Ken Hustvedt/RTP/ 

USEPA/US 

01/29/2009 01:44 PM

To: eric scheaffer, Jim Pew, John Walke, 

mdouglas@4cleanair.org 

cc 

Subject: Fw: Red-Line Version of NSPS Ja Re-Proposal

Industry had asked for a complied amended nsps subpart Ja and I wanted to make it available to you also 

since the docket isn't always the best way to communicate info quickly, 

Please pass along to others. 

kc hustvedt 

----- Forwarded by Ken Hustvedt/RTP/USEPA/US on 01/29/2009 01:32 PM ----- 

Ken Hustvedt/RTP/ 

USEPA/US 

01/29/2009 01:32 PM

To: "Ron Chittim" <Chittim@api.org>, John Wagner, Bill 

Wehrum 

cc: Bob Lucas/RTP/USEPA/US@EPA, Brenda 

Shine/RTP/USEPA/US@EPA 

Subject: Re: Red-Line Version of NSPS Ja Re-Proposal

better late than never? 

we pulled this together and did some review - we believe it is an accurate compilation but cannot 

guarantee it. 

kch 

"Ron Chittim" 

<Chittim@api.org> 

12/19/2008 11:07 AM

To: Ken Hustvedt/RTP/USEPA/US@EPA, Brenda 

Shine/RTP/USEPA/US@EPA, Bob 

Lucas/RTP/USEPA/US@EPA 

cc: 

Subject: Red-Line Version of NSPS Ja Re-Proposal

Is there a chance that you have the June 24, 2008 final rule with the Dec. 2008 proposal revisions 

incorporated (e.g., in a red-line or track changes format)? Or a version that has all the re-proposal 

revisions incorporated? Such a document would make the review process easier. Thanks. 

 

Happy Holidays! 

 

Ron Chittim 

API 

1220 L Street, NW 

Washington, D.C. 20005 

202/682-8176 

chittim@api.org 
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, 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. 

(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, a 

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

(1) Any new piping from a refinery process unit or fuel gas system is physically connected to the 

flare (e.g., for direct emergency relief or some form of continuous or intermittent venting). 

However, the connections described in paragraphs (c)(1)(i) through (iv) 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.

(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) 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.

(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 

Deleted: under §60.14, 

Deleted: if:

Deleted: ; or
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. 

§ 60.101a Definitions. 

Terms used in this subpart are defined in the Clean Air Act, 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.

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

supplied by both gaseous and liquid fuels.

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 consistent with good 

engineering practice to reduce or eliminate the likelihood of recurrence of an event identified by 

a root cause analysis as having caused a discharge of gases to an affected flare in excess of the 

flow rate threshold in §60.103a(a)(4) or the discharge of gases from an affected fuel gas 

combustion device or sulfur recovery plant in excess of the applicable SO2 threshold in 

§60.103a(b).

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 is the best

alternative, including any consideration of cost-effectiveness.

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

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

system reactors. A delayed coking unit consists of the coke drums and associated fractionator.

Flare means an open-flame fuel gas combustion device used for burning off unwanted gas 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 header systems. 

Flare gas recovery system means a system of one or more compressors, piping, and 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 other than a flare.

Deleted: one or more

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

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

to produce a synthetic fuel gas. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

where the combustion air enters the process heater or air preheat.

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

gas includes natural gas when natural gas is 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 anode 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 to comply with the wastewater provisions in 40 CFR 

61.343 though 61.348, 40 CFR 63.647 or the marine tank vessel loading provisions in 40 CFR 

63.652 or 40 CFR 63.651. 

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

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

sulfuric acid. 

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 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.

Deleted: one or more 

Deleted: s

Deleted: one or more 

Deleted: units 

Deleted: the 

Deleted: combined and 

Deleted: §60.692, 

Deleted: through

Deleted: ,

Deleted: 562
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.

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 as a result of 

start-up, shutdown, upset or malfunction. 

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, including but not limited to distillation, cracking, coking, 

reforming, alkylation, isomerization, coke gasification, product loading, sulfur recovery, and 

wastewater treatment. 

Root cause analysis means an assessment to determine the primary cause and any other

significant contributing cause(s), as determined through a process of investigation, of discharge 

of gases to an affected flare in excess of the flow rate threshold in §60.103a(a)(4) or in excess of 

the applicable SO2 threshold in §60.103a(b)(1), or the discharge of gases from an affected fuel 

gas combustion device or sulfur recovery plant in excess of the applicable SO2 thresholds in

§60.103a(b)(2) and (3).

