May 15, 2014 

Redline of 40 CFR part 60, subpart J, showing proposed amendments 

Insertions are shown in bold blue text 

Deletions are shown in red strikeout text 

1 

Title 40: Protection of Environment 

Part 60—Standards of Performance for New Stationary Sources 

Subpart J—Standards of Performance for Petroleum Refineries 

§ 60.100 Applicability, designation of affected facility, and reconstruction. 

(a) The provisions of this subpart are applicable to the following affected facilities in petroleum 

refineries: fluid catalytic cracking unit catalyst regenerators, fuel gas combustion devices, and all 

Claus sulfur recovery plants except Claus plants with a design capacity for sulfur feed of 20 long 

tons per day (LTD) or less. The Claus sulfur recovery plant need not be physically located within 

the boundaries of a petroleum refinery to be an affected facility, provided it processes gases 

produced within a petroleum refinery. 

(b) Any fluid catalytic cracking unit catalyst regenerator or fuel gas combustion device under 

paragraph (a) of this section other than a flare which commences construction, reconstruction or 

modification after June 11, 1973, and on or before May 14, 2007, or any fuel gas combustion 

device under paragraph (a) of this section that is also a flare which commences construction, 

reconstruction or modification after June 11, 1973, and on or before June 24, 2008, or any Claus 

sulfur recovery plant under paragraph (a) of this section which commences construction, 

reconstruction or modification after October 4, 1976, and on or before May 14, 2007, is subject 

to the requirements of this subpart except as provided under paragraphs (c) through (e) of this 

section. 

(c) Any fluid catalytic cracking unit catalyst regenerator under paragraph (b) of this section 

which commences construction, reconstruction, or modification on or before January 17, 1984, is 

exempted from §60.104(b). 

(d) Any fluid catalytic cracking unit in which a contact material reacts with petroleum 

derivatives to improve feedstock quality and in which the contact material is regenerated by 

burning off coke and/or other deposits and that commences construction, reconstruction, or 

modification on or before January 17, 1984, is exempt from this subpart. 

(e) Owners or operators may choose to comply with the applicable provisions of subpart Ja of 

this part to satisfy the requirements of this subpart for an affected facility. 

(f) For purposes of this subpart, under §60.15, the “fixed capital cost of the new components” 

includes the fixed capital cost of all depreciable components which are or will be replaced 

pursuant to all continuous programs of component replacement which are commenced within 

any 2-year period following January 17, 1984. For purposes of this paragraph, “commenced” 

means that an owner or operator has undertaken a continuous program of component 
Page 2 of 23 

2 

replacement or that an owner or operator has entered into a contractual obligation to undertake 

and complete, within a reasonable time, a continuous program of component replacement. 

§ 60.101 Definitions. 

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

and in subpart A. 

(a) Petroleum refinery means any facility engaged in producing gasoline, kerosene, distillate fuel 

oils, residual fuel oils, lubricants, or other products through distillation of petroleum or through 

redistillation, cracking or reforming of unfinished petroleum derivatives. 

(b) Petroleum means the crude oil removed from the earth and the oils derived from tar sands, 

shale, and coal. 

(c) Process gas means any gas generated by a petroleum refinery process unit, except fuel gas 

and process upset gas as defined in this section. 

(d) Fuel gas means any gas which is generated at a petroleum refinery and which is combusted. 

Fuel gas includes natural gas when the natural gas is combined and combusted in any proportion 

with a gas generated at a refinery. Fuel gas does not include gases generated by catalytic 

cracking unit catalyst regenerators and fluid coking burners. Fuel gas does not include vapors 

that are collected and combusted in a thermal oxidizer or flare installed to control emissions from 

wastewater treatment units or marine tank vessel loading operations. 

(e) Process upset gas means any gas generated by a petroleum refinery process unit as a result of 

start-up, shut-down, upset or malfunction. 

(f) Refinery process unit means any segment of the petroleum refinery in which a specific 

processing operation is conducted. 

(g) Fuel gas combustion device means any equipment, such as process heaters, boilers and flares 

used to combust fuel gas, except facilities in which gases are combusted to produce sulfur or 

sulfuric acid. 

(h) Coke burn-off means the coke removed from the surface of the fluid catalytic cracking unit 

catalyst by combustion in the catalyst regenerator. The rate of coke burn-off is calculated by the 

formula specified in §60.106. 

(i) Claus sulfur recovery plant means a process unit which recovers sulfur from hydrogen sulfide 

by a vapor-phase catalytic reaction of sulfur dioxide and hydrogen sulfide. 

(j) Oxidation control system means an emission control system which reduces emissions from 

sulfur recovery plants by converting these emissions to sulfur dioxide. 
Page 3 of 23 

3 

(k) Reduction control system means an emission control system which reduces emissions from 

sulfur recovery plants by converting these emissions to hydrogen sulfide. 

(l) Reduced sulfur compounds means hydrogen sulfide (H2S), carbonyl sulfide (COS) and carbon 

disulfide (CS2). 

(m) Fluid catalytic cracking unit means a refinery process unit in which petroleum derivatives 

are continuously charged; hydrocarbon molecules in the presence of a catalyst suspended in a 

fluidized bed are fractured into smaller molecules, or react with a contact material suspended in a 

fluidized bed to improve feedstock quality for additional processing; and the catalyst or contact 

material is continuously regenerated by burning off coke and other deposits. The unit includes 

the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or 

contact material recovery equipment, and regenerator equipment for controlling air pollutant 

emissions and for heat recovery. 

(n) Fluid catalytic cracking unit catalyst regenerator means one or more regenerators (multiple 

regenerators) which comprise that portion of the fluid catalytic cracking unit in which coke burnoff and catalyst or contact material regeneration occurs, and includes the regenerator combustion 

air blower(s). 

(o) Fresh feed means any petroleum derivative feedstock stream charged directly into the riser or 

reactor of a fluid catalytic cracking unit except for petroleum derivatives recycled within the 

fluid catalytic cracking unit, fractionator, or gas recovery unit. 

(p) Contact material means any substance formulated to remove metals, sulfur, nitrogen, or any 

other contaminant from petroleum derivatives. 

(q) Valid day means a 24-hour period in which at least 18 valid hours of data are obtained. A 

“valid hour” is one in which at least 2 valid data points are obtained. 

§ 60.102 Standard for particulate matter. 

Each owner or operator of any fluid catalytic cracking unit catalyst regenerator that is subject to 

the requirements of this subpart shall comply with the emission limitations set forth in this 

section on and after the date on which the initial performance test, required by §60.8, is 

completed, but not later than 60 days after achieving the maximum production rate at which the 

fluid catalytic cracking unit catalyst regenerator will be operated, or 180 days after initial startup, 

whichever comes first. 

