

(d) As an alternate to meeting the requirements of paragraphs (a) and (b) of this section, an owner or 

operator can petition the Administrator (in writing) to comply with §60.43Da(i)(3) of subpart Da of 

this part or comply with §60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. 

If the Administrator grants the petition, the source will from then on (unless the unit is modified or 

reconstructed in the future) have to comply with the requirements in §60.43Da(i)(3) of subpart Da of 

this part or §60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. 

(e) Units 1 and 2 (as defined in appendix G of this part) at the Newton Power Station owned or 

operated by the Central Illinois Public Service Company will be in compliance with paragraph (a)(2) 

of this section if Unit 1 and Unit 2 individually comply with paragraph (a)(2) of this section or if the 

combined emission rate from Units 1 and 2 does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat 

input to Units 1 and 2. 

§60.44 Standard for nitrogen oxides (NOX). 

(a) Except as provided under paragraph (e) of this section, on and after the date on which the 

performance test required to be conducted by §60.8 is completed, no owner or operator subject to the 

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provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility 

any gases that contain NOX, expressed as NO2in 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: 

Where: 

PSNOX= Prorated standard for NOXwhen 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 NOXdoes not apply. 

(d) Except as provided under paragraph (e) of this section, cyclone-fired units which burn fuels 

containing at least 25 percent of lignite that is mined in North Dakota, South Dakota, or Montana 

remain subject to paragraph (a)(5) of this section regardless of the types of fuel combusted in 

combination with that lignite. 

(e) As an alternate to meeting the requirements of paragraphs (a), (b), and (d) of this section, an owner 

or operator can petition the Administrator (in writing) to comply with §60.44Da(e)(3) of subpart Da of 

this part. If the Administrator grants the petition, the source will from then on (unless the unit is 

modified or reconstructed in the future) have to comply with the requirements in §60.44Da(e)(3) of 

subpart Da of this part. 

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§60.45 Emissions and fuel monitoring. 

(a) Each owner or operator of an affected facility subject to the applicable emissions standard shall 

install, calibrate, maintain, and operate continuous opacity monitoring system (COMS) for measuring 

opacity and a CEMS for measuring SO2 emissions, NOX emissions, and either oxygen (O2) or carbon 

dioxide (CO2) except as provided in paragraph (b) of this section. 

(b) Certain of the CEMS and COMS requirements under paragraph (a) of this section do not apply to 

owners or operators under the following conditions: 

(1) For a fossil-fuel-fired steam generator that burnscombusts 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 COMS for 

measuring the opacity of emissions and CEMS for measuring SO2 emissions are not required if the 

owner or operator monitors SO2 emissions by fuel sampling and analysis or fuel receipts. 

(2) For a fossil-fuel-fired steam generator that does not use a flue gas desulfurization device, a CEMS 

for measuring SO2emissions is not required if the owner or operator monitors SO2emissions by fuel 

sampling and analysis. 

(3) Notwithstanding §60.13(b), installation of a CEMS for NOXmay be delayed until after the initial 

performance tests under §60.8 have been conducted. If the owner or operator demonstrates during the 

performance test that emissions of NOXare less than 70 percent of the applicable standards in §60.44, a 

CEMS for measuring NOXemissions is not required. If the initial performance test results show that 

NOXemissions are greater than 70 percent of the applicable standard, the owner or operator shall install 

a CEMS for NOXwithin one year after the date of the initial performance tests under §60.8 and comply 

with all other applicable monitoring requirements under this part. 

(4) If an owner or operator is not required to and electsdoes not install any CEMS for sulfur 

oxidesSO2 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) For affected facilities using a An owner or operator may petition the Administrator (in writing) to 

install a PM CEMS, a bag leak detection system to monitor the performance of a fabric filter 

(baghouse) according to the most current requirements in section §60.48Da of this part, or an ESP 

predictive model to monitor the performance of the ESP developed in accordance and operated 

according to the most current requirements in section §60.48Da of this part a COMS is not required as 

an alternative to the CEMS for monitoring opacity emissions.

(6) A CEMS COMS for measuring the opacity of emissions is not required for an affected facility

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. 

Comment [CF8]: Clarify that COMS exemption

for opacity monitoring

Comment [CF9]: Try combining SO2 exemptions

into paragraph (b)(1) and COMS exemptions into

(b)(2)?

Comment [CF10]: Add bag leak detection

system and ESP model to COMS exemption options
(A) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in 

§60.58b(i)(3) of subpart Eb of this part. 

(B) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS 

expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 

(C) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the 

operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data 

points required in §60.13(h)(2). 

(D) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(ii) You must calculate the 1-hour average CO emissions levels for each boiler operating day by 

multiplying the average hourly CO output concentration measured by the CO CEMS times the 

corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat 

input to the affected source. The 24-hour average CO emission level is determined by calculating the 

arithmetic average of the hourly CO emission levels computed for each boiler operating day. 

(iii) You must evaluate the preceding 24-hour average CO emission level each boiler operating day 

excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO 

emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment 

and control systems within 24 hours of the first discovery of the high emission incident and, take the 

appropriate corrective action as soon as practicable to adjust control settings or repair equipment to 

reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less. 

(iv) You must record the CO measurements and calculations performed according to paragraph (b)(6) 

of this section and any corrective actions taken. The record of corrective action taken must include the 

date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, 

and the date, time, and description of the corrective action. 

(7) An owner or operator of an affected facility subject to an opacity standard under §60.42 that elects 

to not use a COMS because the affected facility burns only fuels as specified under paragraph (b)(1) of 

this section, monitors PM emissions as specified under paragraph (b)(5) of this section, or monitors 

CO emissions as specified under paragraph (b)(6) of this section, shall conduct a performance test 

using Method 9 of appendix A–4 of this part and the procedures in §60.11 to demonstrate compliance 

with the applicable limit in §60.42 by April 29, 2011 or within 45 days after stopping use of an 

existing COMS, whichever is later, and shall comply with either paragraph (b)(7)(i), (b)(7)(ii), or 

(b)(7)(iii) of this section. The observation period for Method 9 of appendix A-4 of this part 

performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 

percent and all individual 15-second observations are less than or equal to 20 percent during the initial 

60 minutes of observation. The permitting authority may exempt owners or operators of affected 

facilities burning only natural gas from the opacity monitoring requirements. 

(i) Except as provided in paragraph (b)(7)(ii) or (b)(7)(iii) of this section, the owner or operator shall 

conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in 

paragraph (b)(7) of this section according to the applicable schedule in paragraphs (b)(7)(i)(A) through 

(b)(7)(i)(D) of this section, as determined by the most recent Method 9 of appendix A–4 of this part 

performance test results. 
(A) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 12 calendar months from the date that the most recent 

performance test was conducted; 

(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 45 calendar days from the date 

that the most recent performance test was conducted. 

(ii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 of this part performance test, elect to perform subsequent 

monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in 

paragraphs (b)(7)(ii)(A) and (B) of this section. 

(A) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using Method 

22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible 

emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute 

period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the 

initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the 

occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds 

per 30 minute period), the owner or operator shall either document and adjust the operation of the 

facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to 

or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of 

appendix A–4 of this part performance test using the procedures in paragraph (b)(7) of this section 

within 45 calendar days according to the requirements in §60.46(b)(3). 

(B) If no visible emissions are observed for 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 §60.13(c) and calibration checks under §60.13(d), the following 

procedures shall be used: 

(1) Methods 6, 7, and 3B of appendix A of this part, as applicable, shall be used for the performance 

evaluations of SO2and NOXcontinuous monitoring systems. Acceptable alternative methods for 

Methods 6, 7, and 3B of appendix A of this part are given in §60.46(d). 

(2) Sulfur dioxide or nitric oxide, as applicable, shall be used for preparing calibration gas mixtures 

under Performance Specification 2 of appendix B to this part. 

(3) For affected facilities burning fossil fuel(s), the span value for a continuous monitoring system 

measuring the opacity of emissions shall be 80, 90, or 100 percent. For a continuous monitoring 

system measuring sulfur oxides or NOXthe span value shall be determined using one of the following 

procedures: 

(i) Except as provided under paragraph (c)(3)(ii) of this section, SO2and NOXspan values shall be 

determined as follows: 

Fossil fuel 

In parts per million 

Span value for SO2 Span value for NOX

Gas (1) 500. 

Liquid 1,000 500. 

Solid 1,500 1,000. 

Combinations 1,000y + 1,500z 500 (x + y) + 1,000z. 

1

Not applicable. 

Where: 

x = Fraction of total heat input derived from gaseous fossil fuel; 

y = Fraction of total heat input derived from liquid fossil fuel; and 

z = Fraction of total heat input derived from solid fossil fuel. 

(ii) As an alternative to meeting the requirements of paragraph (c)(3)(i) of this section, the owner or 

operator of an affected facility may elect to use the SO2and NOXspan 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 O2is selected, the measurement of the pollutant concentration and 

O2concentration 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: 

Where E, C, F, and %O2are determined under paragraph (f) of this section. 

(2) When a CEMS for measuring CO2is selected, the measurement of the pollutant concentration and 

CO2concentration shall each be on a consistent basis (wet or dry) and the following conversion 

procedure shall be used: 

Where E, C, Fcand %CO2are determined under paragraph (f) of this section. 

(f) The values used in the equations under paragraphs (e)(1) and (2) of this section are derived as 

follows: 

(1) E = pollutant emissions, ng/J (lb/MMBtu). 

(2) C = pollutant concentration, ng/dscm (lb/dscf), determined by multiplying the average 

concentration (ppm) for each one-hour period by 4.15 × 104 M ng/dscm per ppm (2.59 × 10−9M lb/dscf 

per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO2and 46.01 

for NOX. 

(3) %O2, %CO2= O2or CO2volume (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 CO2generated to the 

calorific value of the fuel combusted (Fc), respectively. Values of F and Fcare given as follows: 

(i) For anthracite coal as classified according to ASTM D388 (incorporated by reference, see §60.17), 

F = 2,723 × 10−17dscm/J (10,140 dscf/MMBtu) and Fc= 0.532 × 10−17scm CO2/J (1,980 scf 

CO2/MMBtu). 

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The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert 

it again.
(ii) For subbituminous and bituminous coal as classified according to ASTM D388 (incorporated by 

reference, see §60.17), F = 2.637 × 10−7

dscm/J (9,820 dscf/MMBtu) and Fc= 0.486 × 10−7scm CO2/J 

(1,810 scf CO2/MMBtu). 

(iii) For liquid fossil fuels including crude, residual, and distillate oils, F = 2.476 × 10−7

dscm/J (9,220 

dscf/MMBtu) and Fc= 0.384 × 10−7

scm CO2/J (1,430 scf CO2/MMBtu). 

(iv) For gaseous fossil fuels, F = 2.347 × 10−7

dscm/J (8,740 dscf/MMBtu). For natural gas, propane, 

and butane fuels, Fc= 0.279 × 10−7

scm CO2/J (1,040 scf CO2/MMBtu) for natural gas, 0.322 × 10−7scm 

CO2/J (1,200 scf CO2/MMBtu) for propane, and 0.338 × 10−7

scm CO2/J (1,260 scf CO2/MMBtu) for 

butane. 

(v) For bark F = 2.589 × 10−7

dscm/J (9,640 dscf/MMBtu) and Fc= 0.500 × 10−7scm CO2/J (1,840 scf 

CO2/MMBtu). For wood residue other than bark F = 2.492 × 10−7

dscm/J (9,280 dscf/MMBtu) and Fc= 

0.494 × 10−7

scm CO2/J (1,860 scf CO2/MMBtu). 

(vi) For lignite coal as classified according to ASTM D388 (incorporated by reference, see §60.17), F 

= 2.659 × 10−7

dscm/J (9,900 dscf/MMBtu) and Fc= 0.516 × 10−7scm 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 Fcfactors specified in 

paragraph (f)(4) of this section: 

(i) %H, %C, %S, %N, and %O are content by weight of hydrogen, carbon, sulfur, nitrogen, and 

O2(expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis 

of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or computed from results using ASTM 

D1137, D1945, or D1946 (gaseous fuels) as applicable. (These five methods are incorporated by 

reference, see §60.17.) 

(ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted determined by the ASTM 

test methods D2015 or D5865 for solid fuels and D1826 for gaseous fuels as applicable. (These three 

methods are incorporated by reference, see §60.17.) 

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(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: 

Where: 

Xi= Fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood 

residue, etc.); 

Fior (Fc)i= Applicable F or Fcfactor for each fuel type determined in accordance with paragraphs (f)(4) 

and (f)(5) of this section; and 

n = Number of fuels being burned in combination. 

(g) Excess emission and monitoring system performance reports shall be submitted to the 

Administrator semiannually for each six-month period in the calendar year. All semiannual reports 

shall be postmarked by the 30th day following the end of each six-month period. Each excess emission 

and MSP report shall include the information required in §60.7(c). Periods of excess emissions and 

monitoring systems (MS) downtime that shall be reported are defined as follows: 

(1) Opacity . Excess emissions are defined as any six-minute period during which the average opacity 

of emissions exceeds 20 percent opacity, except that one six-minute average per hour of up to 27 

percent opacity need not be reported. 

(i) For sources subject to the opacity standard of §60.42(b)(1), excess emissions are defined as any sixminute period during which the average opacity of emissions exceeds 35 percent opacity, except that 

one six-minute average per hour of up to 42 percent opacity need not be reported. 

(ii) For sources subject to the opacity standard of §60.42(b)(2), excess emissions are defined as any 

six-minute period during which the average opacity of emissions exceeds 32 percent opacity, except 

that one six-minute average per hour of up to 39 percent opacity need not be reported. 

(2) Sulfur dioxide. Excess emissions for affected facilities are defined as: 

(i) For affected facilities electing not to comply with §60.43(d), any three-hour period during which the 

average emissions (arithmetic average of three contiguous one-hour periods) of SO2as measured by a 

CEMS exceed the applicable standard in §60.43; or 

(ii) For affected facilities electing to comply with §60.43(d), any 30 operating day period during which 

the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of 

SO2as measured by a CEMS exceed the applicable standard in §60.43. Facilities complying with the 

30-day SO2standard shall use the most current associated SO2compliance and monitoring requirements 

in §§60.48Da and 60.49Da of subpart Da of this part or §§60.45b and 60.47b of subpart Db of this 

part, as applicable. 

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(3) Nitrogen oxides. Excess emissions for affected facilities using a CEMS for measuring NOXare 

defined as: 

(i) For affected facilities electing not to comply with §60.44(e), any three-hour period during which the 

average emissions (arithmetic average of three contiguous one-hour periods) exceed the applicable 

standards in §60.44; or 

(ii) For affected facilities electing to comply with §60.44(e), any 30 operating day period during which 

the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of 

NOXas measured by a CEMS exceed the applicable standard in §60.44. Facilities complying with the 

30-day NOXstandard shall use the most current associated NOXcompliance and monitoring 

requirements in §§60.48Da and 60.49Da of subpart Da of this part. 

(4) Particulate matter. Excess emissions for affected facilities using a CEMS for measuring PM are 

defined as any boiler operating day period during which the average emissions (arithmetic average of 

all operating one-hour periods) exceed the applicable standards in §60.42. Affected facilities using PM 

CEMS must follow the most current applicable compliance and monitoring provisions in §§60.48Da 

and 60.49Da of subpart Da of this part. 

(h) The owner or operator of an affected facility subject to the opacity limits in §60.42 that elects to 

monitor emissions according to the requirements in §60.45(b)(7) shall maintain records according to 

the requirements specified in paragraphs (h)(1) through (3) of this section, as applicable to the visible 

emissions monitoring method used. 

(1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (h)(1)(i) through (iii) 

of this section. 

(i) Dates and time intervals of all opacity observation periods; 

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible 

emission observer participating in the performance test; and 

(iii) Copies of all visible emission observer opacity field data sheets; 

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (h)(2)(i) through (iv) 

of this section. 

(i) Dates and time intervals of all visible emissions observation periods; 

(ii) Name and affiliation for each visible emission observer participating in the performance test; 

(iii) Copies of all visible emission observer opacity field data sheets; and 

(iv) Documentation of any adjustments made and the time the adjustments were completed to the 

affected facility operation by the owner or operator to demonstrate compliance with the applicable 

monitoring requirements. 
(3) For each digital opacity compliance system, the owner or operator shall maintain records and 

submit reports according to the requirements specified in the site-specific monitoring plan approved by 

the Administrator. 

§60.46 Test methods and procedures. 

(a) In conducting the performance tests required in §60.8, and subsequent performance tests as 

requested by the EPA Administrator, the owner or operator shall use as reference methods and 

procedures the test methods in appendix A of this part or other methods and procedures as specified in 

this section, except as provided in §60.8(b). Acceptable alternative methods and procedures are given 

in paragraph (d) of this section. 

(b) The owner or operator shall determine compliance with the PM, SO2, and NOXstandards in 

§§60.42, 60.43, and 60.44 as follows: 

(1) The emission rate (E) of PM, SO2, or NOXshall be computed for each run using the following 

equation: 

Where: 

E = Emission rate of pollutant, ng/J (1b/million Btu); 

C = Concentration of pollutant, ng/dscm (1b/dscf); 

%O2= O2concentration, percent dry basis; and 

Fd= Factor as determined from Method 19 of appendix A of this part. 

(2) Method 5 of appendix A of this part shall be used to determine the PM concentration (C) at 

affected facilities without wet flue-gas-desulfurization (FGD) systems and Method 5B of appendix A 

of this part shall be used to determine the PM concentration (C) after FGD systems. 

(i) The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 

dscf). The probe and filter holder heating systems in the sampling train shall be set to provide an 

average gas temperature of 160±14 °C (320±25 °F). 

(ii) The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 

3B of appendix A of this part shall be used to determine the O2concentration (%O2). The O2sample 

shall be obtained simultaneously with, and at the same traverse points as, the particulate sample. If the 

grab sampling procedure is used, the O2concentration for the run shall be the arithmetic mean of the 

sample O2concentrations at all traverse points. 

(iii) If the particulate run has more than 12 traverse points, the O2traverse points may be reduced to 12 

provided that Method 1 of appendix A of this part is used to locate the 12 O2traverse points. 

(3) Method 9 of appendix A of this part and the procedures in §60.11 shall be used to determine 

opacity. 

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(4) Method 6 of appendix A of this part shall be used to determine the SO2concentration. 

(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 O2concentration (%O2). The O2sample shall be 

taken simultaneously with, and at the same point as, the SO2sample. The SO2emission rate shall be 

computed for each pair of SO2and O2samples. The SO2emission 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 NOXconcentration. 

(i) The sampling site and location shall be the same as for the SO2sample. Each run shall consist of 

four grab samples, with each sample taken at about 15-minute intervals. 

(ii) For each NOXsample, 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 O2concentration (%O2). The 

sample shall be taken simultaneously with, and at the same point as, the NOXsample. 

(iii) The NOXemission rate shall be computed for each pair of NOXand O2samples. The NOXemission 

rate (E) for each run shall be the arithmetic mean of the results of the four pairs of samples. 

(c) When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator 

(in order to compute the prorated standard as shown in §§60.43(b) and 60.44(b)) shall determine the 

percentage (w, x, y, or z) of the total heat input derived from each type of fuel as follows: 

(1) The heat input rate of each fuel shall be determined by multiplying the gross calorific value of each 

fuel fired by the rate of each fuel burned. 

(2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid fuels), or D1826 (gaseous fuels) (all 

of these methods are incorporated by reference, see §60.17) shall be used to determine the gross 

calorific values of the fuels. The method used to determine the calorific value of wood residue must be 

approved by the Administrator. 

(3) Suitable methods shall be used to determine the rate of each fuel burned during each test period, 

and a material balance over the steam generating system shall be used to confirm the rate. 

(d) The owner or operator may use the following as alternatives to the reference methods and 

procedures in this section or in other sections as specified: 

(1) The emission rate (E) of PM, SO2and NOXmay 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: 
Where: 

E = Emission rate of pollutant, ng/J (lb/MMBtu); 

C = Concentration of pollutant, ng/dscm (lb/dscf); 

%CO2= CO2concentration, 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 O2and CO2concentration 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 

Fovalue, as determined from the average values of Fdand Fcin Method 19 of appendix A of this part, i.e. 

, Foa= 0.209 (Fda/Fca), then the following procedure shall be followed: 

(A) When Fois less than 0.97 Foa, then E shall be increased by that proportion under 0.97 Foa, e.g. , if 

Fois 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 Fois less than 0.97 Foaand 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 Fois 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 Fois greater than 1.03 Foaand when the average difference d is positive, then E shall be 

decreased by that proportion over 1.03 Foa, e.g. , if Fois 1.05 Foa, E shall be decreased by 2 percent. 

This recalculated value shall be used to determine compliance with the relative accuracy specification. 

(2) For Method 5 or 5B of appendix A–3 of this part, Method 17 of appendix A–6 of this part may be 

used at facilities with or without wet FGD systems if the stack gas temperature at the sampling location 

does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of 

Method 5B of appendix A–3 of this part may be used with Method 17 of appendix A–6 of this part 

only if it is used after wet FGD systems. Method 17 of appendix A–6 of this part shall not be used after 

wet FGD systems if the effluent gas is saturated or laden with water droplets. 

(3) Particulate matter and SO2may 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: 

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it again.
(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 SO2emission 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 

O2concentration (%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. 
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. 

(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 

through (23) of this section. 

(1) Affected facilities (i.e. Hheat recovery steam generators used with duct burners) and associated 

with an electric utility combined cycle gasstationary combustion 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 the affected facility (i.e. 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 KKKK, as applicable, of this part).

(3) Any affected facility that meets the applicability requirements and is subject to subpart Eb or 

subpart CCCC of this part is not subject to the emission standards under subpart Da.

(f) General Duty to minimize emissions. At all times, the owner or operator must operate and 

maintain any affected source, including associated air pollution control equipment and monitoring 

equipment, in a manner consistent with safety and good air pollution control practices for minimizing 

emissions. Determination of whether such operation 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, review of operation and maintenance procedures, review of operation and 

Comment [CF1]: Simplify title

Request comment on simplify language by deleting

references to % reduction for PM & NOx since it is

no longer required by the CAA.

Comment [CF2]: Fix typo

Comment [CF3]: Exempt owner/operators of

MWC & CISWI from the criteria pollutant standards

under subpart Da.  Could have startup burners

greater than 250 MMBtu/hr that would make them

applicable to Da.
maintenance records, and inspection of the source.

§60.41Da Definitions. 

As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and 

in subpart A of this part. 

Affirmative defense means, in the context of an enforcement proceeding, a response or defense put 

forward by a defendant, regarding which the defendant has the burden of proof, and the merits of 

which are independently and objectively evaluated in a judicial or administrative proceeding.

Anthracite means coal that is classified as anthracite according to the American Society of Testing and 

Materials in ASTM D388 (incorporated by reference, see §60.17). 

Available 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 §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 §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 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 

Comment [CF4]: Delete since do not use in the

rule
(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 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, natural gas, 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. The Administrator may waive the 50 percent solid-derived fuel requirement during 

periods of the gasification system construction or repair. 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 §60.17). 

Natural gas means: 

Comment [CF5]: Not used in the rule

Comment [CF6]: Remove condition of derived

from coal or petroleum to include natural gas and

gasified materials

Comment [CF7]: Coke‐oven gas is not derived

for the purpose of creating useful heat.  It would still

be considered a gaseous fuel is burned in an

affected facility burning natural gas.

Comment [CF8]: Add in provision to allow initial

operation on natural gas/distillate oil during

construction.  Might be economic to run the

combined cycle facility on natural gas during

construction/repair of the gasification system.  

Switch NSPS applicability could be a permitting

hassle without any environmental benefit.

Request comment on if IGCC facilities that produce

hydrocarbon or hydrogen (i.e., diesel fuel) should be

covered under KKKK.  By‐product recovery (sulfur,

fertilizer, etc.) would not exempt an IGCC from Da.

Need to clarify heat input calculation for compliance

with the PM standard.   
(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 §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 for facilities constructed, reconstructed, or modified before [INSERT THE DATE 1 DAY 

AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL 

REGISTER], means crude oil or a fuel derived from crude oil, including, but not limited to, distillate 

oil, and residual oil. For units constructed, reconstructed, or modified after [INSERT THE DATE OF 

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], Petroleum means 

crude oil or a fuel derived from crude oil, including, but not limited to, distillate oil, residual oil, and 

petroleum coke. 

Petroleum Coke also known as petcoke means a carbonization product of high-boiling hydrocarbon 

fractions obtained in petroleum processing (heavy residues). Petroleum coke is typically derived from 

oil refinery coker units or other cracking processes.

Potential combustion concentration means the theoretical emissions (nanograms per joule (ng/J), 

lb/MMBtu heat input) that would result from combustion of a fuel in an uncleaned state without 

emission control systems) 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 §60.50Da(c). 

(3) For nitrogen oxides (NOX) is: 

(i) 290 ng/J (0.67 lb/MMBtu) heat input for gaseous fuels; 

Comment [CF9]: Add petroleum coke under

petroleum to be consistent with the EGU MACT.  

Included under “coal” for industrial boiler NSPS.
(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 SO2emission 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 for facilities constructed, reconstructed, or modified before [INSERT THE 

DATE 1 DAY AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE 

FEDERAL REGISTER], means any furnace, boiler, or other device used for combusting fuel for the 

purpose of producing steam (including fossil-fuel-fired steam generators associated with combined 

cycle gas turbines; nuclear steam generators are not included). For units constructed, reconstructed, or 

modified after [INSERT THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE 

FEDERAL REGISTER], Steam Generating Unit means any furnace, boiler, or other device used for 

combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators 

associated with combined cycle gas turbines; nuclear steam generators are not included) plus any 

integrated combustion turbines and fuel cells.

Subbituminous coal means coal that is classified as subbituminous A, B, or C according to the 

American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17). 

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 

Comment [CF10]: Not used

Comment [CF11]: Add co‐located combustion

turbines/fuel cells to definition f affected facility.
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 SO2control system that is located 

downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the 

steam generating unit by contacting the combustion gases with an alkaline slurry or solution and 

forming a liquid material. This definition applies to devices where the aqueous liquid material product 

of this contact is subsequently converted to other forms. Alkaline reagents used in wet FGD 

technology include, but are not limited to, lime, limestone, and sodium. 

§60.42Da Standard for particulate matter (PM). 

