## MEMORANDUM

From: Christian Fellner

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 red line of the proposed amendments against the existing regulatory text. The redline documen ts only include edited sections and are only intended to assist interested parties to unde rstand 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 in corporated by reference in th e corresponding sections noted. These incorporations by referen ce 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 p ublished in theFederal Re gister.The materials are available for purchase at the corresponding addr ess noted below, and all are available for inspection at the Library (C267–01), U.S. EPA, Re search 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 pur chase from at least one of the following addresses: American Society for Testing and Ma terials (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 referen ce (IBR) approved for §60.261. (2) ASTM A100–69, 74, 93, Standard Specificati on 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 fo r 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 Me thod 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 Te st Method for Heat of Co mbustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for §§60.46(c), 60.296(b), an d appendix A: Method 19, Section 12.5.2.2.3. (11) ASTM D270–65, 75, Standard Method of Sa mpling 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 fo r §§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 Speci fication 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 Specificati on 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 fo r 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 Analys is of Natural Gases and Related Types of Gaseous Mixtures by the Mass Spectrom eter, 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; Me thod 11, Section 7.1.3; Method 12, Section 7.1.3; Method 13A, Section 7.1.2; Method 26, Secti on 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 fo r Sulfur in Petroleum Products (HighTemperature Method), IBR approved for §60.4415(a)(1)(i). (26) ASTM D1826–77, 94, Standard Test Method fo r 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 Specifica tion 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 Pr eparing 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 Meth ods 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 fo r 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 a ppendix 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), N oncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromat ography, 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 Te st Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containi ng Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for §60.335(b)(9)(i). (39) ASTM D2622–87, 94, 98, Standard Test Met hod 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 Su lfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrom etry, IBR approved for §60.4415(a)(1)(i). (41) ASTM D2879–83, 96, 97, Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temper ature of Liquids by Isoten iscope, 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 fo r 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 Meas uring Volatile Organi c Matter in Water by Aqueous-Injection Gas Chromat ography, IBR approved for §60.564(j). (44) ASTM D2986–71, 78, 95a, Standard Method fo r 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 U ltimate Analysis of Coal and Coke, IBR approved for §60.45(f)(5)(i) and appe ndix 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 appr oved for §60.335(b)(10)(ii). (50) ASTM D3246–05, Standard Test Method fo r Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR appr oved for §60.4415(a)(1)(ii). (51) ASTM D3270–73T, 80, 91, 95, Standard Test Met hods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautom ated Method), IBR approved for appendix A: Method 13A, Section 16.1. (52) ASTM D3286–85, 96, Standard Test Method fo r Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR a pproved 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 Specifica tion for Kerosine, IBR approved for §§60.41b of subpart Db of this part and 60.41c of subpart Dc of this part. (5 5 4 ) ASTM D3792–79, 91, Standard Test Method for Wa ter Content of Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR approve d for appendix A: Method 24, Section 6.3. (5 6 5 ) ASTM D4017–81, 90, 96a, Standard Test Method fo r Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR a pproved for appendix A: Method 24, Section 6.4. (5 7 6 ) ASTM D4057–81, 95, Standard Practice for Manua l Sampling of Petroleum and Petroleum Products, IBR approved for appe ndix A: Method 19, Section 12.5.2.2.3. (5 8 7 ) ASTM D4057–95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products , IBR approved for §60.4415(a)(1). (5 8 9 ) ASTM D4084–82, 94, Standard Test Method for An alysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for §60.334(h)(1). ( 60 59 ) ASTM D4084–05, Standard Test Method for An alysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reacti on Rate Method), IBR approve d for §§60.4360 and 60.4415(a)(1)(ii). (6 1 0 ) ASTM D4177–95, Standard Practice for Automa tic Sampling of Petroleum and Petroleum Products, IBR approved for appe ndix A: Method 19, Section 12.5.2.2.1. (6 2 1 ) ASTM D4177–95 (Reapproved 2000), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products , IBR approved for §60.4415(a)(1).

## (6 2 3 ) ASTM D4239–85, 94, 97, Standard Test Methods fo r 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. (6 4 3 ) ASTM D4294–02, Standard Test Method for Su lfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fl uorescence Spectrometry, IBR approved for §60.335(b)(10)(i). (6 4 5 ) ASTM D4294–03, Standard Test Method for Su lfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, I BR approved for §60.4415(a)(1)(i). (6 6 5 ) ASTM D4442–84, 92, Standard Test Methods fo r Direct Moisture Content Measurement in Wood and Wood-base Materi als, IBR approved for append ix A: Method 28, Section 16.1.1. (6 7 6 ) ASTM D4444–92, Standard Test Methods for Us e and Calibration of Hand-Held Moisture Meters, IBR approved for appendi x A: Method 28, Section 16.1.1. (6 8 7 ) 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 a ppendix A: Method 24, Section 6.5. (6 9 8 ) ASTM D4468–85 (Reapproved 2000), Standard Te st Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Co lorimetry, IBR approved for §§60.335(b)(10)(ii) and 60.4415(a)(1)(ii). ( 70 69 ) ASTM D4629–02, Standard Test Method fo r Trace Nitrogen in Liquid Petroleum Hydrocarbons by Syringe/Inle t Oxidative Combustion and Chemiluminescence Detection, IBR approved for §§60.49b(e) and 60.335(b)(9)(i). (7 0 1 ) 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). (7 2 1 ) ASTM D4810–88 (Reapproved 1999), Standard Test Method for Hydrogen Sulfide in Natural Gas Using Length of Stain Dete ctor Tubes, IBR approved for §§60.4360 and 60.4415(a)(1)(ii). (7 3 2 ) ASTM D5287–97 (Reapproved 2002), Standard Practice for Automatic Sampling of Gaseous Fuels, IBR approved for §60.4415(a)(1). (7 4 3 ) ASTM D5403–93, Standard Test Methods for Volatile Content of Radiation Curable Materials, IBR approved for appendix A: Method 24, Section 6.6. (7 5 4 ) ASTM D5453–00, Standard Test Method for De termination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by U ltraviolet Fluorescence, IBR approved for §60.335(b)(10)(i). (7 6 5 ) ASTM D5453–05, Standard Test Method for De termination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by U ltraviolet Fluorescence, IBR approved for §60.4415(a)(1)(i). (7 7 6 ) ASTM D5504–01, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chroma tography and Chemiluminescence, IBR approved for §§60.334(h)(1) and 60.4360. (7 8 7 ) ASTM D5762–02, Standard Test Method fo r Nitrogen in Petroleum and Petroleum Products by Boat-Inlet Chemiluminescen ce, IBR approved for §60.335(b)(9)(i).

## (7 9 8 ) ASTM D5865–98, Standard Test Method for Gro ss Calorific Value of Coal and Coke, IBR approved for §60.45(f)(5)(ii), 60.46(c)(2), a nd appendix A: Method 19, Section 12.5.2.1.3. ( 80 79 ) ASTM D6216–98, Standard Practice for Opac ity Monitor Manufact urers to Certify Conformance with Design and Performance Specifications, IBR appr oved for appendix B, Performance Specification 1. (8 1 0 ) ASTM D6228–98, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromato graphy and Flame Photometric Detection, IBR approved for §60.334(h)(1). (8 2 1 ) ASTM D6228–98 (Reapproved 2003), Standard Te st Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography a nd Flame Photometric Detection, IBR approved for §§60.4360 and 60.4415. (8 3 2 ) ASTM D6348–03, Standard Test Method fo r Determination of Gaseous Compounds by Extractive Direct Interface F ourier Transform Infrared (FTIR) Spectroscopy, IBR approved for table 7 of subpart IIII of this part an d table 2 of subpart JJJJ of this part. (8 4 3 ) ASTM D6366–99, Standard Test Method for To tal Trace Nitrogen and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative Co mbustion and Electrochemical Detection, IBR approved for §60.335(b)(9)(i). (8 5 4 ) ASTM D6420–99 (Reapproved 2004) Standard Te st 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. (8 6 5 ) ASTM D6522–00, Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissi ons from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Pr ocess Heaters Using Port able Analyzers, IBR approved for §60.335(a). (8 7 6 ) ASTM D6522–00 (Reapproved 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen C oncentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Tu rbines, Boilers, and Process Heaters Using Portable Analyzers, IBR approved for ta ble 2 of subpart JJJJ of this part. (8 8 7 ) ASTM D6667–01, Standard Test Method for Dete rmination of Total Volatile Sulfur in Gaseous Hydrocarbons and Lique fied Petroleum Gases by Ultr aviolet Fluorescence, IBR approved for §60.335(b)(10)(ii). (8 9 8 ) ASTM D6667–04, Standard Test Method for Dete rmination of Total Volatile Sulfur in Gaseous Hydrocarbons and Lique fied Petroleum Gases by Ultr aviolet 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. ( 89 92 ) ASTM D6784–02, Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Co al-Fired Stationary S ources (Ontario Hydro Method), IBR approved for appe ndix B to part 60, Performa nce Specification 12A, Section 8.6.2.

## (9 3 0 ) ASTM D6784–02, Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Co al-Fired Stationary S ources (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. (94) ASTM D7467 – 10, Standard Specification fo r Diesel Fuel Oil, Biodiesel Blend (B6 to B20), IBR approved for §§60.41b of subpart Db of th is part and 60.41c of subpart Dc of this part. (9 5 1 ) 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). (9 6 2 ) ASTM E260–73, 91, 96, General Gas Chromat ography Procedures, IBR approved for §§60.485a(d)(1), 60.593(b)(2), 60.59 3a(b)(2), and 60.632(f). (b) The following material is available for purchas e 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 a pproved 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 purch ase 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 purchas e 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 purch ase from the Water Pollution Control Federation (WPCF), 2626 Pennsylvania Av enue 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 av ailable for purchase from the fo llowing address: Underwriter's Laboratories, Inc. (UL), 333 Pf ingsten Road, Northbrook, IL 60062. (1) UL 103, Sixth Edition revised as of Sept ember 3, 1986, Standard for Chimneys, Factorybuilt, Residential Type and Building Heating Appliance. (g) The following material is available for pur chase from the following address: West Coast Lumber Inspection Bureau, 6980 SW. Barnes Road, Portland, OR 97223. (1) West Coast Lumber Standard Grading Ru les No. 16, pages 5–21 and 90 and 91, September 3, 1970, revised 1984. (h) The following material is available for purch ase from the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016–5990.

## (1) ASME QRO–1–1994, Standard for the Qualifica tion 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), Powe r 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: Applicat ion, 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 subpa rt 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 S ubpart 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 fo r 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, Chica go, Illinois 60675–2683. You may inspect a copy at EPA's Air and Radiation Docket and Inform ation 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 Stra tegies for Health Care Facilities. American Society for Health Care Environm ental Services of the American Hospital Association. Chicago, Illinois. 1993. AHA Catalog No. 057007. IS BN 0–87258–673–5. IBR approved for §60.35e and §60.55c. (l) This material is available for purchase fr om the National Technical Information Services, 5285 Port Royal Road, Springfield, Virginia 221 61. 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. NT IS 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 Stre et, Tulsa, OK, 74145; or Information Handling Services, 15 Inverness Way East, PO B ox 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. Y ou 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 Associat ion 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 Organizati on for Standards 8178–4: 1996(E) , Reciprocating Internal Combustion Engines—Exhaust Emission Measurem ent—part 4: Test Cycles for Different Engine Applications, IBR approved for §60.4241(b). (2) [Reserved]Subpart D—Standards of Performance fo r 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 mo re 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-fire d 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 sec tion, any facility under para graph (a) of this section that commenced construction or modification after A ugust 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 modifi cation 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, cl ay, 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 hydro carbon 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 Am erican 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 percen t 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, o O n and after the date on which the performance test required to be conducte d by §60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharg ed into the atmosphere from any affected facility any gases that:
(1) Contain PM in excess of 43 nanograms per joul e (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 fo r 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 opac ity, 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 permitte d 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 th at combusts only natural gas and that is subject to a federally enforceable permit lim iting 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 SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that does not use post-combustion technology to reduce emissions of SO 2 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 low sulfur oil from the PM standard.§60.43 Standard for sulfur dioxide (SO 2 ).
(a) Except as provided under paragraph (d) of this section, on and afte r 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 SO 2 in excess of:
(1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil fuel or liquid fossil fuel and wood residue.
(2) 520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue, except as provided in paragraph (e) of this section.
(b) Except as provided under paragraph (d) of this section, when different fossil fuels are burned simultaneously in any combination, the applicable standard (in ng/J) shall be determined by proration using the following formula:

Where:

PS SO 2= Prorated standard for S O2 when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels or from a ll 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 pa ragraphs (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 th is 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 (NO X ).
(a) Except as provided under paragraph (e) of th is 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 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 in sert it again.provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that contain NO X , expressed as NO 2 in excess of:
(1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil fuel.
(2) 129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and wood residue.
(3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue (except lignite or a solid fossil fuel containi ng 25 percent, by weight, or more of coal refuse).
(4) 260 ng/J heat input (0.60 lb MMBtu) derived fr om lignite or lignite a nd wood residue (except as provided under paragraph (a)(5) of this section).
(5) 340 ng/J heat input (0.80 lb MMBtu) derived fr om 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:

PS NOX = Prorated standard for NO X when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels fired or from all fossil fuels and wood residue fired;
w = Percentage of total heat input derived from lignite;
x = Percentage of total heat inpu t 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 NO X does not apply.
(d) Except as provided under paragraph (e) of this section, cyclone-fired units which burn fuels containing at least 25 percent of lignite that is mined in North Dakota, South Dakota, or Montana remain subject to paragraph (a)(5) of this section regardless of the types of fuel combusted in combination with that lignite.
(e) As an alternate to meeting the requirements of para graphs (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. 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 in sert it again.§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 SO 2 emissions, NO X emissions, and either oxygen (O 2 ) or carbon dioxide (CO 2 ) 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 burns combusts only gaseous or liquid fossil fuel (excluding residual oil) with potential SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that does not use post-combustion technology to reduce emissions of SO 2 or PM, CEMS COMS for measuring the opacity of emissions and CEMS for measuring SO 2 emissions are not required if the owner or operator monitors SO 2 emissions by fuel sampling and analysis or fuel receipts.
(2) For a fossil-fuel-fired steam ge nerator that does not use a flue ga s desulfurization device, a CEMS for measuring SO 2 emissions is not required if the owner or operator monitors SO 2 emissions by fuel sampling and analysis.
(3) Notwithstanding §60.13(b), installation of a CEMS for NO X may be delayed until after the initial performance tests under §60.8 have be en conducted. If the owner or operator demonstrates during the performance test th at emissions of NO X are less than 70 percent of the applicable standards in §60.44, a CEMS for measuring NO X emissions is not required. If the initial performance test results show that NO X emissions are greater than 70 percent of the applicable standard, the owner or operator shall install a CEMS for NO X within one year after the date of the in itial performance tests under §60.8 and comply with all other applicable monitoring requirements under this part.
(4) If an owner or operator is not required to and elects does not install any CEMS for sulfur oxides SO 2 and NO X , as provided under paragraphs (b)(1) and (b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for measuring either O 2 or CO 2 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 a n affected facility fossil fuel

- fired steam generator that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO 2 , or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur, a nd 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 acco rding 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 ge nerated 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 em issions levels for each boiler operating day by multiplying the average hourly CO output concen tration 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 le vels computed for each boiler operating day.
(iii) You must evaluate the preceding 24-hour aver age CO emission level each boiler operating day excluding periods of affected source startup, sh utdown, 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 discove ry 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 calc ulations performed according to paragraph (b)(6) of this section and any corrective act ions taken. The record of correc tive 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 descript ion of the corrective action.
(7) An owner or operator of an affected facility su bject 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 co nduct 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 author ity 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 Me thod 9 of appendix A–4 of this part performance tests using the procedures in paragraph (b)(7) of this section according to the app licable schedule in paragr aphs (b)(7)(i)(A) through (b)(7)(i)(D) of this section, as determined by th e 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 maximu m 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 th e most recent performanc e 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 perf ormance 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 gr eater 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 perfo rmance test was conducted.
(ii) If the maximum 6-minute opacity is less th an 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owne r 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) an d (B) of this section.
(A) The owner or operator shall conduct 10 mi nute 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 ex cess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visibl e emissions is greater th an 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 su m 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 opera ting 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 vi sible emissions are observed, dail y 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 owne r 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 sect ion. 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 documentis also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods.
(c) For performance evaluations under §60.13(c) and calibration ch ecks under §60.13(d), the following procedures shall be used:
(1) Methods 6, 7, and 3B of appendix A of this pa rt, as applicable, shall be used for the performance evaluations of SO 2 and NO X continuous monitoring systems. Acceptable alternative methods for Methods 6, 7, and 3B of appendix A of this part are given in §60.46(d).
(2) Sulfur dioxide or nitric oxide, as applicable, sh all 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 NO X the span value shall be determined using one of the following procedures:
(i) Except as provided under paragr aph (c)(3)(ii) of this section, SO 2 and NO X span values shall be determined as follows:

