May 15, 2014 

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

Insertions are shown in bold blue text 

Deletions are shown in red strikeout text 

 

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Title 40: Protection of Environment 

PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

Subpart Ja—Standards of Performance for Petroleum Refineries for Which Construction, 

Reconstruction, or Modification Commenced After May 14, 2007 

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

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

refineries: fluid catalytic cracking units (FCCU), fluid coking units (FCU), delayed coking units, 

fuel gas combustion devices (including process heaters), flares and sulfur recovery plants. The 

sulfur recovery plant need not be physically located within the boundaries of a petroleum 

refinery to be an affected facility, provided it processes gases produced within a petroleum 

refinery. 

(b) Except for flares and delayed coking units, the provisions of this subpart apply only to 

affected facilities under paragraph (a) of this section which either commence construction, 

modification or reconstruction after May 14, 2007, or elect to comply with the provisions of 

this subpart in lieu of complying with the provisions in subpart J of this part. For flares, the 

provisions of this subpart apply only to flares which commence construction, modification or 

reconstruction after June 24, 2008. For the purposes of this subpart, a modification to a flare 

commences when a project that includes any of the activities in paragraphs (c)(1) or (2) of this 

section is commenced. For delayed coking units, the provisions of this subpart apply to delayed 

coking units that commence construction, reconstruction or modification on the earliest of the 

following dates: 

(1) May 14, 2007, for such activities that involve a “delayed coking unit” defined as follows: one 

or more refinery process units in which high molecular weight petroleum derivatives are 

thermally cracked and petroleum coke is produced in a series of closed, batch system reactors; 

(2) December 22, 2008, for such activities that involve a “delayed coking unit” defined as 

follows: a refinery process unit in which high molecular weight petroleum derivatives are 

thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A 

delayed coking unit consists of the coke drums and associated fractionator; 

(3) September 12, 2012, for such activities that involve a “delayed coking unit” as defined in 

§60.101a. 

(c) For all affected facilities other than flares, the provisions in §60.14 regarding modification 

apply. As provided in §60.14(f), the special provisions set forth under this subpart shall 
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supersede the provisions in §60.14 with respect to flares. For the purposes of this subpart, a 

modification to a flare occurs as provided in paragraphs (c)(1) or (2) of this section. 

(1) Any new piping from a refinery process unit, including ancillary equipment, or a fuel gas 

system is physically connected to the flare (e.g., for direct emergency relief or some form of 

continuous or intermittent venting). However, the connections described in paragraphs (c)(1)(i) 

through (vii) of this section are not considered modifications of a flare. 

(i) Connections made to install monitoring systems to the flare. 

(ii) Connections made to install a flare gas recovery system or connections made to upgrade or 

enhance components of a flare gas recovery system (e.g., addition of compressors or recycle 

lines). 

(iii) Connections made to replace or upgrade existing pressure relief or safety valves, provided 

the new pressure relief or safety valve has a set point opening pressure no lower and an internal 

diameter no greater than the existing equipment being replaced or upgraded. 

(iv) Connections made for flare gas sulfur removal. 

(v) Connections made to install back-up (redundant) equipment associated with the flare (such as 

a back-up compressor) that does not increase the capacity of the flare. 

(vi) Replacing piping or moving an existing connection from a refinery process unit to a new 

location in the same flare, provided the new pipe diameter is less than or equal to the diameter of 

the pipe/connection being replaced/moved. 

(vii) Connections that interconnect two or more flares. 

(2) A flare is physically altered to increase the flow capacity of the flare. 

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

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

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

any 2-year period following the relevant applicability date specified in paragraph (b) of this 

section. 

§ 60.101a Definitions. 

Terms used in this subpart are defined in the Clean Air Act (CAA), in §60.2 and in this section. 

Air preheat means a device used to heat the air supplied to a process heater generally by use of a 

heat exchanger to recover the sensible heat of exhaust gas from the process heater. 

Ancillary equipment means equipment used in conjunction with or that serve a refinery process 

unit. Ancillary equipment includes, but is not limited to, storage tanks, product loading 
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operations, wastewater treatment systems, steam- or electricity-producing units (including coke 

gasification units), pressure relief valves, pumps, sampling vents and continuous analyzer vents. 

Cascaded flare system means a series of flares connected to one flare gas header system arranged 

with increasing pressure set points so that discharges will be initially directed to the first flare in 

the series (i.e., the primary flare). If the discharge pressure exceeds a set point at which the flow 

to the primary flare would exceed the primary flare's capacity, flow will be diverted to the 

second flare in the series. Similarly, flow would be diverted to a third (or fourth) flare if the 

pressure in the flare gas header system exceeds a threshold where the flow to the first two (or 

three) flares would exceed their capacities. 

Co-fired process heater means a process heater that employs burners that are designed to be 

supplied by both gaseous and liquid fuels on a routine basis. Process heaters that have gas 

burners with emergency oil back-up burners are not considered co-fired process heaters. 

Coke burn-off means the coke removed from the surface of the FCCU catalyst by combustion in 

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

§60.104a. 

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

other contaminant from petroleum derivatives. 

Corrective action means the design, operation and maintenance changes that one takes consistent 

with good engineering practice to reduce or eliminate the likelihood of the recurrence of the 

primary cause and any other contributing cause(s) of an event identified by a root cause analysis 

as having resulted in a discharge of gases tofrom an affected flare facility in excess of specified 

thresholds. 

Corrective action analysis means a description of all reasonable interim and long-term measures, 

if any, that are available, and an explanation of why the selected corrective action(s) is/are the 

best alternative(s), including, but not limited to, considerations of cost effectiveness, technical 

feasibility, safety and secondary impacts. 

Delayed coking unit means a refinery process unit in which high molecular weight petroleum 

derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch 

system reactors. A delayed coking unit includes, but is not limited to, all of the coke drums 

associated with a single fractionator; the fractionator, including the bottoms receiver and the 

overhead condenser; the coke drum cutting water and quench system, including the jet pump and 

coker quench water tank; and the coke drum blowdown recovery compressor system. 

Emergency flare means a flare that combusts gas exclusively released as a result of malfunctions 

(and not startup, shutdown, routine operations or any other cause) on four or fewer occasions in a 

rolling 365-day period. For purposes of this rule, a flare cannot be categorized as an emergency 

flare unless it maintains a water seal. 
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Flare means a combustion device that uses an uncontrolled volume of air to burn gases. The 

flare includes the foundation, flare tip, structural support, burner, igniter, flare controls, including 

air injection or steam injection systems, flame arrestors and the flare gas header system. In the 

case of an interconnected flare gas header system, the flare includes each individual flare 

serviced by the interconnected flare gas header system and the interconnected flare gas header 

system. 

Flare gas header system means all piping and knockout pots, including those in a subheader 

system, used to collect and transport gas to a flare either from a process unit or a pressure relief 

valve from the fuel gas system, regardless of whether or not a flare gas recovery system draws 

gas from the flare gas header system. The flare gas header system includes piping inside the 

battery limit of a process unit if the purpose of the piping is to transport gas to a flare or 

knockout pot that is part of the flare. 

Flare gas recovery system means a system of one or more compressors, piping and the 

associated water seal, rupture disk or similar device used to divert gas from the flare and direct 

the gas to the fuel gas system or to a fuel gas combustion device. 

Flexicoking unit means a refinery process unit in which high molecular weight petroleum 

derivatives are thermally cracked and petroleum coke is continuously produced and then gasified 

to produce a synthetic fuel gas. 

Fluid catalytic cracking unit means a refinery process unit in which petroleum derivatives are 

continuously charged and hydrocarbon molecules in the presence of a catalyst suspended in a 

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

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

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

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

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

emissions and for heat recovery. When fluid catalyst cracking unit regenerator exhaust from two 

separate fluid catalytic cracking units share a common exhaust treatment (e.g., CO boiler or wet 

scrubber), the fluid catalytic cracking unit is a single affected facility. 

Fluid coking unit means a refinery process unit in which high molecular weight petroleum 

derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed 

system. The fluid coking unit includes the coking reactor, the coking burner, and equipment for 

controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent. 

Forced draft process heater means a process heater in which the combustion air is supplied 

under positive pressure produced by a fan at any location in the inlet air line prior to the point 

where the combustion air enters the process heater or air preheat. For the purposes of this 

subpart, a process heater that uses fans at both the inlet air side and the exhaust air side (i.e., 

balanced draft system) is considered to be a forced draft process heater. 

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

gas includes natural gas when the natural gas is combined and combusted in any proportion with 
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a gas generated at a refinery. Fuel gas does not include gases generated by catalytic cracking unit 

catalyst regenerators, coke calciners (used to make premium grade coke) and fluid coking 

burners, but does include gases from flexicoking unit gasifiers and other gasifiers. Fuel gas does 

not include vapors that are collected and combusted in a thermal oxidizer or flare installed to 

control emissions from wastewater treatment units other than those processing sour water, 

marine tank vessel loading operations or asphalt processing units (i.e., asphalt blowing stills). 

Fuel gas combustion device means any equipment, such as process heaters and boilers, used to 

combust fuel gas. For the purposes of this subpart, fuel gas combustion device does not include 

flares or facilities in which gases are combusted to produce sulfur or sulfuric acid. 

Fuel gas system means a system of compressors, piping, knock-out pots, mix drums, and units 

used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects 

refinery fuel gas from one or more sources for treatment as necessary prior to combusting in 

process heaters or boilers. A fuel gas system may have an overpressure vent to a flare but the 

primary purpose for a fuel gas system is to provide fuel to the refinery. 

Natural draft process heater means any process heater in which the combustion air is supplied 

under ambient or negative pressure without the use of an inlet air (forced draft) fan. For the 

purposes of this subpart, a natural draft process heater is any process heater that is not a forced 

draft process heater, including induced draft systems. 

Non-emergency flare means any flare that is not an emergency flare as defined in this subpart. 

Oxidation control system means an emission control system which reduces emissions from sulfur 

recovery plants by converting these emissions to sulfur dioxide (SO2) and recycling the SO2 to 

the reactor furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or 

converting the SO2 to a sulfur product. 

Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, 

and coal. 

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

oils, residual fuel oils, lubricants, asphalt (bitumen) or other products through distillation of 

petroleum or through redistillation, cracking or reforming of unfinished petroleum derivatives. A 

facility that produces only oil shale or tar sands-derived crude oil for further processing at a 

petroleum refinery using only solvent extraction and/or distillation to recover diluent is not a 

petroleum refinery. 

Primary flare means the first flare in a cascaded flare system. 

Process heater means an enclosed combustion device used to transfer heat indirectly to process 

stream materials (liquids, gases, or solids) or to a heat transfer material for use in a process unit 

instead of steam. 
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Process upset gas means any gas generated by a petroleum refinery process unit or by ancillary 

equipment as a result of startup, shutdown, upset or malfunction. 

Purge gas means gas introduced between a flare's water seal and a flare's tip to prevent oxygen 

infiltration (backflow) into the flare tip. For flares with no water seals, the function of purge gas

is performed by sweep gas (i.e., flares without water seals do not use purge gas). 

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

disulfide. 

Reduction control system means an emission control system which reduces emissions from sulfur 

recovery plants by converting these emissions to H2S and either recycling the H2S to the reactor 

furnace or the first-stage catalytic reactor of the Claus sulfur recovery plant or converting the 

H2S to a sulfur product. 

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

processing operation is conducted. 

Root cause analysis means an assessment conducted through a process of investigation to 

determine the primary cause, and any other contributing cause(s), of a discharge of gases in 

excess of specified thresholds. 

Secondary flare means a flare in a cascaded flare system that provides additional flare capacity 

and pressure relief to a flare gas system when the flare gas flow exceeds the capacity of the 

primary flare. For purposes of this subpart, a secondary flare is characterized by infrequent use 

and must maintain a water seal.

Sour water means water that contains sulfur compounds (usually H2S) at concentrations of 

10 parts per million by weight or more.

Sulfur pit means the storage vessel in which sulfur that is condensed after each Claus catalytic 

reactor is initially accumulated and stored. A sulfur pit does not include secondary sulfur storage 

vessels downstream of the initial Claus reactor sulfur pits. 

Sulfur recovery plant means all process units which recover sulfur from H2S and/or SO2 from a 

common source of sour gas produced at a petroleum refinery. The sulfur recovery plant also 

includes sulfur pits used to store the recovered sulfur product, but it does not include secondary 

sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus 

sulfur recovery plant includes: Reactor furnace and waste heat boiler, catalytic reactors, sulfur 

pits and, if present, oxidation or reduction control systems or incinerator, thermal oxidizer or 

similar combustion device. Multiple sulfur recovery units are a single affected facility only when 

the units share the same source of sour gas. Sulfur recovery plants that receive source gas from 

completely segregated sour gas treatment systems are separate affected facilities. 
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Sweep gas means the gas introduced in a flare gas header system to maintain a constant flow of 

gas to prevent oxygen buildup in the flare header. For flares with no water seals, sweep gas also 

performs the function of preventing oxygen infiltration (backflow) into the flare tip. 

§ 60.102a Emissions limitations. 

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

the emissions limitations in paragraphs (b) through (i) of this section on and after the date on 

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

after achieving the maximum production rate at which the affected facility will be operated or 

180 days after initial startup, whichever comes first. 

(b) An owner or operator subject to the provisions of this subpart shall not discharge or cause the 

discharge into the atmosphere from any FCCU or FCU: 

(1) Particulate matter (PM) in excess of the limits in paragraphs (b)(1)(i), (ii), or (iii) of this 

section. 

(i) 1.0 gram per kilogram per Megagram ((g/kg/Mg)() (1 pound (lb) per 1,000 lb) coke burn-off 

or, if a PM continuous emission monitoring system (CEMS) is used, 0.040 grain per dry standard 

cubic feet (gr/dscf) corrected to 0 percent excess air for each modified or reconstructed FCCU. 

(ii) 0.5 gram per kilogram (g/kg) coke burn-off (0.5 lb PM/1,000 lb coke burn-off) or, if a PM 

CEMS is used, 0.020 gr/dscf corrected to 0 percent excess air for each newly constructed FCCU. 

(iii) 1.0 g/kg/Mg (1 lb/1,000 lb) coke burn-off; or, if a PM CEMS is used, 0.040 grain per dry 

standard cubic feet (gr/dscf) corrected to 0 percent excess air for each affected FCU. 

(2) Nitrogen oxides (NOX) in excess of 80 parts per million by volume (ppmv), dry basis 

corrected to 0 percent excess air, on a 7-day rolling average basis. 

(3) Sulfur dioxide (SO2) in excess of 50 ppmv dry basis corrected to 0 percent excess air, on a 7-

day rolling average basis and 25 ppmv, dry basis corrected to 0 percent excess air, on a 365-day 

rolling average basis. 

(4) Carbon monoxide (CO) in excess of 500 ppmv, dry basis corrected to 0 percent excess air, on 

an hourly average basis. 

(c) The owner or operator of a FCCU or FCU that uses a continuous parameter monitoring 

system (CPMS) according to §60.105a(b)(1) shall comply with the applicable control device 

parameter operating limit in paragraph (c)(1) or (2) of this section. 

(1) If the FCCU or FCU is controlled using an electrostatic precipitator: 

(i) The 3-hour rolling average total power and secondary current to the entire system must not 

fall below the level established during the most recent performance test; and 
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(ii) The daily average exhaust coke burn-off rate must not exceed the level established during the 

most recent performance test. 

(2) If the FCCU or FCU is controlled using a wet scrubber: 

(i) The 3-hour rolling average pressure drop must not fall below the level established during the 

most recent performance test; and 

(ii) The 3-hour rolling average liquid-to-gas ratio must not fall below the level established during 

the most recent performance test. 

(d) If an FCCU or FCU uses a continuous opacity monitoring system (COMS) according to the 

alternative monitoring option in §60.105a(e), the 3-hour rolling average opacity of emissions 

from the FCCU or FCU as measured by the COMS must not exceed the site-specific opacity 

limit established during the most recent performance test. 

(e) The owner or operator of a FCCU or FCU that is exempted from the requirement for a CO 

continuous emissions monitoring system under §60.105a(h)(3) shall comply with the parameter 

operating limits in paragraph (e)(1) or (2) of this section. 

(1) For a FCCU or FCU with no post-combustion control device: 

(i) The hourly average temperature of the exhaust gases exiting the FCCU or FCU must not fall 

below the level established during the most recent performance test. 

(ii) The hourly average oxygen (O2) concentration of the exhaust gases exiting the FCCU or 

FCU must not fall below the level established during the most recent performance test. 

(2) For a FCCU or FCU with a post-combustion control device: 

(i) The hourly average temperature of the exhaust gas vent stream exiting the control device must 

not fall below the level established during the most recent performance test. 

(ii) The hourly average O2 concentration of the exhaust gas vent stream exiting the control 

device must not fall below the level established during the most recent performance test. 

(f) Except as provided in paragraph (f)(3), each owner or operator of an affected sulfur recovery 

plant shall comply with the applicable emission limits in paragraphs (f)(1) or (2) of this section. 

(1) For a sulfur recovery plant with a design production capacity greater than 20 long tons per 

day (LTD), the owner or operator shall comply with the applicable emission limit in 

paragraphs (f)(1)(i) or (f)(1)(ii) of this section. If the sulfur recovery plant consists of 

multiple process trains or release points, the owner or operator shall comply with the 

applicable emission limit for each process train or release point individually or comply with 

the applicable emission limit in paragraphs (f)(1)(i) or (f)(1)(ii) of this section as a flow rate 

weighted average for a group of release points from the sulfur recovery plant provided that 
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flow is monitored as specified in §60.106a(a)(7); if flow is not monitored as specified in 

§60.106a(a)(7), the owner or operator shall comply with the applicable emission limit in 

paragraphs (f)(1)(i) or (f)(1)(ii) of this section for each process train or release point 

individually. For a sulfur recovery plant with a design production capacity greater than 20 

long LTD and a reduction control system not followed by incineration, the owner or 

operator shall also comply with the H2S emission limit in paragraph (f)(1)(iii) of this section 

for each individual release point.:

(i) For a sulfur recovery plant with an oxidation control system or a reduction control system 

followed by incineration, the owner or operator shall not discharge or cause the discharge of any 

gases into the atmosphere (SO2) in excess of the emission limit calculated using Equation 1 of 

this section. For Claus units that use only ambient air in the Claus burner or that elect not 

to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for nonClaus sulfur recovery plants, this SO2 emissions limit is 250 ppm by volume (dry basis) of 

sulfur dioxide (SO2) at zero percent excess air. If the sulfur recovery plant consists of multiple 

process trains or release points the owner or operator shall comply with the 250 ppmv limit for 

each process train or release point or comply with a flow rate weighted average of 250 ppmv for 

all release points from the sulfur recovery plant; or

 0.038   11.53 25.6 2 ELS  k1    %O2  %O2  (Eq. 1) 

Where: 

ELS = Emission limit for large sulfur recovery plant, ppmv (as SO2, dry basis at zero 

percent excess air); 

k1 = Constant factor for emission limit conversion: k1 = 1 for converting to the SO2 limit for 

a sulfur recovery plant with an oxidation control system or a reduction control 

system followed by incineration and k1 = 1.2 for converting to the reduced sulfur 

compounds limit for a sulfur recovery plant with a reduction control system not 

followed by incineration; and 

%O2 = O2 concentration of the air/oxygen mixture supplied to the Claus burner, percent by 

volume (dry basis). If only ambient air is used for the Claus burner or if the owner 

or operator elects not to monitor O2 concentration of the air/oxygen mixture used in 

the Claus burner or for non-Claus sulfur recovery plants, use 20.9% for %O2. 

(ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the 

owner or operator shall not discharge or cause the discharge of any gases into the atmosphere 

containing reduced sulfur compounds in excess of the emission limit calculated using 

Equation 1 of this section. For Claus units that use only ambient air in the Claus burner or 

for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is 300 

ppmv of reduced sulfur compounds and 10 ppmv of H2S, each calculated as ppmv SO2 (dry 

basis) at 0-percent excess air.; or
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(iii) For a sulfur recovery plant with a reduction control system not followed by 

incineration, the owner or operator shall not discharge or cause the discharge of any gases 

into the atmosphere containing hydrogen sulfide (H2S) in excess of 10 ppmv calculated as 

ppmv SO2 (dry basis) at zero percent excess air.For systems using oxygen enrichment, the 

owner or operator shall calculate the applicable emission limit using Equation 1 of this section:

Where: 

ELS = Emission rate of SO2 for large sulfur recovery plant, ppmv; 

k1 = Constant factor for emission limit conversion: k1 = 1 for converting to SO2 limit and k1 = 

1.2 for converting to the reduced sulfur compounds limit; and 

%O2 = O2 concentration to the SRP, percent by volume (dry basis). 

(2) For a sulfur recovery plant with a design production capacity of 20 LTD or less, the owner 

or operator shall comply with the applicable emission limit in paragraphs (f)(2)(i) or 

(f)(2)(ii) of this section. If the sulfur recovery plant consists of multiple process trains or 

release points, the owner or operator may comply with the applicable emission limit for 

each process train or release point individually or comply with the applicable emission 

limit in paragraphs (f)(2)(i) or (f)(2)(ii) of this section as a flow rate weighted average for a 

group of release points from the sulfur recovery plant provided that flow is monitored as 

specified in §60.106a(a)(7); if flow is not monitored as specified in §60.106a(a)(7), the owner 

or operator shall comply with the applicable emission limit in paragraphs (f)(2)(i) or 

(f)(2)(ii) of this section for each process train or release point individually. For a sulfur 

recovery plant with a design production capacity of 20 LTD or less and a reduction control 

system not followed by incineration, the owner or operator shall also comply with the H2S 

emission limit in paragraph (f)(2)(iii) of this section for each individual release point.:

(i) For a sulfur recovery plant with an oxidation control system or a reduction control system 

followed by incineration, the owner or operator shall not discharge or cause the discharge of any 

gases into the atmosphere containing SO2 in excess of the emission limit calculated using 

Equation 2 of this section. For Claus units that use only ambient air in the Claus burner or 

that elect not to monitor O2 concentration of the air/oxygen mixture used in the Claus 

burner or for non-Claus sulfur recovery plants, this SO2 emission limit isin excess of 2,500 

ppmv by volume (dry basis) of SO2 at zero percent excess air. If the sulfur recovery plant 

consists of multiple process trains or release points the owner or operator shall comply with the 

2,500 ppmv limit for each process train or release point or comply with a flow rate weighted 

average of 2,500 ppmv for all release points from the sulfur recovery plant; or

 0.38   115.3 256 2 ESS  k1    %O2  %O2  (Eq. 2) 

Where: 
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ESS = Emission limit for small sulfur recovery plant, ppmv (as SO2, dry basis at zero 

percent excess air); 

k1 = Constant factor for emission limit conversion: k1 = 1 for converting to the SO2 limit for 

a sulfur recovery plant with an oxidation control system or a reduction control 

system followed by incineration and k1 = 1.2 for converting to the reduced sulfur 

compounds limit for a sulfur recovery plant with a reduction control system not 

followed by incineration; and 

%O2 = O2 concentration of the air/oxygen mixture supplied to the Claus burner, percent by 

volume (dry basis). If only ambient air is used in the Claus burner or if the owner or 

operator elects not to monitor O2 concentration of the air/oxygen mixture used in 

the Claus burner or for non-Claus sulfur recovery plants, use 20.9% for %O2. 

(ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the 

owner or operator shall not discharge or cause the discharge of any gases into the atmosphere 

containing reduced sulfur compounds in excess of the emission limit calculated using 

Equation 2 of this section. For Claus units that use only ambient air in the Claus burner or 

for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit isin 

excess of 3,000 ppm by volume of reduced sulfur compounds and 100 ppm by volume of 

hydrogen sulfide (H2S), each calculated as ppmv SO2 by volume (dry basis) at zero percent 

excess air; or.

(iii) For a sulfur recovery plant with a reduction control system not followed by 

incineration, the owner or operator shall not discharge or cause the discharge of any gases 

into the atmosphere containing H2S in excess of 100 ppmv calculated as ppmv SO2 (dry 

basis) at zero percent excess air.For systems using oxygen enrichment, the owner or operator 

shall calculate the applicable emission limit using Equation 2 of this section: 

Where: 

ESS = Emission rate of SO2 for small sulfur recovery plant, ppmv.

(3) The emission limits in paragraphs (f)(1) and (2) shall not apply during pPeriods of 

maintenance of the sulfur pit, during which the emission limits in paragraphs (f)(1) and (2) shall 

not apply, which shall not exceed 240 hours per year. The owner or operator must document the 

time periods during which the sulfur pit vents were not controlled and measures taken to 

minimize emissions during these periods. Examples of these measures include not adding fresh 

sulfur or shutting off vent fans. 

(g) Each owner or operator of an affected fuel gas combustion device shall comply with the 

emissions limits in paragraphs (g)(1) and (2) of this section. 
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(1) Except as provided in (g)(1)(iii) of this section, for each fuel gas combustion device, the 

owner or operator shall comply with either the emission limit in paragraph (g)(1)(i) of this 

section or the fuel gas concentration limit in paragraph (g)(1)(ii) of this section. For CO boilers 

or furnaces that are part of a fluid catalytic cracking unit or fluid coking unit affected 

facility, the owner or operator shall comply with the fuel gas concentration limit in 

paragraph (g)(1)(ii) of this section for all fuel gas streams combusted in these units.

(i) The owner or operator shall not discharge or cause the discharge of any gases into the 

atmosphere that contain SO2 in excess of 20 ppmv (dry basis, corrected to 0-percent excess air) 

determined hourly on a 3-hour rolling average basis and SO2 in excess of 8 ppmv (dry basis, 

corrected to 0-percent excess air), determined daily on a 365 successive calendar day rolling 

average basis; or 

(ii) The owner or operator shall not burn in any fuel gas combustion device any fuel gas that 

contains H2S in excess of 162 ppmv determined hourly on a 3-hour rolling average basis and H2S 

in excess of 60 ppmv determined daily on a 365 successive calendar day rolling average basis. 

(iii) The combustion in a portable generator of fuel gas released as a result of tank degassing 

and/or cleaning is exempt from the emissions limits in paragraphs (g)(1)(i) and (ii) of this 

section. 

(2) For each process heater with a rated capacity of greater than 40 million British thermal units 

per hour (MMBtu/hr) on a higher heating value basis, the owner or operator shall not discharge 

to the atmosphere any emissions of NOX in excess of the applicable limits in paragraphs (g)(2)(i) 

through (iv) of this section. 

(i) For each natural draft process heater, comply with the limit in either paragraph (g)(2)(i)(A) or 

(B) of this section. The owner or operator may comply with either limit at any time, provided 

that the appropriate parameters for each alternative are monitored as specified in §60.107a; if 

fuel gas composition is not monitored as specified in §60.107a(d), the owner or operator must 

comply with the concentration limits in paragraph (g)(2)(i)(A) of this section. 

(A) 40 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30-day rolling 

average basis; or 

(B) 0.040 pounds per million British thermal units (lb/MMBtu) higher heating value basis 

determined daily on a 30-day rolling average basis. 

(ii) For each forced draft process heater, comply with the limit in either paragraph (g)(2)(ii)(A) 

or (B) of this section. The owner or operator may comply with either limit at any time, provided 

that the appropriate parameters for each alternative are monitored as specified in §60.107a; if 

fuel gas composition is not monitored as specified in §60.107a(d), the owner or operator must 

comply with the concentration limits in paragraph (g)(2)(ii)(A) of this section. 

(A) 60 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30-day rolling 

average basis; or 
13 

(B) 0.060 lb/MMBtu higher heating value basis determined daily on a 30-day rolling average 

basis. 

(iii) For each co-fired natural draft process heater, comply with the limit in either paragraph 

(g)(2)(iii)(A) or (B) of this section. The owner or operator must choose one of the emissions 

limits with which to comply at all times: 

(A) 150 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30 successive 

operating day rolling average basis; or 

(B) The daily average emissions limit calculated using Equation 3 of this section: 

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER



  0.06 0.35

 (Eq. 3) 

Where: 

ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu (higher heating value basis); 

Qgas = Daily average volumetric flow rate of fuel gas, standard cubic feet per day (scf/day); 

Qoil = Daily average volumetric flow rate of fuel oil, scf/day; 

HHVgas = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and 

HHVoil = Daily average higher heating value of fuel oil fired to the process heater, MMBtu/scf. 

(iv) For each co-fired forced draft process heater, comply with the limit in either paragraph 

(g)(2)(iv)(A) or (B) of this section. The owner or operator must choose one of the emissions 

limits with which to comply at all times: 

(A) 150 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30 successive 

operating day rolling average basis; or 

(B) The daily average emissions limit calculated using Equation 4 of this section: 

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER



  0.11 0.40

 (Eq. 4) 

Where: 

ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu (higher heating value basis); 

Qgas = Daily average volumetric flow rate of fuel gas, scf/day; 
14 

Qoil = Daily average volumetric flow rate of fuel oil, scf/day; 

HHVgas = Daily average higher heating value of gas fired to the process heater, MMBtu/scf; and 

HHVoil = Daily average higher heating value of fuel oil fired to the process heater, MMBtu/scf. 

(h) [Reserved] 

(i) For a process heater that meets any of the criteria of paragraphs (i)(1)(i) through (iv) of this 

section, an owner or operator may request approval from the Administrator for a NOX emissions 

limit which shall apply specifically to that affected facility. The request shall include information 

as described in paragraph (i)(2) of this section. The request shall be submitted and followed as 

described in paragraph (i)(3) of this section. 

(1) A process heater that meets one of the criteria in paragraphs (i)(1)(i) through (iv) of this 

section may apply for a site-specific NOX emissions limit: 

(i) A modified or reconstructed process heater that lacks sufficient space to accommodate 

installation and proper operation of combustion modification-based technology (e.g., ultra-low 

NOX burners); or 

(ii) A modified or reconstructed process heater that has downwardly firing induced draft burners; 

or 

(iii) A co-fired process heater; or 

(iv) A process heater operating at reduced firing conditions for an extended period of time (i.e., 

operating in turndown mode). The site-specific NOX emissions limit will only apply for those 

operating conditions. 

(2) The request shall include sufficient and appropriate data, as determined by the Administrator, 

to allow the Administrator to confirm that the process heater is unable to comply with the 

applicable NOX emissions limit in paragraph (g)(2) of this section. At a minimum, the request 

shall contain the information described in paragraphs (i)(2)(i) through (iv) of this section. 

(i) The design and dimensions of the process heater, evaluation of available combustion 

modification-based technology, description of fuel gas and, if applicable, fuel oil characteristics, 

information regarding the combustion conditions (temperature, oxygen content, firing rates) and 

other information needed to demonstrate that the process heater meets one of the four classes of 

process heaters listed in paragraph (i)(1) of this section. 

(ii) An explanation of how the data in paragraph (i)(2)(i) demonstrate that ultra-low NOX

burners, flue gas recirculation, control of excess air or other combustion modification-based 

technology (including combinations of these combustion modification-based technologies) 

cannot be used to meet the applicable emissions limit in paragraph (g)(2) of this section. 
15 

(iii) Results of a performance test conducted under representative conditions using the applicable 

methods specified in §60.104a(i) to demonstrate the performance of the technology the owner or 

operator will use to minimize NOX emissions. 

(iv) The means by which the owner or operator will document continuous compliance with the 

site-specific emissions limit. 

(3) The request shall be submitted and followed as described in paragraphs (i)(3)(i) through (iii) 

of this section. 

(i) The owner or operator of a process heater that meets one of the criteria in paragraphs (i)(1)(i) 

through (iv) of this section may request approval from the Administrator within 180 days after 

initial startup of the process heater for a NOX emissions limit which shall apply specifically to 

that affected facility. 

(ii) The request must be submitted to the Administrator for approval. The owner or operator must 

comply with the request as submitted until it is approved. 

(iii) The request shall also be submitted to the following address: U.S. Environmental Protection 

Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, 

U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, 

Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be 

submitted to refinerynsps@epa.gov. 

(4) The approval process for a request for a facility-specific NOX emissions limit is described in 

paragraphs (i)(4)(i) through (iii) of this section. 

(i) Approval by the Administrator of a facility-specific NOX emissions limit request will be 

based on the completeness, accuracy and reasonableness of the request. Factors that the EPA will 

consider in reviewing the request for approval include, but are not limited to, the following: 

(A) A demonstration that the process heater meets one of the four classes of process heaters 

outlined in paragraphs (i)(1) of this section; 

(B) A description of the low-NOX burner designs and other combustion modifications considered 

for reducing NOX emissions; 

(C) The combustion modification option selected; and 

(D) The operating conditions (firing rate, heater box temperature and excess oxygen 

concentration) at which the NOX emission level was established. 

(ii) If the request is approved by the Administrator, a facility-specific NOX emissions limit will 

be established at the NOX emission level demonstrated in the approved request. 
16 

(iii) If the Administrator finds any deficiencies in the request, the request must be revised to 

address the deficiencies and be re-submitted for approval. 

§ 60.103a Design, equipment, work practice or operational standards. 

(a) Except as provided in paragraph (g) of this section, each owner or operator that operates a 

flare that is subject to this subpart shall develop and implement a written flare management plan 

no later than the date specified in paragraph (b) of this section. The flare management plan must 

include the information described in paragraphs (a)(1) through (7) of this section. 

(1) A listing of all refinery process units, ancillary equipment, and fuel gas systems connected to 

the flare for each affected flare. 

(2) An assessment of whether discharges to affected flares from these process units, ancillary 

equipment and fuel gas systems can be minimized. The flare minimization assessment must (at a 

minimum) consider the items in paragraphs (a)(2)(i) through (iv) of this section. The assessment 

must provide clear rationale in terms of costs (capital and annual operating), natural gas offset 

credits (if applicable), technical feasibility, secondary environmental impacts and safety 

considerations for the selected minimization alternative(s) or a statement, with justifications, that 

flow reduction could not be achieved. Based upon the assessment, each owner or operator of an 

affected flare shall identify the minimization alternatives that it has implemented by the due date 

of the flare management plan and shall include a schedule for the prompt implementation of any 

selected measures that cannot reasonably be completed as of that date. 

(i) Elimination of process gas discharge to the flare through process operating changes or gas 

recovery at the source. 

(ii) Reduction of the volume of process gas to the flare through process operating changes. 

(iii) Installation of a flare gas recovery system or, for facilities that are fuel gas rich, a flare gas 

recovery system and a co-generation unit or combined heat and power unit. 

(iv) Minimization of sweep gas flow rates and, for flares with water seals, purge gas flow rates. 

(3) A description of each affected flare containing the information in paragraphs (a)(3)(i) through 

(vii) of this section. 

(i) A general description of the flare, including the information in paragraphs (a)(3)(i)(A) 

through (G) of this section. 

(A) Whether it is a ground flare or elevated (including height). 

(B) The type of assist system (e.g., air, steam, pressure, non-assisted). 

(C) Whether it is simple or complex flare tip (e.g., staged, sequential). 
17 

(D) Whether the flare is part of a cascaded flare system (and if so, whether the flare is primary or 

secondary). 

(E) Whether the flare serves as a backup to another flare. 

(F) Whether the flare is an emergency flare or a non-emergency flare. 

(G) Whether the flare is equipped with a flare gas recovery system. 

(ii) Description and simple process flow diagram showing the interconnection of the following 

components of the flare: flare tip (date installed, manufacturer, nominal and effective tip 

diameter, tip drawing); knockout or surge drum(s) or pot(s) (including dimensions and design 

capacities); flare header(s) and subheader(s); assist system; and ignition system. 

(iii) Flare design parameters, including the maximum vent gas flow rate; minimum sweep gas 

flow rate; minimum purge gas flow rate (if any); maximum supplemental gas flow rate; 

maximum pilot gas flow rate; and, if the flare is steam-assisted, minimum total steam rate. 

(iv) Description and simple process flow diagram showing all gas lines (including flare, purge (if 

applicable), sweep, supplemental and pilot gas) that are associated with the flare. For purge, 

sweep, supplemental and pilot gas, identify the type of gas used. Designate which lines are 

exempt from sulfur, H2S or flow monitoring and why (e.g., natural gas, inherently low sulfur, 

pilot gas). Designate which lines are monitored and identify on the process flow diagram the 

location and type of each monitor. 

(v) For each flow rate, H2S, sulfur content, pressure or water seal monitor identified in paragraph 

(a)(3)(iv) of this section, provide a detailed description of the manufacturer's specifications, 

including, but not limited to, make, model, type, range, precision, accuracy, calibration, 

maintenance and quality assurance procedures. 

(vi) For emergency flares, secondary flares and flares equipped with a flare gas recovery system 

designed, sized and operated to capture all flows except those resulting from startup, shutdown 

or malfunction: 

(A) Description of the water seal, including the operating range for the liquid level. 

