***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EO12866_RefineryRTR 2060 AQ75 NPRM Part63Subpart UUU CC Y Part60Subpart J 

Ja_RegText_20140221

Title 40: Protection of Environment 

PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 

FOR SOURCE CATEGORIES 

Subpart UUU—National Emission Standards for Hazardous Air Pollutants for Petroleum 

Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery 

Units 

What This Subpart Covers 

§63.1560 What is the purpose of this subpart? 

This subpart establishes national emission standards for hazardous air pollutants (HAP) emitted 

from petroleum refineries. This subpart also establishes requirements to demonstrate initial and 

continuous compliance with the emission limitations and work practice standards. 

§63.1561 Am I subject to this subpart? 

(a) You are subject to this subpart if you own or operate a petroleum refinery that is located at a 

major source of HAP emissions. 

(1) A petroleum refinery is an establishment engaged primarily in petroleum refining as defined 

in the Standard Industrial Classification (SIC) code 2911 and the North American Industry 

Classification (NAIC) code 32411, and used mainly for: 

(i) Producing transportation fuels (such as gasoline, diesel fuels, and jet fuels), heating fuels 

(such as kerosene, fuel gas distillate, and fuel oils), or lubricants; 

(ii) Separating petroleum; or 

(iii) Separating, cracking, reacting, or reforming an intermediate petroleum stream, or recovering 

a by-product(s) from the intermediate petroleum stream (e.g., sulfur recovery). 

(2) A major source of HAP is a plant site that emits or has the potential to emit any single HAP 

at a rate of 9.07 megagrams (10 tons) or more per year or any combination of HAP at a rate of 

22.68 megagrams (25 tons) or more per year. 

(b) [Reserved] 

Deleted: 12
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§63.1562 What parts of my plant are covered by this subpart? 

(a) This subpart applies to each new, reconstructed, or existing affected source at a petroleum 

refinery. 

(b) The affected sources are: 

(1) The process vent or group of process vents on fluidized catalytic cracking units that are 

associated with regeneration of the catalyst used in the unit (i.e., the catalyst regeneration flue 

gas vent). 

(2) The process vent or group of process vents on catalytic reforming units (including but not 

limited to semi-regenerative, cyclic, or continuous processes) that are associated with 

regeneration of the catalyst used in the unit. This affected source includes vents that are used 

during the unit depressurization, purging, coke burn, and catalyst rejuvenation. 

(3) The process vent or group of process vents on Claus or other types of sulfur recovery plant 

units or the tail gas treatment units serving sulfur recovery plants that are associated with sulfur 

recovery. 

(4) Each bypass line serving a new, existing, or reconstructed catalytic cracking unit, catalytic 

reforming unit, or sulfur recovery unit. This means each vent system that contains a bypass line 

(e.g., ductwork) that could divert an affected vent stream away from a control device used to 

comply with the requirements of this subpart. 

(c) An affected source is a new affected source if you commence construction of the affected 

source after September 11, 1998, and you meet the applicability criteria in §63.1561 at the time 

you commenced construction. 

(d) Any affected source is reconstructed if you meet the criteria in §63.2. 

(e) An affected source is existing if it is not new or reconstructed. 

(f) This subpart does not apply to: 

(1) A thermal catalytic cracking unit. 

(2) A sulfur recovery unit that does not recover elemental sulfur or where the modified reaction 

is carried out in a water solution which contains a metal ion capable of oxidizing the sulfide ion 

to sulfur (e.g., the LO-CAT II process). 

(3) A redundant sulfur recovery unit not located at a petroleum refinery and used by the refinery 

only for emergency or maintenance backup. 

(4) Equipment associated with bypass lines such as low leg drains, high point bleed, analyzer 

vents, open-ended valves or lines, or pressure relief valves needed for safety reasons. 

(5) Gaseous streams routed to a fuel gas system. 

Deleted: ,
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§63.1563 When do I have to comply with this subpart? 

(a) If you have a new or reconstructed affected source, you must comply with this subpart 

according to the requirements in paragraphs (a)(1) and (2) of this section. 

(1) If you startup your affected source before April 11, 2002, then you must comply with the 

emission limitations and work practice standards for new and reconstructed sources in this 

subpart no later than April 11, 2002. 

(2) If you startup your affected source after April 11, 2002, you must comply with the emission 

limitations and work practice standards for new and reconstructed sources in this subpart upon 

startup of your affected source. 

(b) If you have an existing affected source, you must comply with the emission limitations and 

work practice standards for existing affected sources in this subpart by no later than April 11, 

2005 except as specified in paragraph (c) of this section. 

(c) We will grant an extension of compliance for an existing catalytic cracking unit allowing 

additional time to meet the emission limitations and work practice standards for catalytic 

cracking units in §§63.1564 and 63.1565 if you commit to hydrotreating the catalytic cracking 

unit feedstock and to meeting the emission limitations of this subpart on the same date that your 

facility meets the final Tier 2 gasoline sulfur control standard (40 CFR part 80, subpart J). To 

obtain an extension, you must submit a written notification to your permitting authority 

according to the requirements in §63.1574(e). Your notification must include the information in 

paragraphs (c)(1) and (2) of this section. 

(1) Identification of the affected source with a brief description of the controls to be installed (if 

needed) to comply with the emission limitations for catalytic cracking units in this subpart. 

(2) A compliance schedule, including the information in paragraphs (c)(2)(i) through (iv) of this 

section. 

(i) The date by which onsite construction or the process change is to be initiated. 

(ii) The date by which onsite construction or the process change is to be completed. 

(iii) The date by which your facility will achieve final compliance with both the final Tier 2 

gasoline sulfur control standard as specified in §80.195, and the emission limitations and work 

practice standards for catalytic cracking units in this subpart. In no case will your permitting 

authority grant an extension beyond the date you are required to meet the Tier 2 gasoline sulfur 

control standard or December 31, 2009, whichever comes first. If you don't comply with the 

emission limitations and work practice standards for existing catalytic cracking units by the 

specified date, you will be out-of-compliance with the requirements for catalytic cracking units 

beginning April 11, 2005. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iv) A brief description of interim emission control measures that will be taken to ensure proper 

operation and maintenance of the process equipment during the period of the compliance 

extension. 

(d) If you have an area source that increases its emissions or its potential to emit such that it 

becomes a major source of HAP, the requirements in paragraphs (d)(1) and (2) of this section 

apply. 

(1) Any portion of the existing facility that is a new affected source or a new reconstructed 

source must be in compliance with the requirements of this subpart upon startup. 

(2) All other parts of the source must be in compliance with the requirements of this subpart by 

no later than 3 years after it becomes a major source or, if applicable, the extended compliance 

date granted according to the requirements in paragraph (c) of this section. 

(e) You must meet the notification requirements in §63.1574 according to the schedule in 

§63.1574 and in 40 CFR part 63, subpart A. Some of the notifications must be submitted before 

the date you are required to comply with the emission limitations and work practice standards in 

this subpart. 

Catalytic Cracking Units, Catalytic Reforming Units, Sulfur Recovery Units, and Bypass 

Lines 

§63.1564 What are my requirements for metal HAP emissions from catalytic cracking 

units? 

(a) What emission limitations and work practice standards must I meet? You must: 

(1) Meet each emission limitation in Table 1 of this subpart that applies to you. If your catalytic 

cracking unit is subject to the NSPS for PM in §60.102 or is subject to §60.102a(b)(1) of this 

chapter, you must meet the emission limitations for NSPS units. If your catalytic cracking unit is 

not subject to the NSPS for PM, you can choose from the four options in paragraphs (a)(1)(i) 

through (iv) of this section: 

(i) You can elect to comply with the PM per coke burn-off emission limit (Option 1); 

(ii) You can elect to comply with the PM concentration emission limit (Option 2); 

(iii) You can elect to comply with the Nickel (Ni) lb/hr emission limit (Option 3); or 

(iv) You can elect to comply with the Ni per coke burn-off emission limit (Option 4). 

(2) Comply with each operating limit in Table 2 of this subpart that applies to you. 

(3) Prepare an operation, maintenance, and monitoring plan according to the requirements in 

§63.1574(f) and operate at all times according to the procedures in the plan. 

Deleted: isn't

Deleted: NSPS requirements

Deleted: lb/1,000 lbs of
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) The emission limitations and operating limits for metal HAP emissions from catalytic 

cracking units required in paragraphs (a)(1) and (2) of this section do not apply during periods of 

planned maintenance preapproved by the applicable permitting authority according to the 

requirements in §63.1575(j). 

(5) During periods of startup only, if your catalytic cracking unit is followed by an electrostatic 

precipitator, you can choose from the two options in paragraphs (a)(5)(i) and (ii) of this section: 

(i) You can elect to comply with the requirements paragraphs (a)(1) and (2) of this section; or 

(ii) You can elect to maintain the opacity in the exhaust gas from your catalyst regenerator at or 

below 30 percent opacity on a 6-minute average basis. 

(b) How do I demonstrate initial compliance with the emission limitations and work practice 

standard? You must: 

(1) Install, operate, and maintain a continuous monitoring system(s) according to the 

requirements in §63.1572 and Table 3 of this subpart. 

(2) Conduct a performance test for each catalytic cracking unit not subject to the NSPS for PM 

according to the requirements in §63.1571 and under the conditions specified in Table 4 of this 

subpart. 

(3) Establish each site-specific operating limit in Table 2 of this subpart that applies to you 

according to the procedures in Table 4 of this subpart. 

(4) Use the procedures in paragraphs (b)(4)(i) through (iv) of this section to determine initial 

compliance with the emission limitations. 

(i) If you elect Option 1 in paragraph (a)(1)(i) of this section, compute the PM emission rate 

(lb/1,000 lb of coke burn-off) for each run using Equations 1, 2, and 3 (if applicable) of this 

section and the site-specific opacity limit, if applicable, using Equation 4 of this section as 

follows: 

    c r a r %CO %O K Qoxy %Oxy

%CO R K1Q %CO2 %CO K2Q K3Q 2 2 3 2





 



    

 



     (Eq. 1) 

Where: 

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

Qr = Volumetric flow rate of exhaust gas from catalyst regenerator before adding air or gas 

streams. Example: You may measure upstream or downstream of an electrostatic precipitator, 

but you must measure upstream of a carbon monoxide boiler, dscm/min (dscf/min). You may use 

the alternative in either §63.1573(a)(1) or (a)(2), as applicable, to calculate Qr; 

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

from instruments in the catalytic cracking unit control room, dscm/min (dscf/min); 

Deleted: the NSPS requirements, 

Deleted: s
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

%CO2 = Carbon dioxide concentration in regenerator exhaust, percent by volume (dry basis); 

%CO = Carbon monoxide concentration in regenerator exhaust, percent by volume (dry basis); 

%O2 = Oxygen concentration in regenerator exhaust, percent by volume (dry basis); 

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

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

K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) (0.0062 (lb-min)/(hrdscf-%)); 

Qoxy = Volumetric flow rate of oxygen-enriched air stream to regenerator, as determined from 

instruments in the catalytic cracking unit control room, dscm/min (dscf/min); and 

%Oxy = Oxygen concentration in oxygen-enriched air stream, percent by volume (dry basis). 

c

s sd

R

K C Q E   (Eq. 2) 

Where: 

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

Cs = Concentration of PM, g/dscm (lb/dscf); 

Qsd = Volumetric flow rate of the catalytic cracking unit catalyst regenerator flue gas as 

measured by Method 2 in appendix A to part 60 of this chapter, dscm/hr (dscf/hr); 

Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr); and 

K = Conversion factor, 1.0 (kg2

 /g)/(1,000 kg) (1,000 lb/(1,000 lb)). 

1.0 K' R

H E A

c

s 













   (Eq. 3) 

Where: 

Es = Emission rate of PM allowed, kg/1,000 kg (1b/1,000 lb) of coke burn-off in catalyst 

regenerator; 

1.0 = Emission limitation, kg coke/1,000 kg (lb coke/1,000 lb); 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

A = Allowable incremental rate of PM emissions. Before [THE DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], A=0.18 g/million cal (0.10 lb/million Btu). On or after [THE DATE 18 MONTHS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], A=0 g/million cal (0 lb/million Btu); 

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

your permitting authority approves procedures for determining the heat input rate;

Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr) determined using Equation 1 of this 

section; and 

K’ = Conversion factor to units to standard, 1.0 (kg2

/g)/(1,000 kg) (103 lb/(1,000 lb)). 















  

st

st PMEmR Opacity Limit Opacity 1lb / 1000 lb coke burn (Eq. 4) 

Where: 

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

whichever is greater; 

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

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

(ii) If you elect Option 2 in paragraph (a)(1)(ii) of this section, the PM concentration emission 

limit, determine the average PM concentration from the initial performance test used to certify 

your PM CEMS. 

(iii) If you elect Option 3 in paragraph (a)(1)(iii) of this section, the Ni lb/hr emission limit, 

compute your Ni emission rate using Equation 5 of this section and your site-specific Ni 

operating limit (if you use a continuous opacity monitoring system) using Equations 6 and 7 of 

this section as follows: 

ENi1  CNi Qsd (Eq. 5) 

Where: 

ENi1 = Mass emission rate of Ni, mg/hr (lb/hr); and 

CNi = Ni concentration in the catalytic cracking unit catalyst regenerator flue gas as measured by 

Method 29 in appendix A to part 60 of this chapter, mg/dscm (lbs/dscf). 

st

st

1 Opacity NiEmR1 Opacity  

13g Ni/hr

 (Eq. 6) 

Deleted: and

Deleted: .

Deleted: (ii) If you elect Option 2 in paragraph 

(a)(1)(ii) of this section, the PM emission limit, 

compute your PM emission rate (lb/1,000 lbs of coke 

burn-off) using Equations 1 and 2 of this section and 

your site-specific opacity operating limit (if you use 

a continuous opacity monitoring system) using 

Equation 4 of this section as follows:¶







  st  P Opacity Limit Opacity 1lb/k

Field Code Changed

Deleted: l

Deleted: runs

Deleted: s
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: 

Opacity1 = Opacity value for use in Equation 7 of this section, percent, or 10 percent, whichever 

is greater; and 

NiEmR1st = Average Ni emission rate calculated as the arithmetic average Ni emission rate using 

Equation 5 of this section for each of the performance test runs, g Ni/hr. 

Ni Operating Limit1 Opacity1 Qmon,st E-Catst (Eq. 7) 

Where: 

Ni Operating Limit1 = Maximum permissible hourly average Ni operating limit, percent-acfmppmw, i.e., your site-specific Ni operating limit; 

Qmon,st = Hourly average actual gas flow rate as measured by the continuous parameter 

monitoring system during the performance test or using the alternative procedure in §63.1573, 

acfm; and 

E-Catst = Ni concentration on equilibrium catalyst measured during source test, ppmw. 

(iv) If you elect Option 4 in paragraph (a)(1)(iv) of this section, the Ni per coke burn-off 

emission limit, compute your Ni emission rate using Equations 1 and 8 of this section and your 

site-specific Ni operating limit (if you use a continuous opacity monitoring system) using 

Equations 9 and 10 of this section as follows: 

c

Ni sd

Ni R

C Q E 2

  (Eq. 8) 

Where: 

ENi2 = Normalized mass emission rate of Ni, mg/kg coke (lb/1,000 lbs coke). 

st

st

2 Opacity NiEmR2 Opacity  

1.0mg/kgcoke

 (Eq. 9) 

Where: 

Opacity2= Opacity value for use in Equation 10 of this section, percent, or 10 percent, whichever 

is greater; and 

NiEmR2st = Average Ni emission rate calculated as the arithmetic average Ni emission rate using 

Equation 8 of this section for each of the performance test runs, mg/kg coke. 

c st

mon st

2 2 st R

Q Ni Operating Limit Opacity E-Cat

,

,    (Eq. 10) 

Deleted: lbs/1,000 lbs of
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: 

Ni Operating Limit2 = Maximum permissible hourly average Ni operating limit, percent-ppmwacfm-hr/kg coke, i.e., your site-specific Ni operating limit; and 

Rc,st = Coke burn rate from Equation 1 of this section, as measured during the initial performance 

test, kg coke/hr. 

(5) Demonstrate initial compliance with each emission limitation that applies to you according to 

Table 5 of this subpart. 

(6) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this 

section by submitting your operation, maintenance, and monitoring plan to your permitting 

authority as part of your Notification of Compliance Status. 

(7) Submit the Notification of Compliance Status containing the results of the initial compliance 

demonstration according to the requirements in §63.1574. 

(c) How do I demonstrate continuous compliance with the emission limitations and work 

practice standards? You must: 

(1) Demonstrate continuous compliance with each emission limitation in Tables 1 and 2 of this 

subpart that applies to you according to the methods specified in Tables 6 and 7 of this subpart. 

(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(3) of 

this section by maintaining records to document conformance with the procedures in your 

operation, maintenance, and monitoring plan. 

(3) If you use a continuous opacity monitoring system and elect to comply with Option 3 in 

paragraph (a)(1)(iii) of this section, determine continuous compliance with your site-specific Ni 

operating limit by using Equation 11 of this section as follows: 

Ni Operating Value Opacity Q E-Cat 1   mon  (Eq. 11) 

Where: 

Ni Operating Value1 = Maximum permissible hourly average Ni standard operating value, %-

acfm-ppmw; 

Opacity = Hourly average opacity, percent; 

Qmon = Hourly average actual gas flow rate as measured by continuous parameter monitoring 

system or calculated by alternative procedure in §63.1573, acfm; and 

E-Cat = Ni concentration on equilibrium catalyst from weekly or more recent measurement, 

ppmw. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) If you use a continuous opacity monitoring system and elect to comply with Option 4 in 

paragraph (a)(1)(iv) of this section, determine continuous compliance with your site-specific Ni 

operating limit by using Equation 12 of this section as follows: 

c

mon

2 R

Opacity E-Cat Q Ni Operating Value    (Eq. 12) 

Where: 

Ni Operating Value2 = Maximum permissible hourly average Ni standard operating value, 

percent-acfm-ppmw-hr/kg coke. 

(5) During periods of startup only, if you elect to comply with the alternative limit in paragraph 

(a)(5)(ii) of this section, determine continuous compliance by: collecting opacity readings using 

either a continuous opacity monitoring system according to §63.1572 or manual opacity 

observations following EPA Method 9 in Appendix A-4 to part 60 of this chapter; and 

maintaining each 6-minute average opacity at or below 30 percent. 

§63.1565 What are my requirements for organic HAP emissions from catalytic cracking 

units? 

(a) What emission limitations and work practice standards must I meet? You must: 

(1) Meet each emission limitation in Table 8 of this subpart that applies to you. If your catalytic 

cracking unit is subject to the NSPS for carbon monoxide (CO) in §60.103 of this chapter, you 

must meet the emission limitations for NSPS units. If your catalytic cracking unit isn't subject to 

the NSPS for CO, you can choose from the two options in paragraphs (a)(1)(i) through (ii) of this 

section: 

(i) You can elect to comply with the NSPS requirements (Option 1); or 

(ii) You can elect to comply with the CO emission limit (Option 2). 

(2) Comply with each site-specific operating limit in Table 9 of this subpart that applies to you. 

(3) Prepare an operation, maintenance, and monitoring plan according to the requirements in 

§63.1574(f) and operate at all times according to the procedures in the plan. 

(4) The emission limitations and operating limits for organic HAP emissions from catalytic 

cracking units required in paragraphs (a)(1) and (2) of this section do not apply during periods of 

planned maintenance preapproved by the applicable permitting authority according to the 

requirements in §63.1575(j). 

(5) During periods of startup only, if your catalytic cracking unit is not followed by a CO boiler, 

thermal oxidizer, incinerator, flare or similar combustion device, you can choose from the two 

options in paragraphs (a)(5)(i) and (ii) of this section: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) You can elect to comply with the requirements in paragraphs (a)(1) and (2) of this section; or 

(ii) You can elect to maintain the oxygen (O2) concentration in the exhaust gas from your 

catalyst regenerator at or above 1 volume percent (dry basis). 

(b) How do I demonstrate initial compliance with the emission limitations and work practice 

standards? You must: 

(1) Install, operate, and maintain a continuous monitoring system according to the requirements 

in §63.1572 and Table 10 of this subpart. Except: 

(i) Whether or not your catalytic cracking unit is subject to the NSPS for CO in §60.103 of this 

chapter, you don't have to install and operate a continuous emission monitoring system if you 

show that CO emissions from your vent average less than 50 parts per million (ppm), dry basis. 

You must get an exemption from your permitting authority, based on your written request. To 

show that the emissions average is less than 50 ppm (dry basis), you must continuously monitor 

CO emissions for 30 days using a CO continuous emission monitoring system that meets the 

requirements in §63.1572. 

(ii) If your catalytic cracking unit isn't subject to the NSPS for CO, you don't have to install and 

operate a continuous emission monitoring system or a continuous parameter monitoring system 

if you vent emissions to a boiler (including a “CO boiler”) or process heater that has a design 

heat input capacity of at least 44 megawatts (MW). 

(iii) If your catalytic cracking unit isn't subject to the NSPS for CO, you don't have to install and 

operate a continuous emission monitoring system or a continuous parameter monitoring system 

if you vent emissions to a boiler or process heater in which all vent streams are introduced into 

the flame zone. 

(iv) If you elect to comply with the alternative limit for periods of startup in paragraph (a)(5)(ii) 

of this section, you must also install, operate, and maintain a continuous parameter monitoring 

system to measure and record the oxygen content (percent, dry basis) in the catalyst regenerator 

vent. 

(2) Conduct each performance test for a catalytic cracking unit not subject to the NSPS for CO 

according to the requirements in §63.1571 and under the conditions specified in Table 11 of this 

subpart. 

(3) Establish each site-specific operating limit in Table 9 of this subpart that applies to you 

according to the procedures in Table 11 of this subpart. 

(4) Demonstrate initial compliance with each emission limitation that applies to you according to 

Table 12 of this subpart. 

(5) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this 

section by submitting the operation, maintenance, and monitoring plan to your permitting 

authority as part of your Notification of Compliance Status according to §63.1574. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(6) Submit the Notification of Compliance Status containing the results of the initial compliance 

demonstration according to the requirements in §63.1574. 

(c) How do I demonstrate continuous compliance with the emission limitations and work 

practice standards? You must: 

(1) Demonstrate continuous compliance with each emission limitation in Tables 8 and 9 of this 

subpart that applies to you according to the methods specified in Tables 13 and 14 of this 

subpart. 

(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(3) of 

this section by complying with the procedures in your operation, maintenance, and monitoring 

plan. 

(3) Demonstrate continuous compliance with the alternative limit in paragraph (a)(5)(ii) of this 

section by collecting the hourly average oxygen concentration monitoring data according to 

§63.1572 and maintaining the hourly average oxygen concentration at or above 1 volume percent 

(dry basis). 

§63.1566 What are my requirements for organic HAP emissions from catalytic reforming 

units? 

(a) What emission limitations and work practice standards must I meet? You must: 

(1) Meet each emission limitation in Table 15 of this subpart that applies to you. You can choose 

from the two options in paragraphs (a)(1)(i) and (ii) of this section.

(i) You can elect to vent emissions of total organic compounds (TOC) to a flare (Option 1). On 

and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the 

requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

the flare must meet the control device requirements in §63.11(b) or the requirements of §63.670.

(ii) You can elect to meet a TOC or nonmethane TOC percent reduction standard or 

concentration limit, whichever is less stringent (Option 2). 

(2) Comply with each site-specific operating limit in Table 16 of this subpart that applies to you. 

(3) Except as provided in paragraph (a)(4) of this section, the emission limitations in Tables 15 

and 16 of this subpart apply to emissions from catalytic reforming unit process vents associated 

with initial catalyst depressuring and catalyst purging operations that occur prior to the coke 

burn-off cycle. The emission limitations in Tables 15 and 16 of this subpart do not apply to the 

coke burn-off, catalyst rejuvenation, reduction or activation vents, or to the control systems used 

for these vents. 

Deleted: through

Deleted: :

Deleted: that meets

Deleted: (Option 1); 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) The emission limitations in Tables 15 and 16 of this subpart do not apply to emissions from 

process vents during passive depressuring when the reactor vent pressure is 5 pounds per square 

inch gauge (psig) or less. The emission limitations in Tables 15 and 16 of this subpart do apply 

to emissions from process vents during active purging operations (when nitrogen or other purge 

gas is actively introduced to the reactor vessel) or active depressuring (using a vacuum pump, 

ejector system, or similar device) regardless of the reactor vent pressure. 

(5) Prepare an operation, maintenance, and monitoring plan according to the requirements in 

§63.1574(f) and operate at all times according to the procedures in the plan. 

(b) How do I demonstrate initial compliance with the emission limitations and work practice 

standard? You must: 

(1) Install, operate, and maintain a continuous monitoring system(s) according to the 

requirements in §63.1572 and Table 17 of this subpart. 

(2) Conduct each performance test for a catalytic reforming unit according to the requirements in 

§63.1571 and under the conditions specified in Table 18 of this subpart. 

(3) Establish each site-specific operating limit in Table 16 of this subpart that applies to you 

according to the procedures in Table 18 of this subpart. 

(4) Use the procedures in paragraph (b)(4)(i) or (ii) of this section to determine initial 

compliance with the emission limitations. 

(i) If you elect the percent reduction standard under Option 2, calculate the emission rate of 

nonmethane TOC using Equation 1 of this section (if you use Method 25) or Equation 2 of this 

section (if you use Method 25A or Methods 25A and 18), then calculate the mass emission 

reduction using Equation 3 of this section as follows: 

E  K4McQs (Eq. 1) 

Where: 

E = Emission rate of nonmethane TOC in the vent stream, kilograms-C per hour; 

K4 = Constant, 6.0 × 10−5

 (kilograms per milligram)(minutes per hour); 

Mc = Mass concentration of total gaseous nonmethane organic (as carbon) as measured and 

calculated using Method 25 in appendix A to part 60 of this chapter, mg/dscm; and 

Qs = Vent stream flow rate, dscm/min, at a temperature of 20 degrees Celsius (C). 

  E K5 CTOC Cmethane Qs 6   1 (Eq. 2) 

Where: 

Deleted: and purging operations 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

K5 = Constant, 1.8×10−4 (parts per million)−1 (gram-mole per standard cubic meter) (gram-C per 

gram-mole-hexane) (kilogram per gram) (minutes per hour), where the standard temperature 

(standard cubic meter) is at 20 degrees C (uses 72g-C/g.mole hexane); 

CTOC = Concentration of TOC on a dry basis in ppmv as hexane as measured by Method 25A in 

appendix A to part 60 of this chapter; 

Cmethane = Concentration of methane on a dry basis in ppmv as measured by Method 18 in 

appendix A to part 60 of this chapter. If the concentration of methane is not determined, assume 

Cmethane equals zero; and 

Qs = Vent stream flow rate, dry standard cubic meters per minute, at a temperature of 20 degrees 

C. 

100%  

i

i o

E

E E %reduction (Eq. 3) 

Where: 

Ei = Mass emission rate of TOC at control device inlet, kg/hr; and 

Eo = Mass emission rate of TOC at control device outlet, kg/hr. 

(ii) If you elect the 20 parts per million by volume (ppmv) concentration limit, correct the 

measured TOC concentration for oxygen (O2) content in the gas stream using Equation 4 of this 

section as follows: 

  















  

2

NMTOC, %O TOC methane %O

C C C

20.9%

17.9%

6

1 2 3 (Eq. 4) 

Where: 

CNMTOC, 3%O2 = Concentration of nonmethane TOC on a dry basis in ppmv as hexane corrected to 

3 percent oxygen. 

(5) You are not required to do a TOC performance test if: 

(i) You elect to vent emissions to a flare as provided in paragraph (a)(1)(i) of this section (Option 

1); or 

(ii) You elect the TOC percent reduction or concentration limit in paragraph (a)(1)(ii) of this 

section (Option 2), and you use a boiler or process heater with a design heat input capacity of 44 

MW or greater or a boiler or process heater in which all vent streams are introduced into the 

flame zone. 

(6) Demonstrate initial compliance with each emission limitation that applies to you according to 

Table 19 of this subpart. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(7) Demonstrate initial compliance with the work practice standard in paragraph (a)(5) of this 

section by submitting the operation, maintenance, and monitoring plan to your permitting 

authority as part of your Notification of Compliance Status. 

(8) Submit the Notification of Compliance Status containing the results of the initial compliance 

demonstration according to the requirements in §63.1574. 

(c) How do I demonstrate continuous compliance with the emission limitations and work 

practice standards? You must: 

(1) Demonstrate continuous compliance with each emission limitation in Tables 15 and 16 of this 

subpart that applies to you according to the methods specified in Tables 20 and 21 of this 

subpart. 

(2) Demonstrate continuous compliance with the work practice standards in paragraph (a)(3) of 

this section by complying with the procedures in your operation, maintenance, and monitoring 

plan. 

§63.1567 What are my requirements for inorganic HAP emissions from catalytic 

reforming units? 

(a) What emission limitations and work practice standards must I meet? You must: 

(1) Meet each emission limitation in Table 22 to this subpart that applies to you. If you operate a 

catalytic reforming unit in which different reactors in the catalytic reforming unit are regenerated 

in separate regeneration systems, then these emission limitations apply to each separate 

regeneration system. These emission limitations apply to emissions from catalytic reforming unit 

process vents associated with the coke burn-off and catalyst rejuvenation operations during coke 

burn-off and catalyst regeneration. You can choose from the two options in paragraphs (a)(1)(i) 

through (ii) of this section: 

(i) You can elect to meet a percent reduction standard for hydrogen chloride (HCl) emissions 

(Option 1); or 

(ii) You can elect to meet an HCl concentration limit (Option 2). 

(2) Meet each site-specific operating limit in Table 23 of this subpart that applies to you. These 

operating limits apply during coke burn-off and catalyst rejuvenation. 

(3) Prepare an operation, maintenance, and monitoring plan according to the requirements in 

§63.1574(f) and operate at all times according to the procedures in the plan. 

(b) How do I demonstrate initial compliance with the emission limitations and work practice 

standard? You must: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Install, operate, and maintain a continuous monitoring system(s) according to the 

requirements in §63.1572 and Table 24 of this subpart. 

(2) Conduct each performance test for a catalytic reforming unit according to the requirements in 

§63.1571 and the conditions specified in Table 25 of this subpart. 

(3) Establish each site-specific operating limit in Table 23 of this subpart that applies to you 

according to the procedures in Table 25 of this subpart. 

(4) Use the equations in paragraphs (b)(4)(i) through (iv) of this section to determine initial 

compliance with the emission limitations. 

(i) Correct the measured HCl concentration for oxygen (O2) content in the gas stream using 

Equation 1 of this section as follows: 

HCl

2

HCl, %O C

%O

C 















  20.9%

17.9%

2 3 (Eq. 1) 

Where: 

CHCl,3%O2 = Concentration of HCl on a dry basis in ppmv corrected to 3 percent oxygen or 1 

ppmv, whichever is greater; 

CHCl = Concentration of HCl on a dry basis in ppmv, as measured by Method 26A in 40 CFR 

part 60, appendix A; and 

%O2 = Oxygen concentration in percent by volume (dry basis). 

(ii) If you elect the percent reduction standard, calculate the emission rate of HCl using Equation 

2 of this section; then calculate the mass emission reduction from the mass emission rates using 

Equation 3 of this section as follows: 

EHCl  K6CHClQs (Eq. 2) 

Where: 

EHCl = Emission rate of HCl in the vent stream, grams per hour; 

K6 = Constant, 0.091 (parts per million)−1

 (grams HCl per standard cubic meter) (minutes per 

hour), where the standard temperature (standard cubic meter) is at 20 degrees Celsius (C); and 

Qs = Vent stream flow rate, dscm/min, at a temperature of 20 degrees C. 

100%

,

, ,   

HCl i

HCl i HCl o

E

E E

HCl%reduction (Eq. 3) 

Where: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EHCl,i = Mass emission rate of HCl at control device inlet, g/hr; and 

EHCl,o = Mass emission rate of HCl at control device outlet, g/hr. 

(iii) If you are required to use a colormetric tube sampling system to demonstrate continuous 

compliance with the HCl concentration operating limit, calculate the HCl operating limit using 

Equation 4 of this section as follows: 















 

HCl,3%O2

HCl,RegLimit

HCl,ppmvLimit HCl,AveTube C

C

C 0.9C (Eq. 4) 

Where: 

CHCl,ppmvLimit = Maximum permissible HCl concentration for the HCl concentration operating 

limit, ppmv; 

CHCl,AveTube = Average HCl concentration from the colormetric tube sampling system, calculated 

as the arithmetic average of the average HCl concentration measured for each performance test 

run, ppmv or 1 ppmv, whichever is greater; and 

CHCl,RegLimit = Maximum permissible outlet HCl concentration for the applicable catalytic 

reforming unit as listed in Table 22 of this subpart, either 10 or 30 ppmv. 

(iv) If you are required to use a colormetric tube sampling system to demonstrate continuous 

compliance with the percent reduction operating limit, calculate the HCl operating limit using 

Equation 5 of this section as follows: 



















 

Test

Limit

HCl,%Limit HCl,AveTube %HClReduction

%HClReduction C C

100

100 0.9 (Eq. 5) 

Where: 

CHCl,%Limit = Maximum permissible HCl concentration for the percent reduction operating limit, 

ppmv; 

%HCl ReductionLimit = Minimum permissible HCl reduction for the applicable catalytic 

reforming unit as listed in Table 22 of this subpart, either 97 or 92 percent; and 

%HCl ReductionTest = Average percent HCl reduction calculated as the arithmetic average HCl 

reduction calculated using Equation 3 of this section for each performance source test, percent. 

(5) Demonstrate initial compliance with each emission limitation that applies to you according to 

Table 26 of this subpart. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(6) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this 

section by submitting the operation, maintenance, and monitoring plan to your permitting 

authority as part of your Notification of Compliance Status. 

(7) Submit the Notification of Compliance Status containing the results of the initial compliance 

demonstration according to the requirements in §63.1574. 

(c) How do I demonstrate continuous compliance with the emission limitations and work 

practice standard? You must: 

(1) Demonstrate continuous compliance with each emission limitation in Tables 22 and 23 of this 

subpart that applies to you according to the methods specified in Tables 27 and 28 of this 

subpart. 

(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(3) of 

this section by maintaining records to document conformance with the procedures in your 

operation, maintenance and monitoring plan. 

§63.1568 What are my requirements for HAP emissions from sulfur recovery units? 

(a) What emission limitations and work practice standard must I meet? You must: 

(1) Meet each emission limitation in Table 29 of this subpart that applies to you. If your sulfur 

recovery unit is subject to the NSPS for sulfur oxides in §60.104 or in §60.102a(f)(1) of this 

chapter, you must meet the emission limitations for NSPS units. If your sulfur recovery unit is 

not subject to one of these NSPS for sulfur oxides, you can choose from the options in 

paragraphs (a)(1)(i) through (ii) of this section: 

(i) You can elect to meet the NSPS requirements in §60.104(a)(2) or in §60.102a(f)(1) of this 

chapter (Option 1); or 

(ii) You can elect to meet the total reduced sulfur (TRS) emission limitation (Option 2). 

(2) Meet each operating limit in Table 30 of this subpart that applies to you. 

(3) Prepare an operation, maintenance, and monitoring plan according to the requirements in 

§63.1574(f) and operate at all times according to the procedures in the plan. 

(4) During periods of shutdown only, you can choose from the three options in paragraphs 

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

(i) You can elect to comply with the requirements in paragraphs (a)(1) and (2) of this section. 

(ii) You can elect to send any shutdown purge gases to a flare. On and after [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER], the flare must meet the requirements of §63.670. Prior to [THE 

Deleted: isn't

Deleted: the
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the design and 

operating requirements in §63.11(b) or the requirements of §63.670. 

(iii) You can elect to send any shutdown purge gases to a to a thermal oxidizer or incinerator 

operated at a minimum hourly average temperature of 1,200 degrees Fahrenheit and a minimum 

hourly average outlet oxygen (O2) concentration of 2 volume percent (dry basis). 

(b) How do I demonstrate initial compliance with the emission limitations and work practice 

standards? You must: 

(1) Install, operate, and maintain a continuous monitoring system according to the requirements 

in §63.1572 and Table 31 of this subpart. Except:

(i) If you elect to comply with the alternative limit for periods of shutdown in paragraph (a)(4)(ii) 

of this section, then on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

you must also install, operate, calibrate, and maintain monitoring systems as specified in 

§§63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must either 

install, operate, and maintain continuous parameter monitoring systems following the 

requirements in §63.11 (to detect the presence of a flame; to measure and record the net heating 

value of the gas being combusted; and to measure and record the volumetric flow of the gas 

being combusted) or install, operate, calibrate, and maintain monitoring systems as specified in 

§§63.670 and 63.671. 

(ii) If you elect to comply with the alternative limit for periods of shutdown in paragraph 

(a)(4)(iii) of this section, you must also install, operate, and maintain continuous parameter 

monitoring system to measure and record the temperature and oxygen content (percent, dry 

basis) in the vent from the thermal oxidizer or incinerator. 

(2) Conduct each performance test for a sulfur recovery unit not subject to the NSPS for sulfur 

oxides according to the requirements in §63.1571 and under the conditions specified in Table 32 

of this subpart. 

(3) Establish each site-specific operating limit in Table 30 of this subpart that applies to you 

according to the procedures in Table 32 of this subpart. 

(4) Correct the reduced sulfur samples to zero percent excess air using Equation 1 of this section 

as follows: 

















 

2

c

adj meas %O

C C

20.9

20.9

 (Eq. 1) 

Where: 

Cadj = pollutant concentration adjusted to zero percent oxygen, ppm or g/dscm; 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

20.9 = oxygen concentration in air, percent; 

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

(5) Demonstrate initial compliance with each emission limitation that applies to you according to 

Table 33 of this subpart. 

(6) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this 

section by submitting the operation, maintenance, and monitoring plan to your permitting 

authority as part of your notification of compliance status. 

(7) Submit the notification of compliance status containing the results of the initial compliance 

demonstration according to the requirements in §63.1574. 

(c) How do I demonstrate continuous compliance with the emission limitations and work 

practice standards? You must: 

(1) Demonstrate continuous compliance with each emission limitation in Tables 29 and 30 of this 

subpart that applies to you according to the methods specified in Tables 34 and 35 of this 

subpart. 

(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(3) of 

this section by complying with the procedures in your operation, maintenance, and monitoring 

plan. 