(a) Except as provided in paragraph (a)(4) of this section, On and after the date on which the initial 

performance test is completed or required to be completed under §60.8, whichever date comes first, 

noan owner or operator of an affected facility subject to the provisions of this subpart shall not cause to 

be discharged into the atmosphere from any affected facility for which construction, reconstruction, or 

modification commenced before or on February 28March 1, 2005, any gases that contain filterable 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.

(4) An owner or operator of an affected facility that combusts only gaseous or liquid fuels (excluding 

residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a 

post-combustion technology to reduce emissions of SO2 or PM is exempt from the PM standard 

specified in paragraphs (a)(1), (a)(2), and (a)(3) of this section:

(b) Except as provided in paragraphs (b)(1) and (b)(2) of this section, Oon and after the date the initial 

PM performance test is completed or required to be completed under §60.8, whichever date comes 

first, anno owner or operator subject to the provisions of this subpartof an affected facility shall not 

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. 

(1) 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 of this 

section.

(2) An owner or operator of an affected facility that combusts only natural gas is exempt from the 

opacity standard specified in paragraph b of this section.

Comment [CF12]: Exempt natural gas & low

sulfur oil boilers from the PM limit.

Comment [CF13]: Exempt owner/operators of

facilities only burning natural gas from the opacity

standard

Request comment on exempting all gaseous fuels &

low sulfur petroleum
(c) Except as provided in paragraphs (d) and (e) of this section, on and after the date on which the 

initial performance test is completed or required to be completed under §60.8, whichever date comes 

first, no owner or operator of an affected facility that commenced construction, reconstruction, or 

modification after February 28, 2005 , but before [INSERT THE DATE 1 DAY AFTER THE DATE 

OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], shall cause to be 

discharged into the atmosphere from that affected facility any gases that contain filterable PM in 

excess of either: 

(1) 18 ng/J (0.14 lb/MWh) gross energy output; or 

(2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel. 

(d) As an alternative to meeting the requirements of paragraph (c) of this section, the owner or 

operator of an affected facility for which construction, reconstruction, or modification commenced 

after February 28, 2005, but before [INSERT THE DATE 1 DAY AFTER THE DATE OF 

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], may elect to meet 

the requirements of this paragraph. For an affected facility that commenced construction, 

reconstruction, or modification, Oon and after the date on which the initial performance test is 

completed or required to be completed under §60.8, whichever date comes first, no owner or operator 

of an affected facility shall cause to be discharged into the atmosphere from that affected facility for 

which construction, reconstruction, or modification commenced after February 28, 2005, any gases 

that contain filterable PM in excess of: 

(1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel, 

and 

(2) For an affected facility that commenced construction or reconstruction, 0.1 percent of the 

combustion concentration determined according to the procedure in §60.48Da(o)(5) (99.9 percent 

reduction) for an affected facility for which construction or reconstruction commenced after February 

28, 2005 when combusting solid, liquid, or gaseous fuel, or 

(3) For an affected facility that commenced modification, 0.2 percent of the combustion concentration 

determined according to the procedure in §60.48Da(o)(5) (99.8 percent reduction) for an affected 

facility for which modification commenced after February 28, 2005 when combusting solid, liquid, or 

gaseous fuel.

(e) An owner or operator of an affected facility than combusts only gaseous or liquid fuels (excluding 

residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and that does not 

use a post-combustion technology to reduce emissions of SO2 or PM is exempt from the PM standard 

specified in paragraphs (c) of this section.

(f) Except as provided in paragraphs (g) of this section, on and after the date on which the initial 

performance test is completed or required to be completed under §60.8, whichever date comes first, no 

owner or operator of an affected facility that commenced construction or reconstruction after [INSERT 

THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER],

shall cause to be discharged into the atmosphere from that affected facility any gases that contain total

PM in excess of :

(1) For an affected facility that commenced construction or reconstruction 7.0 ng/J (0.055 lb/MWh) 

gross energy output; or

(2) For an affected facility that commenced modification, 15 ng/J (0.034 lb/MMBtu) heat input.

Comment [CF14]: Request comment if we could

delete since has not been used

Comment [CF15]: Fix typo

Comment [CF16]: Exempt natural gas & low

sulfur oil boilers from the PM limit.
(g) An owner or operator of an affected facility that combusts only natural gas is exempt from the total 

PM standard specified in paragraphs (f) of this section.

(h) The PM emission standards under this section do not apply to an owner or operator of any affected 

facility that is operated under a PM commercial demonstration permit issued by the Administrator in 

accordance with the provisions of §60.47Da.

§60.43Da Standard for sulfur dioxide (SO2). 

(a) On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart 

shall cause to be discharged into the atmosphere from any affected facility which combusts solid fuel 

or solid-derived fuel and for which construction, reconstruction, or modification commenced before or 

on February 28, 2005, except as provided under paragraphs (c), (d), (f) or (h) of this section, any gases 

that contain SO2in 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;

.(3) 180 ng/J (1.4 lb/MWh) gross energy output; or

(4) 65 ng/J (0.15 lb/MMBtu) heat input.

(b) On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart 

shall cause to be discharged into the atmosphere from any affected facility which combusts liquid or 

gaseous fuels (except for liquid or gaseous fuels derived from solid fuels and as provided under 

paragraphs (e) or (h) of this section) and for which construction, reconstruction, or modification 

commenced before or on February 28, 2005, any gases that contain SO2in excess of: 

(1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 

percent reduction); or 

(2) 100 percent of the potential combustion concentration (zero percent reduction) when emissions are 

less than 86 ng/J (0.20 lb/MMBtu) heat input. 

(c) On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart 

shall cause to be discharged into the atmosphere from any affected facility which combusts solid 

solvent refined coal (SRC–I) any gases that contain SO2in 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. 

Comment [CF17]: Since PM standard includes

total PM oil‐fired would still be subject to the

standard

Request comment on if low sulfur distillate should

also be exempt

Comment [CF18]: Add option for

owner/operators of facilities presently covered by

Da to comply with standard for “new” modified

sources.  Might co‐fire with biomass and 70%

reduction on a small amount of fossil fuel could be

difficult.  

Comment [CF19]: Request comment on

deleting/reserving since never used
(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 requirementsSO2 standards under this section do not apply to an owner or 

operator of any affected facility that is operated under an SO2 commercial demonstration permit issued 

by the Administrator in accordance with the provisions of §60.47Da. 

(g) Compliance with the emission limitation and percent reduction requirements under this section are 

both determined on a 30-day rolling average basis except as provided under paragraph (c) of this 

section. 

(h) When different fuels are combusted simultaneously, the applicable standard is determined by 

proration using the following formula: 

(1) If emissions of SO2to the atmosphere are greater than 260 ng/J (0.60 lb/MMBtu) heat input 

(2) If emissions of SO2to the atmosphere are equal to or less than 260 ng/J (0.60 lb/MMBtu) heat 

input: 

Where: 

Es= Prorated SO2emission limit (ng/J heat input); 

%Ps= Percentage of potential SO2emission allowed; 

x = Percentage of total heat input derived from the combustion of liquid or gaseous fuels (excluding 

solid-derived fuels); and 

y = Percentage of total heat input derived from the combustion of solid fuel (including solid-derived 

fuels). 

(i) Except as provided in paragraphs (j) and (k) of this section, on and after the date on which the initial 

performance test is completed or required to be completed under §60.8, whichever date comes first, no 

owner or operator of an affected facility that commenced construction, reconstruction, or modification 

commenced after February 28, 2005, but before [INSERT THE DATE 1 DAY AFTER THE DATE 

OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], 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 commenced 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. 

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.
(2) For an affected facility for which commenced 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 commenced 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 §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, but before [INSERT 

THE DATE 1 DAY AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE 

FEDERAL REGISTER], 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 commenced 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 commenced 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 commenced modification commenced after February 28, 2005, 

any gases that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or 

(iii) 10 percent of the potential combustion concentration (90 percent reduction) on a 30-day rolling 

average basis. 

(k) On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator of an affected facility located in a 
noncontinental area that commenced construction, reconstruction, or modification commenced after 

February 28, 2005, but before [INSERT THE DATE 1 DAY AFTER THE DATE OF PUBLICATION 

OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], 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. 

(l) Except as provided in paragraphs (m) and (n) of this section, on and after the date on which the 

initial performance test is completed or required to be completed under §60.8, whichever date comes 

first, no owner or operator of an affected facility that commenced construction, reconstruction, or 

modification commenced after [INSERT THE DATE OF PUBLICATION OF THIS PROPOSED 

RULE IN THE FEDERAL REGISTER], 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 (l)(1) or (2) of this section.

(1) For an affected facility which commenced construction or reconstruction, any gases that contain 

SO2 in excess of either:

(i) 130 ng/J (1.0 lb/MWh) gross energy output; or

(ii) 3 percent of the potential combustion concentration (97 percent reduction).

(2) For an affected facility which commenced modification, any gases that contain SO2 in excess of 

either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or

(ii) 10 percent of the potential combustion concentration (90 percent reduction).

(m) On and after the date on which the initial performance test is completed or required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 

commenced construction, reconstruction, or modification commenced after [INSERT THE DATE OF 

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], 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 (m)(1) or (2) of this section.

(1) For an affected facility which commenced construction or reconstruction, any gases that contain 

SO2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or

(ii) 6 percent of the potential combustion concentration (94 percent reduction).

(2) For an affected facility which commenced modification, any gases that contain SO2 in excess of 

either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or

(ii) 10 percent of the potential combustion concentration (90 percent reduction).
(n) On and after the date on which the initial performance test is completed or required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility located 

in a noncontinental area that commenced construction, reconstruction, or modification commenced 

after [INSERT THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL 

REGISTER], 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 (n)(1) and (2) of 

this section.

(1) For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause 

to be discharged into the atmosphere any gases that contain SO2 in excess of 520 ng/J (1.2 lb/MMBtu) 

heat input.

(2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall 

not cause to be discharged into the atmosphere any gases that contain SO2 in excess of 230 ng/J (0.54

lb/MMBtu) heat input.

§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 §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 §60.48Da(j)(1): 

(1) NOXemission limits. 

Fuel type 

Emission 

limit for heat 

input 

ng/J lb/M

MBtu

Gaseous fuels: 

Coal-derived fuels 210 0.50 

All other fuels 86 0.20 

Liquid fuels: 

Coal-derived fuels 210 0.50 

Shale oil 210 0.50 

All other fuels 130 0.30 

Solid fuels: 
Coal-derived fuels 210 0.50 

Any fuel containing more than 25%, by weight, coal refuse (1) (1)

Any fuel containing more than 25%, by weight, lignite if the lignite is mined in 

North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace2 340 0.80 

Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J 

heat input emission limit2 260 0.60 

Subbituminous coal 210 0.50 

Bituminous coal 260 0.60 

Anthracite coal 260 0.60 

All other fuels 260 0.60 

1

Exempt from NOXstandards and NOXmonitoring 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) NOXreduction requirement. 

Fuel type Percent reduction of potential combustion 

concentration 

Gaseous fuels 25 

Liquid fuels 30 

Solid fuels 65 

(b) The NOX emission limitations under paragraph (a) of this section do not apply to an owner or 

operator yof an 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 

§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: 

Where: 

En= Applicable standard for NOXwhen multiple fuels are combusted simultaneously (ng/J heat input); 

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.
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 §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 28March 1, 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 §60.48Da(k). 

(2) On and after the date on which the initial performance test is completed or required to be 

completed under §60.8, whichever date comes first, no owner or operator of affected facility for which 

reconstruction commenced after July 9, 1997, but before or on February 28March 1, 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 as provided in 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 §60.8, whichever date comes first, no owner or operator of an 

affected facility that commenced construction, reconstruction, or modification after February 28, 2005 

but before [INSERT THE DATE 1 DAY AFTER THE DATE OF PUBLICATION OF THIS 

PROPOSED RULE IN THE FEDERAL REGISTER], 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 commenced 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 §60.48Da(k). 

(2) For an affected facility for which commenced 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 commenced 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 

Comment [CF20]: Could this duct burner

provision be deleted since it would be covered

under KKKK?  Have to think about HRSG that are

rebuilt/added without changing the combustion

turbine engine
(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 §60.8, whichever date comes first, the owner or operator of an IGCC electric utility 

steam generating unit subject to the provisions of this subpart and for which construction, 

reconstruction, or modification commenced after February 28, 2005 but before [INSERT THE DATE 

1 DAY AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL 

REGISTER], 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 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.

(g) Compliance with the emission limitations under this section are determined on a 30-day rolling 

average basis, except as provided under §60.48Da(j)(1).

(h) On and after the date on which the initial performance test is completed or required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 

commenced construction, reconstruction, or modification after [INSERT THE DATE OF 

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], shall cause to be 

discharged into the atmosphere from that affected facility any gases that contain NOX (expressed as 

NO2) in excess of of 88 ng/J (0.70 lb/MWh) gross energy output,

§60.45Da Standard for mercury (Hg).[Reserved]

(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 §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 §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 

× 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:

Comment [CF21]: Request comment on ability

of coal refuse‐fired facilities to achieve this

standard.

Comment [CF22]: Delete and reserve section

since CAMR was vacated
(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 × 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 × 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 × 

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 

× 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 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.

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.

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.
(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 §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 × 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 §60.50Da(h).

§60.46Da [Reserved] 

§60.47Da Commercial demonstration permit. 

(a) An owner or operator of an affected facility proposing to demonstrate an emerging technology may 

apply to the Administrator for a commercial demonstration permit. The Administrator will issue a 

commercial demonstration permit in accordance with paragraph (e) of this section. Commercial 

demonstration permits may be issued only by the Administrator, and this authority will not be 

delegated. 

(b) An owner or operator of an affected facility that combusts solid solvent refined coal (SRC–I) and 

who is issued a commercial demonstration permit by the Administrator is not subject to the 

SO2emission reduction requirements under §60.43Da(c) but must, as a minimum, reduce SO2emissions 

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 demonstration permit by the Administrator is not subject to 

the SO2emission reduction requirements under §60.43Da(a) but must, as a minimum, reduce 

SO2emissions 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 

NOXemission limitation and percent reduction under §60.44Da(a) but must, as a minimum, reduce 

emissions to less than 300 ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis. 

(e) Commercial demonstration permits may not exceed the following equivalent MW electrical 

generation capacity for any one technology category, and the total equivalent MW electrical generation 

capacity for all commercial demonstration plants may not exceed 15,000 MW. 

Comment [CF23]: Request comment on

deleting existing paragraphs (b) & (c) & to replace

paragraph (e) since they have never been used
Technology Pollutant Equivalent electrical capacity 

(MW electrical output) 

Solid solvent refined coal (SCR I) SO2 6,000–10,000 

Fluidized bed combustion (atmospheric) SO2 400–3,000 

Fluidized bed combustion (pressurized) SO2 400–1,200 

Coal liquification NOX 750–10,000 

Total allowable for all technologies 15,000 

(f) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multipollutant emissions controls system who is issued a commercial demonstration permit by the 

Administrator is not subject to the total PM emission reduction requirements under §60.42Da but must, 

as a minimum, reduce PM emissions to less than 15 ng/J (0.034 lb/MMBtu) heat input.

(g) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multipollutant emissions controls system who is issued a commercial demonstration permit by the 

Administrator is not subject to the SO2 standards or emission reduction requirements under §60.43Da 

but must, as a minimum, reduce SO2 emissions to 5 percent of the potential combustion concentration 

(95 percent reduction) or to less than 180 ng/J (1.4 lb/MWh) gross output on a 30-day rolling average 

basis.

(h) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multipollutant emissions controls system or advanced combustion controls who is issued a commercial 

demonstration permit by the Administrator is not subject to the NOX standards or emission reduction 

requirements under §60.44Da but must, as a minimum, reduce NOX emissions to less than 130 ng/J 

(1.0 lb/MWh) gross output on a 30-day rolling average basis.

(i) Commercial demonstration permits may not exceed the following equivalent MW electrical 

generation capacity for any one technology category.

Technology Pollutant Equivalent Electrical Capacity 

(MW electrical output)

Multi-pollutant Emission Control SO2 1,000

Multi-pollutant Emission Control NOX 1,000

Multi-pollutant Emission Control PM 1,000

Pressurized Fluidized Bed Combustion SO2 1,000

Pressurized Fluidized Bed Combustion NOX 1,000

Pressurized Fluidized Bed Combustion PM 1,000

Advanced Combustion Controls NOX 1,000

§60.48Da Compliance provisions. 

(a) Compliance with the PM emission limitation under §60.42Da(a)(1) constitutes compliance with the 

percent reduction requirements for PM under §60.42Da(a)(2) and (3). 

Comment [CF24]: Should these just reference

the standards within the text?  Easier if can delete

the previous paragraphs.

Comment [CF25]: This would be a combined

NOX + CO standard in the event a combined

standard is finalized.  It would be an equivalent

amount higher than the combined standard

Comment [CF26]: Redundancy between

60.48Da & 60.49Da could be eliminated to make it

easier to follow
(b) Compliance with the NOXemission limitation under §60.44Da(a)(1) constitutes compliance with 

the percent reduction requirements under §60.44Da(a)(2). 

(c) For affected facilities that commenced construction, modification, or reconstruction before 

[INSERT THE DATE 1 DAY AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE 

IN THE FEDERAL REGISTER], Tthe PM emission standards under §60.42Da, and the NOX emission 

standards under §60.44Da apply at all times except during periods of startup, shutdown, or 

malfunction. The sulfur dioxide emission standards under §60.43Da apply at all times except during 

periods of startup, shutdown, or when both emergency conditions exist and the procedures under 

paragraph (d) of this section are implemented. For affected facilities that commence construction, 

modification, or reconstruction after [INSERT THE DATE OF PUBLICATION OF THIS 

PROPOSED RULE IN THE FEDERAL REGISTER], the PM emission standards under §60.42Da, the 

NOX emission standards under §60.44Da, and the sulfur dioxide emission standards under §60.43Da 

apply at all times. 

(d) During emergency conditions in the principal company, an affected facility with a malfunctioning 

flue gas desulfurization system may be operated if SO2emissions 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 SO2emission 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 

§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. 

(e) After the initial performance test required under §60.8, compliance with the SO2emission 

limitations and percentage reduction requirements under §60.43Da and the NOXemission limitations 

under §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 SO2and NOXand a new percent 

reduction for SO2are calculated to show compliance with the standards. 

(f) For the initial performance test required under §60.8, compliance with the SO2emission limitations 

and percent reduction requirements under §60.43Da and the NOXemission limitation under §60.44Da 

is based on the average emission rates for SO2, NOX, and percent reduction for SO2for 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 

Comment [CF27]: Include all periods of

operation.   

Request comment on removing emergency

conditions for existing facilities.  
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) For affected facilities that commenced construction, modification, or reconstruction before 

[INSERT THE DATE 1 DAY AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE 

IN THE FEDERAL REGISTER], Ccompliance 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). For affected facilities that 

commence construction, modification, or reconstruction after [INSERT THE DATE OF 

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], compliance with 

applicable 30-day rolling average SO2 and NOX emission limitations is determined by dividing the sum 

of all the SO2 and NOX emissions for the 30 successive boiler operating days divided by the sum of all 

the gross useful output for the 30 successive boiler operating days.

(2) For affected facilities that commenced construction, modification, or reconstruction before 

[INSERT THE DATE 1 DAY AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE 

IN THE FEDERAL REGISTER], Ccompliance with applicable SO2 percentage reduction 

requirements is determined based on the average inlet and outlet SO2 emission rates for the 30 

successive boiler operating days. For affected facilities that commence construction, modification, or 

reconstruction after [INSERT THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE 

FEDERAL REGISTER], compliance with applicable SO2 percentage reduction requirements is 

determined based on the “as fired” total potential emissions and the total outlet SO2 emissions for the 

30 successive boiler operating days.

(3) For affected facilities that commenced construction, modification, or reconstruction before 

[INSERT THE DATE 1 DAY AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE 

IN THE FEDERAL REGISTER], Ccompliance 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. For affected 

facilities that commence construction, modification, or reconstruction after [INSERT THE DATE OF 

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], compliance with 

applicable daily average PM emission limitations is determined by calculating dividing the sum of all 

PM emissions for PM each boiler operating day divided by the sum of all the gross useful output for 

PM each boiler operating day. Averages are only calculated for boiler operating days that have valid 

non-out-of-control data for at least 18 hours of unit operation during which the standard applies. 

Instead, all of the validnon-out-of-control hourly emission rates of the operating day(s) not meeting the 

minimum 18 hours validnon-out-of-control data daily average requirement are averaged with all of the 

non-out-of-controlvalid hourly emission rates of the next boiler operating day with 18 hours or more of 

non-out-of-controlvalid PM CEMS data to determine compliance. 

(h) If an owner or operator has not obtained the minimum quantity of emission data as required under 

§60.49Da of this subpart, compliance of the affected facility with the emission requirements under 

§§60.43Da and 60.44Da of this subpart for the day on which the 30-day period ends may be 

determined by the Administrator by following the applicable procedures in section 7 of Method 19 of 

appendix A of this part. 

Comment [CF28]: Amended procedures for

calculating emissions rates divides total emissions

by total output over a 30‐day period (total

emissions/total output & not average of hourly

rates).  Minimizes periods of startup and shutdown

since less mass of emissions at lower operational

rates.  Might be useful to add equations.

Comment [CF29]: Update to current language
(i) Compliance provisions for sources subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f) . The 

owner or operator of an affected facility subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f) 

shall calculate NOXemissions as 1.194 × 10−7

 lb/scf-ppm times the average hourly NOXoutput 

concentration in ppm (measured according to the provisions of §60.49Da(c)), times the average hourly 

flow rate (measured in scfh, according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by 

the average hourly gross energy output (measured according to the provisions of §60.49Da(k)). 

Alternatively, for oil-fired and gas-fired units, NOXemissions may be calculated by multiplying the 

hourly NOXemission rate in lb/MMBtu (measured by the CEMS required under §§60.49Da(c) and (d)), 

by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the 

result by the average gross energy output (measured according to the provisions of §60.49Da(k)). 

(j) Compliance provisions for duct burners subject to §60.44Da(a)(1) . To determine compliance with 

the emissions limits for NOXrequired by §60.44Da(a) for duct burners used in combined cycle systems, 

either of the procedures described in paragraph (j)(1) or (2) of this section may be used: 

(1) The owner or operator of an affected duct burner shall conduct the performance test required under 

§60.8 using the appropriate methods in appendix A of this part. Compliance with the emissions limits 

under §60.44Da(a)(1) is determined on the average of three (nominal 1-hour) runs for the initial and 

subsequent performance tests. During the performance test, one sampling site shall be located in the 

exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outlet 

from the heat recovery steam generating unit. Measurements shall be taken at both sampling sites 

during the performance test; or 

(2) The owner or operator of an affected duct burner may elect to determine compliance by using the 

CEMS specified under §60.49Da for measuring NOXand oxygen (O2) (or carbon dioxide (CO2)) and 

meet the requirements of §60.49Da. Alternatively, data from a NOXemission rate ( i.e. , NOX-diluent) 

CEMS certified according to the provisions of §75.20(c) of this chapter and appendix A to part 75 of 

this chapter, and meeting the quality assurance requirements of §75.21 of this chapter and appendix B 

to part 75 of this chapter, may be used, with the following caveats. Data used to meet the requirements 

of §60.51Da shall not include substitute data values derived from the missing data procedures in 

subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the 

procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam 

generating unit. The NOXemission rate at the outlet from the steam generating unit shall constitute the 

NOXemission rate from the duct burner of the combined cycle system. 

(k) Compliance provisions for duct burners subject to §60.44Da(d)(1) or (e)(1) . To determine 

compliance with the emission limitation for NOXrequired by §60.44Da(d)(1) or (e)(1) for duct burners 

used in combined cycle systems, either of the procedures described in paragraphs (k)(1) and (2) of this 

section may be used: 

(1) The owner or operator of an affected duct burner used in combined cycle systems shall determine 

compliance with the applicable NOXemission limitation in §60.44Da(d)(1) or (e)(1) as follows: 

(i) The emission rate (E) of NOXshall be computed using Equation 2 in this section: 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross output; 

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.
Csg= Average hourly concentration of NOXexiting the steam generating unit, ng/dscm (lb/dscf); 

Cte= Average hourly concentration of NOXin 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/h (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 NOXconcentrations (Csgand 

Cte). Method 2, 2F or 2G of appendix A of this part, as appropriate, shall be used to determine the 

volumetric flow rates (Qsgand 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 NOXemission limitation in §60.44Da(d)(1) or (e)(1) is determined 

by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests. 

(2) The owner or operator of an affected duct burner used in a combined cycle system may elect to 

determine compliance with the applicable NOXemission limitation in §60.44Da(d)(1) or (e)(1) on a 30-

day rolling average basis as indicated in paragraphs (k)(2)(i) through (iv) of this section. 

(i) The emission rate (E) of NOXshall be computed using Equation 3 in this section: 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross output; 

Csg= Average hourly concentration of NOXexiting 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/h (MWh). 

(ii) The CEMS specified under §60.49Da for measuring NOXand O2(or CO2) shall be used to 

determine the average hourly NOXconcentrations (Csg). The continuous flow monitoring system 

specified in §60.49Da(l) or §60.49Da(m) shall be used to determine the volumetric flow rate (Qsg) of 

the exhaust gas. If the option to use the flow monitoring system in §60.49Da(m) is selected, the flow 

rate data used to meet the requirements of §60.51Da shall not include substitute data values derived 

from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been 

bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located 

at the outlet from the steam generating unit. 

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.

Comment [CF30]: Fix typo
(iii) The continuous monitoring system specified under §60.49Da(k) for measuring and determining 

gross energy output shall be used to determine the average hourly gross energy output from the entire 

combined cycle unit (Occ), which is the combined output from the combustion turbine and the steam 

generating unit. 

(iv) The owner or operator may, in lieu of installing, operating, and recording data from the continuous 

flow monitoring system specified in §60.49Da(l), determine the mass rate (lb/hr) of NOXemissions 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 NOXshall be computed using Equation 4 in this section: 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross output; 

ERsg= Average hourly emission rate of NOXexiting 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/h (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 NOXemissions limits by measuring the emissions 

combined with the emissions from the other unit(s) utilizing the common steam turbine; or 

(ii) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for 

apportioning the combined gross energy output from the steam turbine for each of the affected duct 

burners. The Administrator may approve such demonstrated substitute methods for apportioning the 

combined gross energy output measured at the steam turbine whenever the demonstration ensures 

accurate estimation of emissions regulated under this part. 

