May 15, 2012 

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

Insertions are shown in bold blue text 

Deletions are shown in red strikeout text

1 

Title 40: Protection of Environment 

PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

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

Reconstruction, or Modification Commenced After May 14, 2007 

Source: 73 FR 35867, June 24, 2008, unless otherwise noted. 

§ 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 flares and 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, the provisions of this subpart apply only to affected facilities under 

paragraph (a) of this section which commence construction, modification, or reconstruction after 

May 14, 2007. 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.

(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 supersede the provisions in §60.14 with respect to flares. For the purposes of 

this subpart, under §60.14, a modification to a flare occurs as provided in paragraphs (c)(1) or 

(2) of this section.if:

(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); or. However, the connections described in paragraphs 

(c)(1)(i) through (vi) 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). 
2 

(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 May 14, 2007. For purposes of this paragraph, “commenced” means 

that an owner or operator has undertaken a continuous program of component replacement or 

that an owner or operator has entered into a contractual obligation to undertake and complete, 

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

Effective Date Note: At 73 FR 55752, Sept. 26, 2008, §60.100a(c) was stayed until Dec. 25, 

2008.

§ 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 latent 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 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 
3 

(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 to an affected flare 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 aone 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. 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; process piping and associated 

equipment such as pumps, valves and connectors; 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.

Flare means an open-flame fuel gas combustion device that uses an uncontrolled volume of 

air toused for burning off unwanted gases or flammable gas and liquids. The flare includes the 

foundation, flare tip, structural support, burner, igniter, flare controls, including air injection or 

steam injection systems, flame arrestors, knockout pots, piping and the flare gas header systems.

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. 
4 

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 one or morea refinery process units 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 one or morea refinery process units 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 

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 fromcomply with the wastewater treatment units other than 

those processing sour waterprovisions in §60.692, 40 CFR 61.343 through 61.348, 40 CFR 
5 

63.647, or the marine tank vessel loading operations or asphalt processing units (i.e., asphalt 

blowing stills)provisions in 40 CFR 63.562 or 40 CFR 63.651. 

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

flares, used to combust fuel gas. For the purposes of this subpart, fuel gas combustion device

does not include flares orexcept 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. 

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 
6 

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. 

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 H2SHS2 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. 

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. 

Effective Date Note: At 73 FR 55752, Sept. 26, 2008, in §60.101a, the definition of “flare” 

was stayed until Dec. 25, 2008.

§ 60.102a Emissions limitations. 
7 

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

the emissions limitations in paragraphs (b) through (ih) 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 kilogram per Megagram (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 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 

(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 
8 

(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 capacity greater than 20 long tons per day (LTD): 

(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 in excess of 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 

(ii) For 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 in 

excess of 300 ppmv by volume of reduced sulfur compounds and 10 ppmv by volume of 

H2Shydrogen sulfide (HS2), each calculated as ppmv SO2 by volume (dry basis) at 0-zero 

percent excess air; or 
9 

(iii) 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 capacity of 20 LTD or less: 

(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 in excess of 2,500 ppm 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 

(ii) For 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 in 

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

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

air; or 

(iii) 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) Periods of maintenance of the sulfur pit, during which the emission limits in paragraphs (f)(1) 

and (2) shall not apply, 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. 
10 

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

emission limits in paragraphs (g)(1) andthrough (23) of this section. 

(1) Except as provided in (g)(1)(iii) of this section, fFor 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. 

(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). 

(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-day24-

hour 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 
11 

(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: 
12 

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; 

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. 

(3) Except as provided in paragraphs (h) and (i) of this section, the owner or operator of an 

affected flare shall not allow flow to each affected flare during normal operations of more than 

7,080 standard cubic meters per day (m3/day) (250,000 standard cubic feet per day (scfd)) on a 

30-day rolling average. The owner or operator of a newly constructed or reconstructed flare shall 

comply with the emission limit in this paragraph by no later than the date that flare becomes an 

affected flare subject to this subpart. The owner or operator of a modified flare shall comply with 

the emission limit in this paragraph by no later than 1 year after that flare becomes an affected 

flare subject to this subpart.

(h) [Reserved]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 

paragraph (g) of this section.

(i) In periods of fuel gas imbalance that are described in the flare management plan required in 

section 60.103a(a), compliance with the emission limit in paragraph (g)(3) of this section is 

demonstrated by following the procedures and maintaining records described in the flare 

management plan to document the periods of excess fuel gas.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., ultralow 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 
13 

(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 modificationbased 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. 

(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. 
14 

(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. 

(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.