(3) Demonstrate continuous compliance with the alternative limit in paragraph (a)(4)(ii) of this 

section by meeting the requirements of either paragraph (c)(3)(i) or (ii) of this section. 

(i) On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must meet the 

requirements of paragraphs (c)(3)(i)(A) through (C) of this section. 

(A) Collect the flare monitoring data according to §§63.670 and 63.671. 

(B) Keep the records specified in §63.655(i)(9). 

(C) Maintain the selected operating parameters as specified in §63.670. 

(ii) Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], you must either meet the 

requirements of paragraph (c)(3)(i) of this section or meet the requirements of paragraphs 

(c)(3)(ii)(A) through (D) of this section. 

(A) Collect the flare monitoring data according to §63.1572. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(B) Record for each 1-hour period whether the monitor was continuously operating and the pilot 

light was continuously present during each 1-hour period. 

(C) Maintain the net heating value of the gas being combusted at or above the applicable limits 

in §63.11. 

(D) Maintain the exit velocity at or below the applicable maximum exit velocity specified in 

§63.11. 

(4) Demonstrate continuous compliance with the alternative limit in paragraph (a)(4)(iii) of this 

section by collecting the hourly average temperature and oxygen concentration monitoring data 

according to §63.1572; maintaining the hourly average temperature at or above 1,200 degrees 

Fahrenheit; and maintaining the hourly average oxygen concentration at or above 2 volume 

percent (dry basis). 

§63.1569 What are my requirements for HAP emissions from bypass lines? 

(a) What work practice standards must I meet? (1) You must meet each work practice standard 

in Table 36 of this subpart that applies to you. You can choose from the four options in 

paragraphs (a)(1)(i) through (iv) of this section: 

(i) You can elect to install an automated system (Option 1); 

(ii) You can elect to use a manual lock system (Option 2); 

(iii) You can elect to seal the line (Option 3); or 

(iv) You can elect to vent to a control device (Option 4). 

(2) As provided in §63.6(g), we, the EPA, may choose to grant you permission to use an 

alternative to the work practice standard in paragraph (a)(1) of this section. 

(3) You must prepare an operation, maintenance, and monitoring plan according to the 

requirements in §63.1574(f) and operate at all times according to the procedures in the plan. 

(b) How do I demonstrate initial compliance with the work practice standards? You must: 

(1) If you elect the option in paragraph (a)(1)(i) of this section, conduct each performance test for 

a bypass line according to the requirements in §63.1571 and under the conditions specified in 

Table 37 of this subpart. 

(2) Demonstrate initial compliance with each work practice standard in Table 36 of this subpart 

that applies to you according to Table 38 of this subpart. 

(3) Demonstrate initial compliance with the work practice standard in paragraph (a)(3) of this 

section by submitting the operation, maintenance, and monitoring plan to your permitting 

authority as part of your notification of compliance status. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) Submit the notification of compliance status containing the results of the initial compliance 

demonstration according to the requirements in §63.1574. 

(c) How do I demonstrate continuous compliance with the work practice standards? You must: 

(1) Demonstrate continuous compliance with each work practice standard in Table 36 of this 

subpart that applies to you according to the requirements in Table 39 of this subpart. 

(2) Demonstrate continuous compliance with the work practice standard in paragraph (a)(2) of 

this section by complying with the procedures in your operation, maintenance, and monitoring 

plan. 

General Compliance Requirements 

§63.1570 What are my general requirements for complying with this subpart? 

(a) You must be in compliance with all of the non-opacity standards in this subpart at all times. 

(b) You must be in compliance with the opacity and visible emission limits in this subpart at all

times. 

(c) At all times, you must operate and maintain any affected source, including associated air 

pollution control and monitoring equipment, in a manner consistent with safety and good air 

pollution control practices for minimizing emissions. The general duty to minimize emissions 

does not require you to make any further efforts to reduce emissions if levels required by the 

applicable standard have been achieved. Determination of whether a source is operating in 

compliance with operation and maintenance requirements will be based on information available 

to the Administrator which may include, but is not limited to, monitoring results, review of 

operation and maintenance procedures, review of operation and maintenance records, and 

inspection of the source. 

(d) During the period between the compliance date specified for your affected source and the 

date upon which continuous monitoring systems have been installed and validated and any 

applicable operating limits have been set, you must maintain a log detailing the operation and 

maintenance of the process and emissions control equipment. 

(e) [Reserved] 

(f) You must report each instance in which you did not meet each emission limitation and each 

operating limit in this subpart that applies to you. This includes periods of startup, shutdown, and 

malfunction. You also must report each instance in which you did not meet the work practice 

standards in this subpart that apply to you. These instances are deviations from the emission 

limitations and work practice standards in this subpart. These deviations must be reported 

according to the requirements in §63.1575. 

Deleted: during the

Deleted: specified in §63.6(f)(1)

Deleted: during the

Deleted: specified in §63.6(h)(1)

Deleted: Y

Deleted: always 

Deleted: your 

Deleted: according to the provisions in 

§63.6(e)(1)(i)

Deleted: (d) You must develop a written startup, 

shutdown, and malfunction plan (SSMP) according 

to the provisions in §63.6(e)(3).¶
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(g) In response to an action to enforce the standards set forth in §63.1564 through §63.1569, you 

may assert an affirmative defense to a claim for civil penalties for violations of such standards 

that are caused by malfunction, as defined at §63.2. Appropriate penalties may be assessed if you 

fail to meet the burden of proving all of the requirements in the affirmative defense. The 

affirmative defense shall not be available for claims for injunctive relief.

(1) Assertion of affirmative defense. To establish the affirmative defense in any action to enforce 

such a standard, you must timely meet the reporting requirements in paragraph (g)(2) of this 

section, and must prove by a preponderance of evidence that: 

(i) The violation: 

(A) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control 

equipment, process equipment, or a process to operate in a normal or usual manner; and 

(B) Could not have been prevented through careful planning, proper design or better operation 

and maintenance practices; and 

(C) Did not stem from any activity or event that could have been foreseen and avoided, or 

planned for; and 

(D) Was not part of a recurring pattern indicative of inadequate design, operation, or 

maintenance; and 

(ii) Repairs were made as expeditiously as possible when a violation occurred; and 

(iii) The frequency, amount, and duration of the violation (including any bypass) were 

minimized to the maximum extent practicable; and 

(iv) If the violation resulted from a bypass of control equipment or a process, then the bypass 

was unavoidable to prevent loss of life, severe personal injury, or severe property damage; and 

(v) All possible steps were taken to minimize the impact of the violation on ambient air quality, 

the environment and human health; and 

(vi) All emissions monitoring and control systems were kept in operation if at all possible, 

consistent with safety and good air pollution control practices; and 

(vii) All of the actions in response to the violation were documented by properly signed, 

contemporaneous operating logs; and 

(viii) At all times, the affected source was operated in a manner consistent with good practices 

for minimizing emissions; and 

(ix) A written root cause analysis has been prepared, the purpose of which is to determine, 

correct, and eliminate the primary causes of the malfunction and the violation resulting from the 

malfunction event at issue. The analysis shall also specify, using best monitoring methods and 

engineering judgment, the amount of any emissions that were the result of the malfunction. 

Deleted: Consistent with §§63.6(e) and 63.7(e)(1), 

deviations that occur during a period of startup, 

shutdown, or malfunction are not violations if you 

demonstrate to the Administrator's satisfaction that 

you were operating in accordance with §63.6(e)(1). 

The SSMP must include elements designed to 

minimize the frequency of such periods (i.e., root 

cause analysis). The Administrator will determine 

whether deviations that occur during a period of 

startup, shutdown, or malfunction are violations, 

according to the provisions in §63.6(e).
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) Report. If you seek to assert an affirmative defense, you must submit a written report to the 

Administrator with all necessary supporting documentation, that explains how you have met the 

requirements set forth in paragraph (g)(1) of this section. This affirmative defense report must be 

included in the first periodic compliance report otherwise required after the initial occurrence of 

the violation of the relevant standard (which may be the end of any applicable averaging period). 

If such compliance report is due less than 45 days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second compliance report due after the initial 

occurrence of the violation of the relevant standard. 

§63.1571 How and when do I conduct a performance test or other initial compliance 

demonstration? 

(a) When must I conduct a performance test? You must conduct performance tests and report the 

results by no later than 150 days after the compliance date specified for your source in §63.1563 

and according to the provisions in §63.7(a)(2). If you are required to do a performance 

evaluation or test for a semi-regenerative catalytic reforming unit catalyst regenerator vent, you 

may do them at the first regeneration cycle after your compliance date and report the results in a 

followup Notification of Compliance Status report due no later than 150 days after the test. 

(1) For each emission limitation or work practice standard where initial compliance is not 

demonstrated using a performance test, opacity observation, or visible emission observation, you 

must conduct the initial compliance demonstration within 30 calendar days after the compliance 

date that is specified for your source in §63.1563. 

(2) For each emission limitation where the averaging period is 30 days, the 30-day period for 

demonstrating initial compliance begins at 12:00 a.m. on the compliance date that is specified for 

your source in §63.1563 and ends at 11:59 p.m., 30 calendar days after the compliance date that 

is specified for your source in §63.1563. 

(3) If you commenced construction or reconstruction between September 11, 1998 and April 11, 

2002, you must demonstrate initial compliance with either the proposed emission limitation or 

the promulgated emission limitation no later than October 8, 2002 or within 180 calendar days 

after startup of the source, whichever is later, according to §63.7(a)(2)(ix). 

(4) If you commenced construction or reconstruction between September 11, 1998 and April 11, 

2002, and you chose to comply with the proposed emission limitation when demonstrating initial 

compliance, you must conduct a second compliance demonstration for the promulgated emission 

limitation by October 10, 2005, or after startup of the source, whichever is later, according to 

§63.7(a)(2)(ix). 

(5) Conduct a performance test for PM or Ni, as applicable, from catalytic cracking units at least 

once every 5 years for those units monitored with CPMS, BLD, or COMS. You must conduct the 

first periodic performance test no later than [THE DATE 18 MONTHS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. 

Those units monitoring PM concentration with a PM CEMS are not required to conduct a 

periodic PM performance test. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(b) What are the general requirements for performance test and performance evaluations? You 

must: 

(1) Conduct performance tests under such conditions as the Administrator specifies to you based 

on representative performance of the affected source for the period being tested. Representative 

conditions exclude periods of startup and shutdown unless specified by the Administrator or an 

applicable subpart. You may not conduct performance tests during periods of malfunction. You 

must record the process information that is necessary to document operating conditions during 

the test and include in such record an explanation to support that such conditions represent 

normal operation. Upon request, you must make available to the Administrator such records as 

may be necessary to determine the conditions of performance tests. 

(2) Except for opacity and visible emission observations, conduct three separate test runs for 

each performance test as specified in §63.7(e)(3). Each test run must last at least 1 hour. 

(3) Conduct each performance evaluation according to the requirements in §63.8(e). 

(4) Calculate the average emission rate for the performance test by calculating the emission rate 

for each individual test run in the units of the applicable emission limitation using Equation 2, 5, 

or 8 of §63.1564, and determining the arithmetic average of the calculated emission rates. 

(c) What procedures must I use for an engineering assessment? You may choose to use an 

engineering assessment to calculate the process vent flow rate, net heating value, TOC emission 

rate, and total organic HAP emission rate expected to yield the highest daily emission rate when 

determining the emission reduction or outlet concentration for the organic HAP standard for 

catalytic reforming units. If you use an engineering assessment, you must document all data, 

assumptions, and procedures to the satisfaction of the applicable permitting authority. An 

engineering assessment may include the approaches listed in paragraphs (c)(1) through (c)(4) of 

this section. Other engineering assessments may be used but are subject to review and approval 

by the applicable permitting authority. 

(1) You may use previous test results provided the tests are representative of current operating 

practices at the process unit, and provided EPA methods or approved alternatives were used; 

(2) You may use bench-scale or pilot-scale test data representative of the process under 

representative operating conditions; 

(3) You may use maximum flow rate, TOC emission rate, organic HAP emission rate, or organic 

HAP or TOC concentration specified or implied within a permit limit applicable to the process 

vent; or 

(4) You may use design analysis based on engineering principles, measurable process 

parameters, or physical or chemical laws or properties. Examples of analytical methods include, 

but are not limited to: 

(i) Use of material balances based on process stoichiometry to estimate maximum TOC 

concentrations; 

Deleted: each 

Deleted: according to the requirements in 

§63.7(e)(1)

Deleted: Not conduct performance tests during 

periods of startup, shutdown, or malfunction, as 

specified in §63.7(e)(1).¶

(5) 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) Calculation of hourly average maximum flow rate based on physical equipment design such 

as pump or blower capacities; and 

(iii) Calculation of TOC concentrations based on saturation conditions. 

(d) Can I adjust the process or control device measured values when establishing an operating 

limit? If you do a performance test to demonstrate compliance, you must base the process or 

control device operating limits for continuous parameter monitoring systems on the results 

measured during the performance test. You may adjust the values measured during the 

performance test according to the criteria in paragraphs (d)(1) through (3) of this section. 

(1) If you must meet the HAP metal emission limitations in §63.1564, you elect the option in 

paragraph (a)(1)(iii) in §63.1564 (Ni lb/hr), and you use continuous parameter monitoring 

systems, you must establish an operating limit for the equilibrium catalyst Ni concentration 

based on the laboratory analysis of the equilibrium catalyst Ni concentration from the initial 

performance test. Section 63.1564(b)(2) allows you to adjust the laboratory measurements of the 

equilibrium catalyst Ni concentration to the maximum level. You must make this adjustment 

using Equation 1 of this section as follows: 

st

st

Ecat

NiEmR1

Ecat-Limit 

13g Ni/hr

 (Eq. 1) 

Where: 

Ecat-Limit = Operating limit for equilibrium catalyst Ni concentration, mg/kg; 

NiEmR1st = Average Ni emission rate calculated as the arithmetic average Ni emission rate using 

Equation 5 of this section for each performance test run, g Ni/hr; and 

Ecatst = Average equilibrium Ni concentration from laboratory test results, mg/kg. 

(2) If you must meet the HAP metal emission limitations in §63.1564, you elect the option in 

paragraph (a)(1)(iv) in §63.1564 (Ni per coke burn-off), and you use continuous parameter 

monitoring systems, you must establish an operating limit for the equilibrium catalyst Ni 

concentration based on the laboratory analysis of the equilibrium catalyst Ni concentration from 

the initial performance test. Section 63.1564(b)(2) allows you to adjust the laboratory 

measurements of the equilibrium catalyst Ni concentration to the maximum level. You must 

make this adjustment using Equation 2 of this section as follows: 

st

st

Ecat

NiEmR2

Ecat-Limit 

1.0mg/kgcokeburn-off

 (Eq. 2) 

Where: 

NiEmR2st = Average Ni emission rate calculated as the arithmetic average Ni emission rate using 

Equation 8 of §63.1564 for each performance test run, mg/kg coke burn-off. 

Deleted: lb/1,000 lb of
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(3) If you choose to adjust the equilibrium catalyst Ni concentration to the maximum level, you 

can't adjust any other monitored operating parameter (i.e., gas flow rate, voltage, pressure drop, 

liquid-to-gas ratio). 

(4) Except as specified in paragraph (d)(3) of this section, if you use continuous parameter 

monitoring systems, you may adjust one of your monitored operating parameters (flow rate, total 

power and secondary current, pressure drop, liquid-to-gas ratio) from the average of measured 

values during the performance test to the maximum value (or minimum value, if applicable) 

representative of worst-case operating conditions, if necessary. This adjustment of measured 

values may be done using control device design specifications, manufacturer recommendations, 

or other applicable information. You must provide supporting documentation and rationale in 

your Notification of Compliance Status, demonstrating to the satisfaction of your permitting 

authority, that your affected source complies with the applicable emission limit at the operating 

limit based on adjusted values. 

(e) Can I change my operating limit? You may change the established operating limit by meeting 

the requirements in paragraphs (e)(1) through (3) of this section. 

(1) You may change your established operating limit for a continuous parameter monitoring 

system by doing an additional performance test, a performance test in conjunction with an 

engineering assessment, or an engineering assessment to verify that, at the new operating limit, 

you are in compliance with the applicable emission limitation. 

(2) You must establish a revised operating limit for your continuous parameter monitoring 

system if you make any change in process or operating conditions that could affect control 

system performance or you change designated conditions after the last performance or 

compliance tests were done. You can establish the revised operating limit as described in 

paragraph (e)(1) of this section. 

(3) You may change your site-specific opacity operating limit or Ni operating limit only by 

doing a new performance test. 

§63.1572 What are my monitoring installation, operation, and maintenance 

requirements? 

(a) You must install, operate, and maintain each continuous emission monitoring system 

according to the requirements in paragraphs (a)(1) through (4) of this section. 

(1) You must install, operate, and maintain each continuous emission monitoring system 

according to the requirements in Table 40 of this subpart. 

(2) If you use a continuous emission monitoring system to meet the NSPS CO or SO2 limit, you 

must conduct a performance evaluation of each continuous emission monitoring system 

according to the requirements in §63.8 and Table 40 of this subpart. This requirement does not 

apply to an affected source subject to the NSPS that has already demonstrated initial compliance 

with the applicable performance specification. 

Deleted: voltage
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(3) As specified in §63.8(c)(4)(ii), each continuous emission monitoring system must complete a 

minimum of one cycle of operation (sampling, analyzing, and data recording) for each 

successive 15-minute period. 

(4) Data must be reduced as specified in §63.8(g)(2). 

(b) You must install, operate, and maintain each continuous opacity monitoring system according 

to the requirements in paragraphs (b)(1) through (3) of this section. 

(1) Each continuous opacity monitoring system must be installed, operated, and maintained 

according to the requirements in Table 40 of this subpart. 

(2) If you use a continuous opacity monitoring system to meet the NSPS opacity limit, you must 

conduct a performance evaluation of each continuous opacity monitoring system according to the 

requirements in §63.8 and Table 40 of this subpart. This requirement does not apply to an 

affected source subject to the NSPS that has already demonstrated initial compliance with the 

applicable performance specification. 

(3) As specified in §63.8(c)(4)(i), each continuous opacity monitoring system must complete a 

minimum of one cycle of sampling and analyzing for each successive 10-second period and one 

cycle of data recording for each successive 6-minute period. 

(c) Except for flare monitoring systems, you must install, operate, and maintain each continuous 

parameter monitoring system according to the requirements in paragraphs (c)(1) through (5) of 

this section. For flares, on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

you must install, operate, calibrate, and maintain monitoring systems as specified in §§63.670 

and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must either meet the 

monitoring system requirements in paragraphs (c)(1) through (5) of this section or meet the 

requirements in §§63.670 and 63.671.

 (1) You must install, operate, and maintain each continuous parameter monitoring system 

according to the requirements in Table 41 of this subpart. You must also meet the equipment 

specifications in Table 41 of this subpart if pH strips or colormetric tube sampling systems are 

used. You must meet the requirements in Table 41 of this subpart for BLD systems.

(2) The continuous parameter monitoring system must complete a minimum of one cycle of 

operation for each successive 15-minute period. You must have a minimum of four successive 

cycles of operation to have a valid hour of data (or at least two if a calibration check is 

performed during that hour or if the continuous parameter monitoring system is out-of-control). 

(3) Each continuous parameter monitoring system must have valid hourly average data from at 

least 75 percent of the hours during which the process operated, except for BLD systems. 

(4) Each continuous parameter monitoring system must determine and record the hourly average 

of all recorded readings and if applicable, the daily average of all recorded readings for each 

operating day, except for BLD systems. The daily average must cover a 24-hour period if 

Deleted: Y

Deleted: The owner or operator shall

Deleted: in a manner consistent with the 

manufacturer's specifications or other written 

procedures that provide adequate assurance that the 

equipment will monitor accurately

Deleted: The owner or operator shall
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

operation is continuous or the number of hours of operation per day if operation is not 

continuous, except for BLD systems. 

(5) Each continuous parameter monitoring system must record the results of each inspection, 

calibration, and validation check. 

(d) You must monitor and collect data according to the requirements in paragraphs (d)(1) and (2) 

of this section. 

(1) You must conduct all monitoring in continuous operation (or collect data at all required 

intervals) at all times the affected source is operating. 

(2) You may not use data recorded during required quality assurance or control activities 

(including, as applicable, calibration checks and required zero and span adjustments) for 

purposes of this regulation, including data averages and calculations, for fulfilling a minimum 

data availability requirement, if applicable. You must use all the data collected during all other 

periods in assessing the operation of the control device and associated control system. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6940, Feb. 9, 2005] 

§63.1573 What are my monitoring alternatives? 

(a) What are the approved alternatives for measuring gas flow rate? (1) You may use this 

alternative to a continuous parameter monitoring system for the catalytic regenerator exhaust gas 

flow rate for your catalytic cracking unit if the unit does not introduce any other gas streams into 

the catalyst regeneration vent (i.e., complete combustion units with no additional combustion 

devices). You may also use this alternative to a continuous parameter monitoring system for the 

catalytic regenerator atmospheric exhaust gas flow rate for your catalytic reforming unit during 

the coke burn and rejuvenation cycles if the unit operates as a constant pressure system during 

these cycles. If you use this alternative, you shall use the same procedure for the performance 

test and for monitoring after the performance test. You shall: 

(i) Install and operate a continuous parameter monitoring system to measure and record the 

hourly average volumetric air flow rate to the catalytic cracking unit or catalytic reforming unit 

regenerator. Or, you may determine and record the hourly average volumetric air flow rate to the 

catalytic cracking unit or catalytic reforming unit regenerator using the appropriate control room 

instrumentation. 

(ii) Install and operate a continuous parameter monitoring system to measure and record the 

temperature of the gases entering the control device (or exiting the catalyst regenerator if you do 

not use an add-on control device). 

(iii) Calculate and record the hourly average actual exhaust gas flow rate using Equation 1 of this 

section as follows: 

Deleted: Except for monitoring malfunctions, 

associated repairs, and required quality assurance or 

control activities (including as applicable, calibration 

checks and required zero and span adjustments), you

Deleted: monitoring malfunctions, associated 

repairs, and 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

  































    

 



 

vent

gas

gas air other P

Temp Q Q Q 1atm

dscfm 293 K

scfm 1.12 (Eq. 1) 

Where 

Qgas = Hourly average actual gas flow rate, acfm; 

1.12 = Default correction factor to convert gas flow from dry standard cubic feet per minute 

(dscfm) to standard cubic feet per minute (scfm); 

Qair = Volumetric flow rate of air to regenerator, as determined from the control room 

instrumentations, dscfm; 

Qother = Volumetric flow rate of other gases entering the regenerator as determined from the 

control room instrumentations, dscfm. (Examples of “other” gases include an oxygen-enriched 

air stream to catalytic cracking unit regenerators and a nitrogen stream to catalytic reforming unit 

regenerators.); 

Tempgas = Temperature of gas stream in vent measured as near as practical to the control device 

or opacity monitor, °K. For wet scrubbers, temperature of gas prior to the wet scrubber; and 

Pvent = Absolute pressure in the vent measured as near as practical to the control device or 

opacity monitor, as applicable, atm. When used to assess the gas flow rate in the final 

atmospheric vent stack, you can assume Pvent = 1 atm. 

(2) You may use this alternative to calculating Qr, the volumetric flow rate of exhaust gas for the 

catalytic cracking regenerator as required in Equation 1 of §63.1564, if you have a gas analyzer 

installed in the catalytic cracking regenerator exhaust vent prior to the addition of air or other gas 

streams. You may measure upstream or downstream of an electrostatic precipitator, but you shall 

measure upstream of a carbon monoxide boiler. You shall: 

(i) Install and operate a continuous parameter monitoring system to measure and record the 

hourly average volumetric air flow rate to the catalytic cracking unit regenerator. Or, you can 

determine and record the hourly average volumetric air flow rate to the catalytic cracking unit 

regenerator using the catalytic cracking unit control room instrumentation. 

(ii) Install and operate a continuous gas analyzer to measure and record the concentration of 

carbon dioxide, carbon monoxide, and oxygen of the catalytic cracking regenerator exhaust. 

(iii) Calculate and record the hourly average flow rate using Equation 2 of this section as 

follows: 

 

2 2

air xy oxy

r %CO %CO %O

Q %O Q Q        10079 100

 (Eq. 2) 

Where: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Qr = Volumetric flow rate of exhaust gas from the catalyst regenerator before adding air or gas 

streams, dscm/min (dscf/min); 

79 = Default concentration of nitrogen and argon in dry air, percent by volume (dry basis); 

%Oxy = Oxygen concentration in oxygen-enriched air stream, percent by volume (dry basis); 

Qoxy = Volumetric flow rate of oxygen-enriched air stream to regenerator as determined from the 

catalytic cracking unit control room instrumentations, dscm/min (dscf/min); 

%CO2 = Carbon dioxide concentration in regenerator exhaust, percent by volume (dry basis); 

CO = Carbon monoxide concentration in regenerator exhaust, percent by volume (dry basis); and 

%O2 = Oxygen concentration in regenerator exhaust, percent by volume (dry basis). 

(b) What is the approved alternative for monitoring pressure drop? You may use this alternative 

to a continuous parameter monitoring system for pressure drop if you operate a jet ejector type 

wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles. You shall: 

(1) Conduct a daily check of the air or water pressure to the spray nozzles; 

(2) Maintain records of the results of each daily check; and 

(3) Repair or replace faulty (e.g., leaking or plugged) air or water lines within 12 hours of 

identification of an abnormal pressure reading. 

(c) What is the approved alternative for monitoring pH or alkalinity levels? You may use the 

alternative in paragraph (c)(1) or (2) of this section for a catalytic reforming unit. 

(1) You shall measure and record the pH of the water (or scrubbing liquid) exiting the wet 

scrubber or internal scrubbing system at least once an hour during coke burn-off and catalyst 

rejuvenation using pH strips as an alternative to a continuous parameter monitoring system. The 

pH strips must meet the requirements in Table 41 of this subpart. 

(2) You shall measure and record the alkalinity of the water (or scrubbing liquid) exiting the wet 

scrubber or internal scrubbing system at least once an hour during coke burn-off and catalyst 

rejuvenation using titration as an alternative to a continuous parameter monitoring system. 

(d) Can I use another type of monitoring system? You may request approval from your 

permitting authority to use an automated data compression system. An automated data 

compression system does not record monitored operating parameter values at a set frequency 

(e.g., once every hour) but records all values that meet set criteria for variation from previously 

recorded values. Your request must contain a description of the monitoring system and data 

recording system, including the criteria used to determine which monitored values are recorded 

and retained, the method for calculating daily averages, and a demonstration that the system 

meets all of the criteria in paragraphs (d)(1) through (5) of this section: 

Deleted: b

Deleted: c

Deleted: c
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) The system measures the operating parameter value at least once every hour; 

(2) The system records at least 24 values each day during periods of operation; 

(3) The system records the date and time when monitors are turned off or on; 

(4) The system recognizes unchanging data that may indicate the monitor is not functioning 

properly, alerts the operator, and records the incident; and 

(5) The system computes daily average values of the monitored operating parameter based on 

recorded data. 

(e) Can I monitor other process or control device operating parameters? You may request 

approval to monitor parameters other than those required in this subpart. You must request 

approval if: 

(1) You use a control device other than a thermal incinerator, boiler, process heater, flare, 

electrostatic precipitator, or wet scrubber; 

(2) You use a combustion control device (e.g., incinerator, flare, boiler or process heater with a 

design heat capacity of at least 44 MW, boiler or process heater where the vent stream is 

introduced into the flame zone), electrostatic precipitator, or scrubber but want to monitor a 

parameter other than those specified; or 

(3) You wish to use another type of continuous emission monitoring system that provides direct 

measurement of a pollutant (i.e., a PM or multi-metals HAP continuous emission monitoring 

system, a carbonyl sulfide/carbon disulfide continuous emission monitoring system, a TOC 

continuous emission monitoring system, or HCl continuous emission monitoring system). 

(f) How do I request to monitor alternative parameters? You must submit a request for review 

and approval or disapproval to the Administrator. The request must include the information in 

paragraphs (f)(1) through (5) of this section. 

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

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

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

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

parameter can be used to determine whether the affected source will continuously comply with 

the emission limitations and the schedule for this demonstration. You must certify that you will 

establish an operating limit 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. 

(3) The frequency and content of monitoring, recording, and reporting, if monitoring and 

recording are not continuous. You also must include the rationale for the proposed monitoring, 

recording, and reporting requirements. 

Deleted: d

Deleted: e

Deleted: e
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) Supporting calculations. 

(5) Averaging time for the alternative operating parameter. 

(g) How do I apply for alternative monitoring requirements if my catalytic cracking unit is 

equipped with a wet scrubber and I have approved alternative monitoring requirements under 

the new source performance standards for petroleum refineries?

(1) You may request alternative monitoring requirements according to the procedures in this 

paragraph if you meet each of the conditions in paragraphs (g)(1)(i) through (iii) of this section: 

(i) Your fluid catalytic cracking unit regenerator vent is subject to the PM limit in 40 CFR 

60.102(a)(1) and uses a wet scrubber for PM emissions control; 

(ii) You have alternative monitoring requirements for the continuous opacity monitoring system 

requirement in 40 CFR 60.105(a)(1) approved by the Administrator; and 

(iii) You are required by this subpart to install, operate, and maintain a continuous opacity 

monitoring system for the same catalytic cracking unit regenerator vent for which you have 

approved alternative monitoring requirements. 

(2) You can request approval to use an alternative monitoring method prior to submitting your 

notification of compliance status, in your notification of compliance status, or at any time. 

(3) You must submit a copy of the approved alternative monitoring requirements along with a 

monitoring plan that includes a description of the continuous monitoring system or method, 

including appropriate operating parameters that will be monitored, test results demonstrating 

compliance with the opacity limit used to establish an enforceable operating limit(s), and the 

frequency of measuring and recording to establish continuous compliance. If applicable, you 

must also include operation and maintenance requirements for the continuous monitoring system. 

(4) We will contact you within 30 days of receipt of your application to inform you of approval 

or of our intent to disapprove your request. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6940, Feb. 9, 2005] 

Notifications, Reports, and Records 

§63.1574 What notifications must I submit and when? 

(a) Except as allowed in paragraphs (a)(1) through (3) of this section, you must submit all of the 

notifications in §§63.6(h), 63.7(b) and (c), 63.8(e), 63.8(f)(4), 63.8(f)(6), and 63.9(b) through (h) 

that apply to you by the dates specified. 

(1) You must submit the notification of your intention to construct or reconstruct according to 

§63.9(b)(5) unless construction or reconstruction had commenced and initial startup had not 

Deleted: f

Deleted: 

Deleted: f
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

occurred before April 11, 2002. In this case, you must submit the notification as soon as 

practicable before startup but no later than July 10, 2002. This deadline also applies to the 

application for approval of construction or reconstruction and approval of construction or 

reconstruction based on State preconstruction review required in §§63.5(d)(1)(i) and 63.5(f)(2). 

(2) You must submit the notification of intent to conduct a performance test required in §63.7(b) 

at least 30 calendar days before the performance test is scheduled to begin (instead of 60 days). 

(3) If you are required to conduct an initial performance test, performance evaluation, design 

evaluation, opacity observation, visible emission observation, or other initial compliance 

demonstration, you must submit a notification of compliance status according to §63.9(h)(2)(ii). 

You can submit this information in an operating permit application, in an amendment to an 

operating permit application, in a separate submission, or in any combination. In a State with an 

approved operating permit program where delegation of authority under section 112(l) of the 

CAA has not been requested or approved, you must provide a duplicate notification to the 

applicable Regional Administrator. If the required information has been submitted previously, 

you do not have to provide a separate notification of compliance status. Just refer to the earlier 

submissions instead of duplicating and resubmitting the previously submitted information. 

(i) For each initial compliance demonstration that does not include a performance test, you must 

submit the Notification of Compliance Status no later than 30 calendar days following 

completion of the initial compliance demonstration. 

(ii) For each initial compliance demonstration that includes a performance test, you must submit 

the notification of compliance status, including the performance test results, no later than 150 

calendar days after the compliance date specified for your affected source in §63.1563. 

(b) As specified in §63.9(b)(2), if you startup your new affected source before April 11, 2002, 

you must submit the initial notification no later than August 9, 2002. 

(c) If you startup your new or reconstructed affected source on or after April 11, 2002, you must 

submit the initial notification no later than 120 days after you become subject to this subpart. 

(d) You also must include the information in Table 42 of this subpart in your notification of 

compliance status. 

(e) If you request an extension of compliance for an existing catalytic cracking unit as allowed in 

§63.1563(c), you must submit a notification to your permitting authority containing the required 

information by October 13, 2003. 

(f) As required by this subpart, you must prepare and implement an operation, maintenance, and 

monitoring plan for each control system and continuous monitoring system for each affected 

source. The purpose of this plan is to detail the operation, maintenance, and monitoring 

procedures you will follow. 

(1) You must submit the plan to your permitting authority for review and approval along with 

your notification of compliance status. While you do not have to include the entire plan in your 

part 70 or 71 permit, you must include the duty to prepare and implement the plan as an 

Deleted: a
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

applicable requirement in your part 70 or 71 operating permit. You must submit any changes to 

your permitting authority for review and approval and comply with the plan until the change is 

approved. 

(2) Each plan must include, at a minimum, the information specified in paragraphs (f)(2)(i) 

through (xii) of this section. 

(i) Process and control device parameters to be monitored for each affected source, along with 

established operating limits. 

(ii) Procedures for monitoring emissions and process and control device operating parameters for 

each affected source. 

(iii) Procedures that you will use to determine the coke burn-rate, the volumetric flow rate (if you 

use process data rather than direct measurement), and the rate of combustion of liquid or solid 

fossil fuels if you use an incinerator-waste heat boiler to burn the exhaust gases from a catalyst 

regenerator. 

(iv) Procedures and analytical methods you will use to determine the equilibrium catalyst Ni 

concentration, the equilibrium catalyst Ni concentration monthly rolling average, and the hourly 

or hourly average Ni operating value. 

(v) Procedures you will use to determine the pH of the water (or scrubbing liquid) exiting a wet 

scrubber if you use pH strips. 

(vi) Procedures you will use to determine the HCl concentration of gases from a catalytic 

reforming unit when you use a colormetric tube sampling system, including procedures for 

correcting for pressure (if applicable to the sampling equipment) and the sampling locations that 

will be used for compliance monitoring purposes. 

(vii) Procedures you will use to determine the gas flow rate for a catalytic cracking unit if you 

use the alternative procedure based on air flow rate and temperature. 

(viii) Monitoring schedule, including when you will monitor and when you will not monitor an 

affected source (e.g., during the coke burn-off, regeneration process). 

(ix) Quality control plan for each continuous opacity monitoring system and continuous emission 

monitoring system you use to meet an emission limit in this subpart. This plan must include 

procedures you will use for calibrations, accuracy audits, and adjustments to the system needed 

to meet applicable requirements for the system. 

(x) Maintenance schedule for each monitoring system and control device for each affected 

source that is generally consistent with the manufacturer's instructions for routine and long-term 

maintenance. 

(xi) If you use a fixed-bed gas-solid adsorption system to control emissions from a catalytic 

reforming unit, you must implement corrective action procedures if the HCl concentration 

measured at the selected compliance monitoring sampling location within the bed exceeds the 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

operating limit. These procedures must require, at minimum, repeat measurement and recording 

of the HCl concentration in the adsorption system exhaust gases and at the selected compliance 

monitoring sampling location within the bed. If the HCl concentration at the selected compliance 

monitoring location within the bed is above the operating limit during the repeat measurement 

while the HCl concentration in the adsorption system exhaust gases remains below the operating 

limit, the adsorption bed must be replaced as soon as practicable. Your procedures must specify 

the sampling frequency that will be used to monitor the HCl concentration in the adsorption 

system exhaust gases subsequent to the repeat measurement and prior to replacement of the 

sorbent material (but not less frequent than once every 4 hours during coke burn-off). If the HCl 

concentration of the adsorption system exhaust gases is above the operating limit when measured 

at any time, the adsorption bed must be replaced within 24 hours or before the next regeneration 

cycle, whichever is longer. 

(xii) Procedures that will be used for purging the catalyst if you do not use a control device to 

comply with the organic HAP emission limits for catalytic reforming units. These procedures 

will include, but are not limited to, specification of the minimum catalyst temperature and the 

minimum cumulative volume of gas per mass of catalyst used for purging prior to uncontrolled 

releases (i.e., during controlled purging events); the maximum purge gas temperature for 

uncontrolled purge events; and specification of the monitoring systems that will be used to 

monitor and record data during each purge event. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6941, Feb. 9, 2005] 

§63.1575 What reports must I submit and when? 

(a) You must submit each report in Table 43 of this subpart that applies to you. 

(b) Unless the Administrator has approved a different schedule, you must submit each report by 

the date in Table 43 of this subpart and according to the requirements in paragraphs (b)(1) 

through (5) of this section. 

(1) The first compliance report must cover the period beginning on the compliance date that is 

specified for your affected source in §63.1563 and ending on June 30 or December 31, 

whichever date is the first date following the end of the first calendar half after the compliance 

date that is specified for your affected source in §63.1563. 

(2) The first compliance report must be postmarked or delivered no later than July 31 or January 

31, whichever date follows the end of the first calendar half after the compliance date that is 

specified for your affected source in §63.1563. 

(3) Each subsequent compliance report must cover the semiannual reporting period from January 

1 through June 30 or the semiannual reporting period from July 1 through December 31. 

(4) Each subsequent compliance report must be postmarked or delivered no later than July 31 or 

January 31, whichever date is the first date following the end of the semiannual reporting period. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(5) For each affected source that is subject to permitting regulations pursuant to part 70 or 71 of 

this chapter, and if the permitting authority has established dates for submitting semiannual 

reports pursuant to §70.6(a)(3)(iii)(A) or §71.6(a)(3)(iii)(A) of this chapter, you may submit the 

first and subsequent compliance reports according to the dates the permitting authority has 

established instead of according to the dates in paragraphs (b)(1) through (4) of this section. 

(c) The compliance report must contain the information required in paragraphs (c)(1) through (4) 

of this section. 

(1) Company name and address. 

(2) Statement by a responsible official, with that official's name, title, and signature, certifying 

the accuracy of the content of the report. 

(3) Date of report and beginning and ending dates of the reporting period. 

(4) If there are no deviations from any emission limitation that applies to you and there are no 

deviations from the requirements for work practice standards, a statement that there were no 

deviations from the emission limitations or work practice standards during the reporting period 

and that no continuous emission monitoring system or continuous opacity monitoring system 

was inoperative, inactive, malfunctioning, out-of-control, repaired, or adjusted. 