(a) No owner or operator subject to the provisions of this subpart shall discharge or cause the 

discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator: 

(1) Particulate matter in excess of 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in the catalyst 

regenerator. 
Page 4 of 23 

4 

(2) Gases exhibiting greater than 30 percent opacity, except for one six-minute average opacity 

reading in any one hour period. 

(b) Where the gases discharged by the fluid catalytic cracking unit catalyst regenerator pass 

through an incinerator or waste heat boiler in which auxiliary or supplemental liquid or solid 

fossil fuel is burned, particulate matter in excess of that permitted by paragraph (a)(1) of this 

section may be emitted to the atmosphere, except that the incremental rate of particulate matter 

emissions shall not exceed 43 grams per Gigajoule (g/GJ) (0.10 lb/million British thermal units 

(Btu)) of heat input attributable to such liquid or solid fossil fuel. 

§ 60.103 Standard for carbon monoxide. 

Each owner or operator of any fluid catalytic cracking unit catalyst regenerator that is subject to 

the requirements of this subpart shall comply with the emission limitations set forth in this 

section on and after the date on which the initial performance test, required by §60.8, is 

completed, but not later than 60 days after achieving the maximum production rate at which the 

fluid catalytic cracking unit catalyst regenerator will be operated, or 180 days after initial startup, 

whichever comes first. 

(a) No owner or operator subject to the provisions of this subpart shall discharge or cause the 

discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator any 

gases that contain carbon monoxide (CO) in excess of 500 ppm by volume (dry basis). 

§ 60.104 Standards for sulfur oxides. 

Each owner or operator that is subject to the requirements of this subpart shall comply with the 

emission limitations set forth in this section on and after the date on which the initial 

performance test, required by §60.8, is completed, but not later than 60 days after achieving the 

maximum production rate at which the affected facility will be operated, or 180 days after initial 

startup, whichever comes first. 

(a) No owner or operator subject to the provisions of this subpart shall: 

(1) Burn in any fuel gas combustion device any fuel gas that contains hydrogen sulfide (H2S) in 

excess of 230 mg/dscm (0.10 gr/dscf). The combustion in a flare of process upset gases or fuel 

gas that is released to the flare as a result of relief valve leakage or other emergency 

malfunctions is exempt from this paragraph. 

(2) Discharge or cause the discharge of any gases into the atmosphere from any Claus sulfur 

recovery plant containing in excess of: 

(i) For an oxidation control system or a reduction control system followed by incineration, 250 

ppm by volume (dry basis) of sulfur dioxide (SO2) at zero percent excess air. 
Page 5 of 23 

5 

(ii) For a reduction control system not followed by incineration, 300 ppm by volume of reduced 

sulfur compounds and 10 ppm by volume of hydrogen sulfide (H2S), each calculated as ppm SO2

by volume (dry basis) at zero percent excess air. 

(b) Each owner or operator that is subject to the provisions of this subpart shall comply with one 

of the following conditions for each affected fluid catalytic cracking unit catalyst regenerator: 

(1) With an add-on control device, reduce SO2 emissions to the atmosphere by 90 percent or 

maintain SO2 emissions to the atmosphere less than or equal to 50 ppm by volume (ppmv), 

whichever is less stringent; or 

(2) Without the use of an add-on control device to reduce SO2 emission, maintain sulfur oxides 

emissions calculated as SO2 to the atmosphere less than or equal to 9.8 kg/Mg (20 lb/ton) coke 

burn-off; or 

(3) Process in the fluid catalytic cracking unit fresh feed that has a total sulfur content no greater 

than 0.30 percent by weight. 

(c) Compliance with paragraph (b)(1), (b)(2), or (b)(3) of this section is determined daily on a 7-

day rolling average basis using the appropriate procedures outlined in §60.106. 

(d) A minimum of 22 valid days of data shall be obtained every 30 rolling successive calendar 

days when complying with paragraph (b)(1) of this section. 

§ 60.105 Monitoring of emissions and operations. 

(a) Continuous monitoring systems shall be installed, calibrated, maintained, and operated by the 

owner or operator subject to the provisions of this subpart as follows: 

(1) For fluid catalytic cracking unit catalyst regenerators subject to §60.102(a)(2), an instrument 

for continuously monitoring and recording the opacity of emissions into the atmosphere. The 

instrument shall be spanned at 60, 70, or 80 percent opacity. 

(2) For fluid catalytic cracking unit catalyst regenerators subject to §60.103(a), an instrument for 

continuously monitoring and recording the concentration by volume (dry basis) of CO emissions 

into the atmosphere, except as provided in paragraph (a)(2) (ii) of this section. 

(i) The span value for this instrument is 1,000 ppm CO. 

(ii) A CO continuous monitoring system need not be installed if the owner or operator 

demonstrates that the average CO emissions are less than 50 ppm (dry basis) and also files a 

written request for exemption to the Administrator and receives such an exemption. The 

demonstration shall consist of continuously monitoring CO emissions for 30 days using an 

instrument that shall meet the requirements of Performance Specification 4 of appendix B of this 

part. The span value shall be 100 ppm CO instead of 1,000 ppm, and the relative accuracy limit 

shall be 10 percent of the average CO emissions or 5 ppm CO, whichever is greater. For 
Page 6 of 23 

6 

instruments that are identical to Method 10 and employ the sample conditioning system of 

Method 10A, the alternative relative accuracy test procedure in §10.1 of Performance 

Specification 2 may be used in place of the relative accuracy test. 

(3) For fuel gas combustion devices subject to §60.104(a)(1), either an instrument for 

continuously monitoring and recording the concentration by volume (dry basis, zero percent 

excess air) of SO2 emissions into the atmosphere or monitoring as provided in paragraph (a)(4) 

of this section). The monitor shall include an oxygen monitor for correcting the data for excess. 

(i) The span values for this monitor are 50 ppm SO2 and 25 percent oxygen (O2). 

(ii) The SO2 monitoring level equivalent to the H2S standard under §60.104(a)(1) shall be 20 

ppm (dry basis, zero percent excess air). 

(iii) The performance evaluations for this SO2 monitor under §60.13(c) shall use Performance 

Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy 

evaluations. Method 6 samples shall be taken at a flow rate of approximately 2 liters/min for at 

least 30 minutes. The relative accuracy limit shall be 20 percent or 4 ppm, whichever is greater, 

and the calibration drift limit shall be 5 percent of the established span value. 

(iv) Fuel gas combustion devices having a common source of fuel gas may be monitored at only 

one location (i.e., after one of the combustion devices), if monitoring at this location accurately 

represents the SO2 emissions into the atmosphere from each of the combustion devices. 