Effective Date Note: At 73 FR 55752, Sept. 26, 2008, §60.102a(g) was stayed until Dec. 25, 

2008.

§ 60.103a Work practice standards. 

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

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

plan. 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 specified in paragraph (b) of 

this sectionthat flare becomes an affected flare subject to this subpart. The owner or operator of 

a modified flare must develop and implement the flare management plan by no later than 1 year 

after the flare becomes an affected flare subject to this subpart. The flare management plan 

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

(1) A listing ofdiagram illustrating all refinery process units, ancillary equipment, and fuel 

gas systems connectedions 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 
15 

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). 

(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, 
16 

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, provideMethods for monitoring flow rate to the flare, 

including 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. for flare gas monitoring devices;

(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. 

(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 
17 

(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.

(53) Procedures to minimize or eliminate discharges to the flare gas system during the planned 

start-up 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.;

(4) Procedures to conduct a root cause analysis of any process upset or malfunction that causes a 

discharge to the flare in excess of 14,160 m3 /day (500,000 scfd);

(65) 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.; and

(6) Explanation of procedures to follow during times that the flare must exceed the limit in 

§60.102a(g)(3) (e.g., keep records of natural gas purchases to support assertion that the refinery 

is producing more fuel gas than needed to operate the processes).(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 (4) 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 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 [the date 3 years from the date of publication of these amendments in the Federal 

Register] 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). 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 
18 

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. 

(cb) Except as provided in paragraphs (f) and (g) of this section, eEach 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.of any emission limit exceedance or 

process start-up, shutdown, upset, or malfunction

(1) For a flare: 

(i) Any time the SO2 emissions exceed that causes a discharge to the atmosphere in excess of

227 kilograms per day (kg/day) (500 lb per day (lb/day)) in any 24-hour period; orof SO2. 

(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 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. 

For any root cause analysis performed, the owner or operator shall record the identification of the 

affected facility, the date and duration of the discharge, the results of the root cause analysis, and 

the action taken as a result of the root cause analysis. (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 
19 

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). 

(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) 
20 

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 [the date 3 years from the date of publication of these amendments in the 

Federal Register] or at startup of the modified flare, whichever is later.The first root cause 

analysis for a modified flare must be conducted no later than the first discharge that occurs after 

the flare has been an affected flare subject to this subpart for 1 year.

(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. 

(ic) 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 

atmosphere.during reactor vessel depressuring Until the coke drum pressure reaches 5 psig, 

the coke drum steamand vent the exhaust gasesmust 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, for combustion in 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: 
21 

(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: 

(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 
22 

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 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 months 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. 

(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 53 of this section: 
23 

c

s sd

K R

c Q E  (Eq. 53) 

Where: 

E = Emission rate of PM, g/kg, lbs per 1,000 lbs (lb/1,000 lbs) 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), [lbs per hour (lbs/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 64 of this section: 

      c r a r CO O K Qoxy Ooxy R KQ CO CO K Q K Q CO % % % 2 % % %  1 2   2  3  2  2  3

 (Eq. 64) 

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)]; 

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); 
24 

%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-dsc-%) [0.0186 (lbmin)/(hr-dscf-%)]; 

K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lbmin)/(hr-dscf)]; 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 75 of this section: 

 

% 2 % % 2 100

79 100 %

CO CO O

Q Oxy Q Q a oxy

r   

     (Eq. 75) 

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); 

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(g)(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). 
25 

(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 86 of this section: 

 

    % 2 20.9

20.9

O C C c adj meas (Eq. 86) 

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; 

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 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. 
26 

(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 97 of this section: 















 

st

st PMEmR Opacity Limit Opacity x

1lb /1,000 lb coke burn (Eq. 97) 

Where: 

Opacity limit = Maximum permissible hourly average opacity, percent, or 10 percent, 

whichever is greater; 

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

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

(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), 

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) and §60.102a(f)(2)(ii) 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. 
27 

(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 86 of this section to adjust pollutant concentrations 

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

(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. 
28 

(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. 

(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 
29 

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 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) 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; 
30 

(4) EPA Method 11, 15, or 15A of Aappendix A–5 to part 60 or EPA Method 16 of Aappendix 

A–6 to part 60 for determining the H2S concentration for affected plants using an H2S monitor as 

specified in §60.107a(a)(2). 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 Aappendix 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. 

(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) 

andthrough (23) 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 paragraph (b)(1)(i) through (viii) 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 voltage to the entire 

system. 
31 

(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 alternativealterative 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. 

(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 

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 
32 

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. 

(i) The owner or operator shall install, operate, and maintain each monitor according to 

Performance Specifications 3 and 4 of Aappendix B to part 60. 