(d) For each deviation from an emission limitation and for each deviation from the requirements 

for work practice standards that occurs at an affected source where you are not using a 

continuous opacity monitoring system or a continuous emission monitoring system to comply 

with the emission limitation or work practice standard in this subpart, the semiannual compliance 

report must contain the information in paragraphs (c)(1) through (3) of this section and the 

information in paragraphs (d)(1) through (4) of this section. 

(1) The total operating time of each affected source during the reporting period and identification 

of the sources for which there was a deviation. 

(2) Information on the number, date, time, duration, and cause of deviations (including unknown 

cause, if applicable). 

(3) Information on the number, duration, and cause for monitor downtime incidents (including 

unknown cause, if applicable, other than downtime associated with zero and span and other daily 

calibration checks). 

(4) The applicable operating limit or work practice standard from which you deviated and either 

the parameter monitor reading during the deviation or a description of how you deviated from 

the work practice standard. 

(e) For each deviation from an emission limitation occurring at an affected source where you are 

using a continuous opacity monitoring system or a continuous emission monitoring system to 

comply with the emission limitation, you must include the information in paragraphs (c)(1) 

through (3) of this section, in paragraphs (d)(1) through (3) of this section, and in paragraphs 

(e)(1) through (13) of this section. 

Deleted: 3

Deleted: , as applicable, and the corrective action 

taken

Deleted: the information
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) [Reserved]

(2) The date and time that each continuous opacity monitoring system or continuous emission 

monitoring system was inoperative, except for zero (low-level) and high-level checks. 

(3) The date and time that each continuous opacity monitoring system or continuous emission 

monitoring system was out-of-control, including the information in §63.8(c)(8). 

(4) An estimate of the quantity of each regulated pollutant emitted over the emission limit during 

the deviation, and a description of the method used to estimate the emissions.

(5) A summary of the total duration of the deviation during the reporting period (recorded in 

minutes for opacity and hours for gases and in the averaging period specified in the regulation 

for other types of emission limitations), and the total duration as a percent of the total source 

operating time during that reporting period. 

(6) A breakdown of the total duration of the deviations during the reporting period and into those 

that are due to control equipment problems, process problems, other known causes, and other 

unknown causes. 

(7) A summary of the total duration of downtime for the continuous opacity monitoring system 

or continuous emission monitoring system during the reporting period (recorded in minutes for 

opacity and hours for gases and in the averaging time specified in the regulation for other types 

of standards), and the total duration of downtime for the continuous opacity monitoring system 

or continuous emission monitoring system as a percent of the total source operating time during 

that reporting period. 

(8) A breakdown of the total duration of downtime for the continuous opacity monitoring system 

or continuous emission monitoring system during the reporting period into periods that are due to 

monitoring equipment malfunctions, non-monitoring equipment malfunctions, quality 

assurance/quality control calibrations, other known causes, and other unknown causes. 

(9) An identification of each HAP that was monitored at the affected source. 

(10) A brief description of the process units. 

(11) The monitoring equipment manufacturer(s) and model number(s). 

(12) The date of the latest certification or audit for the continuous opacity monitoring system or 

continuous emission monitoring system. 

(13) A description of any change in the continuous emission monitoring system or continuous 

opacity monitoring system, processes, or controls since the last reporting period. 

(f) You also must include the information required in paragraphs (f)(1) through (2) of this section 

in each compliance report, if applicable. 

Deleted: The date and time that each malfunction 

started and stopped.

Deleted: The date and time that each deviation 

started and stopped, and whether each deviation 

occurred during a period of startup, shutdown, or 

malfunction or during another period.

Deleted: startup, shutdown, 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) You must include the information in paragraph (c)(1)(i) or (c)(1)(ii) of this section, if 

applicable. 

(i) If you are complying with paragraph (k)(1) of this section, a summary of the results of any 

performance test done during the reporting period on any affected unit. Results of the 

performance test include the identification of the source tested, the date of the test, the 

percentage of emissions reduction or outlet pollutant concentration reduction (whichever is 

needed to determine compliance) for each run and for the average of all runs, and the values of 

the monitored operating parameters. 

(ii) If you are not complying with paragraph (k)(1) of this section, a copy of any performance test 

done during the reporting period on any affected unit. The report may be included in the next 

semiannual compliance report. The copy must include a complete report for each test method 

used for a particular kind of emission point tested. For additional tests performed for a similar 

emission point using the same method, you must submit the results and any other information 

required, but a complete test report is not required. A complete test report contains a brief 

process description; a simplified flow diagram showing affected processes, control equipment, 

and sampling point locations; sampling site data; description of sampling and analysis 

procedures and any modifications to standard procedures; quality assurance procedures; record 

of operating conditions during the test; record of preparation of standards; record of calibrations; 

raw data sheets for field sampling; raw data sheets for field and laboratory analyses; 

documentation of calculations; and any other information required by the test method. 

(2) Any requested change in the applicability of an emission standard (e.g., you want to change 

from the PM standard to the Ni standard for catalytic cracking units or from the HCl 

concentration standard to percent reduction for catalytic reforming units) in your compliance

report. You must include all information and data necessary to demonstrate compliance with the 

new emission standard selected and any other associated requirements. 

(g) You may submit reports required by other regulations in place of or as part of the compliance 

report if they contain the required information. 

(h) [Reserved]

(i) If the applicable permitting authority has approved a period of planned maintenance for your 

catalytic cracking unit according to the requirements in paragraph (j) of this section, you must 

include the following information in your compliance report. 

(1) In the compliance report due for the 6-month period before the routine planned maintenance 

is to begin, you must include a full copy of your written request to the applicable permitting 

authority and written approval received from the applicable permitting authority. 

(2) In the compliance report due after the routine planned maintenance is complete, you must 

include a description of the planned routine maintenance that was performed for the control 

device during the previous 6-month period, and the total number of hours during those 6 months 

that the control device did not meet the emission limitations and monitoring requirements as a 

result of the approved routine planned maintenance. 

Deleted: A

Deleted: periodic

Deleted: The reporting requirements in paragraphs 

(h)(1) and (2) of this section apply to startups, 

shutdowns, and malfunctions:¶

(1) When actions taken to respond are consistent 

with the plan, you are not required to report these 

events in the semiannual compliance report and the 

reporting requirements in §§63.6(e)(3)(iii) and 

63.10(d)(5) do not apply.¶

(2) When actions taken to respond are not consistent 

with the plan, you must report these events and the 

response taken in the semiannual compliance report. 

In this case, the reporting requirements in 

§§63.6(e)(3)(iv) and 63.10(d)(5) do not apply.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(j) If you own or operate multiple catalytic cracking units that are served by a single wet 

scrubber emission control device (e.g., a Venturi scrubber), you may request the applicable 

permitting authority to approve a period of planned routine maintenance for the control device 

needed to meet requirements in your operation, maintenance, and monitoring plan. You must 

present data to the applicable permitting authority demonstrating that the period of planned 

maintenance results in overall emissions reductions. During this pre-approved time period, the 

emission control device may be taken out of service while maintenance is performed on the 

control device and/or one of the process units while the remaining process unit(s) continue to 

operate. During the period the emission control device is unable to operate, the emission limits, 

operating limits, and monitoring requirements applicable to the unit that is operating and the wet 

scrubber emission control device do not apply. The applicable permitting authority may require 

that you take specified actions to minimize emissions during the period of planned maintenance. 

(1) You must submit a written request to the applicable permitting authority at least 6 months 

before the planned maintenance is scheduled to begin with a copy to the EPA Regional 

Administrator. 

(2) Your written request must contain the information in paragraphs (j)(2)(i) through (v) of this 

section. 

(i) A description of the planned routine maintenance to be performed during the next 6 months 

and why it is necessary. 

(ii) The date the planned maintenance will begin and end. 

(iii) A quantified estimate of the HAP and criteria pollutant emissions that will be emitted during 

the period of planned maintenance. 

(iv) An analysis showing the emissions reductions resulting from the planned maintenance as 

opposed to delaying the maintenance until the next unit turnaround. 

(v) Actions you will take to minimize emissions during the period of planned maintenance. 

(k) Electronic submittal of performance test and CEMS performance evaluation data. On and 

after [THE DATE 3 YEARS AFTER DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you must submit the results of a 

performance test or CEMS performance evaluation data using EPA’s Electronic Reporting Tool 

(ERT) according to the procedures in paragraphs (k)(1) and (2) of this section. 

(1) Within 60 days after the date of completing each performance test as required by this subpart, 

you must submit the results of the performance tests according to the method specified by either 

paragraphs (k)(1)(i) or (k)(1)(ii) of this section 

(i) For data collected using test methods supported by EPA’s ERT as listed on the EPA’s ERT 

website (http://www.epa.gov/ttn/chief/ert/index.html), you must submit the results of the 

performance test to the CEDRI accessed through the EPA’s CDX 

(http://cdx.epa.gov/epa_home.asp), unless the Administrator approves another approach. 

Performance test data must be submitted in the file format generated through use of the EPA’s 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

ERT. If you claim that some of the performance test information being submitted is confidential 

business information (CBI), you must submit a complete file generated through the use of the 

EPA’s ERT, including information claimed to be CBI, on a compact disc or other commonly 

used electronic storage media (including, but not limited to, flash drives) by registered letter to 

the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. 

EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old 

Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to the 

EPA via CDX as described earlier in this paragraph. 

(ii) For data collected using test methods that are not supported by the EPA’s ERT as listed on 

the EPA’s ERT website, you must submit the results of the performance test to the Administrator 

at the appropriate address listed in §63.13. 

(2) Within 60 days after the date of completing each CEMS performance evaluation required by 

§63.1571(a) and (b), you must submit the results of the performance evaluation according to the 

method specified by either paragraph (k)(2)(i) or (k(2)(ii) of this section. 

(i) For data collection of relative accuracy test audit (RATA) pollutants that are supported by the 

EPA’s ERT as listed on the ERT website, the owner or operator must submit the results of the 

performance evaluation to the CEDRI that is accessed through the EPA’s CDX, unless the 

Administrator approves another approach. Performance evaluation data must be submitted in a 

file format generated through the use of the EPA’s ERT. If an owner or operator claims that 

some of the performance evaluation information being submitted is CBI, the owner or operator 

must submit a complete file generated through the use of the EPA’s ERT, including information 

claimed to be CBI, on a compact disc or other commonly used electronic storage media 

(including, but not limited to, flash drives) by registered letter to the EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: 

WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be submitted to the EPA via CDX as described earlier in this 

paragraph. 

(ii) For any performance evaluation data with RATA pollutants that are not supported by the 

EPA’s ERT as listed on the EPA’s ERT website, you must submit the results of the performance 

evaluation to the Administrator at the appropriate address listed in §63.13. 

§63.1576 What records must I keep, in what form, and for how long? 

(a) You must keep the records specified in paragraphs (a)(1) through (3) of this section. 

(1) A copy of each notification and report that you submitted to comply with this subpart, 

including all documentation supporting any initial notification or Notification of Compliance 

Status that you submitted, according to the requirements in §63.10(b)(2)(xiv). 

(2) The records specified in paragraphs (a)(2)(i) through (iv) of this section. Deleted: §63.6(e)(3)(iii) 

Deleted: v) related to 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) Record the date, time, and duration of each startup and/or shutdown period, recording the 

periods when the affected source was subject to the standard applicable to startup and shutdown. 

(ii) In the event that an affected unit fails to meet an applicable standard, record the number of 

failures. For each failure record the date, time and duration of each failure. 

(iii) For each failure to meet an applicable standard, record and retain a list of the affected 

sources or equipment, an estimate of the volume of each regulated pollutant emitted over any 

emission limit and a description of the method used to estimate the emissions. 

(iv) Record actions taken to minimize emissions in accordance with §63.1570(c) and any 

corrective actions taken to return the affected unit to its normal or usual manner of operation. 

(3) Records of performance tests, performance evaluations, and opacity and visible emission 

observations as required in §63.10(b)(2)(viii). 

(b) For each continuous emission monitoring system and continuous opacity monitoring system, 

you must keep the records required in paragraphs (b)(1) through (5) of this section. 

(1) Records described in §63.10(b)(2)(vi) through (xi). 

(2) Monitoring data for continuous opacity monitoring systems during a performance evaluation 

as required in §63.6(h)(7)(i) and (ii). 

(3) The performance evaluation plan as described in §63.8(d)(2) for the life of the affected 

source or until the affected source is no longer subject to the provisions of this part, to be made 

available for inspection, upon request, by the Administrator. If the performance evaluation plan 

is revised, you must keep previous (i.e., superseded) versions of the performance evaluation plan 

on record to be made available for inspection, upon request, by the Administrator, for a period of 

5 years after each revision to the plan. The program of corrective action should be included in the 

plan required under §63.8(d)(2). 

(4) Requests for alternatives to the relative accuracy test for continuous emission monitoring 

systems as required in §63.8(f)(6)(i). 

(5) Records of the date and time that each deviation started and stopped. 

(c) You must keep the records in §63.6(h) for visible emission observations. 

(d) You must keep records required by Tables 6, 7, 13, and 14 of this subpart (for catalytic 

cracking units); Tables 20, 21, 27 and 28 of this subpart (for catalytic reforming units); Tables 34 

and 35 of this subpart (for sulfur recovery units); and Table 39 of this subpart (for bypass lines) 

to show continuous compliance with each emission limitation that applies to you. 

(e) You must keep a current copy of your operation, maintenance, and monitoring plan onsite 

and available for inspection. You also must keep records to show continuous compliance with 

the procedures in your operation, maintenance, and monitoring plan. 

Deleted: ,

Deleted: , and malfunction

Deleted: Previous (i.e., superceded) versions of the 

performance evaluation plan as required in 

§63.8(d)(3)

Deleted: , and whether the deviation occurred 

during a period of startup, shutdown, or malfunction 

or during another period
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(f) You also must keep the records of any changes that affect emission control system 

performance including, but not limited to, the location at which the vent stream is introduced into 

the flame zone for a boiler or process heater. 

(g) Your records must be in a form suitable and readily available for expeditious review 

according to §63.10(b)(1). 

(h) As specified in §63.10(b)(1), you must keep each record for 5 years following the date of 

each occurrence, measurement, maintenance, corrective action, report, or record. 

(i) You must keep each record on site for at least 2 years after the date of each occurrence, 

measurement, maintenance, corrective action, report, or record, according to §63.10(b)(1). You 

can keep the records offsite for the remaining 3 years. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Other Requirements and Information 

§63.1577 What parts of the General Provisions apply to me? 

Table 44 of this subpart shows which parts of the General Provisions in §§63.1 through 63.15 

apply to you. 

§63.1578 Who implements and enforces this subpart? 

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

such as your State, local, or tribal agency. If the U.S. EPA Administrator has delegated authority 

to your State, local, or tribal agency, then that Agency has the authority to implement and 

enforce this subpart. You should contact your U.S. EPA Regional Office to find out if this 

subpart is delegated to your State, local, or tribal agency. 

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

tribal agency under 40 CFR part 63, subpart E, the authorities contained in paragraph (c) of this 

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

local, or tribal agency. 

(c) The authorities that will not be delegated to State, local, or tribal agencies are listed in 

paragraphs (c)(1) through (5) of this section. 

(1) Approval of alternatives to the non-opacity emission limitations and work practice standards 

in §§63.1564 through 63.1569 under §63.6(g). 

(2) Approval of alternative opacity emission limitations in §§63.1564 through 63.1569 under 

§63.6(h)(9). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(3) Approval of major alternatives to test methods under §63.7(e)(2)(ii) and (f) and as defined in 

§63.90. 

(4) Approval of major alternatives to monitoring under §63.8(f) and as defined in §63.90. 

(5) Approval of major alternatives to recordkeeping and reporting under §63.10(f) and as defined 

in §63.90. 

§63.1579 What definitions apply to this subpart? 

Terms used in this subpart are defined in the Clean Air Act (CAA), in 40 CFR 63.2, the General 

Provisions of this part (§§63.1 through 63.15), and in this section as listed. If the same term is 

defined in subpart A and in this section, it shall have the meaning given in this section for 

purposes of this subpart.

Affirmative defense means, in the context of an enforcement proceeding, a response or defense 

put forward by a defendant, regarding which the defendant has the burden of proof, and the 

merits of which are independently and objectively evaluated in a judicial or administrative 

proceeding. 

Boiler means any enclosed combustion device that extracts useful energy in the form of steam 

and is not an incinerator. 

Catalytic cracking unit means a refinery process unit in which petroleum derivatives are 

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

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

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

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

but is not limited to, 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 equipment used for heat recovery. 

Catalytic cracking unit catalyst regenerator means one or more regenerators (multiple 

regenerators) which comprise that portion of the catalytic cracking unit in which coke burn-off 

and catalyst or contact material regeneration occurs and includes the regenerator combustion air 

blower(s). 

Catalytic reforming unit means a refinery process unit that reforms or changes the chemical 

structure of naphtha into higher octane aromatics through the use of a metal catalyst and 

chemical reactions that include dehydrogenation, isomerization, and hydrogenolysis. The 

catalytic reforming unit includes the reactor, regenerator (if separate), separators, catalyst 

isolation and transport vessels (e.g., lock and lift hoppers), recirculation equipment, scrubbers, 

and other ancillary equipment. 

Catalytic reforming unit regenerator means one or more regenerators which comprise that 

portion of the catalytic reforming unit and ancillary equipment in which the following 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

regeneration steps typically are performed: depressurization, purge, coke burn-off, catalyst 

rejuvenation with a chloride (or other halogenated) compound(s), and a final purge. The catalytic 

reforming unit catalyst regeneration process can be done either as a semi-regenerative, cyclic, or 

continuous regeneration process. 

Coke burn-off means the coke removed from the surface of the catalytic cracking unit catalyst or 

the catalytic reforming unit catalyst by combustion in the catalyst regenerator. The rate of coke 

burn-off is calculated using Equation 2 in §63.1564. 

Combustion device means an individual unit of equipment such as a flare, incinerator, process 

heater, or boiler used for the destruction of organic HAP or VOC. 

Combustion zone means the space in an enclosed combustion device (e.g., vapor incinerator, 

boiler, furnace, or process heater) occupied by the organic HAP and any supplemental fuel while 

burning. The combustion zone includes any flame that is visible or luminous as well as that 

space outside the flame envelope in which the organic HAP continues to be oxidized to form the 

combustion products. 

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

other contaminants from petroleum derivatives. 

Continuous regeneration reforming means a catalytic reforming process characterized by 

continuous flow of catalyst material through a reactor where it mixes with feedstock, and a 

portion of the catalyst is continuously removed and sent to a special regenerator where it is 

regenerated and continuously recycled back to the reactor. 

Control device means any equipment used for recovering, removing, or oxidizing HAP in either 

gaseous or solid form. Such equipment includes, but is not limited to, condensers, scrubbers, 

electrostatic precipitators, incinerators, flares, boilers, and process heaters. 

Cyclic regeneration reforming means a catalytic reforming process characterized by continual 

batch regeneration of catalyst in situ in any one of several reactors (e.g., 4 or 5 separate reactors) 

that can be isolated from and returned to the reforming operation while maintaining continuous 

reforming process operations (i.e., feedstock continues flowing through the remaining reactors 

without change in feed rate or product octane). 

Deviation means any instance in which an affected source subject to this subpart, or an owner or 

operator of such a source: 

(1) Fails to meet any requirement or obligation established by this subpart, including but not 

limited to any emission limit, operating limit, or work practice standard; or

(2) Fails to meet any term or condition that is adopted to implement an applicable requirement in 

this subpart and that is included in the operating permit for any affected source required to obtain 

such a permit.

Emission limitation means any emission limit, opacity limit, operating limit, or visible emission 

limit. 

Deleted: ; or

Deleted: (3) Fails to meet any emission limit, 

operating limit, or work practice standard in this 

subpart during startup, shutdown, or malfunction, 

regardless of whether or not such failure is permitted 

by this subpart.¶
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Flame zone means the portion of a combustion chamber of a boiler or process heater occupied by 

the flame envelope created by the primary fuel. 

Flow indicator means a device that indicates whether gas is flowing, or whether the valve 

position would allow gas to flow, in or through a line. 

Fuel gas system means the offsite and onsite piping and control system that gathers gaseous 

streams generated by the source, may blend them with sources of gas, if available, and transports 

the blended gaseous fuel at suitable pressures for use as fuel in heaters, furnaces, boilers, 

incinerators, gas turbines, and other combustion devices located within or outside of the refinery. 

The fuel is piped directly to each individual combustion device, and the system typically 

operates at pressures over atmospheric. The gaseous streams can contain a mixture of methane, 

light hydrocarbons, hydrogen, and other miscellaneous species. 

HCl means for the purposes of this subpart, gaseous emissions of hydrogen chloride that serve as 

a surrogate measure for total emissions of hydrogen chloride and chlorine as measured by 

Method 26 or 26A in appendix A to part 60 of this chapter or an approved alternative method. 

Incinerator means an enclosed combustion device that is used for destroying organic 

compounds, with or without heat recovery. Auxiliary fuel may be used to heat waste gas to 

combustion temperatures. An incinerator may use a catalytic combustion process where a 

substance is introduced into an exhaust stream to burn or oxidize contaminants while the 

substances itself remains intact, or a thermal process which uses elevated temperatures as a 

primary means to burn or oxidize contaminants. 

Internal scrubbing system means a wet scrubbing, wet injection, or caustic injection control 

device that treats (in-situ) the catalytic reforming unit recirculating coke burn exhaust gases for 

acid (HCl) control during reforming catalyst regeneration upstream of the atmospheric coke burn 

vent. 

Ni means, for the purposes of this subpart, particulate emissions of nickel that serve as a 

surrogate measure for total emissions of metal HAP, including but not limited to: antimony, 

arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium as 

measured by Method 29 in appendix A to part 60 of this chapter or by an approved alternative 

method. 

Nonmethane TOC means, for the purposes of this subpart, emissions of total organic compounds, 

excluding methane, that serve as a surrogate measure of the total emissions of organic HAP 

compounds including, but not limited to, acetaldehyde, benzene, hexane, phenol, toluene, and 

xylenes and nonHAP VOC as measured by Method 25 in appendix A to part 60 of this chapter, 

by the combination of Methods 18 and 25A in appendix A to part 60 of this chapter, or by an 

approved alternative method. 

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

recovery units by converting these emissions to sulfur dioxide. 

PM means, for the purposes of this subpart, emissions of particulate matter that serve as a 

surrogate measure of the total emissions of particulate matter and metal HAP contained in the 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

particulate matter, including but not limited to: antimony, arsenic, beryllium, cadmium, 

chromium, cobalt, lead, manganese, nickel, and selenium as measured by Methods 5, 5B or 5F in 

Appendix A-3 to part 60 of this chapter or by an approved alternative method. 

Process heater means an enclosed combustion device that primarily transfers heat liberated by 

burning fuel directly to process streams or to heat transfer liquids other than water. 

Process vent means, for the purposes of this subpart, a gas stream that is continuously or 

periodically discharged during normal operation of a catalytic cracking unit, catalytic reforming 

unit, or sulfur recovery unit, including gas streams that are discharged directly to the atmosphere, 

gas streams that are routed to a control device prior to discharge to the atmosphere, or gas 

streams that are diverted through a product recovery device line prior to control or discharge to 

the atmosphere. 

Reduced sulfur compounds means hydrogen sulfide, carbonyl sulfide, and carbon disulfide. 

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

recovery units by converting these emissions to hydrogen sulfide. 

Responsible official means responsible official as defined in 40 CFR 70.2. 

Semi-regenerative reforming means a catalytic reforming process characterized by shutdown of 

the entire reforming unit (e.g., which may employ three to four separate reactors) at specified 

intervals or at the owner's or operator's convenience for in situ catalyst regeneration. 

Sulfur recovery unit means a process unit that recovers elemental sulfur from gases that contain 

reduced sulfur compounds and other pollutants, usually by a vapor-phase catalytic reaction of 

sulfur dioxide and hydrogen sulfide. This definition does not include a unit where the modified 

reaction is carried out in a water solution which contains a metal ion capable of oxidizing the 

sulfide ion to sulfur, e.g., the LO-CAT II process. 

TOC means, for the purposes of this subpart, emissions of total organic compounds that serve as 

a surrogate measure of the total emissions of organic HAP compounds including, but not limited 

to, acetaldehyde, benzene, hexane, phenol, toluene, and xylenes and nonHAP VOC as measured 

by Method 25A in appendix A to part 60 of this chapter or by an approved alternative method. 

TRS means, for the purposes of this subpart, emissions of total reduced sulfur compounds, 

expressed as an equivalent sulfur dioxide concentration, that serve as a surrogate measure of the 

total emissions of sulfide HAP carbonyl sulfide and carbon disulfide as measured by Method 15 

in appendix A to part 60 of this chapter or by an approved alternative method. 

Work practice standard means any design, equipment, work practice, or operational standard, or 

combination thereof, that is promulgated pursuant to section 112(h) of the CAA. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Deleted: a
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 1 to Subpart UUU of Part 63—Metal HAP Emission Limits for Catalytic Cracking 

Units 

As stated in §63.1564(a)(1), you shall meet each emission limitation in the following table that 

applies to you. 

For each new or existing 

catalytic cracking unit . . . 

You shall meet the following emission limits for each 

catalyst regenerator vent . . . 

1. Subject to new source 

performance standard (NSPS) for 

PM in 40 CFR 60.102 

PM emissions must not exceed 1.0 gram per kilogram (g/kg) 

(1.0 lb/1,000 lb) of coke burn-off. Before [THE DATE 18 

MONTHS AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], if the discharged gases pass through an 

incinerator or waste heat boiler in which you burn auxiliary 

or in supplemental liquid or solid fossil fuel, the incremental 

rate of PM emissions must not exceed 43.0 grams per 

Gigajoule (g/GJ) or 0.10 pounds per million British thermal 

units (lb/million Btu) of heat input attributable to the liquid 

or solid fossil fuel; and the opacity of emissions must not 

exceed 30 percent, except for one 6-minute average opacity 

reading in any 1-hour period. 

2. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i) 

PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) 

of 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. 

3. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii) 

PM emissions must not exceed 0.5 g/kg coke burn-off (0.5 

lb/1000 lb coke burn-off) or, if a PM CEMS is used, 0.020 

gr/dscf corrected to 0 percent excess air. 

4. Option 1: PM per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1)

PM emissions must not exceed the limits specified in Item 1 

of this table.

5. Option 2: PM concentration 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1)

PM emissions must not exceed 0.040 gr/dscf corrected to 0 

percent excess air. 

6. Option 3: Ni lb/hr limit, not 

subject to the NSPS for PM in 40 

CFR 60.102 or in 40 CFR 

60.102a(b)(1)

Nickel (Ni) emissions must not exceed 13,000 milligrams per 

hour (mg/hr) (0.029 lb/hr). 

7. Option 4: Ni per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or in 40 

CFR 60.102a(b)(1)

Ni emissions must not exceed 1.0 mg/kg (0.001 lb/1,000 lb) 

of coke burn-off in the catalyst regenerator. 

Deleted: the 

Deleted: per 1,000 kg 

Deleted: in the catalyst regenerator;

Deleted: 2

Deleted: NSPS requirements

Deleted: PM emissions must not exceed 1.0 

kg/1,000 kg (1.0 lb/1,000 lb) of coke burn-off in the 

catalyst regenerator; if the discharged gases pass 

through an incinerator or waste heat boiler in which 

you burn auxiliary or supplemental liquid or solid 

fossil fuel, the incremental rate of PM must not 

exceed 43.0 g/GJ (0.10 lb/million Btu) of heat input 

attributable to the liquid or solid fossil fuel; and the 

opacity of emissions must not exceed 30 percent, 

except for one 6-minute average opacity reading in 

any 1-hour period.

Deleted: 3

Deleted: 1.0 kg/1,000 kg (1.0 lb/1,000 lbs) of coke 

burn-off in the catalyst regenerator

Deleted: 4

Deleted: 5

Deleted: Lb/1,000 lbs of

Deleted: s
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Table 2 to Subpart UUU of Part 63—Operating Limits for Metal HAP Emissions From 

Catalytic Cracking Units 

As stated in §63.1564(a)(2), you shall meet each operating limit in the following table that 

applies to you. 

For each new or 

existing 

catalytic 

cracking unit 

. . . 

For this type of 

continuous 

monitoring system 

. . . 

For this type of 

control device . . .

You shall meet this operating 

limit . . . 

1. Subject to the 

NSPS for PM in 

40 CFR 60.102 

a. Continuous 

opacity monitoring 

system used to 

comply with the 30 

percent opacity 

limit in 40 CFR 

60.102 before 

[THE DATE 18 

MONTHS AFTER 

THE DATE OF 

PUBLICATION 

OF THE FINAL 

RULE 

AMENDMENTS 

IN THE 

FEDERAL 

REGISTER].

Not applicable Not applicable. 

b. Continuous 

opacity monitoring 

system used to 

comply with a sitespecific opacity 

limit

Cyclone, fabric 

filter, or electrostatic

precipitator 

Maintain the 3-hour rolling average 

opacity of emissions from your 

catalyst regenerator vent no higher 

than the site-specific opacity limit 

established during the performance 

test. 

c. Continuous 

parameter 

monitoring 

systems. 

Electrostatic 

precipitator 

Maintain the daily average coke 

burn-off rate or daily average flow 

rate no higher than the limit 

established in the performance test; 

and maintain the 3-hour rolling

average total power and secondary 

current above the limit established 

in the performance test. 

Deleted: .

Deleted: .

Deleted: 2. Option 1: NSPS requirements not 

subject to the NSPS for PM in 40 CFR 60.102.... [1]

Moved down [5]: Not applicable.

Formatted Table

Deleted: a

Deleted: .

Deleted: Electrostatic

Deleted: hourly

Deleted: b

Deleted: gas 

Deleted: daily

Deleted: voltage

Deleted: (or total power input) 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing 

catalytic 

cracking unit 

. . . 

For this type of 

continuous 

monitoring system 

. . . 

For this type of 

control device . . .

You shall meet this operating 

limit . . . 

d. Continuous 

parameter 

monitoring 

systems. 

Wet scrubber Maintain the 3-hour rolling average 

pressure drop above the limit 

established in the performance test;

and maintain the 3-hour rolling

average liquid-to-gas ratio above 

the limit established in the 

performance test. 

e. Bag leak 

detection (BLD) 

system 

Fabric filter Maintain particulate loading below 

the BLD alarm set point 

established in the initial adjustment 

of the BLD system or allowable 

seasonal adjustments. 

2. Subject to 

NSPS for PM in 

40 CFR 

60.102a(b)(1)(i) 

a. PM CEMS Not applicable Not applicable. 

b. Continuous 

opacity monitoring 

system used to 

comply with a sitespecific opacity 

limit 

Cyclone or 

electrostatic 

precipitator 

Maintain the 3-hour rolling average 

opacity of emissions from your 

catalyst regenerator vent no higher 

than the site-specific opacity limit 

established during the performance 

test. 

c. Continuous 

parameter 

monitoring systems 

Electrostatic 

precipitator

Maintain the daily average coke 

burn-off rate or daily average flow 

rate no higher than the limit 

established in the performance test; 

and maintain the 3-hour rolling 

average total power and secondary 

current above the limit established 

in the performance test. 

d. Continuous 

parameter 

monitoring systems 

Wet scrubber Maintain the 3-hour rolling average 

pressure drop above the limit 

established in the performance test; 

and maintain the 3-hour rolling 

average liquid-to-gas ratio above 

the limit established in the 

performance test. 

e. Bag leak 

detection (BLD) 

Fabric filter Maintain particulate loading below 

the BLD alarm set point 

Deleted: c

Deleted: daily

Deleted: (not applicable to a wet scrubber of the 

non-venturi jet-ejector design);

Deleted: daily

Moved (insertion) [2]

Moved (insertion) [3]
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing 

catalytic 

cracking unit 

. . . 

For this type of 

continuous 

monitoring system 

. . . 

For this type of 

control device . . .

You shall meet this operating 

limit . . . 

system established in the initial adjustment 

of the BLD system or allowable 

seasonal adjustments. 

3. Subject to 

NSPS for PM in 

40 CFR 

60.102a(b)(1)(ii) 

Any Any The applicable operating limits in 

Item 2 of this table. 

4. Option 1: PM 

per coke burn-off 

limit not subject 

to the NSPS for 

PM in 40 CFR 

60.102 or 40 

CFR 

60.102a(b)(1)

a. Continuous 

opacity monitoring 

system used to 

comply with a sitespecific opacity 

limit

Cyclone, fabric 

filter, or electrostatic

precipitator 

Maintain the 3-hour rolling average 

opacity of emissions from your 

catalyst regenerator vent no higher 

than the site-specific opacity limit 

established during the performance 

test. Alternatively, before [THE 

DATE 18 MONTHS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], you 

may maintain the hourly average 

opacity of emissions from your 

catalyst generator vent no higher 

than the site-specific opacity limit 

established during the performance 

test.

b. Continuous 

parameter 

monitoring systems 

i. Electrostatic 

precipitator 

(1) Maintain the daily average gas 

flow rate or daily average coke 

burn-off rate no higher than the 

limit established in the 

performance test. 

(2) Maintain the 3-hour rolling 

average total power and secondary 

current above the limit established 

in the performance test. 

Alternatively, before [THE DATE 

18 MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

you may maintain the daily average 

voltage and secondary current (or 

Formatted Table

Deleted: 3: Ni lb/hr

Deleted: .

Deleted: .

Deleted: Electrostatic

Deleted: daily

Deleted: Ni operating value
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing 

catalytic 

cracking unit 

. . . 

For this type of 

continuous 

monitoring system 

. . . 

For this type of 

control device . . .

You shall meet this operating 

limit . . . 

total power input) above the limit 

established in the performance test. 

ii. Wet scrubber (1) Maintain the 3-hour rolling 

average pressure drop above the 

limit established in the 

performance test. Alternatively, 

before [THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], you 

may maintain the daily average 

pressure drop above the limit 

established in the performance test 

(not applicable to a wet scrubber of 

the non-venturi jet-ejector design). 

(2) Maintain the 3-hour rolling 

average liquid-to-gas ratio above 

the limit established in the 

performance test. Alternatively, 

before [THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], you 

may maintain the daily average 

liquid-to-gas ratio above the limit 

established in the performance test. 

c. Bag leak 

detection (BLD) 

system 

Fabric filter Maintain particulate loading below 

the BLD alarm set point 

established in the initial adjustment 

of the BLD system or allowable 

seasonal adjustments. 

5. Option 2: PM 

concentration 

limit not subject 

to the NSPS for 

PM in 40 CFR 

60.102 or 40 

CFR 

PM CEMS Any Not applicable.

Moved (insertion) [4]

Moved (insertion) [5]
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing 

catalytic 

cracking unit 

. . . 

For this type of 

continuous 

monitoring system 

. . . 

For this type of 

control device . . .

You shall meet this operating 

limit . . . 

60.102a(b)(1) 

6. Option 3: Ni 

lb/hr limit not 

subject to the 

NSPS for PM in 

40 CFR 60.102

a. Continuous 

opacity monitoring 

system 

Cyclone, fabric 

filter, or electrostatic

precipitator 

Maintain the 3-hour rolling average 

Ni operating value no higher than 

the limit established during the 

performance test. Alternatively, 

before [THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], you 

may maintain the daily average Ni 

operating value no higher than the 

limit established during the 

performance test. 

b. Continuous 

parameter 

monitoring systems 

i. Electrostatic

precipitator 

(1) Maintain the daily average gas 

flow rate or daily average coke 

burn-off rate no higher than the 

limit established during the 

performance test. 

(2) Maintain the monthly rolling 

average of the equilibrium catalyst 

Ni concentration no higher than the 

limit established during the 

performance test. 

(3) Maintain the 3-hour rolling 

average total power and secondary 

current above the limit established 

in the performance test. 

Alternatively, before [THE DATE 

18 MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

you may maintain the daily average 

voltage and secondary current (or 

total power input) above the 

established during the performance 

test. 

ii. Wet scrubber (1) Maintain the monthly rolling 

Formatted Table

Deleted: b

Deleted: parameter

Deleted: s.

Moved down [6]: i. Electrostatic

Deleted: daily

Deleted: gas flow rate

Deleted: ;

Deleted: monthly rolling

Deleted: of the equilibrium catalyst 

Deleted: concentration

Deleted: ; and maintain the daily average voltage 

and secondary current (or total power input) above 

the established during the performance test

Moved (insertion) [6]
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing 

catalytic 

cracking unit 

. . . 

For this type of 

continuous 

monitoring system 

. . . 

For this type of 

control device . . .

You shall meet this operating 

limit . . . 

average of the equilibrium catalyst 

Ni concentration no higher than the 

limit established during the 

performance test. 

(2) Maintain the 3-hour rolling 

average pressure drop above the 

limit established in the 

performance test. Alternatively, 

before [THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], you 

may maintain the daily average 

pressure drop above the limit 

established during the performance 

test (not applicable to a non-venturi 

wet scrubber of the jet-ejector 

design).

(3) Maintain the 3-hour rolling 

average liquid-to-gas ratio above 

the limit established in the 

performance test. Alternatively, 

before [THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], you 

may maintain the daily average 

liquid-to-gas ratio above the limit 

established during the performance 

test. 

7. Option 4: Ni 

per coke burn-off 

limit not subject 

to the NSPS for 

PM in 40 CFR 

60.102 

a. Continuous 

opacity monitoring 

system 

Cyclone, baghouse, 

or electrostatic

precipitator 

Maintain the 3-hour rolling average 

Ni operating value no higher than 

Ni operating limit established 

during the performance test. 

Alternatively, before [THE DATE 

18 MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

Formatted Table

Deleted: ii. 

Moved up [3]: Wet scrubber

Deleted: monthly

Deleted: of the equilibrium catalyst Ni 

concentration no higher than

Deleted: dur

Deleted: g

Deleted: ;

Deleted: ); and maintain the daily average liquidto-gas ratio above the limit established during the 

performance test.

Deleted: 5

Formatted Table

Deleted: lb/1,000 lbs of

Deleted: Electrostatic

Deleted: Maintain
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing 

catalytic 

cracking unit 

. . . 

For this type of 

continuous 

monitoring system 

. . . 

For this type of 

control device . . .

You shall meet this operating 

limit . . . 

IN THE FEDERAL REGISTER], 

you may elect to maintain the daily 

average Ni operating value no 

higher than the Ni operating limit 

established during the performance 

test. 

b. Continuous 

parameter 

monitoring systems 

i. Electrostatic 

precipitator 

(1) Maintain the monthly rolling 

average of the equilibrium catalyst 

Ni concentration no higher than the 

limit established during the 

performance test. 