(B) Designation of the monitoring option elected (flow and sulfur monitoring or pressure and 

water seal liquid level monitoring). 

(vii) For flares equipped with a flare gas recovery system: 

(A) A description of the flare gas recovery system, including number of compressors and 

capacity of each compressor. 

(B) A description of the monitoring parameters used to quantify the amount of flare gas 

recovered. 
18 

(C) For systems with staged compressors, the maximum time period required to begin gas 

recovery with the secondary compressor(s), the monitoring parameters and procedures used to 

minimize the duration of releases during compressor staging and a justification for why the 

maximum time period cannot be further reduced. 

(4) An evaluation of the baseline flow to the flare. The baseline flow to the flare must be 

determined after implementing the minimization assessment in paragraph (a)(2) of this section. 

Baseline flows do not include pilot gas flow or purge gas flow (i.e., gas introduced after the 

flare's water seal) provided these gas flows remain reasonably constant (i.e., separate flow 

monitors for these streams are not required). Separate baseline flow rates may be established for 

different operating conditions provided that the management plan includes: 

(i) A primary baseline flow rate that will be used as the default baseline for all conditions except 

those specifically delineated in the plan; 

(ii) A description of each special condition for which an alternate baseline is established, 

including the rationale for each alternate baseline, the daily flow for each alternate baseline and 

the expected duration of the special conditions for each alternate baseline; and 

(iii) Procedures to minimize discharges to the affected flare during each special condition 

described in paragraph (a)(4)(ii) of this section, unless procedures are already developed for 

these cases under paragraph (a)(5) through (7) of this section, as applicable. 

(5) Procedures to minimize or eliminate discharges to the flare during the planned startup and 

shutdown of the refinery process units and ancillary equipment that are connected to the affected 

flare, together with a schedule for the prompt implementation of any procedures that cannot 

reasonably be implemented as of the date of the submission of the flare management plan. 

(6) Procedures to reduce flaring in cases of fuel gas imbalance (i.e., excess fuel gas for the 

refinery's energy needs), together with a schedule for the prompt implementation of any 

procedures that cannot reasonably be implemented as of the date of the submission of the flare 

management plan. 

(7) For flares equipped with flare gas recovery systems, procedures to minimize the frequency 

and duration of outages of the flare gas recovery system and procedures to minimize the volume 

of gas flared during such outages, together with a schedule for the prompt implementation of any 

procedures that cannot reasonably be implemented as of the date of the submission of the flare 

management plan. 

(b) Except as provided in paragraph (g) of this section, each owner or operator required to 

develop and implement a written flare management plan as described in paragraph (a) of this 

section must submit the plan to the Administrator as described in paragraphs (b)(1) through (3) 

of this section. 

(1) The owner or operator of a newly constructed or reconstructed flare must develop and 

implement the flare management plan by no later than the date that the flare becomes an affected 
19 

facility subject to this subpart, except for the selected minimization alternatives in paragraph 

(a)(2) and/or the procedures in paragraphs (a)(5) though (a)(7) of this section that cannot 

reasonably be implemented by that date, which the owner or operator must implement in 

accordance with the schedule in the flare management plan. The owner or operator of a modified 

flare must develop and implement the flare management plan by no later than November 11, 

2015 or upon startup of the modified flare, whichever is later. 

(2) The owner or operator must comply with the plan as submitted by the date specified in 

paragraph (b)(1) of this section. The plan should be updated periodically to account for changes 

in the operation of the flare, such as new connections to the flare or the installation of a flare gas 

recovery system, but the plan need be re-submitted to the Administrator only if the owner or 

operator adds an alternative baseline flow rate, revises an existing baseline as described in 

paragraph (a)(4) of this section, installs a flare gas recovery system or is required to change flare 

designations and monitoring methods as described in §60.107a(g). The owner or operator must 

comply with the updated plan as submitted. 

(3) All versions of the plan submitted to the Administrator shall also be submitted to the 

following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and 

Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: 

Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic 

copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov. 

(c) Except as provided in paragraphs (f) and (g) of this section, each owner or operator that 

operates a fuel gas combustion device, flare or sulfur recovery plant subject to this subpart shall 

conduct a root cause analysis and a corrective action analysis for each of the conditions specified 

in paragraphs (c)(1) through (3) of this section. 

(1) For a flare: 

(i) Any time the SO2 emissions exceed 227 kilograms (kg) (500 lb) in any 24-hour period; or 

(ii) Any discharge to the flare in excess of 14,160 standard cubic meters (m3

) (500,000 standard 

cubic feet (scf)) above the baseline, determined in paragraph (a)(4) of this section, in any 24-

hour period; or 

(iii) If the monitoring alternative in §60.107a(g) is elected, any period when the flare gas line 

pressure exceeds the water seal liquid depth, except for periods attributable to compressor 

staging that do not exceed the staging time specified in paragraph (a)(3)(vii)(C) of this section. 

(2) For a fuel gas combustion device, each exceedance of an applicable short-term emissions 

limit in §60.102a(g)(1) if the SO2 discharge to the atmosphere is 227 kg (500 lb) greater than the 

amount that would have been emitted if the emissions limits had been met during one or more 

consecutive periods of excess emissions or any 24-hour period, whichever is shorter. 

(3) For a sulfur recovery plant, each time the SO2 emissions are more than 227 kg (500 lb) 

greater than the amount that would have been emitted if the SO2 or reduced sulfur concentration 
20 

was equal to the applicable emissions limit in §60.102a(f)(1) or (2) during one or more 

consecutive periods of excess emissions or any 24-hour period, whichever is shorter. 

(d) Except as provided in paragraphs (f) and (g) of this section, a root cause analysis and 

corrective action analysis must be completed as soon as possible, but no later than 45 days after a 

discharge meeting one of the conditions specified in paragraphs (c)(1) through (3) of this section. 

Special circumstances affecting the number of root cause analyses and/or corrective action 

analyses are provided in paragraphs (d)(1) through (5) of this section. 

(1) If a single continuous discharge meets any of the conditions specified in paragraphs (c)(1) 

through (3) of this section for 2 or more consecutive 24-hour periods, a single root cause analysis 

and corrective action analysis may be conducted. 

(2) If a single discharge from a flare triggers a root cause analysis based on more than one of the 

conditions specified in paragraphs (c)(1)(i) through (iii) of this section, a single root cause 

analysis and corrective action analysis may be conducted. 

(3) If the discharge from a flare is the result of a planned startup or shutdown of a refinery 

process unit or ancillary equipment connected to the affected flare and the procedures in 

paragraph (a)(5) of this section were followed, a root cause analysis and corrective action 

analysis is not required; however, the discharge must be recorded as described in §60.108a(c)(6) 

and reported as described in §60.108a(d)(5). 

(4) If both the primary and secondary flare in a cascaded flare system meet any of the conditions 

specified in paragraphs (c)(1)(i) through (iii) of this section in the same 24-hour period, a single 

root cause analysis and corrective action analysis may be conducted. 

(5) Except as provided in paragraph (d)(4) of this section, if discharges occur that meet any of 

the conditions specified in paragraphs (c)(1) through (3) of this section for more than one 

affected facility in the same 24-hour period, initial root cause analyses shall be conducted for 

each affected facility. If the initial root cause analyses indicate that the discharges have the same 

root cause(s), the initial root cause analyses can be recorded as a single root cause analysis and a 

single corrective action analysis may be conducted. 

(e) Except as provided in paragraphs (f) and (g) of this section, each owner or operator of a fuel 

gas combustion device, flare or sulfur recovery plant subject to this subpart shall implement the 

corrective action(s) identified in the corrective action analysis conducted pursuant to paragraph 

(d) of this section in accordance with the applicable requirements in paragraphs (e)(1) through 

(3) of this section. 

(1) All corrective action(s) must be implemented within 45 days of the discharge for which the 

root cause and corrective action analyses were required or as soon thereafter as practicable. If an 

owner or operator concludes that corrective action should not be conducted, the owner or 

operator shall record and explain the basis for that conclusion no later than 45 days following the 

discharge as specified in §60.108a(c)(6)(ix). 
21 

(2) For corrective actions that cannot be fully implemented within 45 days following the 

discharge for which the root cause and corrective action analyses were required, the owner or 

operator shall develop an implementation schedule to complete the corrective action(s) as soon 

as practicable. 

(3) No later than 45 days following the discharge for which a root cause and corrective action 

analyses were required, the owner or operator shall record the corrective action(s) completed to 

date, and, for action(s) not already completed, a schedule for implementation, including proposed 

commencement and completion dates as specified in §60.108a(c)(6)(x). 

(f) Modified flares shall comply with the requirements of paragraphs (c) through (e) of this 

section by November 11, 2015 or at startup of the modified flare, whichever is later. Modified 

flares that were not affected facilities subject to subpart J of this part prior to becoming affected 

facilities under §60.100a shall comply with the requirements of paragraph (h) of this section and 

the requirements of §60.107a(a)(2) by November 11, 2015 or at startup of the modified flare, 

whichever is later. Modified flares that were affected facilities subject to subpart J of this part 

prior to becoming affected facilities under §60.100a shall comply with the requirements of 

paragraph (h) of this section and the requirements of §60.107a(a)(2) by November 13, 2012 or at 

startup of the modified flare, whichever is later, except that modified flares that have accepted 

applicability of subpart J under a federal consent decree shall comply with the subpart J 

requirements as specified in the consent decree, but shall comply with the requirements of 

paragraph (h) of this section and the requirements of §60.107a(a)(2) by no later than November 

11, 2015. 

(g) An affected flare subject to this subpart located in the Bay Area Air Quality Management 

District (BAAQMD) may elect to comply with both BAAQMD Regulation 12, Rule 11 and 

BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of 

paragraphs (a) through (e) of this section. An affected flare subject to this subpart located in the 

South Coast Air Quality Management District (SCAQMD) may elect to comply with SCAQMD 

Rule 1118 as an alternative to complying with the requirements of paragraphs (a) through (e) of 

this section. The owner or operator of an affected flare must notify the Administrator that the 

flare is in compliance with BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, 

Rule 12 or SCAQMD Rule 1118. The owner or operator of an affected flare shall also submit the 

existing flare management plan to the following address: U.S. Environmental Protection Agency, 

Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA 

Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research 

Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to 

refinerynsps@epa.gov. 

(h) Each owner or operator shall not burn in any affected flare any fuel gas that contains H2S in 

excess of 162 ppmv determined hourly on a 3-hour rolling average basis. The combustion in a 

flare of process upset gases or fuel gas that is released to the flare as a result of relief valve 

leakage or other emergency malfunctions is exempt from this limit. 

(i) Each owner or operator of a delayed coking unit shall depressure each coke drum to 5 lb per 

square inch gauge (psig) or less prior to discharging the coke drum steam exhaust to the 
22 

atmosphere. Until the coke drum pressure reaches 5 psig, the coke drum steam exhaust must be 

managed in an enclosed blowdown system and the uncondensed vapor must either be recovered 

(e.g., sent to the delayed coking unit fractionators) or vented to the fuel gas system, a fuel gas 

combustion device or a flare. 

(j) Alternative means of emission limitation. (1) Each owner or operator subject to the provisions 

of this section may apply to the Administrator for a determination of equivalence for any means 

of emission limitation that achieves a reduction in emissions of a specified pollutant at least 

equivalent to the reduction in emissions of that pollutant achieved by the controls required in this 

section. 

(2) Determination of equivalence to the design, equipment, work practice or operational 

requirements of this section will be evaluated by the following guidelines: 

(i) Each owner or operator applying for a determination of equivalence shall be responsible for 

collecting and verifying test data to demonstrate the equivalence of the alternative means of 

emission limitation. 

(ii) For each affected facility for which a determination of equivalence is requested, the emission 

reduction achieved by the design, equipment, work practice or operational requirements shall be 

demonstrated. 

(iii) For each affected facility for which a determination of equivalence is requested, the 

emission reduction achieved by the alternative means of emission limitation shall be 

demonstrated. 

(iv) Each owner or operator applying for a determination of equivalence to a work practice 

standard shall commit in writing to work practice(s) that provide for emission reductions equal to 

or greater than the emission reductions achieved by the required work practice. 

(v) The Administrator will compare the demonstrated emission reduction for the alternative 

means of emission limitation to the demonstrated emission reduction for the design, equipment, 

work practice or operational requirements and, if applicable, will consider the commitment in 

paragraph (j)(2)(iv) of this section. 

(vi) The Administrator may condition the approval of the alternative means of emission 

limitation on requirements that may be necessary to ensure operation and maintenance to achieve 

the same emissions reduction as the design, equipment, work practice or operational 

requirements. 

(3) An owner or operator may offer a unique approach to demonstrate the equivalence of any 

equivalent means of emission limitation. 

(4) Approval of the application for equivalence to the design, equipment, work practice or 

operational requirements of this section will be evaluated by the following guidelines: 
23 

(i) After a request for determination of equivalence is received, the Administrator will publish a 

notice in the FEDERAL REGISTER and provide the opportunity for public hearing if the 

Administrator judges that the request may be approved. 

(ii) After notice and opportunity for public hearing, the Administrator will determine the 

equivalence of a means of emission limitation and will publish the determination in the FEDERAL 

REGISTER. 

(iii) Any equivalent means of emission limitations approved under this section shall constitute a 

required work practice, equipment, design or operational standard within the meaning of section 

111(h)(1) of the CAA. 

(5) Manufacturers of equipment used to control emissions may apply to the Administrator for 

determination of equivalence for any alternative means of emission limitation that achieves a 

reduction in emissions achieved by the equipment, design and operational requirements of this 

section. The Administrator will make an equivalence determination according to the provisions 

of paragraphs (j)(2) through (4) of this section. 

§ 60.104a Performance tests. 

(a) The owner or operator shall conduct a performance test for each FCCU, FCU, sulfur recovery 

plant, flare and fuel gas combustion device to demonstrate initial compliance with each 

applicable emissions limit in §60.102a and conduct a performance test for each flare to 

demonstrate initial compliance with the H2S concentration requirement in §60.103a(h) 

according to the requirements of §60.8. The notification requirements of §60.8(d) apply to the 

initial performance test and to subsequent performance tests required by paragraph (b) of this 

section (or as required by the Administrator), but does not apply to performance tests conducted 

for the purpose of obtaining supplemental data because of continuous monitoring system 

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

(b) The owner or operator of a FCCU or FCU that elects to monitor control device operating 

parameters according to the requirements in §60.105a(b), to use bag leak detectors according to 

the requirements in §60.105a(c), or to use COMS according to the requirements in §60.105a(e) 

shall conduct a PM performance test at least once every 12 monthsannually (i.e., once per 

calendar year, with an interval of at least 8 months but no more than 16 months between 

annual tests) and furnish the Administrator a written report of the results of each test. 

(c) In conducting the performance tests required by this subpart (or as requested by the 

Administrator), the owner or operator shall use the test methods in 40 CFR part 60, Appendices 

A-1 through A-8 or other methods as specified in this section, except as provided in §60.8(b). 

(d) The owner or operator shall determine compliance with the PM, NOX, SO2, and CO 

emissions limits in §60.102a(b) for FCCU and FCU using the following methods and 

procedures: 

(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses. 
24 

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate. 

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME 

PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is 

an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. 

(4) Method 5, 5B, or 5F of appendix A-3 to part 60 for determining PM emissions and associated 

moisture content from a FCCU or FCU without a wet scrubber subject to the emissions limit in 

§63.102a(b)(1). Use Method 5 or 5B of appendix A-3 to part 60 for determining PM emissions 

and associated moisture content from a FCCU or FCU with a wet scrubber subject to the 

emissions limit in §63.102a(b)(1). 

(i) The PM performance test consists of 3 valid test runs; the duration of each test run must be no 

less than 60 minutes. 

(ii) The emissions rate of PM (EPM) is computed for each run using Equation 5 of this section: 

c

s sd

KR

c Q E  (Eq. 5) 

Where: 

E = Emission rate of PM, g/kg (lb/1,000 lb) of coke burn-off; 

cs = Concentration of total PM, grams per dry standard cubic meter (g/dscm) (gr/dscf); 

Qsd = Volumetric flow rate of effluent gas, dry standard cubic meters per hour (dry standard 

cubic feet per hour); 

Rc = Coke burn-off rate, kilograms per hour (kg/hr) [lb per hour (lb/hr)] coke; and 

K = Conversion factor, 1.0 grams per gram (7,000 grains per lb). 

(iii) The coke burn-off rate (Rc) is computed for each run using Equation 6 of this section: 

      c 1 r 2 2 a 3 r %CO2 %O2 K3Qoxy %Ooxy R  K Q %CO  %CO  K Q  K Q %CO    2 (Eq. 6) 

Where: 

Rc = Coke burn-off rate, kg/hr (lb/hr); 

Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before 

any emissions control or energy recovery system that burns auxiliary fuel, dry standard 

cubic meters per minute (dscm/min) [dry standard cubic feet per minute (dscf/min)]; 
25 

Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from 

the unit's control room instrumentation, dscm/min (dscf/min); 

Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as 

determined from the unit's control room instrumentation, dscm/min (dscf/min); 

%CO2 = Carbon dioxide (CO2) concentration in FCCU regenerator or fluid coking burner 

exhaust, percent by volume (dry basis); 

%CO = CO concentration in FCCU regenerator or fluid coking burner exhaust, percent by 

volume (dry basis); 

%O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume 

(dry basis); 

%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking 

burner, percent by volume (dry basis); 

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

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

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

(iv) During the performance test, the volumetric flow rate of exhaust gas from catalyst 

regenerator (Qr) before any emission control or energy recovery system that burns auxiliary fuel 

is measured using Method 2 of appendix A-1 to part 60. 

(v) For subsequent calculations of coke burn-off rates or exhaust gas flow rates, the volumetric 

flow rate of Qr is calculated using average exhaust gas concentrations as measured by the 

monitors required in §60.105a(b)(2), if applicable, using Equation 7 of this section: 

 

2 2

a xy oxy

r %CO %CO %O

Q %O Q Q        10079 100

 (Eq. 7) 

Where: 

Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before 

any emission control or energy recovery system that burns auxiliary fuel, dscm/min 

(dscf/min); 
26 

Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from 

the unit's control room instrumentation, dscm/min (dscf/min); 

Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as 

determined from the unit's control room instrumentation, dscm/min (dscf/min); 

%CO2 = Carbon dioxide concentration in FCCU regenerator or fluid coking burner exhaust, 

percent by volume (dry basis); 

%CO = CO concentration FCCU regenerator or fluid coking burner exhaust, percent by volume 

(dry basis). When no auxiliary fuel is burned and a continuous CO monitor is not 

required in accordance with §60.105a(h)(3), assume %CO to be zero; 

%O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume 

(dry basis); and 

%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking 

burner, percent by volume (dry basis). 