Fossil fuel In parts per million

Span value for SO 2 Span value for NO X
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 de rived 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 SO 2 and NO X span values determined according to sections 2.1.1 and 2.1.2 in appendi x 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 accor ding to the applicable proc edures in section 2 of appendix A to part 75 of this chapter.(5) For a fossil-fuel-fired steam ge nerator 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 th is section, the following conversion procedures shall be used to convert the continuous monitoring da ta into units of the applicable standards (ng/J, lb/MMBtu):
(1) When a CEMS for measuring O 2 is selected, the measurement of the pollutant concentration and O 2 concentration shall each be on a consistent basis (wet or dry). Alternative procedures approved by the Administrator shall be used when measurements are on a wet basis. When measurements are on a dry basis, the following conversion procedure shall be used:

Where E, C, F, and %O 2 are determined under paragraph (f) of this section.
(2) When a CEMS for measuring CO 2 is selected, the measurement of the pollutant concentration and CO 2 concentration shall each be on a consistent ba sis (wet or dry) and the following conversion procedure shall be used:

Where E, C, F c and %CO 2 are determined under paragr aph (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 × 10 4 M ng/dscm per ppm (2.59 × 10 − 9 M lb/dscf per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO 2 and 46.01 for NO X
. (3) %O 2 , %CO 2 = O 2 or CO 2 volume (expressed as percent), determined with equipment specified under paragraph (a) of this section.
(4) F, F c = 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 CO 2 generated to the calorific value of the fuel combusted (F c ), respectively. Values of F and F c are given as follows:
(i) For anthracite coal as classified according to ASTM D388 (incorporated by reference, see §60.17), F = 2,723 × 10 − 17 dscm/J (10,140 dscf/MMBtu) and F c = 0.532 × 10 − 17 scm CO 2 /J (1,980 scf CO 2 /MMBtu). 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 in sert 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 in sert it again.(ii) For subbituminous and bituminous coal as cl assified according to ASTM D388 (incorporated by reference, see §60.17), F = 2.637 × 10 − 7 dscm/J (9,820 dscf/MMBtu) and F c = 0.486 × 10 − 7 scm CO 2 /J (1,810 scf CO 2 /MMBtu).
(iii) For liquid fossil fuels including crude, residual, and distillate oils, F = 2.476 × 10 − 7 dscm/J (9,220 dscf/MMBtu) and F c = 0.384 × 10 − 7 scm CO 2 /J (1,430 scf CO 2 /MMBtu).
(iv) For gaseous fossil fuels, F = 2.347 × 10 − 7 dscm/J (8,740 dscf/MMBtu). For natural gas, propane, and butane fuels, F c = 0.279 × 10 − 7 scm CO 2 /J (1,040 scf CO 2 /MMBtu) for natural gas, 0.322 × 10 − 7 scm CO 2 /J (1,200 scf CO 2 /MMBtu) for propane, and 0.338 × 10 − 7 scm CO 2 /J (1,260 scf CO 2 /MMBtu) for butane.
(v) For bark F = 2.589 × 10 − 7 dscm/J (9,640 dscf/MMBtu) and F c = 0.500 × 10 − 7 scm CO 2 /J (1,840 scf CO 2 /MMBtu). For wood residue other than bark F = 2.492 × 10 − 7 dscm/J (9,280 dscf/MMBtu) and F c = 0.494 × 10 − 7 scm CO 2 /J (1,860 scf CO 2 /MMBtu).
(vi) For lignite coal as classifi ed according to ASTM D388 (incorporated by reference, see §60.17), F = 2.659 × 10 − 7 dscm/J (9,900 dscf/MMBtu) and F c = 0.516 × 10 − 7 scm CO 2 /J (1,920 scf CO 2 /MMBtu).
(5) The owner or operator may use the following e quation 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 CO 2 /J, or scf CO 2 /MMBtu) on either basis in lieu of the F or F c factors specified in paragraph (f)(4) of this section:

(i) %H, %C, %S, %N, and %O are content by weig ht of hydrogen, carbon, sulfur, nitrogen, and O 2 (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 applic able. (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 D1 826 for gaseous fuels as ap plicable. (These three methods are incorporated by reference, see §60.17.) 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 in sert it again.(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 pr orated in accordance with the applicable formula as follows:

Where:

X i = Fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood residue, etc.);

F i or (F c ) i = Applicable F or F c factor for each fuel type determined in accordance with paragraphs (f)(4) and (f)(5) of this section; and
n = Number of fuels being burned in combination.
(g) Excess emission and monitoring system performance reports shall be submitted to the Administrator semiannually for each six-month pe riod 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 requir ed in §60.7(c). Periods of excess emissions and monitoring systems (MS) downtime that sh all be reported are defined as follows:
(1) Opacity . Excess emissions are defined as any six-mi nute 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 emission s 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 w ith §60.43(d), any three-hour period during which the average emissions (arithmetic average of three contiguous one-hour periods) of SO 2 as measured by a CEMS exceed the applicable standard in §60.43; or
(ii) For affected facilities electing to comply with §60.43(d), any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of SO 2 as measured by a CEMS exceed the applicable st andard in §60.43. Facilities complying with the 30-day SO 2 standard shall use the most current associated SO 2 compliance and monitoring requirements in §§60.48Da and 60.49Da of subpart Da of this part or §§60.45b and 60.47b of subpart Db of this part, as applicable. 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 in sert it again.(3) Nitrogen oxides. Excess emissions for affected facilities using a CEMS for measuring NO X are defined as:
(i) For affected facilities electing not to comply w ith §60.44(e), any three-hour period during which the average emissions (arithmetic average of three c ontiguous 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 NO X as measured by a CEMS exceed the applicable st andard in §60.44. Facilities complying with the 30-day NO X standard shall use the most current associated NO X compliance and monitoring requirements in §§60.48Da and 60.49Da of subpart Da of this part.
(4) Particulate matter. Excess emissions for affected facilities using a CEMS for measuring PM are defined as any boiler operating day period during which the average emissions (arithmetic average of all operating one-hour periods) exceed the applicable standards in §60.42. Affe cted 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 spec ified in paragraphs (h)(1) through (3) of this section, as applicable to the visible emissions monitoring method used.
(1) For each performance test condu cted using Method 9 of appendix A–4 of this part, the owner or operator shall keep the records including the informat ion 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 visi ble 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 condu cted using Method 22 of appendix A–4 of this part, the owner or operator shall keep the records including the informat ion 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 ob server 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, th e 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 pa rt or other methods and procedures as specified in this section, except as provided in §60.8(b). Acce ptable alternative methods and procedures are given in paragraph (d) of this section.
(b) The owner or operator shall determine compliance with the PM, SO 2 , and NO X standards in §§60.42, 60.43, and 60.44 as follows:
(1) The emission rate (E) of PM, SO 2 , or NO X shall 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);

%O 2 = O 2 concentration, percent dry basis; and

F d = 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-desulfuri zation (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 r un 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 O 2 concentration (%O 2 ). The O 2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate sample. If the grab sampling procedure is used, the O 2 concentration for the run shall be the arithmetic mean of the sample O 2 concentrations at all traverse points.
(iii) If the particulate run has more than 12 traverse points, the O 2 traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O 2 traverse points.
(3) Method 9 of appendix A of th is part and the procedures in §60.11 shall be used to determine opacity. 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 in sert it again.(4) Method 6 of appendix A of this pa rt shall be used to determine the SO 2 concentration.
(i) The sampling site shall be the same as that selected for the particulate sample. The sampling location in the duct shall be at the centroid of the cross section or at a point no closer to the walls than 1 m (3.28 ft). The sampling time and sample volume for each sample run shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples shall be taken during a 1-hour period, with each sample taken within a 30-minute interval.
(ii) The emission rate correction factor, integrated sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 concentration (%O 2 ). The O 2 sample shall be taken simultaneously with, and at the same point as, the SO 2 sample. The SO 2 emission rate shall be computed for each pair of SO 2 and O 2 samples. The SO 2 emission rate (E) for each run shall be the arithmetic mean of the results of the two pairs of samples.
(5) Method 7 of appendix A of this pa rt shall be used to determine the NO X concentration.
(i) The sampling site and location shall be the same as for the SO 2 sample. Each run shall consist of four grab samples, with each sample taken at about 15-minute intervals.
(ii) For each NO X sample, the emission rate correction factor , grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 concentration (%O 2 ). The sample shall be taken simultaneously with, and at the same point as, the NO X sample.
(iii) The NO X emission rate shall be computed for each pair of NO X and O 2 samples. The NO X emission rate (E) for each run shall be the arithmetic mean of the results of the four pairs of samples.
(c) When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator (in order to compute the prorated standard as s hown 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), D2 40 (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 ra te 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, SO 2 and NO X may be determined by using the Fc factor, provided that the following procedure is used:
(i) The emission rate (E) shall be computed using the following equation:Where:
E = Emission rate of pollutant, ng/J (lb/MMBtu);
C = Concentration of pollutant, ng/dscm (lb/dscf);

%CO 2 = CO 2 concentration, percent dry basis; and

F c = 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 percen t, then three runs of Me thod 3B of appendix A of this part shall be used to determine the O 2 and CO 2 concentration according to the procedures in paragraph (b)(2)(ii), (4)(ii), or (5)(ii) of this section. Then if F o (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 F o value, as determined from the average values of F d and F c in Method 19 of appendix A of this part, i.e. , F oa = 0.209 (F da /F ca ), then the following procedure shall be followed:
(A) When F o is less than 0.97 F oa , then E shall be increased by that proportion under 0.97 F oa , e.g. , if F o is 0.95 F oa , E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the emission standard.
(B) When F o is less than 0.97 F oa and when the average difference (d) between the continuous monitor minus the reference methods is negative, then E sh all be increased by that proportion under 0.97 F oa , e.g. , if F o is 0.95 F oa , E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the relative accuracy specification.
(C) When F o is greater than 1.03 F oa and when the average difference d is positive, then E shall be decreased by that proportion over 1.03 F oa , e.g. , if F o is 1.05 F oa , 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 us ed 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 SO 2 may be determined simultaneously with the Method 5 of appendix A of this part train provided that the following changes are made:
(i) The filter and impinger apparatus in sections 2.1. 5 and 2.1.6 of Method 8 of appendix A of this part is used in place of the condenser (section 2.1. 7) of Method 5 of appendix A of this part.
(ii) All applicable procedures in Method 8 of appendix A of this part for the determination of SO 2 (including moisture) are used: 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 in sert it again.(4) For Method 6 of appendix A of this part, Met hod 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 SO 2 emission rate, under the conditions in paragraph (d)(1) of this section.
(5) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be at least 1 hour and the integrated sampling approach shall be used to determine the O 2 concentration (%O 2 ) 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, Met hod 3A of appendix A of this part may be used.Subpart Da—Standards of Perf ormance 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 reco nstruction 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 paragrap hs (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 (fo ssil 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 ( 2 3 ) of this section. (1) Affected facilities (i.e. H h eat recovery steam generators used with duct burners ) and associated with a n electric utility combined cycle gas stationary 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 gene rating unit (i.e. duct burners) are subject to the standards under this subpart. (The emissions resulting from the combustion of fuels in the stationary combustion turbine engine are subject to subpart GG or KKK K , 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 this subpart.
(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.

Add total PM monitoring requirements

– cross reference EGU MACT

Comment [CF2]: Fix typo

Comment [CF3]: Exempt owner/operators of MWC & CISWI from 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 capac ity in all neighboring companies. (b) The sum of the rated capacities of the powe r 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 ne ighboring 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 (i ncorporated 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, physi cal 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 (SO 2 ) 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 de vices 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 po tential 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 a nd 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 percen t 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 engine s, 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 combus tion 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 (SO 2 ) is determined under §60.50Da(c). (3) For nitrogen oxides (NO X ) 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 of ficial 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 SO 2 emission control equipment capable of treating an amount of flue gas equal to the total amount of flue gas generated by an affected facility when operated at maximum capacity divided by the total number of nonspare flue gas desulfurization modules in the system. Spinning reserve means the sum of the unutilized net generating capability of all units of the electric utility company that are synchronized to the power distribution system and that are capable of immediately accepting additional load. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractual arrangement. Steam generating unit 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 subbi tuminous 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. Request comment on adding renewable generation
to definition f affected facility.multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise establishe d 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 SO 2 control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to ot her forms. Alkaline reag ents 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,

no an 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 2 8 9 , 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 SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion technology to reduce emissions of SO 2 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, O o n and after the date the initial PM performance test is completed or required to be completed under §60.8, whichever date comes first, an no owner or operator subject to the provisions of this subpart of 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]: Delete “derived from the ....”
to account for solar thermal augmentation.

Comment [CF13]: Exempt natural gas & low sulfur oil boilers from the PM limit.

Comment [CF14]: Exempt owner/operators of facilities only burning natural gas from the opacity standard Take comment on exempting all gaseous fuels & low sulfur petroleum(c) Except as provided in paragraph s (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, O o n 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 modifi cation commenced after February 28, 2005, any gases that contain filterable PM in excess of: (1) 13 ng/J (0.03 0 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 SO 2 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 SO 2 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 [CF15]: Request comment if we could delete since has not been used

Comment [CF16]: Fix typo

Comment [CF17]: 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 (SO 2 ). (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 paragrap hs (c), (d), (f) or (h) of this section, any gases that contain SO 2 in excess of: (1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); or (2) 30 percent of the potential combustion concentration (70 percent reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat input ;

. (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 SO 2 in excess of: (1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); or (2) 100 percent of the potential combustion concentration (zero percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu) heat input. (c) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid solvent refined coal (SRC–I) any gases that contain SO 2 in excess of 520 ng/J (1.20 lb/MMBtu) heat input and 15 percent of the potential combustion concentration (85 percent reduction) except as provided under paragraph (f) of this section; compliance with the emission limitation is determined on a 30-day rolling average basis and compliance with the percent reduction requirement is determined on a 24-hour basis. (d) Sulfur dioxide emissions are limited to 520 ng /J (1.20 lb/MMBtu) heat input from any affected facility which: (1) Combusts 100 percent anthracite; (2) Is classified as a resource recovery unit; or (3) Is located in a noncontinental area and combusts solid fuel or solid-derived fuel. Comment [CF18]: Since PM standard includes total PM oil

‐ fired would still be subject to the standard

Comment [CF19]: 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 [CF20]: Take comment on 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 requirements SO 2 standards under this section do not apply to an owner or operator of an y affected facility that is operated under an SO 2 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 SO 2 to the atmosphere are greater than 260 ng/J (0.60 lb/MMBtu) heat input

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

Where:

E s = Prorated SO 2 emission limit (ng/J heat input);

%P s = Percentage of potential SO 2 emission allowed; x = Percentage of total heat input derived from the combustion of liquid or gaseous fuels (excluding solid-derived fuels); and y = Percentage of total heat input derived from the combustion of solid fuel (including solid-derived fuels). (i) Except as provided in paragraphs (j) and (k) of this section, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility 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 SO 2 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 SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day rolling average basis ; or (ii) 5 percent of the potential combustion concentration (95 percent reduction) on a 30

- day rolling average basis

.(2) For an affected facility for which commenced reconstruction commenced after February 28, 2005,
, any gases that contain SO 2 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 SO 2 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 combusti on 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 SO 2 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 SO 2 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 SO 2 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 basi s

. (3) For an affected facility for which commenced modification commenced after February 28, 2005
, any gases that contain SO 2 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 combusti on 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 anoncontinental 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 SO 2 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 SO 2 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 SO 2 in excess of if th e 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 SO 2 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 SO 2 in excess of either: (i) 130 ng/J (1.0 lb/MWh) gross energy output; or (ii) 3 percent of the potential combus tion concentration (97 percent reduction). (2) For an affected facility which commenced modification, any gases that contain SO 2 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 TH E 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 SO 2 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 SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output; or (ii) 6 percent of the potential combus tion concentration (94 percent reduction). (2) For an affected facility which commenced modification, any gases that contain SO 2 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 SO 2 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 SO 2 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 SO 2 in excess of 230 ng/J (0.54 lb/MMBtu) heat input. §60.44Da Standard for nitrogen oxides (NO X ). (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 NO X (expressed as NO 2 ) in excess of the following emission limits , based on a 30

- day rolling average basis , except as provided under §60.48Da(j)(1) : (1) NO X emission 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 we ight, lignite if the lignite is mined in N orth Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace 2 340 0.80

Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat input emission limit 2 260 0.60

Subbituminous coal 210 0.50

Bituminous coal 260 0.60

Anthracite coal 260 0.60

All other fuels 260 0.60

1 Exempt from NO X standards and NO X monitoring requirements.

2 Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel. (2) NO X reduction requirement.