(2) Maintain the 3-hour rolling 

average total power and secondary 

current above the limit established 

in the performance test. 

Alternatively, before [THE DATE 

18 MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

you may maintain the daily average 

voltage and secondary current (or 

total power input) above the limit 

established during the performance 

test. 

ii. Wet scrubber (1) Maintain the monthly rolling 

average of the equilibrium catalyst 

Ni concentration no higher than the 

limit established during the 

performance test. 

(2) Maintain the 3-hour rolling 

average pressure drop above the 

limit established in the 

performance test. Alternatively, 

before [THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], you 

may maintain the daily average 

Formatted Table

Deleted: b. Continuous parameter monitoring 

systems.

Deleted: i. Electrostatic precipitator

Deleted: monthly

Deleted: of the equilibrium catalyst Ni 

concentration no higher than

Deleted: dur

Deleted: g

Deleted: ; and

Deleted: f

Formatted Table

Moved up [4]: ii. Wet scrubber

Deleted: monthly

Deleted: of the equilibrium catalyst Ni 

concentration no higher than

Deleted: dur

Deleted: g

Deleted: ;
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing 

catalytic 

cracking unit 

. . . 

For this type of 

continuous 

monitoring system 

. . . 

For this type of 

control device . . .

You shall meet this operating 

limit . . . 

pressure drop above the limit 

established during the performance 

test (not applicable to a non-venturi 

wet scrubber of the jet-ejector 

design).

(3) Maintain the 3-hour rolling 

average liquid-to-gas ratio above 

the limit established in the 

performance test. Alternatively, 

before [THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], you 

may maintain the daily average 

liquid-to-gas ratio above the limit 

established during the performance 

test. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Table 3 to Subpart UUU of Part 63—Continous Monitoring Systems for Metal HAP 

Emissions From Catalytic Cracking Units 

As stated in §63.1564(b)(1), you shall meet each requirement in the following table that applies 

to you. 

For each new or existing 

catalytic cracking unit 

. . . 

If you use this 

type of control 

device for your 

vent . . . 

You shall install, operate, and 

maintain a . . . 

1. Subject to the NSPS for 

PM in 40 CFR 60.102 

a. Cyclone Continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent. 

b. Electrostatic 

precipitator 

Continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent; or continuous 

Deleted: ); and maintain the daily average liquidto-gas ratio above the limit established during the 

performance test.

Deleted: If your catalytic cracking unit is . . .

Deleted: And

Deleted: 1. Subject to the NSPS for PM in 40 CFR 

60.102

Deleted: Any size

Deleted: or wet scrubber or no control device

Deleted: .
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or existing 

catalytic cracking unit 

. . . 

If you use this 

type of control 

device for your 

vent . . . 

You shall install, operate, and 

maintain a . . . 

parameter monitoring systems to 

measure and record the coke burn-off 

rate or the gas flow rate entering or 

exiting the control device1 and the total 

power and secondary current to the 

control device.

c. Wet scrubber Continuous parameter monitoring 

system to measure and record the 

pressure drop across the scrubber2, 

coke burn-off rate or the gas flow rate 

entering or exiting the control device1, 

and total liquid (or scrubbing liquor) 

flow rate to the control device. 

Alternatively, before [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], continuous

opacity monitoring system to measure 

and record the opacity of emissions 

from each catalyst regenerator vent. 

d. Fabric Filter Continuous bag leak detection system 

to measure and record increases in 

relative particulate loading from each 

catalyst regenerator vent or a 

continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent. 

2. Subject to NSPS for 

PM in 40 CFR 

60.102a(b)(1)(i) electing 

to meet the PM per coke 

burn-off limit.

a. Cyclone Continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent. 

 b. Electrostatic 

precipitator 

Continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent; or continuous 

parameter monitoring systems to 

measure and record the coke burn-off 

rate or the gas flow rate entering or 

Deleted: If your catalytic cracking unit is . . .

Deleted: And

Deleted: 2. Option 1: NSPS limits not subject to 

the NSPS for PM in 40 CFR 60.102

Deleted: Any size

Deleted: Electrostatic precipitator or wet

Deleted: or no control device

Deleted: Continuous

Deleted: 3. Option 

Deleted: : PM limit not subject

Deleted: the 

Deleted: 102

Deleted: a. Over 20,000 barrels per day fresh feed 

capacity

Moved up [2]: Electrostatic precipitator

Deleted: b. Up to 20,000 barrels per day fresh feed 

capacity
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or existing 

catalytic cracking unit 

. . . 

If you use this 

type of control 

device for your 

vent . . . 

You shall install, operate, and 

maintain a . . . 

exiting the control device,1 the voltage, 

current, and secondary current to the 

control device. 

 c. Wet scrubber Continuous parameter monitoring 

system to measure and record the 

pressure drop across the scrubber2

, the 

coke burn-off rate or the gas flow rate 

entering or exiting the control device1, 

and total liquid (or scrubbing liquor) 

flow rate to the control device. 

 d. Fabric Filter Continuous bag leak detection system 

to measure and record increases in 

relative particulate loading from each 

catalyst regenerator vent.

3. Subject to NSPS for 

PM in 40 CFR 

60.102a(b)(1)(i) electing 

to meet the PM 

concentration limit.

Any Continuous emission monitoring 

system to measure and record the 

concentration of PM and oxygen from 

each catalyst regenerator vent. 

4. Subject to NSPS for 

PM in 40 CFR 

60.102a(b)(1)(ii) electing 

to meet the PM per coke 

burn-off limit. 

Any See item 2 of this table. 

5. Subject to NSPS for 

PM in 40 CFR 

60.102a(b)(1)(ii) electing 

to meet the PM 

concentration limit. 

Any See item 3 of this table. 

6. Option 1: PM per coke 

burn-off limit not subject 

to the NSPS for PM in 40 

CFR 60.102 or 40 CFR 

60.120a(b)(1). 

Any See item 1 of this table. 

7. Option 2: PM 

concentration limit not 

subject to the NSPS for 

PM in 40 CFR 60.102 or 

40 CFR 60.120a(b)(1) 

Any See item 3 of this table. 

Deleted: If your catalytic cracking unit is . . .

Deleted: And

Deleted: device1 and

Deleted: (or total power input) 

Deleted: c. Any size

Deleted: i

Deleted: (1) 

Deleted: scrubber,

Deleted: (2) If you use a wet scrubber of the nonventuri jet-ejector design, you're not required to 

install and operate a continuous parameter 

monitoring system for pressure drop.

Deleted: d. Any size

Deleted: No electrostatic precipitator or wet 

scrubber

Deleted: opacity

Deleted: opacity

Deleted: emissions

Moved (insertion) [7]
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or existing 

catalytic cracking unit 

. . . 

If you use this 

type of control 

device for your 

vent . . . 

You shall install, operate, and 

maintain a . . . 

8. Option 3: Ni lb/hr limit 

not subject to the NSPS 

for PM in 40 CFR 60.102

or in 40 CFR 

60.102a(b)(1)

a. Cyclone Continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent and continuous 

parameter monitoring system to 

measure and record the coke burn-off 

rate or the gas flow rate entering or 

exiting the control device1. 

 b. Electrostatic 

precipitator 

Continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent and continuous 

parameter monitoring system to 

measure and record the coke burn-off 

rate or the gas flow rate entering or 

exiting the control device1; or 

continuous parameter monitoring 

systems to measure and record the 

coke burn-off rate or the gas flow rate 

entering or exiting the control device1

and the voltage and current [to 

measure the total power to the system] 

and secondary current to the control 

device. 

 c. Wet scrubber Continuous parameter monitoring 

system to measure and record the 

pressure drop across the scrubber2

, gas 

flow rate entering or exiting the control 

device1

, and total liquid (or scrubbing 

liquor) flow rate to the control device. 

 d. Fabric Filter Continuous bag leak detection system 

to measure and record increases in 

relative particulate loading from each 

catalyst regenerator vent or the 

monitoring systems specified in item 

8.a of this table. 

9. Option 4: Ni lb/1,000 

lbs of coke burn-off limit 

not subject to the NSPS 

for PM in 40 CFR 60.102

a. Cyclone Continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent and continuous 

Deleted: If your catalytic cracking unit is . . .

Deleted: And

Deleted: 4

Deleted: a. Over 20,000 barrels per day fresh feed 

capacity

Deleted: Electrostatic precipitator

Deleted: b. Up to 20,000 barrels per day fresh feed 

capacity

Deleted: (or total power input) 

Deleted: c. 

Moved up [7]: Any 

Deleted: size

Deleted: (1) 

Deleted: ¶ ... [2]

Deleted: d. Any size

Deleted: No electrostatic precipitator or wet 

scrubber

Deleted: opacity monitoring 

Deleted: the opacity of emissions

Deleted: and continuous parameter monitoring 

system to measure and record the gas flow rate1

Deleted: 5

Deleted: a. Over 20,000 barrels per day fresh feed 

capacity

Deleted: Electrostatic precipitator
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or existing 

catalytic cracking unit 

. . . 

If you use this 

type of control 

device for your 

vent . . . 

You shall install, operate, and 

maintain a . . . 

or in 40 CFR 

60.102a(b)(1)

parameter monitoring system to 

measure and record the gas flow rate 

entering or exiting the control device1

. 

 b. Electrostatic 

precipitator 

Continuous opacity monitoring system 

to measure and record the opacity of 

emissions from each catalyst 

regenerator vent and continuous 

parameter monitoring system to 

measure and record the coke burn-off 

rate or the gas flow rate entering or 

exiting the control device1; or 

continuous parameter monitoring 

systems to measure and record the 

coke burn-off rate or the gas flow rate 

entering or exiting the control device1

and voltage and current [to measure 

the total power to the system] and 

secondary current to the control 

device. 

 c. Wet scrubber Continuous parameter monitoring 

system to measure and record the 

pressure drop across the scrubber2

, gas 

flow rate entering or exiting the control 

device1

, and total liquid (or scrubbing 

liquor) flow rate to the control device. 

 d. Fabric Filter Continuous bag leak detection system 

to measure and record increases in 

relative particulate loading from each 

catalyst regenerator vent or the 

monitoring systems specified in item 

9.a of this table. 

1

If applicable, you can use the alternative in §63.1573(a)(1) instead of a continuous parameter 

monitoring system for gas flow rate. 

2

If you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing 

spray nozzles, you can use the alternative in §63.1573(b) instead of a continuous parameter 

monitoring system for pressure drop across the scrubber. 

[70 FR 6942, Feb. 9, 2005] 

Deleted: If your catalytic cracking unit is . . .

Deleted: And

Deleted: b. Up to 20,000 barrels per day fresh feed 

capacity

Deleted: the 

Deleted: (or total power input) 

Deleted: c. Any size

Deleted: d. Any size

Deleted: No electrostatic precipitator or wet 

scrubber

Deleted: opacity monitoring 

Deleted: the opacity of emissions

Deleted: and continuous parameter monitoring 

system to measure and record the gas flow rate1
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 4 to Subpart UUU of Part 63—Requirements for Performance Tests for Metal HAP 

Emissions From Catalytic Cracking Units Not Subject to the New Source Performance 

Standard (NSPS) for Particulate Matter (PM) 

As stated in §63.1564(b)(2), you shall meet each requirement in the following table that applies 

to you. 

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

1. Any. a. Select sampling 

port's location and the 

number of traverse 

ports. 

Method 1 or 1A in 

Appendix A-1 to part 

60 of this chapter. 

Sampling sites must be 

located at the outlet of the 

control device or the 

outlet of the regenerator, 

as applicable, and prior to 

any releases to the 

atmosphere. 

 b. Determine velocity 

and volumetric flow 

rate. 

Method 2, 2A, 2C, 

2D, 2F in Appendix 

A-1 to part 60 of this 

chapter, or 2G in 

Appendix A-2 to part 

60 of this chapter, as 

applicable. 

 c. Conduct gas 

molecular weight 

analysis. 

Method 3, 3A, or 3B 

in Appendix A-2 to 

part 60 of this 

chapter, as applicable.

 d. Measure moisture 

content of the stack 

gas. 

Method 4 in 

Appendix A-3 to part 

60 of this chapter. 

 e. If you use an 

electrostatic

precipitator, record the 

total number of fields 

in the control system 

and how many 

operated during the 

applicable performance 

test. 

 

 f. If you use a wet 

scrubber, record the 

 

Deleted: 1. If you elect Option 1 in item 2 of Table 

1, Option 2 in item 3 of Table 1, Option 3 in item 4 

of Table 1, or Option 4 in item 5 of Table 1 of this 

subpart.

Deleted: a

Deleted: , 

Deleted: a

Deleted: a

Deleted: a

Deleted: electro-static
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

total amount (rate) of 

water (or scrubbing 

liquid) and the amount 

(rate) of make-up 

liquid to the scrubber 

during each test run. 

2. Option 1: PM per 

coke burn-off limit, 

not subject to the

NSPS for PM in 40 

CFR 60.102 or in 40 

CFR 60.102a(b)(1)

a. Measure PM 

emissions. 

Method 5, 5B, or 5F 

(40 CFR part 60, 

Appendix A-3) to 

determine PM 

emissions and 

associated moisture 

content for units 

without wet 

scrubbers. Method 5 

or 5B (40 CFR part 

60, Appendix A-3) to 

determine PM 

emissions and 

associated moisture 

content for unit with 

wet scrubber. 

You must maintain a 

sampling rate of at least 

0.15 dry standard cubic 

meters per minute 

(dscm/min) (0.53 dry 

standard cubic feet per 

minute (dscf/min). 

 b. Compute coke burnoff rate and PM 

emission rate (lb/1,000 

lb of coke burn-off).

Equations 1, 2, and 3 

of §63.1564 (if 

applicable). 

c. Measure opacity of 

emissions.

Continuous opacity 

monitoring system. 

You must collect opacity 

monitoring data every 10 

seconds during the entire 

period of the Method 5, 

5B, or 5F performance 

test and reduce the data to 

6-minute averages. 

3. Option 2: PM 

concentration limit, 

not subject to the 

NSPS for PM in 40 

CFR 60.102 or in 40 

CFR 60.102a(b)(1)

a. Measure PM 

concentration. 

Method 5, 5B, or 5F 

(40 CFR part 60, 

Appendix A-3) to 

determine PM 

concentration and 

associated moisture 

content for units 

You must maintain a 

sampling rate of at least 

0.15 dry standard cubic 

meters per minute 

(dscm/min) (0.53 dry 

standard cubic feet per 

Deleted: Elect

Deleted: a

Deleted: a

Deleted: s

Deleted: s)

Deleted: .

Deleted: ¶

c. Measure opacity of emissions. ... [3]

Moved down [8]: c. Measure opacity of 

Formatted Table

Moved (insertion) [8]

Deleted: c. Establish your site-specific opacity 

operating limit if you use a continuous opacity 

monitoring system.

Deleted: Data from the continuous

Deleted: ; determine and record the hourly average 

opacity from all the 6-minute averages; and compute 

the site-specific limit using Equation 4 of §63.1564

Deleted: 4. Option 3: Ni lb/hr

Deleted: of Ni and total metal HAP

Deleted: Method 29 (40 CFR part 60, appendix 

A).
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

without wet 

scrubbers. Method 5 

or 5B (40 CFR part 

60, Appendix A-3) to 

determine PM 

concentration and 

associated moisture 

content for unit with 

wet scrubber.

minute (dscf/min).

4. Option 3: Ni lb/hr 

limit, not subject to 

the NSPS for PM in 

40 CFR 60.102 or in 

40 CFR 

60.102a(b)(1) 

a. Measure 

concentration of Ni. 

Method 29 (40 CFR 

part 60, Appendix A8). 

 b. Compute Ni 

emission rate (lb/hr). 

Equation 5 of 

§63.1564. 

c. Determine the 

equilibrium catalyst Ni 

concentration. 

XRF procedure in 

Appendix A to this 

subpart1; or EPA 

Method 6010B or 

6020 or EPA Method 

7520 or 7521 in SW–

8462; or an alternative 

to the SW-846 

method satisfactory to 

the Administrator. 

You must obtain 1 

sample for each of the 3 

runs; determine and 

record the equilibrium 

catalyst Ni concentration 

for each of the 3 samples; 

and you may adjust the 

laboratory results to the 

maximum value using 

Equation 2 of §63.1571. 

 d. If you use a 

continuous opacity 

monitoring system, 

establish your sitespecific Ni operating 

limit. 

i. Equations 6 and 7 

of §63.1564 using 

data from continuous 

opacity monitoring 

system, gas flow rate, 

results of equilibrium 

catalyst Ni 

concentration 

analysis, and Ni 

emission rate from 

Method 29 test. 

(1) You must collect 

opacity monitoring data 

every 10 seconds during 

the entire period of the 

initial Ni performance 

test; reduce the data to 6-

minute averages; and 

determine and record the 

hourly average opacity 

from all the 6-minute 

averages. 

 (2) You must collect gas 

Formatted Table

Deleted: a

Deleted: -
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

flow rate monitoring data 

every 15 minutes during 

the entire period of the 

initial Ni performance 

test; measure the gas flow 

as near as practical to the 

continuous opacity 

monitoring system; and 

determine and record the 

hourly average actual gas 

flow rate from all the 

readings. 

5. Option 4: Ni per

coke burn-off limit, 

not subject to the 

NSPS for PM in 40 

CFR 60.102 or in 40 

CFR 60.102a(b)(1)

a. Measure 

concentration of Ni. 

Method 29 (40 CFR 

part 60, Appendix A8). 

 b. Compute Ni 

emission rate (lb/1,000 

lb of coke burn-off). 

Equations 1 and 8 of 

§63.1564. 

 c. Determine the 

equilibrium catalyst Ni 

concentration. 

See item 4.c. of this 

table. 

You must obtain 1 

sample for each of the 3 

runs; determine and 

record the equilibrium 

catalyst Ni concentration 

for each of the 3 samples; 

and you may adjust the 

laboratory results to the 

maximum value using 

Equation 2 of §63.1571. 

 d. If you use a 

continuous opacity 

monitoring system, 

establish your sitespecific Ni operating 

limit. 

i. Equations 9 and 10 

of §63.1564 with data 

from continuous 

opacity monitoring 

system, coke burn-off 

rate, results of 

equilibrium catalyst 

Ni concentration 

analysis, and Ni 

(1) You must collect 

opacity monitoring data 

every 10 seconds during 

the entire period of the 

initial Ni performance 

test; reduce the data to 6-

minute averages; and 

determine and record the 

hourly average opacity 

Deleted: lbs/1,000 lbs of

Deleted: and total HAP

Deleted: a

Deleted: s
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

emission rate from 

Method 29 test. 

from all the 6-minute 

averages. 

 (2) You must collect gas 

flow rate monitoring data 

every 15 minutes during 

the entire period of the 

initial Ni performance 

test; measure the gas flow 

rate as near as practical to 

the continuous opacity 

monitoring system; and 

determine and record the 

hourly average actual gas 

flow rate from all the 

readings. 

 e. Record the catalyst 

addition rate for each 

test and schedule for 

the 10-day period prior 

to the test. 

 

6. If you elect 

Option 1 in item 4 in 

Table 1, Option 3 in 

item 6 in Table 1, or 

Option 4 in item 7 in 

Table 1 of this 

subpart and you use 

continuous 

parameter 

monitoring systems. 

a. Establish each 

operating limit in Table 

2 of this subpart that 

applies to you. 

Data from the 

continuous parameter 

monitoring systems 

and applicable 

performance test 

methods. 

 b. Electrostatic 

precipitator or wet 

scrubber: gas flow rate. 

i. Data from the 

continuous parameter 

monitoring systems 

and applicable 

performance test 

methods. 

(1) You must collect gas 

flow rate monitoring data 

every 15 minutes during 

the entire period of the 

initial performance test. 

(2) You must determine 

and record the 3-hr 

average gas flow rate 

Deleted: 

Deleted: 2

Deleted: Entry 3 in Table 1, Option 3 in Entry

Deleted: Entry 5

Deleted: ; and determine and record the maximum 

hourly average gas flow rate from all the readings
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

from all the readings. 

Alternatively, before 

[THE DATE 18 

MONTHS AFTER THE 

DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER], you may 

determine and record the 

maximum hourly average 

gas flow rate from all the 

readings. 

 c. Electrostatic 

precipitator: voltage 

and secondary current 

(or total power input). 

i. Data from the 

continuous parameter 

monitoring systems 

and applicable 

performance test 

methods. 

(1) You must collect 

voltage, current, and 

secondary current 

monitoring data every 15 

minutes during the entire 

period of the performance 

test. Alternatively, before 

[THE DATE 18 

MONTHS AFTER THE 

DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER], you may

collect voltage and 

secondary current (or 

total power input) 

monitoring data every 15 

minutes during the entire 

period of the initial 

performance test. 

(2) You must determine 

and record the 3-hr 

average total power to the 

system and the 3-hr 

Deleted: ; and determine and record the minimum 

hourly average voltage and secondary current (or 

total power input) from all the readings
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

average secondary 

current. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER], you may 

determine and record the 

minimum hourly average 

voltage and secondary 

current (or total power 

input) from all the 

readings. 

 d. Electrostatic 

precipitator or wet 

scrubber: equilibrium 

catalyst Ni 

concentration. 

Results of analysis for 

equilibrium catalyst 

Ni concentration. 

You must determine and 

record the average 

equilibrium catalyst Ni 

concentration for the 3 

runs based on the 

laboratory results. You 

may adjust the value 

using Equation 1 or 2 of 

§63.1571 as applicable. 

 e. Wet scrubber: 

pressure drop (not 

applicable to nonventuri scrubber of jet 

ejector design). 

i. Data from the 

continuous parameter 

monitoring systems 

and applicable 

performance test 

methods. 

(1) You must collect 

pressure drop monitoring 

data every 15 minutes 

during the entire period 

of the initial performance 

test. 

(2) You must determine 

and record the 3-hr 

average pressure drop 

from all the readings. 

Alternatively, before 

[THE DATE 18 

MONTHS AFTER THE 

DATE OF 

PUBLICATION OF THE 

Deleted: ; and determine and record the minimum 

hourly average pressure drop from all the readings
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER], you may 

determine and record the 

minimum hourly average 

pressure drop from all the 

readings. 

 f. Wet scrubber: liquidto-gas ratio i. Data from the 

continuous parameter 

monitoring systems 

and applicable 

performance test 

methods. 

(1) You must collect gas 

flow rate and total water 

(or scrubbing liquid) flow 

rate monitoring data 

every 15 minutes during 

the entire period of the 

initial performance test. 

(2) You must determine 

and record the hourly 

average liquid-to-gas 

ratio from all the 

readings. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER], you may 

determine and record the 

hourly average gas flow 

rate and total water (or 

scrubbing liquid) flow 

rate from all the readings. 

(3) You must determine 

and record the 3-hr 

average liquid-to-gas 

ratio. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF 

Deleted: ; determine and record the hourly average 

gas flow rate and total water (or scrubbing liquid) 

flow rate from all the readings; and determine and 

record the minimum liquid-to-gas ratio
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit 

catalyst regenerator 

vent . . . You must . . . Using . . . 

According to these 

requirements . . . 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER], you may 

determine and record the 

minimum liquid-to-gas 

ratio. 

 g. Alternative 

procedure for gas flow 

rate. 

i. Data from the 

continuous parameter 

monitoring systems 

and applicable 

performance test 

methods. 

(1) You must collect air 

flow rate monitoring data 

or determine the air flow 

rate using control room 

instrumentation every 15 

minutes during the entire 

period of the initial 

performance test. 

(2) You must determine 

and record the 3-hr 

average rate of all the 

readings. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER], you may 

determine and record the 

hourly average rate of all 

the readings. 

(3) You must determine 

and record the maximum 

gas flow rate using 

Equation 1 of §63.1573. 

1

Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure). 

2

EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA 

Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel 

Atomic Absorption, Direct Aspiration, and EPA Method 7521, Nickel Atomic Absorption, 

Deleted: ; determine and record the hourly average 

rate of all the readings; and determine and record the 

maximum gas flow rate using Equation 1 of 

§63.1573
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Direct Aspiration are included in “Test Methods for Evaluating Solid Waste, Physical/Chemical 

Methods,” EPA Publication SW-846, Revision 5 (April 1998). The SW-846 and Updates 

(document number 955-001-00000-1) are available for purchase from the Superintendent of 

Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 512-1800; and 

from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, 

VA 22161, (703) 487-4650. Copies may be inspected at the EPA Docket Center (Air Docket), 

EPA West, Room B-108, 1301 Constitution Ave., NW., Washington, DC; or at the Office of the 

Federal Register, 800 North Capitol Street, NW., Suite 700, Washington, DC. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6944, Feb. 9, 2005] 

Table 5 to Subpart UUU of Part 63—Initial Compliance With Metal HAP Emission Limits 

for Catalytic Cracking Units 

As stated in §63.1564(b)(5), you shall meet each requirement in the following table that applies 

to you. 

For each new and 

existing catalytic 

cracking unit catalyst 

regenerator vent . . . 

For the following emission limit . 

. . 

You have demonstrated initial 

compliance if . . . 

1. Subject to the NSPS 

for PM in 40 CFR 

60.102

PM emissions must not exceed 1.0 

gram per kilogram (g/kg) (1.0 

lb/1,000 lb) of coke burn-off. 

Before [THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], if the 

discharged gases pass through an 

incinerator or waste heat boiler in 

which you burn auxiliary or 

supplemental liquid or solid fossil 

fuel, the incremental rate of PM 

must not exceed 43.0 grams per 

Gigajoule (g/GJ) or 0.10 pounds 

per million British thermal units 

(lb/million Btu) of heat input 

attributable to the liquid or solid 

fossil fuel; and the opacity of 

emissions must not exceed 30 

percent, except for one 6-minute 

average opacity reading in any 1-

hour period 

You have already conducted a 

performance test to demonstrate 

initial compliance with the NSPS 

and the measured PM emission 

rate is less than or equal to 1.0 

g/kg (1.0 lb/1,000 lb) of coke 

burn-off in the catalyst 

regenerator. As part of the 

Notification of Compliance Status, 

you must certify that your vent 

meets the PM limit. You are not 

required to do another 

performance test to demonstrate 

initial compliance. As part of your 

Notification of Compliance Status, 

you certify that your BLD; CO2, 

O2, or CO monitor; or continuous 

opacity monitoring system meets 

the requirements in §63.1572.

Deleted: /1,000 kg

Deleted: in the catalyst regenerator;

Deleted: kg/1,000 

Deleted: If applicable, you have already conducted 

a performance test to demonstrate initial compliance 

with the NSPS and the measured PM rate is less than 

or equal to 43.0 g/GJ (0.10 lb/million Btu) of heat 

input attributable to the liquid or solid fossil fuel. As 

part of the Notification of Compliance Status, you 

must certify that your vent meets the PM emission 

limit.

Moved down [9]: You are not required to do 

another performance test to demonstrate initial 

compliance. 

Deleted: You have already conducted a 

performance test to demonstrate initial compliance 

with the NSPS and the average hourly opacity is no 

more than 30 percent. Except: One 6-minute average 

in any 1-hour period can exceed 30 percent. As part 

of the Notification of Compliance Status, you must 

certify that your vent meets the opacity limit.

Moved down [10]: You are not required to do 

another performance test to demonstrate initial 

compliance. 

Deleted: You have already conducted a 

performance evaluation to demonstrate initial 

compliance with the applicable performance 

specification. As part of your Notification of 

Compliance Status, you certify that your continuous 

opacity monitoring system meets the requirements in 

§63.1572. You are not required to do a performance 

evaluation to demonstrate initial compliance.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit catalyst 

regenerator vent . . . 

For the following emission limit . 

. . 

You have demonstrated initial 

compliance if . . . 

2. Subject to NSPS for 

PM in 40 CFR 

60.102a(b)(1)(i), 

electing to meet the 

PM per coke burn-off 

limit. 

PM emissions must not exceed 0.5 

g/kg (0.5 lb PM/1,000 lb) of coke 

burn-off or, 

You have already conducted a 

performance test to demonstrate 

initial compliance with the NSPS 

and the measured PM emission 

rate is less than or equal to 1.0 g/ 

kg (1.0 lb/1,000 lb) of coke burnoff in the catalyst regenerator. As 

part of the Notification of 

Compliance Status, you must 

certify that your vent meets the 

PM limit. You are not required to 

do another performance test to 

demonstrate initial compliance. As 

part of your Notification of 

Compliance Status, you certify 

that your BLD; CO2, O2, or CO 

monitor; or continuous opacity 

monitoring system meets the 

requirements in §63.1572. 

3. Subject to NSPS for 

PM in 40 CFR 

60.102a(b)(1)(ii), 

electing to meet the 

PM per coke burn-off 

limit. 

PM emissions must not exceed 1.0 

g/kg coke burn-off (1 lb/1000 lb 

coke burn-off). 

You have already conducted a 

performance test to demonstrate 

initial compliance with the NSPS 

and the measured PM emission 

rate is less than or equal to 0.5 

kg/1,000 kg (0.5 lb/1,000 lb) of 

coke burn-off in the catalyst 

regenerator. As part of the 

Notification of Compliance Status, 

you must certify that your vent 

meets the PM limit. You are not 

required to do another 

performance test to demonstrate 

initial compliance. As part of your 

Notification of Compliance Status, 

you certify that your BLD; CO2, 

O2, or CO monitor; or continuous 

opacity monitoring system meets 

the requirements in §63.1572. 

4. Subject to NSPS for 

PM in 40 CFR 

60.102a(b)(1)(i), 

If a PM CEMS is used, 0.020 grain 

per dry standard cubic feet (gr/dscf) 

corrected to 0 percent excess air. 

You have already conducted a 

performance test to demonstrate 

initial compliance with the NSPS 

Moved (insertion) [9]
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit catalyst 

regenerator vent . . . 

For the following emission limit . 

. . 

You have demonstrated initial 

compliance if . . . 

electing to meet the 

PM concentration 

limit. 

and the measured PM 

concentration is less than or equal 

to 0.020 grain per dry standard 

cubic feet (gr/dscf) corrected to 0 

percent excess air. As part of the 

Notification of Compliance Status, 

you must certify that your vent 

meets the PM limit. You are not 

required to do another 

performance test to demonstrate 

initial compliance. As part of your 

Notification of Compliance Status, 

you certify that your PM CEMS 

meets the requirements in 

§63.1572. 

5. Subject to NSPS for 

PM in 40 CFR 

60.102a(b)(1)(ii), 

electing to meet the 

PM concentration 

limit. 

If a PM CEMS is used, 0.040 

gr/dscf corrected to 0 percent 

excess air. 

You have already conducted a 

performance test to demonstrate 

initial compliance with the NSPS 

and the measured PM 

concentration is less than or equal 

to 0.040 gr/dscf corrected to 0 

percent excess air. As part of the 

Notification of Compliance Status, 

you must certify that your vent 

meets the PM limit. You are not 

required to do another 

performance test to demonstrate 

initial compliance. As part of your 

Notification of Compliance Status, 

you certify that your PM CEMS 

meets the requirements in 

§63.1572. 

6. Option 1: PM per 

coke burn-off limit not 

subject to the NSPS for 

PM in 40 CFR 60.102 

or 40 CFR 

60.120a(b)(1)

PM emissions must not exceed 1.0 

gram per kilogram (g/kg) (1.0 

lb/1,000 lb) of coke burn-off. 

Before [THE DATE 3 YEARS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], PM 

emission must not exceed 1.0 g/kg 

The average PM emission rate, 

measured using EPA Method 5, 

5B, or 5F (for a unit without a wet 

scrubber) or 5 or 5B (for a unit 

with a wet scrubber), over the 

period of the initial performance 

test, is no higher than 1.0 g/kg

coke burn-off (1.0 lb/1,000 lb) in 

the catalyst regenerator. The PM 

Moved (insertion) [10]

Deleted: 2

Deleted: Elect NSPS

Deleted: PM emission must not exceed 1.0 

kg/1,000 

Deleted: /1,000 kg 

Deleted: of coke burn-off 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit catalyst 

regenerator vent . . . 

For the following emission limit . 

. . 

You have demonstrated initial 

compliance if . . . 

(1.0 lb/1,000 lb) of coke burn-off in 

the catalyst regenerator; if the 

discharged gases pass through an 

incinerator or waste heat boiler in 

which you burn auxiliary or 

supplemental liquid or solid fossil 

fuel, the incremental rate of PM 

must not exceed 43.0 g/GJ (0.10 

lb/million Btu) of heat input 

attributable to the liquid or solid 

fossil fuel; and the opacity of 

emissions must not exceed 30 

percent, except for one 6-minute 

average opacity reading in any 1-

hour period 

emission rate is calculated using 

Equations 1, 2, and 3 of §63.1564. 

If you use a BLD; CO2, O2, CO 

monitor; or continuous opacity 

monitoring system, your 

performance evaluation shows the 

system meets the applicable 

requirements in §63.1572. 

7. Option 2: PM 

concentration limit, not

subject to the NSPS for 

PM in 40 CFR 60.102 

or in 40 CFR 

60.102a(b)(1)

PM emissions must not exceed 

0.040 gr/dscf corrected to 0 percent 

excess air.

The average PM concentration, 

measured using EPA Method 5, 

5B, or 5F (for a unit without a wet 

scrubber) or Method 5 or 5B (for a 

unit with a wet scrubber), over the 

period of the initial performance 

test, is less than or equal to 0.040 

gr/dscf corrected to 0 percent 

excess air. Your performance 

evaluation shows your PM CEMS

meets the applicable requirements 

in §63.1572. 

8. Option 3: not subject 

to the NSPS for PM 

Nickel (Ni) emissions from your 

catalyst regenerator vent must not 

exceed 13,000 mg/hr (0.029 lb/hr). 

The average Ni emission rate, 

measured using Method 29 over 

the period of the initial 

performance test, is not more than 

13,000 mg/hr (0.029 lb/hr). The Ni 

emission rate is calculated using 

Equation 5 of §63.1564; and if you 

use a BLD; CO2, O2, or CO 

monitor; or continuous opacity 

monitoring system, your 

performance evaluation shows the 

system meets the applicable 

requirements in §63.1572. 

9. Option 4: Ni per Ni emissions from your catalyst The average Ni emission rate, 

Deleted: 2 of §63.1564. If applicable, the average 

PM emission rate, measured using EPA Method 5B 

emission rate, measured using EPA Method 5B or 5F 

(for a unit without a wet scrubber) or Method 5B (for 

a unit with a wet scrubber) over the period of the 

initial performance test, is no higher than 43.0 g/GJ 

(0.10 lb/million Btu) of heat input attributable to the 

liquid or solid fossil fuel. The PM emission rate is 

calculated using Equation 

Deleted: ; no more than one 6-minute average 

measured by the 

Deleted: exceeds 30 percent opacity in any 1-hour 

period over the period of the performance test; and

Deleted: continuous opacity monitoring 

Deleted: 3

Deleted: Not

Deleted: 1.

Deleted: kg/1,000 kg (1.

Deleted: lb/1,000 lb) of coke burn-off in the 

catalyst regenerator

Deleted: emission rate

Deleted: 1.

Deleted: kg/1,000 kg (1.

Deleted: lb/1,000 lb) of coke burn-off in the 

catalyst regenerator. The PM emission rate is 

calculated using Equations 1 and 2 of §63.1564; and 

if you use a continuous opacity monitoring system, 

your 

Deleted: the system

Deleted: 4

Deleted: 5

Deleted: lb/1,000 lbs of
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit catalyst 

regenerator vent . . . 

For the following emission limit . 

. . 

You have demonstrated initial 

compliance if . . . 

coke burn-off limit not 

subject to the NSPS for 

PM. 

regenerator vent must not exceed 

1.0 mg/kg (0.001 lb/1,000 lb) of 

coke burn-off in the catalyst 

regenerator. 

measured using Method 29 over 

the period of the initial 

performance test, is not more than 

1.0 mg/kg (0.001 lb/1,000 lb) of 

coke burn-off in the catalyst 

regenerator. The Ni emission rate 

is calculated using Equation 8 of 

§63.1564; and if you use a BLD; 

CO2, O2, or CO monitor; or 

continuous opacity monitoring 

system, your performance 

evaluation shows the system meets 

the applicable requirements in 

§63.1572.

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6946, Feb. 9, 2005] 

Table 6 to Subpart UUU of Part 63—Continuous Compliance With Metal HAP Emission 

Limits for Catalytic Cracking Units 

As stated in §63.1564(c)(1), you shall meet each requirement in the following table that applies 

to you. 

For each new and 

existing catalytic 

cracking unit . . . 

Subject to this emission limit 

for your catalyst regenerator 

vent . . . 

You shall demonstrate 

continuous compliance by . . . 

1. Subject to the NSPS for 

PM in 40 CFR 60.102 

a. PM emissions must not exceed 

1.0 gram per kilogram (g/kg) (1.0 

lb/1,000 lb) of coke burn-off. 

Before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], if the discharged 

gases pass through an incinerator 

or waste heat boiler in which you 

burn auxiliary or supplemental 

liquid or solid fossil fuel, the 

incremental rate of PM must not 

exceed 43.0 g/GJ (0.10 lb/million 

i. Determining and recording each 

day the average coke burn-off 

rate (thousands of kilograms per 

hour) using Equation 1 in 

§63.1564 and the hours of 

operation for each catalyst 

regenerator.

Deleted: s

Deleted: s

Deleted: /1,000 kg

Deleted: in the catalyst regenerator;

Deleted: ; maintaining PM emission rate below 1.0 

kg/1,000 kg (1.0 lb/1,000 lbs) of coke burn-off; if 

applicable, determining and recording each day the 

rate of combustion of liquid or solid fossil fuels 

(liters/hour or kilograms/hour) and the hours of 

operation during which liquid or solid fossil-fuels are 

combusted in the incinerator-waste heat boiler; if 

applicable, maintaining the PM rate incinerator 

below 43 g/GJ (0.10 lb/million Btu) of heat input 

attributable to the solid or liquid fossil fuel; 

collecting the continuous opacity monitoring data for 

each catalyst regenerator vent according to 

§63.1572; and maintaining each 6-minute average at 

or below 30 percent except that one 6-minute 

average during a 1-hour period can exceed 30 

percent.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit . . . 

Subject to this emission limit 

for your catalyst regenerator 

vent . . . 

You shall demonstrate 

continuous compliance by . . . 