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 refinery process units which recover sulfur from H2S and/or SO2

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

Deleted: HS2
includes sulfur pits used to store the recovered sulfur product, but it does not include secondary 

sulfur storage vessels 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 plants 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. 

§ 60.102a Emissions limitations. 

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

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

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

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

180 days after initial startup, whichever comes first. 

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

discharge into the atmosphere from any FCCU or FCU: 

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

section. 

(i) 1.0 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: 

Deleted: units 

Deleted: h
(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 

(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 of reduced sulfur compounds and 10 ppmv of hydrogen sulfide (H2S), each 

calculated as ppmv SO2 (dry basis) at 0 percent excess air; or 

(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. 

Deleted: ppm by volume

Deleted: ppm by volume

Deleted: HS2

Deleted: ppm

Deleted: by volume 

Deleted: zero
(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. 

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

emission limits in paragraphs (g)(1) and (2) of this section. 

(1) For each fuel gas combustion device, the owner or operator shall comply with either the 

emission limit in paragraph (g)(1)(i) of this section or the fuel gas concentration limit in 

paragraph (g)(1)(ii) of this section. 

(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 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.

An owner or operator of a modified flare that needs to install additional amine scrubbing and 

amine stripping columns to comply with the long-term H2S limit shall comply with the 60 ppmv 

365-day H2S concentration limit no later than 2 years after that flare becomes an affected facility 

subject to this subpart.

(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 (g)(2)(iv).

(i) For each newly constructed, modified, or reconstructed natural draft process heater:

(A) 40 ppmv (dry basis, corrected to 0 percent excess air) determined daily on a 365 successive 

operating day rolling average basis; or

(B) 0.035 pounds per million British thermal units (lb/MMBtu) determined daily on a 365 

successive operating day rolling average basis.

(ii) For each new forced draft process heater:

(A) 40 ppmv (dry basis, corrected to 0 percent excess air) determined daily on a 365 successive 

operating day rolling average basis; or

(B) 0.035 lb/MMBtu determined daily on a 365 successive operating day rolling average basis.

(iii) For each modified or reconstructed forced draft process heater:

Deleted: through (3

Deleted: 24-hour 

Deleted: .
(A) 60 ppmv (dry basis, corrected to 0 percent excess air) determined daily on a 365 successive 

operating day rolling average basis; or

(B) 0.055 lb/MMBtu determined daily on a 365 successive operating day rolling average basis.

(iv) For each co-fired process heater:

(A) 150 ppmv (dry basis, corrected to 0 percent excess air) determined daily on a 365 successive 

operating day rolling average basis (applicable only when the process heater is being co-fired);

or

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

gas gas oil oil

gas gas oil oil

NOx hour Q HHV Q HHV

Q HHV Q HHV

E

+

+ = 0.08 0.27

, (Eq. 3)

Where:

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

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

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

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

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

(h) 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) For a modified or reconstructed process heater that lacks sufficient space to accommodate 

combustion modification-based technology, or for a co-fired process heater, the owner or

operator may petition the Administrator within 90 days after initial startup of the process heater 

for approval of a NOX emissions limit which shall apply specifically to that affected facility. The

petition 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 mission limit in paragraph (g)(2) of this section. If the petition is approved by 

the Administrator, a facility-specific NOX emissions limit will be established at the NOX

emission level achievable when the affected facility is operating in a manner that the 

Administrator determines to be consistent with minimizing NOX emissions. At a minimum, the 

petition shall contain the information described in paragraphs (i)(1) through (4) of this section.

(1) 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 

and combustion conditions, and any other data determined by the Administrator as appropriate.

Deleted: (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.¶

Deleted: 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.¶
(2) An explanation of how the data in paragraph (i)(1) demonstrate that ultra-low NOX burners or 

other means cannot be used to meet the applicable emission limit in paragraph (g)(2) of this

section.

(3) 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.

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

site-specific emissions limit.

§ 60.103a Work practice standards. 