Fuel type Percent reduction of potential combustion concentration

Gaseous fuels 25

Liquid fuels 30

Solid fuels 65

(b) The NO X emission limitations under paragraph (a) of this section do not apply to an owner or operator y of 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:

E n = Applicable standard for NO X when multiple fuels are combusted simultaneously (ng/J heat input);w = Percentage of total heat input derived from the combustion of fuels subject to the 86 ng/J heat input standard; x = Percentage of total heat input derived from the combustion of fuels subject to the 130 ng/J heat input standard; y = Percentage of total heat input derived from the combustion of fuels subject to the 210 ng/J heat input standard; z = Percentage of total heat input derived from the combustion of fuels subject to the 260 ng/J heat input standard; and v = Percentage of total heat input delivered from th e combustion of fuels subj ect 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 2 8 9 , 2005 shall cause to be discharged into the atmosphere any gases that contain NO X (expressed as NO 2 ) 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 2 8 9 , 2005 shall cause to be discharged into the atmosphere any gases that contain NO X (expressed as NO 2 ) 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, recons truction, 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 NO X (expressed as NO 2 ) 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 NO X (expressed as NO 2 ) 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 NO X (expressed as NO 2 ) 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 fo r 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 NO X (expressed as NO 2 ) in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day rolling average basis ; or Comment [CF21]: 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 NO X (expressed as NO 2 ) 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 NO X (expressed as NO 2 ) 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 NO X (expressed as NO 2 ) in excess of the computed weighted-average emissions limit based on the proportion of gross energy output (i n 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) Except as provided in paragraph (f) of this section, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, 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 NO X (expressed as NO 2 ) 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
construc tion, 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 para graphs (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 atm osphere 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

- fir ed electric utility steam generating unit that burns only subbituminous coal: Comment [CF22]: Request comment on ability of reconstructed/modified facilities to achieve this standard and if the IGC standard should remain at 1.5 lb/MWh for hours during which oil if combusted.
Comment [CF23]: 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, base d on the most recent publicly ava ilable 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. De partment 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 d ischarge 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 bur ns 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 g ases 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 ste am 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 lim it 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 sour ce, 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:

EL b = Total allowable Hg in lb/MWh that can be emitted to the atmosphere from any affected source being averaged according to this paragraph.

EL i = Hg emissions limit for the subcategory i (coal rank) that applies to affected source, lb/MWh;

HH i = For each affecte d source, the Btu, MWh, or MJ contributed by the corresponding subcategory i (coal rank) burned during the compliance period; and n = Number of subcategories (coal ranks) being averaged for an affected source.(ii) If you operate a coal

- fired electric util ity 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 th e 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 d etermined 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 nonregula ted 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 t he initial performance test required to be c onducted 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 emi ssions 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 de monstration permit. (a) An owner or operator of an af fected facility proposing to demo nstrate 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 SO 2 emission reduction requirements under §60.4 3Da(c) but must, as a minimum, reduce SO 2 emissions to 20 percent of the potential combustion concentration (80 percent reduction) for each 24-hour period of steam generator operation and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis. (c) An owner or operator of a fluidized bed combustion electric utility steam generator (atmospheric or pressurized) who is issued a commercial demonstration permit by the Administrator is not subject to the SO 2 emission reduction requirements under §6 0.43Da(a) but must, as a minimum, reduce SO 2 emissions to 15 percent of the potential combustion concentration (85 percent reduction) on a 30- day rolling average basis and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis. (d) The owner or operator of an affected facility that combusts coal-derived liquid fuel and who is issued a commercial demonstration permit by the Administrator is not subject to the applicable NO X emission limitation and percent reduction under §60.44Da(a) but must, as a minimum, reduce emissions to less than 300 ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis. (e) Commercial demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category, and the total equivalent MW electrical generation capacity for all commercial demonstration plants may not exceed 15,000 MW. Comment [CF24]: Request comment on deleting existing paragraphs (b) & (c) & to replace paragraph (e) since they have never been usedTechnology 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 N OX 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 emis sion 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 SO 2 standards or emission reduction requirements under §60.43Da but must, as a minimum, reduce SO 2 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 NO X standards or emission reduction requirements under §60.44Da but must, as a minimum, reduce NO X emissions to le ss 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 SO 2 1,000 Multi-pollutant Emission Control NO X 1,000 Multi-pollutant Emission Control PM 1,000 Pressurized Fluidized Bed Combustion SO 2 1,000 Pressurized Fluidized Bed Combustion NO X 1,000 Pressurized Fluidized Bed Combustion PM 1,000 Advanced Combustion Controls NO X 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 [CF25]: Should these just reference the standards within the text? Easier if can delete the previous paragraphs.

Comment [CF26]: 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 [CF27]: Redundancy between 60.48Da & 60.49Da could be eliminated to make it easier to follow(b) Compliance with the NO X emission 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], T t he PM emission standards under §60.42Da, and the NO X 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], th e PM emission standards under §60.42Da, the NO X 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 SO 2 emissions are minimized by: (1) Operating all operable flue gas desulfurization system modules, and bringing back into operation any malfunctioned module as so on as repairs are completed, (2) Bypassing flue gases around only those flue ga s desulfurization system modules that have been taken out of operation because they were incapable of any SO 2 emission reduction or which would have suffered significant physical damage if they had remained in operation, and (3) Designing, constructing, and operating a spare flue gas desulfurization system module for an affected facility larger than 365 MW (1,250 MMBtu/h r) heat input (approximately 125 MW electrical output capacity). The Administrator may at his discre tion 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 perform ance test required under §60.8, compliance with the SO 2 emission limitations and percentage reduction requirements under §60.43Da and the NO X emission 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 SO 2 and NO X and a new percent reduction for SO 2 are calculated to show compliance with the standards. (f) For the initial performance test required under §60.8, compliance with the SO 2 emission limitations and percent reduction requirements under §60.43Da and the NO X emission limitation under §60.44Da is based on the average emission rates for SO 2 , NO X , and percent reduction for SO 2 for the first 30 successive boiler operating days. The initial performance test is the only test in which at least 30 days prior notice is required unless otherwise specified by the Administrator. The initial performance test is Comment [CF28]: Include all periods of operation. Take 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], C c ompliance with applicable 30-day rolling average SO 2 and NO X emission limitations is determined by calculating the arithmetic average of all hourly emission rates for SO 2 and NO X for the 30 successive boiler operating days, except for data obtained during startup, shutdown, malfunction (NO X only), or emergency conditions (SO 2 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 SO 2 and NO X emission limitations is determined by dividing the sum of all the SO 2 and NO X 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], C c ompliance with applicable SO 2 percentage reduction requirements is determined based on the average inlet and outlet SO 2 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 SO 2 percentage reduction requirements is determined based on the “as fired” total potential emissions and the total outlet SO 2 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], C c ompliance with applicable daily average PM emission limitations is determined by calculating the arithmetic averag e 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 valid non-out-of-control hourly emission rates of the operating day(s) not meeting the minimum 18 hours valid non-out-of-control data daily average requirement are averaged with all of the non-out-of-control valid hourly emission rates of the next boiler operating day with 18 hours or more of non-out-of-control valid PM CEMS data to determine compliance. (h) If an owner or operator has not obtained the minimum quantity of emission data as required under §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 [CF29]: 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 [CF30]: 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 fa cility subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f) shall calculate NO X emissions as 1.194 × 10 − 7 lb/scf-ppm times the average hourly NO X output concentration in ppm (measured according to the provisions of §60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)). Alternatively, for oil-fi red and gas-fired units, NO X emissions may be calculated by multiplying the hourly NO X emission rate in lb/MMBtu (measured by the CEMS required under §§60.49Da(c) and (d)), by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of §60.49Da(k)). (j) Compliance provisions for duct burners subject to §60.44Da(a)(1) . To determine compliance with the emissions limits for NO X required by §60.44Da(a) for duct burners used in combined cycle systems, either of the procedures described in paragraph (j)(1) or (2) of this section may be used: (1) The owner or operator of an affected duct burner shall conduct the performance test required under §60.8 using the appropriate methods in appendix A of this part. Compliance with the emissions limits under §60.44Da(a)(1) is determined on the average of three (nominal 1-hour) runs for the initial and subsequent performance tests. During the performance test, one sampling site shall be located in the exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outlet from the heat recovery steam generating unit. Measurements shall be taken at both sampling sites during the performance test; or (2) The owner or operator of an affected duct burner may elect to determine compliance by using the CEMS specified under §60.49Da for measuring NO X and oxygen (O 2 ) (or carbon dioxide (CO 2 )) and meet the requirements of §60.49Da. Alternatively, data from a NO X emission rate ( i.e. , NO X -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 NO X emission rate at the outlet from the steam generating unit shall constitute the NO X emission rate from the duct burner of the combined cycle system. (k) Compliance provisions for duct burners subject to §60.44Da(d)(1) or (e)(1) . To determine compliance with the emission limitation for NO X required by §60.44Da(d)(1) or (e)(1) for duct burners used in combined cycle systems, either of the procedures described in paragraphs (k)(1) and (2) of this section may be used: (1) The owner or operator of an affected duct burner used in combined cycle systems shall determine compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) as follows: (i) The emission rate (E) of NO X shall be computed using Equation 2 in this section:

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross output;C sg = Average hourly concentration of NO X exiting the steam generating unit, ng/dscm (lb/dscf);

C te = Average hourly concentration of NO X in the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf); Q sg = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr (dscf/hr); Q te = Average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/hr (dscf/hr);

O sg = Average hourly gross energy output from steam generating unit, J /h (MW h ); and h = Average hourly fraction of the total heat i nput 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 NO X concentrations (C sg and C te ). Method 2, 2F or 2G of appendix A of this part, as appropriate, shall be used to determine the volumetric flow rates (Q sg and Q te ) of the exhaust gases. The volumetr ic 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 NO X emission limitation in §60.44Da(d)(1) or (e)(1) is determined by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests. (2) The owner or operator of an affected duct burner used in a combined cycle system may elect to determine compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) on a 30- day rolling average basis as indicated in paragraphs (k)(2)(i) through (iv) of this section. (i) The emission rate (E) of NO X shall be computed using Equation 3 in this section:

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross output;

C sg = Average hourly concentration of NO X exiting the steam generating unit, ng/dscm (lb/dscf); Q sg = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr (dscf/hr); and

O cc = Average hourly gross energy output from entire combined cycle unit, J /h (MW h ). (ii) The CEMS specified under §60.49Da for measuring NO X and O 2 (or CO 2 ) shall be used to determine the average hourly NO X concentrations (C sg ). The continuous flow monitoring system specified in §60.49Da(l) or §60.49Da(m) shall be used to determine the volumetric flow rate (Q sg ) 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. Comment [CF31]: 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 (O cc ), 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 NO X emissions by installing, operating, and maintaining continuous fuel flowmeters follo wing 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 NO X shall be computed using Equation 4 in this section:

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross output;

ER sg = Average hourly emission rate of NO X exiting the steam generating unit heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part, ng/J (lb/MMBtu);

H cc = Average hourly heat input rate of entire combined cycle unit, J/hr (MMBtu/hr); and

O cc = Average hourly gross energy output from entire combined cycle unit, J /h (MW h ). (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 NO X emissions limits by me asuring 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 demo nstrated 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 ye ar, 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 ac cording 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 SO 2 emissions as 1.660 × 10 –7 lb/scf-ppm times the average hourly SO 2 output concentration in ppm (measured according to the provisions of §60.49Da(b)), times the average hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)). Alternatively, for oil-fired and gas-fired units, SO 2 emissions may be calculated by multiplying the hourly SO 2 emission rate (in lb/MMBtu), measured by the CEMS Comment [CF32]: Delete since CAMR vacatedrequired 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 th e 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 perf ormance 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 re quirements 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 particul ar 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 quantifie d. 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 [CF33]: 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 oper ation and must complete a minimum of one cycle of sampling and analyzing for each successive 10 se cond 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 f acility 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 disc overy 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 se rves 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 perform ance 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 caseswhen 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) Protocolfor 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 Emi ssion 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 acco rding 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 accordingto 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 forseasonal 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 affect ed 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 averag e 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, valid non-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 valid non-out-of-control CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(5) of this section are not
met. (8) When PM emissions data are not obtained becau se 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 non-out-of-control emissions data for a minimum of 90 percent (only 75 percent is required prior to January 1, 2012) of all operating hours per 30-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 telep hone 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 [CF34]: Clarify COMS not required for facilities not subject to an opacity standardopacity interference is experienced at all locations (both at the inlet and outlet of the SO 2 control system), alternate parameters indicative of th e 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 SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion technology to reduce emissions of SO 2 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, SO 2 , 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 conducte d 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 owner s 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 (i v) 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 [CF35]: Add ESP model to COMS exemption options

Comment [CF36]: No longer need since proposing to exempt natural gas

‐ fired EGUs form 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 th e most recent performance test was conducted; or (D) If the maximum 6-minute average opacity is gr eater 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 perfor mance test wa s 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 oper ating 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 vi sible emissions are obse rved, 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, bu t not necessarily identical, to the requirements in paragraph (a)(3)(iii) of this section. For referenc e 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), Rese arch 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 SO 2 emissions, except where natural gas and/or liquid fuels (excluding residual oil) with potential SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less are is the only fuel s combusted, as follows: (1) Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO 2 control device. (2) For a facility that qualifies under the numerical limit provisions of §60.43Da (d), (i), (j), or (k) SO 2 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 SO 2 emissions in place of a continuous SO 2 emission monitor at the inlet to the SO 2 control device as required under paragraph (b)(1) of this section. (4) If the owner or operator has installed and certified a SO 2 CEMS according to the requirements of §75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used to meet the requirements of this section, provided that: (i) A CO 2 or O 2 continuous monitoring system is installed, calibrated, maintained and operated at the same location, according to paragraph (d) of this section; and (ii) For sources subject to an SO 2 emission limit in lb/MMBtu under §60.43Da: (A) When relative accuracy testing is conducted, SO 2 concentration data and CO 2 (or O 2 ) data are collected simultaneously; and (B) In addition to meeting the applicable SO 2 and CO 2 (or O 2 ) 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 SO 2 and, if required, CO 2 (or O 2 ) 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 SO 2 data have been bias adjusted according to the procedures of part 75 of this chapter. (c)(1) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring NO X emissions discha rged to the atmosphere; or (2) If the owner or operator has installed a NO X emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongo ing 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 report ed 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 O 2 or carbon dioxide (CO 2 ) content of the flue gases at each location where SO 2 or NO X emissions are monitored. For affected facilities subject to a lb/MMBtu SO 2 emission limit under §60.43Da, if the owner or operator has installed and certified a CO 2 or O 2 monitoring system according to §75.20(c) of Comment [CF37]: Add exemption for low sulfur oil form the SO2 CEMS requirement. Do we need to add a fuel sampling/receipts requirement?