(l) [Reserved]Compliance provisions for sources subject to §60.45Da. The owner or operator of an 

affected facility subject to §60.45Da (new sources constructed or reconstructed after January 30, 2004) 

shall calculate the Hg emission rate (lb/MWh) for each calendar month of the year, using hourly Hg 

concentrations measured according to the provisions of §60.49Da(p) in conjunction with hourly stack 

gas volumetric flow rates measured according to the provisions of §60.49Da(l) or (m), and hourly 

gross electrical outputs, determined according to the provisions in §60.49Da(k). Compliance with the 

applicable standard under §60.45Da is determined on a 12-month rolling average basis.[

(m) Compliance provisions for sources subject to §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 §60.43Da(i)(1)(i), (i)(2)(i), 

(i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i) shall calculate SO2emissions as 1.660 × 10–7lb/scf-ppm times the 

average hourly SO2output concentration in ppm (measured according to the provisions of 

§60.49Da(b)), times the average hourly flow rate (measured according to the provisions of §60.49Da(l) 

or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the 

provisions of §60.49Da(k)). Alternatively, for oil-fired and gas-fired units, SO2emissions may be 

calculated by multiplying the hourly SO2emission rate (in lb/MMBtu), measured by the CEMS 

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Comment [CF31]: Delete since CAMR vacated
required under §60.49Da, by the hourly heat input rate (measured according to the provisions of 

§60.49Da(n)), and dividing the result by the average gross energy output (measured according to the 

provisions of §60.49Da(k)). 

(n) Compliance provisions for sources subject to §60.42Da(c)(1) . The owner or operator of an 

affected facility subject to §60.42Da(c)(1) shall calculate PM emissions by multiplying the average 

hourly PM output concentration (measured according to the provisions of §60.49Da(t)), by the average 

hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), and divided 

by the average hourly gross energy output (measured according to the provisions of §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 §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 §60.42Da(c)(2) or (d) by the applicable date specified in §60.8(a). Thereafter, you 

must conduct each subsequent performance test within 12 calendar months following the date the 

previous performance test was required to be conducted. You must conduct each performance test 

according to the requirements in §60.8 using the test methods and procedures in §60.50Da. The owner 

or operator of an affected facility that has not operated for 60 consecutive calendar days prior to the 

date that the subsequent performance test would have been required had the unit been operating is not 

required to perform the subsequent performance test until 30 calendar days after the next boiler 

operating day. Requests for additional 30 day extensions shall be granted by the relevant air division or 

office director of the appropriate Regional Office of the U.S. EPA. 

(2) You must monitor the performance of each electrostatic precipitator or fabric filter (baghouse) 

operated to comply with the applicable PM emissions limit in §60.42Da(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 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. 

Comment [CF32]: Don’t need since say earlier

in the rule.
(C) You must apply a method for producing a simulated zero opacity condition and an upscale (span) 

opacity condition using a certified neutral density filter or other related technique to produce a known 

obscuration of the light beam. All procedures applied must provide a system check of the analyzer 

internal optical surfaces and all electronic circuitry including the lamp and photodetector assembly. 

(D) Except during periods of system breakdowns, repairs, calibration checks, and zero and span 

adjustments, the COMS must be in continuous operation and must complete a minimum of one cycle 

of sampling and analyzing for each successive 10 second period and one cycle of data recording for 

each successive 6-minute period. 

(E) You must reduce all data from the COMS to 6-minute averages. Six-minute opacity averages must 

be calculated from 36 or more data points equally spaced over each 6-minute period. Data recorded 

during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments must 

not be included in the data averages. An arithmetic or integrated average of all data may be used. 

(iii) During each performance test conducted according to paragraph (o)(1) of this section, you must 

establish an opacity baseline level. The value of the opacity baseline level is determined by averaging 

all of the 6-minute average opacity values (reported to the nearest 0.1 percent opacity) from the COMS 

measurements recorded during each of the test run intervals conducted for the performance test, and 

then adding 2.5 percent opacity to your calculated average opacity value for all of the test runs. If your 

opacity baseline level is less than 5.0 percent, then the opacity baseline level is set at 5.0 percent. 

(iv) You must evaluate the preceding 24-hour average opacity level measured by the COMS each 

boiler operating day excluding periods of affected facility startup, shutdown, or malfunction. If the 

measured 24-hour average opacity emission level is greater than the baseline opacity level determined 

in paragraph (o)(2)(iii) of this section, you must initiate investigation of the relevant equipment and 

control systems within 24 hours of the first discovery of the high opacity incident and take the 

appropriate corrective action as soon as practicable to adjust control settings or repair equipment to 

reduce the measured 24-hour average opacity to a level below the baseline opacity level. In cases when 

a wet scrubber is used in combination with another PM control device that serves as the primary PM 

control device, the wet scrubber must be maintained and operated. 

(v) You must record the opacity measurements, calculations performed, and any corrective actions 

taken. The record of corrective action taken must include the date and time during which the measured 

24-hour average opacity was greater than baseline opacity level, and the date, time, and description of 

the corrective action. 

(vi) If the measured 24-hour average opacity for your affected facility remains at a level greater than 

the opacity baseline level after 7 boiler operating days, then you must conduct a new PM performance 

test according to paragraph (o)(1) of this section and establish a new opacity baseline value according 

to paragraph (o)(2) of this section. This new performance test must be conducted within 60 days of the 

date that the measured 24-hour average opacity was first determined to exceed the baseline opacity 

level unless a waiver is granted by the permitting authority. 

(3) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner 

or operator may elect to monitor the performance of an electrostatic precipitator (ESP) operated to 

comply with the applicable PM emissions limit in §60.42Da(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 §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 CoalFired Boiler.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); 

Office of Air Quality Planning and Standards; Sector Policies and Programs Division; Measurement 

Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the 

Technology Transfer Network (TTN) under Emission Measurement Center Continuous Emission 

Monitoring. 

(iii) You must run the ESP predictive model using the applicable input data each boiler operating day 

and evaluate the model output for the preceding boiler operating day excluding periods of affected 

facility startup, shutdown, or malfunction. If the values for one or more of the model parameters 

exceed the applicable baseline levels determined according to your approved site-specific monitoring 

plan, you must initiate investigation of the relevant equipment and control systems within 24 hours of 

the first discovery of a model parameter deviation and, take the appropriate corrective action as soon as 

practicable to adjust control settings or repair equipment to return the model output to within the 

applicable baseline levels. 

(iv) You must record the ESP predictive model inputs and outputs and any corrective actions taken. 

The record of corrective action taken must include the date and time during which the model output 

values exceeded the applicable baseline levels, and the date, time, and description of the corrective 

action. 

(v) If after 7 consecutive days a model parameter continues to exceed the applicable baseline level, 

then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This 

new performance test must be conducted within 60 calendar days of the date that the model parameter 

was first determined to exceed its baseline level unless a waiver is granted by the permitting authority. 

(4) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner 

or operator may elect to monitor the performance of a fabric filter (baghouse) operated to comply with 

the applicable PM emissions limit in §60.42Da(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.) 

(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 sitespecific monitoring plan required by paragraph (o)(4)(ii) of this section. 

(G) You must install the bag leak detection sensor downstream of the fabric filter and upstream of any 

wet scrubber. 

(H) Where multiple detectors are required, the system's instrumentation and alarm may be shared 

among detectors. 

(ii) You must develop and submit to the permitting authority for approval a site-specific monitoring 

plan for each bag leak detection system. You must operate and maintain the bag leak detection system 

according to the site-specific monitoring plan at all times. Each monitoring plan must describe the 

items in paragraphs (o)(4)(ii)(A) through (F) of this section. 

(A) Installation of the bag leak detection system; 

(B) Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point 

will be established; 

(C) Operation of the bag leak detection system, including quality assurance procedures; 

(D) How the bag leak detection system will be maintained, including a routine maintenance schedule 

and spare parts inventory list; 

(E) How the bag leak detection system output will be recorded and stored; and 

(F) Corrective action procedures as specified in paragraph (o)(4)(iii) of this section. In approving the 

site-specific monitoring plan, the permitting authority may allow owners and operators more than 3 

hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the 

monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is 

not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates 

that the requested time will ensure alleviation of this condition as expeditiously as practicable. 

(iii) For each bag leak detection system, you must initiate procedures to determine the cause of every 

alarm within 1 hour of the alarm. Except as provided in paragraph (o)(4)(ii)(F) of this section, you 

must alleviate the cause of the alarm within 3 hours of the alarm by taking whatever corrective 

action(s) are necessary. Corrective actions may include, but are not limited to the following: 

(A) Inspecting the fabric filter for air leaks, torn or broken bags or filter media, or any other condition 

that may cause an increase in particulate emissions; 

(B) Sealing off defective bags or filter media; 

(C) Replacing defective bags or filter media or otherwise repairing the control device; 
(D) Sealing off a defective fabric filter compartment; 

(E) Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection system; 

or 

(F) Shutting down the process producing the particulate emissions. 

(iv) You must maintain records of the information specified in paragraphs (o)(4)(iv)(A) through (C) of 

this section for each bag leak detection system. 

(A) Records of the bag leak detection system output; 

(B) Records of bag leak detection system adjustments, including the date and time of the adjustment, 

the initial bag leak detection system settings, and the final bag leak detection system settings; and 

(C) The date and time of all bag leak detection system alarms, the time that procedures to determine 

the cause of the alarm were initiated, if procedures were initiated within 1 hour of the alarm, the cause 

of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was 

alleviated, and if the alarm was alleviated within 3 hours of the alarm. 

(v) If after any period composed of 30 boiler operating days during which the alarm rate exceeds 5 

percent of the process operating time (excluding control device or process startup, shutdown, and 

malfunction), then you must conduct a new PM performance test according to paragraph (o)(1) of this 

section. This new performance test must be conducted within 60 calendar days of the date that the 

alarm rate was first determined to exceed 5 percent limit unless a waiver is granted by the permitting 

authority. 

(5) An owner or operator of a modified affected facility electing to meet the emission limitations in 

§60.42Da(d) shall determine the percent reduction in PM by using the emission rate for PM 

determined by the performance test conducted according to the requirements in paragraph (o)(1) of this 

section and the ash content on a mass basis of the fuel burned during each performance test run as 

determined by analysis of the fuel as fired. 

(p) As an alternative to meeting the compliance provisions specified in paragraph (o) of this section, an 

owner or operator may elect to install, evaluate, maintain, and operate a CEMS measuring PM 

emissions discharged from the affected facility to the atmosphere and record the output of the system 

as specified in paragraphs (p)(1) through (p)(8) of this section. 

(1) The owner or operator shall submit a written notification to the Administrator of intent to 

demonstrate compliance with this subpart by using a CEMS measuring PM. This notification shall be 

sent at least 30 calendar days before the initial startup of the monitor for compliance determination 

purposes. The owner or operator may discontinue operation of the monitor and instead return to 

demonstration of compliance with this subpart according to the requirements in paragraph (o) of this 

section by submitting written notification to the Administrator of such intent at least 30 calendar days 

before shutdown of the monitor for compliance determination purposes. 

(2) Each CEMS shall be installed, evaluated, operated, and maintained according to the requirements 

in §60.49Da(v). 

(3) The initial performance evaluation shall be completed no later than 180 days after the date of initial 

startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of 

the date of notification to the Administrator required under paragraph (p)(1) of this section, whichever 

is later. 
(4) Compliance with the applicable emissions limit shall be determined based on the 24-hour daily 

(block) average of the hourly arithmetic average emissions concentrations using the continuous 

monitoring system outlet data. The 24-hour block arithmetic average emission concentration shall be 

calculated using EPA Reference Method 19 of appendix A of this part, section 4.1. 

(5) At a minimum, non-out-of-control 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, validnon-out-ofcontrol 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 §60.13(e)(2) of 

subpart A of this part. 

(7) All validnon-out-of-control CEMS data shall be used in calculating average emission 

concentrations even if the minimum CEMS data requirements of paragraph (j)(5) of this section are not 

met. 

(8) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring 

systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to 

provide, as necessary, validnon-out-of-control emissions data for a minimum of 90 percent (only 75 

percent is required prior to January 1, 2012) of all operating hours per 30-day rolling average. 

(q) Compliance provisions for sources subject to §60.42Da(b) . An owner or operator of an affected 

facility subject to the opacity standard in §60.42Da(b) shall monitor the opacity of emissions 

discharged from the affected facility to the atmosphere according to the requirements in §60.49Da(a), 

as applicable to the affected facility.

(r) Affirmative Defense for Exceedance of Emission Limit During Malfunction. In response to an 

action to enforce the standards set forth in paragraph §§60.42Da, 60.43Da, and 60.44Da, you may 

assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are 

caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed, however, if 

you fail to meet your burden of proving all of the requirements in the affirmative defense. The 

affirmative defense shall not be available for claims for injunctive relief.

(1) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the 

notification requirements in paragraph (b) of this section, and must prove by a preponderance of 

evidence that:

(i) The excess emissions: 

(A) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and 

monitoring equipment, process equipment, or a process to operate in a normal or usual manner, and 

(B) Could not have been prevented through careful planning, proper design or better operation and 

maintenance practices; and

(C) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; 

and
(D) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; 

and

(ii) Repairs were made as expeditiously as possible when the applicable emission limitations were 

being exceeded. Off-shift and overtime labor were used, to the extent practicable to make these 

repairs; and

(iii) The frequency, amount and duration of the excess emissions (including any bypass) were 

minimized to the maximum extent practicable during periods of such emissions; and

(iv) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass 

was unavoidable to prevent loss of life, personal injury, or severe property damage; and

(v) All possible steps were taken to minimize the impact of the excess emissions on ambient air 

quality, the environment and human health; and

(vi) All emissions monitoring and control systems were kept in operation if at all possible, consistent 

with safety and good air pollution control practices; and

(vii) All of the actions in response to the excess emissions were documented by properly signed, 

contemporaneous operating logs; and

(viii) At all times, the facility was operated in a manner consistent with good practices for minimizing 

emissions; and

(ix) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and 

eliminate the primary causes of the malfunction and the excess emissions resulting from the 

malfunction event at issue. The analysis shall also specify, using best monitoring methods and 

engineering judgment, the amount of excess emissions that were the result of the malfunction. 

(2) The owner or operator of the facility experiencing an exceedance of its emission limit(s) during a 

malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as 

possible, but no later than two business days after the initial occurrence of the malfunction, if it wishes 

to avail itself of an affirmative defense to civil penalties for that malfunction. The owner or operator 

seeking to assert an affirmative defense shall also submit a written report to the Administrator within 

45 days of the initial occurrence of the exceedance of the standards in §§60.42Da, 60.43Da, and 

60.44Da to demonstrate, with all necessary supporting documentation, that it has met the requirements 

set forth in paragraph (a) of this section. The owner or operator may seek an extension of this deadline 

for up to 30 additional days by submitting a written request to the Administrator before the expiration 

of the 45 day period. Until a request for an extension has been approved by the Administrator, the 

owner or operator is subject to the requirement to submit such report within 45 days of the initial 

occurrence of the exceedance.

§60.49Da Emission monitoring. 

(a) An owner or operator of an affected facility subject to the opacity standard in §60.42Da(b) shall 

monitor the opacity of emissions discharged from the affected facility to the atmosphere according to 

the 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 subject to an opacity standard, shall install, calibrate, maintain, and operate a COMS, and 

record the output of the system, for measuring the opacity of emissions discharged to the atmosphere. 

If opacity interference due to water droplets exists in the stack (for example, from the use of an FGD 

system), the opacity is monitored upstream of the interference (at the inlet to the FGD system). If 

Comment [CF33]: Clarify COMS not required for

facilities not subject to an opacity standard
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), or 

(iv) of this section may elect to monitor opacity as specified in paragraph (a)(3) of this section. 

(i) The affected facility uses a fabric filter (baghouse) to meet the standards in §60.42Da and a bag leak 

detection system is installed and operated according to the requirements in paragraphs 

§60.48Da(o)(4)(i) through (v); 

(ii) The affected facility burns only gaseous or liquid fuels (excluding residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion technology to 

reduce emissions of SO2 or PM; or

(iii) The affected facility meets all of the conditions specified in paragraphs (a)(2)(iii)(A) through (C) 

of this section; or.

(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. 

(iv) The affected facility uses an ESP and uses an ESP predictive model to monitor the performance of 

the ESP developed in accordance and operated according to the most current requirements in section 

§60.48Da of this part.

(3) The owner or operators of an affected facility that meets the conditions in paragraph (a)(2) of this 

section may, as an alternative to using a COMS, elect to monitor visible emissions using the applicable 

procedures specified in paragraphs (a)(3)(i) through (iv) of this section. The opacity performance test 

requirement in paragraph (a)(3)(i) must be conducted by April 29, 2011, within 45 days after stopping 

use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later. The 

permitting authority may exempt owners or operators of affected facilities burning only natural gas 

from the opacity monitoring requirements.

(i) The owner or operator shall conduct a performance test using Method 9 of appendix A–4 of this 

part and the procedures in §60.11. If during the initial 60 minutes of the observation all the 6-minute 

averages are less than 10 percent and all the individual 15-second observations are less than or equal to 

20 percent, then the observation period may be reduced from 3 hours to 60 minutes. 

(ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this section, the owner or operator shall 

conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in 

paragraph (a)(3)(i) of this section according to the applicable schedule in paragraphs (a)(3)(ii)(A) 

through (a)(3)(ii)(D) of this section, as determined by the most recent Method 9 of appendix A–4 of 

this part performance test results. 

Comment [CF34]: Add ESP model to COMS

exemption options

Comment [CF35]: No longer need since

proposing to exempt natural gas‐fired EGUs from

the opacity standard.
(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 45 calendar days from the date 

that the most recent performance test was conducted. 

(iii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent 

monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in 

paragraphs (a)(3)(iii)(A) and (B) of this section. 

(A) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using Method 

22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible 

emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute 

period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the 

initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the 

occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds 

per 30 minute period) the owner or operator shall either document and adjust the operation of the 

facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to 

or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of 

appendix A–4 of this part performance test using the procedures in paragraph (a)(3)(i) of this section 

within 45 calendar days according to the requirements in §60.50Da(b)(3). 

(B) If no visible emissions are observed for 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 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 and/or 

liquid fuels (excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or 

less areis the only fuels combusted, as follows: 

(1) Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO2control device. 

(2) For a facility that qualifies under the numerical limit provisions of §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 SO2emissions in place of a 

continuous SO2emission monitor at the inlet to the SO2control device as required under paragraph 

(b)(1) of this section. 

(4) If the owner or operator has installed and certified a SO2CEMS according to the requirements of 

§75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the 

ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this 

chapter, that CEMS may be used to meet the requirements of this section, provided that: 

(i) A CO2or O2continuous 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 SO2emission limit in lb/MMBtu under §60.43Da: 

(A) When relative accuracy testing is conducted, SO2concentration data and CO2(or O2) data are 

collected simultaneously; and 

(B) In addition to meeting the applicable SO2and CO2(or O2) relative accuracy specifications in Figure 

2 of appendix B to part 75 of this chapter, the relative accuracy (RA) standard in section 13.2 of 

Performance Specification 2 in appendix B to this part is met when the RA is calculated on a 

lb/MMBtu basis; and 

(iii) The reporting requirements of §60.51Da are met. The SO2and, if required, CO2(or O2) data 

reported to meet the requirements of §60.51Da shall not include substitute data values derived from the 

missing data procedures in subpart D of part 75 of this chapter, nor shall the SO2data 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 NOXemissions discharged to the 

atmosphere; or 

(2) If the owner or operator has installed a NOXemission rate CEMS to meet the requirements of part 

75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that 

CEMS may be used to meet the requirements of this section, except that the owner or operator shall 

also meet the requirements of §60.51Da. Data reported to meet the requirements of §60.51Da shall not 

include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor 

shall the data have been bias adjusted according to the procedures of part 75 of this chapter. 

(d) The owner or operator of an affected facility not complying with an output based limit shall install, 

calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring the O2or 

carbon dioxide (CO2) content of the flue gases at each location where SO2or NOXemissions are 

monitored. For affected facilities subject to a lb/MMBtu SO2emission limit under §60.43Da, if the 

owner or operator has installed and certified a CO2or O2monitoring system according to §75.20(c) of 

Comment [CF36]: Add exemption for low sulfur

oil form the SO2 CEMS requirement.  Do we need to

add a fuel sampling/receipts requirement?

Comment [CF37]: Since adding additional

numerical limits it is simpler to just refer the entire

section.
this chapter and appendix A to part 75 of this chapter and the monitoring system continues to meet the 

applicable quality-assurance provisions of §75.21 of this chapter and appendix B to part 75 of this 

chapter, that CEMS may be used together with the part 75 SO2concentration monitoring system 

described in paragraph (b) of this section, to determine the SO2emission rate in lb/MMBtu. SO2data 

used to meet the requirements of §60.51Da shall not include substitute data values derived from the 

missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias 

adjusted according to the procedures of part 75 of this chapter. 

(e) The CEMS under paragraphs (b), (c), and (d) of this section are operated and data recorded during 

all periods of operation of the affected facility including periods of startup, shutdown, malfunction, and

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 §60.13(h) are expressed in ng/J (lb/MMBtu) heat 

input and used to calculate the average emission rates under §60.48Da. The 1-hour averages are 

calculated using the data points required under §60.13(h)(2). 

(h) When it becomes necessary to supplement CEMS data to meet the minimum data requirements in 

paragraph (f) of this section, the owner or operator shall use the reference methods and procedures as 

specified in this paragraph. Acceptable alternative methods and procedures are given in paragraph (j) 

of this section. 

(1) Method 6 of appendix A of this part shall be used to determine the SO2concentration at the same 

location as the SO2monitor. 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 NOXconcentration at the same 

location as the NOXmonitor. 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 O2or CO2concentration at the same location as 

the O2or CO2monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample 

represents a 1-hour average. 

(4) The procedures in Method 19 of appendix A of this part shall be used to compute each 1-hour 

average concentration in ng/J (lb/MMBtu) heat input. 
(i) The owner or operator shall use methods and procedures in this paragraph to conduct monitoring 

system performance evaluations under §60.13(c) and calibration checks under §60.13(d). Acceptable 

alternative methods and procedures are given in paragraph (j) of this section. 

(1) Methods 3B, 6, and 7 of appendix A of this part shall be used to determine O2, SO2, and 

NOXconcentrations, respectively. 

(2) SO2or 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 NOXshall be determined using one of the following 

procedures: 

(i) Except as provided under paragraph (i)(3)(ii) of this section, NOXspan values shall be determined as 

follows: 

Fossil fuel Span values for NOX

(ppm) 

Gas 500. 

Liquid 500. 

Solid 1,000. 

Combination 500 (x + y) + 1,000z. 

Where: 

x = Fraction of total heat input derived from gaseous fossil fuel, 

y = Fraction of total heat input derived from liquid fossil fuel, and 

z = Fraction of total heat input derived from solid fossil fuel. 

(ii) As an alternative to meeting the requirements of paragraph (i)(3)(i) of this section, the owner or 

operator of an affected facility may elect to use the NOXspan 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 SO2CEMS at 

the inlet to the SO2control device is 125 percent of the maximum estimated hourly potential emissions 

of the fuel fired, and the outlet of the SO2control 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, SO2span values shall be determined according to section 2.1.1 in appendix A 

to part 75 of this chapter. 

(j) The owner or operator may use the following as alternatives to the reference methods and 

procedures specified in this section: 
(1) For Method 6 of appendix A of this part, Method 6A or 6B (whenever Methods 6 and 3 or 3B of 

appendix A of this part data are used) or 6C of appendix A of this part may be used. Each Method 6B 

of appendix A of this part sample obtained over 24 hours represents 24 1-hour averages. If Method 6A 

or 6B of appendix A of this part is used under paragraph (i) of this section, the conditions under 

§60.48Da(d)(1) apply; these conditions do not apply under paragraph (h) of this section. 

(2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may 

be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run 

shall be 1 hour. 

(3) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used 

if the sampling time is 1 hour. 

(4) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used. 

(k) The procedures specified in paragraphs (k)(1) through (3) of this section shall be used to determine 

gross output for sources demonstrating compliance with an the output-based standard under 

§§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 §60.42Da, §60.43Da, §60.44Da, or §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 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 §75.20(c) of this chapter and appendix A to part 75 of this chapter, and continuing to 

meet the applicable quality control and quality assurance requirements of §75.21 of this chapter and 

appendix B to part 75 of this chapter, may be used. Flow rate data reported to meet the requirements of 

§60.51Da shall not include substitute data values derived from the missing data procedures in subpart 

D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of 

part 75 of this chapter. 

(n) Gas-fired and oil-fired units. The owner or operator of an affected unit that qualifies as a gas-fired 

or oil-fired unit, as defined in 40 CFR 72.2, may use, as an alternative to the requirements specified in 

either paragraph (l) or (m) of this section, a fuel flow monitoring system certified and operated 

according to the requirements of appendix D of part 75 of this chapter. 

(o) The owner or operator of a duct burner, as described in §60.41Da, which is subject to the 

NOXstandards of §60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to 

Comment [CF38]: Simplify since adding new

paragraphs

Comment [CF39]: Should we add some ASTM

standards for watt and steam meters?

Comment [CF40]: Simplify
measure NOXemissions; 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) [Reserved]The owner or operator of an affected facility demonstrating compliance with an Hg 

limit in §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 §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 §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 §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 §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.

(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 §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, 

Comment [CF41]: Delete since CAMR vacated
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 §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 §72.2 of this chapter) to monitor Hg concentration, 

according to the procedures described in §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 §75.11(b) of this chapter is acceptable for 

this purpose. Alternatively, the appropriate default moisture value, as specified in §75.11(b) or 

§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 

§60.13(d) or part 75 of this chapter (as applicable); 

(5) Ongoing data quality assurance procedures in accordance with the general requirements of §60.13 

or part 75 of this chapter (as applicable); and 

(6) Ongoing recordkeeping and reporting procedures in accordance with the requirements of this 

subpart. 

(t) The owner or operator of an affected facility demonstrating compliance with the output-based 

emissions limitation under §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 

§60.42Da (a)(1) or §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. 

(i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in 

§60.58b(i)(3) of subpart Eb of this part. 