(5) Method 6, 6A, or 6C of appendix A-4 to part 60 for moisture content and for the 

concentration of SO2; the duration of each test run must be no less than 4 hours. The method 

ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—

see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. 

(6) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the 

concentration of NOX calculated as nitrogen dioxide (NO2); the duration of each test run must be 

no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 

7 or 7C of appendix A-4 to part 60. 

(7) Method 10, 10A, or 10B of appendix A-4 to part 60 for moisture content and for the 

concentration of CO. The sampling time for each run must be 60 minutes. 

(8) The owner or operator shall adjust PM, NOX, SO2 and CO pollutant concentrations to 0-

percent excess air or 0-percent O2 using Equation 8 of this section: 

 

    2

c adj meas %O C C 20.9

20.9 (Eq. 8) 

Where: 

Cadj = pollutant concentration adjusted to 0-percent excess air or O2, parts per million (ppm) or 

g/dscm; 

Cmeas = pollutant concentration measured on a dry basis, ppm or g/dscm; 
27 

20.9c = 20.9 percent O2 −0.0 percent O2 (defined O2 correction basis), percent; 

20.9 = O2 concentration in air, percent; and 

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

(e) The owner or operator of a FCCU or FCU that is controlled by an electrostatic precipitator or 

wet scrubber and that is subject to control device operating parameter limits in §60.102a(c) shall 

establish the limits based on the performance test results according to the following procedures: 

(1) Reduce the parameter monitoring data to hourly averages for each test run; 

(2) Determine the hourly average operating limit for each required parameter as the average of 

the three test runs. 

(f) The owner or operator of an FCCU or FCU that uses cyclones to comply with the PM per 

coke burn-off emissions limit in §60.102a(b)(1) and elects to comply with the COMS 

alternative monitoring option in §60.105a(d) shall establish a site-specific opacity operating limit 

according to the procedures in paragraphs (f)(1) through (3) of this section. 

(1) Collect COMS data every 10 seconds during the entire period of the PM performance test and 

reduce the data to 6-minute averages. 

(2) Determine and record the hourly average opacity from all the 6-minute averages. 

(3) Compute the site-specific limit using Equation 9 of this section: 















  

st

st PMEmR Opacity Li mit Opacity 1lb / 1,000 lb coke burn (Eq. 9) 

Where: 

Opacity limit = Maximum permissible 3-hour average opacity, percent, or 10 percent, whichever 

is greater; 

Opacityst = Hourly average opacity measured during the source test, percent; and 

PMEmRst = PM emission rate measured during the source test, lb/1,000 lb coke burn. 

(g) The owner or operator of a FCCU or FCU that is exempt from the requirement to install and 

operate a CO CEMS pursuant to §60.105a(h)(3) and that is subject to control device operating 

parameter limits in §60.102a(c) shall establish the limits based on the performance test results 

using the procedures in paragraphs (g)(1) and (2) of this section. 

(1) Reduce the temperature and O2 concentrations from the parameter monitoring systems to 

hourly averages for each test run. 
28 

(2) Determine the operating limit for temperature and O2 concentrations as the average of the 

average temperature and O2 concentration for the three test runs. 

(h) The owner or operator shall determine compliance with the SO2 and H2S emissions limits for 

sulfur recovery plants in §§60.102a(f)(1)(i), 60.102a(f)(1)(iii), 60.102a(f)(1)(iii), and

60.102a(f)(2)(i), and 60.102a(f)(2)(iii) and the reduced sulfur compounds and H2S emissions 

limits for sulfur recovery plants in §§§60.102a(f)(1)(ii), 60.102a(f)(1)(iii), 60.102a(f)(2)(ii) and 

§60.102a(f)(2)(iii) using the following methods and procedures: 

(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses. 

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate. 

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME 

PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is 

an acceptable alternative to EPA Method 3B of appendix A-2 to part 60. 

(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 concentration. The 

method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to 

part 60. 

(5) Method 15 or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 to 

determine the reduced sulfur compounds and H2S concentrations. The method ANSI/ASME PTC 

19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an 

acceptable alternative to EPA Method 15A of appendix A-5 to part 60. 

(i) Each run consists of 16 samples taken over a minimum of 3 hours. 

(ii) The owner or operator shall calculate the average H2S concentration after correcting for 

moisture and O2 as the arithmetic average of the H2S concentration for each sample during the 

run (ppmv, dry basis, corrected to 0 percent excess air). 

(iii) The owner or operator shall calculate the SO2 equivalent for each run after correcting for 

moisture and O2 as the arithmetic average of the SO2 equivalent of reduced sulfur compounds for 

each sample during the run (ppmv, dry basis, corrected to 0 percent excess air). 

(iv) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations 

to 0-percent O2 or 0- percent excess air. 

(6) If oxygen or oxygen enriched air is used in the Claus burner and either Equation 1 or 2 

of this subpart is used to determine the applicable emissions limit, determine the average 

O2 concentration of the air/oxygen mixture supplied to the Claus burner, in percent by 

volume (dry basis), for the performance test using all hourly average O2 concentrations 

determined during the test runs using the procedures in §60.106a(a)(5) or (6). 
29 

(i) The owner or operator shall determine compliance with the SO2 and NOX emissions limits in 

§60.102a(g) for a fuel gas combustion device according to the following test methods and 

procedures: 

(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses; 

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate; 

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME 

PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is 

an acceptable alternative to EPA Method 3B of appendix A-2 to part 60; 

(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 concentration. The 

method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to 

part 60. 

(i) The performance test consists of 3 valid test runs; the duration of each test run must be no less 

than 1 hour. 

(ii) If a single fuel gas combustion device having a common source of fuel gas is monitored as 

allowed under §60.107a(a)(1)(v), only one performance test is required. That is, performance 

tests are not required when a new affected fuel gas combustion device is added to a common 

source of fuel gas that previously demonstrated compliance. 

(5) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the 

concentration of NOX calculated as NO2; the duration of each test run must be no less than 4 

hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” 

(incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 7 or 7C of 

appendix A-4 to part 60. 

(6) For process heaters with a rated heat capacity between 40 and 100 MMBtu/hr that elect to 

demonstrate continuous compliance with a maximum excess oxygen limit as provided in 

§60.107a(c)(6) or (d)(8), the owner or operator shall establish the O2 operating limit or O2

operating curve based on the performance test results according to the requirements in paragraph 

(i)(6)(i) or (ii) of this section, respectively. 

(i) If a single O2 operating limit will be used: 

(A) Conduct the performance test following the methods provided in paragraphs (i)(1), (2), (3) 

and (5) of this section when the process heater is firing at no less than 70 percent of the rated 

heat capacity. For co-fired process heaters, conduct at least one of the test runs while the process 

heater is being supplied by both fuel gas and fuel oil and conduct at least one of the test runs 

while the process heater is being supplied solely by fuel gas. 
30 

(B) Each test will consist of three test runs. Calculate the NOX concentration for the performance 

test as the average of the NOX concentrations from each of the three test runs. If the NOX

concentration for the performance test is less than or equal to the numerical value of the 

applicable NOX emissions limit (regardless of averaging time), then the test is considered to be a 

valid test. 

(C) Determine the average O2 concentration for each test run of a valid test. 

(D) Calculate the O2 operating limit as the average O2 concentration of the three test runs from a 

valid test. 

(ii) If an O2 operating curve will be used: 

(A) Conduct a performance test following the methods provided in paragraphs (i)(1), (2), (3) and 

(5) of this section at a representative condition for each operating range for which different O2

operating limits will be established. Different operating conditions may be defined as different 

firing rates (e.g., above 50 percent of rated heat capacity and at or below 50 percent of rated heat 

capacity) and/or, for co-fired process heaters, different fuel mixtures (e.g., primarily gas fired, 

primarily oil fired, and equally co-fired, i.e., approximately 50 percent of the input heating value 

is from fuel gas and approximately 50 percent of the input heating value is from fuel oil). 

Performance tests for different operating ranges may be conducted at different times. 

(B) Each test will consist of three test runs. Calculate the NOX concentration for the performance 

test as the average of the NOX concentrations from each of the three test runs. If the NOX

concentration for the performance test is less than or equal to the numerical value of the 

applicable NOX emissions limit (regardless of averaging time), then the test is considered to be a 

valid test. 

(C) If an operating curve is developed for different firing rates, conduct at least one test when the 

process heater is firing at no less than 70 percent of the rated heat capacity and at least one test 

under turndown conditions (i.e., when the process heater is firing at 50 percent or less of the 

rated heat capacity). If O2 operating limits are developed for co-fired process heaters based only 

on overall firing rates (and not by fuel mixtures), conduct at least one of the test runs for each 

test while the process heater is being supplied by both fuel gas and fuel oil and conduct at least 

one of the test runs while the process heater is being supplied solely by fuel gas. 

(D) Determine the average O2 concentration for each test run of a valid test. 

(E) Calculate the O2 operating limit for each operating range as the average O2 concentration of 

the three test runs from a valid test conducted at the representative conditions for that given 

operating range. 

(F) Identify the firing rates for which the different operating limits apply. If only two operating 

limits are established based on firing rates, the O2 operating limits established when the process 

heater is firing at no less than 70 percent of the rated heat capacity must apply when the process 

heater is firing above 50 percent of the rated heat capacity and the O2 operating limits established 
31 

for turndown conditions must apply when the process heater is firing at 50 percent or less of the 

rated heat capacity. 

(G) Operating limits associated with each interval will be valid for 2 years or until another 

operating limit is established for that interval based on a more recent performance test specific 

for that interval, whichever occurs first. Owners and operators must use the operating limits 

determined for a given interval based on the most recent performance test conducted for that 

interval. 

(7) The owner or operator of a process heater complying with a NOX limit in terms of lb/MMBtu 

as provided in §60.102a(g)(2)(i)(B), (g)(2)(ii)(B), (g)(2)(iii)(B) or (g)(2)(iv)(B) or a process 

heater with a rated heat capacity between 40 and 100 MMBtu/hr that elects to demonstrate 

continuous compliance with a maximum excess O2 limit, as provided in §60.107a(c)(6) or (d)(8), 

shall determine heat input to the process heater in MMBtu/hr during each performance test run 

by measuring fuel gas flow rate, fuel oil flow rate (as applicable) and heating value content 

according to the methods provided in §60.107a(d)(5), (d)(6), and (d)(4) or (d)(7), respectively. 

(8) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations 

to 0-percent O2 or 0- percent excess air. 

(j) The owner or operator shall determine compliance with the applicable H2S emissions limit in 

§60.102a(g)(1) for a fuel gas combustion device or the concentration requirement in §60.103a(h) 

for a flare according to the following test methods and procedures: 

(1) [Reserved]Method 1 of appendix A-1 to part 60 for sample and velocity traverses;

(2) [Reserved]Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate;

(3) [Reserved]Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method 

ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—

see §60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60;

(4) EPA Method 11, 15 or 15A of Appendix A-5 to part 60 or EPA Method 16 of Appendix A-6 

to part 60 for determining the H2S concentration for affected facilities using an H2S monitor as 

specified in §60.107a(a)(2). The method ANSI/ASME PTC 19.10-1981 (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 15A of Appendix A-5 to part 

60. The owner or operator may demonstrate compliance based on the mixture used in the fuel 

gas combustion device or flare or for each individual fuel gas stream used in the fuel gas 

combustion device or flare. 

(i) For Method 11 of appendix A-5 to part 60, the sampling time and sample volume must be at 

least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal sampling times must be 

taken at about 1-hour intervals. The arithmetic average of these two samples constitutes a run. 

For most fuel gases, sampling times exceeding 20 minutes may result in depletion of the 

collection solution, although fuel gases containing low concentrations of H2S may necessitate 

sampling for longer periods of time. 
32 

(ii) For Method 15 of appendix A-5 to part 60, at least three injects over a 1-hour period 

constitutes a run. 

(iii) For Method 15A of appendix A-5 to part 60, a 1-hour sample constitutes a run. The method 

ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—

see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. 

(iv) If monitoring is conducted at a single point in a common source of fuel gas as allowed under 

§60.107a(a)(2)(iv), only one performance test is required. That is, performance tests are not 

required when a new affected fuel gas combustion device or flare is added to a common source 

of fuel gas that previously demonstrated compliance. 

§ 60.105a Monitoring of emissions and operations for fluid catalytic cracking units 

(FCCU) and fluid coking units (FCU). 

(a) FCCU and FCU subject to PM emissions limit. Each owner or operator subject to the 

provisions of this subpart shall monitor each FCCU and FCU subject to the PM emissions limit 

in §60.102a(b)(1) according to the requirements in paragraph (b), (c), (d), or (e) of this section. 

(b) Control device operating parameters. Each owner or operator of a FCCU or FCU subject to 

the PM per coke burn-off emissions limit in §60.102a(b)(1) that uses a control device other than 

fabric filter or cyclone shall comply with the requirements in paragraphs (b)(1) and (2) of this 

section. 

(1) The owner or operator shall install, operate and maintain continuous parameter monitor 

systems (CPMS) to measure and record operating parameters for each control device according 

to the applicable requirements in paragraphs (b)(1)(i) through (v) of this section. 

(i) For units controlled using an electrostatic precipitator, the owner or operator shall use CPMS 

to measure and record the hourly average total power input and secondary voltagecurrent to the 

entire system. 

(ii) For units controlled using a wet scrubber, the owner or operator shall use CPMS to measure 

and record the hourly average pressure drop, liquid feed rate, and exhaust gas flow rate. As an 

alternative to a CPMS, the owner or operator must comply with the requirements in either 

paragraph (b)(1)(ii)(A) or (B) of this section. 

(A) As an alternative to pressure drop, the owner or operator of a jet ejector type wet scrubber or 

other type of wet scrubber equipped with atomizing spray nozzles must conduct a daily check of 

the air or water pressure to the spray nozzles and record the results of each check. Faulty (e.g., 

leaking or plugged) air or water lines must be repaired within 12 hours of identification of 

an abnormal pressure reading.

(B) As an alternative to exhaust gas flow rate, the owner or operator shall comply with the 

approved alternative for monitoring exhaust gas flow rate in 40 CFR 63.1573(a) of the National 
33 

Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking 

Units, Catalytic Reforming Units, and Sulfur Recovery Units. 

(iii) The owner or operator shall install, operate, and maintain each CPMS according to the 

manufacturer's specifications and requirements. 

(iv) The owner or operator shall determine and record the average coke burn-off rate and hours 

of operation for each FCCU or FCU using the procedures in §60.104a(d)(4)(iii). 

(v) If you use a control device other than an electrostatic precipitator, wet scrubber, fabric filter, 

or cyclone, you may request approval to monitor parameters other than those required in 

paragraph (b)(1) of this section by submitting an alternative monitoring plan to the 

Administrator. The request must include the information in paragraphs (b)(1)(v)(A) through (E) 

of this section. 

(A) A description of each affected facility and the parameter(s) to be monitored to determine 

whether the affected facility will continuously comply with the emission limitations and an 

explanation of the criteria used to select the parameter(s). 

(B) A description of the methods and procedures that will be used to demonstrate that the 

parameter(s) can be used to determine whether the affected facility will continuously comply 

with the emission limitations and the schedule for this demonstration. The owner or operator 

must certify that an operating limit will be established for the monitored parameter(s) that 

represents the conditions in existence when the control device is being properly operated and 

maintained to meet the emission limitation. 

(C) The frequency and content of the recordkeeping, recording, and reporting, if monitoring and 

recording are not continuous. The owner or operator also must include the rationale for the 

proposed monitoring, recording, and reporting requirements. 

(D) Supporting calculations. 

(E) Averaging time for the alternative operating parameter. 

(2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator 

shall install, operate, calibrate, and maintain an instrument for continuously monitoring the 

concentrations of CO2, O2 (dry basis), and if needed, CO in the exhaust gases prior to any control 

or energy recovery system that burns auxiliary fuels. A CO monitor is not required for 

determining coke burn-off rate when no auxiliary fuel is burned and a continuous CO 

monitor is not required in accordance with §60.105a(h)(3).

(i) The owner or operator shall install, operate and maintain each CO2 and O2 monitor according 

to Performance Specifications 3 and 4 of Appendix B to part 60. 

(ii) The owner or operator shall conduct performance evaluations of each CO2, O2 and COO2

monitor according to the requirements in §60.13(c) and Performance Specifications 3 and 4 of 
34 

Appendix B to part 60. The owner or operator shall use EPA Method 3 of Appendix A-3 to part 

60 and EPA Method 10, 10A or 10B of Appendix A-4 to part 60 for conducting the relative 

accuracy evaluations. 

(iii) If a CO monitor is required, the owner or operator shall install, operate, and maintain 

each CO monitor according to Performance Specification 4 or 4A of Appendix B to part 60. 

If this CO monitor also serves to demonstrate compliance with the CO emissions limit in 

§60.102a(b)(4), the span value for this instrument is 1,000 ppmv; otherwise, the span value 

for this instrument should be set at approximately 2 times the typical CO concentration 

expected in the FCCU of FCU flue gas prior to any emission control or energy recovery 

system that burns auxiliary fuels. 

(iv) If a CO monitor is required, the owner or operator shall conduct performance 

evaluations of each CO monitor according to the requirements in §60.13(c) and 

Performance Specification 4 of Appendix B to part 60. The owner or operator shall use 

Method 10, 10A, or 10B of Appendix A–3 to part 60 for conducting the relative accuracy 

evaluations. 

(v) The owner or operator shall comply with the quality assurance requirements of procedure 1 

of appendix F to part 60, including quarterly accuracy determinations for CO2 and CO monitors, 

annual accuracy determinations for O2 monitors, and daily calibration drift tests. 

(c) Bag leak detection systems. Each owner or operator shall install, operate, and maintain a bag 

leak detection system for each baghouse or similar fabric filter control device that is used to 

comply with the PM per coke burn-off emissions limit in §60.102a(b)(1) for an FCCU or FCU 

according to paragraph (c)(1) of this section; prepare and operate by a site-specific monitoring 

plan according to paragraph (c)(2) of this section; take action according to paragraph (c)(3) of 

this section; and record information according to paragraph (c)(4) of this section. 