Comment [CF38]: Since adding additional numerical limits it is simpler to just refer the 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 SO 2 concentration monitoring system described in paragraph (b) of this section, to determine the SO 2 emission rate in lb/MMBtu. SO 2 data used to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. (e) The CEMS under paragraphs (b), (c), and (d) of this section are operated and data recorded during all periods of operation of the affected facility including periods of star tup, 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 fo r 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, reconstruc tion, or modification after February 28, 2005, the owner or operator shall obtain emissi on 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 SO 2 concentration at the same location as the SO 2 monitor. Samples shall be taken at 60-minute intervals. The sampling time and sample volume for each sample shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour average. (2) Method 7 of appendix A of this part shall be used to determine the NO X concentration at the same location as the NO X monitor. Samples shall be taken at 30-minute intervals. The arithmetic average of two consecutive samples represents a 1-hour average. (3) The emission rate correction factor, integrated bag sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 or CO 2 concentration at the same location as the O 2 or CO 2 monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample represents a 1-hour average. (4) The procedures in Method 19 of appendix A of this part shall be used to compute each 1-hour average concentration in ng/J (lb/MMBtu) heat input.(i) The owner or operator shall use methods and proc edures 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 O 2 , SO 2 , and NO X concentrations, respectively. (2) SO 2 or NO X (NO), as applicable, shall be used for preparing the calibration gas mixtures (in N 2 , 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 NO X shall be determined using one of the following procedures: (i) Except as provided under paragraph (i)(3)(ii) of this section, NO X span values shall be determined as follows:

Fossil fuel Span values for NO X (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 de rived 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 NO X span values determined according to section 2.1.2 in appendix A to part 75 of this chapter. (4) All span values computed under paragraph (i)(3)(i) of this section for burning combinations of fossil fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (i)(3)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter. (5) For affected facilities burning fossil fuel, alone or in combination with non-fossil fuel and determining span values under paragraph (i)(3)(i) of this section, the span value of the SO 2 CEMS at the inlet to the SO 2 control device is 125 percent of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the SO 2 control device is 50 percent of maximum estimated hourly potential emissions of the fuel fired. For affected facilities determining span values under paragraph (i)(3)(ii) of this section, SO 2 span values shall be determined according to section 2.1.1 in appendix A to part 75 of this chapter. (j) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section:(1) For Method 6 of appendix A of this part, Method 6A or 6B (whenever Methods 6 and 3 or 3B of appendix A of this part data are used) or 6C of appendix A of this part may be used. Each Method 6B of appendix A of this part sample obtained over 24 hours represents 24 1-hour averages. If Method 6A or 6B of appendix A of this part is used under paragraph (i) of this section, the conditions under §60.48Da(d)(1) apply; these conditions do not apply under paragraph (h) of this section. (2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be 1 hour. (3) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used if the sampling time is 1 hour. (4) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used. (k) The procedures specified in paragraphs (k)(1) through (3) of this section shall be used to determine gross 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 el ectrical 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 NO X standards of §60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to Comment [CF39]: Simplify since adding new paragraphs

Comment [CF40]: Should we add some ASTM standards for watt and steam meters?

Comment [CF41]: Simplifymeasure NO X emissions; a wattmeter to measure gross electrical output; meters to measure steam flow, temperature, and pressure; and a continuous flow monitoring system to measure the flow of exhaust gases discharged to the atmosphere. (p) [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 CE MS 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 r ecording) 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 concentrati on. (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 determin ed 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 [CF42]: Delete since CAMR vacatedthis 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 c hapter) 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 a ccordance 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 [CF43]: 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, valid non-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 emis sions 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. Th e 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 O 2 (or CO 2 ) 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 O 2 (or CO 2 ), 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 ElectronicReporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or other compatible electronic spreadsheet. Only data collected using test met hods 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 d ata 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 SO 2 , NO X , CO 2 , and O 2 CEMS to meet the requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (w)(1) through (w)(5) of this section. (1) Except as provided for under paragraphs (w)(2), (w)(3), and (w)(4) of this section, each SO 2 , NO X , CO 2 , and O 2 CEMS required under paragraphs (b) through (d) of this section shall be installed, certified, and operated in accordance with the applicable procedures in Performance Specification 2 or 3 in appendix B to this part or according to the procedures in appendices A and B to part 75 of this chapter. Daily calibration drift assessments and quarterly accuracy determinations shall be done in accordance with Procedure 1 in appendix F to this part, and a data assessment report (DAR), prepared according to section 7 of Procedure 1 in appendix F to this part, shall be submitted with each compliance report required under §60.51Da. (2) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to implement the following alternative data accuracy assessment procedures. For all required CO 2 and O 2 CEMS and for SO 2 and NO X CEMS with span values greater than or equal to 100 ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F of this part. If this option is selected, the data validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this chapter shall be followed instead of the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part. For the purposes of data validation under this subpart, the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part shall apply to SO 2 and NO X span values less than 100 ppm; (3) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For all required CO 2 and O 2 CEMS and for SO 2 and NO X CEMS with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits (CGAs) described in Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linearity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.2.4 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the cylinder gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for SO 2 and NO X span values less than or equal to 30 ppm; Comment [CF44]: 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 SO 2 , CO 2 , and O 2 CEMS and for NO X CEMS, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall be met on a lb/MMBtu basis for SO 2 (regardless of the SO 2 emission level during the RATA), and for NO X when the average NO X emission rate measured by the refere nce 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 SO 2 and NO X . 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 (O 2 ) procedures in Method 19 of appendix A of this part shall be used to compute the emission rate of PM. (2) For the particular matter concentration, Method 5 of appendix A of this part shall be used at affected facilities without wet FGD systems and Method 5B of appendix A of this part shall be used after wet FGD systems. (i) The sampling time and sample volume for each run shall be at least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder heating system in the sampling train may be set to provide an average gas temperature of no greater than 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 O 2 concentration. The O 2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate run. If the particulate run has more than 12 traverse points, the O 2 traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O 2 traverse points. If the grab sampling procedure is used, the O 2 concentration for the run shall be the arithmetic mean of the sample O 2 concentrations 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. (c) The owner or operator shall determine compliance with the SO 2 standards in §60.43Da as follows:(1) The percent of potential SO 2 emissions (%Ps) to the atmosphere shall be computed using the following equation:

Where: %Ps = Percent of potential SO 2 emissions, percent; %Rf = Percent reduction from fuel pretreatment, percent; and %Rg = Percent reduction by SO 2 control system, percent. (2) The procedures in Method 19 of appendix A of this part may be used to determine percent reduction (%R f ) 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 SO 2 reduction (%R g ) of any SO 2 control system. Alternatively, a combination of an “as fired” fuel monitor and emission rates measured after the control system, following the procedures in Method 19 of appendix A of this part, may be used if the percent reduction is calculated using the average emission rate from the SO 2 control device and the average SO 2 input rate from the “as fired” fuel analysis for 30 successive boiler operating days. (4) The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the emission rate. (5) The CEMS in §60.49Da(b) and (d) shall be used to determine the concentrations of SO 2 and CO 2 or O 2
. (d) The owner or operator shall determine compliance with the NO X standard in §60.44Da as follows: (1) The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the emission rate of NO X
. (2) The continuous monitoring system in §60.49D a(c) and (d) shall be used to determine the concentrations of NO X and CO 2 or O 2
. (e) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section: (1) For Method 5 or 5B of appendix A–3 of this part, Method 17 of appendix A–6 of this part may be used at facilities with or without wet FGD systems if the stack temperature at the sampling location does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A–3 of this part may be used in Method 17 of appendix A–6 of this part only if it is used after wet FGD systems. Method 17 of appendix A–6 of this part shall not be used after wet FGD systems if the effluent is saturated or laden with water droplets. (2) The F c factor (CO 2 ) 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 CO 2 shall be determined in the same manner as the O 2 concentration.(f) Electric utility combined cycle gas turbines that are not designed to burn fuels containing 50 percent (by heat input) or more solid derived fuel not meeting the definition of natural gas are performance tested for PM, SO 2 , and NO X using the procedures of Method 19 of appendix A–7 of this part. The SO 2 and NO X emission rates calculations from the gas turbine used in Method 19 of appendix A–7 of this part are determined when the gas turbine is pe rformance 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
pro cedures in paragraphs (g)(1) and (2) of this sectio n 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 conversi ons 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 M W 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:

ER cogen = 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);

V grid = Amount of energy sent to the grid over the same compliance period (MWh); and

V process = 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 specif ied 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, shutd own 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 fo r that month, as follows. For the first such month, the substitute monthly Hg emission rate shall be the arithmetic average of all valid hourly Hg emission rates recorded to date. For any subsequent month(s) with insufficient data capture, the substitute monthly Hg emission rate shall be the highest valid hourly Hg emission rate recorded to date. Whenth e 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 th at 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 sta rtup, 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 mont h (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:

E h = Hg mass emissions for the hour, (lb); K = Units conversion constant, 6.24 × 10 − 11 lb

- scm/μgm

- scf;

C h = Hourly H g concentration, wet basis, (μgm/scm); Q h = Hourly stack gas volumetric flow rate, (scfh); and

t h = 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 me asures Hg concentration on a dry basis, use Equation 7 below to calculate the Hg mass emissions for each valid hour:

Where:

E h = Hg mass emissions for the hour, (lb); K = Units conversion constant, 6.24 × 10 − 11 lb

- scm/μgm

- scf;

C h = Hourly Hg concentration, dry basis, (μgm/dscm); Q h = Hourly stack gas volumetric flow rate, (scfh);

t h = Unit operating time, i.e. , the fraction of the hour for which the unit operated; and

B ws = Stack gas moisture content, expressed as a decimal fraction ( e.g. , for 8 percent H 2 O , B ws = 0.08). (C) Use Equation 8, below, to calculate M, the tota l mass of Hg emitted for the month, by summing the hourly masses derived from Equation 6 or 7 (as applicable):Where: M = Total Hg mass emissions for the month, (lb);

E h = 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 Equ ation 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:

E avg = Weighted 12

- month rolling average Hg emission rate, (lb/MWh);

ER i = Monthly Hg emission rate, for month “i”, (lb/MWh); and n = Number of unit operating hours in mon th “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 th at for a particular pair of sorbent traps, C h in Equation 7 shall be the flow

- proportional average Hg concentration measured over the data collection peri od. (i) Daily calibration drift (CD) tests and quarterly accuracy determinations shall be performed for Hg CEMS in accordance with Procedure 1 of appendix F to this part. For the CD assessments, you may use either elemental mercury or mercuric chloride (Hg ° HgCl 2 ) standards. The four quarterly accuracy determinations shall consist of one RATA an d three measurement error (ME) tests using HgCl 2 standards, as described in section 8.3 of Performance Specification 12

– A in appendix B to thispart (note: Hg° standa rds may be used if the Hg monitor does not have a converter). Alternatively, the owner or operator may implement the applicable dail y, weekly, quarterly, a nd annual quality assurance (QA) requirements for Hg CEMS in appendix B to part 75 of this chapter, i n 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 ap pendix K to part 75 of this chapter shall be met for sorbent trap monitoring systems. §60.51Da Reporting requirements. (a) For SO 2 , NO X , 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 SO 2 and NO X the following information is reported to the Administrator for each 24-hour period. (1) Calendar date. (2) The average SO 2 and NO X emission rates (ng/J, lb/MMBtu, or lb/MWh) for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the emission standards; and, description of corrective actions taken. (3) For owners or operators of affected facilities complying with the percent reduction requirement, percent reduction of the potential combustion concentration of SO 2 for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the standard; and, description of corrective actions taken. (4) Identification of the boiler operating days fo r which pollutant or diluent data have not been obtained by an approved method for at least 75 pe rcent 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 (NO X only), emergency conditions (SO 2 only), or other reasons, and justification for excluding data for reasons other than startup, shutdown, malfunction, or emergency conditions. (6) Identification of “F” factor used for calculations, method of determination, and type of fuel combusted. (7) Identification of times when hourly averages have been obtained based on manual sampling methods. (8) Identification of the times when the pollutant concentration exceeded full span of the CEMS. (9) Description of any modifications to CEMS which could affect the ability of the CEMS to comply with Performance Specifications 2 or 3. (c) If the minimum quantity of emission data as required by §60.49Da is not obtained for any 30 successive boiler operating days, the followin g information obtained under the requirements of §60.48Da(h) is reported to the Ad ministrator for that 30-day period: (1) The number of hourly averages available for outlet emission rates (no) and inlet emission rates (n i ) as applicable.(2) The standard deviation of hourly averages for outlet emission rates (s o ) and inlet emission rates (s i ) as applicable. (3) The lower confidence limit for the mean outlet emission rate (E o *) and the upper confidence limit for the mean inlet emission rate (E i *) as applicable. (4) The applicable potential combustion concentration. (5) The ratio of the upper confidence limi t for the mean outlet emission rate (E o *) and the allowable emission rate (E std ) 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 SO 2 emission standard under §60.43Da is claimed, the owner or operator of the affected facility shall submit a signed statement: (1) Indicating what percentage cleaning credit was taken for the calendar quarter, and whether the credit was determined in accordance with the provisions of §60.50Da and Method 19 of appendix A of this part; and (2) Listing the quantity, heat content, and date each pretreated fuel shipment was received during the previous quarter; the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels received at the affected facility during the previous quarter. (f) For any periods for which opacity, SO 2 or NO X emissions data are not available, the owner or operator of the affected facility shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability. (g) [Reserved] 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 as sessment 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 no t 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 SO 2 and/or NO X and/or opacity and/or Hg in lieu of submitting the written reports required under paragraphs (b), (g), and (i) of this section. The format of each quart erly 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 o f 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 (NO X 

### ) 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 NO X 

### standards under this subpart and to the sulfur dioxide (SO 2 

### ) 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 NO X 

### standards under this subpart.
(4) Oil-fired affected facilities having a heat input capacity greater th an 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 NO X 

### standards under this subpart and the PM and SO 2 

### standards 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 NO X 

### standards under this subpart and the SO 2 

### standards under subpart J or subpart Ja (§60. 104 )

. (d) Affected facilities that also meet the applicab ility requirements under subpart E (Standards of performance for incinerators; §60.50) are subject to the NO X 

### and PM standards under this subpart.
(e) Steam generating units meeting the applicability requirements under subpart Da (Standards of performance for electric utility steam generating uni ts; §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 define d 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 sha ll be retained by the Administrator and not transferred to a State. Comment [CF1]: Add subpart Ja exemption.

Comment [CF2]: Should this say ‘not’ subject?
Is subpart E still applicable to any facilities?

### (1) Section 60.44b(f).
(2) Section 60.44b(g).

(3) Section 60.49b(a)(4).

(h) Any affected facility that meets the applicabil ity requirements and is subject to subpart Ea, subpart Eb, or subpart AAAA , or subpart CCCC of this part is not covered by subject to this subpart.

(i) Affected facilities (i.e. H h eat recovery steam generators ) that are associated with combined cycle gas stationary combustion turbines and that meet the applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other affected facilities (i.e. heat recovery steam generators with duct burners) that are capable of combusting more than 29 MW (100 MMBtu/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 genera ting unit are subject to this subpart. (The gas stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part.)
(j) Any affected facility meeting the applicabi lity 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 appli cability 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 cove red by this subpart.
(l) Affected facilities that also meet the app licability requirements under subpart BB (Standards of Performance for Kraft Pulp Mills) are subject to the SO 2 

### and NO X 

### standards under this subpart and the PM standards under subpart BB.

§60.41b Definitions.
As used in this subpart, all terms not defined he rein 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 stat e 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 mill s (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 (CO 2 

### ) levels greater than 50 percent or carbon monoxide levels greater than 10 percent are not byproduct/waste for the purpose of this subpart. Comment [CF3]: Exempt owner/operators of CISWI facilities from subpart Db

Comment [CF4]: 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 mi xtures, 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 generate d 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 combus tion 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 SO 2 

### control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline slurries or solutions used in dry flue gas desu lfurization 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 [CF5]: Expand definitions to include other similar fuels. Need to amend 60.17 as well.

### the firing of additional fuel to heat the exhaus t gases before the exhaust gases enter a steam generating unit.
Emerging technology means any SO 2 

### control system that is not defined as a conventional technology under this section, and for which the owner or operator of the facility has applied to the Administrator and received approval to operate as an emerging technology under §60.49b(a)(4).
Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State Implementation Plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24.
Fluidized bed combustion technology means combustion of fuel in a bed or series of beds (including but not limited to bubbling bed units an d 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 addi tional electrical or mech anical 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 fron t of the first row of convection pass tubes.
Heat transfer medium means any material that is used to transfer heat from one point to another point.
High heat release rate means a heat release rate greater than 730,000 J/sec-m 3 

### (70,000 Btu/hr-ft 3 

### ).

### ISO Conditions means a temperature of 288 Kelvin, a re lative 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-m 3 

### (70,000 Btu/hr-ft 3 

### ) or less.
Mass-feed stoker steam generating unit means a steam generating unit where solid fuel is introduced directly into a retort or is fed directly onto a grate where it is combusted.
Maximum heat input capacity means the ability of a steam gene rating 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 SO 2 

### emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems. For gasified coal or oil that is desulfurized prior to combustion, the Potential sulfur dioxide emission rate is the theoretical SO 2 

### emissions (ng/J or lb/MMBtu heat input) that would result from combusting fuel in a cleaned state without using any post combustion emission control systems.

Process heater means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst.