Btu) of heat input attributable to 

the liquid or solid fossil fuel; and 

the opacity of emissions must not 

exceed 30 percent, except for one 

6-minute average opacity reading 

in any 1-hour period 

ii. Maintaining PM emission rate 

below 1.0 g/kg (1.0 lb/1,000 lb) 

of coke burn-off. 

iii. Conducting a performance test 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER] and once every five 

years thereafter. 

iv. Collecting the applicable 

continuous parametric monitoring 

system data according to 

§63.1572 and maintaining each 

rolling 3-hr average above or 

below (as applicable) the average 

determined during the 

performance test. 

v. Collecting the continuous 

opacity monitoring data for each 

catalyst regenerator vent 

according to §63.1572 and 

maintaining each 6-minute 

average at or below the sitespecific opacity determined 

during the performance test. 

Alternatively, before [THE 

DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the continuous opacity 

monitoring data for each catalyst 

regenerator vent according to 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit . . . 

Subject to this emission limit 

for your catalyst regenerator 

vent . . . 

You shall demonstrate 

continuous compliance by . . . 

§63.1572 and maintaining each 6-

minute average at or below 30 

percent, except that one 6-minute 

average during a 1-hour period 

can exceed 30 percent. 

vi. Before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], if applicable, 

determining and recording each 

day the rate of combustion of 

liquid or solid fossil fuels 

(liters/hour or kilograms/hour) 

and the hours of operation during 

which liquid or solid fossil-fuels 

are combusted in the incineratorwaste heat boiler; if applicable, 

maintaining the incremental rate 

of PM at or below 43 g/GJ (0.10 

lb/million Btu) of heat input 

attributable to the solid or liquid 

fossil fuel. 

2. Subject to NSPS for PM 

in 40 CFR 

60.102a(b)(1)(i), electing 

to meet the PM per coke 

burn-off limit.

PM emissions must not exceed 

0.5 g/kg (0.5 lb PM/1,000 lb) of 

coke burn-off 

Determining and recording each 

day the average coke burn-off 

rate (thousands of kilograms per 

hour) using Equation 1 in 

§63.1564 and the hours of 

operation for each catalyst 

regenerator; maintaining PM 

emission rate below 0.5 g/kg (0.5 

lb PM/1,000 lb) of coke burn-off; 

conducting a performance test 

once every year; collecting the 

applicable continuous parametric 

monitoring system data according 

to §63.1572 and maintaining each 

rolling 3-hr average above or 

below (as applicable) the average 

determined during the 

performance test; collecting the 

Deleted: Option 1: Elect NSPS not subject

Deleted: the 

Deleted: 102

Deleted: See item 1.a. of this table

Deleted: See item 1.a.i. of this table.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit . . . 

Subject to this emission limit 

for your catalyst regenerator 

vent . . . 

You shall demonstrate 

continuous compliance by . . . 

continuous opacity monitoring 

data for each regenerator vent 

according to §63.1572 and 

maintaining each 6-minute 

average at or below the sitespecific opacity determined 

during the performance test.

3. Subject to NSPS for PM

in 40 CFR 

60.102a(b)(1)(ii), electing 

to meet the PM per coke 

burn-off limit.

PM emissions must not exceed 

1.0 g/kg coke burn-off (1 lb/1000 

lb coke burn-off).

Determining and recording each 

day the average coke burn-off 

rate (thousands of kilograms per 

hour) using Equation 1 in 

§63.1564 and the hours of 

operation for each catalyst 

regenerator; maintaining PM 

emission rate below 1.0 g/kg (1.0 

lb/1,000 lb) of coke burn-off; 

conducting a performance test 

once every year; collecting the 

applicable continuous parametric 

monitoring system data according 

to §63.1572 and maintaining each 

rolling 3-hr average above or 

below (as applicable) the average 

determined during the 

performance test; collecting the 

continuous opacity monitoring 

data for each regenerator vent 

according to §63.1572 and 

maintaining each 6-minute 

average at or below the sitespecific opacity determined 

during the performance test. 

4. Subject to NSPS for PM 

in 40 CFR 

60.102a(b)(1)(i), electing 

to meet the PM 

concentration limit. 

If a PM CEMS is used, 0.020 

grain per dry standard cubic feet 

(gr/dscf) corrected to 0 percent 

excess air. 

Maintaining PM concentration 

below 0.020 gr/dscf corrected to 

0 percent excess air. 

5. Subject to NSPS for PM 

in 40 CFR 

60.102a(b)(1)(ii), electing 

to meet the PM 

concentration limit. 

If a PM CEMS is used, 0.040 

gr/dscf corrected to 0 percent 

excess air. 

Maintaining PM concentration 

below 0.040 gr/dscf corrected to 

0 percent excess air. 

Deleted: Option 2: PM limit not subject

Deleted: the 

Deleted: /1,000 kg (1.0 lb/1,000 lb) of

Deleted: in the catalyst regenerator

Deleted: by Equation 1 of §63.1564 (you can use 

process data to determine the volumetric flow rate); 

and maintaining the 

Deleted: kg/1,000 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit . . . 

Subject to this emission limit 

for your catalyst regenerator 

vent . . . 

You shall demonstrate 

continuous compliance by . . . 

6. Option 1: PM per coke 

burn-off limit, not subject 

to the NSPS for PM in 40 

CFR 60.102 or in 40 CFR 

60.102a(b)(1) 

See item 1 of this table See item 1 of this table. 

7. Option 2: PM 

concentration limit, not 

subject to the NSPS for 

PM in 40 CFR 60.102 or 

in 40 CFR 60.102a(b)(1) 

PM emissions must not exceed 

0.040 gr/dscf corrected to 0 

percent excess air. 

See item 5 of this table. 

8. Option 3: Ni lb/hr limit, 

not subject to the NSPS 

for PM in 40 CFR 60.102 

or in 40 CFR 

60.102a(b)(1)

Ni emissions must not exceed 

13,000 mg/hr (0.029 lb/hr). 

Maintaining Ni emission rate 

below 13,000 mg/hr (0.029 lb/hr); 

conducting a performance test 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER] and once every five 

years thereafter; and collecting 

the applicable continuous 

parametric monitoring system 

data according to §63.1572 and 

maintaining each rolling 3-hr 

average above or below (as 

applicable) the average 

determined during the 

performance test. 

9. Option 4: Ni per coke 

burn-off limit, not subject 

to the NSPS for PM in 40 

CFR 60.102 or in 40 CFR 

60.102a(b)(1)

Ni emissions must not exceed 1.0 

mg/kg (0.001 lb/1,000 lb) of 

coke burn-off in the catalyst 

regenerator 

Determining and recording each 

day the average coke burn-off 

rate (thousands of kilograms per 

hour) and the hours of operation 

for each catalyst regenerator by 

Equation 1 of §63.1564 (you can 

use process data to determine the 

volumetric flow rate); and 

maintaining Ni emission rate 

below 1.0 mg/kg (0.001 lb/1,000 

lb) of coke burn-off in the 

catalyst regenerator; conducting a 

performance test before [THE 

DATE 18 MONTHS AFTER 

Deleted: 4

Deleted: .

Deleted: 5

Deleted: lb/1,000 lbs of

Deleted: s

Deleted: s
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit . . . 

Subject to this emission limit 

for your catalyst regenerator 

vent . . . 

You shall demonstrate 

continuous compliance by . . . 

THE DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER] and 

once every five years thereafter; 

and collecting the applicable 

continuous parametric monitoring 

system data according to 

§63.1572 and maintaining each 

rolling 3-hr average above or 

below (as applicable) the average 

determined during the 

performance test. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6948, Feb. 9, 2005] 

Table 7 to Subpart UUU of Part 63—Continuous Compliance With Operating Limits for 

Metal HAP Emissions From Catalytic Cracking Units 

As stated in §63.1564(c)(1), you shall meet each requirement in the following table that applies 

to you. 

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

1. Subject to NSPS 

for PM in 40 CFR 

60.102 

a. Continuous 

opacity monitoring 

system used to 

comply with 30 

percent opacity 

limit. 

Not applicable. Complying with Table 6 of this 

subpart. 

b. Continuous 

parametric 

monitoring systems 

– electrostatic 

precipitator 

The average gas 

flow rate entering 

or exiting the 

control device must 

not exceed the 

operating limit 

established during 

the performance 

test. 

Collecting the hourly and 3-hr 

rolling average gas flow rate 

monitoring data according to 

§63.1572; and maintaining the 

3-hr rolling average gas flow 

rate at or below the limit 

established during the 

performance test. 

The average total Collecting the hourly and 3-hr 

Deleted: .
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

power and 

secondary current 

to the control 

device must not fall 

below the 

operating limit 

established during 

the performance 

test. 

rolling average total power and 

secondary current monitoring 

data according to §63.1572; and 

maintaining the 3-hr rolling 

average total power and 

secondary current at or above 

the limit established during the 

performance test. 

c. Continuous 

parametric 

monitoring systems 

– wet scrubber 

The average 

pressure drop 

across the scrubber 

must not fall below 

the operating limit 

established during 

the performance 

test. 

Collecting the hourly and 3-hr 

rolling average pressure drop 

monitoring data according to 

§63.1572; and maintaining the 

3-hr rolling average pressure 

drop at or above the limit 

established during the 

performance test. 

The average liquidto-gas ratio must 

not fall below the 

operating limit 

established during 

the performance 

test. 

Collecting the hourly and 3-hr 

rolling average gas flow rate 

and scrubber liquid flow rate 

monitoring data according to 

§63.1572; determining and 

recording the 3-hr liquid-to-gas 

ratio; and maintaining the 3-hr 

rolling average liquid-to-gas 

ratio at or above the limit 

established during the 

performance test. 

d. BLD – fabric 

filter 

Increases in 

relative particulate.

Collecting and maintaining 

records of BLD system output; 

determining the cause of the 

alarm within 1 hour of the 

alarm; and alleviating the cause 

of the alarm within 3 hours by 

corrective action. 

e. Continuous 

opacity monitoring 

system, used for 

site-specific 

opacity limit - 

Cyclone or 

electrostatic 

The average 

opacity must not 

exceed the opacity 

established during 

the performance 

test.

Collecting the hourly and 3-hr 

rolling average opacity 

monitoring data according to 

§63.1572; maintaining the 3-hr 

rolling average opacity at or 

above the limit established 

Deleted: 2. Option 1: Elect NSPS not subject to 

the NSPS for PM in 40 CFR 60.102.

Deleted: .

Moved down [11]: Not applicable.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

precipitator during the performance test.

2. Subject to NSPS 

for PM in 40 CFR 

60.102a(b)(1)(ii), 

electing to meet the 

PM per coke burnoff limit. 

Any Any See items 1.b, 1.c, 1.d, and 1.e 

of this table. 

3. Subject to NSPS 

for PM in 40 CFR 

60.102a(b)(1), 

electing to meet the 

PM concentration 

limit. 

PM CEMS Not applicable. Complying with Table 6 of this 

subpart.

4. Option 1: PM per 

coke burn-off limit,

not subject to the 

NSPS for PM in 40 

CFR 60.102 or in 40 

CFR 60.102a(b)(1).

a. Continuous 

opacity monitoring 

system. 

The opacity of 

emissions from 

your catalyst 

regenerator vent 

must not exceed 

the site-specific 

opacity operating 

limit established 

during the 

performance test. 

Collecting the 3-hr rolling 

average continuous opacity 

monitoring system data 

according to §63.1572; and 

maintaining the 3-hr rolling 

average opacity at or below the 

site-specific limit. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the hourly average 

continuous opacity monitoring 

system data according to 

§63.1572; and maintaining the 

hourly average opacity at or 

below the site-specific limit. 

 b. Continuous 

parameter 

monitoring 

systems—

electrostatic 

precipitator. 

i. The average gas 

flow rate entering 

or exiting the 

control device must 

not exceed the 

operating limit 

established during 

the performance 

Collecting the hourly and 3-hr 

rolling average gas flow rate 

monitoring data according to 

§63.1572; and maintaining the 

3-hr rolling average gas flow 

rate at or below the limit 

established during the 

performance test. Alternatively, 

Moved down [12]: Complying with Table 6 of 

this subpart.

Moved (insertion) [12]

Deleted: 3

Deleted: 2

Deleted: .

Deleted: Collecting

Deleted: daily

Deleted: Collecting
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

test. before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the hourly and daily 

average gas flow rate 

monitoring data according to 

§63.15721

; and maintaining the 

daily average gas flow rate at or 

below the limit established 

during the performance test. 

 ii. The average 

voltage and 

secondary current 

(or total power 

input) to the 

control device must 

not fall below the 

operating limit 

established during 

the performance 

test. 

Collecting the hourly and 3-hr 

rolling average total power and 

secondary current monitoring 

data according to §63.1572; and 

maintaining the 3-hr rolling 

average total power and 

secondary current at or above 

the limit established during the 

performance test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the hourly and daily 

average voltage and secondary 

current (or total power input) 

monitoring data according to 

§63.1572; and maintaining the 

daily average voltage and 

secondary current (or total 

power input) at or above the 

limit established during the 

performance test. 

 c. Continuous 

parameter 

monitoring 

systems—wet 

i. The average 

pressure drop 

across the scrubber 

must not fall below 

Collecting the hourly and 3-hr 

rolling average pressure drop 

monitoring data according to 

§63.1572; and maintaining the 

Deleted: daily

Deleted: Collecting

Deleted: daily

Deleted: Collecting
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

scrubber. the operating limit 

established during 

the performance 

test. 

3-hr rolling average pressure 

drop at or above the limit 

established during the 

performance test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the hourly and daily 

average pressure drop 

monitoring data according to 

§63.1572; and maintaining the 

daily average pressure drop 

above the limit established 

during the performance test. 

 ii. The average 

liquid-to-gas ratio 

must not fall below 

the operating limit 

established during 

the performance 

test. 

Collecting the hourly and 3-hr 

rolling average gas flow rate 

and scrubber liquid flow rate 

monitoring data according to 

§63.1572; determining and 

recording the 3-hr liquid-to-gas 

ratio; and maintaining the 3-hr 

rolling average liquid-to-gas 

ratio at or above the limit 

established during the 

performance test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the hourly average 

gas flow rate and water (or 

scrubbing liquid) flow rate 

monitoring data according to 

§63.15721

; determining and 

recording the hourly average 

liquid-to-gas ratio; determining 

and recording the daily average 

liquid-to-gas ratio; and 

Deleted: daily

Deleted: Collecting
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

maintaining the daily average 

liquid-to-gas ratio above the 

limit established during the 

performance test. 

d. BLD – fabric 

filter 

Increases in 

relative particulate.

Collecting and maintaining 

records of BLD system output; 

determining the cause of the 

alarm within 1 hour of the 

alarm; and alleviating the cause 

of the alarm within 3 hours by 

corrective action. 

e. Continuous 

opacity monitoring 

system, used for 

site-specific 

opacity limit - 

Cyclone or 

electrostatic 

precipitator 

The average 

opacity must not 

exceed the opacity 

established during 

the performance 

test. 

Collecting the hourly and 3-hr 

rolling average opacity 

monitoring data according to 

§63.1572; maintaining the 3-hr 

rolling average opacity at or 

above the limit established 

during the performance test. 

5. Option 2: PM 

concentration limit, 

not subject to the 

NSPS for PM in 40 

CFR 60.102 or in 40 

CFR 60.102a(b)(1). 

PM CEMS Not applicable. Complying with Table 6 of this 

subpart. 

6. Option 3: Ni lb/hr 

limit not subject to 

the NSPS for PM in 

40 CFR 60.102. 

a. Continuous 

opacity monitoring 

system. 

i. The daily 

average Ni 

operating value 

must not exceed 

the site-specific Ni 

operating limit 

established during 

the performance 

test. 

(1) Collecting the hourly 

average continuous opacity 

monitoring system data 

according to §63.1572; 

determining and recording 

equilibrium catalyst Ni 

concentration at least once a 

week2

; collecting the hourly 

average gas flow rate 

monitoring data according to 

§63.15721

; and determining and 

recording the hourly average Ni 

operating value using Equation 

11 of §63.1564. 

(2) Determining and recording 

the 3-hour rolling average Ni 

Moved (insertion) [11]

Deleted: 4

Deleted: ; determining and recording the daily 

average Ni operating value; and maintaining the 

daily average Ni operating value below the sitespecific Ni operating limit established during the 

performance test
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

operating value and maintaining 

the 3-hour rolling average Ni 

operating value below the sitespecific Ni operating limit 

established during the 

performance test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

determining and recording the 

daily average Ni operating value 

and maintaining the daily 

average Ni operating value 

below the site-specific Ni 

operating limit established 

during the performance test. 

 b. Continuous 

parameter 

monitoring 

systems—

electrostatic 

precipitator. 

i. The average gas 

flow rate entering 

or exiting the 

control device must 

not exceed the 

operating limit 

established during 

the performance 

test. 

See item 4.b.i of this table. 

 ii. The average 

voltage and 

secondary current 

(or total power 

input) must not fall 

below the level 

established in the 

performance test. 

See item 4.b.ii of this table. 

 iii. The monthly 

rolling average of 

the equilibrium 

catalyst Ni 

concentration must 

not exceed the 

Determining and recording the 

equilibrium catalyst Ni 

concentration at least once a 

week2

; determining and 

recording the monthly rolling 

average of the equilibrium 

Deleted: daily

Deleted: 3

Deleted: .

Deleted: daily

Deleted: 3

Deleted: .
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

level established 

during the 

performance test. 

catalyst Ni concentration once 

each week using the weekly or 

most recent value; and 

maintaining the monthly rolling 

average below the limit 

established in the performance 

test. 

 c. Continuous 

parameter 

monitoring 

systems—wet 

scrubber. 

i. The average 

pressure drop must 

not fall below the 

operating limit 

established in the 

performance test. 

See item 4.c.i of this table. 

 ii. The average 

liquid-to-gas ratio 

must not fall below 

the operating limit 

established during 

the performance 

test. 

See item 4.c.ii of this table. 

 iii. The monthly 

rolling average 

equilibrium 

catalyst Ni 

concentration must 

not exceed the 

level established 

during the 

performance test. 

Determining and recording the 

equilibrium catalyst Ni 

concentration at least once a 

week2

; determining and 

recording the monthly rolling 

average of equilibrium catalyst 

Ni concentration once each 

week using the weekly or most 

recent value; and maintaining 

the monthly rolling average 

below the limit established in 

the performance test. 

d. BLD – fabric 

filter 

Increases in 

relative particulate.

See item 4.d of this table. 

e. Continuous 

opacity monitoring 

system, used for 

site-specific 

opacity limit - 

Cyclone or 

electrostatic 

The average 

opacity must not 

exceed the opacity 

established during 

the performance 

test. 

See item 4.e of this table. 

Deleted: wetscrubber

Deleted: daily

Deleted: 3

Deleted: .

Deleted: daily

Deleted: 3

Deleted: .
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

precipitator 

7. Option 4: Ni per

coke burn-off limit 

not subject to the 

NSPS for PM in 40 

CFR 60.102. 

a. Continuous 

opacity monitoring 

system. 

i. The daily 

average Ni 

operating value 

must not exceed 

the site-specific Ni 

operating limit 

established during 

the performance 

test. 

(1) Collecting the hourly 

average continuous opacity 

monitoring system data 

according to §63.1572; 

collecting the hourly average 

gas flow rate monitoring data 

according to §63.15721

; 

determining and recording 

equilibrium catalyst Ni 

concentration at least once a 

week2

; and determining and 

recording the hourly average Ni 

operating value using Equation 

12 of §63.1564. 

(2) Determining and recording 

the 3-hour rolling average Ni 

operating value and maintaining 

the 3-hour rolling average Ni 

operating value below the sitespecific Ni operating limit 

established during the 

performance test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

determining and recording the 

daily average Ni operating value 

and maintaining the daily 

average Ni operating value 

below the site-specific Ni 

operating limit established 

during the performance test. 

 b. Continuous 

parameter 

monitoring 

systems—

electrostatic 

precipitator. 

i. The daily 

average gas flow 

rate to the control 

device must not 

exceed the level 

established in the 

See item 4.b.i of this table. 

Deleted: 5

Deleted: lb/ton of

Deleted: ; determining and recording the daily 

average Ni operating value; and maintaining the 

daily average Ni operating value below the sitespecific Ni operating limit established during the 

performance test

Deleted: 3

Deleted: .
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

performance test. 

 ii. The daily 

average voltage 

and secondary 

current (or total 

power input) must 

not fall below the 

level established in 

the performance 

test. 

See item 4.b.ii of this table. 

 iii. The monthly 

rolling average 

equilibrium 

catalyst Ni 

concentration must 

not exceed the 

level established 

during the 

performance test. 

See item 6.b.iii of this table. 

 c. Continuous 

parameter 

monitoring 

systems—wet 

scrubber. 

i. The daily 

average pressure 

drop must not fall 

below the 

operating limit 

established in the 

performance test. 

See item 4.c.i of this table. 

 ii. The daily 

average liquid-togas ratio must not 

fall below the 

operating limit 

established during 

the performance 

test. 

See item 4.c.ii of this table. 

 iii. The monthly 

rolling average 

equilibrium 

catalyst Ni 

concentration must 

not exceed the 

level established 

See item 6.c.iii of this table. 

Deleted: 3

Deleted: .

Deleted: 4

Deleted: .

Deleted: 3

Deleted: .

Deleted: 3

Deleted: .

Deleted: 4

Deleted: .
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new or 

existing catalytic 

cracking unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

during the 

performance test. 

d. BLD – fabric 

filter 

Increases in 

relative particulate.

See item 4.d of this table. 

e. Continuous 

opacity monitoring 

system, used for 

site-specific 

opacity limit - 

Cyclone or 

electrostatic 

precipitator 

The average 

opacity must not 

exceed the opacity 

established during 

the performance 

test. 

See item 4.e of this table. 

1

If applicable, you can use the alternative in §63.1573(a)(1) for gas flow rate instead of a 

continuous parameter monitoring system if you used the alternative method in the initial 

performance test. 

2

The equilibrium catalyst Ni concentration must be measured by the procedure, Determination of 

Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure) in Appendix A to 

this subpart; or by EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission 

Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA 

Method 7520, Nickel Atomic Absorption, Direct Aspiration, or EPA Method 7521, Nickel 

Atomic Absorption, Direct Aspiration; or by an alternative to EPA Method 6010B, 6020, 7520, 

or 7521 satisfactory to the Administrator. The EPA Methods 6010B, 6020, 7520, and 7521 are 

included in “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” EPA 

Publication SW-846, Revision 5 (April 1998). The SW-846 and Updates (document number 955-

001-00000-1) are available for purchase from the Superintendent of Documents, U.S. 

Government Printing Office, Washington, DC 20402, (202) 512-1800; and from the National 

Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 

487-4650. Copies may be inspected at the EPA Docket Center (Air Docket), EPA West, Room 

B-108, 1301 Constitution Ave., NW., Washington, DC; or at the Office of the Federal Register, 

800 North Capitol Street, NW., Suite 700, Washington, DC. These methods are also available at 

http://www.epa.gov/epaoswer/hazwaste/test/main.htm. 

[70 FR 6948, Feb. 9, 2005] 

Table 8 to Subpart UUU of Part 63—Organic HAP Emission Limits for Catalytic Cracking 

Units 

As stated in §63.1565(a)(1), you shall meet each emission limitation in the following table that 

applies to you. 

Deleted: a
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

cracking unit . . . 

You shall meet the following emission limit for each catalyst 

regenerator vent . . . 

1. Subject to the NSPS for 

carbon monoxide (CO) in 

40 CFR 60.103 

CO emissions from the catalyst regenerator vent or CO boiler 

serving the catalytic cracking unit must not exceed 500 parts per 

million volume (ppmv) (dry basis). 

2. Not subject to the 

NSPS for CO in 40 CFR 

60.103 

a. CO emissions from the catalyst regenerator vent or CO boiler 

serving the catalytic cracking unit must not exceed 500 ppmv (dry 

basis). 

b. If you use a flare to meet the CO limit, then on and after [THE 

DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

the flare must meet the requirements of §63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

the flare must meet the requirements for control devices in §63.11(b)

and visible emissions must not exceed a total of 5 minutes during 

any 2 consecutive hours, or the flare must meet the requirements of 

§63.670. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6948, Feb. 9, 2005] 

Table 9 to Subpart UUU of Part 63—Operating Limits for Organic HAP Emissions From 

Catalytic Cracking Units 

As stated in §63.1565(a)(2), you shall meet each operating limit in the following table that 

applies to you. 

For each new 

or existing 

catalytic 

cracking unit 

. . . 

For this type 

of continuous 

monitoring 

system . . . 

For this type of 

control device . . . 

You shall meet this operating limit . . 

. 

1. Subject to 

the NSPS for 

carbon 

monoxide 

(CO) in 40 

CFR 60.103 

Continuous 

emission 

monitoring 

system. 

Not applicable Not applicable. 

2. Not subject 

to the NSPS 

for CO in 40 

CFR 60.103 

a. Continuous 

emission 

monitoring 

system. 

Not applicable Not applicable. 

Deleted: :
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. Continuous 

parameter 

monitoring 

systems. 

i. Thermal incinerator Maintain the daily average combustion 

zone temperature above the limit 

established during the performance test; 

and maintain the daily average oxygen 

concentration in the vent stream 

(percent, dry basis) above the limit 

established during the performance test. 

 ii. Boiler or process 

heater with a design 

heat input capacity 

under 44 MW or a 

boiler or process 

heater in which all 

vent streams are not 

introduced into the 

flame zone. 

Maintain the daily average combustion 

zone temperature above the limit 

established in the performance test. 

 iii. Flare On and after [THE DATE 3 YEARS 

AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must meet the 

requirements of §63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare pilot 

light must be present at all times and the 

flare must be operating at all times that 

emissions may be vented to it, or the 

flare must meet the requirements of 

§63.670. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6948, Feb. 9, 2005] 

Table 10 to Subpart UUU of Part 63—Continuous Monitoring Systems for Organic HAP 

Emissions From Catalytic Cracking Units 

As stated in §63.1565(b)(1), you shall meet each requirement in the following table that applies 

to you. 

Deleted: The
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new 

or existing 

catalytic 

cracking unit . 

. . 

And you use this type of 

control device for your 

vent . . . 

You shall install, operate, and maintain this 

type of continuous monitoring system . . . 

1. Subject to the 

NSPS for 

carbon 

monoxide (CO) 

in 40 CFR 

60.103. 

Not applicable Continuous emission monitoring system to 

measure and record the concentration by volume 

(dry basis) of CO emissions from each catalyst 

regenerator vent. 

2. Not subject 

to the NSPS for 

CO in 40 CFR 

60.103 

a. Thermal incinerator Continuous emission monitoring system to 

measure and record the concentration by volume 

(dry basis) of CO emissions from each catalyst 

regenerator vent; or continuous parameter 

monitoring systems to measure and record the 

combustion zone temperature and oxygen content 

(percent, dry basis) in the incinerator vent stream. 

 b. Process heater or boiler 

with a design heat input 

capacity under 44 MW or 

process heater or boiler in 

which all vent streams are 

not introduced into the 

flame zone. 

Continuous emission monitoring system to 

measure and record the concentration by volume 

(dry basis) of CO emissions from each catalyst 

regenerator vent; or continuous parameter 

monitoring systems to measure and record the 

combustion zone temperature. 

 c. Flare On and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the monitoring systems required in 

§§63.670 and 63.671. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], monitoring device such 

as a thermocouple, an ultraviolet beam sensor, or 

infrared sensor to continuously detect the presence 

of a pilot flame, or the monitoring systems 

required in §§63.670 and 63.671. 

 d. No control device Continuous emission monitoring system to 

measure and record the concentration by volume 

(dry basis) of CO emissions from each catalyst 

regenerator vent. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6948, Feb. 9, 2005] 

Deleted: Monitoring
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 11 to Subpart UUU of Part 63—Requirements for Performance Tests for Organic 

HAP Emissions From Catalytic Cracking Units Not Subject to New Source Performance 

Standard (NSPS) for Carbon Monoxide (CO) 

As stated in §63.1565(b)(2) and (3), you shall meet each requirement in the following table that 

applies to you. 

For . . . You must . . . Using . . . 

According to these 

requirements . . . 

1. Each new or 

existing catalytic 

cracking unit 

catalyst 

regenerator vent. 

a. Select sampling port's 

location and the number 

of traverse ports. 

Method 1 or 1A in 

appendix A to part 60 of 

this chapter. 

Sampling sites must be 

located at the outlet of the 

control device or the outlet 

of the regenerator, as 

applicable, and prior to any 

releases to the atmosphere. 

 b. Determine velocity and 

volumetric flow rate. 

Method 2, 2A, 2D, 2F, 

or 2G in appendix A to 

part 60 of this chapter, 

as applicable. 

 c. Conduct gas molecular 

weight analysis. 

Method 3, 3A, or 3B in 

appendix A to part 60 of 

this chapter, as 

applicable. 

 d. Measure moisture 

content of the stack gas. 

Method 4 in appendix A 

to part 60 of this 

chapter. 

2. For each new 

or existing 

catalytic cracking 

unit catalyst 

regenerator vent 

if you use a 

continuous 

emission 

monitoring 

system. 

Measure CO emissions Data from your 

continuous emission 

monitoring system. 

Collect CO monitoring data 

for each vent for 24 

consecutive operating 

hours; and reduce the 

continuous emission 

monitoring data to 1-hour 

averages computed from 

four or more data points 

equally spaced over each 1-

hour period. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

3. Each catalytic 

cracking unit 

catalyst 

regenerator vent 

if you use 

continuous 

parameter 

monitoring 

systems. 

a. Measure the CO 

concentration (dry basis) 

of emissions exiting the 

control device. 

Method 10, 10A, or 10B 

in appendix A to part 60 

of this chapter, as 

applicable. 

 b. Establish each 

operating limit in Table 9 

of this subpart that applies 

to you. 

Data from the 

continuous parameter 

monitoring systems. 

 c. Thermal incinerator 

combustion zone 

temperature. 

Data from the 

continuous parameter 

monitoring systems. 

Collect temperature 

monitoring data every 15 

minutes during the entire 

period of the CO initial 

performance test; and 

determine and record the 

minimum hourly average 

combustion zone 

temperature from all the 

readings. 

 d. Thermal incinerator: 

oxygen, content (percent, 

dry basis) in the 

incinerator vent stream. 

Data from the 

continuous parameter 

monitoring systems. 

Collect oxygen 

concentration (percent, dry 

basis) monitoring data 

every 15 minutes during 

the entire period of the CO 

initial performance test; 

and determine and record 

the minimum hourly 

average percent excess 

oxygen concentration from 

all the readings. 

 e. If you use a process 

heater or boiler with a 

design heat input capacity 

under 44 MW or process 

heater or boiler in which 

all vent streams are not 

introduced into the flame 

zone, establish operating 

limit for combustion zone 

temperature. 

Data from the 

continuous parameter 

monitoring systems. 

Collect the temperature 

monitoring data every 15 

minutes during the entire 

period of the CO initial 

performance test; and 

determine and record the 

minimum hourly average 

combustion zone 

temperature from all the 

readings. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 f. If you use a flare, 

conduct visible emission 

observations. 

Method 22 (40 CFR 

part 60, appendix A). 

On and after [THE DATE 

3 YEARS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

meet the requirements of 

§63.670. Prior to [THE 

DATE 3 YEARS AFTER 

THE DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

maintain a 2-hour 

observation period; and 

record the presence of a 

flame at the pilot light over 

the full period of the test or 

meet the requirements of 

§63.670. 

 g. If you use a flare, 

determine that the flare 

meets the requirements 

for net heating value of 

the gas being combusted 

and exit velocity. 

40 CFR 63.11(b)(6)

through (8). 

On and after [THE DATE 

3 YEARS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

the flare must meet the 

requirements of §63.670. 

Prior to [THE DATE 3 

YEARS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

the flare must meet the 

control device 

requirements in §63.11(b) 

or the requirements of 

§63.670.

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6948, Feb. 9, 2005] 

Table 12 to Subpart UUU of Part 63—Initial Compliance With Organic HAP Emission 

Limits for Catalytic Cracking Units 

Deleted: Maintain

Deleted: 60
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

As stated in §63.1565(b)(4), you shall meet each requirement in the following table that applies 

to you. 

For each new 

and existing 

catalytic 

cracking unit . 

. . 

For the following 

emission limit . . . You have demonstrated initial compliance if . . . 

1. Subject to the 

NSPS for 

carbon 

monoxide (CO) 

in 40 CFR 

60.103 

CO emissions from your 

catalyst regenerator vent 

or CO boiler serving the 

catalytic cracking unit 

must not exceed 500 

ppmv (dry basis). 

You have already conducted a performance test to 

demonstrate initial compliance with the NSPS and 

the measured CO emissions are less than or equal to 

500 ppm (dry basis). As part of the Notification of 

Compliance Status, you must certify that your vent 

meets the CO limit. You are not required to conduct 

another performance test to demonstrate initial 

compliance. You have already conducted a 

performance evaluation to demonstrate initial 

compliance with the applicable performance 

specification. As part of your Notification of 

Compliance Status, you must certify that your 

continuous emission monitoring system meets the 

applicable requirements in §63.1572. You are not 

required to conduct another performance evaluation 

to demonstrate initial compliance. 

2. Not subject to 

the NSPS for 

CO in 40 CFR 

60.103 

a. CO emissions from 

your catalyst regenerator 

vent or CO boiler serving 

the catalytic cracking 

unit must not exceed 500 

ppmv (dry basis). 

i. If you use a continuous parameter monitoring 

system, the average CO emissions measured by 

Method 10 over the period of the initial 

performance test are less than or equal to 500 ppmv 

(dry basis). 

 ii. If you use a continuous emission monitoring 

system, the hourly average CO emissions over the 

24-hour period for the initial performance test are 

not more than 500 ppmv (dry basis); and your 

performance evaluation shows your continuous 

emission monitoring system meets the applicable 

requirements in §63.1572. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. If you use a flare, 

visible emissions must 

not exceed a total of 5 

minutes during any 2 

operating hours. 

On and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare meets the requirements of 

§63.670. Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], visible emissions, measured by 

Method 22 during the 2-hour observation period 

during the initial performance test, are no higher 

than 5 minutes, or the flare meets the requirements 

of §63.670.

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6948, Feb. 9, 2005] 

Table 13 to Subpart UUU of Part 63—Continuous Compliance With Organic HAP 

Emission Limits for Catalytic Cracking Units 

As stated in §63.1565(c)(1), you shall meet each requirement in the following table that applies 

to you. 

For each new 

and existing 

catalytic 

cracking unit 

. . . 

Subject to this 

emission limit for 

your catalyst 

regenerator vent . . 

. 

If you must . 

. . 

You shall demonstrate continuous 

compliance by . . . 

1. Subject to 

the NSPS for 

carbon 

monoxide 

(CO) in 40 

CFR 60.103 

CO emissions from 

your catalyst 

regenerator vent or 

CO boiler serving the 

catalytic cracking unit 

must not exceed 500 

ppmv (dry basis). 

Continuous 

emission 

monitoring 

system 

Collecting the hourly average CO 

monitoring data according to §63.1572; 

and maintaining the hourly average CO 

concentration at or below 500 ppmv (dry 

basis). 

2. Not subject 

to the NSPS 

for CO in 40 

CFR 60.103 

i. CO emissions from 

your catalyst 

regenerator vent or 

CO boiler serving the 

catalytic cracking unit 

must not exceed 500 

ppmv (dry basis). 

Continuous 

emission 

monitoring 

system. 

Same as above. 

Deleted: Visible
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 ii. CO emissions from 

your catalyst 

regenerator vent or 

CO boiler serving the 

catalytic cracking unit 

must not exceed 500 

ppmv (dry basis). 

Continuous 

parameter 

monitoring 

system. 

Maintaining the hourly average CO 

concentration below 500 ppmv (dry 

basis). 

 iii. Visible emissions 

from a flare must not 

exceed a total of 5 

minutes during any 2-

hour period. 

Control 

device-flare 

On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

meeting the requirements of §63.670. 

Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER], 

maintaining visible emissions below a 

total of 5 minutes during any 2-hour 

operating period, or meeting the 

requirements of §63.670. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6948, Feb. 9, 2005] 

Table 14 to Subpart UUU of Part 63—Continuous Compliance With Operating Limits for 

Organic HAP Emissions From Catalytic Cracking Units 

As stated in §63.1565(c)(1), you shall meet each requirement in the following table that applies 

to you. 

For each 

new existing 

catalytic 

cracking 

unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by . . . 

1. Subject to 

NSPS for 

carbon 

monoxide 

(CO) in 40 

CFR 60.103 

Continuous emission 

monitoring system. 

Not applicable Complying with Table 13 of this 

subpart. 

Deleted: s

Deleted: Maintaining
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

2. Not 

subject to 

the NSPS for 

CO in 40 

CFR 60.103 

a. Continuous 

emission monitoring 

system 

Not applicable Complying with Table 13 of this 

subpart. 

 b. Continuous 

parameter monitoring 

systems—thermal 

incinerator. 

i. The daily average 

combustion zone 

temperature must not 

fall below the level 

established during 

the performance test.

Collecting the hourly and daily 

average temperature monitoring 

data according to §63.1572; and 

maintaining the daily average 

combustion zone temperature 

above the limit established during 

the performance test. 

 ii. The daily average 

oxygen concentration 

in the vent stream 

(percent, dry basis) 

must not fall below 

the level established 

during the 

performance test. 

Collecting the hourly and daily 

average oxygen concentration 

monitoring data according to 

§63.1572; and maintaining the 

daily average oxygen concentration 

above the limit established during 

the performance test. 

 c. Continuous 

parameter monitoring 

systems—boiler or 

process heater with a 

design heat input 

capacity under 44 MW 

or boiler or process 

heater in which all 

vent streams are not 

introduced into the 

flame zone. 

The daily 

combustion zone 

temperature must not 

fall below the level 

established in the 

performance test. 

Collecting the average hourly and 

daily temperature monitoring data 

according to §63.1572; and 

maintaining the daily average 

combustion zone temperature 

above the limit established during 

the performance test. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 d. Continuous 

parameter monitoring 

system—flare. 

The flare pilot light 

must be present at all 

times and the flare 

must be operating at 

all times that 

emissions may be 

vented to it. 