(4) Instead of the SO2 monitor in paragraph (a)(3) of this section for fuel gas combustion devices 

subject to §60.104(a)(1), an instrument for continuously monitoring and recording the 

concentration (dry basis) of H2S in fuel gases before being burned in any fuel gas combustion 

device. 

(i) The span value for this instrument is 425 mg/dscm H2S. 

(ii) Fuel gas combustion devices having a common source of fuel gas may be monitored at only 

one location, if monitoring at this location accurately represents the concentration of H2S in the 

fuel gas being burned. 

(iii) The performance evaluations for this H2S monitor under §60.13(c) shall use Performance 

Specification 7. Method 11, 15, 15A, or 16 shall be used for conducting the relative accuracy 

evaluations. 

(iv) The owner or operator of a fuel gas combustion device is not required to comply with 

paragraph (a)(3) or (4) of this section for fuel gas streams that are exempt under §60.104(a)(1) 

and fuel gas streams combusted in a fuel gas combustion device that are inherently low in sulfur 

content. Fuel gas streams meeting one of the requirements in paragraphs (a)(4)(iv)(A) through 

(D) of this section will be considered inherently low in sulfur content. If the composition of a 

fuel gas stream changes such that it is no longer exempt under §60.104(a)(1) or it no longer 

meets one of the requirements in paragraphs (a)(4)(iv)(A) through (D) of this section, the owner 
Page 7 of 23 

7 

or operator must begin continuous monitoring under paragraph (a)(3) or (4) of this section within 

15 days of the change. 

(A) Pilot gas for heaters and flares. 

(B) Fuel gas streams that meet a commercial-grade product specification for sulfur content of 30 

ppmv or less. In the case of a liquefied petroleum gas (LPG) product specification in the 

pressurized liquid state, the gas phase sulfur content should be evaluated assuming complete 

vaporization of the LPG and sulfur containing-compounds at the product specification 

concentration. 

(C) Fuel gas streams produced in process units that are intolerant to sulfur contamination, such as 

fuel gas streams produced in the hydrogen plant, the catalytic reforming unit, the isomerization 

unit, and HF alkylation process units. 

(D) Other fuel gas streams that an owner or operator demonstrates are low-sulfur according to 

the procedures in paragraph (b) of this section. 

(5) For Claus sulfur recovery plants with oxidation control systems or reduction control systems 

followed by incineration subject to §60.104(a)(2)(i), an instrument for continuously monitoring 

and recording the concentration (dry basis, zero percent excess air) of SO2 emissions into the 

atmosphere. The monitor shall include an oxygen monitor for correcting the data for excess air. 

(i) The span values for this monitor are 500 ppm SO2 and 25 percent O2. 

(ii) The performance evaluations for this SO2 monitor under §60.13(c) shall use Performance 

Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy 

evaluations. 

(6) For Claus sulfur recovery plants with reduction control systems not followed by incineration 

subject to §60.104(a)(2)(ii), an instrument for continuously monitoring and recording the 

concentration of reduced sulfur and O2 emissions into the atmosphere. The reduced sulfur 

emissions shall be calculated as SO2 (dry basis, zero percent excess air). 

(i) The span values for this monitor are 450 ppm reduced sulfur and 25 percent O2. 

(ii) The performance evaluations for this reduced sulfur (and O2) monitor under §60.13(c) shall 

use Performance Specification 5 of appendix B of this part(and Performance Specification 3 of 

appendix B of this part for the O2 analyzer). Methods 15 or 15A and Method 3 shall be used for 

conducting the relative accuracy evaluations. If Method 3 yields O2 concentrations below 0.25 

percent during the performance specification test, the O2 concentration may be assumed to be 

zero and the reduced sulfur CEMS need not include an O2 monitor. 

(7) In place of the reduced sulfur monitor under paragraph (a)(6) of this section, an instrument 

using an air or O2 dilution and oxidation system to convert the reduced sulfur to SO2 for 

continuously monitoring and recording the concentration (dry basis, zero percent excess air) of 
Page 8 of 23 

8 

the resultant SO2 . The monitor shall include an oxygen monitor for correcting the data for 

excess oxygen. 

(i) The span values for this monitor are 375 ppm SO2 and 25 percent O2. 

(ii) For reporting purposes, the SO2 exceedance level for this monitor is 250 ppm (dry basis, zero 

percent excess air). 

(iii) The performance evaluations for this SO2 (and O2) monitor under §60.13(c) shall use 

Performance Specification 5. Methods 15 or 15A and Method 3 shall be used for conducting the 

relative accuracy evaluations. 

(8) An instrument for continuously monitoring and recording concentrations of SO2 in the gases 

at both the inlet and outlet of the SO2 control device from any fluid catalytic cracking unit 

catalyst regenerator for which the owner or operator seeks to comply specifically with the 90 

percent reduction option under §60.104(b)(1). 

(i) The span value of the inlet monitor shall be set at 125 percent of the maximum estimated 

hourly potential SO2 emission concentration entering the control device, and the span value of 

the outlet monitor shall be set at 50 percent of the maximum estimated hourly potential SO2

emission concentration entering the control device. 

(ii) The performance evaluations for these SO2 monitors under §60.13(c) shall use Performance 

Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy 

evaluations. 

(9) An instrument for continuously monitoring and recording concentrations of SO2 in the gases 

discharged into the atmosphere from any fluid catalytic cracking unit catalyst regenerator for 

which the owner or operator seeks to comply specifically with the 50 ppmv emission limit under 

§60.104 (b)(1). 

(i) The span value of the monitor shall be set at 50 percent of the maximum hourly potential SO2

emission concentration of the control device. 

(ii) The performance evaluations for this SO2 monitor under §60.13 (c) shall use Performance 

Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the relative accuracy 

evaluations. 

(10) An instrument for continuously monitoring and recording concentrations of oxygen (O2) in 

the gases at both the inlet and outlet of the sulfur dioxide control device (or the outlet only if 

specifically complying with the 50 ppmv standard) from any fluid catalytic cracking unit catalyst 

regenerator for which the owner or operator has elected to comply with §60.104(b)(1). The span 

of this continuous monitoring system shall be set at 10 percent. 

(11) The continuous monitoring systems under paragraphs (a)(8), (a)(9), and (a)(10) of this 

section are operated and data recorded during all periods of operation of the affected facility 
Page 9 of 23 

9 

including periods of startup, shutdown, or malfunction, except for continuous monitoring system 

breakdowns, repairs, calibration checks, and zero and span adjustments. 