(1) Each bag leak detection system must meet the specifications and requirements in paragraphs 

(c)(1)(i) through (viii) of this section. 

(i) The bag leak detection system must be certified by the manufacturer to be capable of 

detecting PM emissions at concentrations of 0.00044 grains per actual cubic foot or less. 

(ii) The bag leak detection system sensor must provide output of relative PM loadings. The 

owner or operator shall continuously record the output from the bag leak detection system using 

electronic or other means (e.g., using a strip chart recorder or a data logger). 

(iii) The bag leak detection system must be equipped with an alarm system that will sound when 

the system detects an increase in relative particulate loading over the alarm set point established 

according to paragraph (c)(1)(iv) of this section, and the alarm must be located such that it can be 

heard by the appropriate plant personnel. 
35 

(iv) In the initial adjustment of the bag leak detection system, the owner or operator must 

establish, at a minimum, the baseline output by adjusting the sensitivity (range) and the 

averaging period of the device, the alarm set points, and the alarm delay time. 

(v) Following initial adjustment, the owner or operator shall not adjust the averaging period, 

alarm set point, or alarm delay time without approval from the Administrator or delegated 

authority except as provided in paragraph (c)(1)(vi) of this section. 

(vi) Once per quarter, the owner or operator may adjust the sensitivity of the bag leak detection 

system to account for seasonal effects, including temperature and humidity, according to the 

procedures identified in the site-specific monitoring plan required by paragraph (c)(2) of this 

section. 

(vii) The owner or operator shall install the bag leak detection sensor downstream of the 

baghouse and upstream of any wet scrubber. 

(viii) Where multiple detectors are required, the system's instrumentation and alarm may be 

shared among detectors. 

(2) The owner or operator shall develop and submit to the Administrator for approval a sitespecific monitoring plan for each baghouse and bag leak detection system. The owner or 

operator shall operate and maintain each baghouse and bag leak detection system according to 

the site-specific monitoring plan at all times. Each monitoring plan must describe the items in 

paragraphs (c)(2)(i) through (vii) of this section. 

(i) Installation of the bag leak detection system; 

(ii) Initial and periodic adjustment of the bag leak detection system, including how the alarm setpoint will be established; 

(iii) Operation of the bag leak detection system, including quality assurance procedures; 

(iv) How the bag leak detection system will be maintained, including a routine maintenance 

schedule and spare parts inventory list; 

(v) How the bag leak detection system output will be recorded and stored; 

(vi) Procedures as specified in paragraph (c)(3) of this section. In approving the site-specific 

monitoring plan, the Administrator or delegated authority may allow owners and operators more 

than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator 

identifies in the monitoring plan this specific condition as one that could lead to an alarm, 

adequately explains why it is not feasible to alleviate this condition within 3 hours of the time the 

alarm occurs, and demonstrates that the requested time will ensure alleviation of this condition as 

expeditiously as practicable; and 
36 

(vii) How the baghouse system will be operated and maintained, including monitoring of 

pressure drop across baghouse cells and frequency of visual inspections of the baghouse interior 

and baghouse components such as fans and dust removal and bag cleaning mechanisms. 

(3) For each bag leak detection system, the owner or operator shall initiate procedures to 

determine the cause of every alarm within 1 hour of the alarm. Except as provided in paragraph 

(c)(2)(vi) of this section, the owner or operator shall alleviate the cause of the alarm within 3 

hours of the alarm by taking whatever action(s) are necessary. Actions may include, but are not 

limited to the following: 

(i) Inspecting the baghouse for air leaks, torn or broken bags or filter media, or any other 

condition that may cause an increase in particulate emissions; 

(ii) Sealing off defective bags or filter media; 

(iii) Replacing defective bags or filter media or otherwise repairing the control device; 

(iv) Sealing off a defective baghouse compartment; 

(v) Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection 

system; or 

(vi) Shutting down the process producing the particulate emissions. 

(4) The owner or operator shall maintain records of the information specified in paragraphs 

(c)(4)(i) through (iii) of this section for each bag leak detection system. 

(i) Records of the bag leak detection system output; 

(ii) Records of bag leak detection system adjustments, including the date and time of the 

adjustment, the initial bag leak detection system settings, and the final bag leak detection system 

settings; and 

(iii) The date and time of all bag leak detection system alarms, the time that procedures to 

determine the cause of the alarm were initiated, the cause of the alarm, an explanation of the 

actions taken, the date and time the cause of the alarm was alleviated, and whether the alarm was 

alleviated within 3 hours of the alarm. 

(d) Continuous emissions monitoring systems (CEMS). An owner or operator subject to the PM 

concentration emission limit (in gr/dscf) in §60.102a(b)(1) for an FCCU or FCU shall install, 

operate, calibrate, and maintain an instrument for continuously monitoring and recording the 

concentration (0 percent excess air) of PM in the exhaust gases prior to release to the 

atmosphere. The monitor must include an O2 monitor for correcting the data for excess air. 
37 

(1) The owner or operator shall install, operate, and maintain each PM monitor according to 

Performance Specification 11 of appendix B to part 60. The span value of this PM monitor is 

0.08 gr/dscf PM. 

(2) The owner or operator shall conduct performance evaluations of each PM monitor according 

to the requirements in §60.13(c) and Performance Specification 11 of appendix B to part 60. The 

owner or operator shall use EPA Methods 5 or 5I of appendix A-3 to part 60 or Method 17 of 

appendix A-6 to part 60 for conducting the relative accuracy evaluations. 

(3) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive. 

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according 

to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. 

Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative 

accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 

3B of appendix A-2 to part 60. 

(5) The owner or operator shall comply with the quality assurance requirements of Procedure 2 

of appendix B to part 60 for each PM CEMS and Procedure 1 of appendix F to part 60 for each 

O2 monitor, including quarterly accuracy determinations for each PM monitor, annual accuracy 

determinations for each O2 monitor, and daily calibration drift tests. 

(e) Alternative monitoring option for FCCU and FCU—COMS. Each owner or operator of an 

FCCU or FCU that uses cyclones to comply with the PM emission limit in §60.102a(b)(1) shall 

monitor the opacity of emissions according to the requirements in paragraphs (e)(1) through (3) 

of this section. 

(1) The owner or operator shall install, operate, and maintain an instrument for continuously 

monitoring and recording the opacity of emissions from the FCCU or the FCU exhaust vent. 

(2) The owner or operator shall install, operate, and maintain each COMS according to 

Performance Specification 1 of appendix B to part 60. The instrument shall be spanned at 20 to 

60 percent opacity. 

(3) The owner or operator shall conduct performance evaluations of each COMS according to 

§60.13(c) and Performance Specification 1 of appendix B to part 60. 

(f) FCCU and FCU subject to NOX limit. Each owner or operator subject to the NOX emissions 

limit in §60.102a(b)(2) for an FCCU or FCU shall install, operate, calibrate, and maintain an 

instrument for continuously monitoring and recording the concentration by volume (dry basis, 0 

percent excess air) of NOX emissions into the atmosphere. The monitor must include an O2

monitor for correcting the data for excess air. 
38 

(1) The owner or operator shall install, operate, and maintain each NOX monitor according to 

Performance Specification 2 of appendix B to part 60. The span value of this NOX monitor is 200 

ppmv NOX. 

(2) The owner or operator shall conduct performance evaluations of each NOX monitor according 

to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The 

owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for 

conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue 

and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative 

to EPA Method 7 or 7C of appendix A-4 to part 60. 

(3) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive. 

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according 

to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. 

Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative 

accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 

3B of appendix A-2 to part 60. 

(5) The owner or operator shall comply with the quality assurance requirements of Procedure 1 

of appendix F to part 60 for each NOX and O2 monitor, including quarterly accuracy 

determinations for NOX monitors, annual accuracy determinations for O2 monitors, and daily 

calibration drift tests. 

(g) FCCU and FCU subject to SO2 limit. The owner or operator subject to the SO2 emissions 

limit in §60.102a(b)(3) for an FCCU or an FCU shall install, operate, calibrate, and maintain an 

instrument for continuously monitoring and recording the concentration by volume (dry basis, 

corrected to 0 percent excess air) of SO2 emissions into the atmosphere. The monitor shall 

include an O2 monitor for correcting the data for excess air. 

(1) The owner or operator shall install, operate, and maintain each SO2 monitor according to 

Performance Specification 2 of appendix B to part 60. The span value of this SO2 monitor is 200 

ppmv SO2. 

(2) The owner or operator shall conduct performance evaluations of each SO2 monitor according 

to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The 

owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI / ASME PTC 19.10-1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 6 or 6A of appendix A-4 to part 60. 
39 

(3) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive. 

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according 

to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. 

Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative 

accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 

3B of appendix A-2 to part 60. 

(5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 

of appendix F to part 60 for each SO2 and O2 monitor, including quarterly accuracy 

determinations for SO2 monitors, annual accuracy determinations for O2 monitors, and daily 

calibration drift tests. 

(h) FCCU and fluid coking units subject to CO emissions limit. Except as specified in paragraph 

(h)(3) of this section, the owner or operator shall install, operate, calibrate, and maintain an 

instrument for continuously monitoring and recording the concentration by volume (dry basis) of 

CO emissions into the atmosphere from each FCCU and FCU subject to the CO emissions limit 

in §60.102a(b)(4). 

(1) The owner or operator shall install, operate, and maintain each CO monitor according to 

Performance Specification 4 or 4A of appendix B to part 60. The span value for this instrument 

is 1,000 ppmv CO. 

(2) The owner or operator shall conduct performance evaluations of each CO monitor according 

to the requirements in §60.13(c) and Performance Specification 4 or 4A of appendix B to part 60. 

The owner or operator shall use Methods 10, 10A, or 10B of appendix A-4 to part 60 for 

conducting the relative accuracy evaluations. 

(3) A CO CEMS need not be installed if the owner or operator demonstrates that all hourly 

average CO emissions are and will remain less than 50 ppmv (dry basis) corrected to 0 percent 

excess air. The Administrator may revoke this exemption from monitoring upon a determination 

that CO emissions on an hourly average basis have exceeded 50 ppmv (dry basis) corrected to 0 

percent excess air, in which case a CO CEMS shall be installed within 180 days. 

(i) The demonstration shall consist of continuously monitoring CO emissions for 30 days using 

an instrument that meets the requirements of Performance Specification 4 or 4A of appendix B to 

part 60. The span value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative accuracy 

limit shall be 10 percent of the average CO emissions or 5 ppmv CO, whichever is greater. For 

instruments that are identical to Method 10 of appendix A-4 to part 60 and employ the sample 

conditioning system of Method 10A of appendix A-4 to part 60, the alternative relative accuracy 

test procedure in section 10.1 of Performance Specification 2 of appendix B to part 60 may be 

used in place of the relative accuracy test. 
40 

(ii) The owner or operator must submit the following information to the Administrator: 

(A) The measurement data specified in paragraph (h)(3)(i) of this section along with all other 

operating data known to affect CO emissions; and 

(B) Descriptions of the CPMS for exhaust gas temperature and O2 monitor required in paragraph 

(h)(4) of this section and operating limits for those parameters to ensure combustion conditions 

remain similar to those that exist during the demonstration period. 

(iii) The effective date of the exemption from installation and operation of a CO CEMS is the 

date of submission of the information and data required in paragraph (h)(3)(ii) of this section. 

(4) The owner or operator of a FCCU or FCU that is exempted from the requirement to install 

and operate a CO CEMS in paragraph (h)(3) of this section shall install, operate, calibrate, and 

maintain CPMS to measure and record the operating parameters in paragraph (h)(4)(i) or (ii) of 

this section. The owner or operator shall install, operate, and maintain each CPMS according to 

the manufacturer's specifications. 

(i) For a FCCU or FCU with no post-combustion control device, the temperature and O2

concentration of the exhaust gas stream exiting the unit. 

(ii) For a FCCU or FCU with a post-combustion control device, the temperature and O2

concentration of the exhaust gas stream exiting the control device. 

(i) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess emissions 

for a FCCU or FCU subject to the emissions limitations in §60.102a(b) are defined as specified 

in paragraphs (i)(1) through (6) of this section. Note: Determine all averages, except for opacity, 

as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 3-hour 

average as the arithmetic average of three contiguous 1-hour averages. 

(1) If a CPMS is used according to §60.105a(b)(1), all 3-hour periods during which the average 

PM control device operating characteristics, as measured by the continuous monitoring systems 

under §60.105a(b)(1), fall below the levels established during the performance test. If the 

alternative to pressure drop CPMS is used for the owner or operator of a jet ejector type 

wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, each 

day in which abnormal pressure readings are not corrected within 12 hours of 

identification.

(2) If a bag leak detection system is used according to §60.105a(c), each day in which the 

cause of an alarm is not alleviated within the time period specified in §60.105a(c)(3). 

(3) If a PM CEMS is used according to §60.105a(d), all 7-day periods during which the average 

PM emission rate, as measured by the continuous PM monitoring system under §60.105a(d) 

exceeds 0.040 gr/dscf corrected to 0 percent excess air for a modified or reconstructed FCCU, 

0.020 gr/dscf corrected to 0 percent excess air for a newly constructed FCCU, or 0.040 gr/dscf 

for an affected fluid coking unit. 
41 

(34) If a COMS is used according to §60.105a(e), all 3-hour periods during which the average 

opacity, as measured by the COMS under §60.105a(e), exceeds the site-specific limit established 

during the most recent performance test. 

(45) All rolling 7-day periods during which the average concentration of NOX as measured by 

the NOX CEMS under §60.105a(f) exceeds 80 ppmv for an affected FCCU or FCU. 

(56) All rolling 7-day periods during which the average concentration of SO2 as measured by the 

SO2 CEMS under §60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which 

the average concentration of SO2 as measured by the SO2 CEMS exceeds 25 ppmv. 

(67) All 1-hour periods during which the average CO concentration as measured by the CO 

continuous monitoring system under §1A60.105a(h) exceeds 500 ppmv or, if applicable, all 1-

hour periods during which the average temperature and O2 concentration as measured by the 

continuous monitoring systems under §60.105a(h)(4) fall below the operating limits established 

during the performance test. 

§ 60.106a Monitoring of emissions and operations for sulfur recovery plants. 

(a) The owner or operator of a sulfur recovery plant that is subject to the emissions limits in 

§60.102a(f)(1) or §60.102a(f)(2) shall: 

(1) For sulfur recovery plants subject to the SO2 emission limit in §60.102a(f)(1)(i) or 

§60.102a(f)(2)(i), the owner or operator shall install, operate, calibrate, and maintain an 

instrument for continuously monitoring and recording the concentration (dry basis, zero percent 

excess air) of any SO2 emissions into the atmosphere. The monitor shall include an oxygen 

monitor for correcting the data for excess air. 

(i) The span values for thisthe SO2 monitor areis two times the applicable SO2 emission limit 

and between 10 and 25 percentat the highest O2, inclusive concentration in the air/oxygen 

stream used in the Claus burner, if applicable. 

(ii) The owner or operator shall install, operate, and maintain each SO2 CEMS according to 

Performance Specification 2 of appendix B to part 60. 

(iii) The owner or operator shall conduct performance evaluations of each SO2 monitor 

according to the requirements in §60.13(c) and Performance Specification 2 of appendix B to 

part 60. The owner or operator shall use Methods 6 or 6C of appendix A-4 to part 60 and Method 

3 or 3A of appendix A-2 of part 60 for conducting the relative accuracy evaluations. The method 

ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—

see §60.17) is an acceptable alternative to EPA Method 6. 

(iv) The owner or operator shall install, operate, and maintain each O2 monitor according 

to Performance Specification 3 of appendix B to part 60. 
42 

(v) The span value for the O2 monitor must be selected between 10 and 25 percent, 

inclusive. 

(vi) The owner or operator shall conduct performance evaluations for the O2 monitor 

according to the requirements of §60.13(c) and Performance Specification 3 of appendix B 

to part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to part 

60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–

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

acceptable alternative to EPA Method 3B of appendix A–2 to part 60. 

(vii) The owner or operator shall comply with the applicable quality assurance procedures 

of appendix F to part 60 for each monitor, including annual accuracy determinations for 

each O2 monitor, and daily calibration drift determinations. 

(2) For sulfur recovery plants that are subject to the reduced sulfur compound and 

H2Scompounds emission limit in §60.102a(f)(1)(ii) or §60.102a(f)(2)(ii), the owner or operator 

shall install, operate, calibrate, and maintain an instrument for continuously monitoring and 

recording the concentration of reduced sulfur, H2S, compounds and O2 emissions into the 

atmosphere. The reduced sulfur compounds emissions shall be calculated as SO2 (dry basis, zero 

percent excess air). 

(i) The span values for thisthe reduced sulfur compounds monitor areis two times the 

applicable reduced sulfur compounds emission limit, two times the H2S emission limit, and 

between 10 and 25 percent as SO2 at the highest O2, inclusive concentration in the air/oxygen 

stream used in the Claus burner, if applicable. 

(ii) The owner or operator shall install, operate, and maintain each reduced sulfur compounds 

CEMS according to Performance Specification 5 of appendix B to part 60. 

(iii) The owner or operator shall conduct performance evaluations of each reduced sulfur 

compounds monitor according to the requirements in §60.13(c) and Performance Specification 5 

of appendix B to part 60. The owner or operator shall use Methods 15 or 15A of appendix A-5 to 

part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-

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

acceptable alternative to EPA Method 15A of appendix A-5 to part 60. 

(iv) The owner or operator shall install, operate, and maintain each H2S CEMS according to 

Performance Specification 7 of appendix B to part 60. 

(v) The owner or operator shall conduct performance evaluations of each reduced sulfur monitor 

according to the requirements in §60.13(c) and Performance Specification 5 of appendix B to 

part 60. The owner or operator shall use Methods 11, 15, or 15A of appendix A-5 to part 60 or 

Method 16 of appendix A-6 to part 60 for conducting the relative accuracy evaluations. The 

method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 

60. 
43 

(ivvi) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. 

(viiv) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive. 

(viiivi) The owner or operator shall conduct performance evaluations for the O2 monitor 

according to the requirements of §60.13(c) and Performance Specification 3 of appendix B to 

part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for 

conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue 

and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative 

to EPA Method 3B of appendix A-2 to part 60. 

(ixvii) The owner or operator shall comply with the applicable quality assurance procedures of 

appendix F to part 60 for each monitor, including annual accuracy determinations for each O2

monitor, and daily calibration drift determinations. 