### Pulp and paper mills means industrial plants that are clas sified by the Department of Commerce under North American Industry Classification Sy stem (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 carri es the coal to the combustion chamber of the steamgenerating 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 comb usted 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 SO 2 

### emission control, has a SO 2 

### emission rate equal to or less than 215 ng/J (0.5 lb/MMBtu) heat input. For units constructed, reconstructed, or modified after February 28, 2005 and not located in a noncontinental area, very low sulfur oil means oil that contains no more than 0.30 weight percent sulfur or that, when combusted without SO 2 

### emission control, has a SO 2 

### emission rate equal to or less than 140 ng/J (0.32 lb/MMBtu) heat input. For units constructed, reconstructed, or modified after February 28, 2005 and located in a noncontinental

area, very low sulfur oil means oil that contains no more than 0.5 weight percent sulfur or that, when combusted without SO 2 

### emission control, has a SO 2 

### emission rate equal to or less than 215 ng/J (0.50 lb/MMBtu) heat input.
Wet flue gas desulfurization technology means a SO 2 

### control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gas with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet flue gas desulfurization technology include, but are no t 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 SO 2


### . 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 (SO 2 

### ).
(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 af fected facility that co mmenced 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 SO 2 

### in excess of 87 ng/J (0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO 2 

### emission rate (90 percent reduction) and the emission limit determined according to the following formula:

Where:

E s 

### = SO 2 

### emission limit, in ng/J or lb/MMBtu heat input;

K a 

### = 520 ng/J (or 1.2 lb/MMBtu);

K b 

### = 340 ng/J (or 0.80 lb/MMBtu);

H a 

### = Heat input from the combustion of coal, in J (MMBtu); and

H b 

### = Heat input from the combustion of oil, in J (MMBtu).
For facilities complying with the percent reductio n standard, only the heat input supplied to the affected facility from the combustion of coal and o il is counted in this paragraph. No credit is provided for the heat input to the affected facil ity from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or h eat 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 SO 2 

### in excess of 87 ng/J (0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO 2 

### emission rate (80 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. If coal or oil is fired with coal refuse, the affected facility is subject to paragraph (a) or (d) of this section, as app licable. 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. 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 in sert it again.

### (c) On and after the date on which the performan ce test is completed or is required to be completed under §60.8, whichever comes first, no ow ner 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 SO 2 

### emissions, shall cause to be discharged into the atmosphere any gases that contain SO 2 

### in excess of 50 percent of the potential SO 2 

### emission rate (50 percent reduction) and that contain SO 2 

### in excess of the emission limit determined according to the following formula:

Where:

E s 

### = SO2 emission limit, in ng/J or lb/MM Btu heat input;

K c 

### = 260 ng/J (or 0.60 lb/MMBtu);

K d 

### = 170 ng/J (or 0.40 lb/MMBtu);

H c 

### = Heat input from the combustion of coal, in J (MMBtu); and

H d 

### = Heat input from the combustion of oil, in J (MMBtu).
For facilities complying with the percent reductio n standard, only the heat input supplied to the affected facility from the combustion of coal and o il is counted in this paragraph. No credit is provided for the heat input to the affected facil ity 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 SO 2 

### in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input if the affected facility combusts oil other than very low sulfur oil. Per cent 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 natu ral 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 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 in sert it again.

### (3) Affected facilities co mbusting 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 c oke oven gas alone or in combin ation with natural gas or very low sulfur distillate oil.
(e) Except as provided in paragraph (f) of this s ection, compliance with the emission limits, fuel oil sulfur limits, and/or percent reduction require ments 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 pe rmit 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 SO 2 

### emission limits and percent reduction requirements under this section apply at all times, including periods of startup, shutdown, and malfunction.
(h) Reductions in the potential SO 2 

### emission rate through fuel pretreatment are not credited toward the percent reduction requirement under paragraph (c) of this section unless:
(1) Fuel pretreatment results in a 50 percent or greater reduction in potential SO 2 

### emissions and
(2) Emissions from the pretreated fuel (without combustion or post-combustion SO 2 

### control) are equal to or less than the emission limits sp ecified 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 SO 2 

### control system is not being operated because of malfunction or maintenance of the SO 2 

### control system.
(j) Percent reduction requirements are not applicab le 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 SO 2 

### emission rate or fuel oil sulfur content; or (2) maintaining fuel records as described in §60.49b(r).
(k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) of this section, on and after the date on which the initial performance test is co mpleted 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 SO 2 

### in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 8 per cent (0.08) of the potential SO 2 

### emission rate (92 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat i nput. 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 o il 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 SO 2 

### emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less are exempt from the SO 2 

### emissions limit in paragraph (k)(1) of this section.
(3) Units that are located in a noncontinental area and that combust coal, oil, or natural gas shall not discharge any gases that contain SO 2 

### in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input if the affected facility combusts oil or natural gas.
(4) As an alternative to meeting the requirements under paragraph (k)(1) of this section, modified facilities that combust coal or a mixture of coal with other fuels shall not cause to be discharged into the atmosphere any gases that contain SO 2 

### in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO 2 

### 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 perfo rmance 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/MMB tu) heat input, (i) If the affected facility combusts only coal, or
(ii) If the affected facility combusts coal and ot her 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 af fected facility combusts coal and other fuels and has an annual capacity factor for the other fuels gr eater 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 af fected 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 limi ting 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 no t using a post-combustion technology (except a wet scrubber) for reducing PM or SO 2 

### emissions is not subject to the PM limits under §60.43b(a).
(b) On and after the date on which the performance test is completed or required to be completed under §60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, and that combusts oil (or mixtures of oil with other fuels) and us es a conventional or emerging technology to reduce SO 2 

### emissions shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
(c) On and after the date on which the initial perfo rmance test is completed or is required to be completed under §60.8, whichever comes first, no ow ner 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 requireme nt 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 perfo rmance 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 mixt ures of municipal-type solid waste with other fuels, shall cause to be discharged into the atmo sphere 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 limi ting operation of the affected facility to an annual capacity factor of 30 percent (0.30) or le ss 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 co mpleted 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 in itial 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 fuel s, or a mixture of these fuels with any other fuels shall cause to be discharged into the atmos phere 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 paragrap h. 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 modifica tion 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 perfo rmance 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 perfo rmance 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 perfo rmance 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 no t subject to a PM standard in §60.43b and not using a post-combustion technology (except a wet scrubber) to reduce SO 2 

### or PM emissions is not subject to the PM limits in (h)(1) of this section.
(6) On and after the date on which the initial perfo rmance 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 fu els, 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 SO 2 

### or PM emissions is not subject to the PM limits in (h)(1) of this section.
§60.44b Standard for nitrogen oxides (NO X 

### ).
(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 affect ed facility that is subj ect 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 NO X 

### (expressed as NO 2 

### ) in excess of the following emission limits:

Fuel/steam generating unit type N itrogen oxide emission limits (expressed as NO 2 

### ) heat input

ng/J lb/MMB t T u
(1) Natural gas and distilla te 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 operato r of an affected facility that simultaneously combusts mixtures of only??? coal, oil, or natural gas shall cau se to be discharged into the atmosphere from that affected facility any gases that contain NO X 

### in excess of a limit determined by the use of the following formula:

Where:

E n 

### = NO X 

### emission limit (expressed as NO 2 

### ), ng/J (lb/MMBtu);

EL go 

### = Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/MMBtu); 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 in sert it again.

### H go 

### = Heat input from combustion of natural gas or distillate oil, J (MMBtu);

EL ro 

### = Appropriate emission limit from paragraph (a)(2) for combustion of residual oil, ng/J (lb/MMBtu);

H ro 

### = Heat input from combustion of residual oil, J (MMBtu);

EL c 

### = Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and

H c 

### = 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 aff ected 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 NO X 

### in excess of the emission limit for the coal or oil, or mixt ures 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 fo r 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 f acility 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 perform ance 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 SO 2 

### 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 NO X 

### 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 requi red to be completed unde r §60.8, whichever date comes first, no owner or operator of an aff ected facility that simultaneously combusts only? coal, oil, or natural gas with bypro duct/waste shall cause to be disc harged into the atmosphere any gases that contain NO X 

### in excess of the emission limit determined by the following formula unless the affected facility has an annual capacity factor for coal, oil, and natural gas of 10 percent (0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10 percent (0.10) or less:

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 in sert it again. Comment [CF8]: 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.

### Where:

E n 

### = NO X 

### emission limit (expressed as NO 2 

### ), ng/J (lb/MMBtu);

EL go 

### = Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);

H go 

### = Heat input from combustion of natural gas, distillate oil and gaseous byproduct/waste, J (MMBtu);

EL ro 

### = Appropriate emission limit from paragraph (a )(2) for combustion of residual oil and/or byproduct/waste, ng/J (lb/MMBtu);

H ro 

### = Heat input from combustion of residual oil, J (MMBtu);

EL c 

### = Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and

H c 

### = 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 NO X 

### emission limit that shall apply specifically to that affected facility when the byproduct/waste is combus ted. The petition shall include sufficient and appropriate data, as determined by the Administrator, such as NO X 

### emissions from the affected facility, waste composition (including nitrogen content), and combustion conditions to allow the Administrator to confirm that the affected facility is unable to comply with the emission limits in paragraph (e) of this section and to determine the appropriate emission limit for the affected facility.
(1) Any owner or operator of an affected facility petitioning for a facility-specific NO X 

### emission limit under this section shall:
(i) Demonstrate compliance with the emission limits for natural gas and dist illate oil in paragraph (a)(1) of this section or for residual oil in paragr aph (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 sh all be combusted in the affected facility; and
(ii) Demonstrate that the affected facility is unabl e 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 gase ous 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 demonstr ating compliance under paragraph (f)(1)(i) of this section.

(2) The NO X 

### emission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, shall be applicable to the affected facility until and unless the petition is approved by the Administrator. If the petition is approved by the Administrator, a facility-specific NO X 

### emission limit will be established at the NO X 

### emission level achievable when the affected facility is combusting oil or natural gas and byproduct/waste in a manner that the Administrato r determines to be consistent with minimizing

### NO X 

### emissions. In lieu of amending this subpart, a le tter will be sent to the facility describing the facility-specific NO X 

### limit. The facility shall use the compliance procedures detailed in the letter and make the letter available to the public. If the Administrator determines it is appropriate, the conditions and requirements of the letter can be reviewed and changed at any point.
(g) Any owner or operator of an affected facility that combusts hazardous waste (as defined by 40 CFR part 261 or 40 CFR part 761) with natural gas or oil may petition the Administrator within 180 days of the initial startup of the affected facility for a waiver from compliance with the NO X 

### emission limit that applies specifically to that affected facility. The petition must include sufficient and appropriate data, as dete rmined by the Administrator, on NO X 

### emissions from the affected facility, waste destruction efficiencies , waste composition (including nitrogen content), the quantity of specific wastes to be com busted and combustion conditions to allow the Administrator to determine if the affected facility is able to comply with the NO X 

### emission limits required by this section. The owner or operator of the affected facility shall demonstrate that when hazardous waste is combusted in the aff ected facility, thermal destruction efficiency requirements for hazardous waste specified in an applicable federally enforceable requirement preclude compliance with the NO X 

### emission limits of this section. The NO X 

### emission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, are applicable to the af fected facility until and unless the petition is approved by the Administ rator. (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 NO X 

### limit. The facility shall use the compliance pro cedures 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 NO X 

### standards under this section apply at all times including periods of startup, shutdown, or malfunction.
(i) Except as provided under paragraph (j) of this section, compliance with the emission limits under this section is determined on a 30-day rolling average basis.
(j) Compliance with the emission limits under th is 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 natu ral 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 en forceable requirement limiting operation of the affected facility to the firing of natural gas, distillate oil, and/or residual oil with a nitroge n 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, distil late 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 NO X 

### emission limits under this section.
(l) On and after the date on which the initial perf ormance 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 affect ed facility any gases that contain NO X 

### (expressed as NO 2 

### ) in excess of the following limits:
(1) If the affected facility combusts coal, oil, natu ral 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 requi rement 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:

E n 

### = NO X 

### emission limit, (lb/MMBtu);

H go 

### = 30-day heat input from combustion of natural gas or distillate oil; and

H r 

### = 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 comp lying 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 SO 2 

### emission standards in §60.42b apply at al l times. Facilities burning coke oven gas alone or in combination with any other gaseous fu els or distillate oil are allowed to exceed the limit 30 operating days per calendar year for SO 2 

### control system maintenance.
(b) In conducting the performance tests required under §60.8, the owner or operator shall use the methods and procedures in appendix A (including fu el 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 sec tion. The 30-day notice required in §60.8(d) applies only to the initial performance test unless otherwis e specified by the Administrator. 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 in sert it again.

### (c) The owner or operator of an affected facility shall conduct performance tests to determine compliance with the percent of potential SO 2 

### emission rate (% P s 

### ) and the SO 2 

### emission rate (E s 

### ) 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 SO 2 

### standards shall be determined using a 30-day average. The first operating day included in the initial performance test shall be scheduled within 30 days after achieving the maximum production ra te 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 SO 2 

### emission rate (E ho 

### ) and the 30-day average emission rate (E ao 

### ). 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 SO 2 

### emission rate (%P s 

### ) emitted to the atmosphere is computed using the following formula:

Where:

%P s 

### = Potential SO 2 

### emission rate, percent;

%R g 

### = SO 2 

### removal efficiency of the control device as determined by Method 19 of appendix A of this part, in percent; and

%R f 

### = SO 2 

### removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, in percent.
(3) If coal or oil is combusted with other fuels, the same procedures required in paragraph (c)(2) of this section are used, except as provided in the following:
(i) An adjusted hourly SO 2 

### emission rate (E ho o 

### ) is used in Equation 19–19 of Method 19 of appendix A of this part to compute an adjusted 30-day average emission rate (E ao o 

### ). The Eho° is computed using the following formula:

Where:

E ho o 

### = Adjusted hourly SO 2 

### emission rate, ng/J (lb/MMBtu); 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 in sert 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 in sert it again.

### E ho 

### = Hourly SO 2 

### emission rate, ng/J (lb/MMBtu);

E w 

### = SO 2 

### concentration in fuels other than coal and oil combusted in the affected facility, as determined by the fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The value E w 

### for each fuel lot is used for each hourly average during the time that the lot is being combusted; and

X k 

### = Fraction of total heat input from fuel combustio n 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 SO 2 

### emission rate (%P s 

### ), an adjusted %R g 

### (%R g o 

### ) is computed from the adjusted E ao o 

### from paragraph (b)(3)(i) of this section and an adjusted average SO 2 

### inlet rate (E ai o 

### ) using the following formula:

To compute E ai o 

### , an adjusted hourly SO 2 

### inlet rate (E hi o 

### ) is used. The E hi o 

### is computed using the following formula:

Where:

E hi o 

### = Adjusted hourly SO 2 

### inlet rate, ng/J (lb/MMBtu); and

E hi 

### = Hourly SO 2 

### inlet rate, ng/J (lb/MMBtu).
(4) The owner or operator of an affected facility subject to paragraph (c)(3) of this section does not have to measure parameters E w 

### or X k 

### if the owner or operator elects to assume that X k 

### = 1.0. Owners or operators of affected facilities who assume X k 

### = 1.0 shall:

(i) Determine %P s 

### following the procedures in paragraph (c)(2) of this section; and

(ii) Sulfur dioxide emissions (E s 

### ) are considered to be in compliance with SO 2 

### emission limits under §60.42b.
(5) The owner or operator of an affected facility that qualifies under the provisions of §60.42b(d) does not have to measure parameters E w 

### or X k 

### in paragraph (c)(3) of this section if the owner or operator of the affected facility elects to measure SO 2 

### emission rates of the coal or oil following the fuel sampling and analysis procedures in Method 19 of appendix A–7 of this part.
(d) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility that combusts only very low sulfur oil, natural gas, or a mixture of these fuels, has an annual capacity factor for oil of 10 percent (0.10) or less, and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor for oil of 10 percent (0.10) or less shall: 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 in sert 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 in sert it again.

### (1) Conduct the initial performance test over 24 consecutive steam generating unit operating hours at full load;
(2) Determine compliance with the standards af ter 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 generati ng 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 an y 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, otherw ise the maximum design capacity provided by the manufacturer is used.
(f) For the initial performance test required under §60.8, compliance with the SO 2 

### emission limits and percent reduction requirements under §60.42b is based on the average emission rates and the average percent reduction for SO 2 

### for the first 30 consecutive steam generating unit operating days, except as provided under para graph (d) of this section. The initial performance test is the only test for which at least 30 days prior no tice 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 ra te at which the affected facility will be operated, but not later than 180 da ys after initial startup of the f acility. 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 requi red under §60.8, compliance with the SO 2 

### emission limits and percent reduction requirements under §60.42b is based on the average emission rates and the average percent reduction for SO 2 

### for 30 successive steam generating unit operating days, except as provided under paragraph (d). A separate performance test is completed at the end of each steam generating unit operating day after the initial performance test, and a new 30-day average emission rate and percent reduction for SO 2 

### are calculated to show compliance with the standard.
(h) Except as provided under paragraph (i) of this section, the owner or operator of an affected facility shall use all valid SO 2 

### emissions data in calculating %P s 

### and E ho 

### under paragraph (c), of this section whether or not the minimum emissions data requirements under §60.46b are achieved. All valid emissions data, including valid SO 2 

### emission data collected during periods of startup, shutdown and malfunction, shall be used in calculating %P s 

### and E ho 

### pursuant to paragraph (c) of this section.
(i) During periods of malfunct ion or maintenance of the SO 2 

### control systems when oil is combusted as provided under §60.42b(i), emission data are not used to calculate %P s 

### or E s 

### under §60.42b(a), (b) or (c), however, the emissions data are used to determine compliance with the emission limit under §60.42b(i).