On and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], meeting 

the requirements of §63.670. Prior 

to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the flare monitoring data 

according to §63.1572 and 

recording for each 1-hour period 

whether the monitor was 

continuously operating and the 

pilot light was continuously present 

during each 1-hour period, or 

meeting the requirements of 

§63.670. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6948, Feb. 9, 2005] 

Table 15 to Subpart UUU of Part 63—Organic HAP Emission Limits for Catalytic 

Reforming Units 

As stated in §63.1566(a)(1), you shall meet each emission limitation in the following table that 

applies to you. 

For each applicable 

process vent for a new 

or existing catalytic 

reforming unit . . . 

You shall meet this emission limit during initial catalyst 

depressuring and catalyst purging operations . . . 

1. Option 1 On and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], vent emissions to a flare that meets the 

requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], vent emissions to a flare that meets 

the requirements for control devices in §63.11(b) and visible emissions 

from a flare must not exceed a total of 5 minutes during any 2-hour 

operating period, or vent emissions to a flare that meets the 

requirements of §63.670. 

2. Option 2 Reduce uncontrolled emissions of total organic compounds (TOC) or 

nonmethane TOC from your process vent by 98 percent by weight 

Deleted: Collecting

Deleted: ;

Deleted: Vent

Deleted: . Visible
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

using a control device or to a concentration of 20 ppmv (dry basis as 

hexane), corrected to 3 percent oxygen, whichever is less stringent. If 

you vent emissions to a boiler or process heater to comply with the 

percent reduction or concentration emission limitation, the vent stream 

must be introduced into the flame zone, or any other location that will 

achieve the percent reduction or concentration standard. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6951, Feb. 9, 2005] 

Table 16 to Subpart UUU of Part 63—Operating Limits for Organic HAP Emissions From 

Catalytic Reforming Units 

As stated in §63.1566(a)(2), you shall meet each operating limit in the following table that 

applies to you. 

For each new or 

existing 

catalytic 

reforming unit . 

. . 

For this type of control 

device . . . 

You shall meet this operating limit during 

initial catalyst depressuring and purging 

operations. . . 

1. Option 1: vent 

to flare 

Flare On and after [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare must meet 

the requirements of §63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare pilot light must be 

present at all times and the flare must be 

operating at all times that emissions may be 

vented to it, or the flare must meet the 

requirements of §63.670. 

2. Option 2: 

Percent reduction 

or concentration 

limit 

a. Thermal incinerator, boiler 

or process heater with a 

design heat input capacity 

under 44 MW, or boiler or 

process heater in which all 

vent streams are not 

introduced into the flame 

zone 

The daily average combustion zone 

temperature must not fall below the limit 

established during the performance test. 

Deleted: that meets the requirements for control 

devices in §63.11(b)

Deleted: The
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. No control device Operate at all times according to your 

operation, maintenance, and monitoring plan 

regarding minimum catalyst purging 

conditions that must be met prior to allowing 

uncontrolled purge releases. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6951, Feb. 9, 2005] 

Table 17 to Subpart UUU of Part 63—Continuous Monitoring Systems for Organic HAP 

Emissions From Catalytic Reforming Units 

As stated in §63.1566(b)(1), you shall meet each requirement in the following table that applies 

to you. 

For each 

applicable process 

vent for a new or 

existing catalytic 

reforming unit . . 

. 

If you use this type of 

control device . . . 

You shall install and operate this type of 

continuous monitoring system . . . 

1. Option 1: vent to 

a flare 

Flare On and after [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the monitoring 

systems required in §§63.670 and 63.671. 

Prior to [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], monitoring device 

such as a thermocouple, an ultraviolet beam 

sensor, or infrared sensor to continuously 

detect the presence of a pilot flame, or the 

monitoring systems required in §§63.670 and 

63.671. 

2. Option 2: percent 

reduction or 

concentration limit. 

Thermal incinerator, 

process heater or boiler with 

a design heat input capacity 

under 44 MW, or process 

heater or boiler in which all 

vent streams are not 

introduced into the flame 

zone 

Continuous parameter monitoring systems to 

measure and record the combustion zone 

temperature. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6952, Feb. 9, 2005] 

Deleted: that meets the requirements for control 

devices in §63.11(b)

Deleted: Monitoring
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 18 to Subpart UUU of Part 63—Requirements for Performance Tests for Organic 

HAP Emissions From Catalytic Reforming Units 

As stated in §63.1566(b)(2) and (3), you shall meet each requirement in the following table that 

applies to you. 

For each new 

or existing 

catalytic 

reforming 

unit . . . You must . . . Using . . . 

According to these 

requirements . . . 

1. Option 1: 

Vent to a flare 

a. Conduct visible 

emission observations 

Method 22 (40 CFR part 

60, appendix A) 

On and after [THE DATE 3 

YEARS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

the flare must meet the 

requirements of §63.670. 

Prior to [THE DATE 3 

YEARS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER],2-

hour observation period. 

Record the presence of a 

flame at the pilot light over 

the full period of the test, or 

the requirements of §63.670. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. Determine that the 

flare meets the 

requirements for net 

heating value of the gas 

being combusted and 

exit velocity 

40 CFR 63.11(b)(6) 

through (8).

On and after [THE DATE 3 

YEARS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

the flare must meet the 

requirements of §63.670. 

Prior to [THE DATE 3 

YEARS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

the flare must meet the 

control device requirements 

in §63.11(b) or the 

requirements of §63.670. 

2. Option 2: 

Percent 

reduction or 

concentration 

limit 

a. Select sampling site Method 1 or 1A (40 

CFR part 60, appendix 

A). No traverse site 

selection method is 

needed for vents smaller 

than 0.10 meter in 

diameter. 

Sampling sites must be 

located at the inlet (if you 

elect the emission reduction 

standard) and outlet of the 

control device and prior to 

any releases to the 

atmosphere. 

 b. Measure gas 

volumetric flow rate 

Method 2, 2A, 2C, 2D, 

2F, or 2G (40 CFR part 

60, appendix A), as 

applicable 

Moved (insertion) [13]

Moved down [14]: Not applicable

Deleted: .

Moved up [13]: 40 CFR 63.11(b)(6) through (8).
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 c. Measure TOC 

concentration (for 

percent reduction 

standard) 

Method 25 (40 part 60, 

appendix A) to measure 

nonmethane TOC 

concentration (in carbon 

equivalents) at inlet and 

outlet of the control 

device. If the 

nonmethane TOC outlet 

concentration is 

expected to be less than 

50 ppm (as carbon), you 

can use Method 25A to 

measure TOC 

concentration (as 

hexane) at the inlet and 

the outlet of the control 

device. If you use 

Method 25A, you may 

use Method 18 (40 CFR 

part 60, appendix A) to 

measure the methane 

concentration to 

determine the 

nonmethane TOC 

concentration 

Take either an integrated 

sample or four grab samples 

during each run. If you use a 

grab sampling technique, 

take the samples at 

approximately equal 

intervals in time, such as 15-

minute intervals during the 

run. 

 d. Calculate TOC or 

nonmethane TOC 

emission rate and mass 

emission reduction 

 Calculate emission rate by 

Equation 1 of §63.1566 (if 

you use Method 25) or 

Equation 2 of §63.1566 (if 

you use Method 25A). 

Calculate mass emission 

reduction by Equation 3 of 

§63.1566. 

 e. For concentration 

standard, measure TOC 

concentration. 

(Optional: Measure 

methane 

concentration.) 

Method 25A (40 CFR 

part 60, appendix A) to 

measure TOC 

concentration (as 

hexane) at the outlet of 

the control device. You 

may elect to use Method 

18 (40 CFR part 60, 

appendix A) to measure 

the methane 

concentration 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 f. Determine oxygen 

content in the gas 

stream at the outlet of 

the control device 

Method 3A or 3B (40 

CFR part 60, appendix 

A), as applicable 

 g. Calculate the TOC or 

nonmethane TOC 

concentration corrected 

for oxygen content (for 

concentration standard) 

Equation 4 of §63.1566 

 h. Establish each 

operating limit in Table 

16 of this subpart that 

applies to you for a 

thermal incinerator, or 

process heater or boiler 

with a design heat input 

capacity under 44 MW, 

or process heater or 

boiler in which all vent 

streams are not 

introduced into flame 

zone 

Data from the 

continuous parameter 

monitoring systems 

Collect the temperature 

monitoring data every 15 

minutes during the entire 

period of the initial TOC 

performance test. Determine 

and record the minimum 

hourly average combustion 

zone temperature. 

 i. If you do not use a 

control device, 

document the purging 

conditions used prior to 

testing following the 

minimum requirements 

in the operation, 

maintenance, and 

monitoring plan. 

Data from monitoring 

systems as identified in 

the operation, 

maintenance, and 

monitoring plan 

Procedures in the operation, 

maintenance, and monitoring 

plan. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6952, Feb. 9, 2005] 

Table 19 to Subpart UUU of Part 63—Initial Compliance With Organic HAP Emission 

Limits for Catalytic Reforming Units 

As stated in §63.1566(b)(7), you shall meet each requirement in the following table that applies 

to you. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each 

applicable 

process vent for a 

new or existing 

catalytic 

reforming unit 

. . . 

For the following emission 

limit . . . 

You have demonstrated initial 

compliance if . . . 

Option 1 Visible emissions from a flare 

must not exceed a total of 5 

minutes during any 2 

consecutive hours 

On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], the 

flare meets the requirements of §63.670. 

Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], visible

emissions, measured using Method 22 over 

the 2-hour observation period of the 

performance test, do not exceed a total of 5 

minutes, or the flare meets the 

requirements of §63.670. 

Option 2 Reduce uncontrolled emissions 

of total organic compounds 

(TOC) or nonmethane TOC 

from your process vent by 98 

percent by weight using a 

control device or to a 

concentration of 20 ppmv (dry 

basis as hexane), corrected to 3 

percent oxygen, whichever is 

less stringent 

The mass emission reduction of 

nonmethane TOC measured by Method 25 

over the period of the performance test is 

at least 98 percent by weight as calculated 

using Equations 1 and 3 of §63.1566; or 

the mass emission reduction of TOC 

measured by Method 25A (or nonmethane 

TOC measured by Methods 25A and 18) 

over the period of the performance test is 

at least 98 percent by weight as calculated 

using Equations 2 and 3 of §63.1566; or 

the TOC concentration measured by 

Method 25A (or the nonmethane TOC 

concentration measured by Methods 25A 

and 18) over the period of the performance 

test does not exceed 20 ppmv (dry basis as 

hexane) corrected to 3 percent oxygen as 

calculated using Equation 4 of §63.1566. 

[70 FR 6953, Feb. 9, 2005] 

Table 20 to Subpart UUU of Part 63—Continuous Compliance With Organic HAP 

Emission Limits for Catalytic Reforming Units 

Deleted: Visible
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

As stated in §63.1566(c)(1), you shall meet each requirement in the following table that applies 

to you. 

For each 

applicable 

process vent for 

a new or 

existing 

catalytic 

reforming unit . 

. . For this emission limit . . . 

You shall demonstrate continuous 

compliance during initial catalyst 

depressuring and catalyst purging 

operations by . . . 

1. Option 1 Vent emissions from your process 

vent to a flare.

On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

meeting the requirements of §63.670. 

Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], maintaining

visible emissions from a flare below a 

total of 5 minutes during any 2 

consecutive hours, or meeting the 

requirements of §63.670. 

2. Option 2 Reduce uncontrolled emissions of 

total organic compounds (TOC) or 

nonmethane TOC from your 

process vent by 98 percent by 

weight using a control device or to 

a concentration of 20 ppmv (dry 

basis as hexane), corrected to 3 

percent oxygen, whichever is less 

stringent. 

Maintaining a 98 percent by weight 

emission reduction of TOC or nonmethane 

TOC; or maintaining a TOC or 

nonmethane TOC concentration of not 

more than 20 ppmv (dry basis as hexane), 

corrected to 3 percent oxygen, whichever 

is less stringent. 

[70 FR 6954, Feb. 9, 2005] 

Table 21 to Subpart UUU of Part 63—Continuous Compliance With Operating Limits for 

Organic HAP Emissions From Catalytic Reforming Units 

As stated in §63.1566(c)(1), you shall meet each requirement in the following table that applies 

to you. 

Deleted: that meets the requirements in §63.11(b).

Deleted: Maintaining
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each 

applicable 

process vent 

for a new or 

existing 

catalytic 

reforming 

unit . . . If you use . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance during 

initial catalyst depressuring 

and purging operations by . . . 

1. Option 1 Flare The flare pilot light 

must be present at all 

times and the flare 

must be operating at 

all times that 

emissions may be 

vented to it 

On and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], 

meeting the requirements of 

§63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting flare monitoring data 

according to §63.1572 and 

recording for each 1-hour period 

whether the monitor was 

continuously operating and the 

pilot light was continuously 

present during each 1-hour 

period, or meeting the 

requirements of §63.670. 

2. Option 2 a. Thermal 

incinerator boiler or 

process heater with a 

design input capacity 

under 44 MW or 

boiler or process 

heater in which not 

all vent streams are 

not introduced into 

the flame zone 

Maintain the daily 

average combustion 

zone temperature 

above the limit 

established during the 

performance test 

Collecting, the hourly and daily 

temperature monitoring data 

according to §63.1572; and 

maintaining the daily average 

combustion zone temperature 

above the limit established during 

the performance test. 

Deleted: that meets the requirements in §63.11(b)

Deleted: C

Deleted: ;
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. No control device Operate at all times 

according to your 

operation, 

maintenance, and 

monitoring plan 

regarding minimum 

purging conditions 

that must be met prior 

to allowing 

uncontrolled purge 

releases 

Recording information to 

document compliance with the 

procedures in your operation, 

maintenance, and monitoring 

plan. 

[70 FR 6954, Feb. 9, 2005] 

Table 22 to Subpart UUU of Part 63—Inorganic HAP Emission Limits for Catalytic 

Reforming Units 

As stated in §63.1567(a)(1), you shall meet each emission limitation in the following table that 

applies to you. 

For . . . 

You shall meet this emission limit for each applicable 

catalytic reforming unit process vent during coke burnoff and catalyst rejuvenation . . . 

1. Each existing semiregenerative catalytic reforming 

unit 

Reduce uncontrolled emissions of hydrogen chloride (HCl) 

by 92 percent by weight or to a concentration of 30 ppmv 

(dry basis), corrected to 3 percent oxygen. 

2. Each existing cyclic or 

continuous catalytic reforming 

unit 

Reduce uncontrolled emissions of HCl by 97 percent by 

weight or to a concentration of 10 ppmv (dry basis), corrected 

to 3 percent oxygen. 

3. Each new semi-regenerative, 

cyclic, or continuous catalytic 

reforming unit 

Reduce uncontrolled emissions of HCl by 97 percent by 

weight or to a concentration of 10 ppmv (dry basis), corrected 

to 3 percent oxygen. 

[70 FR 6955, Feb. 9, 2005] 

Table 23 to Subpart UUU of Part 63—Operating Limits for Inorganic HAP Emission 

Limitations for Catalytic Reforming Units 

As stated in §63.1567(a)(2), you shall meet each operating limit in the following table that 

applies to you. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each applicable process 

vent for a new or existing 

catalytic reforming unit with 

this type of control device . . 

. 

You shall meet this operating limit during coke burn-off and 

catalyst rejuvenation . . . 

1. Wet scrubber The daily average pH or alkalinity of the water (or scrubbing 

liquid) exiting the scrubber must not fall below the limit 

established during the performance test; and the daily average 

liquid-to-gas ratio must not fall below the limit established 

during the performance test. 

2. Internal scrubbing system 

or no control device (e.g., hot 

regen system) meeting outlet 

HCl concentration limit. 

The daily average HCl concentration in the catalyst regenerator 

exhaust gas must not exceed the limit established during the 

performance test. 

3. Internal scrubbing system 

meeting HCl percent reduction 

standard. 

The daily average pH or alkalinity of the water (or scrubbing 

liquid) exiting the internal scrubbing system must not fall below 

the limit established during the performance test; and the daily 

average liquid-to-gas ratio must not fall below the limit 

established during the performance test. 

4. Fixed-bed gas-solid 

adsorption system 

The daily average temperature of the gas entering or exiting the 

adsorption system must not exceed the limit established during 

the performance test; and the HCl concentration in the 

adsorption system exhaust gas must not exceed the limit 

established during the performance test. 

5. Moving-bed gas-solid 

adsorption system (e.g., 

ChlorsorbTM System). 

The daily average temperature of the gas entering or exiting the 

adsorption system must not exceed the limit established during 

the performance test; and the weekly average chloride level on 

the sorbent entering the adsorption system must not exceed the 

design or manufacturer's recommended limit (1.35 weight 

percent for the ChlorsorbTM System); and the weekly average 

chloride level on the sorbent leaving the adsorption system must 

not exceed the design or manufacturer's recommended limit (1.8 

weight percent for the ChlorsorbTM System). 

[70 FR 6955, Feb. 9, 2005] 

Table 24 to Subpart UUU of Part 63—Continuous Monitoring Systems for Inorganic HAP 

Emissions From Catalytic Reforming Units 

As stated in §63.1567(b)(1), you shall meet each requirement in the following table that applies 

to you. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

If you use this type of 

control device for your vent 

. . . 

You shall install and operate this type of continuous 

monitoring system . . . 

1. Wet scrubber Continuous parameter monitoring system to measure and record 

the total water (or scrubbing liquid) flow rate entering the 

scrubber during coke burn-off and catalyst rejuvenation; and 

continuous parameter monitoring system to measure and record 

gas flow rate entering or exiting the scrubber during coke burnoff and catalyst rejuvenation1

; and continuous parameter 

monitoring system to measure and record the pH or alkalinity of 

the water (or scrubbing liquid) exiting the scrubber during coke 

burn-off and catalyst rejuvenation.2

2. Internal scrubbing system 

or no control device (e.g., hot 

regen system) to meet HCl

outlet concentration limit. 

Colormetric tube sampling system to measure the HCl

concentration in the catalyst regenerator exhaust gas during coke 

burn-off and catalyst rejuvenation. The colormetric tube sampling 

system must meet the requirements in Table 41 of this subpart. 

3. Internal scrubbing system 

to meet HCl percent 

reduction standard 

Continuous parameter monitoring system to measure and record 

the gas flow rate entering or exiting the internal scrubbing system 

during coke burn-off and catalyst rejuvenation; and continuous 

parameter monitoring system to measure and record the total 

water (or scrubbing liquid) flow rate entering the internal 

scrubbing system during coke burn-off and catalyst rejuvenation; 

and continuous parameter monitoring system to measure and 

record the pH or alkalinity of the water (or scrubbing liquid) 

exiting the internal scrubbing system during coke burn-off and 

catalyst rejuvenation.2

4. Fixed-bed gas-solid 

adsorption system 

Continuous parameter monitoring system to measure and record 

the temperature of the gas entering or exiting the adsorption 

system during coke burn-off and catalyst rejuvenation; and 

colormetric tube sampling system to measure the gaseous HCl

concentration in the adsorption system exhaust and at a point 

within the absorbent bed not to exceed 90 percent of the total 

length of the absorbent bed during coke burn-off and catalyst 

rejuvenation. The colormetric tube sampling system must meet 

the requirements in Table 41 of this subpart. 

5. Moving-bed gas-solid 

adsorption system (e.g., 

ChlorsorbTM System). 

Continuous parameter monitoring system to measure and record 

the temperature of the gas entering or exiting the adsorption 

system during coke burn-off and catalyst rejuvenation. 

1

If applicable, you can use the alternative in §63.1573 (a)(1) instead of a continuous parameter 

monitoring system for gas flow rate or instead of a continuous parameter monitoring system for 

the cumulative volume of gas. 

2

If applicable, you can use the alternative in §63.1573(c)(1) instead of a continuous parameter 

monitoring system for pH of the water (or scrubbing liquid) or the alternative in §63.1573(c)(2) 

Deleted: 1

Deleted: 1

Deleted: 1

Deleted: 1

Deleted: b

Deleted: b
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

instead of a continuous parameter monitoring system for alkalinity of the water (or scrubbing 

liquid). 

[70 FR 6956, Feb. 9, 2005] 

Table 25 to Subpart UUU of Part 63—Requirements for Performance Tests for Inorganic 

HAP Emissions From Catalytic Reforming Units 

As stated in §63.1567(b)(2) and (3), you shall meet each requirement in the following table that 

applies to you. 

For each new 

and existing 

catalytic 

reforming unit 

using . . . You shall . . . Using . . . 

According to these 

requirements . . . 

1. Any or no 

control system 

a. Select 

sampling port 

location(s) and 

the number of 

traverse points 

Method 1 or 1A (40 CFR 

part 60, appendix A), as 

applicable. 

(1) If you operate a control 

device and you elect to meet 

an applicable HCl percent 

reduction standard, 

sampling sites must be 

located at the inlet of the 

control device or internal 

scrubbing system and at the 

outlet of the control device 

or internal scrubber system 

prior to any release to the 

atmosphere. For a series of 

fixed-bed systems, the 

outlet sampling site should 

be located at the outlet of 

the first fixed-bed, prior to 

entering the second fixedbed in the series. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 (2) If you elect to meet an 

applicable HCl outlet 

concentration limit, locate 

sampling sites at the outlet 

of the control device or 

internal scrubber system 

prior to any release to the 

atmosphere. For a series of 

fixed-bed systems, the 

outlet sampling site should 

be located at the outlet of 

the first fixed-bed, prior to 

entering the second fixedbed in the series. If there is 

no control device, locate 

sampling sites at the outlet 

of the catalyst regenerator 

prior to any release to the 

atmosphere. 

 b. Determine 

velocity and 

volumetric flow 

rate. 

Method 2, 2A, 2C, 2D, 2F, 

or 2G (40 CFR part 60, 

appendix A), as applicable. 

 c. Conduct gas 

molecular weight 

analysis. 

Method 3, 3A, or 3B (40 

CFR part 60, appendix A), as 

applicable 

 d. Measure 

moisture content 

of the stack gas 

Method 4 (40 CFR part 60, 

appendix A) 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 e. Measure the 

HCl 

concentration at 

the selected 

sampling 

locations 

Method 26 or 26A (40 CFR 

part 60, appendix A). If your 

control device is a wet 

scrubber or internal 

scrubbing system, you must 

use Method 26A 

(1) For semi-regenerative 

and cyclic regeneration 

units, conduct the test 

during the coke burn-off 

and catalyst rejuvenation 

cycle, but collect no 

samples during the first 

hour or the last 6 hours of 

the cycle (for semiregenerative units) or during 

the first hour or the last 2 

hours of the cycle (for 

cyclic regeneration units). 

For continuous regeneration 

units, the test should be 

conducted no sooner than 3 

days after process unit or 

control system start up. 

 (2) Determine and record 

the HCl concentration 

corrected to 3 percent 

oxygen (using Equation 1 of 

§63.1567) for each 

sampling location for each 

test run. 

 (3) Determine and record 

the percent emission 

reduction, if applicable, 

using Equation 3 of 

§63.1567 for each test run. 

 (4) Determine and record 

the average HCl 

concentration (corrected to 

3 percent oxygen) and the 

average percent emission 

reduction, if applicable, for 

the overall source test from 

the recorded test run values. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

2. Wet scrubber a. Establish 

operating limit 

for pH level or 

alkalinity 

i. Data from continuous 

parameter monitoring 

systems 

Measure and record the pH 

or alkalinity of the water (or 

scrubbing liquid) exiting 

scrubber every 15 minutes 

during the entire period of 

the performance test. 

Determine and record the 

minimum hourly average 

pH or alkalinity level from 

the recorded values. 

 ii. Alternative pH procedure 

in §63.1573 (b)(1). 

Measure and record the pH 

of the water (or scrubbing 

liquid) exiting the scrubber 

during coke burn-off and 

catalyst rejuvenation using 

pH strips at least three times 

during each test run. 

Determine and record the 

average pH level for each 

test run. Determine and 

record the minimum test run 

average pH level. 

 iii. Alternative alkalinity 

method in §63.1573(c)(2) 

Measure and record the 

alkalinity of the water (or 

scrubbing liquid) exiting the 

scrubber during coke burnoff and catalyst rejuvenation 

using discrete titration at 

least three times during each 

test run. Determine and 

record the average alkalinity 

level for each test run. 

Determine and record the 

minimum test run average 

alkalinity level. 

Deleted: b
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. Establish 

operating limit 

for liquid-to-gas 

ratio. 

i. Data from continuous 

parameter monitoring 

systems 

Measure and record the gas 

flow rate entering or exiting 

the scrubber and the total 

water (or scrubbing liquid) 

flow rate entering the 

scrubber every 15 minutes 

during the entire period of 

the performance test. 

Determine and record the 

hourly average gas flow rate 

and total water (or 

scrubbing liquid) flow rate. 

Determine and record the 

minimum liquid-to-gas ratio 

from the recorded, paired 

values. 

 ii. Alternative procedure for 

gas flow rate in 

§63.1573(a)(1) 

Collect air flow rate 

monitoring data or 

determine the air flow rate 

using control room 

instruments every 15 

minutes during the entire 

period of the initial 

performance test. Determine 

and record the hourly 

average rate of all the 

readings. Determine and 

record the maximum gas 

flow rate using Equation 1 

of §63.1573. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

3. Internal 

scrubbing system 

or no control 

device (e.g., hot 

regen system) 

meeting HCl 

outlet 

concentration 

limit. 

Establish 

operating limit 

for HCl 

concentration. 

Data from continuous 

parameter monitoring 

system. 

Measure and record the HCl 

concentration in the catalyst 

regenerator exhaust gas 

using the colormetric tube 

sampling system at least 

three times during each test 

run. Determine and record 

the average HCl 

concentration for each test 

run. Determine and record 

the average HCl 

concentration for the overall 

source test from the 

recorded test run averages. 

Determine and record the 

operating limit for HCl 

concentration using 

Equation 4 of §63.1567. 

4. Internal 

scrubbing system 

meeting HCl 

percent reduction 

standard 

a. Establish 

operating limit 

for pH level or 

alkalinity 

i. Data from continuous 

parameter monitoring system

Measure and record the pH 

alkalinity of the water (or 

scrubbing liquid) exiting the 

internal scrubbing system 

every 15 minutes during the 

entire period of the 

performance test. Determine 

and record the minimum 

hourly average pH or 

alkalinity level from the 

recorded values. 

 ii. Alternative pH method in 

§63.1573(c)(1) 

Measure and in record pH 

of the water (or scrubbing 

liquid) exiting the internal 

scrubbing system during 

coke burn-off and catalyst 

rejuvenation using pH strips 

at least three times during 

each test run. Determine and 

record the average pH level 

for each test run. Determine 

and record the minimum 

test run average pH level. 

Deleted: b
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 iii. Alternative alkalinity 

method in §63.1573(c)(2) 

Measure and record the 

alkalinity water (or 

scrubbing liquid) exiting the 

internal scrubbing system 

during coke burn-off and 

catalyst rejuvenation using 

discrete titration at least 

three times during each test 

run. Determine and record 

the average alkalinity level 

for each test run. Determine 

and record the minimum 

test run average alkalinity 

level. 

 b. Establish 

operating limit 

for liquid-to-gas 

ratio 

Data from continuous 

parameter monitoring 

systems 

Measure and record the gas 

entering or exiting the 

internal scrubbing system 

and the total water (or 

scrubbing liquid) flow rate 

entering the internal 

scrubbing system every 15 

minutes during the entire 

period of the performance 

test. Determine and record 

the hourly average gas flow 

rate and total water (or 

scrubbing liquid) flow rate. 

Determine and record the 

minimum liquid-to-gas ratio 

from the recorded, paired 

values. 

5. Fixed-bed gassolid adsorption 

system. Gas-solid 

a. Establish 

operating limit 

for temperature 

Data from continuous 

parameter monitoring system

Measure and record the 

temperature of gas entering 

or exiting the adsorption 

system every 15 minutes. 

Determine and record the 

maximum hourly average 

temperature. 

Deleted: b
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. Establish 

operating limit 

for HCl 

concentration 

i. Data from continuous 

parameter monitoring 

systems 

(1) Measure and record the 

HCl concentration in the 

exhaust gas from the fixedbed adsorption system using 

the colormetric tube 

sampling system at least 

three times during each test 

run. Determine and record 

the average HCl 

concentration for each test 

run. Determine and record 

the average HCl 

concentration for the overall 

source test from the 

recorded test run averages. 

 (2) If you elect to comply 

with the HCl outlet 

concentration limit (Option 

2), determine and record the 

operating limit for HCl 

concentration using 

Equation 4 of §63.1567. If 

you elect to comply with the 

HCl percent reduction 

standard (Option 1), 

determine and record the 

operating limit for HCl 

concentration using 

Equation 5 of §63.1567. 

6. Moving-bed 

gas-solid 

adsorption system 

(e.g., 

ChlorsorbTM

System) 

a. Establish 

operating limit 

for temperature 

Data from continuous 

parameter monitoring 

systems. 

Measure and record the 

temperature of gas entering 

or exiting the adsorption 

system every 15 minutes. 

Determine and record the 

maximum hourly average 

temperature. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. Measure the 

chloride level on 

the sorbent 

entering and 

exiting the 

adsorption 

system. 

Determination of Metal 

Concentration on Catalyst 

Particles (Instrumental 

Analyzer Procedure) in 

appendix A to subpart UUU; 

or EPA Method 5050 

combined either with EPA 

Method 9056, or with EPA 

Method 9253; or EPA 

Method 9212 with the soil 

extraction procedures listed 

within the method.1

Measure and record the 

chloride concentration of 

the sorbent material entering 

and exiting the adsorption 

system at least three times 

during each test run. 

Determine and record the 

average weight percent 

chloride concentration of 

the sorbent entering the 

adsorption system for each 

test run. Determine and 

record the average weight 

percent chloride 

concentration of the sorbent 

exiting the adsorption 

system for each test run. 

1

The EPA Methods 5050, 9056, 9212 and 9253 are included in “Test Methods for Evaluating 

Solid Waste, Physical/Chemical Methods,” EPA Publication SW-846, Revision 5 (April 1998). 

The SW-846 and Updates (document number 955-001-00000-1) are available for purchase from 

the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, 

(202) 512-1800; and from the National Technical Information Services (NTIS), 5285 Port Royal 

Road, Springfield, VA 22161, (703) 487-4650. Copies may be inspected at the EPA Docket 

Center (Air Docket), EPA West, Room B-108, 1301 Constitution Ave., NW., Washington, DC; 

or at the Office of the Federal Register, 800 North Capitol Street, NW., Suite 700, Washington, 

DC. These methods are also available at http://www.epa.gov/epaoswer/hazwaste/test/main.htm. 

[70 FR 6956, Feb. 9, 2005] 

Table 26 to Subpart UUU of Part 63—Initial Compliance With Inorganic HAP Emission 

Limits for Catalytic Reforming Units 

As stated in §63.1567(b)(4), you shall meet each requirement in the following table that applies 

to you. 

For . . . 

For the following 

emission limit . . . 

You have demonstrated initial 

compliance if . . . 

1. Each existing semiregenerative catalytic 

reforming unit 

Reduce uncontrolled 

emissions of HCl by 92 

percent by weight or to a 

concentration of 30 ppmv, 

(dry basis), corrected to 3 

percent oxygen. 

Average emissions HCl measured 

using Method 26 or 26A, as applicable, 

over the period of the performance test, 

are reduced by 92 percent or to a 

concentration less than or equal to 30 

ppmv (dry basis) corrected to 3 percent 

oxygen. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

2. Each existing cyclic or 

continuous catalytic 

reforming unit and each 

new semi-regenerative, 

cyclic, or continuous 

catalytic reforming unit. 

Reduce uncontrolled 

emissions of HCl by 97 

percent by weight or to a 

concentration of 10 ppmv 

(dry basis), corrected to 3 

percent oxygen 

Average emissions of HCl measured 

using Method 26 or 26A, as applicable, 

over the period of the performance test, 

are reduced by 97 percent or to a 

concentration less than or equal to 10 

ppmv (dry basis) corrected to 3 percent 

oxygen. 

[70 FR 6959, Feb. 9, 2005] 

Table 27 to Subpart UUU of Part 63—Continuous Compliance With Inorganic HAP 

Emission Limits for Catalytic Reforming Units 

As stated in §63.1567(c)(1), you shall meet each requirement in the following table that applies 

to you. 

For . . . For this emission limit . . . 

You shall demonstrate 

continuous compliance during 

coke burn-off and catalyst 

rejuvenation by . . . 

1. Each existing semiregenerative catalytic 

reforming unit 

Reduce uncontrolled emissions of 

HCl by 92 percent by weight or to 

a concentration of 30 ppmv (dry 

basis), corrected to 3 percent 

oxygen. 

Maintaining a 92 percent HCl 

emission reduction or an HCl 

concentration no more than 30 

ppmv (dry basis), corrected to 3 

percent oxygen. 

2. Each existing cyclic 

or continuous catalytic 

reforming unit 

Reduce uncontrolled emissions of 

HCl by 97 percent by weight or to 

a concentration of 10 ppmv (dry 

basis), corrected to 3 percent 

oxygen 

Maintaining a 97 percent HCl 

control efficiency or an HCl 

concentration no more than 10 

ppmv (dry basis), corrected to 3 

percent oxygen. 

3. Each new semiregenerative, cyclic, or 

continuous catalytic 

reforming unit 

Reduce uncontrolled emissions of 

HCl by 97 percent by weight or to 

a concentration of 10 ppmv (dry 

basis), corrected to 3 percent 

oxygen 

Maintaining a 97 percent HCl 

control efficiency or an HCl 

concentration no more than 10 

ppmv (dry basis), corrected to 3 

percent oxygen. 

[70 FR 6960, Feb. 9, 2005] 

Table 28 to Subpart UUU of Part 63—Continuous Compliance With Operating Limits for 

Inorganic HAP Emissions From Catalytic Reforming Units 

As stated in §63.1567(c)(1), you shall meet each requirement in the following table that applies 

to you. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For each new and 

existing catalytic 

reforming unit 

using this type of 

control device or 

system . . . For this operating limit . . . 

You shall demonstrate continuous 

compliance during coke burn-off 

and catalyst rejuvenation by . . . 

1. Wet scrubber a. The daily average pH or alkalinity 

of the water (or scrubbing liquid) 

exiting the scrubber must not fall 

below the level established during 

the performance test 

Collecting the hourly and daily 

average pH or alkalinity monitoring 

data according to §63.15721

; and 

maintaining the daily average pH or 

alkalinity above the operating limit 

established during the performance 

test. 

 b. The daily average liquid-to-gas 

ratio must not fall below the level 

established during the performance 

test 

Collecting the hourly average gas 

flow rate2

 and total water (or 

scrubbing liquid) flow rate 

monitoring data according to 

§63.1572; and determining and 

recording the hourly average liquidto-gas ratio; and determining and 

recording the daily average liquid-togas ratio; and maintaining the daily 

average liquid-to-gas ratio above the 

limit established during the 

performance test. 

2. Internal 

scrubbing system or 

no control device 

(e.g., hot regen 

system) meeting 

HCl concentration 

limit 

The daily average HCl concentration 

in the catalyst regenerator exhaust 

gas must not exceed the limit 

established during the performance 

test 

Measuring and recording the HCl 

concentration at least 4 times during 

a regeneration cycle (equally spaced 

in time) or every 4 hours, whichever 

is more frequent, using a colormetric 

tube sampling system; calculating 

the daily average HCl concentration 

as an arithmetic average of all 

samples collected in each 24-hour 

period from the start of the coke 

burn-off cycle or for the entire 

duration of the coke burn-off cycle if 

the coke burn-off cycle is less than 

24 hours; and maintaining the daily 

average HCl concentration below the 

applicable operating limit. 

3. Internal 

scrubbing system 

meeting percent 

HCl reduction 

a. The daily average pH or alkalinity 

of the water (or scrubbing liquid) 

exiting the internal scrubbing system 

must not fall below the limit 

Collecting the hourly and daily 

average pH or alkalinity monitoring 

data according to §63.15721

 and 

maintaining the daily average pH or 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

standard established during the performance 

test 

alkalinity above the operating limit 

established during the performance 

test. 

 b. The daily average liquid-to-gas 

ratio must not fall below the level 

established during the performance 

test 

Collecting the hourly average gas 

flow rate2

 and total water (or 

scrubbing liquid) flow rate 

monitoring data according to 

§63.1572; and determining and 

recording the hourly average liquidto-gas ratio; and determining and 

recording the daily average liquid-togas ratio; and maintaining the daily 

average liquid-to-gas ratio above the 

limit established during the 

performance test. 

4. Fixed-bed gassolid adsorption 

systems 

a. The daily average temperature of 

the gas entering or exiting the 

adsorption system must not exceed 

the limit established during the 

performance test 

Collecting the hourly and daily 

average temperature monitoring data 

according to §63.1572; and 

maintaining the daily average 

temperature below the operating 

limit established during the 

performance test. 

 b. The HCl concentration in the 

exhaust gas from the fixed-bed gassolid adsorption system must not 

exceed the limit established during 

the performance test 

Measuring and recording the 

concentration of HCl weekly or 

during each regeneration cycle, 

whichever is less frequent, using a 

colormetric tube sampling system at 

a point within the adsorbent bed not 

to exceed 90 percent of the total 

length of the adsorption bed during 

coke-burn-off and catalyst 

rejuvenation; implementing 

procedures in the operating and 

maintenance plan if the HCl 

concentration at the sampling 

location within the adsorption bed 

exceeds the operating limit; and 

maintaining the HCl concentration in 

the gas from the adsorption system 

below the applicable operating limit. 

5. Moving-bed gassolid adsorption 

system (e.g., 

ChlorsorbTM

System 

a. The daily average temperature of 

the gas entering or exiting the 

adsorption system must not exceed 

the limit established during the 

performance test 

Collecting the hourly and daily 

average temperature monitoring data 

according to §63.1572; and 

maintaining the daily average 

temperature below the operating 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

limit established during the 

performance test. 

 b. The weekly average chloride level 

on the sorbent entering the 

adsorption system must not exceed 

the design or manufacturer's 

recommended limit (1.35 weight 

percent for the ChlorsorbTM System)

Collecting samples of the sorbent 

exiting the adsorption system three 

times per week (on non-consecutive 

days); and analyzing the samples for 

total chloride3

; and determining and 

recording the weekly average 

chloride concentration; and 

maintaining the chloride 

concentration below the design or 

manufacturer's recommended limit 

(1.35 weight percent for the 

ChlorsorbTM System). 

 c. The weekly average chloride level 

on the sorbent exiting the adsorption 

system must not exceed the design 

or manufacturer's recommended 

limit (1.8 weight percent for the 

ChlorsorbTM System) 

Collecting samples of the sorbent 

exiting the adsorption system three 

times per week (on non-consecutive 

days); and analyzing the samples for 

total chloride concentration; and 

determining and recording the 

weekly average chloride 

concentration; and maintaining the 

chloride concentration below the 

design or manufacturer's 

recommended limit (1.8 weight 

percent ChlorsorbTM System). 