(3) In place of the reduced sulfur compounds monitor required in paragraph (a)(2) of this 

section, the owner or operator shallmay install, calibrate, operate, and maintain an instrument 

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

continuously monitoring and recording the concentration (dry basis, 0 percent excess air) of the 

total resultant SO2 . The monitor must include an O2 monitor for correcting the data for excess 

O2. 

(i) The span value for this monitor is two times the applicable SO2 emission limitreduced sulfur 

compounds emission limit as SO2 at the highest O2 concentration in the air/oxygen stream 

used in the Claus burner, if applicable. 

(ii) The owner or operator shall conduct performance evaluations of each SO2 monitor according 

to the requirements in §60.13(c) and Performance Specification 5 of appendix B to part 60. The 

owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 15A of appendix A-5 to part 60. 

(iii) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. 

(iv) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive. 

(v) The owner or operator shall conduct performance evaluations for the O2 monitor according to 

the requirements of §60.13(c) and Performance Specification 3 of appendix B to part 60. The 

owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 3B of appendix A-2 to part 60. 
44 

(vi) The owner or operator shall comply with the applicable quality assurance procedures of 

appendix F to part 60 for each monitor, including quarterly accuracy determinations for each SO2

monitor, annual accuracy determinations for each O2 monitor, and daily calibration drift 

determinations. 

(4) For sulfur recovery plants that are subject to the H2S emission limit in 

§60.102a(f)(1)(iii) or §60.102a(f)(2)(iii), the owner or operator shall install, operate, 

calibrate, and maintain an instrument for continuously monitoring and recording the 

concentration of H2S, and O2 emissions into the atmosphere. The H2S emissions shall be 

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

(i) The span value for this monitor is two times the applicable H2S emission limit. 

(ii) The owner or operator shall install, operate, and maintain each H2S CEMS according 

to Performance Specification 7 of appendix B to part 60. 

(iii) The owner or operator shall conduct performance evaluations for each H2S monitor 

according to the requirements of §60.13(c) and Performance Specification 7 of appendix B 

to part 60. The owner or operator shall use Methods 11 or 15 of appendix A–5 to part 60 or 

Method 16 of appendix A–6 to part 60 for conducting the relative accuracy evaluations. 

The method ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses,” 

(incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 15A of 

appendix A–5 to part 60. 

(iv) The owner or operator shall install, operate, and maintain each O2 monitor according 

to Performance Specification 3 of appendix B to part 60. 

(v) The span value for the O2 monitor must be selected between 10 and 25 percent, 

inclusive. 

(vi) The owner or operator shall conduct performance evaluations for the O2 monitor 

according to the requirements of §60.13(c) and Performance Specification 3 of appendix B 

to part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to part 

60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–

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

acceptable alternative to EPA Method 3B of appendix A–2 to part 60. 

(vii) The owner or operator shall comply with the applicable quality assurance procedures 

of appendix F to part 60 for each monitor, including annual accuracy determinations for 

each O2 monitor, and daily calibration drift determinations.. 

(5) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner 

and that elects to monitor O2 concentration of the air/oxygen mixture supplied to the Claus 

burner, the owner or operator shall install, operate, calibrate, and maintain an instrument 

for continuously monitoring and recording the O2 concentration of the air/oxygen mixture 

supplied to the Claus burner in order to determine the allowable emissions limit. 
45 

(i) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. 

(ii) The span value for the O2 monitor shall be 100 percent. 

(iii) The owner or operator shall conduct performance evaluations for the O2 monitor 

according to the requirements of §60.13(c) and Performance Specification 3 of appendix B 

to part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to part 

60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–

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

acceptable alternative to EPA Method 3B of appendix A–2 to part 60. 

(iv) The owner or operator shall comply with the applicable quality assurance procedures 

of appendix F to part 60 for each monitor, including annual accuracy determinations for 

each O2 monitor, and daily calibration drift determinations. 

(v) The owner or operator shall use the hourly average O2 concentration from this monitor 

for use in Equation 1 or 2 of §60.102a(f), as applicable, for each hour and determine the 

allowable emission limit as the arithmetic average of 12 contiguous 1-hour averages (i.e., 

the rolling 12-hour average). 

(6) As an alternative to the O2 monitor required in paragraph (a)(5) of this section, the 

owner or operator may install, calibrate, operate, and maintain a CPMS to measure and 

record the volumetric gas flow rate of ambient air and oxygen-enriched gas supplied to the 

Claus burner and calculate the hourly average O2 concentration of the air/oxygen mixture 

used in the Claus burner as specified in paragraphs (a)(6)(i) through (iv) of this section in 

order to determine the allowable emissions limit as specified in paragraphs (a)(6)(v) of this 

section. 

(i) The owner or operator shall install, calibrate, operate and maintain each flow monitor 

according to the manufacturer’s procedures and specifications and the following 

requirements. 

(A) The owner or operator shall install locate the monitor in a position that provides a 

representative measurement of the total gas flow rate. 

(B) Use a flow sensor with a measurement sensitivity of no more than 5 percent of the flow 

rate or 10 cubic feet per minute, whichever is greater. 

(C) Use a flow monitor that is maintainable online, is able to continuously correct for 

temperature, pressure and, for ambient air flow monitor, moisture content, and is able to 

record dry flow in standard conditions (as defined in §60.2) over one-minute averages. 

(D) At least quarterly, perform a visual inspection of all components of the monitor for 

physical and operational integrity and all electrical connections for oxidation and galvanic 

corrosion if the flow monitor is not equipped with a redundant flow sensor. 
46 

(E) Recalibrate the flow monitor in accordance with the manufacturer's procedures and 

specifications biennially (every two years) or at the frequency specified by the 

manufacturer.

(ii) The owner or operator shall use 20.9 percent as the oxygen content of the ambient air. 

(iii) The owner or operator shall use product specifications (e.g., as reported in material 

safety data sheets) for percent oxygen for purchased oxygen. For oxygen produced onsite, 

the percent oxygen shall be determined by periodic measurements or process knowledge. 

(iv) The owner or operator shall calculate the hourly average O2 concentration of the 

air/oxygen mixture used in the Claus burner using Equation 10 of this section: 



















   

air oxy

air 2,oxy oxy

2 Q Q

Q %O Q %O20.9

 (Eq. 10) 

Where: 

%O2 = O2 concentration of the air/oxygen mixture used in the Claus burner, percent by 

volume (dry basis); 

20.9 = O2 concentration in air, percent dry basis; 

Qair = Volumetric flow rate of ambient air used in the Claus burner, dscfm; 

%O2,oxy = O2 concentration in the enriched oxygen stream, percent dry basis; and 

Qoxy = Volumetric flow rate of enriched oxygen stream used in the Claus burner, dscfm. 

(v) The owner or operator shall use the hourly average O2 concentration determined using 

Equation 8 of this section for use in Equation 1 or 2 of §60.102a(f), as applicable, for each 

hour and determine the allowable emission limit as the arithmetic average of 12 contiguous 

1-hour averages (i.e., the rolling 12-hour average). 

(7) Owners or operators of a sulfur recovery plant that elects to comply with the SO2

emission limit in §60.102a(f)(1)(i) or §60.102a(f)(2)(i) or the reduced sulfur compounds 

emission limit in §60.102a(f)(1)(ii) or §60.102a(f)(2)(ii) as a flow rate weighted average for a 

group of release points from the sulfur recovery plant rather than for each process train or 

release point individually shall install, calibrate, operate, and maintain a CPMS to measure 

and record the volumetric gas flow rate of each release point within the group of release 

points from the sulfur recovery plant as specified in paragraphs (a)(7)(i) through (iv) of this 

section. 
47 

(i) The owner or operator shall install, calibrate, operate and maintain each flow monitor 

according to the manufacturer’s procedures and specifications and the following 

requirements. 

(A) The owner or operator shall install locate the monitor in a position that provides a 

representative measurement of the total gas flow rate. 

(B) Use a flow sensor with a measurement sensitivity of no more than 5 percent of the flow 

rate or 10 cubic feet per minute, whichever is greater. 

(C) Use a flow monitor that is maintainable online, is able to continuously correct for 

temperature, pressure, and moisture content, and is able to record dry flow in standard 

conditions (as defined in §60.2) over one-minute averages. 

(D) At least quarterly, perform a visual inspection of all components of the monitor for 

physical and operational integrity and all electrical connections for oxidation and galvanic 

corrosion if the flow monitor is not equipped with a redundant flow sensor. 

(E) Recalibrate the flow monitor in accordance with the manufacturer's procedures and 

specifications biennially (every two years) or at the frequency specified by the 

manufacturer.

(ii) The owner or operator shall correct the flow to 0 percent excess air using Equation 11 

of this section: 

  

    c

2

adj meas

%O Q Q 20.920.9 (Eq. 11) 

Where: 

Qadj = Volumetric flow rate adjusted to 0 percent excess air, dry standard cubic feet per 

minute (dscfm); 

Cmeas = Volumetric flow rate measured by the flow meter corrected to dry standard 

conditions, dscfm; 

20.9c = 20.9 percent O2−0.0 percent O2 (defined O2 correction basis), percent; 

20.9 = O2 concentration in air, percent; and 

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

(iii) The owner or operator shall calculate the flow weighted average SO2 or reduced sulfur 

compounds concentration for each hour using Equation 12 of this section: 
48 

 











 N

n

adj,n

N

n

n adj,n

ave

Q

C Q

C

1

1 (Eq. 12) 

Where: 

Cave = Flow weighted average concentration of the pollutant, ppmv (dry basis, zero percent 

excess air). The pollutant is either SO2 [if complying with the SO2 emission limit in 

§60.102a(f)(1)(i) or §60.102a(f)(2)(i)] or reduced sulfur compounds [if complying 

with the reduced sulfur compounds emission limit in §60.102a(f)(1)(ii) or 

§60.102a(f)(2)(ii)]; 

N = Number of release points within the group of release points from the sulfur recovery 

plant for which emissions averaging is elected; 

Cn = Pollutant concentration in the nth release point within the group of release points from 

the sulfur recovery plant for which emissions averaging is elected, ppmv (dry basis, 

zero percent excess air); 

Qadj,n = Volumetric flow rate of the nth release point within the group of release points from 

the sulfur recovery plant for which emissions averaging is elected, dry standard 

cubic feet per minute (dscfm, adjusted to 0 percent excess air). 

(iv) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner, 

the owner or operator shall use Equation 10 of this section and the hourly emission limits 

determined in paragraphs (a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant 

concentration to determine the flow weighted average hourly emission limit for each hour. 

The allowable emission limit shall be calculated as the arithmetic average of 12 contiguous 

1-hour averages (i.e., the rolling 12-hour average). 

(b) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess 

emissions for sulfur recovery plants subject to the emissions limitations in §60.102a(f) are 

defined as specified in paragraphs (b)(1) through (3) of this section. NOTE: Determine all 

averages as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 

12-hour average as the arithmetic average of 12 contiguous 1-hour averages. 

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

continuous monitoring system required under paragraph (a)(1) of this section exceeds the 

applicable emission limit (dry basis, zero percent excess air); or 

(2) All 12-hour periods during which the average concentration of reduced sulfur compounds 

(as SO2) as measured by the reduced sulfur compounds continuous monitoring system required 

under paragraph (a)(2) or (a)(3) of this section exceeds the applicable emission limit; or 
49 

(3) All 12-hour periods during which the average concentration of H2S as measured by the H2S 

continuous monitoring system required under paragraph (a)(24) of this section exceeds the 

applicable emission limit (dry basis, 0 percent excess air). 

§ 60.107a Monitoring of emissions and operations for fuel gas combustion devices and 

flares. 

(a) Fuel gas combustion devices subject to SO2 or H2S limit and flares subject to H2S 

concentration requirements. The owner or operator of a fuel gas combustion device that is 

subject to §60.102a(g)(1) and elects to comply with the SO2 emission limits in §60.102a(g)(1)(i) 

shall comply with the requirements in paragraph (a)(1) of this section. The owner or operator of 

a fuel gas combustion device that is subject to §60.102a(g)(1) and elects to comply with the H2S 

concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration 

requirement in §60.103a(h) shall comply with paragraph (a)(2) of this section. 

(1) The owner or operator of a fuel gas combustion device that elects to comply with the SO2

emissions limits in §60.102a(g)(1)(i) shall install, operate, calibrate and maintain an instrument 

for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of 

SO2 emissions into the atmosphere. The monitor must include an O2 monitor for correcting the 

data for excess air. 

(i) The owner or operator shall install, operate, and maintain each SO2 monitor according to 

Performance Specification 2 of appendix B to part 60. The span value for the SO2 monitor is 50 

ppmv SO2. 

(ii) The owner or operator shall conduct performance evaluations for the SO2 monitor according 

to the requirements of §60.13(c) and Performance Specification 2 of appendix B to part 60. The 

owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 6 or 6A of appendix A-4 to part 60. Samples taken by Method 6 of appendix A-4 to part 

60 shall be taken at a flow rate of approximately 2 liters/min for at least 30 minutes. The relative 

accuracy limit shall be 20 percent or 4 ppmv, whichever is greater, and the calibration drift limit 

shall be 5 percent of the established span value. 

(iii) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value for the O2 monitor must be 

selected between 10 and 25 percent, inclusive. 

(iv) The owner or operator shall conduct performance evaluations for the O2 monitor according 

to the requirements of §60.13(c) and Performance Specification 3 of appendix B to part 60. The 

owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 3B of appendix A-2 to part 60. 
50 

(v) The owner or operator shall comply with the applicable quality assurance procedures in 

appendix F to part 60, including quarterly accuracy determinations for SO2 monitors, annual 

accuracy determinations for O2 monitors, and daily calibration drift tests. 

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

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

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

(2) The owner or operator of a fuel gas combustion device that elects to comply with the H2S 

concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration 

requirement in §60.103a(h) shall install, operate, calibrate and maintain an instrument for 

continuously monitoring and recording the concentration by volume (dry basis) of H2S in the 

fuel gases before being burned in any fuel gas combustion device or flare. 

(i) The owner or operator shall install, operate and maintain each H2S monitor according to 

Performance Specification 7 of Appendix B to part 60. The span value for this instrument is 300 

ppmv H2S. 

(ii) The owner or operator shall conduct performance evaluations for each H2S monitor 

according to the requirements of §60.13(c) and Performance Specification 7 of appendix B to 

part 60. The owner or operator shall use Method 11, 15, or 15A of appendix A-5 to part 60 or 

Method 16 of appendix A-6 to part 60 for conducting the relative accuracy evaluations. The 

method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 

60. 

(iii) The owner or operator shall comply with the applicable quality assurance procedures in 

appendix F to part 60 for each H2S monitor. 

(iv) Fuel gas combustion devices or flares having a common source of fuel gas may be 

monitored at only one location, if monitoring at this location accurately represents the 

concentration of H2S in the fuel gas being burned in the respective fuel gas combustion devices 

or flares. 

(v) The owner or operator of a flare subject to §60.103a(c) through (e) may use the instrument 

required in paragraph (e)(1) of this section to demonstrate compliance with the H2S 

concentration requirement in §60.103a(h) if the owner or operator complies with the 

requirements of paragraph (e)(1)(i) through (iv) and if the instrument has a span (or dual span, if 

necessary) capable of accurately measuring concentrations between 20 and 300 ppmv. If the 

instrument required in paragraph (e)(1) of this section is used to demonstrate compliance with 

the H2S concentration requirement, the concentration directly measured by the instrument must 

meet the numeric concentration in §60.103a(h). 

(vi) The owner or operator of modified flare that meets all three criteria in paragraphs 

(a)(2)(vi)(A) through (C) of this section shall comply with the requirements of paragraphs 

(a)(2)(i) through (v) of this section no later than November 11, 2015. The owner or operator shall 
51 

comply with the approved alternative monitoring plan or plans pursuant to §60.13(i) until the 

flare is in compliance with requirements of paragraphs (a)(2)(i) through (v) of this section. 

(A) The flare was an affected facility subject to subpart J of this part prior to becoming an 

affected facility under §60.100a. 

(B) The owner or operator had an approved alternative monitoring plan or plans pursuant to 

§60.13(i) for all fuel gases combusted in the flare. 

(C) The flare did not have in place on or before September 12, 2012 an instrument for 

continuously monitoring and recording the concentration by volume (dry basis) of H2S in the 

fuel gases that is capable of complying with the requirements of paragraphs (a)(2)(i) through (v) 

of this section. 

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

paragraph (a)(1) or (2) of this section for fuel gas streams that are exempt under 

§§60.102a(g)(1)(iii) or 60.103a(h) or, for fuel gas streams combusted in a process heater, other 

fuel gas combustion device or flare that are inherently low in sulfur content. Fuel gas streams 

meeting one of the requirements in paragraphs (a)(3)(i) through (iv) of this section will be 

considered inherently low in sulfur content. 

(i) Pilot gas for heaters and flares. 

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

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

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

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

concentration. 

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

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

and HF alkylation process units. 

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

the procedures in paragraph (b) of this section. 

(4) If the composition of an exempt fuel gas stream changes, the owner or operator must follow 

the procedures in paragraph (b)(3) of this section. 

(b) Exemption from H2S monitoring requirements for low-sulfur fuel gas streams. The owner or 

operator of a fuel gas combustion device or flare may apply for an exemption from the H2S 

monitoring requirements in paragraph (a)(2) of this section for a fuel gas stream that is inherently 

low in sulfur content. A fuel gas stream that is demonstrated to be low-sulfur is exempt from the 

monitoring requirements of paragraphs (a)(1) and (2) of this section until there are changes in 

operating conditions or stream composition. 
52 

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

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

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

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

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

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

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

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

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

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

demonstrating that the sulfur content is less than 5 ppmv H2S. Sampling data must include, at 

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

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

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

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

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

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

§60.17), with ranges 0-10/0-100 ppm (N = 10/1)using tubes with a maximum span between 10 

and 40 ppmv inclusive when 1≤N≤10, where N = number of pump strokes, to test the 

applicant fuel gas stream for H2S; and 

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

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

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

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

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

typical operating conditions affecting H2S content in the fuel gas stream going to the loading 

rack flare). 

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

paragraph (b)(1) of this section. 

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

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

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

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

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

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

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

range. 
53 

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

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

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

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

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

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

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

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

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

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

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

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

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

gas combustion device must also determine a rolling 365-day average using the stain sampling 

results; an average H2S concentration of 5 ppmv must be used for days within the rolling 365-

day period prior to the operation change. 