(a) Each 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 that 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 18

months after the flare becomes an affected flare subject to this subpart unless the owner or 

operator of the affected flare commits in writing to install a flare gas recovery system, in which 

case the owner or operator of a modified flare must develop and implement the flare 

management plan by no later than 2 years after the flare becomes an affected flare subject to this

subpart. The plan must include: 

(1) A listing of all refinery process units and fuel gas systems connected to the flare for each 

affected flare and an assessment of whether discharges to affected flares from these process units

and fuel gas systems can be minimized; 

(2) Methods 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; 

(3) Procedures to minimize discharges to the flare gas system during the planned start-up and 

shutdown of the refinery process units that are connected to the affected flare; 

(4) Procedures to conduct a root cause analysis as soon as possible but no later than 45 days after

any discharge to the flare in excess of 14,160 standard cubic meters (m3) (500,000 standard cubic 

feet (scf)) in any 24-hour period. The first root cause analysis and corrective action analysis for a 

modified flare must be conducted no later than the first discharge triggering a root cause analysis 

that occurs after the flare has been an affected flare subject to this subpart for 18 months, unless 

the owner or operator of the affected flare commits in writing to install a flare gas recovery

system, in which case the flow rate root cause analysis for a modified flare must be conducted no 

later than the first discharge triggering a flow rate root cause analysis that occurs after the flare

has been an affected flare subject to this subpart for 2 years;

Deleted: 1 year

Deleted: diagram illustrating

Deleted: connections

Deleted: of

Deleted: process upset or malfunction 

that causes a 

Deleted: /day

Deleted: scfd);
(5) Procedures to conduct a corrective action analysis and implement corrective actions as soon 

as possible but no later than 45 days after a discharge exceeding the flow rate threshold in

paragraph (a)(4) of this section to minimize the recurrence of similarly caused events based on 

the finding of the root cause analysis required under paragraph (a)(4) of this section; and 

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

refinery’s energy needs).

(b) Each owner or operator that operates a fuel gas combustion device or sulfur recovery plant 

subject to this subpart shall conduct a root cause analysis and a corrective action analysis under 

each of the conditions specified in paragraphs (b)(1) through (3) of this section and implement 

corrective actions to minimize the recurrence of a similarly caused event. If a single continuous 

discharge causes emissions to exceed a level specified in paragraphs (b)(1) through (3) of this 

section for 2 or more consecutive 24-hour periods, a single root cause analysis may be

conducted. For any root cause analysis and corrective action analysis performed, and for any 

corrective action taken, the owner or operator shall, as soon as possible but no later than 45 days 

after the discharge, record the identification of the affected facility, the date and duration of the 

discharge, a description of the root cause of the discharge as identified by the root cause analysis, 

results of the corrective action analysis, and the corrective action taken as a result of the root 

cause analysis, as specified in §60.108a(c)(6).

(1) For a flare, conduct a root cause analysis and a corrective action analysis and take corrective 

action each time the SO2 emissions exceed 227 kilograms (kg) (500 pounds (lb)) in any 24-hour

period. The first root cause analysis and corrective action analysis for a modified flare must be 

conducted no later than the first discharge of SO2 triggering a root cause analysis that occurs

after the flare has been an affected flare subject to this subpart for 18 months, unless the owner 

or operator of the affected flare commits in writing to install a flare gas recovery system, in 

which case the root cause analysis for a modified flare must be conducted no later than the first

discharge of SO2 triggering a root cause analysis that occurs after the flare has been an affected 

flare subject to this subpart for 2 years.

(2) For any fuel gas combustion device other than a flare, conduct a root cause analysis and a

corrective action analysis and take corrective action for each exceedance of an applicable shortterm 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

the period of the exceedance.

(3) For a sulfur recovery plant, conduct a root cause analysis and a corrective action analysis and 

take corrective action when the daily 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 emission limit in §60.102a(f)(1) or (2) for the entire 24-hour period.

(c) When an owner or operator implements corrective action(s) as specified by paragraphs (a)(5) 

and (b) of this section, the owner or operator shall, no later than 45 days following the discharge, 

record a description of the action(s) and, if not already completed, a schedule for its (their)

implementation, including proposed commencement and completion dates. If an owner or 

Deleted: reduce flaring in cases of fuel 

gas imbalance (i.e., excess fuel gas for

Deleted: refinery's energy needs)

Deleted: 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).

Deleted: any emission limit exceedance 

or process start-up, shutdown, upset, or 

malfunction that causes a discharge to 

Deleted: atmosphere

Deleted: excess

Deleted: 227 kilograms per day 

(kg/day) (500 lb per day (lb/day)) of SO2.

Deleted: results

Deleted: the

Deleted: . 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.
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.

(d) Each owner or operator of a delayed coking unit shall depressure to 5 lb per square inch 

gauge (psig) during reactor vessel depressuring and vent the exhaust gases to the fuel gas system 

for combustion in a fuel gas combustion device. 

§ 60.104a Performance tests. 