Comment [CF42]: Could paragraph (s) also be

reserved?
(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, validnon-out-of-control 1-hour CO emissions averages must be obtained for at 

least 90 percent of the operating hours on a 30-day rolling average basis. The 1-hour averages are 

calculated using the data points required in §60.13(h)(2). 

(iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(2) You must calculate the 1-hour average CO emissions levels for each boiler operating day by 

multiplying the average hourly CO output concentration measured by the CO CEMS times the 

corresponding average hourly flue gas flow rate and divided by the corresponding average hourly 

useful energy output from the affected facility. The 24-hour average CO emission level is determined 

by calculating the arithmetic average of the hourly CO emission levels computed for each boiler 

operating day. 

(3) You must evaluate the preceding 24-hour average CO emission level each boiler operating day 

excluding periods of affected facility startup, shutdown, or malfunction. If the 24-hour average CO 

emission level is greater than 1.4 lb/MWh, you must initiate investigation of the relevant equipment 

and control systems within 24 hours of the first discovery of the high emission incident and, take the 

appropriate corrective action as soon as practicable to adjust control settings or repair equipment to 

reduce the 24-hour average CO emission level to 1.4 lb/MWh or less. 

(4) You must record the CO measurements and calculations performed according to paragraph (u)(3) 

of this section and any corrective actions taken. The record of corrective action taken must include the 

date and time during which the 24-hour average CO emission level was greater than 1.4 lb/MWh, and 

the date, time, and description of the corrective action. 

(v) The owner or operator of an affected facility using a CEMS measuring PM emissions to meet 

requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in 

paragraphs (v)(1) through (v)(4) of this section. 

(1) The owner or operator shall conduct a performance evaluation of the CEMS according to the 

applicable requirements of §60.13, Performance Specification 11 in appendix B of this part, and 

procedure 2 in appendix F of this part. 

(2) During each PM correlation testing run of the CEMS required by Performance Specification 11 in 

appendix B of this part, PM and O2(or CO2) data shall be collected concurrently (or within a 30- to 60-

minute period) by both the CEMS and performance tests conducted using the following test methods. 

(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part 

shall be used; and 

(ii) For O2(or CO2), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. 

(3) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance 

with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and 

Response Correlation Audits must be performed every 3 years. 

(4) As of January 1, 2012 and within 60 days after the date of completing each performance test, as 

defined in §63.2, conducted to demonstrate compliance with this subpart, you must submit relative 

accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, 

except opacity data, electronically to EPA’s Central Data Exchange (CDX) by using the Electronic 
Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or other compatible 

electronic spreadsheet. Only data collected using test methods compatible with ERT are subject to this 

requirement to be submitted electronically into EPA’s WebFIRE database.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 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 O2CEMS 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 O2CEMS required under paragraphs (b) through (d) of this section shall be installed, 

certified, and operated in accordance with the applicable procedures in Performance Specification 2 or 

3 in appendix B to this part or according to the procedures in appendices A and B to part 75 of this 

chapter. Daily calibration drift assessments and quarterly accuracy determinations shall be done in 

accordance with Procedure 1 in appendix F to this part, and a data assessment report (DAR), prepared 

according to section 7 of Procedure 1 in appendix F to this part, shall be submitted with each 

compliance report required under §60.51Da. 

(2) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or 

operator may elect to implement the following alternative data accuracy assessment procedures. For all 

required CO2and O2CEMS and for SO2and NOXCEMS 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 SO2and NOXspan 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 CO2and O2CEMS and for SO2and NOXCEMS 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 

SO2and NOXspan values less than or equal to 30 ppm; 

Comment [CF43]: Updated language for

electronic reporting
(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 O2CEMS and for NOXCEMS, 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 SO2emission level during the RATA), and for 

NOXwhen the average NOXemission 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. 

§60.50Da Compliance determination procedures and methods. 

(a) In conducting the performance tests required in §60.8, the owner or operator shall use as reference 

methods and procedures the methods in appendix A of this part or the methods and procedures as 

specified in this section, except as provided in §60.8(b). Section 60.8(f) does not apply to this section 

for SO2and 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 §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 filterable 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 160±14 °C (320±25 °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 

O2concentration. The O2sample 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 O2traverse points may 

be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O2traverse 

points. If the grab sampling procedure is used, the O2concentration for the run shall be the arithmetic 

mean of the sample O2concentrations at all traverse points. 

(3) Method 9 of appendix A of this part and the procedures in §60.11 shall be used to determine 

opacity. 
(4) Total particular matter concentration consists of the sum of the filterable and condensable 

fractions. The condensable fraction shall be measured using Method 202 of appendix M of part 51,

and the filterable fraction shall be measured using Method 5 of appendix A of this part.

(c) The owner or operator shall determine compliance with the SO2standards in §60.43Da as follows: 

(1) The percent of potential SO2emissions (%Ps) to the atmosphere shall be computed using the 

following equation: 

Where: 

%Ps = Percent of potential SO2emissions, percent; 

%Rf = Percent reduction from fuel pretreatment, percent; and 

%Rg = Percent reduction by SO2control 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 

SO2reduction (%Rg) of any SO2control system. Alternatively, a combination of an “as fired” fuel 

monitor and emission rates measured after the control system, following the procedures in Method 19 

of appendix A of this part, may be used if the percent reduction is calculated using the average 

emission rate from the SO2control device and the average SO2input rate from the “as fired” fuel 

analysis for 30 successive boiler operating days. 

(4) The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the 

emission rate. 

(5) The CEMS in §60.49Da(b) and (d) shall be used to determine the concentrations of SO2and CO2or 

O2. 

(d) The owner or operator shall determine compliance with the NOXstandard in §60.44Da as follows: 

(1) The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the 

emission rate of NOX. 

(2) The continuous monitoring system in §60.49Da(c) and (d) shall be used to determine the 

concentrations of NOXand CO2or O2. 

(e) The owner or operator may use the following as alternatives to the reference methods and 

procedures specified in this section: 

(1) For Method 5 or 5B of appendix A–3 of this part, Method 17 of appendix A–6 of this part may be 

used at facilities with or without wet FGD systems if the stack temperature at the sampling location 

does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of 

Method 5B of appendix A–3 of this part may be used in Method 17 of appendix A–6 of this part only 

if it is used after wet FGD systems. Method 17 of appendix A–6 of this part shall not be used after wet 

FGD systems if the effluent is saturated or laden with water droplets. 

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(2) The Fcfactor (CO2) procedures in Method 19 of appendix A of this part may be used to compute the 

emission rate of PM under the stipulations of §60.46(d)(1). The CO2shall be determined in the same 

manner as the O2concentration. 

(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 NOXusing the procedures of Method 19 of appendix A–7 of this part. The 

SO2and NOXemission 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 §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.

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 §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 §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 §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, 

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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:

Where:

Eh= Hg mass emissions for the hour, (lb);

K = Units conversion constant, 6.24 × 10−11 lb-scm/μgm-scf;

Ch= Hourly Hgconcentration, wet basis, (μgm/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:

Where:

Eh= Hg mass emissions for the hour, (lb);

K = Units conversion constant, 6.24 × 10−11lb-scm/μgm-scf;

Ch= Hourly Hg concentration, dry basis, (μgm/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):

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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.

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.

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 §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, Chin 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 

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use either elemental mercury or mercuric chloride (Hg° HgCl2) standards. The four quarterly accuracy 

determinations shall consist of one RATA and three measurement error (ME) tests using 

HgCl2standards, as described in section 8.3 of Performance Specification 12–A in appendix B to this 

part (note: Hg° 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.

§60.51Da Reporting requirements. 

(a) For SO2, NOX, and 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 SO2and NOXthe following information is reported to the Administrator for each 24-hour 

period. 

(1) Calendar date. 

(2) The average SO2and NOXemission rates (ng/J, lb/MMBtu, or lb/MWh) for each 30 successive 

boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance 

with the emission standards; and, description of corrective actions taken. 

(3) For owners or operators of affected facilities complying with the percent reduction requirement, 

percent reduction of the potential combustion concentration of SO2for 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 (NOXonly), emergency conditions (SO2only), 

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 §60.49Da is not obtained for any 30 

successive boiler operating days, the following information obtained under the requirements of 

§60.48Da(h) is reported to the Administrator for that 30-day period: 
(1) The number of hourly averages available for outlet emission rates (no) and inlet emission rates (ni) 

as applicable. 

(2) The standard deviation of hourly averages for outlet emission rates (so) and inlet emission rates (si) 

as applicable. 

(3) The lower confidence limit for the mean outlet emission rate (Eo*) and the upper confidence limit 

for the mean inlet emission rate (Ei*) as applicable. 

(4) The applicable potential combustion concentration. 

(5) The ratio of the upper confidence limit for the mean outlet emission rate (Eo*) and the allowable 

emission rate (Estd) as applicable. 

(d) If any standards under §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 §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 SO2emission standard under §60.43Da is claimed, the owner 

or operator of the affected facility shall submit a signed statement: 

(1) Indicating what percentage cleaning credit was taken for the calendar quarter, and whether the 

credit was determined in accordance with the provisions of §60.50Da and Method 19 of appendix A of 

this part; and 

(2) Listing the quantity, heat content, and date each pretreated fuel shipment was received during the 

previous quarter; the name and location of the fuel pretreatment facility; and the total quantity and total 

heat content of all fuels received at the affected facility during the previous quarter. 

(f) For any periods for which opacity, SO2or NOXemissions data are not available, the owner or 

operator of the affected facility shall submit a signed statement indicating if any changes were made in 

operation of the emission control system during the period of data unavailability. Operations of the 

control system and affected facility during periods of data unavailability are to be compared with 

operation of the control system and affected facility before and following the period of data 

unavailability. 

(g) [Reserved]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 §60.7, periods of excess emissions are defined as all 

6-minute periods during which the average opacity exceeds the applicable opacity standards under 

§60.42Da(b). Opacity levels in excess of the applicable opacity standard and the date of such excesses 

are to be submitted to the Administrator each calendar quarter. 

(j) The owner or operator of an affected facility shall submit the written reports required under this 

section and subpart A to the Administrator semiannually for each six-month period. All semiannual 

reports shall be postmarked by the 30th day following the end of each six-month period. 

(k) The owner or operator of an affected facility may submit electronic quarterly reports for SO2and/or 

NOXand/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. 

§60.52Da Recordkeeping requirements. 

(a) [Reserved]The owner or operator of an affected facility subject to the emissions limitations in 

§60.45Da shall provide notifications in accordance with §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 §60.7(f).
(b) The owner or operator of an affected facility subject to the opacity limits in §60.42Da(b) that elects 

to monitor emissions according to the requirements in §60.49Da(a)(3) shall maintain records according 

to the requirements specified in paragraphs (b)(1) through (3) of this section, as applicable to the 

visible emissions monitoring method used. 

(1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (b)(1)(i) through (iii) 

of this section. 

(i) Dates and time intervals of all opacity observation periods; 

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible 

emission observer participating in the performance test; and 

(iii) Copies of all visible emission observer opacity field data sheets; 

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (b)(2)(i) through (iv) 

of this section. 

(i) Dates and time intervals of all visible emissions observation periods; 

(ii) Name and affiliation for each visible emission observer participating in the performance test; 

(iii) Copies of all visible emission observer opacity field data sheets; and 

(iv) Documentation of any adjustments made and the time the adjustments were completed to the 

affected facility operation by the owner or operator to demonstrate compliance with the applicable 

monitoring requirements. 

(3) For each digital opacity compliance system, the owner or operator shall maintain records and 

submit reports according to the requirements specified in the site-specific monitoring plan approved by 

the Administrator. 
Subpart Db—Standards of Performance for Industrial-Commercial-Institutional Steam 

Generating Units 

§60.40b Applicability and delegation of authority. 

(a) The affected facility to which this subpart applies is each steam generating unit that 

commences construction, modification, or reconstruction after June 19, 1984, and that has a heat 

input capacity from fuels combusted in the steam generating unit of greater than 29 megawatts 

(MW) (100 million British thermal units per hour (MMBtu/hr)). 

(b) Any affected facility meeting the applicability requirements under paragraph (a) of this 

section and commencing construction, modification, or reconstruction after June 19, 1984, but on 

or before June 19, 1986, is subject to the following standards: 

(1) Coal-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 

250 MMBtu/hr), inclusive, are subject to the particulate matter (PM) and nitrogen oxides (NOX) 

standards under this subpart. 

(2) Coal-fired affected facilities having a heat input capacity greater than 73 MW (250 

MMBtu/hr) and meeting the applicability requirements under subpart D (Standards of 

performance for fossil-fuel-fired steam generators; §60.40) are subject to the PM and 

NOXstandards under this subpart and to the sulfur dioxide (SO2) standards under subpart D 

(§60.43). 

(3) Oil-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 

MMBtu/hr), inclusive, are subject to the NOXstandards 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 fossilfuel-fired steam generators; §60.40) are also subject to the NOXstandards under this subpart and 

the PM and SO2standards under subpart D (§60.42 and §60.43). 

(c) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja 

(Standards of performance for petroleum refineries; §60.104) are subject to the PM and NOX

standards under this subpart and the SO2 standards under subpart J or subpart Ja (§60.104). 

(d) Affected facilities that also meet the applicability requirements under subpart E (Standards of 

performance for incinerators; §60.50) are subject to the NOXand PM standards under this 

subpart. 

(e) Steam generating units meeting the applicability requirements under subpart Da (Standards of 

performance for electric utility steam generating units; §60.40Da) are not subject to this subpart. 

(f) Any change to an existing steam generating unit for the sole purpose of combusting gases 

containing total reduced sulfur (TRS) as defined under §60.281 is not considered a modification 

under §60.14 and the steam generating unit is not subject to this subpart. 

(g) In delegating implementation and enforcement authority to a State under section 111(c) of the 

Clean Air Act, the following authorities shall be retained by the Administrator and not 

transferred to a State. 

Comment [CF1]: Add subpart Ja exemption.
(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, or subpart CCCC of this part is not covered bysubject to this 

subpart. 

(i) Affected facilities (i.e. Hheat recovery steam generators) that are associated with combined 

cycle gasstationary combustion turbines and that meet the applicability requirements of subpart 

KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other 

affected facilities (i.e. heat recovery steam generators with duct burners) that are capable of 

combusting more than 29 MW (100 MMBtu/hr) heat input of fossil fuel. If the affected facility 

(i.e. heat recovery steam generator) is subject to this subpart, only emissions resulting from 

combustion of fuels in the steam generating unit are subject to this subpart. (The gasstationary 

combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part.) 

(j) Any affected facility meeting the applicability requirements under paragraph (a) of this 

section and commencing construction, modification, or reconstruction after June 19, 1986 is not 

subject to subpart D (Standards of Performance for Fossil-Fuel-Fired Steam Generators, §60.40). 

(k) Any affected facility that meets the applicability requirements and is subject to an EPA 

approved State or Federal section 111(d)/129 plan implementing subpart Cb or subpart BBBB of 

this part is not covered by this subpart.

(l) Affected facilities that also meet the applicability requirements under subpart BB (Standards 

of Performance for Kraft Pulp Mills) are subject to the SO2 and NOX standards under this subpart 

and the PM standards under subpart BB.

§60.41b Definitions. 

As used in this subpart, all terms not defined herein shall have the meaning given them in the 

Clean Air Act and in subpart A of this part. 

Annual capacity factor means the ratio between the actual heat input to a steam generating unit 

from the fuels listed in §60.42b(a), §60.43b(a), or §60.44b(a), as applicable, during a calendar 

year and the potential heat input to the steam generating unit had it been operated for 8,760 hours 

during a calendar year at the maximum steady state design heat input capacity. In the case of 

steam generating units that are rented or leased, the actual heat input shall be determined based 

on the combined heat input from all operations of the affected facility in a calendar year. 

Byproduct/waste means any liquid or gaseous substance produced at chemical manufacturing 

plants, petroleum refineries, or pulp and paper mills (except natural gas, distillate oil, or residual 

oil) and combusted in a steam generating unit for heat recovery or for disposal. Gaseous 

substances with carbon dioxide (CO2) levels greater than 50 percent or carbon monoxide levels 

greater than 10 percent are not byproduct/waste for the purpose of this subpart. 

Comment [CF2]: Exempt owner/operators of

CISWI facilities from subpart Db

Comment [CF3]: Exempting black liquor

recovery boilers from the PM limit.  The recent

round of amendments brought them under the PM

limit since they have an ESP to control PM and burn

low sulfur oil.  The subpart BB limit is similar to the

pre 2005 standard.
Chemical manufacturing plants mean industrial plants that are classified by the Department of 

Commerce under Standard Industrial Classification (SIC) Code 28. 

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the 

American Society of Testing and Materials in ASTM D388 (incorporated by reference, see 

§60.17), coal refuse, and petroleum coke. Coal-derived synthetic fuels, including but not limited 

to solvent refined coal, gasified coal not meeting the definition of natural gas, coal-oil mixtures, 

coke oven gas, and coal-water mixtures, are also included in this definition for the purposes of 

this subpart. 

Coal refuse means any byproduct of coal mining or coal cleaning operations with an ash content 

greater than 50 percent, by weight, and a heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a 

dry basis. 

Cogeneration , also known as combined heat and power, means a facility that simultaneously 

produces both electric (or mechanical) and useful thermal energy from the same primary energy 

source. 

Coke oven gas means the volatile constituents generated in the gaseous exhaust during the 

carbonization of bituminous coal to form coke. 

Combined cycle system means a system in which a separate source, such as a gas turbine, internal 

combustion engine, kiln, etc., provides exhaust gas to a steam generating unit. 

Conventional technology means wet flue gas desulfurization (FGD) technology, dry FGD 

technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization 

technology. 

Distillate oil means fuel oils that contain 0.05 weight percent nitrogen or less and comply with 

the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing 

and Materials in ASTM D396 (incorporated by reference, see §60.17), 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 §60.17), kerosene, as defined by the American Society of Testing 

and Materials in ASTM D3699 (incorporated by reference, see §60.17), biodiesel as defined by 

the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see 

§60.17), or biodiesel blends as defined by the American Society of Testing and Materials in 

ASTM D7467 (incorporated by reference, see §60.17). 

Dry flue gas desulfurization technology means a SO2control 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 

Comment [CF4]: Expand definitions to include

other similar fuels.  Need to amend 60.17 as well.
the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a steam 

generating unit. 

Emerging technology means any SO2control system that is not defined as a conventional 

technology under this section, and for which the owner or operator of the facility has applied to 

the Administrator and received approval to operate as an emerging technology under 

§60.49b(a)(4). 

Federally enforceable means all limitations and conditions that are enforceable by the 

Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any 

applicable State Implementation Plan, and any permit requirements established under 40 CFR 

52.21 or under 40 CFR 51.18 and 51.24. 

Fluidized bed combustion technology means combustion of fuel in a bed or series of beds 

(including but not limited to bubbling bed units and circulating bed units) of limestone aggregate 

(or other sorbent materials) in which these materials are forced upward by the flow of 

combustion air and the gaseous products of combustion. 

Fuel pretreatment means a process that removes a portion of the sulfur in a fuel before 

combustion of the fuel in a steam generating unit. 

Full capacity means operation of the steam generating unit at 90 percent or more of the 

maximum steady-state design heat input capacity. 

Gaseous fuel means any fuel that is a gas at ISO conditions. This includes, but is not limited to, 

natural gas and gasified coal (including coke oven gas). 

Gross output means the gross useful work performed by the steam generated. For units 

generating only electricity, the gross useful work performed is the gross electrical output from 

the turbine/generator set. For cogeneration units, the gross useful work performed is the gross 

electrical or mechanical output plus 75 percent of the useful thermal output measured relative to 

ISO conditions that is not used to generate additional electrical or mechanical output or to 

enhance the performance of the unit ( i.e. , steam delivered to an industrial process). 

Heat input means heat derived from combustion of fuel in a steam generating unit and does not 

include the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases 

from other sources, such as gas turbines, internal combustion engines, kilns, etc. 

Heat release rate means the steam generating unit design heat input capacity (in MW or Btu/hr) 

divided by the furnace volume (in cubic meters or cubic feet); the furnace volume is that volume 

bounded by the front furnace wall where the burner is located, the furnace side waterwall, and 

extending to the level just below or in front of the first row of convection pass tubes. 

Heat transfer medium means any material that is used to transfer heat from one point to another 

point. 

High heat release rate means a heat release rate greater than 730,000 J/sec-m3

 (70,000 Btu/hr-ft3

). 
ISO Conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a 

pressure of 101.3 kilopascals. 

Lignite means a type of coal classified as lignite A or lignite B by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, see §60.17). 

Low heat release rate means a heat release rate of 730,000 J/sec-m3

 (70,000 Btu/hr-ft3 ) or less. 

Mass-feed stoker steam generating unit means a steam generating unit where solid fuel is 

introduced directly into a retort or is fed directly onto a grate where it is combusted. 

Maximum heat input capacity means the ability of a steam generating unit to combust a stated 

maximum amount of fuel on a steady state basis, as determined by the physical design and 

characteristics of the steam generating unit. 

Municipal-type solid waste means refuse, more than 50 percent of which is waste consisting of a 

mixture of paper, wood, yard wastes, food wastes, plastics, leather, rubber, and other 

combustible materials, and noncombustible materials such as glass and rock. 

Natural gas means: 

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic 

formations beneath the earth's surface, of which the principal constituent is methane; or 

(2) Liquefied petroleum gas, as defined by the American Society for Testing and Materials in 

ASTM D1835 (incorporated by reference, see §60.17); or 

(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, 

natural gas must either be composed of at least 70 percent methane by volume or have a gross 

calorific value between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 

Btu per dry standard cubic foot). 

Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the 

Commonwealth of Puerto Rico, or the Northern Mariana Islands. 

Oil means crude oil or petroleum or a liquid fuel derived from crude oil or petroleum, including 

distillate and residual oil. 

Petroleum refinery means industrial plants as classified by the Department of Commerce under 

Standard Industrial Classification (SIC) Code 29. 

Potential sulfur dioxide emission rate means the theoretical SO2emissions (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 SO2emissions (ng/J or 

lb/MMBtu heat input) that would result from combusting fuel in a cleaned state without using 

any post combustion emission control systems. 

Process heater means a device that is primarily used to heat a material to initiate or promote a 

chemical reaction in which the material participates as a reactant or catalyst. 
Pulp and paper mills means industrial plants that are classified by the Department of Commerce 

under North American Industry Classification System (NAICS) Code 322 or Standard Industrial 

Classification (SIC) Code 26. 

Pulverized coal-fired steam generating unit means a steam generating unit in which pulverized 

coal is introduced into an air stream that carries the coal to the combustion chamber of the steam 

generating unit where it is fired in suspension. This includes both conventional pulverized coalfired and micropulverized coal-fired steam generating units. 

Residual oil means crude oil, fuel oil numbers 1 and 2 that have a nitrogen content greater than 

0.05 weight percent, and all fuel oil numbers 4, 5 and 6, as defined by the American Society of 

Testing and Materials in ASTM D396 (incorporated by reference, see §60.17). 

Spreader stoker steam generating unit means a steam generating unit in which solid fuel is 

introduced to the combustion zone by a mechanism that throws the fuel onto a grate from above. 

Combustion takes place both in suspension and on the grate. 

Steam generating unit means a device that combusts any fuel or byproduct/waste and produces 

steam or heats water or heats any heat transfer medium. This term includes any municipal-type 

solid waste incinerator with a heat recovery steam generating unit or any steam generating unit 

that combusts fuel and is part of a cogeneration system or a combined cycle system. This term 

does not include process heaters as they are defined in this subpart. 

Steam generating unit operating day means a 24-hour period between 12:00 midnight and the 

following midnight during which any fuel is combusted at any time in the steam generating unit. 

It is not necessary for fuel to be combusted continuously for the entire 24-hour period. 

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 SO2emission control, has a SO2emission 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 SO2emission control, has a 

SO2emission 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 SO2emission control, has a SO2emission rate equal to or less than 215 

ng/J (0.50 lb/MMBtu) heat input. 

Wet flue gas desulfurization technology means a SO2control 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. 

Formatted: Font: Italic

Comment [CF5]: Added return to separate

definitions

Formatted: Font: Italic
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. 

§60.42b Standard for sulfur dioxide (SO2). 

(a) Except as provided in paragraphs (b), (c), (d), or (j) of this section, on and after the date on 

which the performance test is completed or required to be completed under §60.8, whichever 

comes first, no owner or operator of an affected facility that commenced construction, 

reconstruction, or modification on or before February 28, 2005, that combusts coal or oil shall 

cause to be discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 

lb/MMBtu) or 10 percent (0.10) of the potential SO2emission rate (90 percent reduction) and the 

emission limit determined according to the following formula: 

Where: 

Es= SO2emission limit, in ng/J or lb/MMBtu heat input; 

Ka= 520 ng/J (or 1.2 lb/MMBtu); 

Kb= 340 ng/J (or 0.80 lb/MMBtu); 

Ha= Heat input from the combustion of coal, in J (MMBtu); and 

Hb= Heat input from the combustion of oil, in J (MMBtu). 

For facilities complying with the percent reduction standard, only the heat input supplied to the 

affected facility from the combustion of coal and oil is counted in this paragraph. No credit is 

provided for the heat input to the affected facility from the combustion of natural gas, wood, 

municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, 

such as gas turbines, internal combustion engines, kilns, etc. 

(b) On and after the date on which the performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator of an affected facility that 

commenced construction, reconstruction, or modification on or before February 28, 2005, that 

combusts coal refuse alone in a fluidized bed combustion steam generating unit shall cause to be 

discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) 

or 20 percent (0.20) of the potential SO2emission 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. 

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(c) On and after the date on which the performance test is completed or is required to be 

completed under §60.8, whichever comes first, no owner or operator of an affected facility that 

combusts coal or oil, either alone or in combination with any other fuel, and that uses an 

emerging technology for the control of SO2emissions, shall cause to be discharged into the 

atmosphere any gases that contain SO2in excess of 50 percent of the potential SO2emission rate 

(50 percent reduction) and that contain SO2in excess of the emission limit determined according 

to the following formula: 

Where: 

Es= SO2 emission limit, in ng/J or lb/MM Btu heat input; 

Kc= 260 ng/J (or 0.60 lb/MMBtu); 

Kd= 170 ng/J (or 0.40 lb/MMBtu); 

Hc= Heat input from the combustion of coal, in J (MMBtu); and 

Hd= Heat input from the combustion of oil, in J (MMBtu). 