(12) The owner or operator shall use the following procedures to evaluate the continuous 

monitoring systems under paragraphs (a)(8), (a)(9), and (a)(10) of this section. 

(i) Method 3 or 3A and Method 6 or 6C for the relative accuracy evaluations under the §60.13(e) 

performance evaluation. 

(ii) appendix F, Procedure 1, including quarterly accuracy determinations and daily calibration 

drift tests. 

(13) When seeking to comply with §60.104(b)(1), when emission data are not obtained because 

of continuous monitoring system breakdowns, repairs, calibration checks and zero and span 

adjustments, emission data will be obtained by using one of the following methods to provide 

emission data for a minimum of 18 hours per day in at least 22 out of 30 rolling successive 

calendar days. 

(i) The test methods as described in §60.106(k); 

(ii) A spare continuous monitoring system; or 

(iii) Other monitoring systems as approved by the Administrator. 

(b) An owner or operator may demonstrate that a fuel gas stream combusted in a fuel gas 

combustion device subject to §60.104(a)(1) that is not specifically exempted in §60.105(a)(4)(iv) 

is inherently low in sulfur. A fuel gas stream that is determined to be low-sulfur is exempt from 

the monitoring requirements in paragraphs (a)(3) and (4) of this section until there are changes in 

operating conditions or stream composition. 

(1) The owner or operator shall submit to the Administrator a written application for an 

exemption from monitoring. The application must contain the following information: 

(i) A description of the fuel gas stream/system to be considered, including submission of a 

portion of the appropriate piping diagrams indicating the boundaries of the fuel gas 

stream/system, and the affected fuel gas combustion device(s) to be considered; 

(ii) A statement that there are no crossover or entry points for sour gas (high H2S content) to be 

introduced into the fuel gas stream/system (this should be shown in the piping diagrams); 

(iii) An explanation of the conditions that ensure low amounts of sulfur in the fuel gas stream 

(i.e., control equipment or product specifications) at all times; 

(iv) The supporting test results from sampling the requested fuel gas stream/system 

demonstrating that the sulfur content is less than 5 ppmv. Sampling data must include, at 

minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas 
Page 10 of 23 

10 

streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be 

collected unless other additional information would support reduced sampling. The owner or 

operator shall use detector tubes (“length-of-stain tube” type measurement) following the “Gas 

Processors Association Standard 2377-86, Test for Hydrogen Sulfide and Carbon Dioxide in 

Natural Gas Using Length of Stain Tubes,” 1986 Revision (incorporated by reference—see 

§60.17), using tubes with a maximum span between 10 and 40 ppmv inclusive when 

1≤N≤10, where N = number of pump strokes, with ranges 0–10/0–100 ppm (N = 10/1) to test 

the applicant fuel gas stream for H2S; and 

(v) A description of how the 2 weeks (or seven samples for infrequently operated fuel gas 

streams/systems) of monitoring results compares to the typical range of H2S concentration (fuel 

quality) expected for the fuel gas stream/system going to the affected fuel gas combustion device 

(e.g., the 2 weeks of daily detector tube results for a frequently operated loading rack included 

the entire range of products loaded out, and, therefore, should be representative of typical 

operating conditions affecting H2S content in the fuel gas stream going to the loading rack flare). 

(2) The effective date of the exemption is the date of submission of the information required in 

paragraph (b)(1) of this section). 

(3) No further action is required unless refinery operating conditions change in such a way that 

affects the exempt fuel gas stream/system (e.g., the stream composition changes). If such a 

change occurs, the owner or operator will follow the procedures in paragraph (b)(3)(i), (b)(3)(ii), 

or (b)(3)(iii) of this section. 

(i) If the operation change results in a sulfur content that is still within the range of 

concentrations included in the original application, the owner or operator shall conduct an H2S 

test on a grab sample and record the results as proof that the concentration is still within the 

range. 

(ii) If the operation change results in a sulfur content that is outside the range of concentrations 

included in the original application, the owner or operator may submit new information 

following the procedures of paragraph (b)(1) of this section within 60 days (or within 30 days 

after the seventh grab sample is tested for infrequently operated process units). 

(iii) If the operation change results in a sulfur content that is outside the range of concentrations 

included in the original application and the owner or operator chooses not to submit new 

information to support an exemption, the owner or operator must begin H2S monitoring using 

daily stain sampling to demonstrate compliance using length-of stain tubes with a maximum 

span between 200 and 400 ppmv inclusive when 1≤N≤5, where N = number of pump 

strokes. The owner or operator must begin monitoring according to the requirements in 

paragraphs (a)(1) or (a)(2) of this section as soon as practicable but in no case later than 180 days 

after the operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv 

is an exceedance of the 3-hour H2S concentration limit. The owner or operator must determine a 

rolling 365-day average using the stain sampling results; an average H2S concentration of 5 

ppmv must be used for days prior to the operation change.
Page 11 of 23 

11 

(c) The average coke burn-off rate (Mg (tons) per hour) and hours of operation shall be recorded 

daily for any fluid catalytic cracking unit catalyst regenerator subject to §60.102, §60.103, or 

§60.104(b)(2). 

(d) For any fluid catalytic cracking unit catalyst regenerator under §60.102 that uses an 

incinerator-waste heat boiler to combust the exhaust gases from the catalyst regenerator, the 

owner or operator shall record daily the rate of combustion of liquid or solid fossil-fuels and the 

hours of operation during which liquid or solid fossil-fuels are combusted in the incineratorwaste heat boiler. 

(e) For the purpose of reports under §60.7(c), periods of excess emissions that shall be 

determined and reported are defined as follows: 

NOTE: All averages, except for opacity, shall be determined as the arithmetic average of the 

applicable 1-hour averages, e.g., the rolling 3-hour average shall be determined as the arithmetic 

average of three contiguous 1-hour averages. 

(1) Opacity. All 1-hour periods that contain two or more 6-minute periods during which the 

average opacity as measured by the continuous monitoring system under §60.105(a)(1) exceeds 

30 percent. 

(2) Carbon monoxide. All 1-hour periods during which the average CO concentration as 

measured by the CO continuous monitoring system under §60.105(a)(2) exceeds 500 ppm. 

(3) Sulfur dioxide from fuel gas combustion. (i) All rolling 3-hour periods during which the 

average concentration of SO2 as measured by the SO2 continuous monitoring system under 

§60.105(a)(3) exceeds 20 ppm (dry basis, zero percent excess air); or 

(ii) All rolling 3-hour periods during which the average concentration of H2S as measured by the 

H2S continuous monitoring system under §60.105(a)(4) exceeds 230 mg/dscm (0.10 gr/dscf). 