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

plant, 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 4 of this section: 

c

s sd

K R

c Q E = (Eq. 4) 

Where: 

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

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

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

feet per hour; 

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

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

(iii) The coke burn-off rate (Rc) is computed for each run using Equation 5 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. 5) 

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 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); 

Deleted: 3

Deleted: 3

Deleted: s

Deleted: s

Deleted: s

Deleted: s

Deleted: s

Deleted: 4

Deleted: 4
%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 (lb-min)/(hrdscf-%)]; 

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

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

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

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

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

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

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

monitors required in §60.105a(b)(2), if applicable, using Equation 6 of this section: 

( )

100 % 2 % % 2

79 100 %

CO CO O

Q Oxy Q Q a oxy

r − − −

× + − × = (Eq. 6) 

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). 

Deleted: 5

Deleted: 5
(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 7 of this section: 

( )⎥⎦

⎤ ⎢⎣⎡ − = % 2 20.9

20.9

O C C c adj meas (Eq. 7) 

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. 

(3) Compute the site-specific limit using Equation 8 of this section:

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ =

st

st PMEmR

lb lb coke burn Opacity Limit Opacity x 1 /1,000 (Eq. 8)

Deleted: 6

Deleted: 6
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 lb coke burn.

(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. 

(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 7 of this section: 

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. 

(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 7 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 

Deleted: 6
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. 

(j) The owner or operator shall determine compliance with the H2S emissions limit 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 11, 15, or 15A of appendix A–5 to part 60 or Method 16 of appendix 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 

appendix A–5 to part 60. The owner or operator may demonstrate compliance based on the 

mixture used in the fuel gas combustion device or for each individual fuel gas stream used in the 

fuel gas combustion device. 

(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 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) shall comply with the requirements 

in paragraphs (b)(1) and (2) of this section. 

(1) The owner or operator shall install, operate, and maintain continuous parameter monitor 

systems (CPMS) to measure and record operating parameters for each control device according 

to the requirements in paragraph (b)(1)(i) through (iii) 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. 

(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 alterative 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). 

Deleted: through (3
(v) If you use a control device other than an electrostatic precipitator, wet scrubber, fabric filter, 

or cyclone, you may request approval to monitor parameters other than those required in 

paragraph (b)(1) of this section by submitting an alternative monitoring plan to the 

Administrator. The request must include the information in paragraphs (b)(1)(v)(A) through (E) 

of this section. 

(A) A description of each affected facility and the parameter(s) to be monitored to determine 

whether the affected facility will continuously comply with the emission limitations and an 

explanation of the criteria used to select the parameter(s). 

(B) A description of the methods and procedures that will be used to demonstrate that the 

parameter(s) can be used to determine whether the affected facility will continuously comply 

with the emission limitations and the schedule for this demonstration. The owner or operator 

must certify that an operating limit will be established for the monitored parameter(s) that 

represents the conditions in existence when the control device is being properly operated and 

maintained to meet the emission limitation. 

(C) The frequency and content of the recordkeeping, recording, and reporting, if monitoring and 

recording are not continuous. The owner or operator also must include the rationale for the 

proposed monitoring, recording, and reporting requirements. 

(D) Supporting calculations. 

(E) Averaging time for the alternative operating parameter. 

(2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator 

shall install, operate, calibrate, and maintain an instrument for continuously monitoring the 

concentrations of CO2, O2 (dry basis), and if needed, CO in the exhaust gases prior to any control 

or energy recovery system that burns auxiliary fuels. 

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

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

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

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

Appendix B to part 60. The owner or operator shall use Method 3 of Appendix A–3 to part 60 

and 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 

Deleted: Specification

Deleted: appendix

Deleted: Specification

Deleted: appendix

Deleted: appendix
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 

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; 

(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 

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 

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). 

(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. 

(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) All rolling 7-day periods during which the average concentration of SO2 as measured by the 

SO2 CEMS under §60.105a(g) exceeds 50 ppmv, and all rolling 365-day periods during which 

the average concentration of SO2 as measured by the SO2 CEMS exceeds 25 ppmv. 

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

continuous monitoring system under §1A60.105a(h) exceeds 500 ppmv or, if applicable, all 1-

hour periods during which the average temperature and O2 concentration as measured by the 

continuous monitoring systems under §60.105a(h)(4) fall below the operating limits established 

during the performance test. 

§ 60.106a Monitoring of emissions and operations for sulfur recovery plants. 