For facilities complying with the percent reduction standard, only the heat input supplied to the 

affected facility from the combustion of coal and oil is counted in this paragraph. No credit is 

provided for the heat input to the affected facility from the combustion of natural gas, wood, 

municipal-type solid waste, or other fuels, or from the heat input derived from exhaust gases 

from other sources, such as gas turbines, internal combustion engines, kilns, etc. 

(d) On and after the date on which the performance test is completed or required to be completed 

under §60.8, whichever comes first, no owner or operator of an affected facility that commenced 

construction, reconstruction, or modification on or before February 28, 2005 and listed in 

paragraphs (d)(1), (2), (3), or (4) of this section shall cause to be discharged into the atmosphere 

any gases that contain SO2in 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 

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(3) Affected facilities combusting coal or oil, alone or in combination with any fuel, in a duct 

burner as part of a combined cycle system where 30 percent (0.30) or less of the heat entering the 

steam generating unit is from combustion of coal and oil in the duct burner and 70 percent (0.70) 

or more of the heat entering the steam generating unit is from the exhaust gases entering the duct 

burner; or 

(4) The affected facility burns coke oven gas alone or in combination with natural gas or very 

low sulfur distillate oil. 

(e) Except as provided in paragraph (f) of this section, compliance with the emission limits, fuel 

oil sulfur limits, and/or percent reduction requirements under this section are determined on a 30-

day rolling average basis. 

(f) Except as provided in paragraph (j)(2) of this section, compliance with the emission limits or 

fuel oil sulfur limits under this section is determined on a 24-hour average basis for affected 

facilities that (1) have a federally enforceable permit limiting the annual capacity factor for oil to 

10 percent or less, (2) combust only very low sulfur oil, and (3) do not combust any other fuel. 

(g) Except as provided in paragraph (i) of this section and §60.45b(a), the SO2emission limits 

and percent reduction requirements under this section apply at all times, including periods of 

startup, shutdown, and malfunction. 

(h) Reductions in the potential SO2emission 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 SO2emissions and 

(2) Emissions from the pretreated fuel (without combustion or post-combustion SO2control) 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 SO2control system is not being operated because of 

malfunction or maintenance of the SO2control system. 

(j) Percent reduction requirements are not applicable to affected facilities combusting only very 

low sulfur oil. The owner or operator of an affected facility combusting very low sulfur oil shall 

demonstrate that the oil meets the definition of very low sulfur oil by: (1) Following the 

performance testing procedures as described in §60.45b(c) or §60.45b(d), and following the 

monitoring procedures as described in §60.47b(a) or §60.47b(b) to determine SO2emission rate 

or fuel oil sulfur content; or (2) maintaining fuel records as described in §60.49b(r). 

(k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) of this section, on and after the 

date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, no owner or operator of an affected facility that commences 

construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, 

natural gas, a mixture of these fuels, or a mixture of these fuels with any other fuels shall cause 

to be discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 

lb/MMBtu) heat input or 8 percent (0.08) of the potential SO2emission 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 SO2emission rate of 140 ng/J (0.32 lb/MMBtu) 

heat input or less are exempt from the SO2emissions 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 SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the 

affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input if the affected facility 

combusts oil or natural gas. 

(4) As an alternative to meeting the requirements under paragraph (k)(1) of this section, modified 

facilities that combust coal or a mixture of coal with other fuels shall not cause to be discharged 

into the atmosphere any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input 

or 10 percent (0.10) of the potential SO2 emission rate (90 percent reduction) and 520 ng/J (1.2 

lb/MMBtu) heat input. 

§60.43b Standard for particulate matter (PM). 

(a) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever comes first, no owner or operator of an affected facility that 

commenced construction, reconstruction, or modification on or before February 28, 2005 that 

combusts coal or combusts mixtures of coal with other fuels, shall cause to be discharged into 

the atmosphere from that affected facility any gases that contain PM in excess of the following 

emission limits: 

(1) 22 ng/J (0.051 lb/MMBtu) heat input, (i) If the affected facility combusts only coal, or 

(ii) If the affected facility combusts coal and other fuels and has an annual capacity factor for the 

other fuels of 10 percent (0.10) or less. 

(2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal and other fuels and 

has an annual capacity factor for the other fuels greater than 10 percent (0.10) and is subject to a 

federally enforceable requirement limiting operation of the affected facility to an annual capacity 

factor greater than 10 percent (0.10) for fuels other than coal. 

(3) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts coal or coal and other 

fuels and 

(i) Has an annual capacity factor for coal or coal and other fuels of 30 percent (0.30) or less, 

(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less, 

(iii) Has a federally enforceable requirement limiting operation of the affected facility to an 

annual capacity factor of 30 percent (0.30) or less for coal or coal and other solid fuels, and 
(iv) Construction of the affected facility commenced after June 19, 1984, and before November 

25, 1986. 

(4) An affected facility burning coke oven gas alone or in combination with other fuels not 

subject to a PM standard under §60.43b and not using a post-combustion technology (except a 

wet scrubber) for reducing PM or SO2emissions is not subject to the PM limits under §60.43b(a). 

(b) On and after the date on which the performance test is completed or required to be completed 

under §60.8, whichever comes first, no owner or operator of an affected facility that commenced 

construction, reconstruction, or modification on or before February 28, 2005, and that combusts 

oil (or mixtures of oil with other fuels) and uses a conventional or emerging technology to reduce 

SO2emissions shall cause to be discharged into the atmosphere from that affected facility any 

gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input. 

(c) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever comes first, no owner or operator of an affected facility that 

commenced construction, reconstruction, or modification on or before February 28, 2005, and 

that combusts wood, or wood with other fuels, except coal, shall cause to be discharged from that 

affected facility any gases that contain PM in excess of the following emission limits: 

(1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor 

greater than 30 percent (0.30) for wood. 

(2) 86 ng/J (0.20 lb/MMBtu) heat input if (i) The affected facility has an annual capacity factor 

of 30 percent (0.30) or less for wood; 

(ii) Is subject to a federally enforceable requirement limiting operation of the affected facility to 

an annual capacity factor of 30 percent (0.30) or less for wood; and 

(iii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less. 

(d) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility 

that combusts municipal-type solid waste or mixtures of municipal-type solid waste with other 

fuels, shall cause to be discharged into the atmosphere from that affected facility any gases that 

contain PM in excess of the following emission limits: 

(1) 43 ng/J (0.10 lb/MMBtu) heat input; 

(i) If the affected facility combusts only municipal-type solid waste; or 

(ii) If the affected facility combusts municipal-type solid waste and other fuels and has an annual 

capacity factor for the other fuels of 10 percent (0.10) or less. 

(2) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts municipal-type solid 

waste or municipal-type solid waste and other fuels; and 

(i) Has an annual capacity factor for municipal-type solid waste and other fuels of 30 percent 

(0.30) or less; 
(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less; 

(iii) Has a federally enforceable requirement limiting operation of the affected facility to an 

annual capacity factor of 30 percent (0.30) or less for municipal-type solid waste, or municipaltype solid waste and other fuels; and 

(iv) Construction of the affected facility commenced after June 19, 1984, but on or before 

November 25, 1986. 

(e) For the purposes of this section, the annual capacity factor is determined by dividing the 

actual heat input to the steam generating unit during the calendar year from the combustion of 

coal, wood, or municipal-type solid waste, and other fuels, as applicable, by the potential heat 

input to the steam generating unit if the steam generating unit had been operated for 8,760 hours 

at the maximum heat input capacity. 

(f) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility 

that 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 §60.8, whichever date comes first, no owner or operator of an affected facility 

that commenced construction, reconstruction, or modification after February 28, 2005, and that 

combusts coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other 

fuels shall cause to be discharged into the atmosphere from that affected facility any gases that 

contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, 

(2) As an alternative to meeting the requirements of paragraph (h)(1) of this section, the owner or 

operator of an affected facility for which modification commenced after February 28, 2005, may 

elect to meet the requirements of this paragraph. On and after the date on which the initial 

performance test is completed or required to be completed under §60.8, no owner or operator of 

an affected facility that commences modification after February 28, 2005 shall cause to be 

discharged into the atmosphere from that affected facility any gases that contain PM in excess of 

both: 

(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a 

mixture of these fuels, or a mixture of these fuels with any other fuels; and 

(ii) 0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, 

oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels. 

Comment [CF6]: Take comment on exempting

owners/operators burning low sulfur distillate oil

alone or in combination with other fuels not subject

to an opacity standard from the opacity standard.
(3) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility 

that commences modification after February 28, 2005, and that combusts over 30 percent wood 

(by heat input) on an annual basis and has a maximum heat input capacity of 73 MW (250 

MMBtu/h) or less shall cause to be discharged into the atmosphere from that affected facility any 

gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input. 

(4) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility 

that commences modification after February 28, 2005, and that combusts over 30 percent wood 

(by heat input) on an annual basis and has a maximum heat input capacity greater than 73 MW 

(250 MMBtu/h) shall cause to be discharged into the atmosphere from that affected facility any 

gases that contain PM in excess of 37 ng/J (0.085 lb/MMBtu) heat input. 

(5) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, an owner or operator of an affected facility 

not located in a noncontinental area that commences construction, reconstruction, or 

modification after February 28, 2005, and that combusts only oil that contains no more than 0.30 

weight percent sulfur, coke oven gas, a mixture of these fuels, or either fuel (or a mixture of 

these fuels) in combination with other fuels not subject to a PM standard in §60.43b and not 

using a post-combustion technology (except a wet scrubber) to reduce SO2or PM emissions is 

not subject to the PM limits in (h)(1) of this section. 

(6) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, an owner or operator of an affected facility 

located in a noncontinental area that commences construction, reconstruction, or modification 

after February 28, 2005, and that combusts only oil that contains no more than 0.5 weight 

percent sulfur, coke oven gas, a mixture of these fuels, or either fuel (or a mixture of these fuels) 

in combination with other fuels not subject to a PM standard in §60.43b and not using a postcombustion technology (except a wet scrubber) to reduce SO2or PM emissions is not subject to 

the PM limits in (h)(1) of this section. 

§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 §60.8, whichever 

date comes first, no owner or operator of an affected facility that is subject to the provisions of 

this section and that combusts only coal, oil, or natural gas shall cause to be discharged into the 

atmosphere from that affected facility any gases that contain NOX(expressed as NO2) in excess 

of the following emission limits: 

Fuel/steam generating unit type 

Nitrogen oxide emission limits 

(expressed as NO2) heat input 

ng/J lb/MMBtTu 

(1) Natural gas and distillate oil, except (4): 

Comment [CF7]: Should we add an exemption

for periods of continuous duty ignition (standby)

exemption that the EPA regional Authority could

approve?
(i) Low heat release rate 43 0.10 

(ii) High heat release rate 86 0.20 

(2) Residual oil: 

(i) Low heat release rate 130 0.30 

(ii) High heat release rate 170 0.40 

(3) Coal: 

(i) Mass-feed stoker 210 0.50 

(ii) Spreader stoker and fluidized bed combustion 260 0.60 

(iii) Pulverized coal 300 0.70 

(iv) Lignite, except (v) 260 0.60 

(v) Lignite mined in North Dakota, South Dakota, or 

Montana and combusted in a slag tap furnace 340 0.80 

(vi) Coal-derived synthetic fuels 210 0.50 

(4) Duct burner used in a combined cycle system: 

(i) Natural gas and distillate oil 86 0.20 

(ii) Residual oil 170 0.40 

(b) Except as provided under paragraphs (k) and (l) of this section, on and after the date on 

which the initial performance test is completed or is required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected facility that simultaneously 

combusts mixtures of 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: 

Where: 

En= NOXemission 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); 

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Comment [CF8]: Only?
Hgo= Heat input from combustion of natural gas or distillate oil, J (MMBtu); 

ELro= Appropriate emission limit from paragraph (a)(2) for combustion of residual oil, ng/J 

(lb/MMBtu); 

Hro= Heat input from combustion of residual oil, J (MMBtu); 

ELc= Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J 

(lb/MMBtu); and 

Hc= Heat input from combustion of coal, J (MMBtu). 

(c) Except as provided under paragraph (d) and (l) of this section, on and after the date on which 

the initial performance test is completed or is required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility that simultaneously combusts coal 

or oil, 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 §60.8, whichever date comes first, no owner or operator of an affected facility 

that simultaneously combusts natural gas or distillate oil with a potential SO2 emissions rate of 

26 ng/J (0.060 lb/MMBtu) or less with wood, municipal-type solid waste, or other solid fuel, 

except coal, shall cause to be discharged into the atmosphere from that affected facility any gases 

that contain NOX in excess of 130 ng/J (0.30 lb/MMBtu) heat input unless the affected facility 

has an annual capacity factor for natural gas, distillate oil, or a mixture of these fuels of 10 

percent (0.10) or less and is subject to a federally enforceable requirement that limits operation 

of the affected facility to an annual capacity factor of 10 percent (0.10) or less for natural gas, 

distillate oil, or a mixture of these fuels. 

(e) Except as provided under paragraph (l) of this section, on and after the date on which the 

initial performance test is completed or is required to be completed under §60.8, whichever date 

comes first, no owner or operator of an affected facility that simultaneously combusts coal, oil, 

or natural gas with byproduct/waste shall cause to be discharged into the atmosphere any gases 

that contain NOXin 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: 

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Comment [CF9]: Add low sulfur distillate as

alternative to NG to increase flexibility for

owners/operators of wood‐fired boilers.  Low sulfur

distillate combusts clean enough to qualify for low

capacity factor exemption.

Comment [CF10]: Only?
Where: 

En= NOXemission 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 NOXemission 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 NOXemissions 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 NOXemission 

limit under this section shall: 

(i) Demonstrate compliance with the emission limits for natural gas and distillate oil in paragraph 

(a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, 

by conducting a 30-day performance test as provided in §60.46b(e). During the performance test 

only natural gas, distillate oil, or residual oil shall be combusted in the affected facility; and 

(ii) Demonstrate that the affected facility is unable to comply with the emission limits for natural 

gas and distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or 

(l)(1) of this section, as appropriate, when gaseous or liquid byproduct/waste is combusted in the 

affected facility under the same conditions and using the same technological system of emission 

reduction applied when demonstrating compliance under paragraph (f)(1)(i) of this section. 

(2) The NOXemission 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 NOXemission limit will be established at the 

NOXemission 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 
NOXemissions. In lieu of amending this subpart, a letter will be sent to the facility describing the 

facility-specific NOXlimit. The facility shall use the compliance procedures detailed in the letter 

and make the letter available to the public. If the Administrator determines it is appropriate, the 

conditions and requirements of the letter can be reviewed and changed at any point. 

(g) Any owner or operator of an affected facility that combusts hazardous waste (as defined by 

40 CFR part 261 or 40 CFR part 761) with natural gas or oil may petition the Administrator 

within 180 days of the initial startup of the affected facility for a waiver from compliance with 

the NOXemission limit that applies specifically to that affected facility. The petition must include 

sufficient and appropriate data, as determined by the Administrator, on NOXemissions 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 NOXemission 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 NOXemission limits of this section. The NOXemission 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 

NOXlimit. 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 NOXstandards 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 NOXemission limits under this section. 

(l) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date 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 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: 

Where: 

En= NOXemission limit, (lb/MMBtu); 

Hgo= 30-day heat input from combustion of natural gas or distillate oil; and 

Hr= 30-day heat input from combustion of any other fuel. 

(3) After February 27, 2006, units where more than 10 percent of total annual output is electrical 

or mechanical may comply with an optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, 

based on a 30-day rolling average. Units complying with this output-based limit must 

demonstrate compliance according to the procedures of §60.48Da(i) of subpart Da of this part, 

and must monitor emissions according to §60.49Da(c), (k), through (n) of subpart Da of this part. 

§60.45b Compliance and performance test methods and procedures for sulfur dioxide. 

(a) The SO2emission standards in §60.42b apply at all times. Facilities burning coke oven gas 

alone or in combination with any other gaseous fuels or distillate oil are allowed to exceed the 

limit 30 operating days per calendar year for SO2control system maintenance. 

(b) In conducting the performance tests required under §60.8, the owner or operator shall use the 

methods and procedures in appendix A (including fuel certification and sampling) of this part or 

the methods and procedures as specified in this section, except as provided in §60.8(b). Section 

60.8(f) does not apply to this section. The 30-day notice required in §60.8(d) applies only to the 

initial performance test unless otherwise specified by the Administrator. 

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(c) The owner or operator of an affected facility shall conduct performance tests to determine 

compliance with the percent of potential SO2emission rate (% Ps) and the SO2emission rate (Es) 

pursuant to §60.42b following the procedures listed below, except as provided under paragraph 

(d) and (k) of this section. 

(1) The initial performance test shall be conducted over 30 consecutive operating days of the 

steam generating unit. Compliance with the SO2standards 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 

SO2emission rate (Eho) and the 30-day average emission rate (Eao). The hourly averages used to 

compute the 30-day averages are obtained from the CEMS of §60.47b(a) or (b). 

(ii) The percent of potential SO2emission rate (%Ps) emitted to the atmosphere is computed using 

the following formula: 

Where: 

%Ps= Potential SO2emission rate, percent; 

%Rg= SO2removal efficiency of the control device as determined by Method 19 of appendix A 

of this part, in percent; and 

%Rf= SO2removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of 

this part, in percent. 

(3) If coal or oil is combusted with other fuels, the same procedures required in paragraph (c)(2) 

of this section are used, except as provided in the following: 

(i) An adjusted hourly SO2emission rate (Ehoo

 ) is used in Equation 19–19 of Method 19 of 

appendix A of this part to compute an adjusted 30-day average emission rate (Eaoo

 ). The Eho° is 

computed using the following formula: 

Where: 

Ehoo

 = Adjusted hourly SO2emission rate, ng/J (lb/MMBtu); 

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Eho= Hourly SO2emission rate, ng/J (lb/MMBtu); 

Ew= SO2concentration 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 Ewfor 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 SO2emission rate (%Ps), an adjusted %Rg(%Rg

o

 ) is 

computed from the adjusted Eaoo

 from paragraph (b)(3)(i) of this section and an adjusted average 

SO2inlet rate (Eai

o

 ) using the following formula: 

To compute Eai

o

 , an adjusted hourly SO2inlet rate (Ehi

o

 ) is used. The Ehi

o

 is computed using the 

following formula: 

Where: 

Ehi

o

 = Adjusted hourly SO2inlet rate, ng/J (lb/MMBtu); and 

Ehi= Hourly SO2inlet 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 Ewor Xkif 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 %Psfollowing the procedures in paragraph (c)(2) of this section; and 

(ii) Sulfur dioxide emissions (Es) are considered to be in compliance with SO2emission limits 

under §60.42b. 

(5) The owner or operator of an affected facility that qualifies under the provisions of §60.42b(d) 

does not have to measure parameters Ewor Xkin paragraph (c)(3) of this section if the owner or 

operator of the affected facility elects to measure SO2emission 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: 

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(1) Conduct the initial performance test over 24 consecutive steam generating unit operating 

hours at full load; 

(2) Determine compliance with the standards after the initial performance test based on the 

arithmetic average of the hourly emissions data during each steam generating unit operating day 

if a CEMS is used, or based on a daily average if Method 6B of appendix A of this part or fuel 

sampling and analysis procedures under Method 19 of appendix A of this part are used. 

(e) The owner or operator of an affected facility subject to §60.42b(d)(1) shall demonstrate the 

maximum design capacity of the steam generating unit by operating the facility at maximum 

capacity for 24 hours. This demonstration will be made during the initial performance test and a 

subsequent demonstration may be requested at any other time. If the 24-hour average firing rate 

for the affected facility is less than the maximum design capacity provided by the manufacturer 

of the affected facility, the 24-hour average firing rate shall be used to determine the capacity 

utilization rate for the affected facility, otherwise the maximum design capacity provided by the 

manufacturer is used. 

(f) For the initial performance test required under §60.8, compliance with the SO2emission limits 

and percent reduction requirements under §60.42b is based on the average emission rates and the 

average percent reduction for SO2for the first 30 consecutive steam generating unit operating 

days, except as provided under paragraph (d) of this section. The initial performance test is the 

only test for which at least 30 days prior notice is required unless otherwise specified by the 

Administrator. The initial performance test is to be scheduled so that the first steam generating 

unit operating day of the 30 successive steam generating unit operating days is completed within 

30 days after achieving the maximum production rate at which the affected facility will be 

operated, but not later than 180 days after initial startup of the facility. The boiler load during the 

30-day period does not have to be the maximum design load, but must be representative of future 

operating conditions and include at least one 24-hour period at full load. 

(g) After the initial performance test required under §60.8, compliance with the SO2emission 

limits and percent reduction requirements under §60.42b is based on the average emission rates 

and the average percent reduction for SO2for 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 SO2are 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 SO2emissions data in calculating %Psand Ehounder paragraph (c), of 

this section whether or not the minimum emissions data requirements under §60.46b are 

achieved. All valid emissions data, including valid SO2emission data collected during periods of 

startup, shutdown and malfunction, shall be used in calculating %Psand Ehopursuant to paragraph 

(c) of this section. 

(i) During periods of malfunction or maintenance of the SO2control systems when oil is 

combusted as provided under §60.42b(i), emission data are not used to calculate %Psor Esunder 

§60.42b(a), (b) or (c), however, the emissions data are used to determine compliance with the 

emission limit under §60.42b(i). 
(j) The owner or operator of an affected facility that only combusts very low sulfur oil, natural 

gas, or a mixture of these fuels with any other fuels not subject to an SO2standard is not subject 

to the compliance and performance testing requirements of this section if the owner or operator 

obtains fuel receipts as described in §60.49b(r). 

(k) The owner or operator of an affected facility seeking to demonstrate compliance in 

§§60.42b(d)(4), 60.42b(j), 60.42b(k)(2), and 60.42b(k)(3) (when not burning coal) shall follow 

the applicable procedures in §60.49b(r). 

§60.46b Compliance and performance test methods and procedures for particulate matter 

and nitrogen oxides. 

(a) The PM emission standards and opacity limits under §60.43b apply at all times except during 

periods of startup, shutdown, or malfunction. The NOXemission standards under §60.44b apply 

at all times. 

(b) Compliance with the PM emission standards under §60.43b shall be determined through 

performance testing as described in paragraph (d) of this section, except as provided in paragraph 

(i) of this section. 

(c) Compliance with the NOXemission standards under §60.44b shall be determined through 

performance testing under paragraph (e) or (f), or under paragraphs (g) and (h) of this section, as 

applicable. 

(d) To determine compliance with the PM emission limits and opacity limits under §60.43b, the 

owner or operator of an affected facility shall conduct an initial performance test as required 

under §60.8, and shall conduct subsequent performance tests as requested by the Administrator, 

using the following procedures and reference methods: 

(1) Method 3A or 3B of appendix A–2 of this part is used for gas analysis when applying 

Method 5 of appendix A–3 of this part or Method 17 of appendix A–6 of this part. 

(2) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of 

PM as follows: 

(i) Method 5 of appendix A of this part shall be used at affected facilities without wet flue gas 

desulfurization (FGD) systems; and 

(ii) Method 17 of appendix A–6 of this part may be used at facilities with or without wet 

scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C 

(320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A–3 of this part 

may be used in Method 17 of appendix A–6 of this part only if it is used after a wet FGD system. 

Do not use Method 17 of appendix A–6 of this part after wet FGD systems if the effluent is 

saturated or laden with water droplets. 

(iii) Method 5B of appendix A of this part is to be used only after wet FGD systems. 

(3) Method 1 of appendix A of this part is used to select the sampling site and the number of 

traverse sampling points. The sampling time for each run is at least 120 minutes and the 
minimum sampling volume is 1.7 dscm (60 dscf) except that smaller sampling times or volumes 

may be approved by the Administrator when necessitated by process variables or other factors. 

(4) For Method 5 of appendix A of this part, the temperature of the sample gas in the probe and 

filter holder is monitored and is maintained at 160±14 °C (320±25 °F). 

(5) For determination of PM emissions, the oxygen (O2) or CO2sample 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 O2or CO2measurements 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 NOXrequired under §60.44b, the owner 

or operator of an affected facility shall conduct the performance test as required under §60.8 

using the continuous system for monitoring NOXunder §60.48(b). 

(1) For the initial compliance test, NOXfrom 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 NOXemission standards under §60.44b. The 30-day average 

emission rate is calculated as the average of all hourly emissions data recorded by the monitoring 

system during the 30-day test period. 

(2) Following the date on which the initial performance test is completed or is required to be 

completed in §60.8, whichever date comes first, the owner or operator of an affected facility 

which combusts coal (except as specified under §60.46b(e)(4)) or which combusts residual oil 

having a nitrogen content greater than 0.30 weight percent shall determine compliance with the 

NOXemission standards in §60.44b on a continuous basis through the use of a 30-day rolling 

average emission rate. A new 30-day rolling average emission rate is calculated for each steam 

generating unit operating day as the average of all of the hourly NOXemission data for the 

preceding 30 steam generating unit operating days. 

(3) Following the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, the owner or operator of an affected facility 

that has a heat input capacity greater than 73 MW (250 MMBtu/hr) and that combusts natural 

gas, distillate oil, or residual oil having a nitrogen content of 0.30 weight percent or less shall 

determine compliance with the NOXstandards under §60.44b on a continuous basis through the 

use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is 

calculated each steam generating unit operating day as the average of all of the hourly 

NOXemission data for the preceding 30 steam generating unit operating days. 
(4) Following the date on which the initial performance test is completed or required to be 

completed under §60.8, whichever date comes first, the owner or operator of an affected facility 

that has a heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts natural gas, 

distillate oil, gasified coal, or residual oil having a nitrogen content of 0.30 weight percent or less 

shall upon request determine compliance with the NOXstandards in §60.44b through the use of a 

30-day performance test. During periods when performance tests are not requested, 

NOXemissions data collected pursuant to §60.48b(g)(1) or §60.48b(g)(2) are used to calculate a 

30-day rolling average emission rate on a daily basis and used to prepare excess emission 

reports, but will not be used to determine compliance with the NOXemission 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 NOXemission data for the preceding 30 steam generating unit 

operating days. 

(5) If the owner or operator of an affected facility that combusts residual oil does not sample and 

analyze the residual oil for nitrogen content, as specified in §60.49b(e), the requirements of 

§60.48b(g)(1) apply and the provisions of §60.48b(g)(2) are inapplicable. 