(4) Sulfur dioxide from Claus sulfur recovery plants. (i) All 12-hour periods during which the 

average concentration of SO2 as measured by the SO2 continuous monitoring system under 

§60.105(a)(5) exceeds 250 ppm (dry basis, zero percent excess air); or 

(ii) All 12-hour periods during which the average concentration of reduced sulfur (as SO2) as 

measured by the reduced sulfur continuous monitoring system under §60.105(a)(6) exceeds 300 

ppm; or 

(iii) All 12-hour periods during which the average concentration of SO2 as measured by the SO2

continuous monitoring system under §60.105(a)(7) exceeds 250 ppm (dry basis, zero percent 

excess air). 
Page 12 of 23 

12 

§ 60.106 Test methods and procedures. 

(a) In conducting the performance tests required in §60.8, the owner or operator shall use as 

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

and procedures as specified in this section, except as provided in §60.8(b). 

(b) The owner or operator shall determine compliance with the particulate matter (PM) standards 

in §60.102(a) as follows: 

(1) The emission rate (E) of PM shall be computed for each run using the following equation: 

c

s sd

KR

c Q E 

Where: 

E = Emission rate of PM, kg/Mg (lb/ton) of coke burn-off. 

cs = Concentration of PM, g/dscm (gr/dscf). 

Qsd = Volumetric flow rate of effluent gas, dscm/hr (dscf/hr). 

Rc = Coke burn-off rate, Mg/hr (ton/hr) coke. 

K=Conversion factor, 1,000 g/kg (7,000 gr/lb). 

(2) Method 5B or 5F is to be used to determine particulate matter emissions and associated 

moisture content from affected facilities without wet FGD systems; only Method 5B is to be 

used after wet FGD systems. The sampling time for each run shall be at least 60 minutes and the 

sampling rate shall be at least 0.015 dscm/min (0.53 dscf/min), except that shorter sampling 

times may be approved by the Administrator when process variables or other factors preclude 

sampling for at least 60 minutes. 

(3) The coke burn-off rate (Rc) shall be computed for each run using the following equation: 

Rc = K1Qr (%CO2 + %CO) + K2Qa −K3Qr (%CO/2 + %CO2 + %O2) + K3Qoxy (%Ooxy) 

Where: 

Rc = Coke burn-off rate, kilograms per hour (kg/hr) (lb/hr). 

Qr = Volumetric flow rate of exhaust gas from fluid catalytic cracking unit regenerator before 

entering the emission control system, dscm/min (dscf/min). 

Qa = Volumetric flow rate of air to fluid catalytic cracking unit regenerator, as determined from 

the fluid catalytic cracking unit control room instrumentation, dscm/min (dscf/min). 
Page 13 of 23 

13 

Qoxy = Volumetric flow rate of O2 enriched air to fluid catalytic cracking unit regenerator, as 

determined from the fluid catalytic cracking unit control room instrumentation, dscm/min 

(dscf/min). 

%CO2 = Carbon dioxide concentration in fluid catalytic cracking unit regenerator exhaust, 

percent by volume (dry basis). 

%CO = CO concentration in FCCU regenerator exhaust, percent by volume (dry basis). 

%O2 = O2 concentration in fluid catalytic cracking unit regenerator exhaust, percent by volume 

(dry basis). 

%Ooxy = O2 concentration in O2 enriched air stream inlet to the fluid catalytic cracking unit 

regenerator, percent by volume (dry basis). 

K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hrdscf-%)]. 

K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hrdscf)]. 

K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) [0.00624 (lbmin)/(hr-dscf-%)]. 

(i) Method 2 shall be used to determine the volumetric flow rate (Qr). 

(ii) The emission correction factor, integrated sampling and analysis procedure of Method 3B 

shall be used to determine CO2, CO, and O2 concentrations. 

(4) Method 9 and the procedures of §60.11 shall be used to determine opacity. 

(c) If auxiliary liquid or solid fossil-fuels are burned in an incinerator-waste heat boiler, the 

owner or operator shall determine the emission rate of PM permitted in §60.102(b) as follows: 

(1) The allowable emission rate (Es) of PM shall be computed for each run using the following 

equation: 

  Es  F  A H Rc

Where: 

Es = Emission rate of PM allowed, kg/Mg (lb/ton) of coke burn-off in catalyst regenerator. 

F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in catalyst regenerator. 

A = Allowable incremental rate of PM emissions, 43 g/GJ (0.10 lb/million Btu). 
Page 14 of 23 

14 

H = Heat input rate from solid or liquid fossil fuel, GJ/hr (million Btu/hr). 

Rc = Coke burn-off rate, Mg coke/hr (ton coke/hr). 

(2) Procedures subject to the approval of the Administrator shall be used to determine the heat 

input rate. 

(3) The procedure in paragraph (b)(3) of this section shall be used to determine the coke burn-off 

rate (Rc). 

(d) The owner or operator shall determine compliance with the CO standard in §60.103(a) by 

using the integrated sampling technique of Method 10 to determine the CO concentration (dry 

basis). The sampling time for each run shall be 60 minutes. 

(e)(1) The owner or operator shall determine compliance with the H2S standard in §60.104(a)(1) 

as follows: Method 11, 15, 15A, or 16 shall be used to determine the H2S concentration. The 

gases entering the sampling train should be at about atmospheric pressure. If the pressure in the 

refinery fuel gas lines is relatively high, a flow control valve may be used to reduce the pressure. 

If the line pressure is high enough to operate the sampling train without a vacuum pump, the 

pump may be eliminated from the sampling train. The sample shall be drawn from a point near 

the centroid of the fuel gas line. 

(i) For Method 11, the sampling time and sample volume shall be at least 10 minutes and 0.010 

dscm (0.35 dscf). Two samples of equal sampling times shall be taken at about 1-hour intervals. 

The arithmetic average of these two samples shall constitute a run. For most fuel gases, sampling 

times exceeding 20 minutes may result in depletion of the collection solution, although fuel 

gases containing low concentrations of H2S may necessitate sampling for longer periods of time. 

(ii) For Method 15 or 16, at least three injects over a 1-hour period shall constitute a run. 

(iii) For Method 15A, a 1-hour sample shall constitute a run. 

(2) Where emissions are monitored by §60.105(a)(3), compliance with §60.104(a)(1) shall be 

determined using Method 6 or 6C and Method 3 or 3A. The method ANSI/ASME PTC 19.10-

1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an 

acceptable alternative to EPA Method 6. A 1-hour sample shall constitute a run. Method 6 

samples shall be taken at a rate of approximately 2 liters/min. The ppm correction factor (Method 

6) and the sampling location in paragraph (f)(1) of this section apply. Method 4 shall be used to 

determine the moisture content of the gases. The sampling point for Method 4 shall be adjacent 

to the sampling point for Method 6 or 6C. 