(c) Process heaters complying with the NOX concentration-based limit. The owner or operator of 

a process heater subject to the NOX emissions limit in §60.102a(g)(2) and electing to comply 

with the applicable emissions limit in §60.102a(g)(2)(i)(A), (g)(2)(ii)(A), (g)(2)(iii)(A) or 

(g)(2)(iv)(A) shall install, operate, calibrate and maintain an instrument for continuously 

monitoring and recording the concentration (dry basis, 0-percent excess air) of NOX emissions 

into the atmosphere according to the requirements in paragraphs (c)(1) through (5) of this 

section, except as provided in paragraph (c)(6) of this section. The monitor must include an O2

monitor for correcting the data for excess air. 

(1) Except as provided in paragraph (c)(6) of this section, the owner or operator shall install, 

operate and maintain each NOX monitor according to Performance Specification 2 of Appendix 

B to part 60. The span value of this NOX monitor must be between 2 and 3 times the applicable 

emissions limit, inclusive. 

(2) The owner or operator shall conduct performance evaluations of each NOX monitor according 

to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The 

owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for 

conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue 

and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative 

to EPA Method 7 or 7C of appendix A-4 to part 60. 

(3) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive. 

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according 

to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. 

Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative 
54 

accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 

3B of appendix A-2 to part 60. 

(5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 

of appendix F to part 60 for each NOX and O2 monitor, including quarterly accuracy 

determinations for NOX monitors, annual accuracy determinations for O2 monitors, and daily 

calibration drift tests. 

(6) The owner or operator of a process heater that has a rated heating capacity of less than 100 

MMBtu and is equipped with combustion modification-based technology to reduce NOX

emissions (i.e., low-NOX burners, ultra-low-NOX burners) may elect to comply with the 

monitoring requirements in paragraphs (c)(1) through (5) of this section or, alternatively, the 

owner or operator of such a process heater shall conduct biennial performance tests according to 

the requirements in §60.104a(i), establish a maximum excess O2 operating limit or operating 

curve according to the requirements in §60.104a(i)(6) and comply with the O2 monitoring 

requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O2

operating curve is used (i.e., if different O2 operating limits are established for different 

operating ranges), the owner or operator of the process heater must also monitor fuel gas flow 

rate, fuel oil flow rate (as applicable) and heating value content according to the methods 

provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section, respectively. 

(d) Process heaters complying with the NOX heating value-based or mass-based limit. The owner 

or operator of a process heater subject to the NOX emissions limit in §60.102a(g)(2) and electing 

to comply with the applicable emissions limit in §60.102a(g)(2)(i)(B) or (g)(2)(ii)(B) shall 

install, operate, calibrate and maintain an instrument for continuously monitoring and recording 

the concentration (dry basis, 0-percent excess air) of NOX emissions into the atmosphere and 

shall determine the F factor of the fuel gas stream no less frequently than once per day according 

to the monitoring requirements in paragraphs (d)(1) through (4) of this section. The owner or 

operator of a co-fired process heater subject to the NOX emissions limit in §60.102a(g)(2) and 

electing to comply with the heating value-based limit in §60.102a(g)(2)(iii)(B) or (g)(2)(iv)(B) 

shall install, operate, calibrate and maintain an instrument for continuously monitoring and 

recording the concentration (dry basis, 0-percent excess air) of NOX emissions into the 

atmosphere according to the monitoring requirements in paragraph (d)(1) of this section; install, 

operate, calibrate and maintain an instrument for continuously monitoring and recording the flow 

rate of the fuel gas and fuel oil fed to the process heater according to the monitoring 

requirements in paragraph (d)(5) and (6) of this section; for fuel gas streams, determine gas 

composition according to the requirements in paragraph (d)(4) of this section or the higher 

heating value according to the requirements in paragraph (d)(7) of this section; and for fuel oil 

streams, determine the heating value according to the monitoring requirements in paragraph 

(d)(7) of this section. 

(1) Except as provided in paragraph (d)(8) of this section, the owner or operator shall install, 

operate and maintain each NOX monitor according to the requirements in paragraphs (c)(1) 

through (5) of this section. The monitor must include an O2 monitor for correcting the data for 

excess air. 
55 

(2) Except as provided in paragraph (d)(3) of this section, the owner or operator shall sample and 

analyze each fuel stream fed to the process heater using the methods and equations in section 

12.3.2 of EPA Method 19 of Appendix A-7 to part 60 to determine the F factor on a dry basis. If 

a single fuel gas system provides fuel gas to several process heaters, the F factor may be 

determined at a single location in the fuel gas system provided it is representative of the fuel gas 

fed to the affected process heater(s). 

(3) As an alternative to the requirements in paragraph (d)(2) of this section, the owner or 

operator of a gas-fired process heater shall install, operate and maintain a gas composition 

analyzer and determine the average F factor of the fuel gas using the factors in Table 1 of this 

subpart and Equation 1013 of this section. If a single fuel gas system provides fuel gas to several 

process heaters, the F factor may be determined at a single location in the fuel gas system 

provided it is representative of the fuel gas fed to the affected process heater(s). 

 

 





  

i i

i i

d X MHC

X MEV

F

1,000,000

 (Eq. 1013) 

Where: 

Fd = F factor on dry basis at 0-percent excess air, dscf/MMBtu. 

Xi = mole or volume fraction of each component in the fuel gas. 

MEVi = molar exhaust volume, dry standard cubic feet per mole (dscf/mol). 

MHCi = molar heat content, Btu per mole (Btu/mol). 

1,000,000 = unit conversion, Btu per MMBtu. 

(4) The owner or operator shall conduct performance evaluations of each compositional monitor 

according to the requirements in Performance Specification 9 of Appendix B to part 60. Any of 

the following methods shall be used for conducting the relative accuracy evaluations: 

(i) EPA Method 18 of Appendix A-6 to part 60; 

(ii) ASTM D1945-03 (Reapproved 2010)(incorporated by reference-see §60.17); 

(iii) ASTM D1946-90 (Reapproved 2006)(incorporated by reference-see §60.17); 

(iv) ASTM D6420-99 (Reapproved 2004)(incorporated by reference-see §60.17); 

(v) GPA 2261-00 (incorporated by reference-see §60.17); or 

(vi) ASTM UOP539-97 (incorporated by reference-see §60.17). 
56 

(5) The owner or operator shall install, operate and maintain fuel gas flow monitors according to 

the manufacturer's recommendations. For volumetric flow meters, temperature and pressure 

monitors must be installed in conjunction with the flow meter or in a representative location to 

correct the measured flow to standard conditions (i.e., 68 °F and 1 atmosphere). For mass flow 

meters, use gas compositions determined according to paragraph (d)(4) of this section to 

determine the average molecular weight of the fuel gas and convert the mass flow to a 

volumetric flow at standard conditions (i.e., 68 °F and 1 atmosphere). The owner or operator 

shall conduct performance evaluations of each fuel gas flow monitor according to the 

requirements in §60.13 and Performance Specification 6 of Appendix B to part 60. Any of the 

following methods shall be used for conducting the relative accuracy evaluations: 

(i) EPA Method 2, 2A, 2B, 2C or 2D of Appendix A-2 to part 60; 

(ii) ASME MFC-3M-2004 (incorporated by reference-see §60.17); 

(iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) (incorporated by reference-see §60.17); 

(iv) ASME MFC-6M-1998 (Reaffirmed 2005) (incorporated by reference-see §60.17); 

(v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006) (incorporated by reference-see §60.17); 

(vi) ASME MFC-11M-2006 (incorporated by reference-see §60.17); 

(vii) ASME MFC-14M-2003 (incorporated by reference-see §60.17); 

(viii) ASME MFC-18M-2001 (incorporated by reference-see §60.17); 

(ix) AGA Report No. 3, Part 1 (incorporated by reference-see §60.17); 

(x) AGA Report No. 3, Part 2 (incorporated by reference-see §60.17); 

(xi) AGA Report No. 11 (incorporated by reference-see §60.17); 

(xii) AGA Report No. 7 (incorporated by reference-see §60.17); and 

(xiii) API Manual of Petroleum Measurement Standards, Chapter 22, Section 2 (incorporated by 

reference-see §60.17). 

(6) The owner or operator shall install, operate and maintain each fuel oil flow monitor according 

to the manufacturer's recommendations. The owner or operator shall conduct performance 

evaluations of each fuel oil flow monitor according to the requirements in §60.13 and 

Performance Specification 6 of Appendix B to part 60. Any of the following methods shall be 

used for conducting the relative accuracy evaluations: 

(i) Any one of the methods listed in paragraph (d)(5) of this section that are applicable to fuel oil 

( i.e., “fluids”); 
57 

(ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006) (incorporated by reference-see §60.17); 

(iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006) (incorporated by reference-see §60.17); 

(iv) ASME MFC-16-2007 (incorporated by reference-see §60.17); 

(v) ASME MFC-22-2007 (incorporated by reference-see §60.17); or 

(vi) ISO 8316 (incorporated by reference-see §60.17). 

(7) The owner or operator shall determine the higher heating value of each fuel fed to the process 

heater using any of the applicable methods included in paragraphs (d)(7)(i) through (ix) of this 

section. If a common fuel supply system provides fuel gas or fuel oil to several process heaters, 

the higher heating value of the fuel in each fuel supply system may be determined at a single 

location in the fuel supply system provided it is representative of the fuel fed to the affected 

process heater(s). The higher heating value of each fuel fed to the process heater must be 

determined no less frequently than once per day except as provided in paragraph (d)(7)(x) of this 

section. 

(i) ASTM D240-02 (Reapproved 2007) (incorporated by reference-see §60.17). 

(ii) ASTM D1826-94 (Reapproved 2003) (incorporated by reference-see §60.17). 

(iii) ASTM D1945-03 (Reapproved 2010) (incorporated by reference-see §60.17). 

(iv) ASTM D1946-90 (Reapproved 2006) (incorporated by reference-see §60.17). 

(v) ASTM D3588-98 (Reapproved 2003) (incorporated by reference-see §60.17). 

(vi) ASTM D4809-06 (incorporated by reference-see §60.17). 

(vii) ASTM D4891-89 (Reapproved 2006) (incorporated by reference-see §60.17). 

(viii) GPA 2172-09 (incorporated by reference-see §60.17). 

(ix) Any of the methods specified in section 2.2.7 of Appendix D to part 75. 

(x) If the fuel oil supplied to the affected co-fired process heater originates from a single storage 

tank, the owner or operator may elect to use the storage tank sampling method in section 2.2.4.2 

of Appendix D to part 75 instead of daily sampling, except that the most recent value for heating 

content must be used. 

(8) The owner or operator of a process heater that has a rated heating capacity of less than 100 

MMBtu and is equipped with combustion modification based technology to reduce NOX

emissions (i.e., low-NOX burners or ultra-low NOX burners) may elect to comply with the 

monitoring requirements in paragraphs (d)(1) through (7) of this section or, alternatively, the 
58 

owner or operator of such a process heater shall conduct biennial performance tests according to 

the requirements in §60.104a(i), establish a maximum excess O2 operating limit or operating 

curve according to the requirements in §60.104a(i)(6) and comply with the O2 monitoring 

requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O2

operating curve is used (i.e., if different O2 operating limits are established for different 

operating ranges), the owner or operator of the process heater must also monitor fuel gas flow 

rate, fuel oil flow rate (as applicable) and heating value content according to the methods 

provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section, respectively. 

(e) Sulfur monitoring for assessing root cause analysis threshold for affected flares. Except as 

described in paragraphs (e)(4) and (h) of this section, the owner or operator of an affected flare 

subject to §60.103a(c) through (e) shall determine the total reduced sulfur concentration for each 

gas line directed to the affected flare in accordance with either paragraph (e)(1), (e)(2) or (e)(3) 

of this section. Different options may be elected for different gas lines. If a monitoring system is 

in place that is capable of complying with the requirements related to either paragraph (e)(1), 

(e)(2) or (e)(3) of this section, the owner or operator of a modified flare must comply with the 

requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section upon startup of the 

modified flare. If a monitoring system is not in place that is capable of complying with the 

requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or 

operator of a modified flare must comply with the requirements related to either paragraph 

(e)(1), (e)(2) or (e)(3) of this section no later than November 11, 2015 or upon startup of the 

modified flare, whichever is later. 

(1) Total reduced sulfur monitoring requirements. The owner or operator shall install, operate, 

calibrate and maintain an instrument or instruments for continuously monitoring and recording 

the concentration of total reduced sulfur in gas discharged to the flare. 

(i) The owner or operator shall install, operate and maintain each total reduced sulfur monitor 

according to Performance Specification 5 of Appendix B to part 60. The span value should be 

determined based on the maximum sulfur content of gas that can be discharged to the flare (e.g., 

roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 

5,000 ppmv. A single dual range monitor may be used to comply with the requirements of this 

paragraph and paragraph (a)(2) of this section provided the applicable span specifications are 

met. 

(ii) The owner or operator shall conduct performance evaluations of each total reduced sulfur 

monitor according to the requirements in §60.13(c) and Performance Specification 5 of 

Appendix B to part 60. For flares that routinely have flow, theThe owner or operator of each 

total reduced sulfur monitor shall use EPA Method 15A of Appendix A-5 to part 60 for 

conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 

(incorporated by reference-see §60.17) is an acceptable alternative to EPA Method 15A of 

Appendix A-5 to part 60. The alternative relative accuracy procedures described in section 16.0 

of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for 

conducting the relative accuracy evaluations. For flares that do not receive routine flow, the 

alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 

of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy 
59 

evaluations, except that it is not necessary to include as much of the sampling probe or sampling 

line as practical. 

(iii) The owner or operator shall comply with the applicable quality assurance procedures in 

Appendix F to part 60 for each total reduced sulfur monitor. 

(2) H2S monitoring requirements. The owner or operator shall install, operate, calibrate, and 

maintain an instrument or instruments for continuously monitoring and recording the 

concentration of H2S in gas discharged to the flare according to the requirements in paragraphs 

(e)(2)(i) through (iii) of this section and shall collect and analyze samples of the gas and 

calculate total sulfur concentrations as specified in paragraphs (e)(2)(iv) through (ix) of this 

section. 

(i) The owner or operator shall install, operate and maintain each H2S monitor according to 

Performance Specification 7 of Appendix B to part 60. The span value should be determined 

based on the maximum sulfur content of gas that can be discharged to the flare (e.g., roughly 1.1 

to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. 

A single dual range H2S monitor may be used to comply with the requirements of this paragraph 

and paragraph (a)(2) of this section provided the applicable span specifications are met. 

(ii) The owner or operator shall conduct performance evaluations of each H2S monitor according 

to the requirements in §60.13(c) and Performance Specification 7 of Appendix B to part 60. For 

flares that routinely have flow, tThe owner or operator shall use EPA Method 11, 15 or 15A of 

Appendix A-5 to part 60 for conducting the relative accuracy evaluations. The method 

ANSI/ASME PTC 19.10-1981 (incorporated by reference—see §60.17) is an acceptable 

alternative to EPA Method 15A of Appendix A-5 to part 60. The alternative relative accuracy 

procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for conducting the relative accuracy evaluations. For flares that 

do not receive routine flow, the alternative relative accuracy procedures described in section 16.0 

of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for 

conducting the relative accuracy evaluations, except that it is not necessary to include as much of 

the sampling probe or sampling line as practical. 

(iii) The owner or operator shall comply with the applicable quality assurance procedures in 

Appendix F to part 60 for each H2S monitor. 

(iv) In the first 10 operating days after the date the flare must begin to comply with 

§60.103a(c)(1), the owner or operator shall collect representative daily samples of the gas 

discharged to the flare. The samples may be grab samples or integrated samples. The owner or 

operator shall take subsequent representative daily samples at least once per week or as required 

in paragraph (e)(2)(ix) of this section. 

(v) The owner or operator shall analyze each daily sample for total sulfur using either EPA 

Method 15A of Appendix A-5 to part 60, EPA Method 16A of Appendix A-6 to part 60, ASTM 

Method D4468-85 (Reapproved 2006) (incorporated by reference—see §60.17) or ASTM 

Method D5504-08 (incorporated by reference—see §60.17). 
60 

(vi) The owner or operator shall develop a 10-day average total sulfur-to-H2S ratio and 95-

percent confidence interval as follows: 

(A) Calculate the ratio of the total sulfur concentration to the H2S concentration for each day 

during which samples are collected. 

(B) Determine the 10-day average total sulfur-to-H2S ratio as the arithmetic average of the daily 

ratios calculated in paragraph (e)(2)(vi)(A) of this section. 

(C) Determine the acceptable range for subsequent weekly samples based on the 95-percent 

confidence interval for the distribution of daily ratios based on the 10 individual daily ratios 

using Equation 1114 of this section. 

AR Ratio SDev  Avg  2 (Eq. .262 1114) 

Where: 

AR = Acceptable range of subsequent ratio determinations, unitless. 

RatioAvg = 10-day average total sulfur-to-H2S concentration ratio, unitless. 

2.262 = t-distribution statistic for 95-percent 2-sided confidence interval for 10 samples (9 

degrees of freedom). 

SDev = Standard deviation of the 10 daily average total sulfur-to-H2S concentration ratios used 

to develop the 10-day average total sulfur-to-H2S concentration ratio, unitless. 

(vii) For each day during the period when data are being collected to develop a 10-day average, 

the owner or operator shall estimate the total sulfur concentration using the measured total sulfur 

concentration measured for that day. 

(viii) For all days other than those during which data are being collected to develop a 10-day 

average, the owner or operator shall multiply the most recent 10-day average total sulfur-to-H2S 

ratio by the daily average H2S concentrations obtained using the monitor as required by 

paragraph (e)(2)(i) through (iii) of this section to estimate total sulfur concentrations. 

(ix) If the total sulfur-to-H2S ratio for a subsequent weekly sample is outside the acceptable 

range for the most recent distribution of daily ratios, the owner or operator shall develop a new 

10-day average ratio and acceptable range based on data for the outlying weekly sample plus 

data collected over the following 9 operating days. 

(3) SO2 monitoring requirements. The owner or operator shall install, operate, calibrate and 

maintain an instrument for continuously monitoring and recording the concentration of SO2 from 

a process heater or other fuel gas combustion device that is combusting gas representative of the 

fuel gas in the flare gas line according to the requirements in paragraph (a)(1) of this section, 

determine the F factor of the fuel gas at least daily according to the requirements in paragraphs 
61 

(d)(2) through (4) of this section, determine the higher heating value of the fuel gas at least daily 

according to the requirements in paragraph (d)(7) of this section and calculate the total sulfur 

content (as SO2 ) in the fuel gas using Equation 1215 of this section. 