(f) To determine compliance with the emissions limits for NOXrequired by §60.44b(a)(4) or 

§60.44b(l) for duct burners used in combined cycle systems, either of the procedures described in 

paragraph (f)(1) or (2) of this section may be used: 

(1) The owner or operator of an affected facility shall conduct the performance test required 

under §60.8 as follows: 

(i) The emissions rate (E) of NOXshall be computed using Equation 1 in this section: 

Where: 

E = Emissions rate of NOXfrom 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 NOXconcentrations. 

Method 3A or 3B of appendix A of this part shall be used to determine O2concentration. 

(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. 

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.
(iv) Compliance with the emissions limits under §60.44b(a)(4) or §60.44b(l) is determined by the 

three-run average (nominal 1-hour runs) for the initial and subsequent performance tests; or 

(2) The owner or operator of an affected facility may elect to determine compliance on a 30-day 

rolling average basis by using the CEMS specified under §60.48b for measuring NOXand O2and 

meet the requirements of §60.48b. The sampling site shall be located at the outlet from the steam 

generating unit. The NOXemissions rate at the outlet from the steam generating unit shall 

constitute the NOXemissions rate from the duct burner of the combined cycle system. 

(g) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall 

demonstrate the maximum heat input capacity of the steam generating unit by operating the 

facility at maximum capacity for 24 hours. The owner or operator of an affected facility shall 

determine the maximum heat input capacity using the heat loss method or the heat input method 

described in sections 5 and 7.3 of the ASME Power Test Codes 4.1 (incorporated by reference, 

see §60.17). This demonstration of maximum heat input capacity shall be made during the initial 

performance test for affected facilities that meet the criteria of §60.44b(j). It shall be made within 

60 days after achieving the maximum production rate at which the affected facility will be 

operated, but not later than 180 days after initial start-up of each facility, for affected facilities 

meeting the criteria of §60.44b(k). Subsequent demonstrations may be required by the 

Administrator at any other time. If this demonstration indicates that the maximum heat input 

capacity of the affected facility is less than that stated by the manufacturer of the affected 

facility, the maximum heat input capacity determined during this demonstration shall be used to 

determine the capacity utilization rate for the affected facility. Otherwise, the maximum heat 

input capacity provided by the manufacturer is used. 

(h) The owner or operator of an affected facility described in §60.44b(j) that has a heat input 

capacity greater than 73 MW (250 MMBtu/hr) shall: 

(1) Conduct an initial performance test as required under §60.8 over a minimum of 24 

consecutive steam generating unit operating hours at maximum heat input capacity to 

demonstrate compliance with the NOXemission standards under §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 NOXemission standards under 

§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 §60.43b(a)(4) or §60.43b(h)(5) shall follow the applicable procedures in 

§60.49b(r). 

(j) In place of PM testing with Method 5 or 5B of appendix A–3 of this part, or Method 17 of 

appendix A–6 of this part, an owner or operator may elect to install, calibrate, maintain, and 

operate a CEMS for monitoring PM emissions discharged to the atmosphere and record the 

output of the system. The owner or operator of an affected facility who elects to continuously 

monitor PM emissions instead of conducting performance testing using Method 5 or 5B of 
appendix A–3 of this part or Method 17 of appendix A–6 of this part shall comply with the 

requirements specified in paragraphs (j)(1) through (j)(14) of this section. 

(1) Notify the Administrator one month before starting use of the system. 

(2) Notify the Administrator one month before stopping use of the system. 

(3) The monitor shall be installed, evaluated, and operated in accordance with §60.13 of subpart 

A of this part. 

(4) The initial performance evaluation shall be completed no later than 180 days after the date of 

initial startup of the affected facility, as specified under §60.8 of subpart A of this part or within 

180 days of notification to the Administrator of use of the CEMS if the owner or operator was 

previously determining compliance by Method 5, 5B, or 17 of appendix A of this part 

performance tests, whichever is later. 

(5) The owner or operator of an affected facility shall conduct an initial performance test for PM 

emissions as required under §60.8 of subpart A of this part. Compliance with the PM emission 

limit shall be determined by using the CEMS specified in paragraph (j) of this section to measure 

PM and calculating a 24-hour block arithmetic average emission concentration using EPA 

Reference Method 19 of appendix A of this part, section 4.1. 

(6) Compliance with the PM emission limit shall be determined based on the 24-hour daily 

(block) average of the hourly arithmetic average emission concentrations using CEMS outlet 

data. 

(7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraphs 

(j)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average. 

(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average. 

(ii) [Reserved] 

(8) The 1-hour arithmetic averages required under paragraph (j)(7) of this section shall be 

expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day 

daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be 

calculated using the data points required under §60.13(e)(2) of subpart A of this part. 

(9) All valid CEMS data shall be used in calculating average emission concentrations even if the 

minimum CEMS data requirements of paragraph (j)(7) of this section are not met. 

(10) The CEMS shall be operated according to Performance Specification 11 in appendix B of 

this part. 

(11) During the correlation testing runs of the CEMS required by Performance Specification 11 

in appendix B of this part, PM and O2(or CO2) data shall be collected concurrently (or within a 

30-to 60-minute period) by both the continuous emission monitors and performance tests 

conducted using the following test methods. 
(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this 

part shall be used; and 

(ii) For O2(or CO2), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. 

(12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in 

accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be 

performed annually and Response Correlation Audits must be performed every 3 years. 

(13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, 

calibration checks, and zero and span adjustments, emissions data shall be obtained by using 

other monitoring systems as approved by the Administrator or EPA Reference Method 19 of 

appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 

percent of total operating hours per 30-day rolling average. 

(14) As of January 1, 2012 and within 60 days after the date of completing each performance 

test, as defined in §63.2, conducted to demonstrate compliance with this subpart, you must 

submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., 

compliance test) data, except opacity data, electronically to EPA’s Central Data Exchange 

(CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert 

tool.html/) or other compatible electronic spreadsheet. Only data collected using test methods 

compatible with ERT are subject to this requirement to be submitted electronically into EPA’s 

WebFIRE database.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.

§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 SO2standards in §60.42b shall install, calibrate, maintain, and 

operate CEMS for measuring SO2concentrations and either O2or CO2concentrations and shall 

record the output of the systems. For units complying with the percent reduction standard, the 

SO2and either O2or CO2concentrations shall both be monitored at the inlet and outlet of the 

SO2control device. If the owner or operator has installed and certified SO2and O2or CO2CEMS 

according to the requirements of §75.20(c)(1) of this chapter and appendix A to part 75 of this 

chapter, and is continuing to meet the ongoing quality assurance requirements of §75.21 of this 

chapter and appendix B to part 75 of this chapter, those CEMS may be used to meet the 

requirements of this section, provided that: 

(1) When relative accuracy testing is conducted, SO2concentration data and CO2(or O2) data are 

collected simultaneously; and 

(2) In addition to meeting the applicable SO2and 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 

Comment [CF11]: Updated language for

electronic reporting.
(3) The reporting requirements of §60.49b are met. SO2and CO2(or O2) data used to meet the 

requirements of §60.49b shall not include substitute data values derived from the missing data 

procedures in subpart D of part 75 of this chapter, nor shall the SO2data 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 SO2emissions 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 SO2input rate, or 

(2) Measuring SO2according to Method 6B of appendix A of this part at the inlet or outlet to the 

SO2control 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 SO2and CO2measurement 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 SO2emission 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 SO2emission rates measured by the CEMS required by paragraph (a) of 

this section and required under §60.13(h) is expressed in ng/J or lb/MMBtu heat input and is 

used to calculate the average emission rates under §60.42(b). Each 1-hour average SO2emission 

rate must be based on 30 or more minutes of steam generating unit operation. The hourly 

averages shall be calculated according to §60.13(h)(2). Hourly SO2emission rates are not 
calculated if the affected facility is operated less than 30 minutes in a given clock hour and are 

not counted toward determination of a steam generating unit operating day. 

(e) The procedures under §60.13 shall be followed for installation, evaluation, and operation of 

the CEMS. 

(1) Except as provided for in paragraph (e)(4) of this section, all CEMS shall be operated in 

accordance with the applicable procedures under Performance Specifications 1, 2, and 3 of 

appendix B of this part. 

(2) Except as provided for in paragraph (e)(4) of this section, quarterly accuracy determinations 

and daily calibration drift tests shall be performed in accordance with Procedure 1 of appendix F 

of this part. 

(3) For affected facilities combusting coal or oil, alone or in combination with other fuels, the 

span value of the SO2CEMS at the inlet to the SO2control device is 125 percent of the maximum 

estimated hourly potential SO2emissions of the fuel combusted, and the span value of the CEMS 

at the outlet to the SO2control device is 50 percent of the maximum estimated hourly potential 

SO2emissions of the fuel combusted. Alternatively, SO2span 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 CO2and O2monitors and for SO2and NOXmonitors 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 CO2and O2monitors and for SO2and NOXmonitors 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-ofcontrol 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 SO2and NOXspan values less than or equal 

to 30 ppm; and 

(iii) For SO2, CO2, and O2monitoring systems and for NOXemission 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 SO2emission level during the RATA), and for NOXwhen the average NOXemission rate 

measured by the reference method during the RATA is less than 0.100 lb/MMBtu. 

(f) The owner or operator of an affected facility that combusts very low sulfur oil or is 

demonstrating compliance under §60.45b(k) is not subject to the emission monitoring 

requirements under paragraph (a) of this section if the owner or operator maintains fuel records 

as described in §60.49b(r). 

§60.48b Emission monitoring for particulate matter and nitrogen oxides. 

(a) Except as provided in paragraph (j) of this section, the owner or operator of an affected 

facility subject to the opacity standard under §60.43b shall install, calibrate, maintain, and 

operate a continuous opacity monitoring systems (COMS) for measuring the opacity of 

emissions discharged to the atmosphere and record the output of the system. The owner or 

operator of an affected facility subject to an opacity standard under §60.43b and meeting the 

conditions under paragraphs (j)(1), (2), (3), (4), or (5), or (6) of this section who elects not to use 

a COMS shall conduct a performance test using Method 9 of appendix A–4 of this part and the 

procedures in §60.11 to demonstrate compliance with the applicable limit in §60.43b by April 

29, 2011, within 45 days of stopping use of an existing COMS, or within 180 days after initial 

startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), 

or (a)(3) of this section. The observation period for Method 9 of appendix A-4 of this part 

performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less 

than 10 percent and all individual 15-second observations are less than or equal to 20 percent 

during the initial 60 minutes of observation. 

(1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall 

conduct subsequent Method 9 of appendix A–4 of this part performance tests using the 

procedures in paragraph (a) of this section according to the applicable schedule in paragraphs 

(a)(1)(i) through (a)(1)(iv) of this section, as determined by the most recent Method 9 of 

appendix A–4 of this part performance test results. 

(i) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 12 calendar months from the date that the most 

recent performance test was conducted or within 45 days of the next day that fuel with an opacity 

standard is combusted, whichever is later; 

(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or 

equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be 

completed within 6 calendar months from the date that the most recent performance test was 

conducted; 

Comment [CF12]: Could we cut this date since it

will only be historical?

Comment [CF13]: Request comment on

simplifying to:

5% of less – 12 months

5% ‐ 10% ‐ 6 months

Greater than 10% ‐ 3 months

Comment [CF14]: Allow flexibility to account

for intermittent use of fuels with an opacity

standard.
(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 45 calendar days from 

the date that the most recent performance test was conducted. 

(2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to 

performing subsequent Method 9 of appendix A–4 of this part performance tests, elect to 

perform subsequent monitoring using Method 22 of appendix A–7 of this part according to the 

procedures specified in paragraphs (a)(2)(i) and (ii) of this section. 

(i) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using 

Method 22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any 

visible emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 

minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds 

during the initial 10 minute observation, immediately conduct a 30 minute observation. If the 

sum of the occurrence of visible emissions is greater than 5 percent of the observation period ( 

i.e. , 90 seconds per 30 minute period), the owner or operator shall either document and adjust 

the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of 

visible emissions is equal to or less than 5 percent during a 30 minute observation ( i.e. , 90 

seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the 

procedures in paragraph (a) of this section within 45 calendar days according to the requirements 

in §60.46d(d)(7). 

(ii) If no visible emissions are observed for 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. 

(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. 

Comment [CF15]: Request comment on

reducing to 5 or 10 days
(b) Except as provided under paragraphs (g), (h), and (i) of this section, the owner or operator of 

an affected facility subject to a NOXstandard under §60.44b shall comply with either paragraphs 

(b)(1) or (b)(2) of this section. 

(1) Install, calibrate, maintain, and operate CEMS for measuring NOXand 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 NOXemission rate CEMS to meet the requirements of 

part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this 

chapter, that CEMS may be used to meet the requirements of this section, except that the owner 

or operator shall also meet the requirements of §60.49b. Data reported to meet the requirements 

of §60.49b shall not include data substituted using the missing data procedures in subpart D of 

part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of 

part 75 of this chapter. 

(c) The CEMS required under paragraph (b) of this section shall be operated and data recorded 

during all periods of operation of the affected facility except for CEMS breakdowns and repairs. 

Data is recorded during calibration checks, and zero and span adjustments. 

(d) The 1-hour average NOXemission rates measured by the continuous NOXmonitor required by 

paragraph (b) of this section and required under §60.13(h) shall be expressed in ng/J or 

lb/MMBtu heat input and shall be used to calculate the average emission rates under §60.44b. 

The 1-hour averages shall be calculated using the data points required under §60.13(h)(2). 

(e) The procedures under §60.13 shall be followed for installation, evaluation, and operation of 

the continuous monitoring systems. 

(1) For affected facilities combusting coal, wood or municipal-type solid waste, the span value 

for a COMS shall be between 60 and 80 percent. 

(2) For affected facilities combusting coal, oil, or natural gas, the span value for NOXis 

determined using one of the following procedures: 

(i) Except as provided under paragraph (e)(2)(ii) of this section, NOXspan 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 NOXspan values determined according to 

section 2.1.2 in appendix A to part 75 of this chapter. 

(3) All span values computed under paragraph (e)(2)(i) of this section for combusting mixtures 

of regulated fuels are rounded to the nearest 500 ppm. Span values computed under paragraph 

(e)(2)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 

of this chapter. 

(f) When NOXemission 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 NOXemission rates as 

specified in a plan submitted pursuant to §60.49b(c). 

(h) The owner or operator of a duct burner, as described in §60.41b, that is subject to the 

NOXstandards in §60.44b(a)(4), §60.44b(e), or §60.44b(l) is not required to install or operate a 

continuous emissions monitoring system to measure NOXemissions. 

(i) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) is not 

required to install or operate a CEMS for measuring NOXemissions. 

(j) The owner or operator of an affected facility that meets the conditions in either paragraph 

(j)(1), (2), (3), (4), (5), or (6), or (7) of this section is not required to install or operate a COMS 

if: 

(1) The affected facility uses a PM CEMS to monitor PM emissions; or 

(2) The affected facility burns only liquid (excluding residual oil) or gaseous fuels with potential 

SO2emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion 

technology to reduce SO2or PM emissions. The owner or operator must maintain fuel records of 

the sulfur content of the fuels burned, as described under §60.49b(r); or 
(3) The affected facility burns coke oven gas alone or in combination with fuels meeting the 

criteria in paragraph (j)(2) of this section and does not use a post-combustion technology to 

reduce SO2or PM emissions; or 

(4) The affected facility does not use post-combustion technology (except a wet scrubber) for 

reducing PM, SO2, or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils 

that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions 

of CO to the atmosphere from the affected facility are maintained at levels less than or equal to 

0.15 lb/MMBtu on a steam generating unit operating day average basis. Owners and operators of 

affected facilities electing to comply with this paragraph must demonstrate compliance according 

to the procedures specified in paragraphs (j)(4)(i) through (iv) of this section; or 

(i) You must monitor CO emissions using a CEMS according to the procedures specified in 

paragraphs (j)(4)(i)(A) through (D) of this section. 

(A) The CO CEMS must be installed, certified, maintained, and operated according to the 

provisions in §60.58b(i)(3) of subpart Eb of this part. 

(B) Each 1-hour CO emissions average is calculated using the data points generated by the CO 

CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 

(C) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent 

of the operating hours on a 30-day rolling average basis. The 1-hour averages are calculated 

using the data points required in §60.13(h)(2). 

(D) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(ii) You must calculate the 1-hour average CO emissions levels for each steam generating unit 

operating day by multiplying the average hourly CO output concentration measured by the CO 

CEMS times the corresponding average hourly flue gas flow rate and divided by the 

corresponding average hourly heat input to the affected source. The 24-hour average CO 

emission level is determined by calculating the arithmetic average of the hourly CO emission 

levels computed for each steam generating unit operating day. 

(iii) You must evaluate the preceding 24-hour average CO emission level each steam generating 

unit operating day excluding periods of affected source startup, shutdown, or malfunction. If the 

24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate 

investigation of the relevant equipment and control systems within 24 hours of the first discovery 

of the high emission incident and, take the appropriate corrective action as soon as practicable to 

adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 

0.15 lb/MMBtu or less. 

(iv) You must record the CO measurements and calculations performed according to paragraph 

(j)(4) of this section and any corrective actions taken. The record of corrective action taken must 

include the date and time during which the 24-hour average CO emission level was greater than 

0.15 lb/MMBtu, and the date, time, and description of the corrective action. 
(5) The affected facility uses a bag leak detection system to monitor the performance of a fabric 

filter (baghouse) according to the most recent current requirements in section §60.48Da of this 

part; or

(6) The affected facility uses an ESP as the primary PM control device and uses an ESP 

predictive model to monitor the performance of the ESP developed in accordance and operated 

according to the most current requirements in section §60.48Da of this part; or

(76) The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 

0.30 weight percent sulfur and operates according to a written site-specific monitoring plan 

approved by the permitting authority. This monitoring plan must include procedures and criteria 

for establishing and monitoring specific parameters for the affected facility indicative of 

compliance with the opacity standard. 

(k) Owners or operators complying with the PM emission limit by using a PM CEMS must 

calibrate, maintain, operate, and record the output of the system for PM emissions discharged to 

the atmosphere as specified in §60.46b(j). The CEMS specified in paragraph §60.46b(j) shall be 

operated and data recorded during all periods of operation of the affected facility except for 

CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span 

adjustments. 

§60.49b Reporting and recordkeeping requirements. 

(a) The owner or operator of each affected facility shall submit notification of the date of initial 

startup, as provided by §60.7. This notification shall include: 

(1) The design heat input capacity of the affected facility and identification of the fuels to be 

combusted in the affected facility; 

(2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity 

factor for any fuel or mixture of fuels under §§60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii), 

(d)(2)(iii), 60.44b(c), (d), (e), (i), (j), (k), 60.45b(d), (g), 60.46b(h), or 60.48b(i); 

(3) The annual capacity factor at which the owner or operator anticipates operating the facility 

based on all fuels fired and based on each individual fuel fired; and 

(4) Notification that an emerging technology will be used for controlling emissions of SO2. The 

Administrator will examine the description of the emerging technology and will determine 

whether the technology qualifies as an emerging technology. In making this determination, the 

Administrator may require the owner or operator of the affected facility to submit additional 

information concerning the control device. The affected facility is subject to the provisions of 

§60.42b(a) unless and until this determination is made by the Administrator. 

(b) The owner or operator of each affected facility subject to the SO2, PM, and/or NOXemission 

limits under §§60.42b, 60.43b, and 60.44b shall submit to the Administrator the performance test 

data from the initial performance test and the performance evaluation of the CEMS using the 

applicable performance specifications in appendix B of this part. The owner or operator of each 

affected facility described in §60.44b(j) or §60.44b(k) shall submit to the Administrator the 

Comment [CF16]: Add ESP model to COMS

exemption options
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 NOXstandard in §60.44b who 

seeks to demonstrate compliance with those standards through the monitoring of steam 

generating unit operating conditions in the provisions of §60.48b(g)(2) shall submit to the 

Administrator for approval a plan that identifies the operating conditions to be monitored in 

§60.48b(g)(2) and the records to be maintained in §60.49b(g). This plan shall be submitted to the 

Administrator for approval within 360 days of the initial startup of the affected facility. An 

affected facility burning coke oven gas alone or in combination with other gaseous fuels or 

distillate oil shall submit this plan to the Administrator for approval within 360 days of the initial 

startup of the affected facility or by November 30, 2009, whichever date comes later. If the plan 

is approved, the owner or operator shall maintain records of predicted nitrogen oxide emission 

rates and the monitored operating conditions, including steam generating unit load, identified in 

the plan. The plan shall: 

(1) Identify the specific operating conditions to be monitored and the relationship between these 

operating conditions and NOXemission 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 O2level); 

(2) Include the data and information that the owner or operator used to identify the relationship 

between NOXemission rates and these operating conditions; and 

(3) Identify how these operating conditions, including steam generating unit load, will be 

monitored under §60.48b(g) on an hourly basis by the owner or operator during the period of 

operation of the affected facility; the quality assurance procedures or practices that will be 

employed to ensure that the data generated by monitoring these operating conditions will be 

representative and accurate; and the type and format of the records of these operating conditions, 

including steam generating unit load, that will be maintained by the owner or operator under 

§60.49b(g). 

(d) Except as provided in paragraph (d)(2) of this section, the owner or operator of an affected 

facility shall record and maintain records as specified in paragraph (d)(1) of this section. 

(1) The owner or operator of an affected facility shall record and maintain records of the amounts 

of each fuel combusted during each day and calculate the annual capacity factor individually for 

coal, distillate oil, residual oil, natural gas, wood, and municipal-type solid waste for the 

reporting period. The annual capacity factor is determined on a 12-month rolling average basis 

with a new annual capacity factor calculated at the end of each calendar month. 

(2) As an alternative to meeting the requirements of paragraph (d)(1) of this section, the owner or 

operator of an affected facility that is subject to a federally enforceable permit restricting fuel use 

to a single fuel such that the facility is not required to continuously monitor any emissions 

(excluding opacity) or parameters indicative of emissions may elect to record and maintain 

records of the amount of each fuel combusted during each calendar month. 
(e) For an affected facility that combusts residual oil and meets the criteria under §§60.46b(e)(4), 

60.44b(j), or (k), the owner or operator shall maintain records of the nitrogen content of the 

residual oil combusted in the affected facility and calculate the average fuel nitrogen content for 

the reporting period. The nitrogen content shall be determined using ASTM Method D4629 

(incorporated by reference, see §60.17), or fuel suppliers. If residual oil blends are being 

combusted, fuel nitrogen specifications may be prorated based on the ratio of residual oils of 

different nitrogen content in the fuel blend. 

(f) For an affected facility subject to the opacity standard in §60.43b, the owner or operator shall 

maintain records of opacity. In addition, an owner or operator that elects to monitor emissions 

according to the requirements in §60.48b(a) shall maintain records according to the requirements 

specified in paragraphs (f)(1) through (3) of this section, as applicable to the visible emissions 

monitoring method used. 

(1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner 

or operator shall keep the records including the information specified in paragraphs (f)(1)(i) 

through (iii) of this section. 

(i) Dates and time intervals of all opacity observation periods; 

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible 

emission observer participating in the performance test; and 

(iii) Copies of all visible emission observer opacity field data sheets; 

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the 

owner or operator shall keep the records including the information specified in paragraphs 

(f)(2)(i) through (iv) of this section. 

(i) Dates and time intervals of all visible emissions observation periods; 

(ii) Name and affiliation for each visible emission observer participating in the performance test; 

(iii) Copies of all visible emission observer opacity field data sheets; and 

(iv) Documentation of any adjustments made and the time the adjustments were completed to the 

affected facility operation by the owner or operator to demonstrate compliance with the 

applicable monitoring requirements. 

(3) For each digital opacity compliance system, the owner or operator shall maintain records and 

submit reports according to the requirements specified in the site-specific monitoring plan 

approved by the Administrator. 

(g) Except as provided under paragraph (p) of this section, the owner or operator of an affected 

facility subject to the NOXstandards under §60.44b shall maintain records of the following 

information for each steam generating unit operating day: 

(1) Calendar date; 
(2) The average hourly NOXemission rates (expressed as NO2) (ng/J or lb/MMBtu heat input) 

measured or predicted; 

(3) The 30-day average NOXemission 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 

NOXemission rates are in excess of the NOXemissions standards under §60.44b, with the reasons 

for such excess emissions as well as a description of corrective actions taken; 

(5) Identification of the steam generating unit operating days for which pollutant data have not 

been obtained, including reasons for not obtaining sufficient data and a description of corrective 

actions taken; 

(6) Identification of the times when emission data have been excluded from the calculation of 

average emission rates and the reasons for excluding data; 

(7) Identification of “F” factor used for calculations, method of determination, and type of fuel 

combusted; 

(8) Identification of the times when the pollutant concentration exceeded full span of the CEMS; 

(9) Description of any modifications to the CEMS that could affect the ability of the CEMS to 

comply with Performance Specification 2 or 3; and 

(10) Results of daily CEMS drift tests and quarterly accuracy assessments as required under 

appendix F, Procedure 1 of this part. 

(h) The owner or operator of any affected facility in any category listed in paragraphs (h)(1) or 

(2) of this section is required to submit excess emission reports for any excess emissions that 

occurred during the reporting period. 

(1) Any affected facility subject to the opacity standards in §60.43b(f) or to the operating 

parameter monitoring requirements in §60.13(i)(1). 

(2) Any affected facility that is subject to the NOXstandard of §60.44b, and that: 

(i) Combusts natural gas, distillate oil, gasified coal, or residual oil with a nitrogen content of 0.3 

weight percent or less; or 

(ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and is required to monitor 

NOXemissions on a continuous basis under §60.48b(g)(1) or steam generating unit operating 

conditions under §60.48b(g)(2). 

(3) For the purpose of §60.43b, excess emissions are defined as all 6-minute periods during 

which the average opacity exceeds the opacity standards under §60.43b(f). 

(4) For purposes of §60.48b(g)(1), excess emissions are defined as any calculated 30-day rolling 

average NOXemission rate, as determined under §60.46b(e), that exceeds the applicable emission 

limits in §60.44b. 
(i) The owner or operator of any affected facility subject to the continuous monitoring 

requirements for NOXunder §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 SO2standards under §60.42b shall 

submit reports. 