1

If applicable, you can use either alternative in §63.1573(c) instead of a continuous parameter 

monitoring system for pH or alkalinity if you used the alternative method in the initial 

performance test. 

2

If applicable, you can use the alternative in §63.1573(a)(1) instead of a continuous parameter 

monitoring system for the gas flow rate or cumulative volume of gas entering or exiting the 

system if you used the alternative method in the initial performance test. 

3

The total chloride concentration of the sorbent material must be measured by the procedure, 

“Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure)” 

in appendix A to this subpart; or by using EPA Method 5050, Bomb Preparation Method for 

Solid Waste, combined either with EPA Method 9056, Determination of Inorganic Anions by 

Ion Chromatography, or with EPA Method 9253, Chloride (Titrimetric, Silver Nitrate); or by 

using EPA Method 9212, Potentiometric Determination of Chloride in Aqueous Samples with 

Ion-Selective Electrode, and using the soil extraction procedures listed within the method. The 

EPA Methods 5050, 9056, 9212 and 9253 are included in “Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods,” EPA Publication SW-846, Revision 5 (April 1998). The 

SW-846 and Updates (document number 955-001-00000-1) are available for purchase from the 

Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 

512-1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, 

Deleted: ClorsorbTM

Deleted: b
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Springfield, VA 22161, (703) 487-4650. Copies may be inspected at the EPA Docket Center (Air 

Docket), EPA West, Room B-108, 1301 Constitution Ave., NW., Washington, DC; or at the 

Office of the Federal Register, 800 North Capitol Street, NW., Suite 700, Washington, DC. 

These methods are also available at http://www.epa.gov/epaoswer/hazwaste/test/main.htm. 

[70 FR 6954, Feb. 9, 2005] 

Table 29 to Subpart UUU of Part 63—HAP Emission Limits for Sulfur Recovery Units 

As stated in §63.1568(a)(1), you shall meet each emission limitation in the following table that 

applies to you. 

For . . . 

You shall meet this emission limit for each 

process vent . . . 

1. Each new or existing Claus sulfur recovery 

unit part of a sulfur recovery plant with 

design capacity greater than 20 long tons per 

day and subject to the NSPS for sulfur oxides 

in 40 CFR 60.104(a)(2) or in 40 CFR 

60.102a(f)(1). 

a. 250 ppmv (dry basis) of sulfur dioxide (SO2) at 

zero percent excess air, or concentration 

determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an oxidation control 

system or if you use a reduction control system 

followed by incineration. 

 b. 300 ppmv of reduced sulfur compounds 

calculated as ppmv SO2 (dry basis) at zero 

percent excess air, or concentration determined 

using Equation 1 of 40 CFR 60.102a(f)(1)(i), if 

you use a reduction control system without 

incineration. 

2. Each new or existing sulfur recovery unit 

(Claus or other type, regardless of size) not 

subject to the NSPS for sulfur oxides in 40 

CFR 60.104(a)(2) or in 40 CFR 

60.102a(f)(1): Option 1 (Elect NSPS). 

a. 250 ppmv (dry basis) of SO2 at zero percent 

excess air, or concentration determined using 

Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use 

an oxidation control system or if you use a

reduction control system followed by 

incineration. 

 b. 300 ppmv of reduced sulfur compounds 

calculated as ppmv SO2 (dry basis) at zero 

percent excess air, or concentration determined 

using Equation 1 of 40 CFR 60.102a(f)(1)(i), if 

you use a reduction control system without 

incineration. 

3. Each new or existing sulfur recovery unit 

(Claus or other type, regardless of size) not 

subject to the NSPS for sulfur oxides in 40 

CFR 60.104(a)(2) or in 40 CFR 

60.102a(f)(1): Option 2 (TRS limit). 

300 ppmv of total reduced sulfur (TRS) 

compounds, expressed as an equivalent SO2

concentration (dry basis) at zero percent oxygen. 

Deleted: of

Deleted: or more 

Deleted: or

Deleted: or

Deleted: paragraph (a)(2) of 

Deleted: :
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Table 30 to Subpart UUU of Part 63—Operating Limits for HAP Emissions From Sulfur 

Recovery Units 

As stated in §63.1568(a)(2), you shall meet each operating limit in the following table that 

applies to you. 

For . . . 

If use this 

type of 

control 

device 

You shall meet this operating limit. . 

. 

1. Each new or existing Claus sulfur 

recovery unit part of a sulfur recovery 

plant with design capacity greater than

20 long tons per day and subject to the 

NSPS for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1). 

Not 

applicable 

Not applicable. 

2. Each new or existing sulfur recovery 

unit (Claus or other type, regardless of 

size) not subject to the NSPS for sulfur 

oxides in 40 CFR 60.104(a)(2) or in 40 

CFR 60.102a(f)(1): Option 1 (Elect 

NSPS). 

Not 

applicable 

Not applicable. 

3. Each new or existing sulfur recovery 

unit (Claus or other type, regardless of 

size) not subject to the NSPS for sulfur 

oxides in 40 CFR 60.104(a)(2) or in 40 

CFR 60.102a(f)(1): Option 2 (TRS 

limit), if using continuous emissions 

monitoring systems. 

Not 

applicable

Not applicable. 

4. Each new or existing sulfur recovery 

unit (Claus or other type, regardless of 

size) not subject to the NSPS for sulfur 

oxides in 40 CFR 60.104(a)(2) or in 40 

CFR 60.102a(f)(1): Option 2 (TRS 

limit), if using continuous parameter 

monitoring systems. 

Thermal 

incinerator 

Maintain the daily average combustion 

zone temperature above the limit 

established during the performance test; 

and maintain the daily average oxygen 

concentration in the vent stream 

(percent, dry basis) above the limit 

established during the performance test. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Deleted: of

Deleted: or more 

Moved (insertion) [14]

Deleted: 3
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 31 to Subpart UUU of Part 63—Continuous Monitoring Systems for HAP Emissions 

From Sulfur Recovery Units 

As stated in §63.1568(b)(1), you shall meet each requirement in the following table that applies 

to you. 

For . . . For this limit . . . 

You shall install and operate this 

continuous monitoring system . . . 

1. Each new or existing Claus 

sulfur recovery unit part of a 

sulfur recovery plant with 

design capacity greater than

20 long tons per day and 

subject to the NSPS for sulfur 

oxides in 40 CFR 60.104(a)(2)

or in 40 CFR 60.102a(f)(1).

a. 250 ppmv (dry basis) of 

SO2 at zero percent excess 

air if you use an oxidation 

or reduction control 

system followed by 

incineration 

Continuous emission monitoring 

system to measure and record the 

hourly average concentration of SO2

(dry basis) at zero percent excess air 

for each exhaust stack. This system 

must include an oxygen monitor for 

correcting the data for excess air. 

 b. 300 ppmv of reduced 

sulfur compounds 

calculated as ppmv SO2

(dry basis) at zero percent 

excess air if you use a 

reduction control system 

without incineration 

Continuous emission monitoring 

system to measure and record the 

hourly average concentration of 

reduced sulfur and oxygen (O2) 

emissions. Calculate the reduced 

sulfur emissions as SO2 (dry basis) 

at zero percent excess air. Exception:

You can use an instrument having an 

air or SO2 dilution and oxidation 

system to convert the reduced sulfur 

to SO2 for continuously monitoring 

and recording the concentration (dry 

basis) at zero percent excess air of 

the resultant SO2 instead of the 

reduced sulfur monitor. The monitor 

must include an oxygen monitor for 

correcting the data for excess 

oxygen. 

c. If you use Equation 1 of 

40 CFR 60.102a(f)(1)(i) to 

set your emission limit 

Complete either item 1.a or item 1.b; 

and you must also install and operate 

a continuous emission monitoring 

system to measure and record the O2

concentration for the inlet air/oxygen 

supplied to the system. 

2. Option 1: Elect NSPS. Each 

new or existing sulfur 

recovery unit (Claus or other 

type, regardless of size) not 

subject to the NSPS for sulfur 

a. 250 ppmv (dry basis) of 

SO2 at zero percent excess 

air if you use an oxidation 

or reduction control 

system followed by 

Continuous emission monitoring 

system to measure and record the 

hourly average concentration of SO2

(dry basis), at zero percent excess air 

for each exhaust stack. This system 

Deleted: of

Deleted: or more 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

oxides in paragraph (a) (2) of 

40 CFR 60.104 or in 40 CFR 

60.102a(f)(1).

incineration must include an oxygen monitor for 

correcting the data for excess air. 

 b. 300 ppmv of reduced 

sulfur compounds 

calculated as ppmv SO2

(dry basis) at zero percent 

excess air if you use a 

reduction control system 

without incineration. 

Continuous emission monitoring 

system to measure and record the 

hourly average concentration of 

reduced sulfur and O2 emissions for 

each exhaust stack. Calculate the 

reduced sulfur emissions as SO2 (dry 

basis), at zero percent excess air. 

Exception: You can use an 

instrument having an air or O2

dilution and oxidation system to 

convert the reduced sulfur to SO2 for 

continuously monitoring and 

recording the concentration (dry 

basis) at zero percent excess air of 

the resultant SO2 instead of the 

reduced sulfur monitor. The monitor 

must include an oxygen monitor for 

correcting the data for excess 

oxygen. 

c. If you use Equation 1 of 

40 CFR 60.102a(f)(1)(i) to 

set your emission limit 

Complete either item 2.a or item 2.b; 

and you must also install and operate 

a continuous emission monitoring 

system to measure and record the O2

concentration for the inlet air/oxygen 

supplied to the system. 

3. Option 2: TRS limit. Each 

new or existing sulfur 

recovery unit (Claus or other 

type, regardless of size) not 

subject to the NSPS for sulfur 

oxides in 40 CFR 60.104(a)(2)

or in 40 CFR 60.102a(f)(1).

300 ppmv of total reduced 

sulfur (TRS) compounds, 

expressed as an equivalent 

SO2 concentration (dry 

basis) at zero percent 

oxygen 

i. Continuous emission monitoring 

system to measure and record the 

hourly average concentration of TRS 

for each exhaust stack; this monitor 

must include an oxygen monitor for 

correcting the data for excess 

oxygen; or 

 ii. Continuous parameter monitoring 

systems to measure and record the 

combustion zone temperature of 

each thermal incinerator and the 

oxygen content (percent, dry basis) 

in the vent stream of the incinerator. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6961, Feb. 9, 2005] 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 32 to Subpart UUU of Part 63—Requirements for Performance Tests for HAP 

Emissions From Sulfur Recovery Units Not Subject to the New Source Performance 

Standards for Sulfur Oxides 

As stated in §63.1568(b)(2) and (3), you shall meet each requirement in the following table that 

applies to you. 

For . . . You must . . . Using . . .

According to 

these 

requirements . 

. . 

1. Each new and existing sulfur 

recovery unit: Option 1 (Elect NSPS). 

Measure SO2 concentration 

(for an oxidation or 

reduction system followed 

by incineration) or measure

the concentration of 

reduced sulfur (or SO2 if 

you use an instrument to 

convert the reduced sulfur 

to SO2) for a reduction 

control system without 

incineration. 

Data from 

continuous 

emission 

monitoring 

system. 

Collect SO2

monitoring data 

every 15 minutes 

for 24 

consecutive 

operating hours. 

Reduce the data 

to 1-hour 

averages 

computed from 

four or more 

data points 

equally spaced 

over each 1-hour 

period. 

Measure O2 concentration 

for the inlet air/oxygen 

supplied to the system, if 

using Equation 1 of 40 CFR 

60.102a(f)1)(i) to set your 

emission limit 

Data from 

continuous 

emission 

monitoring 

system 

Collect O2

monitoring data 

every 15 minutes 

for 24 

consecutive 

operating hours. 

Reduce the data 

to 1-hour 

averages 

computed from 

four or more 

data points 

equally spaced 

over each 1-hour 

period; and 

average over the 

24-hour period 

for input to 

Equation 1 of 40 

CFR 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

60.102a(f)(1)(i). 

2. Each new and existing sulfur 

recovery unit: Option 2 (TRS limit), 

using CEMS 

Measure the concentration 

of reduced sulfur (or SO2 if 

you use an instrument to 

convert the reduced sulfur 

to SO2) 

Data from 

continuous 

emission 

monitoring 

system. 

Collect TRS data 

every 15 minutes 

for 24 

consecutive 

operating hours. 

Reduce the data 

to 1-hour 

averages 

computed from 

four or more 

data points 

equally spaced 

over each 1-hour 

period. 

3. Each new and existing sulfur 

recovery unit: Option 2 (TRS limit), if 

using continuous parameter monitoring 

systems

a. Select sampling port's 

location and the number of 

traverse ports. 

Method 1 

or 1A in 

Appendix

A-1 to part 

60 of this 

chapter. 

Sampling sites 

must be located 

at the outlet of 

the control 

device and prior 

to any releases to 

the atmosphere. 

 b. Determine velocity and 

volumetric flow rate. 

Method 2, 

2A, 2C, 

2D, 2F, or 

2G in 

appendix 

A to part 

60 of this 

chapter, as 

applicable.

 c. Conduct gas molecular 

weight analysis; obtain the 

oxygen concentration 

needed to correct the 

emission rate for excess air.

Method 3, 

3A, or 3B 

in 

appendix 

A to part 

60 of this 

chapter, as 

applicable.

Take the 

samples 

simultaneously 

with reduced 

sulfur or 

moisture 

samples. 

 d. Measure moisture 

content of the stack gas. 

Method 4 

in 

appendix 

A to part 

60 of this 

Make your 

sampling time 

for each Method 

4 sample equal 

to that for 4 

Method 15 

Deleted: 2

Deleted: .

Deleted: appendix
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

chapter. samples. 

 e. Measure the 

concentration of TRS. 

Method 15 

or 15A in 

appendix 

A to part 

60 of this 

chapter, as 

applicable.

If the crosssectional area of 

the duct is less 

than 5 square 

meters (m2

) or 

54 square feet, 

you must use the 

centroid of the 

cross section as 

the sampling 

point. If the 

cross-sectional 

area is 5 m2

 or 

more and the 

centroid is more 

than 1 meter (m) 

from the wall, 

your sampling 

point may be at a 

point no closer 

to the walls than 

1 m or 39 inches. 

Your sampling 

rate must be at 

least 3 liters per 

minute or 0.10 

cubic feet per 

minute to ensure 

minimum 

residence time 

for the sample 

inside the 

sample lines. 

 f. Calculate the SO2

equivalent for each run 

after correcting for 

moisture and oxygen. 

The 

arithmetic 

average of 

the SO2

equivalent 

for each 

sample 

during the 

run. 

 g. Correct the reduced 

sulfur samples to zero 

Equation 1 

of 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

percent excess air. §63.1568. 

 h. Establish each operating 

limit in Table 30 of this 

subpart that applies to you. 

Data from 

the 

continuous 

parameter 

monitoring 

system. 

 i. Measure thermal 

incinerator: combustion 

zone temperature. 

Data from 

the 

continuous 

parameter 

monitoring 

system. 

Collect 

temperature 

monitoring data 

every 15 minutes 

during the entire 

period of the 

performance 

test; and 

determine and 

record the 

minimum hourly 

average 

temperature 

from all the 

readings. 

 j. Measure thermal 

incinerator: oxygen 

concentration (percent, dry 

basis) in the vent stream. 

Data from 

the 

continuous 

parameter 

monitoring 

system. 

Collect oxygen 

concentration 

(percent, dry 

basis) data every 

15 minutes 

during the entire 

period of the 

performance 

test; and 

determine and 

record the 

minimum hourly 

average percent 

excess oxygen 

concentration. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Table 33 to Subpart UUU of Part 63—Initial Compliance With HAP Emission Limits for 

Sulfur Recovery Units 

As stated in §63.1568(b)(5), you shall meet each requirement in the following table that applies 

to you. 

Deleted: sa

Deleted: ¶

k. If you use a continuous emission monitoring 

system, measure TRS concentration. ... [4]
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

For . . . 

For the following emission 

limit . . . 

You have demonstrated initial 

compliance if . . . 

1. Each new or existing 

Claus sulfur recovery unit 

part of a sulfur recovery 

plant with design capacity 

greater than 20 long tons 

per day and subject to the 

NSPS for sulfur oxides in 

40 CFR 60.104(a)(2) or in 

40 CFR 60.102a(f)(1). 

a. 250 ppmv (dry basis) SO2

at zero percent excess air, or 

concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an 

oxidation or reduction control 

system followed by 

incineration 

You have already conducted a 

performance test to demonstrate 

initial compliance with the NSPS 

and each 12-hour rolling average 

concentration of SO2 emissions 

measured by the continuous 

emission monitoring system is less 

than or equal to 250 ppmv (dry 

basis) at zero percent excess air, or 

the concentration determined using 

Equation 1 of 40 CFR 

60.102a(f)(1)(i). As part of the 

Notification of Compliance Status, 

you must certify that your vent 

meets the SO2 limit. You are not 

required to do another performance 

test to demonstrate initial 

compliance. You have already 

conducted a performance 

evaluation to demonstrate initial 

compliance with the applicable 

performance specification. As part 

of your Notification of Compliance 

Status, you must certify that your 

continuous emission monitoring 

system meets the applicable 

requirements in §63.1572. You are 

not required to do another 

performance evaluation to 

demonstrate initial compliance. 

Deleted: of

Deleted: or more 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. 300 ppmv of reduced sulfur 

compounds calculated as 

ppmv SO2 (dry basis) at zero 

percent excess air, or 

concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use a 

reduction control system 

without incineration 

You have already conducted a 

performance test to demonstrate 

initial compliance with the NSPS 

and each 12-hour rolling average 

concentration of reduced sulfur 

compounds measured by your 

continuous emission monitoring 

system is less than or equal to 300 

ppmv, calculated as ppmv SO2 (dry 

basis) at zero percent excess air, or 

the concentration determined using 

Equation 1 of 40 CFR 

60.102a(f)(1)(i). As part of the 

Notification of Compliance Status, 

you must certify that your vent 

meets the SO2 limit. You are not 

required to do another performance 

test to demonstrate initial 

compliance. You have already 

conducted a performance 

evaluation to demonstrate initial 

compliance with the applicable 

performance specification. As part 

of your Notification of Compliance 

Status, you must certify that your 

continuous emission monitoring 

system meets the applicable 

requirements in §63.1572. You are 

not required to do another 

performance evaluation to 

demonstrate initial compliance. 

2. Option 1: Elect NSPS. 

Each new or existing sulfur 

recovery unit (Claus or 

other type, regardless of 

size) not subject to the 

NSPS for sulfur oxides in 

40 CFR 60.104(a)(2) or in 

40 CFR 60.102a(f)(1).

a. 250 ppmv (dry basis) of 

SO2 at zero percent excess air, 

or concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an 

oxidation or reduction control 

system followed by 

incineration 

Each 12-hour rolling average 

concentration of SO2 emissions 

measured by the continuous 

emission monitoring system during 

the initial performance test is less 

than or equal to 250 ppmv (dry 

basis) at zero percent excess air, or 

the concentration determined using 

Equation 1 of 40 CFR 

60.102a(f)(1)(i); and your 

performance evaluation shows the 

monitoring system meets the 

applicable requirements in 

§63.1572. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 b. 300 ppmv of reduced sulfur 

compounds calculated as 

ppmv SO2 (dry basis) at zero 

percent excess air, or 

concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use a 

reduction control system 

without incineration 

Each 12-hour rolling average 

concentration of reduced sulfur 

compounds measured by the 

continuous emission monitoring 

system during the initial 

performance test is less than or 

equal to 300 ppmv, calculated as 

ppmv SO2 (dry basis) at zero 

percent excess air, or the 

concentration determined using 

Equation 1 of 40 CFR 

60.102a(f)(1)(i); and your 

performance evaluation shows the 

continuous emission monitoring 

system meets the applicable 

requirements in §63.1572. 

3. Option 2: TRS limit. 

Each new or existing sulfur 

recovery unit (Claus or 

other type, regardless of 

size) not subject to the 

NSPS for sulfur oxides in 

40 CFR 60.104(a)(2) or in 

40 CFR 60.102a(f)(1).

300 ppmv of TRS compounds 

expressed as an equivalent 

SO2 concentration (dry basis) 

at zero percent oxygen 

If you use continuous parameter 

monitoring systems, the average 

concentration of TRS emissions 

measured using Method 15 during 

the initial performance test is less 

than or equal to 300 ppmv 

expressed as equivalent SO2

concentration (dry basis) at zero 

percent oxygen. If you use a 

continuous emission monitoring 

system, each 12-hour rolling 

average concentration of TRS 

emissions measured by the 

continuous emission monitoring 

system during the initial 

performance test is less than or 

equal to 300 ppmv expressed as an 

equivalent SO2 (dry basis) at zero 

percent oxygen; and your 

performance evaluation shows the 

continuous emission monitoring 

system meets the applicable 

requirements in §63.1572. 

[70 FR 6962, Feb. 9, 2005] 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 34 to Subpart UUU of Part 63—Continuous Compliance With HAP Emission Limits 

for Sulfur Recovery Units 

As stated in §63.1568(c)(1), you shall meet each requirement in the following table that applies 

to you. 

For . . . For this emission limit . . . 

You shall demonstrate 

continuous compliance by . . . 

1. Each new or existing 

Claus sulfur recovery unit 

part of a sulfur recovery 

plant with design capacity 

greater than 20 long tons per 

day and subject to the NSPS 

for sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1). 

a. 250 ppmv (dry basis) of SO2

at zero percent excess air, or 

concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an 

oxidation or reduction control 

system followed by 

incineration. 

Collecting the hourly average SO2

monitoring data (dry basis, 

percent excess air) according to 

§63.1572; determining and 

recording each 12-hour rolling 

average concentration of SO2; 

maintaining each 12-hour rolling 

average concentration of SO2 at or 

below the applicable emission 

limitation; and reporting any 12-

hour rolling average concentration 

of SO2 greater than the applicable 

emission limitation in the 

semiannual compliance report 

required by §63.1575. 

 b. 300 ppmv of reduced sulfur 

compounds calculated as 

ppmv SO2 (dry basis) at zero 

percent excess air, or 

concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use a 

reduction control system 

without incineration. 

Collecting the hourly average 

reduced sulfur (and air or O2

dilution and oxidation) monitoring 

data according to §63.1572; 

determining and recording each 

12-hour rolling average 

concentration of reduced sulfur; 

maintaining each 12-hour rolling 

average concentration of reduced 

sulfur at or below the applicable 

emission limitation; and reporting 

any 12-hour rolling average 

concentration of reduced sulfur 

greater than the applicable 

emission limitation in the 

semiannual compliance report 

required by §63.1575. 

2. Option 1: Elect NSPS. 

Each new or existing sulfur 

recovery unit (Claus or other 

type, regardless of size) not 

subject to the NSPS for 

a. 250 ppmv (dry basis) of SO2

at zero percent excess air, or 

concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an 

Collecting the hourly average SO2

data (dry basis, percent excess air) 

according to §63.1572; 

determining and recording each 

12-hour rolling average 

Deleted: of

Deleted: or more 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1). 

oxidation or reduction control 

system followed by 

incineration. 

concentration of SO2; maintaining 

each 12-hour rolling average 

concentration of SO2 at or below 

the applicable emission limitation; 

and reporting any 12-hour rolling 

average concentration of SO2

greater than the applicable 

emission limitation in the 

semiannual compliance report 

required by §63.1575. 

 b. 300 ppmv of reduced sulfur 

compounds calculated as 

ppmv SO2 (dry basis) at zero 

percent excess air, or 

concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use a 

reduction control system 

without incineration. 

Collecting the hourly average 

reduced sulfur (and air or O2

dilution and oxidation) monitoring 

data according to §63.1572; 

determining and recording each 

12-hour rolling average 

concentration of reduced sulfur; 

maintaining each 12-hour rolling 

average concentration of reduced 

sulfur at or below the applicable 

emission limitation; and reporting 

any 12-hour rolling average 

concentration of reduced sulfur 

greater than the applicable 

emission limitation in the 

semiannual compliance report 

required by §63.1575. 

3. Option 2: TRS limit. Each 

new or existing sulfur 

recovery unit (Claus or other 

type, regardless of size) not 

subject to the NSPS for 

sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1). 

300 ppmv of TRS compounds, 

expressed as an SO2

concentration (dry basis) at 

zero percent oxygen or 

reduced sulfur compounds 

calculated as ppmv SO2 (dry 

basis) at zero percent excess 

air. 

i. If you use continuous parameter 

monitoring systems, collecting the 

hourly average TRS monitoring 

data according to §63.1572 and 

maintaining each 12-hour average 

concentration of TRS at or below 

the applicable emission limitation; 

or 

 ii. If you use a continuous 

emission monitoring system, 

collecting the hourly average TRS 

monitoring data according to 

§63.1572, determining and 

recording each 12-hour rolling 

average concentration of TRS; 

maintaining each 12-hour rolling 

average concentration of TRS at 

or below the applicable emission 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

limitation; and reporting any 12-

hour rolling average TRS 

concentration greater than the 

applicable emission limitation in 

the semiannual compliance report 

required by §63.1575. 

[70 FR 6963, Feb. 9, 2005] 

Table 35 to Subpart UUU of Part 63—Continuous Compliance With Operating Limits for 

HAP Emissions From Sulfur Recovery Units 

As stated in §63.1568(c)(1), you shall meet each requirement in the following table that applies 

to you. 

For . . . 

For this operating limit . 

. . 

You shall demonstrate 

continuous compliance by . . . 

1. Each new or existing Claus 

sulfur recovery unit part of a sulfur 

recovery plant with design capacity 

greater than 20 long tons per day 

and subject to the NSPS for sulfur 

oxides in paragraph 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1). 

Not applicable Meeting the requirements of 

Table 34 of this subpart. 

2. Option 1: Elect NSPS Each new 

or existing sulfur recovery unit 

(Claus or other type, regardless of 

size) not subject to the NSPS for 

sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1).

Not applicable Meeting the requirements of 

Table 34 of this subpart. 

3. Option 2: TRS limit Each new or 

existing sulfur recovery unit (Claus 

or other type, regardless of size) not 

subject to the NSPS for sulfur 

oxides in 40 CFR 60.104(a)(2) or in 

40 CFR 60.102a(f)(1).

a. Maintain the daily 

average combustion zone 

temperature above the 

level established during 

the performance test. 

Collecting the hourly and daily 

average temperature monitoring 

data according to §63.1572; and 

maintaining the daily average 

combustion zone temperature at 

or above the limit established 

during the performance test. 

 b. The daily average 

oxygen concentration in 

the vent stream (percent, 

dry basis) must not fall 

below the level 

Collecting the hourly and daily 

average O2 monitoring data 

according to §63.1572; and 

maintaining the average O2

concentration above the level 

Deleted: of

Deleted: or more 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

established during the 

performance test. 

established during the 

performance test. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Table 36 to Subpart UUU of Part 63—Work Practice Standards for HAP Emissions From 

Bypass Lines 

As stated in §63.1569(a)(1), you shall meet each work practice standard in the following table 

that applies to you. 

Option You shall meet one of these equipment standards . . . 

1. Option 

1 

Install and operate a device (including a flow indicator, level recorder, or electronic 

valve position monitor) to demonstrate, either continuously or at least every hour, 

whether flow is present in the by bypass line. Install the device at or as near as 

practical to the entrance to any bypass line that could divert the vent stream away 

from the control device to the atmosphere. 

2. Option 

2 

Install a car-seal or lock-and-key device placed on the mechanism by which the 

bypass device flow position is controlled (e.g., valve handle, damper level) when the 

bypass device is in the closed position such that the bypass line valve cannot be 

opened without breaking the seal or removing the device. 

3. Option 

3 

Seal the bypass line by installing a solid blind between piping flanges. 

4. Option 

4 

Vent the bypass line to a control device that meets the appropriate requirements in 

this subpart. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6964, Feb. 9, 2005] 

Table 37 to Subpart UUU of Part 63—Requirements for Performance Tests for Bypass 

Lines 

As stated in §63.1569(b)(1), you shall meet each requirement in the following table that applies 

to you. 

For this standard . . . You shall . . . 

1. Option 1: Install and 

operate a flow indicator, 

level recorder, or electronic 

valve position monitor. 

Record during the performance test for each type of control device 

whether the flow indicator, level recorder, or electronic valve 

position monitor was operating and whether flow was detected at 

any time during each hour of level the three runs comprising the 

performance test. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 38 to Subpart UUU of Part 63—Initial Compliance With Work Practice Standards 

for HAP Emissions From Bypass Lines 

As stated in §63.1569(b)(2), you shall meet each requirement in the following table that applies 

to you. 

Option . . . For this work practice standard . . . 

You have demonstrated 

initial compliance if . . . 

1. Each new or 

existing bypass line 

associated with a 

catalytic cracking 

unit, catalytic 

reforming unit, or 

sulfur recovery unit 

a. Option 1: Install and operate a device 

(including a flow indicator, level recorder, 

or electronic valve position monitor) to 

demonstrate, either continuously or at 

least every hour, whether flow is present 

in bypass line. Install the device at or as 

near as practical to the entrance to any 

bypass line that could divert the vent 

stream away from the control device to 

the atmosphere 

The installed equipment 

operates properly during each 

run of the performance test and 

no flow is present in the line 

during the test. 

 b. Option 2: Install a car-seal or lock-andkey device placed on the mechanism by 

which the bypass device flow position is 

controlled (e.g., valve handle, damper 

level) when the bypass device is in the 

closed position such that the bypass line 

valve cannot be opened without breaking 

the seal or removing the device 

As part of the notification of 

compliance status, you certify 

that you installed the 

equipment, the equipment was 

operational by your compliance 

date, and you identify what 

equipment was installed. 

 c. Option 3: Seal the bypass line by 

installing a solid blind between piping 

flanges 

See item 1.b of this table. 

 d. Option 4: Vent the bypass line to a 

control device that meets the appropriate 

requirements in this subpart 

See item 1.b of this table. 

[70 FR 6965, Feb. 9, 2005] 

Table 39 to Subpart UUU of Part 63—Continuous Compliance With Work Practice 

Standards for HAP Emissions From Bypass Lines 

As stated in §63.1569(c)(1), you shall meet each requirement in the following table that applies 

to you. 

If you elect this 

standard . . . You shall demonstrate continuous compliance by . . . 

1. Option 1: Flow Monitoring and recording on a continuous basis or at least every hour 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

indicator, level 

recorder, or electronic 

valve position 

monitor. 

whether flow is present in the bypass line; visually inspecting the device 

at least once every hour if the device is not equipped with a recording 

system that provides a continuous record; and recording whether the 

device is operating properly and whether flow is present in the bypass 

line. 

2. Option 2: Car-seal 

or lock-and-key device 

Visually inspecting the seal or closure mechanism at least once every 

month; and recording whether the bypass line valve is maintained in the 

closed position and whether flow is present in the line. 

3. Option 3: Solid 

blind flange 

Visually inspecting the blind at least once a month; and recording 

whether the blind is maintained in the correct position such that the vent 

stream cannot be diverted through the bypass line. 

4. Option 4: Vent to 

control device 

Monitoring the control device according to appropriate subpart 

requirements. 

5. Option 1, 2, 3, or 4 Recording and reporting the time and duration of any bypass. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6965, Feb. 9, 2005] 

Table 40 to Subpart UUU of Part 63—Requirements for Installation, Operation, and 

Maintenance of Continuous Opacity Monitoring Systems and Continuous Emission 

Monitoring Systems 

As stated in §63.1572(a)(1) and (b)(1), you shall meet each requirement in the following table 

that applies to you. 

This type of continuous opacity or 

emission monitoring system . . . Must meet these requirements . . . 

1. Continuous opacity monitoring system Performance specification 1 (40 CFR part 60, 

appendix B). 

2. PM CEMS; this monitor must include 

an O2 monitor for correcting the data for 

excess air. 

The requirements in 40 CFR 60.105a(d). 

3. CO2, O2, and CO monitors for coke 

burn-off rate 

The requirements in 40 CFR 60.105a(b)(2). 

4. CO continuous emission monitoring 

system 

Performance specification 4 (40 CFR part 60, 

appendix B); span value of 1,000 ppm; and procedure 

1 (40 CFR part 60, appendix F) except relative 

accuracy test audits are required annually instead of 

quarterly. 

5. CO continuous emission monitoring 

system used to demonstrate emissions 

average under 50 ppm (dry basis). 

Performance specification 4 (40 CFR part 60, 

appendix B); and span value of 100 ppm. 

6. SO2 continuous emission monitoring Performance specification 2 (40 CFR part 60, 

Deleted: 2

Deleted: 3

Deleted: 4
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

system for sulfur recovery unit with 

oxidation control system or reduction 

control system; this monitor must include 

an O2 monitor for correcting the data for 

excess air. 

Appendix B); span value of 500 ppm SO2, or if using 

Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of 

two times the limit at the highest O2 concentration; 

use Methods 6 or 6C (40 CFR part 60, Appendix A4) for certifying the SO2 monitor and Methods 3A or 

3B (40 CFR part 60, Appendix A-2) for certifying the 

O2 monitor; and procedure 1 (40 CFR part 60, 

Appendix F) except relative accuracy test audits are 

required annually instead of quarterly. 

7. Reduced sulfur and O2 continuous 

emission monitoring system for sulfur 

recovery unit with reduction control 

system not followed by incineration; this 

monitor must include an O2 monitor for 

correcting the data for excess air unless 

exempted. 

Performance specification 5 (40 CFR part 60, 

Appendix B), except calibration drift specification is 

2.5 percent of the span value instead of 5 percent; 

span value is 450 ppm reduced sulfur, or if using 

Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of 

two times the limit at the highest O2 concentration; 

use Methods 15 or 15A (40 CFR part 60, Appendix 

A-5) for certifying the reduced sulfur monitor and 

Methods 3A or 3B (40 CFR part 60, Appendix A-2) 

for certifying the O2 monitor; if Method 3A or 3B 

yields O2 concentrations below 0.25 percent during 

the performance evaluation, the O2 concentration can 

be assumed to be zero and the O2 monitor is not 

required; and procedure 1 (40 CFR part 60, Appendix 

F), except relative accuracy test audits, are required 

annually instead of quarterly. 

8. Instrument with an air or O2 dilution 

and oxidation system to convert reduced 

sulfur to SO2 for continuously monitoring 

the concentration of SO2 instead of 

reduced sulfur monitor and O2 monitor. 

Performance specification 5 (40 CFR part 60, 

Appendix B); span value of 375 ppm SO2 or if using 

Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of 

two times the limit at the highest O2 concentration; 

use Methods 15 or 15A for certifying the reduced 

sulfur monitor and 3A or 3B for certifying the O2

monitor; and procedure 1 (40 CFR part 60, Appendix 

F), except relative accuracy test audits, are required 

annually instead of quarterly. 

9. TRS continuous emission monitoring 

system for sulfur recovery unit; this 

monitor must include an O2 monitor for 

correcting the data for excess air. 

Performance specification 5 (40 CFR part 60, 

appendix B). 

10. O2 monitor for oxygen concentration. If necessary due to interferences, locate the oxygen 

sensor prior to the introduction of any outside gas 

stream; performance specification 3 (40 CFR part 60, 

appendix B; and procedure 1 (40 CFR part 60, 

appendix F), except relative accuracy test audits, are 

required annually instead of quarterly. 

11. O2 monitor for oxygen concentration Install, operate, and maintain each O2 monitor 

Deleted: a

Deleted: a

Deleted: a

Deleted: 5

Deleted: a

Deleted: a

Deleted: O2monitor

Deleted: a

Deleted: 6

Deleted: a

Deleted: a

Deleted: 7

Deleted: 8
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

in inlet or supply. according to Performance Specification 3 of 

Appendix B to part 60; the span value for the O2

monitor must be selected between 20 and 100 

percent; conduct performance evaluations for O2

monitor according to Performance Specification 3 of 

Appendix B to part 60, and must use Method 3A or 

3B of Appendix A-2 to part 60 for conducting 

relative accuracy evaluations; comply with 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. 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, 6965, Feb. 9, 2005] 

Table 41 to Subpart UUU of Part 63—Requirements for Installation, Operation, and 

Maintenance of Continuous Parameter Monitoring Systems 

As stated in §63.1572(c)(1), you shall meet each requirement in the following table that applies 

to you. 

If you use . . . You shall . . . 

1. pH strips Use pH strips with an accuracy of ±10 percent. 

2. pH meter Locate the pH sensor in a position that provides a representative 

measurement of pH; ensure the sample is properly mixed and 

representative of the fluid to be measured. 

Use a pH sensor with an accuracy of at least ±0.2 pH units. 

Check the pH meter’s calibration on at least one point at least once 

daily; check the pH meter’s calibration on at least two points at 

least once quarterly; at least monthly, inspect all components for 

integrity and all electrical components for continuity; record the 

results of each calibration check and inspection. 

3. Colormetric tube 

sampling system 

Use a colormetric tube sampling system with a printed numerical scale 

in ppmv, a standard measurement range of 1 to 10 ppmv (or 1 to 30 

ppmv if applicable), and a standard deviation for measured values of 

no more than ±15 percent. System must include a gas detection pump 

and hot air probe if needed for the measurement range. 

4. BLD Follow the requirements in 40 CFR 60.105a(c). 

5. Voltage, secondary 

current, or total power 

input sensors 

Use meters with an accuracy of at least ± 5 percent over the operating 

range. 

Each time that the unit is not operating, confirm that the meters read 

zero. Conduct a calibration check at least annually; conduct 

calibration checks following any period of more than 24 hours 

Deleted: 2
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

throughout which the meter exceeds the manufacturer’s specified 

maximum operating range; at least monthly, inspect all 

components of the continuous parameter monitoring system for 

integrity and all electrical connections for continuity; and record 

the results of each calibration check and inspection. 

6. Pressure/Pressure drop 

1 sensors 

Locate the pressure sensor(s) in a position that provides a 

representative measurement of the pressure; minimizes or 

eliminates pulsating pressure, vibration, and internal and external 

corrosion. 

Use a gauge with an accuracy of at least ± 5 percent over the operating 

range or 0.5 inches of water column, whichever is greater. 