(a) The owner or operator of a sulfur recovery plant that is subject to the emissions limits in 

§60.102a(f)(1) or §60.102a(f)(2) shall: 

(1) For sulfur recovery plants subject to the SO2 emission limit in §60.102a(f)(1)(i) or 

§60.102a(f)(2)(i), the owner or operator shall install, operate, calibrate, and maintain an 

instrument for continuously monitoring and recording the concentration (dry basis, zero percent 

excess air) of any SO2 emissions into the atmosphere. The monitor shall include an oxygen 

monitor for correcting the data for excess air. 

(i) The span values for 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. 

Deleted: Except as provided in 

paragraph (i)(7) of this section, all
(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. 

(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. 

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. 

(a) Fuel gas combustion devices subject to SO2 or H2S limit. The owner or operator of a fuel gas 

combustion device that is subject to the requirements in §60.102a(g) shall comply with the 

requirements in paragraph (a)(1) of this section for SO2 emissions or paragraph (a)(2) of this 

section for H2S emissions. 

(1) The owner or operator of a fuel gas combustion device subject 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. 

(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 subject to the H2S concentration limits 

in §60.102a(g)(1)(ii) 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. 

(i) The owner or operator shall install, operate, and maintain each H2S monitor according to 

Performance Specification 7 of appendix B to part 60. The span value for this instrument is 300

ppmv H2S. 

(ii) The owner or operator shall conduct performance evaluations for each H2S monitor 

according to the requirements of §60.13(c) and Performance Specification 7 of appendix B to 

part 60. The owner or operator shall use Method 11, 15, or 15A of appendix A–5 to part 60 or 

Deleted: 320
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 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. 

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

paragraph (a)(1) or (2) of this section for fuel gas streams that are exempt under §60.102a(h) and 

fuel gas streams combusted in a process heater or other fuel gas combustion device 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 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) to be considered; 

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

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

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

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

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

demonstrating that the sulfur content is less than 5 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 

(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 

owner or operator must determine a rolling 365-day average using the stain sampling results; an 

average H2S concentration of 5 ppmv must be used for days prior to the operation change. 

(c) Process heaters complying with the NOX concentration-based limit. The owner or operator of 

a process heater subject to the NOX emission limit in §60.102a(g)(2) and electing to comply with 

the applicable emission 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) The owner or operator shall install, operate, and maintain each NOX monitor according to 

Performance Specification 2 of appendix B to part 60. The span value of this NOX monitor must 

be between 2 and 3 times the applicable emission limit, inclusive. 

(2) The owner or operator shall conduct performance evaluations of each NOX monitor according 

to the requirements in §60.13(c) and Performance Specification 2 of appendix B to part 60. The 

owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A–4 to part 60 for 

conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, “Flue 

and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative 

to EPA Method 7 or 7C of appendix A–4 to part 60. 

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

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive. 

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according 

to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. 

Method 3, 3A, or 3B of appendix A–2 to part 60 shall be used for conducting the relative 

accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas 

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

3B of appendix A–2 to part 60. 

(5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 

of appendix F to part 60 for each NOX and O2 monitor, including quarterly accuracy 

determinations for NOX monitors, annual accuracy determinations for O2 monitors, and daily 

calibration drift tests. 

(6) The owner or operator of a process heater that has a rated heating capacity of less than 100 

MMBtu and is equipped with combustion modification-based technology to reduce NOX

emissions (i.e., low-NOX burners, ultra-low-NOX burners) may elect to comply with the 

Deleted: subject to NOX

Deleted: is 200 ppmv NOX

Deleted: lowDeleted: burners (LNB) or ultra

Deleted: (ULNB) is not subject to the 
monitoring requirements in paragraphs (c)(1) through (5) of this section or, alternatively, the 

owner or operator of such a process heater shall conduct biennial performance tests, establish a

maximum excess oxygen concentration operating limit, and comply with the O2 monitoring 

requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. 

(d) Process heaters complying with the NOX heating value-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), (g)(2)(ii)(B), or (g)(2)(iii)(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 emission limit in §60.102a(g)(2) and

electing to comply with the heating value-based limit in §60.102a(g)(2)(iv)(B) shall also 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, an instrument for continuously

monitoring and recording the flow rate of the fuel oil and fuel gas fed to the process heater

according to the monitoring requirements in paragraph (d)(5) and (6) of this section, and shall 

determine the heating value of the fuel oil and fuel gas streams no less frequently than once per 

day according to the monitoring requirements in paragraph (d)(7) of this section. 