(f) The owner or operator shall determine compliance with the SO2 and the H2S and reduced 

sulfur standards in §60.104(a)(2) as follows: 

(1) Method 6 shall be used to determine the SO2 concentration. The concentration in mg/dscm 

obtained by Method 6 or 6C is multiplied by 0.3754 to obtain the concentration in ppm. The 
Page 15 of 23 

15 

sampling point in the duct shall be the centroid of the cross section if the cross-sectional area is 

less than 5.00 m2

 (53.8 ft2) or at a point no closer to the walls than 1.00 m (39.4 in.) if the crosssectional area is 5.00 m2

 or more and the centroid is more than 1 m from the wall. The sampling 

time and sample volume shall be at least 10 minutes and 0.010 dscm (0.35 dscf) for each sample. 

Eight samples of equal sampling times shall be taken at about 30-minute intervals. The 

arithmetic average of these eight samples shall constitute a run. For Method 6C, a run shall 

consist of the arithmetic average of four 1-hour samples. Method 4 shall be used to determine the 

moisture content of the gases. The sampling point for Method 4 shall be adjacent to the sampling 

point for Method 6 or 6C. The sampling time for each sample shall be equal to the time it takes 

for two Method 6 samples. The moisture content from this sample shall be used to correct the 

corresponding Method 6 samples for moisture. For documenting the oxidation efficiency of the 

control device for reduced sulfur compounds, Method 15 shall be used following the procedures 

of paragraph (f)(2) of this section. 

(2) Method 15 shall be used to determine the reduced sulfur and H2S concentrations. Each run 

shall consist of 16 samples taken over a minimum of 3 hours. The sampling point shall be the 

same as that described for Method 6 in paragraph (f)(1) of this section. To ensure minimum 

residence time for the sample inside the sample lines, the sampling rate shall be at least 3.0 lpm 

(0.10 cfm). The SO2 equivalent for each run shall be calculated after being corrected for moisture 

and oxygen as the arithmetic average of the SO2 equivalent for each sample during the run. 

Method 4 shall be used to determine the moisture content of the gases as the paragraph (f)(1) of 

this section. The sampling time for each sample shall be equal to the time it takes for four 

Method 15 samples. 

(3) The oxygen concentration used to correct the emission rate for excess air shall be obtained by 

the integrated sampling and analysis procedure of Method 3 or 3A. The samples shall be taken 

simultaneously with the SO2, reduced sulfur and H2S, or moisture samples. The SO2, reduced 

sulfur, and H2S samples shall be corrected to zero percent excess air using the equation in 

paragraph (h)(6) of this section. 

(g) Each performance test conducted for the purpose of determining compliance under 

§60.104(b) shall consist of all testing performed over a 7-day period using Method 6 or 6C and 

Method 3 or 3A. To determine compliance, the arithmetic mean of the results of all the tests shall 

be compared with the applicable standard. 

(h) For the purpose of determining compliance with §60.104(b)(1), the following calculation 

procedures shall be used: 

(1) Calculate each 1-hour average concentration (dry, zero percent oxygen, ppmv) of sulfur 

dioxide at both the inlet and the outlet to the add-on control device as specified in §60.13(h). 

These calculations are made using the emission data collected under §60.105(a). 

(2) Calculate a 7-day average (arithmetic mean) concentration of sulfur dioxide for the inlet and 

for the outlet to the add-on control device using all of the 1-hour average concentration values 

obtained during seven successive 24-hour periods. 
Page 16 of 23 

16 

(3) Calculate the 7-day average percent reduction using the following equation: 

Rso2 = 100(Cso2(i)−Cso2(o))/Cso2(i) 

where: 

Rso2 = 7-day average sulfur dioxide emission reduction, percent 

Cso2(i) = sulfur dioxide emission concentration determined in §60.106(h)(2) at the inlet to the 

add-on control device, ppmv 

Cso2(o) = sulfur dioxide emission concentration determined in §60.106(h)(2) at the outlet to the 

add-on control device, ppmv 

100 = conversion factor, decimal to percent 

(4) Outlet concentrations of sulfur dioxide from the add-on control device for compliance with 

the 50 ppmv standard, reported on a dry, O2-free basis, shall be calculated using the procedures 

outlined in §60.106(h)(1) and (2) above, but for the outlet monitor only. 

(5) If supplemental sampling data are used for determining the 7-day averages under paragraph 

(h) of this section and such data are not hourly averages, then the value obtained for each 

supplemental sample shall be assumed to represent the hourly average for each hour over which 

the sample was obtained. 

(6) For the purpose of adjusting pollutant concentrations to zero percent oxygen, the following 

equation shall be used: 

Cadj = Cmeas [20.9c/(20.9−%O2)] 

where: 

Cadj = pollutant concentration adjusted to zero percent oxygen, ppm or g/dscm 

Cmeas = pollutant concentration measured on a dry basis, ppm or g/dscm 

20.9c = 20.9 percent oxygen−0.0 percent oxygen (defined oxygen correction basis), percent 

20.9 = oxygen concentration in air, percent 

%O2 = oxygen concentration measured on a dry basis, percent 

(i) For the purpose of determining compliance with §60.104(b)(2), the following reference 

methods and calculation procedures shall be used except as provided in paragraph (i)(12) of this 

section: 
Page 17 of 23 

17 

(1) One 3-hour test shall be performed each day. 

(2) For gases released to the atmosphere from the fluid catalytic cracking unit catalyst 

regenerator: 

(i) Method 8 as modified in §60.106(i)(3) for moisture content and for the concentration of sulfur 

oxides calculated as sulfur dioxide, 

(ii) Method 1 for sample and velocity traverses, 

(iii) Method 2 calculation procedures (data obtained from Methods 3 and 8) for velocity and 

volumetric flow rate, and 

(iv) Method 3 for gas analysis. 

(3) Method 8 shall be modified by the insertion of a heated glass fiber filter between the probe 

and first impinger. The probe liner and glass fiber filter temperature shall be maintained above 

160 °C (320 °F). The isopropanol impinger shall be eliminated. Sample recovery procedures 

described in Method 8 for container No. 1 shall be eliminated. The heated glass fiber filter also 

shall be excluded; however, rinsing of all connecting glassware after the heated glass fiber filter 

shall be retained and included in container No. 2. Sampled volume shall be at least 1 dscm. 

(4) For Method 3, the integrated sampling technique shall be used. 

(5) Sampling time for each run shall be at least 3 hours. 