(ii) The owner or operator shall conduct performance evaluations of each CO2, O2, and CO 

monitor according to the requirements in §60.13(c) and Performance Specifications 3 and 4 of 

Aappendix B to part 60. The owner or operator shall use EPA Method 3 of Aappendix 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) 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. 

(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 
33 

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 

(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; 
34 

(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. 

(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 
35 

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. 

(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 
36 

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. 

(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). 
37 

(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 ppm 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 ppm CO instead of 1,000 ppm, and the relative accuracy 

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

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. 

(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. 
38 

(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. 

(2) 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. 

(3) 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. 

(4) 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. 

(5) Except as provided in paragraph (i)(7) of this section, aAll 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. 

(6) All 1-hour periods during which the average CO concentration as measured by the CO 

continuous monitoring system under §60.105a(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. 
39 

(i) The span values for this monitor are two times the applicable SO2 emission limit and between 

10 and 25 percent O2, inclusive. 

(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. 

(2) For sulfur recovery plants that are subject to the reduced sulfur compound and H2S 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, and O2 emissions into the atmosphere. The reduced sulfur 

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

(i) The span values for this monitor are two times the applicable reduced sulfur emission limit, 

two times the H2S emission limit, and between 10 and 25 percent O2, inclusive. 

(ii) The owner or operator shall install, operate, and maintain each reduced sulfur 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 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. 

(vi) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. 

(vii) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive. 
40 

(viii) 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. 

(ix) 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 monitor required in paragraph (a)(2) of this section, the owner 

or operator shall 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 limit. 

(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. 

(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. 

(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. 
41 

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 (as SO2) as 

measured by the reduced sulfur continuous monitoring system required under paragraph (a)(2) of 

this section exceeds the applicable emission limit; or 

(3) All 12-hour periods during which the average concentration of H2S as measured by the H2S 

continuous monitoring system required under paragraph (a)(2) 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 the requirements in §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

for SO2 emissions or. 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 for H2S emissions. 

(1) The owner or operator of a fuel gas combustion device that elects to comply withsubject to

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 

ppm 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 ppm, whichever is greater, and the calibration drift limit 

shall be 5 percent of the established span value. 
42 

(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. 

(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 withsubject to

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 Aappendix B to part 60. The span value for this instrument is 

300320 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 
43 

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) 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). 

(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§60.102a(h) and fuel gas streams combusted in a 

process heater, or 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. 

(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); 
44 

(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 ppm 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) 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. 

(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. 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 
45 

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 thesubject to 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, tThe owner or operator shall install, 

operate, and maintain each NOX monitor according to Performance Specification 2 of Aappendix 

B to part 60. The span value of this NOX monitor must be between 2 and 3 times the 

applicable emissions limit, inclusiveis 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 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, (LNB) or ultra low-NOX burners (ULNB) may elect to 

comply withis not subject to the monitoring requirements in paragraphs (c)(1) through (5) of this 

section. or, alternatively, tThe owner or operator of such a process heater shallmust conduct 

biennial performance tests according to the requirements in §60.104a(i), establish a 
46 

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 valuebased 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. 

(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 10 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). 
47 

 

 





  

i i

i i

d X MHC

X MEV

F

1,000,000

 (Eq. 10) 

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, Standard Method for Analysis of Natural Gas by Gas 

Chromatography (incorporated by reference—see §60.17); 

(iii) ASTM D1946–90 (Reapproved 2006), Standard Method for Analysis of Reformed Gas 

by Gas Chromatography (incorporated by reference—see §60.17); 

(iv) ASTM D6420–99 (Reapproved 2004), Standard Test Method for Determination of 

Gaseous Organic Compounds by Direct Interface Gas Chromatography-Mass 

Spectrometry (incorporated by reference—see §60.17); 

(v) Gas Processors Association Standard 2261-00, Analysis for Natural Gas and Similar 

Gaseous Mixtures by Gas Chromatography (2000) (incorporated by reference—see 

§60.17); or 

(vi) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography (incorporated by 

reference—see §60.17). 