TSFG  CSO2  Fd  HHVFG (Eq. 1215) 

Where: 

TSFG = Total sulfur concentration, as SO2, in the fuel gas, ppmv. 

CSO2 = Concentration of SO2 in the exhaust gas, ppmv (dry basis at 0-percent excess air). 

Fd = F factor gas on dry basis at 0-percent excess air, dscf/MMBtu. 

HHVFG = Higher heating value of the fuel gas, MMBtu/scf. 

(4) Exemptions from sulfur monitoring requirements. Flares identified in paragraphs (e)(4)(i) 

through (iv) of this section are exempt from the requirements in paragraphs (e)(1) through (3) of 

this section. For each such flare, except as provided in paragraph (e)(4)(iv), engineering 

calculations shall be used to calculate the SO2 emissions in the event of a discharge that may 

trigger a root cause analysis under §60.103a(c)(1). 

(i) Flares that can only receive: 

(A) Fuel gas streams that are inherently low in sulfur content as described in paragraph (a)(3)(i) 

through (iv) of this section; and/or 

(B) Fuel gas streams that are inherently low in sulfur content for which the owner or operator has 

applied for an exemption from the H2S monitoring requirements as described in paragraph (b) of 

this section. 

(ii) Emergency flares, provided that for each such flare, the owner or operator complies with the 

monitoring alternative in paragraph (g) of this section. 

(iii) Flares equipped with flare gas recovery systems designed, sized and operated to capture all 

flows except those resulting from startup, shutdown or malfunction, provided that for each such 

flare, the owner or operator complies with the monitoring alternative in paragraph (g) of this 

section. 

(iv) Secondary flares that receive gas diverted from the primary flare. In the event of a discharge 

from the secondary flare, the sulfur content measured by the sulfur monitor on the primary flare 

should be used to calculate SO2 emissions, regardless of whether or not the monitoring 

alternative in paragraph (g) of this section is selected for the secondary flare. 

(f) Flow monitoring for flares. Except as provided in paragraphs (f)(2) and (h) of this section, the 

owner or operator of an affected flare subject to §60.103a(c) through (e) shall install, operate, 
62 

calibrate and maintain, in accordance with the specifications in paragraph (f)(1) of this section, a 

CPMS to measure and record the flow rate of gas discharged to the flare. If a flow monitor is not 

already in place, the owner or operator of a modified flare shall comply with the requirements of 

this paragraph by no later than November 11, 2015 or upon startup of the modified flare, 

whichever is later. 

(1) The owner or operator shall install, calibrate, operate and maintain each flow monitor 

according to the manufacturer's procedures and specifications and the following requirements. 

(i) Locate the monitor in a position that provides a representative measurement of the total gas 

flow rate. 

(ii) Use a flow sensor with a measurement sensitivity of no more than 5 percent of the flow rate 

or 10 cubic feet per minute, whichever is greater. 

(iii) Use a flow monitor that is maintainable online, is able to continuously correct for 

temperature and pressure and is able to record flow in standard conditions (as defined in §60.2) 

over one-minute averages. 

(iv) At least quarterly, perform a visual inspection of all components of the monitor for physical 

and operational integrity and all electrical connections for oxidation and galvanic corrosion if the 

flow monitor is not equipped with a redundant flow sensor. 

(v) Recalibrate the flow monitor in accordance with the manufacturer's procedures and 

specifications biennially (every two years) or at the frequency specified by the manufacturer. 

(2) Emergency flares, secondary flares and flares equipped with flare gas recovery systems 

designed, sized and operated to capture all flows except those resulting from startup, shutdown 

or malfunction are not required to install continuous flow monitors; provided, however, that for 

any such flare, the owner or operator shall comply with the monitoring alternative in paragraph 

(g) of this section. 

(g) Alternative monitoring for certain flares equipped with water seals. The owner or operator of 

an affected flare subject to §60.103a(c) through (e) that can be classified as either an emergency 

flare, a secondary flare or a flare equipped with a flare gas recovery system designed, sized and 

operated to capture all flows except those resulting from startup, shutdown or malfunction may, 

as an alternative to the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this 

section, install, operate, calibrate and maintain, in accordance with the requirements in 

paragraphs (g)(1) through (7) of this section, a CPMS to measure and record the pressure in the 

flare gas header between the knock-out pot and water seal and to measure and record the water 

seal liquid level. If the required monitoring systems are not already in place, the owner or 

operator of a modified flare shall comply with the requirements of this paragraph by no later than 

November 11, 2015 or upon startup of the modified flare, whichever is later. 
63 

(1) Locate the pressure sensor(s) in a position that provides a representative measurement of the 

pressure and locate the liquid seal level monitor in a position that provides a representative 

measurement of the water column height. 

(2) Minimize or eliminate pulsating pressure, vibration and internal and external corrosion. 

(3) Use a pressure sensor and level monitor with a minimum tolerance of 1.27 centimeters of 

water. 

(4) Using a manometer, check pressure sensor calibration quarterly. 

(5) Conduct calibration checks any time the pressure sensor exceeds the manufacturer's specified 

maximum operating pressure range or install a new pressure sensor. 

(6) In a cascaded flare system that employs multiple secondary flares, pressure and liquid level 

monitoring is required only on the first secondary flare in the system (i.e., the secondary flare 

with the lowest pressure release set point). 

(7) This alternative monitoring option may be elected only for flares with four or fewer pressure 

exceedances required to be reported under §60.108a(d)(5) (“reportable pressure exceedances”) in 

any 365 consecutive calendar days. Following the fifth reportable pressure exceedance in a 365-

day period, the owner or operator must comply with the sulfur and flow monitoring requirements 

of paragraphs (e) and (f) of this section as soon as practical, but no later than 180 days after the 

fifth reportable pressure exceedance in a 365-day period. 

(h) Alternative monitoring for flares located in the BAAQMD or SCAQMD. An affected flare 

subject to this subpart located in the BAAQMD may elect to comply with the monitoring 

requirements in both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 

as an alternative to complying with the requirements of paragraphs (e) and (f) of this section. An 

affected flare subject to this subpart located in the SCAQMD may elect to comply with the 

monitoring requirements in SCAQMD Rule 1118 as an alternative to complying with the 

requirements of paragraphs (e) and (f) of this section. 

(i) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess emissions 

for fuel gas combustion devices subject to the emissions limitations in §60.102a(g) and flares 

subject to the concentration requirement in §60.103a(h) are defined as specified in paragraphs 

(i)(1) through (5) of this section. Determine a rolling 3-hour or a rolling daily average as the 

arithmetic average of the applicable 1-hour averages (e.g., a rolling 3-hour average is the 

arithmetic average of three contiguous 1-hour averages). Determine a rolling 30-day or a rolling 

365-day average as the arithmetic average of the applicable daily averages (e.g., a rolling 30-day 

average is the arithmetic average of 30 contiguous daily averages). 

(1) SO2 or H2S limits for fuel gas combustion devices. (i) If the owner or operator of a fuel gas 

combustion device elects to comply with the SO2 emission limits in §60.102a(g)(1)(i), each 

rolling 3-hour period during which the average concentration of SO2 as measured by the SO2

continuous monitoring system required under paragraph (a)(1) of this section exceeds 20 ppmv, 
64 

and each rolling 365-day period during which the average concentration of SO2 as measured by 

the SO2 continuous monitoring system required under paragraph (a)(1) of this section exceeds 8 

ppmv. 

(ii) If the owner or operator of a fuel gas combustion device elects to comply with the H2S 

concentration limits in §60.102a(g)(1)(ii), each rolling 3-hour period during which the average 

concentration of H2S as measured by the H2S continuous monitoring system required under 

paragraph (a)(2) of this section exceeds 162 ppmv and each rolling 365-day period during which 

the average concentration as measured by the H2S continuous monitoring system under 

paragraph (a)(2) of this section exceeds 60 ppmv. 

(iii) If the owner or operator of a fuel gas combustion device becomes subject to the 

requirements of daily stain tube sampling in paragraph (b)(3)(iii) of this section, each day during 

which the daily concentration of H2S exceeds 162 ppmv and each rolling 365-day period during 

which the average concentration of H2S exceeds 60 ppmv. 

(2) H2S concentration limits for flares. (i) Each rolling 3-hour period during which the average 

concentration of H2S as measured by the H2S continuous monitoring system required under 

paragraph (a)(2) of this section exceeds 162 ppmv. 

(ii) If the owner or operator of a flare becomes subject to the requirements of daily stain tube 

sampling in paragraph (b)(3)(iii) of this section, each day during which the daily concentration of 

H2S exceeds 162 ppmv. 

(3) Rolling 30-day average NOX limits for fuel gas combustion devices. Each rolling 30-day 

period during which the average concentration of NOX as measured by the NOX continuous 

monitoring system required under paragraph (c) or (d) of this section exceeds: 

(i) For a natural draft process heater, 40 ppmv and, if monitored according to §60.107a(d), 0.040 

lb/MMBtu; 

(ii) For a forced draft process heater, 60 ppmv and, if monitored according to §60.107a(d), 0.060 

lb/MMBtu; and 

(iii) For a co-fired process heater electing to comply with the NOX limit in §60.102a(g)(2)(iii)(A) 

or (g)(2)(iv)(A), 150 ppmv. 

(iv) The site-specific limit determined by the Administrator under §60.102a(i). 

(4) Daily NOX limits for fuel gas combustion devices. Each day during which the concentration 

of NOX as measured by the NOX continuous monitoring system required under paragraph (d) of 

this section exceeds the daily average emissions limit calculated using Equation 3 in 

§60.102a(g)(2)(iii)(B) or Equation 4 in §60.102a(g)(2)(iv)(B). 

(5) Daily O2 limits for fuel gas combustion devices. Each day during which the concentration of 

O2 as measured by the O2 continuous monitoring system required under paragraph (c)(6) or 
65 

(d)(8) of this section exceeds the O2 operating limit or operating curve determined during the 

most recent biennial performance test. 

§ 60.108a Recordkeeping and reporting requirements. 

(a) Each owner or operator subject to the emissions limitations in §60.102a shall comply with the 

notification, recordkeeping, and reporting requirements in §60.7 and other requirements as 

specified in this section. 

(b) Each owner or operator subject to an emissions limitation in §60.102a shall notify the 

Administrator of the specific monitoring provisions of §§60.105a, 60.106a and 60.107a with 

which the owner or operator intends to comply. Each owner or operator of a co-fired process 

heater subject to an emissions limitation in §60.102a(g)(2)(iii) or (iv) shall submit to the 

Administrator documentation showing that the process heater meets the definition of a co-fired 

process heater in §60.101a. Notifications required by this paragraph shall be submitted with the 

notification of initial startup required by §60.7(a)(3). 

(c) The owner or operator shall maintain the following records: 

(1) A copy of the flare management plan. 

(2) Records of information to document conformance with bag leak detection system operation 

and maintenance requirements in §60.105a(c). 

(3) Records of bag leak detection system alarms and actions according to §60.105a(c). 

(4) For each FCCU and fluid coking unit subject to the monitoring requirements in 

§60.105a(b)(1), records of the average coke burn-off rate and hours of operation. 

(5) For each fuel gas stream to which one of the exemptions listed in §60.107a(a)(3) applies, 

records of the specific exemption determined to apply for each fuel stream. If the owner or 

operator applies for the exemption described in §60.107a(a)(3)(iv), the owner or operator must 

keep a copy of the application as well as the letter from the Administrator granting approval of 

the application. 

(6) Records of discharges greater than 500 lb SO2 in any 24-hour period from any affected flare, 

discharges greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion 

device or sulfur recovery plant and discharges to an affected flare in excess of 500,000 scf above 

baseline in any 24-hour period as required by §60.103a(c). If the monitoring alternative provided 

in §60.107a(g) is selected, the owner or operator shall record any instance when the flare gas line 

pressure exceeds the water seal liquid depth, except for periods attributable to compressor 

staging that do not exceed the staging time specified in §60.103a(a)(3)(vii)(C). The following 

information shall be recorded no later than 45 days following the end of a discharge exceeding 

the thresholds: 

(i) A description of the discharge. 
66 

(ii) The date and time the discharge was first identified and the duration of the discharge. 

(iii) The measured or calculated cumulative quantity of gas discharged over the discharge 

duration. If the discharge duration exceeds 24 hours, record the discharge quantity for each 24-

hour period. For a flare, record the measured or calculated cumulative quantity of gas discharged 

to the flare over the discharge duration. If the discharge duration exceeds 24 hours, record the 

quantity of gas discharged to the flare for each 24-hour period. Engineering calculations are 

allowed for fuel gas combustion devices, but are not allowed for flares, except for those 

complying with the alternative monitoring requirements in §60.107a(g). 

(iv) For each discharge greater than 500 lb SO2 in any 24-hour period from a flare, the measured 

total sulfur concentration or both the measured H2S concentration and the estimated total sulfur 

concentration in the fuel gas at a representative location in the flare inlet. 

(v) For each discharge greater than 500 lb SO2 in excess of the applicable short-term emissions 

limit in §60.102a(g)(1) from a fuel gas combustion device, either the measured concentration of 

H2S in the fuel gas or the measured concentration of SO2 in the stream discharged to the 

atmosphere. Process knowledge can be used to make these estimates for fuel gas combustion 

devices, but cannot be used to make these estimates for flares, except as provided in 

§60.107a(e)(4). 

(vi) For each discharge greater than 500 lb SO2 in excess of the allowable limits from a sulfur 

recovery plant, either the measured concentration of reduced sulfur or SO2 discharged to the 

atmosphere. 

(vii) For each discharge greater than 500 lb SO2 in any 24-hour period from any affected flare or 

discharge greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion 

device or sulfur recovery plant, the cumulative quantity of H2S and SO2 released into the 

atmosphere. For releases controlled by flares, assume 99-percent conversion of reduced sulfur or 

total sulfur to SO2 . For fuel gas combustion devices, assume 99-percent conversion of H2S to 

SO2. 

(viii) The steps that the owner or operator took to limit the emissions during the discharge. 

(ix) The root cause analysis and corrective action analysis conducted as required in §60.103a(d), 

including an identification of the affected facility, the date and duration of the discharge, a 

statement noting whether the discharge resulted from the same root cause(s) identified in a 

previous analysis and either a description of the recommended corrective action(s) or an 

explanation of why corrective action is not necessary under §60.103a(e). 

(x) For any corrective action analysis for which corrective actions are required in §60.103a(e), a 

description of the corrective action(s) completed within the first 45 days following the discharge 

and, for action(s) not already completed, a schedule for implementation, including proposed 

commencement and completion dates. 
67 

(xi) For each discharge from any affected flare that is the result of a planned startup or shutdown 

of a refinery process unit or ancillary equipment connected to the affected flare, a statement that 

a root cause analysis and corrective action analysis are not necessary because the owner or 

operator followed the flare management plan. 

(7) If the owner or operator elects to comply with §60.107a(e)(2) for a flare, records of the H2S 

and total sulfur analyses of each grab or integrated sample, the calculated daily total sulfur-toH2S ratios, the calculated 10-day average total sulfur-to-H2S ratios and the 95-percent confidence 

intervals for each 10-day average total sulfur-to-H2S ratio. 

(d) Each owner or operator subject to this subpart shall submit an excess emissions report for all 

periods of excess emissions according to the requirements of §60.7(c) except that the report shall 

contain the information specified in paragraphs (d)(1) through (7) of this section. 

(1) The date that the exceedance occurred; 

(2) An explanation of the exceedance; 

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

affected facility or control system; and 

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

(5) The information described in paragraph (c)(6) of this section for all discharges listed in 

paragraph (c)(6) of this section. For a flare complying with the monitoring alternative under 

§60.107a(g), following the fifth discharge required to be recorded under paragraph (c)(6) of this 

section and reported under this paragraph, the owner or operator shall include notification that 

monitoring systems will be installed according to §60.107a(e) and (f) within 180 days following 

the fifth discharge. 

(6) For any periods for which monitoring data are not available, any changes made in operation 

of the emission control system during the period of data unavailability which could affect the 

ability of the system to meet the applicable emission limit. Operations of the control system and 

affected facility during periods of data unavailability are to be compared with operation of the 

control system and affected facility before and following the period of data unavailability. 

(7) A written statement, signed by a responsible official, certifying the accuracy and 

completeness of the information contained in the report. 

§ 60.109a Delegation of authority. 

(a) This subpart can be implemented and enforced by the U.S. EPA or a delegated authority such 

as a State, local, or tribal agency. You should contact your U.S. EPA Regional Office to find out 

if this subpart is delegated to a State, local, or tribal agency within your State. 
68 

(b) In delegating implementation and enforcement authority of this subpart to a state, local or 

tribal agency, the approval authorities contained in paragraphs (b)(1) through (4) of this section 

are retained by the Administrator of the U.S. EPA and are not transferred to the state, local or 

tribal agency. 

(1) Approval of a major change to test methods under §60.8(b). A “major change to test method” 

is defined in 40 CFR 63.90. 

(2) Approval of a major change to monitoring under §60.13(i). A “major change to monitoring” 

is defined in 40 CFR 63.90. 

(3) Approval of a major change to recordkeeping/reporting under §60.7(b) through (f). A “major 

change to recordkeeping/reporting” is defined in 40 CFR 63.90. 

(4) Approval of an application for an alternative means of emission limitation under §60.103a(j) 

of this subpart. 

Table 1 to Subpart Ja of Part 60—Molar Exhaust Volumes and Molar Heat Content of 

Fuel Gas Constituents 

Constituent 

MEVa

dscf/mol 

MHCb

Btu/mol 

Methane (CH4) 7.29 842

Ethane (C2H6) 12.96 1,475

Hydrogen (H2) 1.61 269

Ethene (C2H4) 11.34 1,335

Propane (C3H8) 18.62 2,100

Propene (C3H6) 17.02 1,947

Butane (C4H10) 24.30 2,717

Butene (C4H8) 22.69 2,558

Inerts 0.85 0

a

 MEV = molar exhaust volume, dry standard cubic feet per gram-mole (dscf/g-mol) at standard 

conditions of 68 °F and 1 atmosphere. 

b

 MHC = molar heat content (higher heating value basis), Btu per gram-mole (Btu/g-mol).