(k) For each affected facility subject to the compliance and performance testing requirements of 

§60.45b and the reporting requirement in paragraph (j) of this section, the following information 

shall be reported to the Administrator: 

(1) Calendar dates covered in the reporting period; 

(2) Each 30-day average SO2emission 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 SO2control 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 SO2emissions 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 SO2or diluent (O2or CO2) data have not been obtained by an approved method for at 

least 75 percent of the operating hours in the steam generating unit operating day; justification 

for not obtaining sufficient data; and description of corrective action taken; 

(5) Identification of the times when emissions data have been excluded from the calculation of 

average emission rates; justification for excluding data; and description of corrective action taken 

if data have been excluded for periods other than those during which coal or oil were not 

combusted in the steam generating unit; 

(6) Identification of “F” factor used for calculations, method of determination, and type of fuel 

combusted; 

(7) Identification of times when hourly averages have been obtained based on manual sampling 

methods; 

(8) Identification of the times when the pollutant concentration exceeded full span of the CEMS; 

(9) Description of any modifications to the CEMS that could affect the ability of the CEMS to 

comply with Performance Specification 2 or 3; 

(10) Results of daily CEMS drift tests and quarterly accuracy assessments as required under 

appendix F, Procedure 1 of this part; and 

(11) The annual capacity factor of each fired as provided under paragraph (d) of this section. 
(l) For each affected facility subject to the compliance and performance testing requirements of 

§60.45b(d) and the reporting requirements of paragraph (j) of this section, the following 

information shall be reported to the Administrator: 

(1) Calendar dates when the facility was in operation during the reporting period; 

(2) The 24-hour average SO2emission rate measured for each steam generating unit operating 

day during the reporting period that coal or oil was combusted, ending in the last 24-hour period 

in the quarter; reasons for noncompliance with the emission standards; and a description of 

corrective actions taken; 

(3) Identification of the steam generating unit operating days that coal or oil was combusted for 

which S02or diluent (O2or CO2) data have not been obtained by an approved method for at least 

75 percent of the operating hours; justification for not obtaining sufficient data; and description 

of corrective action taken; 

(4) Identification of the times when emissions data have been excluded from the calculation of 

average emission rates; justification for excluding data; and description of corrective action taken 

if data have been excluded for periods other than those during which coal or oil were not 

combusted in the steam generating unit; 

(5) Identification of “F” factor used for calculations, method of determination, and type of fuel 

combusted; 

(6) Identification of times when hourly averages have been obtained based on manual sampling 

methods; 

(7) Identification of the times when the pollutant concentration exceeded full span of the CEMS; 

(8) Description of any modifications to the CEMS that could affect the ability of the CEMS to 

comply with Performance Specification 2 or 3; and 

(9) Results of daily CEMS drift tests and quarterly accuracy assessments as required under 

Procedure 1 of appendix F 1 of this part. If the owner or operator elects to implement the 

alternative data assessment procedures described in §§60.47b(e)(4)(i) through (e)(4)(iii), each 

data assessment report shall include a summary of the results of all of the RATAs, linearity 

checks, CGAs, and calibration error or drift assessments required by §§60.47b(e)(4)(i) through 

(e)(4)(iii). 

(m) For each affected facility subject to the SO2standards in §60.42(b) for which the minimum 

amount of data required in §60.47b(c) were not obtained during the reporting period, the 

following information is reported to the Administrator in addition to that required under 

paragraph (k) of this section: 

(1) The number of hourly averages available for outlet emission rates and inlet emission rates; 

(2) The standard deviation of hourly averages for outlet emission rates and inlet emission rates, 

as determined in Method 19 of appendix A of this part, section 7; 
(3) The lower confidence limit for the mean outlet emission rate and the upper confidence limit 

for the mean inlet emission rate, as calculated in Method 19 of appendix A of this part, section 7; 

and 

(4) The ratio of the lower confidence limit for the mean outlet emission rate and the allowable 

emission rate, as determined in Method 19 of appendix A of this part, section 7. 

(n) If a percent removal efficiency by fuel pretreatment ( i.e. , %Rf) is used to determine the 

overall percent reduction ( i.e. , %Ro) under §60.45b, the owner or operator of the affected 

facility shall submit a signed statement with the report. 

(1) Indicating what removal efficiency by fuel pretreatment ( i.e. , %Rf) was credited during the 

reporting period; 

(2) Listing the quantity, heat content, and date each pre-treated fuel shipment was received 

during the reporting period, the name and location of the fuel pretreatment facility; and the total 

quantity and total heat content of all fuels received at the affected facility during the reporting 

period; 

(3) Documenting the transport of the fuel from the fuel pretreatment facility to the steam 

generating unit; and 

(4) Including a signed statement from the owner or operator of the fuel pretreatment facility 

certifying that the percent removal efficiency achieved by fuel pretreatment was determined in 

accordance with the provisions of Method 19 of appendix A of this part and listing the heat 

content and sulfur content of each fuel before and after fuel pretreatment. 

(o) All records required under this section shall be maintained by the owner or operator of the 

affected facility for a period of 2 years following the date of such record. 

(p) The owner or operator of an affected facility described in §60.44b(j) or (k) shall maintain 

records of the following information for each steam generating unit operating day: 

(1) Calendar date; 

(2) The number of hours of operation; and 

(3) A record of the hourly steam load. 

(q) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall 

submit to the Administrator a report containing: 

(1) The annual capacity factor over the previous 12 months; 

(2) The average fuel nitrogen content during the reporting period, if residual oil was fired; and 

(3) If the affected facility meets the criteria described in §60.44b(j), the results of any 

NOXemission tests required during the reporting period, the hours of operation during the 

reporting period, and the hours of operation since the last NOXemission test. 
(r) The owner or operator of an affected facility who elects to use the fuel based compliance 

alternatives in §60.42b or §60.43b shall either: 

(1) The owner or operator of an affected facility who elects to demonstrate that the affected 

facility combusts only very low sulfur oil, natural gas, wood, a mixture of these fuels, or any of 

these fuels (or a mixture of these fuels) in combination with other fuels that are known to contain 

an insignificant amount of sulfur in §60.42b(j) or §60.42b(k) shall obtain and maintain at the 

affected facility fuel receipts from the fuel supplier that certify that the oil meets the definition of 

distillate oil and gaseous fuel meets the definition of natural gas as defined in §60.41b and the 

applicable sulfur limit. For the purposes of this section, the distillate oil need not meet the fuel 

nitrogen content specification in the definition of distillate oil. Reports shall be submitted to the 

Administrator certifying that only very low sulfur oil meeting this definition, natural gas, wood, 

and/or other fuels that are known to contain insignificant amounts of sulfur were combusted in 

the affected facility during the reporting period; or 

(2) The owner or operator of an affected facility who elects to demonstrate compliance based on 

fuel analysis in §60.42b or §60.43b shall develop and submit a site-specific fuel analysis plan to 

the Administrator for review and approval no later than 60 days before the date you intend to 

demonstrate compliance. Each fuel analysis plan shall include a minimum initial requirement of 

weekly testing and each analysis report shall contain, at a minimum, the following information: 

(i) The potential sulfur emissions rate of the representative fuel mixture in ng/J heat input; 

(ii) The method used to determine the potential sulfur emissions rate of each constituent of the 

mixture. For distillate oil and natural gas a fuel receipt or tariff sheet is acceptable; 

(iii) The ratio of different fuels in the mixture; and 

(iv) The owner or operator can petition the Administrator to approve monthly or quarterly 

sampling in place of weekly sampling. 

(s) Facility specific NOXstandard 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 NOXemission 

limit for fossil fuel in §60.44b(a) applies. 
(ii) When natural gas and chemical by-product waste are simultaneously combusted, the 

NOXemission limit is 289 ng/J (0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet 

air provided for combustion shall be provided to the reducing zone of the C.AOG incinerator. 

(3) Emission monitoring . (i) The percent of total inlet air provided to the reducing zone shall be 

determined at least every 15 minutes by measuring the air flow of all the air entering the 

reducing zone and the air flow of all the air entering the oxidation zone, and compliance with the 

percentage of total inlet air that is provided to the reducing zone shall be determined on a 3-hour 

average basis. 

(ii) The NOXemission limit shall be determined by the compliance and performance test methods 

and procedures for NOXin §60.46b(i). 

(iii) The monitoring of the NOXemission limit shall be performed in accordance with §60.48b. 

(4) Reporting and recordkeeping requirements . (i) The owner or operator of the C.AOG 

incinerator shall submit a report on any excursions from the limits required by paragraph (a)(2) 

of this section to the Administrator with the quarterly report required by paragraph (i) of this 

section. 

(ii) The owner or operator of the C.AOG incinerator shall keep records of the monitoring 

required by paragraph (a)(3) of this section for a period of 2 years following the date of such 

record. 

(iii) The owner of operator of the C.AOG incinerator shall perform all the applicable reporting 

and recordkeeping requirements of this section. 

(t) Facility-specific NOXstandard 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 NOXburner 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 NOXemission 

limit for fossil fuel in §60.44b(a) applies. 

(ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the 

NOXemission 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 NOXemission limit shall be determined by the compliance and performance test methods 

and procedures for NOXin §60.46b. 

(iii) The monitoring of the NOXemission limit shall be performed in accordance with §60.48b. 

(4) Reporting and recordkeeping requirements . (i) The owner or operator of Boiler No. 100 

shall submit a report on any excursions from the limits required by paragraph (b)(2) of this 

section to the Administrator with the quarterly report required by §60.49b(i). 

(ii) The owner or operator of Boiler No. 100 shall keep records of the monitoring required by 

paragraph (b)(3) of this section for a period of 2 years following the date of such record. 

(iii) The owner of operator of Boiler No. 100 shall perform all the applicable reporting and 

recordkeeping requirements of §60.49b. 

(u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia . (1) This 

paragraph (u) applies only to the pharmaceutical manufacturing facility, commonly referred to as 

the Stonewall Plant, located at Route 340 South, in Elkton, Virginia (“site”) and only to the 

natural gas-fired boilers installed as part of the powerhouse conversion required pursuant to 40 

CFR 52.2454(g). The requirements of this paragraph shall apply, and the requirements of 

§§60.40b through 60.49b(t) shall not apply, to the natural gas-fired boilers installed pursuant to 

40 CFR 52.2454(g). 

(i) The site shall equip the natural gas-fired boilers with low NOXtechnology. 

(ii) The site shall install, calibrate, maintain, and operate a continuous monitoring and recording 

system for measuring NOXemissions discharged to the atmosphere and opacity using a 

continuous emissions monitoring system or a predictive emissions monitoring system. 

(iii) Within 180 days of the completion of the powerhouse conversion, as required by 40 CFR 

52.2454, the site shall perform a performance test to quantify criteria pollutant emissions. 

(2) [Reserved] 

(v) The owner or operator of an affected facility may submit electronic quarterly reports for 

SO2and/or NOXand/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 NOXstandard 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 NOXemission 

limit for fossil fuel in §60.44b(a) applies. 

(ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the 

NOXemission limit is 215 ng/J (0.5 lb/MMBtu). 

(2) Emission monitoring for nitrogen oxides . (i) The NOXemissions shall be determined by the 

compliance and performance test methods and procedures for NOXin §60.46b. 

(ii) The monitoring of the NOXemissions shall be performed in accordance with §60.48b. 

(3) Reporting and recordkeeping requirements . (i) The owner or operator of the No. 2 Power 

Boiler shall submit a report on any excursions from the limits required by paragraph (x)(2) of 

this section to the Administrator with the quarterly report required by §60.49b(i). 

(ii) The owner or operator of the No. 2 Power Boiler shall keep records of the monitoring 

required by paragraph (x)(3) of this section for a period of 2 years following the date of such 

record. 

(iii) The owner or operator of the No. 2 Power Boiler shall perform all the applicable reporting 

and recordkeeping requirements of §60.49b. 

(y) Facility-specific NOXstandard for INEOS USA's AOGI located in Lima, Ohio: 

(1) Standard for NO X. (i) When fossil fuel alone is combusted, the NOXemission limit for fossil 

fuel in §60.44b(a) applies. 

(ii) When fossil fuel and chemical byproduct/waste are simultaneously combusted, the 

NOXemission limit is 645 ng/J (1.5 lb/MMBtu). 

(2) Emission monitoring for NO X. (i) The NOXemissions shall be determined by the compliance 

and performance test methods and procedures for NOXin §60.46b. 

(ii) The monitoring of the NOXemissions shall be performed in accordance with §60.48b. 

(3) Reporting and recordkeeping requirements . (i) The owner or operator of the AOGI shall 

submit a report on any excursions from the limits required by paragraph (y)(2) of this section to 

the Administrator with the quarterly report required by paragraph (i) of this section. 

(ii) The owner or operator of the AOGI shall keep records of the monitoring required by 

paragraph (y)(3) of this section for a period of 2 years following the date of such record. 

(iii) The owner or operator of the AOGI shall perform all the applicable reporting and 

recordkeeping requirements of this section. 
Subpart Dc—Standards of Performance for Small Industrial-Commercial-Institutional Steam 

Generating Units 

§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, §60.48c(a)(4) shall be retained by the Administrator and not transferred to a State. 

(c) Steam generating units that meet the applicability requirements in paragraph (a) of this section are 

not subject to the sulfur dioxide (SO2) or particulate matter (PM) emission limits, performance testing 

requirements, or monitoring requirements under this subpart (§§60.42c, 60.43c, 60.44c, 60.45c, 

60.46c, or 60.47c) during periods of combustion research, as defined in §60.41c. 

(d) Any temporary change to an existing steam generating unit for the purpose of conducting 

combustion research is not considered a modification under §60.14. 

(e) Heat recovery steam generatorAffected facilitiess (i.e. heat recovery steam generators and fuel 

heaters) that are associated with combined cycle gasstationary combustion turbines and meet the 

applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart 

will continue to apply to all other heat recovery steam generators, fuel heaters, and other affected 

facilities that are capable of combusting more than or equal to 2.9 MW (10 MMBtu/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, fuel heater, or other affected facility is subject to this subpart, only 

emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. 

(The gas stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, 

of this part). 

(f) Any affected facility that meets the applicability requirements and covered byis subject to subpart 

AAAA or subpart CCCC of this part is not subject byto this subpart. 

(g) Any facility that meets the applicability requirements and is subject to covered by an EPA 

approved State or Federal section 111(d)/129 plan implementing subpart BBBB of this part is not 

subject byto this subpart. 

§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 

Comment [CF1]: Clarify broad definition to be

consistent with broad definition of affected facility

under KKKK – fuel heater, etc.

Comment [CF2]: Exempt owner/operators of

CISWI facilities from subpart Dc  
based on the combined heat input from all operations of the affected facility during a period of 12 

consecutive calendar months. 

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the 

American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), 

coal refuse, and petroleum coke. Coal-derived synthetic fuels derived from coal for the purposes of 

creating useful heat, including but not limited to solvent refined coal, gasified coal not meeting the 

definition of natural gas, coal-oil mixtures, and coal-water mixtures, are also included in this definition 

for the purposes of this subpart. 

Coal refuse means any by-product of coal mining or coal cleaning operations with an ash content 

greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram 

(kJ/kg) (6,000 Btu per pound (Btu/lb) on a dry basis. 

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 stationary gas turbine, 

internal combustion engine, or kiln) provides exhaust gas to a steam generating unit. 

Combustion research means the experimental firing of any fuel or combination of fuels in a steam 

generating unit for the purpose of conducting research and development of more efficient combustion 

or more effective prevention or control of air pollutant emissions from combustion, provided that, 

during these periods of research and development, the heat generated is not used for any purpose other 

than preheating combustion air for use by that steam generating unit ( i.e. , the heat generated is 

released to the atmosphere without being used for space heating, process heating, driving pumps, 

preheating combustion air for other units, generating electricity, or any other purpose). 

Conventional technology means wet flue gas desulfurization technology, dry flue gas desulfurization 

technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization 

technology. 

Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined 

by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see 

§60.17), 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 §60.17), kerosene, as defined by the 

American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see §60.17), 

biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated 

by reference, see §60.17), or biodiesel blends as defined by the American Society of Testing and 

Materials in ASTM D7467 (incorporated by reference, see §60.17). 

Dry flue gas desulfurization technology means a SO2control 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. 

Comment [CF3]: Delete since not used in

subpart Dc.

Comment [CF4]: Expand definitions to include

other similar fuels.  Need to amend 60.17 as well.
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 SO2control system that is not defined as a conventional technology 

under this section, and for which the owner or operator of the affected facility has received approval 

from the Administrator to operate as an emerging technology under §60.48c(a)(4). 

Federally enforceable means all limitations and conditions that are enforceable by the Administrator, 

including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State 

implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 

51.18 and 51.24. 

Fluidized bed combustion technology means a device wherein fuel is distributed onto a bed (or series 

of beds) of limestone aggregate (or other sorbent materials) for combustion; and these materials are 

forced upward in the device by the flow of combustion air and the gaseous products of combustion. 

Fluidized bed combustion technology includes, but is not limited to, bubbling bed units and circulating 

bed units. 

Fuel pretreatment means a process that removes a portion of the sulfur in a fuel before combustion of 

the fuel in a steam generating unit. 

Heat input means heat derived from combustion of fuel in a steam generating unit and does not include 

the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases from other 

sources (such as stationary gas turbines, internal combustion engines, and kilns). 

Heat transfer medium means any material that is used to transfer heat from one point to another point. 

Maximum design heat input capacity means the ability of a steam generating unit to combust a stated 

maximum amount of fuel (or combination of fuels) on a steady state basis as determined by the 

physical design and characteristics of the steam generating unit. 

Natural gas means: 

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic 

formations beneath the earth's surface, of which the principal constituent is methane; or 

(2) Liquefied petroleum (LP) gas, as defined by the American Society for Testing and Materials in 

ASTM D1835 (incorporated by reference, see §60.17); or 

(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural 

gas must either be composed of at least 70 percent methane by volume or have a gross calorific value 

between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard 

cubic foot). 

Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the 

Commonwealth of Puerto Rico, or the Northern Mariana Islands. 

Oil means crude oil or petroleum, or a liquid fuel derived from crude oil or petroleum, including 

distillate oil and residual oil. 

Comment [CF5]: Request comment on deleting

fuel treatment references in both Db & Dc.
Potential sulfur dioxide emission rate means the theoretical SO2emissions (nanograms per joule (ng/J) 

or lb/MMBtu heat input) that would result from combusting fuel in an uncleaned state and without 

using emission control systems. 

Process heater means a device that is primarily used to heat a material to initiate or promote a 

chemical reaction in which the material participates as a reactant or catalyst. 

Residual oil means crude oil, fuel oil that does not comply with the specifications under the definition 

of distillate oil, and all fuel oil numbers 4, 5, and 6, as defined by the American Society for Testing and 

Materials in ASTM D396 (incorporated by reference, see §60.17). 

Steam generating unit means a device that combusts any fuel and produces steam or heats water or 

heats any heat transfer medium. This term includes any duct burner that combusts fuel and is part of a 

combined cycle system. This term does not include process heaters as defined in this subpart. 

Steam generating unit operating day means a 24-hour period between 12:00 midnight and the 

following midnight during which any fuel is combusted at any time in the steam generating unit. It is 

not necessary for fuel to be combusted continuously for the entire 24-hour period. 

Wet flue gas desulfurization technology means an SO2control 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. 

§60.42c Standard for sulfur dioxide (SO2). 

(a) Except as provided in paragraphs (b), (c), and (e) of this section, on and after the date on which the 

performance test is completed or required to be completed under §60.8, whichever date comes first, the 

owner or operator of an affected facility that combusts only coal shall neither: cause to be discharged 

into the atmosphere from the affected facility any gases that contain SO2in excess of 87 ng/J (0.20 

lb/MMBtu) heat input or 10 percent (0.10) of the potential SO2emission rate (90 percent reduction), 

nor cause to be discharged into the atmosphere from the affected facility any gases that contain SO2in 

excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected 

facility shall neither: cause to be discharged into the atmosphere from the affected facility any gases 

that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential 

SO2emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the 

affected facility any gases that contain SO2in excess of the emission limit is determined pursuant to 

paragraph (e)(2) of this section. 

Comment [CF6]: Should subpart Db be

amended to be consistent and use “only” as well?
(b) Except as provided in paragraphs (c) and (e) of this section, on and after the date on which the 

performance test is completed or required to be completed under §60.8, whichever date comes first, the 

owner or operator of an affected facility that: 

(1) Combusts only coal refuse alone in a fluidized bed combustion steam generating unit shall neither: 

(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

excess of 87 ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO2emission rate 

(80 percent reduction); nor 

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

excess of SO2in 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 

SO2emissions limit or the 90 percent SO2reduction 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 SO2emissions shall 

neither: 

(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

excess of 50 percent (0.50) of the potential SO2emission rate (50 percent reduction); nor 

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

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 SO2reduction requirement specified in this paragraph and the 

emission limit determined pursuant to paragraph (e)(2) of this section. 

(c) On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator of an affected facility that combusts 

coal, alone or in combination with any other fuel, and is listed in paragraphs (c)(1), (2), (3), or (4) of 

this section shall cause to be discharged into the atmosphere from that affected facility any gases that 

contain SO2in 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; or.

(4) Affected facilities that combust coal in a duct burner as part of a combined cycle system where 30 

percent (0.30) or less of the heat entering the steam generating unit is from combustion of coal in the 

duct burner and 70 percent (0.70) or more of the heat entering the steam generating unit is from 

exhaust gases entering the duct burner. 

(d) On and after the date on which the initial performance test is completed or required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 
combusts oil shall cause to be discharged into the atmosphere from that affected facility any gases that 

contain SO2in excess of 215 ng/J (0.50 lb/MMBtu) heat input from oil; or, as an alternative, no owner 

or operator of an affected facility that combusts oil shall combust oil in the affected facility that 

contains greater than 0.5 weight percent sulfur. The percent reduction requirements are not applicable 

to affected facilities under this paragraph. 

(e) On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator of an affected facility that combusts 

coal, oil, or coal and oil with any other fuel shall cause to be discharged into the atmosphere from that 

affected facility any gases that contain SO2in excess of the following: 

(1) The percent of potential SO2emission rate or numerical SO2emission 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: 

Where: 

Es= SO2emission 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 SO2emission 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 SO2emission 

rate; and 

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.

Comment [CF7]: Clarify that cannot dilute with

natural gas

Comment [CF8]: Could be made easier to

understand?
(2) Emissions from the pretreated fuel (without either combustion or post-combustion SO2control) 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), or (4) of this section, compliance 

with the emission limits or fuel oil sulfur limits under this section may be determined based on a 

certification from the fuel supplier, as described under §60.48c(f), as applicable. 

(1) Distillate oil-fired affected facilities with heat input capacities between 2.9 and 29 MW (10 and 100 

MMBtu/hr). 

(2) Residual oil-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 

MMBtu/hr). 

(3) Coal-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 

MMBtu/hr).

(4) Other fuels-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 

MMBtu/hr).

(i) The SO2emission 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. 

§60.43c Standard for particulate matter (PM). 

(a) On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced 

construction, reconstruction, or modification on or before February 28, 2005, that combusts coal or 

combusts mixtures of coal with other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/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 §60.8, whichever date comes first, no owner or operator of an affected facility that 

Comment [CF9]: Add to be consistent with

60.48c(f)

Comment [CF10]: If deleted this would allow

fuel mixing in noncontinental areas

Comment [CF11]: 

“can combust” instead of “combusts”

Make consistent with permits that allow

combustion of alternate fuels – check with OECA
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 §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 §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 §60.8, whichever date comes first, no owner or 

operator of an affected facility that commences modification after February 28, 2005 shall cause to be 

discharged into the atmosphere from that affected facility any gases that contain PM in excess of both: 

(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of 

these fuels, or a mixture of these fuels with any other fuels; and 

(ii) 0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, 

wood, a mixture of these fuels, or a mixture of these fuels with any other fuels. 

(3) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 

commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat 

input) on an annual basis and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater shall 

Comment [CF12]: “can combust” instead of

“combusts”

Formatted: Highlight
cause to be discharged into the atmosphere from that affected facility any gases that contain PM in 

excess of 43 ng/J (0.10 lb/MMBtu) heat input. 

(4) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, aAn owner or operator of an affected facility that 

commences construction, reconstruction, or modification after February 28, 2005, and that combusts 

only oil that contains no more than 0.50 weight percent sulfur or a mixture of 0.50 weight percent 

sulfur oil with other fuels not subject to a PM standard under §60.43c and not using a post-combustion 

technology (except a wet scrubber) to reduce PM or SO2emissions is not subject to the PM limit in this 

section. 

§60.44c Compliance and performance test methods and procedures for sulfur dioxide. 

(a) Except as provided in paragraphs (g) and (h) of this section and §60.8(b), performance tests 

required under §60.8 shall be conducted following the procedures specified in paragraphs (b), (c), (d), 

(e), and (f) of this section, as applicable. Section 60.8(f) does not apply to this section. The 30-day 

notice required in §60.8(d) applies only to the initial performance test unless otherwise specified by the 

Administrator. 

(b) The initial performance test required under §60.8 shall be conducted over 30 consecutive operating 

days of the steam generating unit. Compliance with the percent reduction requirements and 

SO2emission limits under §60.42c shall be determined using a 30-day average. The first operating day 

included in the initial performance test shall be scheduled within 30 days after achieving the maximum 

production rate at which the affect facility will be operated, but not later than 180 days after the initial 

startup of the facility. The steam generating unit load during the 30-day period does not have to be the 

maximum design heat input capacity, but must be representative of future operating conditions. 

(c) After the initial performance test required under paragraph (b) of this section and §60.8, 

compliance with the percent reduction requirements and SO2emission limits under §60.42c is based on 

the average percent reduction and the average SO2emission 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 SO2emission 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 SO2emission rate 

(Eho) and the 30-day average SO2emission 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 

Eaowhen 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: 

Where: 

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Comment [CF13]: Check with OECA
Ehoo = Adjusted Eho, ng/J (lb/MMBtu); 

Eho= Hourly SO2emission rate, ng/J (lb/MMBtu); 

Ew= SO2concentration 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 Ewfor 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 Ewif the owner or operator elects to 

assume Ew= 0. 

Xk= Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by 

applicable procedures in Method 19 of appendix A of this part. 

(2) The owner or operator of an affected facility that qualifies under the provisions of §60.42c(c) or (d) 

(where percent reduction is not required) does not have to measure the parameters Ewor Xkif the owner 

or operator of the affected facility elects to measure emission rates of the coal or oil using the fuel 

sampling and analysis procedures under Method 19 of appendix A of this part. 