(1) 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 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 9 of this section. If a single fuel gas system provides fuel gas to several 

process heaters, the F factor may be determined at a single location in the fuel gas system 

provided it is representative of the fuel gas fed to the affected process heater(s).

( )

∑ ( )

∑

×

× × =

i i

i i

d X MHC

X MEV

F

1,000 ,000

 (Eq. 9)

Where:

Deleted: . The 

Deleted: must 
Fd = F factor on dry basis at 0% excess air.

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. Method 

18 of Appendix A–6 to part 60 shall be used for conducting the relative accuracy evaluations. 

The following methods are acceptable alternatives to EPA Method 18 of Appendix A–2 to part 

60:

(i) ASTM D1945–03, Standard Method for Analysis of Natural Gas by Gas Chromatography 

(incorporated by reference-see §60.17);

(ii) 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);

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

Gas Chromatography (incorporated by reference-see §60.17); and

(iv) Gas Processors Association Standard 2261–00, Analysis for Natural Gas and Similar 

Gaseous Mixtures by Gas Chromatography (incorporated by reference-see §60.17).

(5) The owner or operator shall conduct performance evaluations of each fuel gas flow monitor 

according to the requirements in §60.13(c) and Performance Specification 6 of Appendix B to 

part 60. Method 2, 2A, 2B, 2C, or 2D of Appendix A–2 to part 60 shall be used for conducting 

the relative accuracy evaluations. The following methods are acceptable alternatives to EPA

Method 2, 2A, 2B, 2C, or 2D of Appendix A–2 to part 60:

(i) ASME MFC–3M–1989 (Reaffirmed 1995), Measurement of Fluid Flow in Pipes Using 

Orifice, Nozzle, and Venturi (incorporated by reference-see §60.17);

(ii) ASME MFC–4M–1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters 

(incorporated by reference-see §60.17);

(iii) ASME–MFC–5M–1985, (Reaffirmed 1994), Measurement of Liquid Flow in Closed 

Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference-see §60.17);

(iv) ASME MFC–6M–1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters 

(incorporated by reference-see §60.17);
(v) ASME MFC–7M–1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical 

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

(vi) ASME MFC–9M–1988 (Reaffirmed 2001), Measurement of Liquid Flow in Closed 

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

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

Measurement of Gas by Turbine Meters Second Revision, April 1996 (incorporated by 

reference-see §60.17); and

(viii) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, First 

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

Devices, August 2005 (incorporated by reference-see §60.17).

(6) The owner or operator shall conduct install, operate, and maintain each fuel oil flow monitor 

according to the manufacturer’s recommendations. 

(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 (v) 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).

(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 D4809–06, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference-see §60.17).

(iv) 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).

(v) Gas Processors Association Standard 2172–96, Calculation of Gross Heating Value, Relative 

Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis

(incorporated by reference—see §60.17).

(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, establish a

maximum excess oxygen concentration operating limit, and comply with the O2 monitoring 

requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance.
(e) Sulfur monitoring for affected flares. The owner or operator of an affected flare subject to 

§60.103a(b) shall determine reduced sulfur compound concentrations in accordance with 

paragraph (e)(1) of this section or total sulfur compound concentrations in accordance with either 

paragraph (e)(2) or (3) of this section.

(1) The owner or operator shall install, operate, calibrate, and maintain an instrument for 

continuously monitoring and recording the concentration of reduced sulfur compounds in flare 

gas. The owner or operator of a modified flare must install this instrument no later than 18 

months after the flare becomes an affected flare subject to this subpart unless the owner or 

operator of the affected flare commits in writing to install a flare gas recovery system, in which 

case the owner or operator of a modified flare must install this instrument no later than 2 years 

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

(i) The owner or operator shall install, operate, and maintain each reduced sulfur compounds 

CEMS according to Performance Specification 5 of Appendix B to part 60. 

(ii) The owner or operator shall conduct performance evaluations of each reduced sulfur 

compounds monitor according to the requirements in §60.13(c) and Performance Specification 5 

of Appendix B to part 60. The owner or operator shall use Method 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 comply with the applicable quality assurance procedures in 

Appendix F to part 60 for each reduced sulfur monitor.

(2) The owner or operator shall install, operate, calibrate, and maintain an instrument for 

continuously monitoring and recording the concentration of total sulfur compounds in flare gas. 