(6) All testing shall be performed at the same location. Where the gases discharged by the fluid 

catalytic cracking unit catalyst regenerator pass through an incinerator-waste heat boiler in which 

auxiliary or supplemental gaseous, liquid, or solid fossil fuel is burned, testing shall be 

conducted at a point between the regenerator outlet and the incinerator-waste heat boiler. An 

alternative sampling location after the waste heat boiler may be used if alternative coke burn-off 

rate equations, and, if requested, auxiliary/supplemental fuel SOX credits, have been submitted to 

and approved by the Administrator prior to sampling. 

(7) Coke burn-off rate shall be determined using the procedures specified under paragraph (b)(3) 

of this section, unless paragraph (i)(6) of this section applies. 

(8) Calculate the concentration of sulfur oxides as sulfur dioxide using equation 8-3 in Section 

6.5 of Method 8 to calculate and report the total concentration of sulfur oxides as sulfur dioxide 

(Csox). 

(9) Sulfur oxides emission rate calculated as sulfur dioxide shall be determined for each test run 

by the following equation: 
Page 18 of 23 

18 

Where: 

ESOx = sulfur oxides emission rate calculated as sulfur dioxide, kg/hr (lb/hr) 

CSOx = sulfur oxides emission concentration calculated as sulfur dioxide, g/dscm (gr/dscf) 

Qsd = dry volumetric stack gas flow rate corrected to standard conditions, dscm/hr (dscf/hr) 

K=1,000 g/kg (7,000 gr/lb) 

(10) Sulfur oxides emissions calculated as sulfur dioxide shall be determined for each test run by 

the following equation: 

Where: 

RSOx = Sulfur oxides emissions calculated as kg sulfur dioxide per Mg (lb/ton) coke burn-off. 

ESOx = Sulfur oxides emission rate calculated as sulfur dioxide, kg/hr (lb/hr). 

Rc = Coke burn-off rate, Mg/hr (ton/hr). 

(11) Calculate the 7-day average sulfur oxides emission rate as sulfur dioxide per Mg (ton) of 

coke burn-off by dividing the sum of the individual daily rates by the number of daily rates 

summed. 

(12) An owner or operator may, upon approval by the Administrator, use an alternative method 

for determining compliance with §60.104(b)(2), as provided in §60.8(b). Any requests for 

approval must include data to demonstrate to the Administrator that the alternative method 

would produce results adequate for the determination of compliance. 

(j) For the purpose of determining compliance with §60.104(b)(3), the following analytical 

methods and calculation procedures shall be used: 

(1) One fresh feed sample shall be collected once per 8-hour period. 

(2) Fresh feed samples shall be analyzed separately by using any one of the following applicable 

analytical test methods: ASTM D129-64, 78, or 95, ASTM D1552-83 or 95, ASTM D2622-87, 

94, or 98, or ASTM D1266-87, 91, or 98. (These methods are incorporated by reference: see 

§60.17.) The applicable range of some of these ASTM methods is not adequate to measure the 

levels of sulfur in some fresh feed samples. Dilution of samples prior to analysis with 

verification of the dilution ratio is acceptable upon prior approval of the Administrator. 
Page 19 of 23 

19 

(3) If a fresh feed sample cannot be collected at a single location, then the fresh feed sulfur 

content shall be determined as follows: 

(i) Individual samples shall be collected once per 8-hour period for each separate fresh feed 

stream charged directly into the riser or reactor of the fluid catalytic cracking unit. For each 

sample location the fresh feed volumetric flow rate at the time of collecting the fresh feed sample 

shall be measured and recorded. The same method for measuring volumetric flow rate shall be 

used at all locations. 

(ii) Each fresh feed sample shall be analyzed separately using the methods specified under 

paragraph (j)(2) of this section. 

(iii) Fresh feed sulfur content shall be calculated for each 8-hour period using the following 

equation: 

where: 

Sf = fresh feed sulfur content expressed in percent by weight of fresh feed. 

n = number of separate fresh feed streams charged directly to the riser or reactor of the fluid 

catalytic cracking unit. 

Qf = total volumetric flow rate of fresh feed charged to the fluid catalytic cracking unit. 

Si = fresh feed sulfur content expressed in percent by weight of fresh feed for the “ith” sampling 

location. 

Qi = volumetric flow rate of fresh feed stream for the “ith” sampling location. 

(4) Calculate a 7-day average (arithmetic mean) sulfur content of the fresh feed using all of the 

fresh feed sulfur content values obtained during seven successive 24-hour periods. 

(k) The test methods used to supplement continuous monitoring system data to meet the 

minimum data requirements in §60.104(d) will be used as described below or as otherwise 

approved by the Administrator. 

(1) Methods 6, 6B, or 8 are used. The sampling location(s) are the same as those specified for the 

monitor. 

(2) For Method 6, the minimum sampling time is 20 minutes and the minimum sampling volume 

is 0.02 dscm (0.71 dscf) for each sample. Samples are taken at approximately 60-minute 
Page 20 of 23 

20 

intervals. Each sample represents a 1-hour average. A minimum of 18 valid samples is required 

to obtain one valid day of data. 

(3) For Method 6B, collection of a sample representing a minimum of 18 hours is required to 

obtain one valid day of data. 

(4) For Method 8, the procedures as outlined in this section are used. The equivalent of 16 hours 

of sampling is required to obtain one valid day of data. 

§ 60.107 Reporting and recordkeeping requirements. 

(a) Each owner or operator subject to §60.104(b) shall notify the Administrator of the specific 

provisions of §60.104(b) with which the owner or operator seeks to comply. Notification shall be 

submitted with the notification of initial startup required by §60.7(a)(3). If an owner or operator 

elects at a later date to comply with an alternative provision of §60.104(b), then the 

Administrator shall be notified by the owner or operator in the report described in paragraph (c) 

of this section. 

(b) Each owner or operator subject to §60.104(b) shall record and maintain the following 

information: 

(1) If subject to §60.104(b)(1), 

(i) All data and calibrations from continuous monitoring systems located at the inlet and outlet to 

the control device, including the results of the daily drift tests and quarterly accuracy 

assessments required under appendix F, Procedure 1; 

(ii) Measurements obtained by supplemental sampling (refer to §60.105(a)(13) and §60.106(k)) 

for meeting minimum data requirements; and 

(iii) The written procedures for the quality control program required by appendix F, Procedure 1. 

(2) If subject to §60.104(b)(2), measurements obtained in the daily Method 8 testing, or those 

obtained by alternative measurement methods, if §60.106(i)(12) applies. 

(3) If subject to §60.104(b)(3), data obtained from the daily feed sulfur tests. 

(4) Each 7-day rolling average compliance determination. 