### (j) The owner or operator of an affected facility that only combusts very low sulfur oil, natural gas, or a mixture of these fuels with any other fuels not subject to an SO 2 

### standard is not subject to the compliance and performance testing requirements of this section if the owner or operator obtains fuel receipts as described in §60.49b(r).
(k) The owner or operator of an affected facility seeking to demonstrate compliance in §§60.42b(d)(4), 60.42b(j), 60.42b(k)(2), and 60.42b(k)(3) (when not burning coal) shall follow the applicable procedures in §60.49b(r).
§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 NO X 

### emission standards under §60.44b apply at all times.
(b) Compliance with the PM emission standards under §60.43b shall be determined through performance testing as described in paragraph (d) of this section, except as provided in paragraph (i) of this section.
(c) Compliance with the NO X 

### emission standards under §60.44b shall be determined through performance testing under paragraph (e) or (f), or under paragraphs (g) and (h) of this section, as applicable.
(d) To determine compliance with the PM emission limits and opacity limits under §60.43b, the owner or operator of an affected facility shall conduct an initial performance test as required under §60.8, and shall conduct subsequent perfor mance 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 pa rt 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 ma y 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 pa rt 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 (O 2 

### ) or CO 2 

### sample is obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling location.
(6) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rate expressed in ng/J heat input is determined using:

(i) The O 2 

### or CO 2 

### measurements and PM measurements obtained under this section;
(ii) The dry basis F factor; and
(iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this part.
(7) Method 9 of appendix A of this part is used for determining the opacity of stack emissions.
(e) To determine compliance with the emission limits for NO X 

### required under §60.44b, the owner or operator of an affected facility shall conduct the performance test as required under §60.8 using the continuous system for monitoring NO X 

### under §60.48(b).
(1) For the initial compliance test, NO X 

### from the steam generating unit are monitored for 30 successive steam generating unit operating days and the 30-day average emission rate is used to determine compliance with the NO X 

### emission standards under §60.44b. The 30-day average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 30-day test period.
(2) Following the date on which the initial perform ance 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 NO X 

### emission standards in §60.44b on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated for each steam generating unit operating day as the average of all of the hourly NO X 

### emission data for the preceding 30 steam generating unit operating days.
(3) Following the date on which the initial perform ance test is completed or is required to be completed under §60.8, whichever da te comes first, the owner or op erator of an af fected 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 nitr ogen content of 0.30 weight percent or less shall determine compliance with the NO X 

### standards under §60.44b on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NO X 

### emission data for the preceding 30 steam generating unit operating days.

### (4) Following the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, the owner or operator of an affected facility that has a heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts natural gas, distillate oil, gasified coal, or residual oil having a nitrogen content of 0.30 weight percent or less shall upon request determine compliance with the NO X 

### standards in §60.44b through the use of a 30-day performance test. During periods when performance tests are not requested, NO X 

### emissions data collected pursuant to §60.48b(g)(1) or §60.48b(g)(2) are used to calculate a 30-day rolling average emission rate on a daily basis and used to prepare excess emission reports, but will not be used to determine compliance with the NO X 

### emission standards. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NO X 

### emission data for the preceding 30 steam generating unit operating days.
(5) If the owner or operator of an affected facility that combusts residual oil does not sample and analyze the residual oil for nitrogen content, as specified in §60.49b(e), the requirements of §60.48b(g)(1) apply and the provisions of §60.48b(g)(2) are inapplicable.
(f) To determine compliance with the emissions limits for NO X 

### required by §60.44b(a)(4) or §60.44b(l) for duct burners used in combined cycle systems, either of the procedures described in paragraph (f)(1) or (2) of this section may be used:
(1) The owner or operator of an affected facility shall conduct the performance test required under §60.8 as follows:

(i) The emissions rate (E) of NO X 

### shall be computed using Equation 1 in this section:

Where:

E = Emissions rate of NO X 

### from the duct burner, ng/J (lb/MMBtu) heat input;

E sg 

### = Combined effluent emissions rate, in ng/J (l b/MMBtu) heat input using appropriate F factor as described in Method 19 of appendix A of this part;

H g 

### = Heat input rate to the combustion turbine, in J/hr (MMBtu/hr);

H b 

### = Heat input rate to the duct burner, in J/hr (MMBtu/hr); and

E g 

### = 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 NO X 

### concentrations. Method 3A or 3B of appendix A of this part shall be used to determine O 2 

### concentration.
(iii) The owner or operator sha ll 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 in sert it again.

### (iv) Compliance with the emission s 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 NO X 

### and O 2 

### and meet the requirements of §60.48b. The sampling site shall be located at the outlet from the steam generating unit. The NO X 

### emissions rate at the outlet fro m the steam generating unit shall constitute the NO X 

### emissions rate from the duct burner of the combined cycle system.
(g) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall demonstrate the maximum heat input capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. The owner or operator of an affected facility shall determine the maximum heat input capacity using the heat loss method or the heat input method described in sections 5 and 7.3 of the ASME Power Test Codes 4.1 (incorporated by reference, see §60.17). This demonstration of maximum heat input capacity shall be made during the initial performance test for affected facilities that meet the criteria of §60.44b(j). It shall be made within 60 days after achieving the maximum production ra te 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 demons tration 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 facilit y 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 NO X 

### emission 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 NO X 

### emission standards under §60.44b over a minimum of 3 consecutive steam generating unit operating hours at maximum heat input capacity using Method 7, 7A, 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 comp leted 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 specifi ed 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 calculati ng 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 th e CEMS required by Performance Specification 11 in appendix B of this part, PM and O 2 

### (or CO 2 

### ) 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 O 2 

### (or CO 2 

### ), 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 Ad ministrator 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., refere nce 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 require ment to be submitted electronically into EPA’s WebFIRE database. After July 1, 2011, within 90 days af ter completing a correlation testing run, the owner or operator of an affected facility sha ll 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 C ode: 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 SO 2 

### standards in §60.42b shall install, calibrate, maintain, and operate CEMS for measuring SO 2 

### concentrations and either O 2 

### or CO 2 

### concentrations and shall record the output of the systems. For units complying with the percent reduction standard, the SO 2 

### and either O 2 

### or CO 2 

### concentrations shall both be monito red at the inlet and outlet of the SO 2 

### control device. If the owner or operator has installed and certified SO 2 

### and O 2 

### or CO 2 

### CEMS according to the requirements of §75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, those CEMS may be used to meet the requirements of this s ection, provided that:
(1) When relative accuracy testing is conducted, SO 2 

### concentration data and CO 2 

### (or O 2 

### ) data are collected simultaneously; and
(2) In addition to meeting the applicable SO 2 

### and CO 2 

### (or O 2 

### ) 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 [CF9]: Updated language for electronic reporting.

### (3) The reporting requirements of §60.49b are met. SO 2 

### and CO 2 

### (or O 2 

### ) data used to meet the requirements of §60.49b shall not include substitu te data values derive d from the missing data procedures in subpart D of part 75 of this chapter, nor shall the SO 2 

### data have been bias adjusted according to the procedures of part 75 of this chapter.
(b) As an alternative to operating CEMS as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO 2 

### emissions and percent reduction by:
(1) Collecting coal or oil samples in an as-fired condition at the inlet to the steam generating unit and analyzing them for sulfur and heat content according to Method 19 of appendix A of this part. Method 19 of appendix A of this part provides procedures for converting these measurements into the format to be used in calculating the average SO 2 

### input rate, or
(2) Measuring SO 2 

### according to Method 6B of appendix A of this part at the inlet or outlet to the SO 2 

### control system. An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of this part sampling location. The stratification test shall consist of three paired runs of a suitable SO 2 

### and CO 2 

### measurement train operated at the candidate location and a second similar train operated according to the procedures in section 3.2 and the applicable procedures in section 7 of Performance Specification 2. Method 6B of appendix A of this part, Method 6A of appendix A of this part, or a combination of Methods 6 and 3 or 3B of appendix A of this part or Methods 6C and 3A of appendix A of this part are suitable measurement techniques. If Method 6B of appendix A of this part is used for the second train, sampling time and timer operation may be adjusted for the strati fication 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 SO 2 

### emission rate, E D 

### , shall be determined using the procedure described in Method 6A of appendix A of this part, section 7.6.2 (Equ ation 6A–8) and stated in ng/J (lb/MMBtu) heat input.
(4) The mean 30-day emission rate is calcula ted 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 da ta with data collected with other monitoring systems as approved by the Administrator or th e reference methods and procedures as described in paragraph (b) of this section.
(d) The 1-hour average SO 2 

### emission rates measured by the CEMS required by paragraph (a) of this section and required under §60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used to calculate the average emission rates under §60.42(b). Each 1-hour average SO 2 

### emission rate must be based on 30 or more minutes of steam generating unit operation. The hourly averages shall be calculated according to §60.13(h)(2). Hourly SO 2 

### emission rates are not

### calculated if the affected facility is operated le ss 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 combus ting coal or oil, alone or in co mbination with other fuels, the span value of the SO 2 

### CEMS at the inlet to the SO 2 

### control device is 125 percent of the maximum estimated hourly potential SO 2 

### emissions of the fuel combusted, and the span value of the CEMS at the outlet to the SO 2 

### control device is 50 percent of the maximum estimated hourly potential SO 2 

### emissions of the fuel combusted. Alternatively, SO 2 

### span values determined according to section 2.1.1 in appendix A to part 75 of this chapter may be used.
(4) As an alternative to meeting the requirements of requirements of paragraphs (e)(1) and (e)(2) of this section, the owner or operator may el ect to implement the following alternative data accuracy assessment procedures:
(i) For all required CO 2 

### and O 2 

### monitors and for SO 2 

### and NO X 

### monitors with span values greater than or equal to 100 ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F to this part.
(ii) For all required CO 2 

### and O 2 

### monitors and for SO 2 

### and NO X 

### monitors with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits (CGAs) described in Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linear ity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; the data valid ation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter sha ll 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 SO 2 

### and NO X 

### span values less than or equal to 30 ppm; and

(iii) For SO 2 

### , CO 2 

### , and O 2 

### monitoring systems and for NO X 

### emission rate monitoring systems, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy

### specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall be met on a lb/MMBtu basis for SO 2 

### (regardless of the SO 2 

### emission level during the RATA), and for NO X 

### when the average NO X 

### emission rate measured by the reference method during the RATA is less than 0.100 lb/MMBtu.
(f) The owner or operator of an affected facility that combusts very low sulfur oil or is demonstrating compliance under §60.45b(k) is not subject to the emission monitoring requirements under paragraph (a) of this section if the owner or operator maintains fuel records as described in §60.49b(r).
§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 sh all 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 subs equent Method 9 of appendix A–4 of this part performance test must be comple ted 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 da te that the most recent performance test was conducted; Comment [CF10]: Could we cut this date since it will only be historical?

Comment [CF11]: Request comment on simplifying to: 5% of less

– 12 months 5% ‐ 10% ‐ 6 months Greater than 10% ‐ 3 months

Comment [CF12]: 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 da te that the most recent performance test was conducted; or
(iv) If the maximum 6-minute average opacity is gr eater 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 an y visible emissions is gr eater 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 great er 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 th an 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 op erating 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 pa ragraph (a)(2) of this section. For reference purposes in preparing the monitoring plan, s ee OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Compute r-Based Photographic Analysis Systems.” This document is available from the U.S. Environmenta l 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 [CF13]: 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 NO X 

### standard under §60.44b shall comply with either paragraphs (b)(1) or (b)(2) of this section.

(1) Install, calibrate, maintain, and operate CEMS for measuring NO X 

### and O 2 

### (or CO 2 

### ) emissions discharged to the atmosphere, and shall record the output of the system; or
(2) If the owner or operator has installed a NO X 

### emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this section, except that the owner or operator shall also meet the requirements of §60.49b. Data reported to meet the requirements of §60.49b shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.
(c) The CEMS required under paragraph (b) of this section shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments.
(d) The 1-hour average NO X 

### emission rates measured by the continuous NO X 

### monitor required by paragraph (b) of this section and required under §60.13(h) shall be expressed in ng/J or lb/MMBtu heat input and shall be used to cal culate 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 comb usting 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 NO X 

### is determined using one of the following procedures:
(i) Except as provided under paragraph (e)(2)(ii) of this section, NO X 

### span values shall be determined as follows:

Fuel Span values for NO X 

### (ppm)

N atural 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 NO X 

### span values determined according to section 2.1.2 in appendix A to part 75 of this chapter.
(3) All span values computed under paragraph (e)(2)(i) of this section for combusting mixtures of regulated fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (e)(2)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter.

(f) When NO X 

### emission data are not obtained because of CEMS breakdowns, repairs, calibration checks and zero and span adjustments, emission data will be obtained by using standby monitoring systems, Method 7 of appendix A of th is 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 NO X 

### emission rates as specified in a plan submitted pursuant to §60.49b(c).
(h) The owner or operator of a duct burner, as described in §60.41b, that is subject to the NO X 

### standards in §60.44b(a)(4), §60.44b(e), or §60.44b(l) is not required to install or operate a continuous emissions monitoring system to measure NO X 

### emissions.
(i) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) is not required to install or operate a CEMS for measuring NO X 

### emissions.
(j) The owner or operator of an affected facili ty 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 onl y liquid (excluding residual oil) or gaseous fuels with potential SO 2 

### emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion technology to reduce SO 2 

### or PM emissions. The owner or operator must maintain fuel records of the sulfur content of the fuels burne d, as described under §60.49b(r); or

### (3) The affected facility burns coke oven gas al one 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 SO 2 

### or PM emissions; or
(4) The affected facility does not use post-com bustion technology (excep t a wet scrubber) for reducing PM, SO 2 

### , 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 CE MS 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 calculate d 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 aver ages must be obtained for at least 90 percent of the operating h ours on a 30-day rolling average basis. The 1-hour averag es 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 s ource startup, shutdown, or malfunction. If the 24-hour average CO emission level is greate r 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 control device and uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section §60.48Da of this part; or

( 7 6 ) The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur and operates according to a written site-specific monitoring plan approved by the permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard.
(k) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere as specified in §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 emergi ng technology will be used for controlling emissions of SO 2 

### . 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 determina tion is made by the Administrator.
(b) The owner or operator of each affected facility subject to the SO 2 

### , PM, and/or NO X 

### emission limits under §§60.42b, 60.43b, and 60.44b shall submit to the Administrator the performance test data from the initial performance test and the performance evaluation of the CEMS using the applicable performance specifications in appendix B of this part. The owner or operator of each affected facility described in §60.44b(j) or §60.44b(k) shall submit to the Administrator the Comment [CF14]: Add ESP model to COMS exemption options

### maximum heat input capacity data from the demo nstration of the maximum heat input capacity of the affected facility.
(c) The owner or operator of each affected facility subject to the NO X 

### standard in §60.44b who seeks to demonstrate compliance with those standards through the monitoring of steam generating unit operating conditions in the provi sions 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 th e 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 Administ rator 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, includ ing steam generating unit load, identified in the plan. The plan shall:
(1) Identify the specific operating conditions to be monitored and the rela tionship between these operating conditions and NO X 

### emission rates ( i.e. , ng/J or lbs/MMBtu heat input). Steam generating unit operating conditions include, bu t 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 O 2 

### level);
(2) Include the data and information that the owner or operator used to identify the relationship between NO X 

### emission rates and these operating conditions; and
(3) Identify how these operati ng 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 form at 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 sp ecified 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 calcula te the annual capacity factor individually for coal, distillate oil, residual o il, 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 residu al 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 a nd 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 pr orated 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 th e information specified in paragraphs (f)(1)(i) through (iii) of this section.