The owner or operator of a modified flare must install this instrument no later than 18 months 

after the flare becomes an affected flare subject to this subpart unless the owner or operator of 

the affected flare commits in writing to install a flare gas recovery system, in which case the 

owner or operator of a modified flare must install this instrument no later than 2 years after the 

flare becomes an affected flare subject to this subpart. 

(i) The owner or operator shall install, operate, and maintain each total sulfur compounds CEMS 

according to Performance Specification 5 of Appendix B to part 60.

(ii) The owner or operator shall conduct performance evaluations of each total sulfur compounds 

monitor according to the requirements in §60.13(c) and Performance Specification 5 of 

Appendix B to part 60. The owner or operator shall use Method 16 or 16A 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 16A of Appendix A–6 to part 60.

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

Appendix F to part 60 for each reduced sulfur monitor.

Deleted: d

Deleted: shall

Deleted: by 

Deleted: 1 year

Deleted: 1

Deleted: appendix

Deleted: 2

Deleted: appendix

Deleted: Methods 

Deleted: appendix

Deleted: appendix

Deleted: 3

Deleted: appendix
(3) The owner or operator shall install, operate, calibrate, and maintain an instrument for 

continuously monitoring and recording the concentration of H2S in flare gas according to the 

requirements in paragraphs (e)(3)(i) through (iii) of this section and shall collect and analyze

samples of flare gas and calculate total sulfur concentrations as specified in paragraphs (e)(3)(iv) 

through (ix) of this section. The owner or operator of a modified flare must install this H2S

monitor no later than 18 months after the flare becomes an affected flare subject to this subpart 

unless the owner or operator of the affected flare commits in writing to install a flare gas 

recovery system, in which case the owner or operator of a modified flare must install this 

instrument no later than 2 years after the flare becomes an affected flare subject to this subpart.

(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 must be between 1 and 5 

percent (by volume) inclusive. 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. The 

owner or operator shall use 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.

(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 flare may be required to perform a root cause analysis 

under §60.103a(b)(1), the owner or operator shall collect representative daily samples of the flare 

gas. 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)(3)(vii) of this section.

(v) The owner or operator shall analyze each daily sample for total sulfur using 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 D5504–01 (Reapproved 2006),

“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)(3)(vi)(A) of this section.
(C) Determine the 95 percent confidence interval for the distribution of daily ratios based on the 

10 individual daily ratios.

(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)(3)(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 95 percent 

confidence interval for the most recent distribution of daily ratios, the owner or operator shall

develop a new 10-day average ratio and 95 percent confidence interval based on data for the 

outlying weekly sample plus data collected over the following 9 operating days.

(f) Flow monitoring for flares. The owner or operator of an affected flare subject to 

§60.103a(a)(4) shall install, operate, calibrate, and maintain CPMS to measure and record the 

flare gas flow rate. The owner or operator of a modified flare shall install this instrument by no 

later than 18 months after the flare becomes an affected flare subject to this subpart unless the 

owner or operator of the affected flare commits in writing to install a flare gas recovery system, 

in which case flow monitoring is not required until after the flare has been an affected flare 

subject to this subpart for 2 years. 

(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. 

(2) The owner or operator shall install, operate, and maintain each CPMS according to the 

manufacturer's specifications and requirements. 

(g) 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) are 

defined as specified in paragraphs (f)(1) through (4) of this section. 

Note: Determine all averages 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) All 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 all rolling 365-day periods during which the average concentration as measured by 

the SO2 continuous monitoring system required under paragraph (a)(1) of this section exceeds 8 

ppmv; or 

(2) All 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 

Deleted: e

Deleted: 102a(g)(3

Deleted: exhaust 

Deleted: 1 year

Deleted: f
required under paragraph (b)(3)(iii) of this section exceeds 162 ppmv, and all 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. 

(3) All rolling 365-day 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) 40 ppmv or 0.035 lb/MMBtu for a newly constructed process heater or a modified or 

reconstructed natural draft process heater;

(ii) 60 ppmv or 0.055 lb/MMBtu for a modified or reconstructed forced draft process heater;

(iii) 150 ppmv or the daily average emission limit calculated using Equation 3 in 

§60.102a(g)(2)(iv)(B) for a co-fired process heater; and 

(iv) The site-specific limit determined by the Administrator under §60.102a(i).

(4) All daily periods during which the concentration of NOX as measured by the NOX continuous 

monitoring system required under paragraph (d) of this section exceeds the applicable emissions 

limit in §60.102a(g)(2)(iv). 