(c) Each owner or operator subject to §60.104(b) shall submit a report except as provided by 

paragraph (d) of this section. The following information shall be contained in the report: 

(1) Any 7-day period during which: 

(i) The average percent reduction and average concentration of sulfur dioxide on a dry, O2-free 

basis in the gases discharged to the atmosphere from any fluid cracking unit catalyst regenerator 
Page 21 of 23 

21 

for which the owner or operator seeks to comply with §60.104(b)(1) is below 90 percent and 

above 50 ppmv, as measured by the continuous monitoring system prescribed under 

§60.105(a)(8), or above 50 ppmv, as measured by the outlet continuous monitoring system 

prescribed under §60.105(a)(9). The average percent reduction and average sulfur dioxide 

concentration shall be determined using the procedures specified under §60.106(h); 

(ii) The average emission rate of sulfur dioxide in the gases discharged to the atmosphere from 

any fluid catalytic cracking unit catalyst regenerator for which the owner or operator seeks to 

comply with §60.104(b)(2) exceeds 9.8 kg SOX per 1,000 kg coke burn-off, as measured by the 

daily testing prescribed under §60.106(i). The average emission rate shall be determined using 

the procedures specified under §60.106(i); and 

(iii) The average sulfur content of the fresh feed for which the owner or operator seeks to comply 

with §60.104(b)(3) exceeds 0.30 percent by weight. The fresh feed sulfur content, a 7-day rolling 

average, shall be determined using the procedures specified under §60.106(j). 

(2) Any 30-day period in which the minimum data requirements specified in §60.104(d) are not 

obtained. 

(3) For each 7-day period during which an exceedance has occurred as defined in paragraphs 

(c)(1)(i) through (c)(1)(iii) and (c)(2) of this section: 

(i) The date that the exceedance occurred; 

(ii) An explanation of the exceedance; 

(iii) Whether the exceedance was concurrent with a startup, shutdown, or malfunction of the 

fluid catalytic cracking unit or control system; and 

(iv) A description of the corrective action taken, if any. 

(4) If subject to §60.104(b)(1), 

(i) The dates for which and brief explanations as to why fewer than 18 valid hours of data were 

obtained for the inlet continuous monitoring system; 

(ii) The dates for which and brief explanations as to why fewer than 18 valid hours of data were 

obtained for the outlet continuous monitoring system; 

(iii) Identification of times when hourly averages have been obtained based on manual sampling 

methods; 

(iv) Identification of the times when the pollutant concentration exceeded full span of the 

continuous monitoring system; and 
Page 22 of 23 

22 

(v) Description of any modifications to the continuous monitoring system that could affect the 

ability of the continuous monitoring system to comply with Performance Specifications 2 or 3. 

(vi) Results of daily drift tests and quarterly accuracy assessments as required under appendix F, 

Procedure 1. 

(5) If subject to §60.104(b)(2), for each day in which a Method 8 sample result required by 

§60.106(i) was not obtained, the date for which and brief explanation as to why a Method 8 

sample result was not obtained, for approval by the Administrator. 

(6) If subject to §60.104(b)(3), for each 8-hour period in which a feed sulfur measurement 

required by §60.106(j) was not obtained, the date for which and brief explanation as to why a 

feed sulfur measurement was not obtained, for approval by the Administrator. 

(d) For any periods for which sulfur dioxide or oxides emissions data are not available, the 

owner or operator of the affected facility shall submit a signed statement indicating if any 

changes were made in operation of the emission control system during the period of data 

unavailability which could affect the ability of the system to meet the applicable emission limit. 

Operations of the control system and affected facility during periods of data unavailability are to 

be compared with operation of the control system and affected facility before and following the 

period of data unavailability. 

(e) For each fuel gas stream combusted in a fuel gas combustion device subject to §60.104(a)(1), 

if an owner or operator determines that one of the exemptions listed in §60.105(a)(4)(iv) applies 

to that fuel gas stream, the owner or operator shall maintain records of the specific exemption 

chosen for each fuel gas stream. If the owner or operator applies for the exemption described in 

§60.105(a)(4)(iv)(D), the owner or operator must keep a copy of the application as well as the 

letter from the Administrator granting approval of the application. 

(f) The owner or operator of an affected facility shall submit the reports required under this 

subpart to the Administrator semiannually for each six-month period. All semiannual reports 

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

(g) The owner or operator of the affected facility shall submit a signed statement certifying the 

accuracy and completeness of the information contained in the report. 

§ 60.108 Performance test and compliance provisions. 

(a) Section 60.8(d) shall apply to the initial performance test specified under paragraph (c) of this 

section, but not to the daily performance tests required thereafter as specified in §60.108(d). 

Section 60.8(f) does not apply when determining compliance with the standards specified under 

§60.104(b). Performance tests conducted for the purpose of determining compliance under 

§60.104(b) shall be conducted according to the applicable procedures specified under §60.106. 

(b) Owners or operators who seek to comply with §60.104(b)(3) shall meet that standard at all 

times, including periods of startup, shutdown, and malfunctions. 
Page 23 of 23 

23 

(c) The initial performance test shall consist of the initial 7-day average calculated for 

compliance with §60.104(b)(1), (b)(2), or (b)(3). 

(d) After conducting the initial performance test prescribed under §60.8, the owner or operator of 

a fluid catalytic cracking unit catalyst regenerator subject to §60.104(b) shall conduct a 

performance test for each successive 24-hour period thereafter. The daily performance tests shall 

be conducted according to the appropriate procedures specified under §60.106. In the event that a 

sample collected under §60.106(i) or (j) is accidentally lost or conditions occur in which one of 

the samples must be discontinued because of forced shutdown, failure of an irreplaceable portion 

of the sample train, extreme meteorological conditions, or other circumstances, beyond the 

owner or operators' control, compliance may be determined using available data for the 7-day 

period. 

(e) Each owner or operator subject to §60.104(b) who has demonstrated compliance with one of 

the provisions of §60.104(b) but a later date seeks to comply with another of the provisions of 

§60.104(b) shall begin conducting daily performance tests as specified under paragraph (d) of 

this section immediately upon electing to become subject to one of the other provisions of 

§60.104(b). The owner or operator shall furnish the Administrator with a written notification of 

the change in the semiannual report required by §60.107(f). 

§ 60.109 Delegation of authority. 

(a) In delegating implementation and enforcement authority to a State under section 111(c) of the 

Act, the authorities contained in paragraph (b) of this section shall be retained by the 

Administrator and not transferred to a State. 

(b) Authorities which shall not be delegated to States: 

(1) Section 60.105(a)(13)(iii), 

(2) Section 60.106(i)(12).