(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° 

Fahrenheit 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° 

Fahrenheit and 1 atmosphere). The owner or operator shall conduct performance 
48 

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, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and 

Venturi (incorporated by reference—see §60.17); 

(iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008), Measurement of Gas Flow by Turbine 

Meters (incorporated by reference—see §60.17); 

(iv) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of Fluid Flow in Pipes Using 

Vortex Flowmeters (incorporated by reference—see §60.17); 

(v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of Gas Flow by Means of 

Critical Flow Venturi Nozzles (incorporated by reference—see §60.17); 

(vi) ASME MFC-11M-2006, Measurement of Fluid Flow by Means of Coriolis Mass 

Flowmeters (incorporated by reference—see §60.17); 

(vii) ASME MFC-14M-2003, Measurement of Fluid Flow Using Small Bore Precision 

Orifice Meters (incorporated by reference—see §60.17); 

(viii) ASME MFC-18M-2001, Measurement of Fluid Flow Using Variable Area Meters 

(incorporated by reference—see §60.17); 

(ix) American Gas Association (AGA) Report No. 3: Orifice Metering for Natural Gas and 

Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines 

(1990) (incorporated by reference—see §60.17); 

(x) AGA Report No. 3: Orifice Metering for Natural Gas and Other Related Hydrocarbon 

Fluids, Part 2: Specification and Installation Requirements (2000) (incorporated by 

reference—see §60.17); 

(xi) AGA Report No. 11: Measurement of Natural Gas by Coriolis Meter (2003) 

(incorporated by reference—see §60.17); 

(xii) American Gas Association Transmission Measurement Committee Report No. 7: 

Measurement of Gas by Turbine Meters (Revised February 2006) (incorporated by 

reference—see §60.17); and 

(xiii) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, 

Chapter 22-Testing Protocol, Section 2-Differential Pressure Flow Measurement Devices, 

First Edition, August 2005 (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 
49 

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”); 

(ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006), Measurement of Liquid Flow in Closed 

Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference—see 

§60.17); 

(iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement of Liquid Flow in 

Closed Conduits by Weighing Method (incorporated by reference—see §60.17); 

(iv) ASME MFC-16-2007, Measurement of Liquid Flow in Closed Conduits with 

Electromagnetic Flowmeters (incorporated by reference—see §60.17); 

(v) ASME MFC-22-2007, Measurement of Liquid by Turbine Flowmeters (incorporated by 

reference—see §60.17); or 

(vi) ISO 8316: Measurement of Liquid Flow in Closed Conduits—Method by Collection of 

the Liquid in a Volumetric Tank (1987–10-01)—First Edition (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), Standard Test Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference—see §60.17). 

(ii) ASTM D1826-94 (Reapproved 2003), Standard Test Method for Calorific (Heating) 

Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated 

by reference—see §60.17). 

(iii) ASTM D1945-03, Standard Method for Analysis of Natural Gas by Gas 

Chromatography (incorporated by reference—see §60.17). 

(iv) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis of Reformed Gas 

by Gas Chromatography (incorporated by reference—see §60.17). 
50 

(v) ASTM D3588-98 (Reapproved 2003), Standard Practice for Calculating Heat Value, 

Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by 

reference—see §60.17). 

(vi) ASTM D4809-06, Standard Test Method for Heat of Combustion of Liquid 

Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by 

reference—see §60.17). 

(vii) ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of 

Gases in Natural Gas Range by Stoichiometric Combustion (incorporated by reference—

see §60.17). 

(viii) Gas Processors Association Standard 2172-09, Calculation of Gross Heating Value, 

Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for 

Natural Gas Mixtures for Custody Transfer (2009) (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 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. 

(ed) Sulfur monitoring for assessing root cause analysis threshold for affected flares. Except as 

described in paragraphs (e)(4) and (h) of this section, tThe owner or operator of an affected 

flare subject to §60.103a(bc) 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.install, operate, calibrate, and maintain an instrument for continuously 

monitoring and recording the concentration of reduced sulfur in flare gas. 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 
51 

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, tThe 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 sectionshall install this 

instrument by no later than [the date 3 years from the date of publication of these 

amendments in the Federal Register] or upon startup of the modified flare, whichever is 

later1 year after the flare becomes an affected flare subject to this subpart.

(1) Total reduced sulfur monitoring requirements. The owner or operator shall install, 

operate, calibrate and maintain an instrument for continuously monitoring and recording 

the concentration of total reduced sulfur in gas discharged to the flare. 

(i1) The owner or operator shall install, operate, and maintain each total reduced sulfur 

monitorCEMS according to Performance Specification 5 of Aappendix 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.

(ii2) 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 

Aappendix B to part 60. For flares that routinely have flow, tThe owner or operator of each 

total reduced sulfur monitor shall use EPA Methods 15 or 15A of Aappendix 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 Aappendix 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.

(iii3) The owner or operator shall comply with the applicable quality assurance procedures in 

Aappendix 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 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 
52 

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, the 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, “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. 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) of this subpart, 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) “Standard Test Method for Total Sulfur in 

Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry” (incorporated by 

reference—see §60.17) or ASTM Method D5504-08 “Standard Test Method for 

Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas 

Chromatography and Chemiluminescence” (incorporated by reference—see §60.17). 