§ 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 or work practice 

standard in §60.103a 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. The 

notification must include, if applicable, a written statement that the owner or operator of an 

affected flare is installing a flare gas recovery system or additional amine adsorption and 

stripping columns. Notification 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. 

Deleted: 24-hour

Deleted: 40 ppmv.

Deleted: rolling 30-day

Deleted: average flow rate to an 

affected flare

Deleted: e

Deleted: 250,000 scfd
(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 records of discharges greater than 500 lb 

SO2 in any 24-hour period from any affected flare, discharges greater than 500 lb SO2 in excess 

of the allowable limits from a fuel gas combustion device other than a flare or sulfur recovery 

plant, and discharges to an affected flare in excess of 500,000 scf in any 24-hour period. The 

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

exceeding the thresholds: 

(i) A description of the discharge. 

(ii) The date and time the discharge was first identified and the duration of the discharge. 

(iii) The measured or calculated cumulative quantity of gas discharged over the discharge 

duration. If the discharge duration exceeds 24 hours, record the discharge quantity for each 24-

hour period. For a flare, record the measured or calculated cumulative quantity of gas discharged 

to the flare over the discharge duration. If the discharge duration exceeds 24 hours, record the 

quantity of gas discharged to the flare for each 24-hour period. Engineering calculations are 

allowed for fuel gas combustion devices other than flares. 

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

reduced sulfur concentration, measured total sulfur concentration, or both the measured H2S

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

location in the flare inlet.

(v) For each discharge greater than 500 lb SO2 in excess of the applicable short-term emissions 

limit in §60.102a(g)(1) from a fuel gas combustion device other than a flare, 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 other than flares. 

(vi) For each discharge greater than 500 lb SO2 in excess of the allowable limits from a sulfur 

recovery plant, either the measured concentration of reduced sulfur or SO2 discharged to the

atmosphere.

(vii) For each discharge greater than 500 lb SO2 in any 24-hour period from any affected flare or 

discharge greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion 

device other than a flare 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.

Deleted: /day

Deleted: scfd. These records shall 

include

Deleted: For discharges greater than 

500 lb/day SO2, the 

Deleted: discharges

Deleted: /day

Deleted: or estimated 

Deleted: of 

Deleted: , TRS

Deleted: discharges

Deleted: /day
(ix) Results of any root-cause analysis and corrective action analysis conducted as required in 

§60.103a(a)(4) and (5) and §60.103a(b), including a statement noting whether the discharge

resulted from the same root cause identified in a previous analysis, and either a description of the 

corrective action and a schedule for implementation or an explanation of why corrective action is 

not necessary as required in §60.103a(c). 

(7) If the owner or operator complies with §60.107a(d)(3) 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) The information described in paragraph (c)(6) of this section for all discharges for which a 

root-cause analysis, corrective action analysis, and implementation of corrective action were

required by §60.103a(a)(4) and (5), §60.103a(b), and §60.103a(c). 

(6) For any periods for which monitoring data are not available, any changes made in operation 

of the emission control system during the period of data unavailability which could affect the 

ability of the system to meet the applicable emission limit. Operations of the control system and 

affected facility during periods of data unavailability are to be compared with operation of the 

control system and affected facility before and following the period of data unavailability. 

(7) A written statement, signed by a responsible official, certifying the accuracy and 

completeness of the information contained in the report. 

§ 60.109a Delegation of authority. 

(a) This subpart can be implemented and enforced by the U.S. EPA or a delegated authority such 

as a State, local, or tribal agency. You should contact your U.S. EPA Regional Office to find out 

if this subpart is delegated to a State, local, or tribal agency within your State. 

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

tribal agency, the approval authorities contained in paragraphs (b)(1) through (4) of this section 

are retained by the Administrator of the U.S. EPA and are not transferred to the State, local, or 

tribal agency. 

Deleted: A root-cause summary report 

that provides the

Deleted: e

Deleted: was

Deleted: 3
(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 a petition to establish a site-specific NOX emissions limit for a modified or 

reconstructed process heater under §60.102a(i). 

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) 7.28 842

Ethane (C2H6) 12.94 1,475

Hydrogen (H2) 1.61 269

Ethene (C2H4) 11.34 1,335

Propane (C3H8) 18.61 2,100

Propene (C3H6) 17.01 1,947

Butane (C4H10) 24.28 2,717

Butene (C4H8) 22.67 2,558

Inerts 0.85 0 a

 MEV = molar exhaust volume, dry standard cubic feet per mole (dscf/mol)

b

 MHC = molar heat content, Btu per mole (Btu/mol)