(f) Affected facilities subject to the percent reduction requirements under §60.42c(a) or (b) shall 

determine compliance with the SO2emission limits under §60.42c pursuant to paragraphs (d) or (e) of 

this section, and shall determine compliance with the percent reduction requirements using the 

following procedures: 

(1) If only coal is combusted, the percent of potential SO2emission rate is computed using the 

following formula: 

Where: 

%Ps= Potential SO2emission rate, in percent; 

%Rg= SO2removal efficiency of the control device as determined by Method 19 of appendix A of this 

part, in percent; and 

%Rf= SO2removal 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 SO2inlet rate (Eaio) using the following formula: 

Where: 

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The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted. Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.
%Rgo = Adjusted %Rg, in percent; 

Eaoo = Adjusted Eao, ng/J (lb/MMBtu); and 

Eaio = Adjusted average SO2inlet rate, ng/J (lb/MMBtu). 

(ii) To compute Eaio, an adjusted hourly SO2inlet rate (Ehio) is used. The Ehio is computed using the 

following formula: 

Where: 

Ehio = Adjusted Ehi, ng/J (lb/MMBtu); 

Ehi= Hourly SO2inlet rate, ng/J (lb/MMBtu); 

Ew= SO2concentration 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 Ewfor 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 Ewif the owner or operator elects to 

assume Ew= 0; and 

Xk= Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by 

applicable procedures in Method 19 of appendix A of this part. 

(g) For oil-fired affected facilities where the owner or operator seeks to demonstrate compliance with 

the fuel oil sulfur limits under §60.42c based on shipment fuel sampling, the initial performance test 

shall consist of sampling and analyzing the oil in the initial tank of oil to be fired in the steam 

generating unit to demonstrate that the oil contains 0.5 weight percent sulfur or less. Thereafter, the 

owner or operator of the affected facility shall sample the oil in the fuel tank after each new shipment 

of oil is received, as described under §60.46c(d)(2). 

(h) For affected facilities subject to §60.42c(h)(1), (2), or (3) where the owner or operator seeks to 

demonstrate compliance with the SO2standards based on fuel supplier certification, the performance 

test shall consist of the certification from the fuel supplier, as described in §60.48c(f), as applicable. 

(i) The owner or operator of an affected facility seeking to demonstrate compliance with the 

SO2standards under §60.42c(c)(2) shall demonstrate the maximum design heat input capacity of the 

steam generating unit by operating the steam generating unit at this capacity for 24 hours. This 

demonstration shall be made during the initial performance test, and a subsequent demonstration may 

be requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility 

is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, 

the demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for 

the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer 

shall be used. 

(j) The owner or operator of an affected facility shall use all valid SO2emissions data in calculating 

%Psand Ehounder paragraphs (d), (e), or (f) of this section, as applicable, whether or not the minimum 

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emissions data requirements under §60.46c(f) are achieved. All valid emissions data, including valid 

data collected during periods of startup, shutdown, and malfunction, shall be used in calculating %Psor 

Ehopursuant to paragraphs (d), (e), or (f) of this section, as applicable. 

§60.45c Compliance and performance test methods and procedures for particulate matter. 

(a) The owner or operator of an affected facility subject to the PM and/or opacity standards under 

§60.43c shall conduct an initial performance test as required under §60.8, and shall conduct subsequent 

performance tests as requested by the Administrator, to determine compliance with the standards using 

the following procedures and reference methods, except as specified in paragraph (c) of this section. 

(1) Method 1 of appendix A of this part shall be used to select the sampling site and the number of 

traverse sampling points. 

(2) Method 3A or 3B of appendix A–2 of this part shall be used for gas analysis when applying 

Method 5 or 5B of appendix A–3 of this part or 17 of appendix A–6 of this part. 

(3) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as 

follows: 

(i) Method 5 of appendix A of this part may be used only at affected facilities without wet scrubber 

systems. 

(ii) Method 17 of appendix A of this part may be used at affected facilities with or without wet 

scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C (320 

°F). The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of this part may be used in 

Method 17 of appendix A of this part only if Method 17 of appendix A of this part is used in 

conjunction with a wet scrubber system. Method 17 of appendix A of this part shall not be used in 

conjunction with a wet scrubber system if the effluent is saturated or laden with water droplets. 

(iii) Method 5B of appendix A of this part may be used in conjunction with a wet scrubber system. 

(4) The sampling time for each run shall be at least 120 minutes and the minimum sampling volume 

shall be 1.7 dry standard cubic meters (dscm) [60 dry standard cubic feet (dscf)] except that smaller 

sampling times or volumes may be approved by the Administrator when necessitated by process 

variables or other factors. 

(5) For Method 5 or 5B of appendix A of this part, the temperature of the sample gas in the probe and 

filter holder shall be monitored and maintained at 160 ±14 °C (320±25 °F). 

(6) For determination of PM emissions, an oxygen (O2) or carbon dioxide (CO2) measurement shall be 

obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing 

the duct at the same sampling location. 

(7) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rates expressed in 

ng/J (lb/MMBtu) heat input shall be determined using: 

(i) The O2or CO2measurements and PM measurements obtained under this section, (ii) The dry basis F 

factor, and 
(iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this 

part. 

(8) Method 9 of appendix A–4 of this part shall be used for determining the opacity of stack emissions. 

(b) The owner or operator of an affected facility seeking to demonstrate compliance with the PM 

standards under §60.43c(b)(2) shall demonstrate the maximum design heat input capacity of the steam 

generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration 

shall be made during the initial performance test, and a subsequent demonstration may be requested at 

any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the 

maximum design heat input capacity stated by the manufacturer of the affected facility, the 

demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the 

affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer 

shall be used. 

(c) In place of PM testing with Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix 

A–6 of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for 

monitoring PM emissions discharged to the atmosphere and record the output of the system. The 

owner or operator of an affected facility who elects to continuously monitor PM emissions instead of 

conducting performance testing using Method 5 or 5B of appendix A–3 of this part or Method 17 of 

appendix A–6 of this part shall install, calibrate, maintain, and operate a CEMS and shall comply with 

the requirements specified in paragraphs (c)(1) through (c)(14) of this section. 

(1) Notify the Administrator 1 month before starting use of the system. 

(2) Notify the Administrator 1 month before stopping use of the system. 

(3) The monitor shall be installed, evaluated, and operated in accordance with §60.13 of subpart A of 

this part. 

(4) The initial performance evaluation shall be completed no later than 180 days after the date of initial 

startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of 

notification to the Administrator of use of CEMS if the owner or operator was previously determining 

compliance by Method 5, 5B, or 17 of appendix A of this part performance tests, whichever is later. 

(5) The owner or operator of an affected facility shall conduct an initial performance test for PM 

emissions as required under §60.8 of subpart A of this part. Compliance with the PM emission limit 

shall be determined by using the CEMS specified in paragraph (d) of this section to measure PM and 

calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 

19 of appendix A of this part, section 4.1. 

(6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) 

average of the hourly arithmetic average emission concentrations using CEMS outlet data. 

(7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraph (c)(7)(i) of 

this section for 75 percent of the total operating hours per 30-day rolling average. 

(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average. 

(ii) [Reserved] 
(8) The 1-hour arithmetic averages required under paragraph (c)(7) of this section shall be expressed in 

ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic 

average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data 

points required under §60.13(e)(2) of subpart A of this part. 

(9) All valid CEMS data shall be used in calculating average emission concentrations even if the 

minimum CEMS data requirements of paragraph (c)(7) of this section are not met. 

(10) The CEMS shall be operated according to Performance Specification 11 in appendix B of this 

part. 

(11) During the correlation testing runs of the CEMS required by Performance Specification 11 in 

appendix B of this part, PM and O2(or CO2) data shall be collected concurrently (or within a 30- to 60-

minute period) by both the continuous emission monitors and performance tests conducted using the 

following test methods. 

(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part 

shall be used; and 

(ii) For O2 (or CO2), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. 

(12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in 

accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed 

annually and Response Correlation Audits must be performed every 3 years. 

(13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring 

systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to 

provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours on a 

30-day rolling average. 

(14) As of January 1, 2012 and within 60 days after the date of completing each performance test, as 

defined in §63.2, conducted to demonstrate compliance with this subpart, you must submit relative 

accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, 

except opacity data, electronically to EPA’s Central Data Exchange (CDX) by using the Electronic 

Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or other compatible 

electronic spreadsheet. Only data collected using test methods compatible with ERT are subject to this 

requirement to be submitted electronically into EPA’s WebFIRE database.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 

§60.43c(e)(4) shall follow the applicable procedures under §60.48c(f). For residual oil-fired affected 

facilities, fuel supplier certifications are only allowed for facilities with heat input capacities between 

2.9 and 8.7 MW (10 to 30 MMBtu/hr). 

Comment [CF14]: Updated language for

electronic reporting.
§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 SO2emission limits under §60.42c shall install, calibrate, maintain, and operate a 

CEMS for measuring SO2concentrations and either O2or CO2concentrations at the outlet of the 

SO2control device (or the outlet of the steam generating unit if no SO2control device is used), and shall 

record the output of the system. The owner or operator of an affected facility subject to the percent 

reduction requirements under §60.42c shall measure SO2concentrations and either O2or 

CO2concentrations at both the inlet and outlet of the SO2control device. 

(b) The 1-hour average SO2emission rates measured by a CEMS shall be expressed in ng/J or 

lb/MMBtu heat input and shall be used to calculate the average emission rates under §60.42c. Each 1-

hour average SO2emission rate must be based on at least 30 minutes of operation, and shall be 

calculated using the data points required under §60.13(h)(2). Hourly SO2emission rates are not 

calculated if the affected facility is operated less than 30 minutes in a 1-hour period and are not 

counted toward determination of a steam generating unit operating day. 

(c) The procedures under §60.13 shall be followed for installation, evaluation, and operation of the 

CEMS. 

(1) All CEMS shall be operated in accordance with the applicable procedures under Performance 

Specifications 1, 2, and 3 of appendix B of this part. 

(2) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance 

with Procedure 1 of appendix F of this part. 

(3) For affected facilities subject to the percent reduction requirements under §60.42c, the span value 

of the SO2CEMS at the inlet to the SO2control device shall be 125 percent of the maximum estimated 

hourly potential SO2emission rate of the fuel combusted, and the span value of the SO2CEMS at the 

outlet from the SO2control device shall be 50 percent of the maximum estimated hourly potential 

SO2emission rate of the fuel combusted. 

(4) For affected facilities that are not subject to the percent reduction requirements of §60.42c, the span 

value of the SO2CEMS at the outlet from the SO2control device (or outlet of the steam generating unit 

if no SO2control device is used) shall be 125 percent of the maximum estimated hourly potential 

SO2emission rate of the fuel combusted. 

(d) As an alternative to operating a CEMS at the inlet to the SO2control device (or outlet of the steam 

generating unit if no SO2control device is used) as required under paragraph (a) of this section, an 

owner or operator may elect to determine the average SO2emission rate by sampling the fuel prior to 

combustion. As an alternative to operating a CEMS at the outlet from the SO2control device (or outlet 

of the steam generating unit if no SO2control device is used) as required under paragraph (a) of this 

section, an owner or operator may elect to determine the average SO2emission 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 asfired 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 

SO2input 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 SO2at the inlet or 

outlet of the SO2control 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 SO2and CO2measurement train operated at the candidate location and a 

second similar train operated according to the procedures in §3.2 and the applicable procedures in 

section 7 of Performance Specification 2 of appendix B of this part. Method 6B of appendix A of this 

part, Method 6A of appendix A of this part, or a combination of Methods 6 and 3 of appendix A of this 

part or Methods 6C and 3A of appendix A of this part are suitable measurement techniques. If Method 

6B of appendix A of this part is used for the second train, sampling time and timer operation may be 

adjusted for the stratification test as long as an adequate sample volume is collected; however, both 

sampling trains are to be operated similarly. For the location to be adequate for Method 6B of appendix 

A of this part 24-hour tests, the mean of the absolute difference between the three paired runs must be 

less than 10 percent (0.10). 

(e) The monitoring requirements of paragraphs (a) and (d) of this section shall not apply to affected 

facilities subject to §60.42c(h) (1), (2), or (3) where the owner or operator of the affected facility seeks 

to demonstrate compliance with the SO2standards based on fuel supplier certification, as described 

under §60.48c(f), as applicable. 

(f) The owner or operator of an affected facility operating a CEMS pursuant to paragraph (a) of this 

section, or conducting as-fired fuel sampling pursuant to paragraph (d)(1) of this section, shall obtain 

emission data for at least 75 percent of the operating hours in at least 22 out of 30 successive steam 

generating unit operating days. If this minimum data requirement is not met with a single monitoring 

system, the owner or operator of the affected facility shall supplement the emission data with data 

collected with other monitoring systems as approved by the Administrator. 

§60.47c Emission monitoring for particulate matter. 

(a) Except as provided in paragraphs (c), (d), (e), (f), and (g), and (h) of this section, the owner or 

operator of an affected facility combusting coal, oil, or wood that is subject to the opacity standards 

under §60.43c shall install, calibrate, maintain, and operate a continuous opacity monitoring system 

(COMS) for measuring the opacity of the emissions discharged to the atmosphere and record the 

output of the system. The owner or operator of an affected facility subject to an opacity standard in 

§60.43c(c) that is not required to use a COMS due to paragraphs (c), (d), (e), or (f), or (g) of this 

section that elects not to use a COMS shall conduct a performance test using Method 9 of appendix A–
4 of this part and the procedures in §60.11 to demonstrate compliance with the applicable limit in 

§60.43c by April 29, 2011, within 45 days of stopping use of an existing COMS, or within 180 days 

after initial startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), 

(a)(2), or (a)(3) of this section. The observation period for Method 9 of appendix A-4 of this part 

performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 

percent and all individual 15-second observations are less than or equal to 20 percent during the initial 

60 minutes of observation.. 

(1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall 

conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in 

paragraph (a) of this section according to the applicable schedule in paragraphs (a)(1)(i) through 

(a)(1)(iv) of this section, as determined by the most recent Method 9 of appendix A–4 of this part 

performance test results. 

(i) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 12 calendar months from the date that the most recent 

performance test was conducted or within 45 days of the next day that fuel with an opacity standard is 

combusted, whichever is later; 

(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal 

to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed 

within 6 calendar months from the date that the most recent performance test was conducted; 

(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 45 calendar days from the date 

that the most recent performance test was conducted. 

(2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent 

monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in 

paragraphs (a)(2)(i) and (ii) of this section. 

(i) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using Method 

22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible 

emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute 

period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the 

initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the 

occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds 

per 30 minute period) the owner or operator shall either document and adjust the operation of the 

facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to 

or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of 

appendix A–4 of this part performance test using the procedures in paragraph (a) of this section within 

45 calendar days according to the requirements in §60.45c(a)(8). 

Comment [CF15]: Allow flexibility to account

for intermittent use of fuels with an opacity

standard.
(ii) 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. 

(3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing 

subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring 

using a digital opacity compliance system according to a site-specific monitoring plan approved by the 

Administrator. The observations shall be similar, but not necessarily identical, to the requirements in 

paragraph (a)(2) of this section. For reference purposes in preparing the monitoring plan, see OAQPS 

“Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based 

Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection 

Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs 

Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document 

is also available on the Technology Transfer Network (TTN) under Emission Measurement Center 

Preliminary Methods. 

(b) All COMS shall be operated in accordance with the applicable procedures under Performance 

Specification 1 of appendix B of this part. The span value of the opacity COMS shall be between 60 

and 80 percent. 

(c) Owners and operators of an affected facilities that burn only distillate oil that contains no more than 

0.5 weight percent sulfur and/or liquid or gaseous fuels with potential sulfur dioxide emission rates of 

26 ng/J (0.060 lb/MMBtu) heat input or less and that do not use a post-combustion technology to 

reduce SO2 or PM emissions and that are subject to an opacity standard in §60.43c(c) are not required 

to operate a COMS if they follow the applicable procedures in §60.48c(f). 

(d) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, 

maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere 

as specified in §60.45c(c). The CEMS specified in paragraph §60.45c(c) shall be operated and data 

recorded during all periods of operation of the affected facility except for CEMS breakdowns and 

repairs. Data is recorded during calibration checks, and zero and span adjustments. 

(e) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and 

that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO2, or carbon 

monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 

weight percent sulfur, and is operated such that emissions of CO discharged to the atmosphere from 

the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating 

day average basis is not required to operate a COMS. Owners and operators of affected facilities 

electing to comply with this paragraph must demonstrate compliance according to the procedures 

specified in paragraphs (e)(1) through (4) of this section; or 

(1) You must monitor CO emissions using a CEMS according to the procedures specified in 

paragraphs (e)(1)(i) through (iv) of this section. 

(i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in 

§60.58b(i)(3) of subpart Eb of this part. 

(ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS 

expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 
(iii) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the 

operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data 

points required in §60.13(h)(2). 

(iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(2) You must calculate the 1-hour average CO emissions levels for each steam generating unit 

operating day by multiplying the average hourly CO output concentration measured by the CO CEMS 

times the corresponding average hourly flue gas flow rate and divided by the corresponding average 

hourly heat input to the affected source. The 24-hour average CO emission level is determined by 

calculating the arithmetic average of the hourly CO emission levels computed for each steam 

generating unit operating day. 

(3) You must evaluate the preceding 24-hour average CO emission level each steam generating unit 

operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour 

average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the 

relevant equipment and control systems within 24 hours of the first discovery of the high emission 

incident and, take the appropriate corrective action as soon as practicable to adjust control settings or 

repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less. 

(4) You must record the CO measurements and calculations performed according to paragraph (e) of 

this section and any corrective actions taken. The record of corrective action taken must include the 

date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, 

and the date, time, and description of the corrective action. 

(f) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and 

that uses a bag leak detection system to monitor the performance of a fabric filter (baghouse) according 

to the most recent current requirements in section §60.48Da of this part is not required to operate a 

COMS. 

(g) The affected facility uses an ESP as the primary PM control device and uses an ESP predictive 

model to monitor the performance of the ESP developed in accordance and operated according to the 

most current requirements in section §60.48Da of this part.

(hg) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) 

and that burns only gaseous fuels and/or fuel oils that contain less than or equal to 0.5 weight percent 

sulfur and operates according to a written site-specific monitoring plan approved by the permitting 

authority is not required to operate a COMS. This monitoring plan must include procedures and 

criteria for establishing and monitoring specific parameters for the affected facility indicative of 

compliance with the opacity standard. 

§60.48c Reporting and recordkeeping requirements. 

(a) The owner or operator of each affected facility shall submit notification of the date of construction 

or reconstruction and actual startup, as provided by §60.7 of this part. This notification shall include: 

(1) The design heat input capacity of the affected facility and identification of fuels to be combusted in 

the affected facility. 

Comment [CF16]: Add ESP model to COMS

exemption options

Comment [CF17]: Clarify can burn gaseous fuels

along with low S oil
(2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor 

for any fuel or mixture of fuels under §60.42c, or §60.43c. 

(3) The annual capacity factor at which the owner or operator anticipates operating the affected facility 

based on all fuels fired and based on each individual fuel fired. 

(4) Notification if an emerging technology will be used for controlling SO2emissions. The 

Administrator will examine the description of the control device and will determine whether the 

technology qualifies as an emerging technology. In making this determination, the Administrator may 

require the owner or operator of the affected facility to submit additional information concerning the 

control device. The affected facility is subject to the provisions of §60.42c(a) or (b)(1), unless and until 

this determination is made by the Administrator. 

(b) The owner or operator of each affected facility subject to the SO2emission limits of §60.42c, or the 

PM or opacity limits of §60.43c, shall submit to the Administrator the performance test data from the 

initial and any subsequent performance tests and, if applicable, the performance evaluation of the 

CEMS and/or COMS using the applicable performance specifications in appendix B of this part. 

(c) In addition to the applicable requirements in §60.7, the owner or operator of an affected facility 

subject to the opacity limits in §60.43c(c) shall submit excess emission reports for any excess 

emissions from the affected facility that occur during the reporting period and maintain records 

according to the requirements specified in paragraphs (c)(1) through (3) of this section, as applicable to 

the visible emissions monitoring method used. 

(1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (c)(1)(i) through (iii) 

of this section. 

(i) Dates and time intervals of all opacity observation periods; 

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible 

emission observer participating in the performance test; and 

(iii) Copies of all visible emission observer opacity field data sheets; 

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (c)(2)(i) through (iv) 

of this section. 

(i) Dates and time intervals of all visible emissions observation periods; 

(ii) Name and affiliation for each visible emission observer participating in the performance test; 

(iii) Copies of all visible emission observer opacity field data sheets; and 

(iv) Documentation of any adjustments made and the time the adjustments were completed to the 

affected facility operation by the owner or operator to demonstrate compliance with the applicable 

monitoring requirements. 
(3) For each digital opacity compliance system, the owner or operator shall maintain records and 

submit reports according to the requirements specified in the site-specific monitoring plan approved by 

the Administrator 

(d) The owner or operator of each affected facility subject to the SO2emission limits, fuel oil sulfur 

limits, or percent reduction requirements under §60.42c shall submit reports to the Administrator. 

(e) The owner or operator of each affected facility subject to the SO2emission limits, fuel oil sulfur 

limits, or percent reduction requirements under §60.42c shall keep records and submit reports as 

required under paragraph (d) of this section, including the following information, as applicable. 

(1) Calendar dates covered in the reporting period. 

(2) Each 30-day average SO2emission rate (ng/J or lb/MMBtu), or 30-day average sulfur content 

(weight percent), calculated during the reporting period, ending with the last 30-day period; reasons for 

any noncompliance with the emission standards; and a description of corrective actions taken. 

(3) Each 30-day average percent of potential SO2emission rate calculated during the reporting period, 

ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a 

description of the corrective actions taken. 

(4) Identification of any steam generating unit operating days for which SO2or diluent (O2or CO2) data 

have not been obtained by an approved method for at least 75 percent of the operating hours; 

justification for not obtaining sufficient data; and a description of corrective actions taken. 

(5) Identification of any times when emissions data have been excluded from the calculation of 

average emission rates; justification for excluding data; and a description of corrective actions taken if 

data have been excluded for periods other than those during which coal or oil were not combusted in 

the steam generating unit. 

(6) Identification of the F factor used in calculations, method of determination, and type of fuel 

combusted. 

(7) Identification of whether averages have been obtained based on CEMS rather than manual 

sampling methods. 

(8) If a CEMS is used, identification of any times when the pollutant concentration exceeded the full 

span of the CEMS. 

(9) If a CEMS is used, description of any modifications to the CEMS that could affect the ability of the 

CEMS to comply with Performance Specifications 2 or 3 of appendix B of this part. 

(10) If a CEMS is used, results of daily CEMS drift tests and quarterly accuracy assessments as 

required under appendix F, Procedure 1 of this part. 

(11) If fuel supplier certification is used to demonstrate compliance, records of fuel supplier 

certification as described under paragraph (f)(1), (2), (3), or (4) of this section, as applicable. In 

addition to records of fuel supplier certifications, the report shall include a certified statement signed 

by the owner or operator of the affected facility that the records of fuel supplier certifications 

submitted represent all of the fuel combusted during the reporting period. 
(f) Fuel supplier certification shall include the following information: 

(1) For distillate oil: 

(i) The name of the oil supplier; 

(ii) A statement from the oil supplier that the oil complies with the specifications under the definition 

of distillate oil in §60.41c; and 

(iii) The sulfur content or maximum sulfur content of the oil. 

(2) For residual oil: 

(i) The name of the oil supplier; 

(ii) The location of the oil when the sample was drawn for analysis to determine the sulfur content of 

the oil, specifically including whether the oil was sampled as delivered to the affected facility, or 

whether the sample was drawn from oil in storage at the oil supplier's or oil refiner's facility, or other 

location; 

(iii) The sulfur content of the oil from which the shipment came (or of the shipment itself); and 

(iv) The method used to determine the sulfur content of the oil. 

(3) For coal: 

(i) The name of the coal supplier; 

(ii) The location of the coal when the sample was collected for analysis to determine the properties of 

the coal, specifically including whether the coal was sampled as delivered to the affected facility or 

whether the sample was collected from coal in storage at the mine, at a coal preparation plant, at a coal 

supplier's facility, or at another location. The certification shall include the name of the coal mine (and 

coal seam), coal storage facility, or coal preparation plant (where the sample was collected); 

(iii) The results of the analysis of the coal from which the shipment came (or of the shipment itself) 

including the sulfur content, moisture content, ash content, and heat content; and 

(iv) The methods used to determine the properties of the coal. 

(4) For other fuels: 

(i) The name of the supplier of the fuel; 

(ii) The potential sulfur emissions rate or maximum potential sulfur emissions rate of the fuel in ng/J 

heat input; and 

(iii) The method used to determine the potential sulfur emissions rate of the fuel. 

(g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of this section, the owner or operator of 

each affected facility shall record and maintain records of the amount of each fuel combusted during 

each operating day. 
(2) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or 

operator of an affected facility that combusts only natural gas, wood, fuels using fuel certification in 

§60.48c(f) to demonstrate compliance with the SO2standard, fuels not subject to an emissions standard 

(excluding opacity), or a mixture of these fuels may elect to record and maintain records of the amount 

of each fuel combusted during each calendar month. 

(3) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or 

operator of an affected facility or multiple affected facilities located on a contiguous property unit 

where the only fuels combusted in any steam generating unit (including steam generating units not 

subject to this subpart) at that property are natural gas, wood, distillate oil meeting the most current 

requirements in §60.42C to use fuel certification to demonstrate compliance with the SO2standard, 

and/or fuels, excluding coal and residual oil, not subject to an emissions standard (excluding opacity) 

may elect to record and maintain records of the total amount of each steam generating unit fuel 

delivered to that property during each calendar month. 

(h) The owner or operator of each affected facility subject to a federally enforceable requirement 

limiting the annual capacity factor for any fuel or mixture of fuels under §60.42c or §60.43c shall 

calculate the annual capacity factor individually for each fuel combusted. The annual capacity factor is 

determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end 

of the calendar month. 

(i) All records required under this section shall be maintained by the owner or operator of the affected 

facility for a period of two years following the date of such record. 

(j) The reporting period for the reports required under this subpart is each six-month period. All reports 

shall be submitted to the Administrator and shall be postmarked by the 30th day following the end of 

the reporting period.