(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. 
53 

(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 11 of this section. 

AR Ratio SDev  Avg  2.262 (Eq. 11) 

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 (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 12 of this section. 

TS FG  CSO2  Fd  HHVFG (Eq. 12) 

Where: 
54 

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. 

(fe) Flow monitoring for flares. Except as provided in paragraphs (f)(2) and (h) of this 

section, tThe owner or operator of an affected flare subject to §60.103a(c) through 

(e)§60.102a(g)(3) shall install, operate, calibrate, and maintain, in accordance with the 

specifications in paragraph (f)(1) of this section, a CPMS to measure and record the exhaust 

gas flow rate of gas discharged to the flare. If a flow monitor is not already in place, tThe 

owner or operator of a modified flare shall comply with the requirements of this 

paragraphinstall this instrument by no later than [the date 3 years from the date of 

publication of these amendments in the Federal Register] or upon startup of the modified 

flare, whichever is later1 year after the flare becomes an affected flare subject to this subpart.
55 

(1) The CPMS must be able to correct for the temperature and pressure of the system and output 

flow in standard conditions as defined in §60.2.

(12) The owner or operator shall install, calibrate, operate, and maintain each flow 

monitorCPMS 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 [the date 3 

years from the date of publication of these amendments in the Federal Register] or upon 

startup of the modified flare, whichever is later. 
56 

(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. 

(if) 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 (if)(1) through (54) of this section.

Note: Determine all averages as the arithmetic average of the applicable 1-hour averages, e.g., 

determine thea rolling 3-hour or a rolling daily average as the arithmetic average of the 

applicable three contiguous 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). 
57 

(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), 

eachAll rolling 3-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 20 

ppmv, and eachall rolling 365-day 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 8 ppmv.; or

(ii2) 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), eachAll rolling 3-hour periods 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, all days in which the concentration of 

H2S as measured by daily stain tube sampling required under paragraph (b)(3)(iii) of this section 

exceeds 162 ppmv, and eachall rolling 365-day periods 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. EachAll rolling 30-

day24-hour periods 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) All rolling 30-day periods during which the average flow rate to an affected flare as measured 

by the monitoring system required under paragraph (e) of this section exceeds 250,000 

scfd.Daily NOX limits for fuel gas combustion devices. Each day during which the 
58 

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) of this section exceeds the O2 operating limit or operating curve determined during 

the most recent biennial performance test.

Effective Date Note: At 73 FR 55752, Sept. 26, 2008, §60.107a (d) and (e) were stayed until

Dec. 25, 2008.

§ 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 seeks 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 cofired 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. and each root cause analysis of a discharge;

(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) The owner or operator shall record and maintain rRecords of discharges greater than 500 

lb/day 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 scfd above baseline in any 24-hour period 
59 

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). These following 

informationrecords shall be recorded no later than 45 days following the end of a discharge 

exceeding the thresholdsinclude: 

(i) A description of the discharge. 

(ii) For discharges greater than 500 lb/day SO2, tThe 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

other than flares, except for those complying with the alternative monitoring requirements 

in §60.107a(g). 

(iv) For each discharges greater than 500 lb/day SO2 in any 24-hour period from a flare, the 

measured total sulfuror estimated concentration or both the measuredof H2S concentration 

and the estimated total sulfur concentration in the fuel gas at a representative location in 

the flare inlet, TRS and SO2 of the stream discharged. Process knowledge can be used to make 

these estimates for fuel gas combustion devices other than flares.

(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 discharges greater than 500 lb/day 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 other 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. 
60 

(vix) TheResults of any root -cause analysis and corrective action analysis conducted as 

required in §60.103a(a)(4) and §60.103a(db), 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. 

(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-to-H2S 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) A root-cause summary report that provides tThe information described in paragraph (ce)(6) 

of this section for all discharges listed in paragraph (c)(6) of this sectionfor which a root-cause 

analysis was required by §60.103a(a)(4) and §60.103a(b). 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. 
61 

(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. 

(b) In delegating implementation and enforcement authority of this subpart to a sState, local, or 

tribal agency, the approval authorities contained in paragraphs (b)(1) through (43) of this section 

are retained by the Administrator of the U.S. EPA and are not transferred to the sState, 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. 

Tables to Subpart Ja of Part 60 

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° Farhenheit and 1 atmosphere 

b

 MHC = molar heat content (higher heating value basis), Btu per gram-mole (Btu/g-mol)