(i) Dates and time intervals of al l opacity observation periods;
(ii) Name, affiliation, and copy of current visi ble emission reading certi fication 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 emissi on 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 sp ecified 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 NO X 

### standards under §60.44b shall maintain records of the following information for each steam generating unit operating day:

(1) Calendar date;

### (2) The average hourly NO X 

### emission rates (expressed as NO 2 

### ) (ng/J or lb/MMBtu heat input) measured or predicted;
(3) The 30-day average NO X 

### emission rates (ng/J or lb/MMBtu h eat 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 NO X 

### emission rates are in excess of the NO X 

### emissions standards under §60.44b, with the reasons for such excess emissions as well as a description of corrective actions taken;
(5) Identification of the steam generating unit ope rating 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 da ta 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 facilit y in any category listed in paragraphs (h)(1) or (2) of this section is required to submit exce ss 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 NO X 

### standard of §60.44b, and that:
(i) Combusts natural gas, distillate oil, gasified co al, 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 NO X 

### emissions on a continuous basis under §60.48b(g)(1) or steam generating unit operating conditions under §60.48b(g)(2).
(3) For the purpose of §60.43b, excess emissions are defined as all 6-minute periods during which the average opacity exceeds the opacity standards under §60.43b(f).
(4) For purposes of §60.48b(g)(1), excess emissions are defined as any calculated 30-day rolling average NO X 

### emission rate, as determined under §60.46b(e), that exceeds the applicable emission limits in §60.44b.

### (i) The owner or operator of any affected facility subject to the continuous monitoring requirements for NO X 

### under §60.48(b) shall submit reports containing the information recorded under paragraph (g) of this section.
(j) The owner or operator of any affected facility subject to the SO 2 

### standards under §60.42b shall submit reports.
(k) For each affected facility subject to the compliance and performance testing requirements of §60.45b and the reporting requirement in paragraph (j) of this section, the following information shall be reported to the Administrator:

(1) Calendar dates covered in the reporting period;
(2) Each 30-day average SO 2 

### emission rate (ng/J or lb/MMBtu heat input) measured during the reporting period, ending with the last 30-da y period; reasons for noncompliance with the emission standards; and a description of corrective actions taken; For an exceedance due to maintenance of the SO 2 

### control system covered in paragraph 60.45b(a), the report shall identify the days on which the mainte nance was performed and a description of the maintenance;
(3) Each 30-day average percent reduction in SO 2 

### emissions calculated during the reporting period, ending with the last 30-day period; reasons for noncompliance with the emission standards; and a description of corrective actions taken;
(4) Identification of the steam generating unit opera ting days that coal or oil was combusted and for which SO 2 

### or diluent (O 2 

### or CO 2 

### ) 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 SO 2 

### emission rate measured for each steam generating unit operating day during the reporting period that coal or oil was combusted, ending in the last 24-hour period in the quarter; reasons for noncompliance with the emission standards; and a description of corrective actions taken;
(3) Identification of the steam generating unit opera ting days that coal or oil was combusted for which S0 2 

### or diluent (O 2 

### or CO 2 

### ) 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 quart erly 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 in clude a summary of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift asse ssments required by §§60.47b(e)(4)(i) through (e)(4)(iii).
(m) For each affected facility subject to the SO 2 

### standards in §60.42(b) for which the minimum amount of data required in §60.47b(c) were not obtained during the reporting period, the following information is reported to the Admi nistrator 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 fo r 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 ou tlet 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. , %R f 

### ) is used to determine the overall percent reduction ( i.e. , %R o 

### ) 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. , %R f 

### ) 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 receive d 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 ap pendix 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 re porting period, if residual oil was fired; and
(3) If the affected facility meets the criteria described in §60.44b(j), the results of any NO X 

### emission tests required during the reporting period, the hours of operation during the reporting period, and the hours of operation since the last NO X 

### emission test.

### (r) The owner or operator of an affected facilit y 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 se ction, the distillate oil need not meet the fuel nitrogen content specification in the definition of di stillate 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 cont ain, 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 NO X 

### standard for Cytec Industries Fortie r Plant's C.AOG incinerator located in Westwego, Louisiana:

(1) Definitions

. Oxidation zone is defined as the portion of the C.AOG in cinerator 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 NO X 

### emission limit for fossil fuel in §60.44b(a) applies.

### (ii) When natural gas and chemical by-product waste are simultaneously combusted, the NO X 

### emission limit is 289 ng/J (0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air provided for combustion shall be provided to the reducing zone of the C.AOG incinerator.

(3) Emission monitoring . (i) The percent of total inlet air pr ovided 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 NO X 

### emission limit shall be determined by the compliance and performance test methods and procedures for NO X 

### in §60.46b(i).
(iii) The monitoring of the NO X 

### emission limit shall be perform ed 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 qu arterly report required by paragraph (i) of this section.
(ii) The owner or operator of the C.AOG incine rator 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 incine rator shall perform all the applicable reporting and recordkeeping requirements of this section.
(t) Facility-specific NO X 

### standard for Rohm and Haas Kentucky Incorporated's Boiler No. 100 located in Louisville, Kentucky:

(1) Definitions

. Air ratio control damper is defined as the part of the low NO X 

### burner that is adjusted to control the split of total combustion air delivered to the reducing and oxidation portions of the combustion flame.
Flue gas recirculation line is defined as the part of Boiler No. 100 that recirculates a portion of the boiler flue gas back into the combustion air.

(2) Standard for nitrogen oxides . (i) When fossil fuel alone is combusted, the NO X 

### emission limit for fossil fuel in §60.44b(a) applies.
(ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the NO X 

### emission limit is 473 ng/J (1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at a minimum of 5 inches (12.7 centimeters) out of the boiler, and the flue gas recirculation line shall be operated at a minimum of 10 percent open as indicated by its valve opening position indicator.

### (3) Emission monitoring for nitrogen oxides . (i) The air ratio control damper tee handle setting and the flue gas recirculation line valve opening position indicator setting shall be recorded during each 8-hour operating shift.

(ii) The NO X 

### emission limit shall be determined by the compliance and performance test methods and procedures for NO X 

### in §60.46b.
(iii) The monitoring of the NO X 

### emission limit shall be performed in accordance with §60.48b.

(4) Reporting and recordkeeping requirements . (i) The owner or operator of Boiler No. 100 shall submit a report on any excursions from th e 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 NO X 

### technology.
(ii) The site shall install, calibrate, maintain, and operate a continuous monitoring and recording system for measuring NO X 

### emissions discharged to the atmosphere and opacity using a continuous emissions monitoring system or a predictive emissions monitoring system.
(iii) Within 180 days of the completion of the powerhouse conversion, as required by 40 CFR 52.2454, the site shall perform a performance te st to quantify criteria pollutant emissions.

(2) [Reserved]
(v) The owner or operator of an affected facility may submit electronic quarterly reports for SO 2 

### and/or NO X 

### and/or opacity in lieu of submitting the written reports required under paragraphs (h), (i), (j), (k) or (l) of this section. The format of each quarterly electronic report shall be coordinated with the permitting authority. The electronic report(s) sha ll 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, indica ting whether compliance with the applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period. Before submitting reports in th e electronic format, the owner or operator shall coordinate with the permitting authority to obt ain 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 Administrato r and shall be postmarked by the 30th day following the end of the reporting period.
(x) Facility-specific NO X 

### standard for Weyerhaeuser Company' s No. 2 Power Boiler located in New Bern, North Carolina:

(1) Standard for nitrogen oxides . (i) When fossil fuel alone is combusted, the NO X 

### emission limit for fossil fuel in §60.44b(a) applies.
(ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the NO X 

### emission limit is 215 ng/J (0.5 lb/MMBtu).

(2) Emission monitoring for nitrogen oxides . (i) The NO X 

### emissions shall be determined by the compliance and performance test methods and procedures for NO X 

### in §60.46b.
(ii) The monitoring of the NO X 

### emissions shall be performed in accordance with §60.48b.

(3) Reporting and recordkeeping requirements . (i) The owner or operator of the No. 2 Power Boiler shall submit a report on any excursions from the limits required by paragraph (x)(2) of this section to the Administrator with the quarterly report required by §60.49b(i).
(ii) The owner or operator of the No. 2 Power Boiler shall keep records of the monitoring required by paragraph (x)(3) of this section for a period of 2 years following the date of such record.
(iii) The owner or operator of the No. 2 Power Bo iler shall perform all the applicable reporting and recordkeeping requirements of §60.49b.
(y) Facility-specific NO X 

### standard for INEOS USA's AO GI located in Lima, Ohio:

(1) Standard for NO X 

### . (i) When fossil fuel alone is combusted, the NO X 

### emission limit for fossil fuel in §60.44b(a) applies.
(ii) When fossil fuel and chemical byproduct/waste are simultaneously combusted, the NO X 

### emission limit is 645 ng/J (1.5 lb/MMBtu).

(2) Emission monitoring for NO X 

### . (i) The NO X 

### emissions shall be determ ined by the compliance and performance test methods and procedures for NO X 

### in §60.46b.
(ii) The monitoring of the NO X 

### emissions shall be performed in accordance with §60.48b.

(3) Reporting and recordkeeping requirements . (i) The owner or operator of the AOGI shall submit a report on any excursions from the limits required by paragraph (y)(2) of this section to the Administrator with the quarterly report required by paragraph (i) of this section.
(ii) The owner or operator of the AOGI shall keep records of the monitoring required by paragraph (y)(3) of this section for a period of 2 years following the date of such record.
(iii) The owner or operator of the AOGI shall perform all the applicable reporting and recordkeeping requirements of this section.Subpart Dc—Standards of Performance for Sm all Industrial-Commercial-Institutional Steam Generating Units
§60.40c Applicability and delegation of authority.
(a) Except as provided in paragraphs (d), (e), (f), an d (g) of this section, the affected facility to which this subpart applies is each steam generating unit for which construc tion, 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 (SO 2 ) 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 com bustion 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 generator Affected facilities s (i.e. heat recovery steam generators and fuel heaters) that are associated with combined cycle gas stationary combustion turbines and meet the applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other heat recovery steam generators , fuel heaters, and other affected facilities that are capable of combusting more than or equal to 2.9 MW (10 MMBtu/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 by is subject to subpart AAAA or subpart CCCC of this part is not subject by to 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 by to 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 Dcbased on the combined heat input from all operatio ns 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 AS TM D388 (incorporated by reference, see §60.17), coal refuse, and petroleum coke. Coal-derived synt hetic fuels derived from coal for the purposes of creating useful heat, including but not limited to so lvent 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 sour ce (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 po llutant emissions from co mbustion, provided that, during these periods of research and development, th e heat generated is not us ed 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 fo r space heating, process heating, driving pumps, preheating combustion air for other units, gene rating electricity, or any other purpose).
Conventional technology means wet flue gas desulfurization tech nology, dry flue gas desulfurization technology, atmospheric fluidized bed combus tion technology, and oil hydrodesulfurization technology.

Distillate oil means fuel oil that complies with the specificatio ns for fuel oil numbers 1 or 2, as defined by the American Society for Testing and Material s 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 (incorpo rated by reference, see §60.17) , kerosene, as defined by the American Society of Testing and Materials in AS TM 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 SO 2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gase s with an alkaline reagent and water, whether introduced separately or as a prem ixed 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 SO 2 control system that is not defi ned as a conventi onal 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 di stributed 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 comb ustion 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 combusti on of fuel in a steam generating unit and does not include the heat derived from preheated combustion air, reci rculated 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 characteristic s 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 gase ous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percen t 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]: Take comment on deleting fuel
treatment references.Potential sulfur dioxide emission rate means the theoretical SO 2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from co mbusting 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 (incorpora ted 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 incl ude 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 SO 2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gase s 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 reag ents 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 mi xes an aqueous stream or slurry with the exhaust gases from a stea m generating unit to control emissions of PM or SO 2
.
Wood means wood, wood residue, bark, or any deriva tive fuel or residue thereof, in any form, including but not limited to sawdus t, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues.

§60.42c Standard for sulfur dioxide (SO 2 ).
(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 SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO 2 emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases that contain SO 2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected facility shall neither: cause to be discharged into the atmosphere from the affected facility any gases that contain SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO 2 emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases that contain SO 2 in excess of the emission limit is determined pursuant to paragraph (e)(2) of this section.(b) Except as provided in paragraphs (c) and (e) of this section, on and after the date on which the performance test is completed or required to be completed under §60.8, whichever date comes first, the owner or operator of an affected facility that:
(1) Combusts only coal refuse alone in a fluidized bed combustion steam generating unit shall neither:
(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO 2 emission rate (80 percent reduction); nor
(ii) Cause to be discharged into the atmosphere fro m that affected facility any gases that contain SO 2 in excess of SO 2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is fired with coal refuse, the affected facility subject to paragraph (a) of this section. If oil or any other fuel (except coal) is fired with coal refuse, the affected facility is subject to the 87 ng/J (0.20 lb/MMBtu) heat input SO 2 emissions limit or the 90 percent SO 2 reduction requirement specified in paragraph (a) of this section and the emission limit is determined pursuant to paragraph (e)(2) of this section.
(2) Combusts only coal and that uses an emerging technology for the control of SO 2 emissions shall neither:
(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of 50 percent (0.50) of the potential SO 2 emission rate (50 percent reduction); nor
(ii) Cause to be discharged into the atmosphere fro m that affected facility any gases that contain SO 2 in excess of 260 ng/J (0.60 lb/MMBtu) heat input. If co al is combusted with other fuels, the affected facility is subject to the 50 percent SO 2 reduction requirement specified in this paragraph and the emission limit determined pursuant to paragraph (e)(2) of this section.
(c) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, alone or in combination with any other fuel, and is listed in paragraphs (c)(1), (2), (3), or (4) of this section shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of the emission limit determined pursuant to paragraph (e)(2) of this section. Percent reduction requirements are not applicable to affected facilities under paragraphs (c)(1), (2), (3), or (4).

(1) Affected facilities that have a heat input capacity of 22 MW (75 MMBtu/hr) or less

. ;
(2) Affected facilities that have an annual capacity for coal of 55 perc ent (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 th e 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 da te comes first, no owner or operato r of an affected facility thatcombusts oil shall cause to be discharged into the at mosphere from that affected facility any gases that contain SO 2 in excess of 215 ng/J (0.50 lb/MMBtu) heat input from oil ; or, as an alternative, no owner or operator of an affected facility that combusts oil shall combust oil in the affected facility that contains greater than 0.5 weight percent sulfur. The percent reduction requirements are not applicable to affected facilities under this paragraph.
(e) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, or coal and oil with any other fuel shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of the following:
(1) The percent of potential SO 2 emission rate or numerical SO 2 emission rate required under paragraph (a) or (b)(2) of this section, as applicable, for any affected facility that
(i) Combusts coal in combination with any other fuel;
(ii) Has a heat input capacity greater than 22 MW (75 MMBtu/hr); and
(iii) Has an annual capacity factor for coal greater than 55 percent (0.55); and
(2) The emission limit determined according to the following formula for any affected facility that combusts coal, oil, or coal and oil with any other fuel:

Where:

E s = SO 2 emission limit, expressed in ng/J or lb/MMBtu heat input;

K a = 520 ng/J (1.2 lb/MMBtu);

K b = 260 ng/J (0.60 lb/MMBtu);

K c = 215 ng/J (0.50 lb/MMBtu);

H a = Heat input from the combustion of coal, except co al combusted in an affect ed facility subject to paragraph (b)(2) of this secti on, in Joules (J) [MMBtu];

H b = Heat input from the combustion of coal in an affected facility subject to paragraph (b)(2) of this section, in J (MMBtu); and

H c = Heat input from the combustion of oil, in J (MMBtu).
(f) Reduction in the potential SO 2 emission rate through fuel pretreat ment is not credited toward the percent reduction requirem ent under paragraph (b)(2) of this section unless:
(1) Fuel pretreatment results in a 50 percent (0.50) or greater reduction in the potential SO 2 emission 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 in sert it again. Comment [CF6]: Clarify that cannot dilute with natural gas

Comment [CF7]: Could be made easier to understand?(2) Emissions from the pretreated fuel (without either combustion or post-combustion SO 2 control) are equal to or less than the emission limits specified under paragraph (b)(2) of this section.
(g) Except as provided in paragraph (h) of this section, compliance with the percent reduction requirements, fuel oil sulfur limits, and emission limits of this sec tion 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 de scribed under §60.48c(f), as applicable.

(1) Distillate oil-fired affected facilities with he at 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 faci lities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).

(i) The SO 2 emission limits, fuel oil sulfur limits, and percent reduction requirements under this section apply at all times, including periods of startup, shutdown, and malfunction.
(j) For affected facilities located in noncontinental areas and affected facilities complying with the percent reduction standard, only the heat input supplie d 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 da te comes first, no owner or operato r of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that can combust s coal or combusts mixtures of coal with othe r fuels and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater, shall cause to be discharg ed 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 affe cted 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 da te comes first, no owner or operator of an affected facility that Comment [CF8]: Add to be consistent with 60.48c(f)

Comment [CF9]: If deleted this would allow fuel mixing in noncontinental areas

Comment [CF10]: Make consistent with permits that allow combustion of alternate fuels

– check with OECAcommenced construction, reconstruction, or modification on or before February 28, 2005, that can combust s 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 affe cted 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 su bpart and are subject to a federally en forceable 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 sect ion 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 da te comes first, no owner or operato r of an affected facility that commences construction, reconstruction, or m odification after February 28, 2005, and that can combust s 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 gase s that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided in paragrap hs (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 modi fication 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 mo dification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected fa cility any gases that cont ain 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 thes e fuels with any other fuels; and
(ii) 0.2 percent of the combustion concentration (9 9.8 percent reduction) when combusting coal, oil, wood, a mixture of these fuels, or a mixt ure 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 da te comes first, no owner or operato r of an affected facility that commences modification afte r February 28, 2005, and that com busts over 30 percent wood (by heat input) on an annual basis and has a heat input ca pacity of 8.7 MW (30 MMBtu/hr) or greater shallcause 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, whic hever date comes first, a A n owner or operator of an affected facility that commences construction, reconstruction, or modifica tion 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 no t using a post-combustion technology (except a wet scrubber) to reduce PM or SO 2 emissions 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 paragr aphs (g) and (h) of this sectio n and §60.8(b), performance tests required under §60.8 shall be conducted following the procedures spec ified in paragraphs (b), (c), (d), (e), and (f) of this section, as applicable. Section 60.8(f) does not a pply to this section. The 30-day notice required in §60.8(d) applies onl y 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 SO 2 emission limits under §60.42c shall be determined using a 30-day average. The first operating day included in the initial performance test shall be scheduled within 30 days after achieving the maximum production rate at which the affect facility will be operated, but not later than 180 days after the initial startup of the facility. The steam generating unit load during the 30-day period does not have to be the maximum design heat input capacity, but must be representative of future operating conditions.
(c) After the initial performance test required under paragraph (b) of this section and §60.8, compliance with the percent reduction requirements and SO 2 emission limits under §60.42c is based on the average percent reduction and the average SO 2 emission rates for 30 consecutive steam generating unit operating days. A separate performance test is completed at the end of each steam generating unit operating day, and a new 30-day average percent reduction and SO 2 emission rate are calculated to show compliance with the standard.
(d) If only coal, only oil, or a mixture of coal and oil is combusted in an affected facility, the procedures in Method 19 of appendix A of th is part are used to determine the hourly SO 2 emission rate (E ho ) and the 30-day average SO 2 emission rate (E ao ). The hourly averages used to compute the 30-day averages are obtained from the CEMS. Method 19 of appe ndix A of this part shall be used to calculate E ao when using daily fuel sampling or Meth od 6B of appendix A of this part.

(e) If coal, oil, or coal and oil are combusted with other fuels:
(1) An adjusted E ho (E ho o) is used in Equation 19–19 of Method 19 of appendix A of this part to compute the adjusted E ao (E ao o). The E ho o is computed using the following formula:

Where: 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 in sert it again.E ho o = Adjusted E ho , ng/J (lb/MMBtu);

E ho = Hourly SO 2 emission rate, ng/J (lb/MMBtu);

E w = SO 2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Met hod 9 of appendix A of this part, ng/J (lb/MMBtu). The value E w for each fuel lot is used for each hourly average during the time that the lot is being combusted. The owner or operato r does not have to measure E w if the owner or operator elects to assume E w = 0.

X k = Fraction of the total heat input from fuel combus tion 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 th at qualifies under the provisions of §60.42c(c) or (d) (where percent reduction is not required) do es not have to meas ure the parameters E w or X k if the owner or operator of the affected facility elects to measure emission rates of the coal or oil using the fuel sampling and analysis procedures under Method 19 of appendix A of this part.
(f) Affected facilities subject to the percent reduction requirements under §60.42c(a) or (b) shall determine compliance with the SO 2 emission limits under §60.42c pursuant to paragraphs (d) or (e) of this section, and shall determine compliance with the percent reduction requirements using the following procedures:
(1) If only coal is combusted, the percent of potential SO 2 emission rate is computed using the following formula:

Where:

%P s = Potential SO 2 emission rate, in percent;

%R g = SO 2 removal efficiency of the control device as de termined by Method 19 of appendix A of this part, in percent; and

%R f = SO 2 removal efficiency of fuel pretreatment as de termined by Method 19 of appendix A of this part, in percent.

(2) If coal, oil, or coal and oil are combusted wi th other fuels, the same procedures required in paragraph (f)(1) of this section are used, ex cept as provided for in the following:
(i) To compute the %P s , an adjusted %R g (%R g o) is computed from E ao o from paragraph (e)(1) of this section and an adjusted average SO 2 inlet rate (E ai o) using the following formula:

Where: 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 in sert 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 in sert it again.%R g o = Adjusted %R g , in percent;

E ao o = Adjusted E ao , ng/J (lb/MMBtu); and

E ai o = Adjusted average SO 2 inlet rate, ng/J (lb/MMBtu).
(ii) To compute E ai o, an adjusted hourly SO 2 inlet rate (E hi o) is used. The E hi o is computed using the following formula:

Where:

E hi o = Adjusted E hi , ng/J (lb/MMBtu);

E hi = Hourly SO 2 inlet rate, ng/J (lb/MMBtu);

E w = SO 2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Met hod 19 of appendix A of this part, ng/J (lb/MMBtu). The value E w for each fuel lot is used for each hourly average during the time that the lot is being combusted. The owner or operato r does not have to measure E w if the owner or operator elects to assume E w = 0; and

X k = Fraction of the total heat input from fuel combus tion 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 owne r or operator seeks to demonstrate compliance with the fuel oil sulfur limits under §60 .42c based on shipment fuel sampli ng, 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 de scribed under §60.46c(d)(2).
(h) For affected facilities subject to §60.42c(h)(1), (2), or (3) wher e the owner or operator seeks to demonstrate compliance with the SO 2 standards based on fuel supplie r 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 SO 2 standards under §60.42c(c)(2) shall demonstrate th e maximum design heat input capacity of the steam generating unit by operating the steam gene rating 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 firi ng 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 SO 2 emissions data in calculating %P s and E ho under paragraphs (d), (e), or (f) of this section, as applicable, whether or not the minimum 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 in sert it again.emissions data requirements under §60.46c(f) are ac hieved. All valid emissions data, including valid data collected during periods of startup, shutdown, and malfunction, shall be used in calculating %P s or E ho pursuant 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 re quired 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 pa rt 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 stac k gas temperature does not exceed a temperature of 160 °C (320 °F). The procedures of Sections 8.1 and 11.1 of Met hod 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 scru bber 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 th is 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 main tained at 160 ±14 °C (320±25 °F).
(6) For determination of PM emissions, an oxygen (O 2 ) or carbon dioxide (CO 2 ) 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 ra tes expressed in ng/J (lb/MMBtu) heat input shall be determined using:

(i) The O 2 or CO 2 measurements and PM measurements obtained under this section, (ii) The dry basis F factor, and(iii) The dry basis emission rate ca lculation 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 tes ting 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 em ission 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 arithmeti c 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 h our shall be used to calculate each 1-hour arithmetic average.

(ii) [Reserved](8) The 1-hour arithmetic averages re quired 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 calcula ting 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 Perf ormance 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 O 2 (or CO 2 ) data shall be collected concur rently (or within a 30- to 60- minute period) by both the continuous emission mo nitors 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 CO 2 ), Method 3A or 3B of appendix A–2 of th is 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 breakdow ns, 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 complian ce 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 Cent ral 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 comple ting each performance evaluation required by paragraph (c)(11) of this section, the owner or operator of the affected facili ty must either submit the test data to EPA by successfully entering the data electronically into EPA's WebFIRE data base available a t http://cfpub.epa.gov/oarweb /index.cfm?action=fire.main or mail a copy to: United States Environmental Protection Agency; Energy Stra tegies Group; 109 TW Alexander DR; Mail Code: D243

– 01; RTP, NC 27711

. (d) The owner or operator of an affected fac ility 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 [CF11]: Updated language for electronic reporting.§60.46c Emission monitoring for sulfur dioxide.
(a) Except as provided in paragra phs (d) and (e) of this section, th e owner or operator of an affected facility subject to the SO 2 emission limits under §60.42c shall install, calibrate, maintain, and operate a CEMS for measuring SO 2 concentrations and either O 2 or CO 2 concentrations at the outlet of the SO 2 control device (or the outlet of the steam generating unit if no SO 2 control device is used), and shall record the output of the system. The owner or operator of an affected facility subject to the percent reduction requirements under §60.42c shall measure SO 2 concentrations and either O 2 or CO 2 concentrations at both the inlet and outlet of the SO 2 control device.
(b) The 1-hour average SO 2 emission rates measured by a CEMS shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calcul ate the average em ission rates under §60.42c. Each 1- hour average SO 2 emission rate must be based on at least 30 minutes of operation, and shall be calculated using the data points required under §60.13(h)(2). Hourly SO 2 emission rates are not calculated if the affected facility is operated less than 30 minutes in a 1-hour period and are not counted toward determination of a steam generating unit operating day.
(c) The procedures under §60.13 shall be followed for installation, evaluation, and operation of the CEMS.
(1) All CEMS shall be operated in accordance with the applicable proced ures 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 SO 2 CEMS at the inlet to the SO 2 control device shall be 125 percent of the maximum estimated hourly potential SO 2 emission rate of the fuel combusted, and the span value of the SO 2 CEMS at the outlet from the SO 2 control device shall be 50 percent of the maximum estimated hourly potential SO 2 emission rate of the fuel combusted.
(4) For affected facilities that are not subject to the percent reduction requirements of §60.42c, the span value of the SO 2 CEMS at the outlet from the SO 2 control device (or outlet of the steam generating unit if no SO 2 control device is used) shall be 125 percent of the maximu m estimated hourly potential SO 2 emission rate of the fuel combusted.
(d) As an alternative to operating a CEMS at the inlet to the SO 2 control device (or outlet of the steam generating unit if no SO 2 control device is used) as required unde r paragraph (a) of this section, an owner or operator may elect to determine the average SO 2 emission rate by sampling the fuel prior to combustion. As an alternative to operating a CEMS at the outlet from the SO 2 control device (or outlet of the steam generating unit if no SO 2 control device is used) as requi red under paragraph (a) of this section, an owner or operator may elect to determine the average SO 2 emission rate by using Method 6B of appendix A of this part. Fuel sampling shall be conducted pursuant to either paragraph (d)(1) or (d)(2) of this section. Method 6B of appendix A of this part shall be conducted pursuant to paragraph (d)(3) of this section.
(1) For affected facilities combusting coal or oil, coal or oil samples shall be collected daily in an 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 pa rt. Method 19 of appendix A of this part providesprocedures for converting these measurements into th e format to be used in calculating the average SO 2 input rate.
(2) As an alternative fuel sampling procedure for affected facilities combusting oil, oil samples may be collected from the fuel tank for each steam generating unit immediately after the fuel tank is filled and before any oil is combusted. The owner or operator of the affected facility shall analyze the oil sample to determine the sulfur content of the oil. If a partially empty fuel tank is refilled, a new sample and analysis of the fuel in the tank would be required upo n 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 SO 2 at the inlet or outlet of the SO 2 control system. An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of this part sampling location. The stratification test shall consist of three paired runs of a suitable SO 2 and CO 2 measurement train operated at the candidate location and a second similar train operated accordi ng 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 co mbination of Methods 6 and 3 of appendix A of this part or Methods 6C and 3A of a ppendix A of this part are suitable measurement techniques. If Method 6B of appendix A of this part is used for the s econd 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) wher e the owner or operator of the affected facility seeks to demonstrate compliance with the SO 2 standards based on fuel supplie r certification, as described under §60.48c(f), as applicable.
(f) The owner or operator of an affected facility op erating 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 leas t 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 system s 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 emission s 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 pe rformance 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 Me thod 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 mo st recent Method 9 of appendix A–4 of this part performance test results.
(i) If no visible emissions are observed, a subseq uent Method 9 of appendix A–4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted;
(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 6 calendar months from the date that th e most recent performanc e 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 perf ormance 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 perfo rmance 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 owne r 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 ex cess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visibl e emissions is greater th an 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 su m of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the procedures in paragraph (a) of this section within 45 calendar days according to the requirements in §60.45c(a)(8).(ii) If no visible emissions are observed for 30 oper ating 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 vi sible emissions are observed, dail y 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 owne r 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 fr om 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 app licable 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 fu els 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 em ission 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 calibra tion 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, SO 2 , 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 em issions 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 de monstrate compliance according to the procedures specified in paragraphs (e)(1) th rough (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 em issions 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 fl ow 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 averag e 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 sy stems 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 calc ulations 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 descript ion 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 pr imary PM control device and uses an ESP predictive model to monitor the performance of the ESP devel oped in accordance and operated according to the most current requirements in section §60.48Da of this part.

( h g ) 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-s pecific 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 para meters 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 faci lity and identification of fuels to be combusted in the affected facility. Comment [CF12]: Add ESP model to COMS exemption options

Comment [CF13]: Clarify can burn gaseous fuels along with low S oil(2) If applicable, a copy of any federally enforceabl e 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 SO 2 emissions. The Administrator will examine the description of the control device and will determine whether the technology qualifies as an emerging technology. In making this determination, the Administrator may require the owner or operator of the affected facility to submit additional information concerning the control device. The affected facility is subject to the provisions of §60.42c(a) or (b)(1), unless and until this determination is made by the Administrator.
(b) The owner or operator of each affected facility subject to the SO 2 emission limits of §60.42c, or the PM or opacity limits of §60.43c, shall submit to the Administrator the performance test data from the initial and any subsequent performance tests and, if applicable, the performance evaluation of the CEMS and/or COMS using the applicable performanc e 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 peri od 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 condu cted using Method 9 of appendix A–4 of this part, the owner or operator shall keep the records including the informat ion 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 visi ble 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 condu cted using Method 22 of appendix A–4 of this part, the owner or operator shall keep the records including the informat ion 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 ob server 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, th e 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 SO 2 emission limits, fuel oil sulfur limits, or percent reducti on requirements under §60.42 c shall submit reports to the Administrator.
(e) The owner or operator of each affected facility subject to the SO 2 emission limits, fuel oil sulfur limits, or percent reduc tion requirements under §60.42c shall keep records and submit reports as required under paragraph (d) of th is section, including the following information, as applicable.
(1) Calendar dates covered in the reporting period.
(2) Each 30-day average SO 2 emission rate (ng/J or lb/MMBtu), or 30-day average sulfur content (weight percent), calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of co rrective actions taken.
(3) Each 30-day average percent of potential SO 2 emission rate calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of the corre ctive actions taken.
(4) Identification of any steam generating unit operating days for which SO 2 or diluent (O 2 or CO 2 ) data have not been obtained by an ap proved 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 fr om the calculation of average emission rates; justification for excluding data ; and a description of corrective actions taken if data have been excl uded for periods other than those during wh ich coal or oil were not combusted in the steam generating unit.

(6) Identification of the F factor used in calcula tions, method of determination, and type of fuel combusted.
(7) Identification of whether averages have b een 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 modification s to the CEMS that could affect the ability of the CEMS to comply with Performance Specifica tions 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 paragr aph (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 in clude 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 th e 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 certific ation 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 para graphs (g)(2) and (g)(3) of this section, the owner or operator of each affected facility shall record and maintain re cords 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 SO 2 standard, fuels not subject to an emissions standard (excluding opacity), or a mixture of these fuels may elect to record and maintain records of the amount of each fuel combusted during each calendar month.
(3) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility or multiple affect ed facilities located on a contiguous property unit where the only fuels combusted in any steam gene rating unit (including steam generating units not subject to this subpart) at that pr operty are natural gas, wood, distil late oil meeting the most current requirements in §60.42C to use fuel certifica tion to demonstrate compliance with the SO 2 standard, and/or fuels, excluding coal and residual oil, not subject to an emissions st andard (excluding opacity) may elect to record and maintain records of the total amount of each steam generating unit fuel delivered to that property du ring each calendar month.
(h) The owner or operator of each affected facili ty 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 a nnual 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 unde r 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.