Check pressure tap for plugs at least once a week; using a manometer, 

check gauge calibration quarterly and transducer calibration 

monthly; conduct calibration checks following any period of more 

than 24 hours throughout which the sensor exceeds the 

manufacturer’s specified maximum operating pressure range or 

install a new pressure sensor; at least monthly, inspect all 

components for integrity, all electrical connections for continuity, 

and all mechanical connections for leakage; record the results of 

each calibration check and inspection. 

7. Air flow rate, gas flow 

rate, or total water (or 

scrubbing liquid) flow 

rate sensors 

Locate the flow sensor(s) and other necessary equipment (such as 

straightening vanes) in a position that provides representative 

flow; reduce swirling flow or abnormal velocity distributions due 

to upstream and downstream disturbances. If you elect to comply 

with Option 3 (Ni lb/hr) or Option 4 (Ni lb/1,000 lb of coke burnoff) for the HAP metal emission limitations in § 63.1564, install 

the continuous parameter monitoring system for gas flow rate as 

close as practical to the continuous opacity monitoring system; and 

if you don’t use a continuous opacity monitoring system, install 

the continuous parameter monitoring system for gas flow rate as 

close as practical to the control device. 

Use a flow rate sensor with an accuracy of at least ±5 percent, or 0.5 

gallons per minute for liquid flow, or 10 cubic feet per minute for 

gas flow, whichever is greater. 

Conduct a flow sensor calibration check at least semiannually; 

conduct calibration checks following any period of more than 24 

hours throughout which the sensor exceeds the manufacturer’s 

specified maximum operating range or install a new flow sensor; 

at least monthly, inspect all components for leakage; record the 

results of each calibration check and inspection. 

8. Temperature sensors Locate the temperature sensor in the combustion zone, or in the 

ductwork immediately downstream of the combustion zone before 

any substantial heat exchange occurs or in the ductwork 

immediately downstream of the regenerator; locate the 

temperature sensor in a position that provides a representative 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

temperature; shield the temperature sensor system from 

electromagnetic interference and chemical contaminants. 

Use a temperature sensor with an accuracy of at least ±1 percent of the 

temperature being measured, expressed in degrees Celsius (C) or 

2.8 degrees C, whichever is greater. 

Conduct calibration checks at least annually; conduct calibration 

checks following any period of more than 24 hours throughout 

which the sensor exceeds the manufacturer’s specified maximum 

operating temperature range, or install a new temperature sensor; 

at least monthly, inspect all components for integrity and all 

electrical connections for continuity, oxidation, and galvanic 

corrosion; record the results of each calibration check and 

inspection. 

9. Oxygen content 

sensors2

Locate the oxygen sensor so that it provides a representative 

measurement of the oxygen content of the exit gas stream; ensure 

the sample is properly mixed and representative of the gas to be 

measured. 

Use an oxygen sensor with an accuracy of at least ±1 percent of the 

range of the sensor. 

Conduct calibration checks at least quarterly; conduct calibration 

checks following any period of more than 24 hours throughout 

which the sensor exceeds the manufacturer’s specified maximum 

operating range, or install a new oxygen sensor; at least monthly, 

inspect all components for integrity and all electrical connections 

for continuity; record the results of each calibration and inspection. 

1

Not applicable to non-venturi wet scrubbers of the jet-ejector design. 

2

This does not replace the requirements for oxygen monitors that are required to use continuous 

emissions monitoring systems. These requirements apply to oxygen sensors that are continuous 

parameter monitors, such as those that monitor combustion zone oxygen concentration and 

regenerator exit oxygen concentration. 

[70 FR 6966, Feb. 9, 2005] 

Table 42 to Subpart UUU of Part 63—Additional Information for Initial Notification of 

Compliance Status 

As stated in §63.1574(d), you shall meet each requirement in the following table that applies to 

you. 

For . . . You shall provide this additional information . . . 

1. Identification of 

affected sources and 

Nature, size, design, method of operation, operating design capacity of 

each affected source; identify each emission point for each HAP; identify 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

emission points. any affected source or vent associated with an affected source not subject 

to the requirements of subpart UUU. 

2. Initial compliance Identification of each emission limitation you will meet for each affected 

source, including any option you select (i.e., NSPS, PM or Ni, flare, 

percent reduction, concentration, options for bypass lines); if applicable, 

certification that you have already conducted a performance test to 

demonstrate initial compliance with the NSPS for an affected source; 

certification that the vents meet the applicable emission limit and the 

continuous opacity or that the emission monitoring system meets the 

applicable performance specification; if applicable, certification that you 

have installed and verified the operational status of equipment by your 

compliance date for each bypass line that meets the requirements of 

Option 2, 3, or 4 in §63.1569 and what equipment you installed; 

identification of the operating limit for each affected source, including 

supporting documentation; if your affected source is subject to the NSPS, 

certification of compliance with NSPS emission limitations and 

performance specifications; a brief description of performance test 

conditions (capacity, feed quality, catalyst, etc.); an engineering 

assessment (if applicable); and if applicable, the flare design (e.g., steamassisted, air-assisted, or non-assisted), all visible emission readings, heat 

content determinations, flow rate measurements, and exit velocity 

determinations made during the Method 22 test. 

3. Continuous 

compliance 

Each monitoring option you elect; and identification of any unit or vent 

for which monitoring is not required; and the definition of “operating 

day.” (This definition, subject to approval by the applicable permitting 

authority, must specify the times at which a 24-hr operating day begins 

and ends.) 

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Table 43 to Subpart UUU of Part 63—Requirements for Reports 

As stated in §63.1575(a), you shall meet each requirement in the following table that applies to 

you. 

You must 

submit . . . The report must contain . . . 

You shall submit the 

report . . . 

1. A 

compliance

report 

If there are not deviations from any emission limitation 

or work practice standard that applies to you, a 

statement that there were no deviations from the 

standards during the reporting period and that no 

continuous opacity monitoring system or continuous 

emission monitoring system was inoperative, inactive, 

out-of-control, repaired, or adjusted; if you have a 

Semiannually according 

to the requirements in 

§63.1575(b). 

Deleted: a(n) . . 

Deleted: Compliance
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

deviation from any emission limitation or work 

practice standard during the reporting period, the report 

must contain the information in §63.1575(c) through 

(e).

2. 

Performance 

test and 

CEMS 

performance 

evaluation 

data

On and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER],

the information specified in §63.1575(k)(1).

Within 60 days after the 

date of completing each 

test according to the 

requirements in 

§63.1575(k).

[67 FR 17773, Apr. 11, 2002, as amended at 70 FR 6942, Feb. 9, 2005] 

Table 44 to Subpart UUU of Part 63—Applicability of NESHAP General Provisions to 

Subpart UUU 

As stated in §63.1577, you shall meet each requirement in the following table that applies to you. 

Citation Subject 

Applies to 

subpart 

UUU Explanation 

§63.1(a)(1)–(4) General Applicability Yes 

§63.1(a)(5) [Reserved] Not 

applicable

§63.1(a)(6) Yes Except the correct mail drop 

(MD) number is C404–04. 

§63.1(a)(7)–(9) [Reserved] Not 

applicable

§63.1(a)(10)–(12) Yes Except that subpart UUU 

specifies calendar or operating 

day. 

§63.1(b)(1) Initial Applicability 

Determination for this part 

Yes 

§63.1(b)(2) [Reserved] Not 

applicable

§63.1(b)(3) Yes 

§63.1(c)(1) Applicability of this part 

after a Relevant Standard has 

been set under this part 

Yes 

§63.1(c)(2) No Area sources are not subject to 

subpart UUU. 

Deleted: if you have a deviation from any 

emission limitation or work practice standard during 

the reporting period, the report must contain

Deleted: d) or (e)

Deleted: Applicability
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§63.1(c)(3)–(4) [Reserved] Not 

applicable

§63.1(c)(5) Yes 

§63.1(d) [Reserved] Not 

applicable

§63.1(e) Applicability of Permit 

Program 

Yes 

§63.2 Definitions Yes §63.1579 of subpart UUU 

specifies that if the same term is 

defined in subparts A and UUU, 

it shall have the meaning given 

in subpart UUU.

§63.3 Units and Abbreviations Yes 

§63.4(a)(1)–(2) Prohibited Activities Yes 

§63.4(a)(3)–(5) [Reserved] Not 

applicable

§63.4(b)–(c) Circumvention and 

Fragmentation 

Yes 

§63.5(a) Construction and 

Reconstruction

Yes 

§63.5(b)(1) Yes 

§63.5(b)(2) [Reserved] Not 

applicable

§63.5(b)(3)–(4) Yes In §63.5(b)(4), replace the 

reference to §63.9(b) with 

§63.9(b)(4) and (5). 

§63.5(b)(5) [Reserved] Not 

applicable

§63.5(b)(6) Yes 

§63.5(c) [Reserved] Not 

applicable

§63.5(d)(1)(i) Application for Approval of 

Construction or 

Reconstruction—General 

Application Requirements 

Yes Except subpart UUU specifies 

the application is submitted as 

soon as practicable before 

startup but not later than 90 days 

after the promulgation date if

construction or reconstruction 

had commenced and initial 

startup had not occurred before 

promulgation. 

Moved (insertion) [15]

Deleted: A)–(C

Moved up [15]: Construction and Reconstruction

Deleted: ,

Deleted: (rather then 60) 

Deleted: where
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§63.5(d)(1)(ii) Yes Except that emission estimates 

specified in §63.5(d)(1)(ii)(H) 

are not required, and 

§63.5(d)(1)(ii)(G) and (I) are 

Reserved and do not apply. 

§63.5(d)(1)(iii) No Subpart UUU specifies 

submission of notification of 

compliance status. 

§63.5(d)(2) Yes

§63.5(d)(3) Yes 

§63.5(d)(4) Yes 

§63.5(e) Approval of Construction or 

Reconstruction 

Yes 

§63.5(f)(1) Approval of Construction or 

Reconstruction Based on 

State Review 

Yes

§63.5(f)(2) Yes Except that the cross-reference 

to §63.9(b)(2) does not apply. 

§63.6(a) Compliance with Standards 

and Maintenance—

Applicability 

Yes 

§63.6(b)(1)–(4) Compliance Dates for New 

and Reconstructed Sources 

Yes 

§63.6(b)(5) Yes Except that subpart UUU 

specifies different compliance 

dates for sources. 

§63.6(b)(6) [Reserved] Not 

applicable

§63.6(b)(7) Compliance Dates for New 

and Reconstructed Area 

Sources That Become Major 

Yes 

§63.6(c)(1)–(2) Compliance Dates for 

Existing Sources 

Yes Except that subpart UUU 

specifies different compliance 

dates for sources subject to Tier 

II gasoline sulfur control 

requirements. 

§63.6(c)(3)–(4) [Reserved] Not 

applicable

§63.6(c)(5) Compliance Dates for 

Existing Area Sources That 

Become Major 

Yes 

Deleted: No

Deleted: Except that §63.5(d)(3)(ii) does not 

apply.

Deleted: 0

Deleted: 60 days is changed to 90 days and

Deleted: 53

Deleted: B
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§63.6(d) [Reserved] Not 

applicable

§63.6(e)(1)(i) General Duty to Minimize 

Emissions 

No See §63.1570(c) for general duty 

requirement. 

§63.6(e)(1)(ii) Requirement to Correct 

Malfunctions as Soon as 

Possible 

No 

§63.6(e)(1)(iii) Compliance with Standards

and Maintenance 

Requirements 

Yes 

§63.6(e)(2) [Reserved] Not 

Applicable

§63.6(e)(3)(i) Startup, Shutdown, and 

Malfunction Plan

Requirements

No

§63.6(e)(3)(ii) [Reserved] Not 

applicable

§63.6(e)(3)(iii)-(ix) No

§63.6(f)(1) SSM Exemption No

§63.6(f)(2)(i)–

(iii)(C) 

Compliance with Standards

and Maintenance 

Requirements

Yes 

§63.6(f)(2)(iii)(D) Yes

§63.6(f)(2)(iv)–(v) Yes 

§63.6(f)(3) Yes Except the cross-references to 

§63.6(f)(1) and §63.6(e)(1)(i) 

are changed to §63.1570(c).

§63.6(g) Alternative Standard Yes 

§63.6(h)(1) SSM Exemption for 

Opacity/VE Standards 

No

§63.6(h)(2)(i) Determining Compliance 

with Opacity/VE Standards 

No Subpart UUU specifies methods. 

§63.6(h)(2)(ii) [Reserved] Not 

applicable

§63.6(h)(2)(iii) Yes 

§63.6(h)(3) [Reserved] Not 

applicable

§63.6(h)(4) Notification of Opacity/VE Yes Applies to Method 22 tests. 

Deleted: )–(2

Deleted: Operation

Formatted Table

Deleted: )–(iii

Deleted: Yes

Deleted: iv

Deleted: Yes

Deleted: Except that reports of actions not 

consistent with plan are not required within 2 and 7 

days of action but rather must be included in next 

periodic report.

Deleted: v)–(viii

Deleted: Yes

Deleted: The owner or operator is only required to 

keep the latest version of the plan.

Deleted: e)(3)(ix

Deleted: Yes

Deleted: 1)–(

Deleted: Emission 

Deleted: No

Formatted Table

Formatted Table

Deleted: Yes
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Observation Date 

§63.6(h)(5) Conducting Opacity/VE 

Observations 

No 

§63.6(h)(6) Records of Conditions 

During Opacity/VE 

Observations 

Yes Applies to Method 22 

observations. 

§63.6(h)(7)(i) Report COM Monitoring 

Data from Performance Test 

Yes 

§63.6(h)(7)(ii) Using COM Instead of 

Method 9 

No 

§63.6(h)(7)(iii) Averaging Time for COM 

during Performance Test 

Yes 

§63.6(h)(7)(iv) COM Requirements Yes 

§63.6(h)(7)(v) COMS Results and Visual 

Observations 

Yes 

§63.6(h)(8) Determining Compliance 

with Opacity/VE Standards 

Yes 

§63.6(h)(9) Adjusted Opacity Standard Yes 

§63.6(i)(1)–(14) Extension of Compliance Yes Extension of compliance under 

§63.6(i)(4) not applicable to a 

facility that installs catalytic 

cracking feed hydrotreating and 

receives an extended compliance 

date under §63.1563(c). 

§63.6(i)(15) [Reserved] Not 

applicable

§63.6(i)(16) Yes 

§63.6(j) Presidential Compliance 

Exemption 

Yes 

§63.7(a)(1) Performance Test 

Requirements Applicability 

Yes Except that subpart UUU 

specifies the applicable test and 

demonstration procedures. 

§63.7(a)(2) Performance Test Dates Yes Except test results must be 

submitted in the Notification of 

Compliance Status report due 

150 days after the compliance 

date. 

§63.7(a)(3) Section 114 Authority Yes 

§63.7(a)(4) Force Majeure Yes 

§63.7(b) Notifications Yes Except that subpart UUU 

Deleted: No

Deleted: Test
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

specifies notification at least 30 

days prior to the scheduled test 

date rather than 60 days. 

§63.7(c) Quality Assurance 

Program/Site-Specific Test 

Plan 

Yes 

§63.7(d) Performance Test Facilities Yes 

§63.7(e)(1) Performance Testing No See §63.1571(b)(1). 

§63.7(e)(2)–(4) Conduct of Tests Yes 

§63.7(f) Alternative Test Method Yes 

§63.7(g) Data Analysis, 

Recordkeeping, Reporting 

Yes Except performance test reports 

must be submitted with 

notification of compliance status 

due 150 days after the 

compliance date, and 

§63.7(g)(2) is Reserved and does 

not apply. 

§63.7(h) Waiver of Tests Yes 

§63.8(a)(1) Monitoring RequirementsApplicability Yes 

§63.8(a)(2) Performance Specifications Yes 

§63.8(a)(3) [Reserved] Not 

applicable

§63.8(a)(4) Monitoring with Flares Yes Except that for a flare complying 

with §63.670, the crossreference to §63.11 in this 

paragraph does not include 

§63.11(b).

§63.8(b)(1) Conduct of Monitoring Yes 

§63.8(b)(2)–(3) Multiple Effluents and 

Multiple Monitoring Systems

Yes Subpart UUU specifies the 

required monitoring locations. 

§63.8(c)(1) Monitoring System 

Operation and Maintenance 

Yes 

§63.8(c)(1)(i) General Duty to Minimize 

Emissions and CMS 

Operation

No See §63.1570(c).

§63.8(c)(1)(ii) Keep Necessary Parts for 

CMS 

Yes 

§63.8(c)(1)(iii) Requirement to Develop 

SSM Plan for CMS 

No

Deleted: )–(ii

Deleted: Startup, Shutdown, and Malfunctions

Deleted: Yes

Deleted: Except that subpart UUU specifies that 

reports are not required if actions are consistent with 

the SSM plan, unless requested by the permitting 

authority. If actions are not consistent, actions must 

be described in next compliance report.

Deleted: Compliance with Operation and 

Maintenance Requirements

Deleted: Yes
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§63.8(c)(2)–(3) Monitoring System 

Installation 

Yes Except that subpart UUU 

specifies that for continuous 

parameter monitoring systems, 

operational status verification 

includes completion of 

manufacturer written 

specifications or installation, 

operation, and calibration of the 

system or other written 

procedures that provide adequate 

assurance that the equipment 

will monitor accurately. 

§63.8(c)(4) Continuous Monitoring 

System Requirements 

Yes

§63.8(c)(5) COMS Minimum Procedures Yes 

§63.8(c)(6) CMS Requirements Yes

§63.8(c)(7)–(8) CMS Requirements Yes 

§63.8(d)(1)–(2) Quality Control Program for 

CMS

Yes 

§63.8(d)(3) Written Procedures for CMS No 

§63.8(e) CMS Performance 

Evaluation 

Yes Except that results are to be 

submitted as part of the 

Notification Compliance Status 

due 150 days after the 

compliance date. 

§63.8(f)(1)–(5) Alternative Monitoring 

Methods 

Yes Except that subpart UUU 

specifies procedures for 

requesting alternative 

monitoring systems and 

alternative parameters. 

§63.8(f)(6) Alternative to Relative 

Accuracy Test 

Yes Applicable to continuous 

emission monitoring systems if 

performance specification 

requires a relative accuracy test 

audit. 

§63.8(g)(1)–(4) Reduction of Monitoring 

Data 

Yes Applies to continuous opacity 

monitoring system or continuous 

emission monitoring system. 

§63.8(g)(5) Data Reduction No Subpart UUU specifies 

requirements. 

§63.9(a) Notification Requirements— Yes Duplicate Notification of 

Deleted: No

Deleted: Subpart UUU specifies operational 

requirements.

Deleted: §63.8(c)(4)(i)–(ii)

Deleted: Continuous Monitoring System 

Requirements

Deleted: Yes

Deleted: Except that these requirements apply only 

to a continuous opacity monitoring system or a 

continuous emission monitoring system if you are 

subject to the NSPS or elect to comply with the 

NSPS opacity, CO, or SO2 limits.

Deleted: No

Deleted: Except that these requirements apply only 

to a continuous opacity monitoring system or 

continuous emission monitoring system if you are 

subject to the NSPS or elect to comply with the 

NSPS opacity, CO, or SO2 limits.

Formatted Table

Deleted: Except that these requirements apply only 

to a continuous opacity monitoring system or 

continuous emission monitoring system if you are 

subject to the NSPS or elect to comply with the 

NSPS opacity, CO, or SO2 limits.

Formatted Table

Deleted: Except that these requirements apply only 

to a continuous opacity monitoring system or 

continuous emission monitoring system if you are 

subject to the NSPS or elect to comply with the 

NSPS opacity, CO, or SO2 limits. Results
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Applicability Compliance Status report to the 

Regional Administrator may be 

required. 

§63.9(b)(1)–(2) Initial Notifications Yes Except that notification of 

construction or reconstruction is 

to be submitted as soon as 

practicable before startup but no 

later than 30 days after the 

effective date if construction or 

reconstruction had commenced 

but startup had not occurred 

before the effective date. 

§63.9(b)(3) [Reserved] Not 

applicable

§63.9(b)(4)–(5) Initial Notification 

Information 

Yes Except §63.9(b)(4)(ii)-(iv), 

which are Reserved and do not 

apply. 

§63.9(c) Request for Extension of 

Compliance 

Yes 

§63.9(d) New Source Notification for 

Special Compliance 

Requirements 

Yes 

§63.9(e) Notification of Performance 

Test 

Yes Except that notification is 

required at least 30 days before 

test. 

§63.9(f) Notification of VE/Opacity 

Test 

Yes 

§63.9(g) Additional Notification 

Requirements for Sources 

with Continuous Monitoring 

Systems 

Yes 

§63.9(h) Notification of Compliance 

Status 

Yes Except that subpart UUU 

specifies the notification is due 

no later than 150 days after 

compliance date, and except that 

the reference to 

§63.5(d)(1)(ii)(H) in §63.9(h)(5) 

does not apply. 

§63.9(i) Adjustment of Deadlines Yes 

§63.9(j) Change in Previous 

Information 

Yes 

63.10(a) Recordkeeping and Yes 

Formatted Table

Deleted: ), (4)–(5

Deleted: (rather than 60 days) 

Deleted: Except that these requirements apply only 

to a continuous opacity monitoring system or 

continuous emission monitoring system if you are 

subject to the NSPS or elect to comply with the 

NSPS opacity, CO, or SO2 limits.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reporting Applicability 

§63.10(b)(1) General Recordkeeping 

Requirements 

Yes 

§63.10(b)(2)(i) Recordkeeping of 

Occurrence and Duration of 

Startups and Shutdowns 

No 

§63.10(b)(2)(ii) Recordkeeping of 

Malfunctions

No See §63.1576(a)(2) for 

recordkeeping of (1) date, time 

and duration; (2) listing of 

affected source or equipment, 

and an estimate of the volume of 

each regulated pollutant emitted 

over the standard; and (3) 

actions taken to minimize 

emissions and correct the failure.

§63.10(b)(2)(iii) Maintenance Records Yes 

§63.10(b)(2)(iv)–

(v) 

Actions Taken to Minimize 

Emissions During SSM 

No 

§63.10(b)(2)(vi) Recordkeeping for CMS 

Malfunctions 

Yes 

§63.10(b)(2)(vii)–

(xiv) 

Other CMS Requirements Yes 

§63.10(b)(3) Recordkeeping for 

Applicability 

Determinations. 

Yes 

§63.10(c)(1)–(6) Additional Records for 

Continuous Monitoring 

Systems 

Yes Except §63.10(c)(2)-(4), which 

are Reserved and do not apply.

§63.10(c)(7)–(8) Additional Recordkeeping 

Requirements for CMS – 

Identifying Exceedances and 

Excess Emissions 

Yes

§63.10(c)(9) [Reserved] Not 

applicable

 §63.10(c)(10) Recording Nature and Cause 

of Malfunctions 

No See §63.1576(a)(2) for 

malfunctions recordkeeping 

requirements. 

§63.10(c)(11) Recording Corrective 

Actions 

No See §63.1576(a)(2) for 

malfunctions recordkeeping 

requirements. 

§63.10(c)(12)–(14) Additional CMS Yes 

Deleted: Records

Deleted: Yes

Deleted: Except that §63.10(b)(2)(xiii) applies if 

you use a continuous emission monitoring system to 

meet the NSPS or you select to meet the NSPS, CO, 

or SO2 reduced sulfur limit and the performance 

evaluation requires a relative accuracy test audit.

Deleted: ), (9)–(15

Deleted: Except that these requirements apply if 

you use a continuous opacity monitoring system or a 

continuous emission monitoring system to meet the 

NSPS or elect to meet the NSPS opacity, CO, or SO2

limits.

Deleted: Records of 

Deleted: and Exceedances

Deleted: No

Deleted: Subpart UUU specifies requirements.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Recordkeeping Requirements

§63.10(c)(15) Use of SSM Plan No 

§63.10(d)(1) General Reporting 

Requirements 

Yes 

§63.10(d)(2) Performance Test Results No Subpart UUU requires 

performance test results to be 

reported as part of the 

Notification of Compliance 

Status due 150 days after the 

compliance date. 

§63.10(d)(3) Opacity or VE Observations Yes 

§63.10(d)(4) Progress Reports Yes 

§63.10(d)(5) SSM Reports No See §63.1575(d) for CPMS 

malfunction reporting and 

§63.1575(e) for COMS and 

CEMS malfunction reporting.

§63.10(e)(1)–(2) Additional CMS Reports Yes Except that reports of 

performance evaluations must be 

submitted in Notification of 

Compliance Status. 

§63.10(e)(3) Excess Emissions/CMS 

Performance Reports 

No Subpart UUU specifies the 

applicable requirements. 

§63.10(e)(4) COMS Data Reports Yes 

§63.10(f) Recordkeeping/Reporting 

Waiver 

Yes 

§63.11(a) Control Device and Work 

Practice Requirements

Applicability

Yes 

§63.11(b) Flares Yes Except that flares complying 

with §63.670 are not subject to 

the requirements of §63.11(b). 

§63.11(c)-(e) Alternative Work Practice 

for Monitoring Equipment 

for Leaks 

Yes 

§63.12 State Authority and 

Delegations 

Yes 

§63.13 Addresses Yes 

§63.14 Incorporation by Reference Yes 

§63.15 Availability of Information Yes 

Deleted: §63.10(d)(5)(i)

Deleted: Startup, Shutdown, and Malfunction 

Reports

Deleted: Yes

Deleted: Except that reports are not required if 

actions are consistent with the SSM plan, unless 

requested by permitting authority.

Deleted: )(ii

Deleted: Yes

Deleted: Except that actions taken during a startup, 

shutdown, or malfunction that are not consistent with 

the plan do not need to be reported within 2 and 7 

days of commencing and completing the action, 

respectively, but must be included in the next 

periodic report.

Deleted: these requirements apply only to a 

continuous opacity monitoring system or continuous 

emission monitoring system if you are subject to the 

NSPS or elect to comply with the NSPS opacity, CO, 

or SO2 limits. Reports

Deleted: Applicable to flares.

Deleted: e
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

and Confidentiality

§63.16 Performance Track 

Provisions 

Yes 

[70 FR 6966, Feb. 9, 2005, as amended at 71 FR 20462, Apr. 20, 2006] 

Appendix A to Subpart UUU of Part 63—Determination of Metal Concentration on 

Catalyst Particles (Instrumental Analyzer Procedure) 

1.0 Scope and Application. 

1.1 Analytes. The analytes for which this method is applicable include any elements with an 

atomic number between 11 (sodium) and 92 (uranium), inclusive. Specific analytes for which 

this method was developed include: 

Analyte CAS No. Minimum detectable limit 

Nickel compounds 7440–02–0 <2 % of span. 

Total chlorides 16887–00–6 <2 % of span. 

1.2 Applicability. This method is applicable to the determination of analyte concentrations on 

catalyst particles. This method is applicable for catalyst particles obtained from the fluid catalytic 

cracking unit (FCCU) regenerator (i.e., equilibrium catalyst), from air pollution control systems 

operated for the FCCU catalyst regenerator vent (FCCU fines), from catalytic reforming units 

(CRU), and other processes as specified within an applicable regulation. This method is 

applicable only when specified within the regulation. 

1.3 Data Quality Objectives. Adherence to the requirements of this method will enhance the 

quality of the data obtained from the analytical method. 

2.0 Summary of Method. 

2.1 A representative sample of catalyst particles is collected, prepared, and analyzed for analyte 

concentration using either energy or wavelength dispersive X-ray fluorescent (XRF) 

spectrometry instrumental analyzers. In both types of XRF spectrometers, the instrument 

irradiates the sample with high energy (primary) x-rays and the elements in the sample absorb 

the x-rays and then re-emit secondary (fluorescent) x-rays of characteristic wavelengths for each 

element present. In energy dispersive XRF spectrometers, all secondary x-rays (of all 

wavelengths) enter the detector at once. The detector registers an electric current having a height 

proportional to the photon energy, and these pulses are then separated electronically, using a 

pulse analyzer. In wavelength dispersive XRF spectrometers, the secondary x-rays are dispersed 

spatially by crystal diffraction on the basis of wavelength. The crystal and detector are made to 

synchronously rotate and the detector then receives only one wavelength at a time. The intensity 

of the x-rays emitted by each element is proportional to its concentration, after correcting for 

matrix effects. For nickel compounds and total chlorides, the XRF instrument response is 

Deleted: o
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

expected to be linear to analyte concentration. Performance specifications and test procedures are 

provided to ensure reliable data. 

3.0 Definitions. 

3.1 Measurement System. The total equipment required for the determination of analyte 

concentration. The measurement system consists of the following major subsystems: 

3.1.1 Sample Preparation. That portion of a system used for one or more of the following: 

sample acquisition, sample transport, sample conditioning, or sample preparation prior to 

introducing the sample into the analyzer. 

3.1.2 Analyzer. That portion of the system that senses the analyte to be measured and generates 

an output proportional to its concentration. 

3.1.3 Data Recorder. A digital recorder or personal computer used for recording measurement 

data from the analyzer output. 

3.2 Span. The upper limit of the gas concentration measurement range displayed on the data 

recorder. 

3.3 Calibration Standards. Prepared catalyst samples or other samples of known analyte 

concentrations used to calibrate the analyzer and to assess calibration drift. 

3.4 Energy Calibration Standard. Calibration standard, generally provided by the XRF 

instrument manufacturer, used for assuring accuracy of the energy scale. 

3.5 Accuracy Assessment Standard. Prepared catalyst sample or other sample of known analyte 

concentrations used to assess analyzer accuracy error. 

3.6 Zero Drift. The difference in the measurement system output reading from the initial value 

for zero concentration level calibration standard after a stated period of operation during which 

no unscheduled maintenance, repair, or adjustment took place. 

3.7 Calibration Drift. The difference in the measurement system output reading from the initial 

value for the mid-range calibration standard after a stated period of operation during which no 

unscheduled maintenance, repair, or adjustment took place. 

3.8 Spectral Interferences. Analytical interferences and excessive biases caused by elemental 

peak overlap, escape peak, and sum peak interferences between elements in the samples. 

3.9 Calibration Curve. A graph or other systematic method of establishing the relationship 

between the analyzer response and the actual analyte concentration introduced to the analyzer. 

3.10 Analyzer Accuracy Error. The difference in the measurement system output reading and the 

ideal value for the accuracy assessment standard. 

4.0 Interferences. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

4.1 Spectral interferences with analyte line intensity determination are accounted for within the 

method program. No action is required by the XRF operator once these interferences have been 

addressed within the method. 

4.2 The X-ray production efficiency is affected by particle size for the very lightest elements. 

However, particulate matter (PM) 2.5 particle size effects are substantially < 1 percent for most 

elements. The calibration standards should be prepared with material of similar particle size or 

be processed (ground) to produce material of similar particle size as the catalyst samples to be 

analyzed. No additional correction for particle size is performed. Alternatively, the sample can 

be fused in order to eliminate any potential particle size effects. 

5.0 Safety. 

5.1 Disclaimer. This method may involve hazardous materials, operations, and equipment. This 

test method may not address all of the safety problems associated with its use. It is the 

responsibility of the user of this test method to establish appropriate safety and health practices 

and determine the applicability of regulatory limitations prior to performing this test method. 

5.2 X-ray Exposure. The XRF uses X-rays; XRF operators should follow instrument 

manufacturer's guidelines to protect from accidental exposure to X-rays when the instrument is 

in operation. 

5.3 Beryllium Window. In most XRF units, a beryllium (Be) window is present to separate the 

sample chamber from the X-ray tube and detector. The window is very fragile and brittle. Do not 

allow sample or debris to fall onto the window, and avoid using compressed air to clean the 

window because it will cause the window to rupture. If the window should rupture, note that Be 

metal is poisonous. Use extreme caution when collecting pieces of Be and consult the instrument 

manufacturer for advice on cleanup of the broken window and replacement. 

6.0 Equipment and Supplies. 

6.1 Measurement System. Use any measurement system that meets the specifications of this 

method listed in section 13. The typical components of the measurement system are described 

below. 

6.1.1 Sample Mixer/Mill. Stainless steel, or equivalent to grind/mix catalyst and binders, if used, 

to produce uniform particle samples. 

6.1.2 Sample Press/Fluxer. Stainless steel, or equivalent to produce pellets of sufficient size to 

fill analyzer sample window, or alternatively, a fusion device capable of preparing a fused disk 

of sufficient size to fill analyzer sample window. 

6.1.3 Analytical Balance. ±0.0001 gram accuracy for weighing prepared samples (pellets). 

6.1.4 Analyzer. An XRF spectrometer to determine the analyte concentration in the prepared 

sample. The analyzer must meet the applicable performance specifications in section 13. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

6.1.5 Data Recorder. A digital recorder or personal computer for recording measurement data. 

The data recorder resolution (i.e., readability) must be 0.5 percent of span. Alternatively, a digital 

or analog meter having a resolution of 0.5 percent of span may be used to obtain the analyzer 

responses and the readings may be recorded manually. 

7.0 Reagents and Standards. 

7.1 Calibration Standards. The calibration standards for the analyzer must be prepared catalyst 

samples or other material of similar particle size and matrix as the catalyst samples to be tested 

that have known concentrations of the analytes of interest. Preparation (grinding/milling/fusion) 

of the calibration standards should follow the same processes used to prepare the catalyst 

samples to be tested. The calibration standards values must be established as the average of a 

minimum of three analyses using an approved EPA or ASTM method with instrument analyzer 

calibrations traceable to the U.S. National Institute of Standards and Technology (NIST), if 

available. The maximum percent deviation of the triplicate calibration standard analyses should 

agree within 10 percent of the average value for the triplicate analysis (see Figure 1). If the 

calibration analyses do not meet this criteria, the calibration standards must be re-analyzed. If 

unacceptable variability persists, new calibration standards must be prepared. Approved methods 

for the calibration standard analyses include, but are not limited to, EPA Methods 6010B, 6020, 

7520, or 7521 of SW–846.1

 Use a minimum of four calibration standards as specified below (see 

Figure 1): 

7.1.1 High-Range Calibration Standard. Concentration equivalent to 80 to 100 percent of the 

span. The concentration of the high-range calibration standard should exceed the maximum 

concentration anticipated in the catalyst samples. 

7.1.2 Mid-Range Calibration Standard. Concentration equivalent to 40 to 60 percent of the span. 

7.1.3 Low-Range Calibration Standard. Concentration equivalent to 1 to 20 percent of the span. 

The concentration of the low-range calibration standard should be selected so that it is less than 

either one-fourth of the applicable concentration limit or of the lowest concentration anticipated 

in the catalyst samples. 

7.1.4 Zero Calibration Standard. Concentration of less than 0.25 percent of the span. 

7.2 Accuracy Assessment Standard. Prepare an accuracy assessment standard and determine the 

ideal value for the accuracy assessment standard following the same procedures used to prepare 

and analyze the calibration standards as described in section 7.1. The maximum percent 

deviation of the triplicate accuracy assessment standard analyses should agree within 10 percent 

of the average value for the triplicate analysis (see Figure 1). The concentration equivalent of the 

accuracy assessment standard must be between 20 and 80 percent of the span. 

7.3 Energy Calibration Standard. Generally, the energy calibration standard will be provided by 

the XRF instrument manufacturer for energy dispersive spectrometers. Energy calibration is 

performed using the manufacturer's recommended calibration standard and involves 

measurement of a specific energy line (based on the metal in the energy calibration standard). 

This is generally an automated procedure used to assure the accuracy of the energy scale. This 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

calibration standard may not be applicable to all models of XRF spectrometers (particularly 

wavelength dispersive XRF spectrometers). 

8.0 Sample Collection, Preservation, Transport, and Storage. [Reserved] 

9.0 Quality Control. 

9.1 Energy Calibration. For energy dispersive spectrometers, conduct the energy calibration by 

analyzing the energy calibration standard provided by the manufacturer. The energy calibration 

involves measurement of a specific energy line (based on the metal in the energy calibration 

standard) and then determination of the difference between the measured peak energy value and 

the ideal value. This analysis, if applicable, should be performed daily prior to any sample 

analyses to check the instrument's energy scale. This is generally an automated procedure and 

assures the accuracy of the energy scale. If the energy scale calibration process is not automated, 

follow the manufacturer's procedures to manually adjust the instrument, as necessary. 

9.2 Zero Drift Test. Conduct the zero drift test by analyzing the analyte concentration output by 

the measurement system with the initial calibration value for the zero calibration standard (see 

Figure 2). This analysis should be performed with each set of samples analyzed. 

9.3 Calibration Drift Test. Conduct the calibration drift test by analyzing the analyte 

concentration output by the measurement system with the initial calibration value for the midrange calibration standard (see Figure 2). This analysis should be performed with each set of 

samples analyzed. 

9.4 Analyzer Accuracy Test. Conduct the analyzer accuracy test by analyzing the accuracy 

assessment standard and comparing the value output by the measurement system with the ideal 

value for the accuracy assessment standard (see Figure 2). This analysis should be performed 

with each set of samples analyzed. 

10.0 Calibration and Standardization. 

10.1 Perform the initial calibration and set-up following the instrument manufacturer's 

instructions. These procedures should include, at a minimum, the major steps listed in sections 

10.2 and 10.3. Subsequent calibrations are to be performed when either a quality 

assurance/quality control (QA/QC) limit listed in section 13 is exceeded or when there is a 

change in the excitation conditions, such as a change in the tube, detector, X-ray filters, or signal 

processor. Calibrations are typically valid for 6 months to 1 year. 

10.2 Instrument Calibration. Calibration is performed initially with calibration standards of 

similar matrix and binders, if used, as the samples to be analyzed (see Figure 1). 

10.3 Reference Peak Spectra. Acquisition of reference spectra is required only during the initial 

calibration. As long as no processing methods have changed, these peak shape references remain 

valid. This procedure consists of placing the standards in the instrument and acquiring individual 

elemental spectra that are stored in the method file with each of the analytical conditions. These 

reference spectra are used in the standard deconvolution of the unknown spectra. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

11.0 Analytical Procedure. 

11.1 Sample Preparation. Prepare catalyst samples using the same procedure used to prepare the 

calibration standards. Measure and record the weight of sample used. Measure and record the 

amount of binder, if any, used. Pellets or films must be of sufficient size to cover the analyzer 

sample window. 

11.2 Sample Analyses. Place the prepared catalyst samples into the analyzer. Follow the 

manufacturer's instructions for analyzing the samples. 

11.3 Record and Store Data. Use a digital recorder or personal computer to record and store 

results for each sample. Record any mechanical or software problems encountered during the 

analysis. 

12.0 Data Analysis and Calculations. 

Carry out the following calculations, retaining at least one extra significant figure beyond that of 

the acquired data. Round off figures after final calculation. 

12.1 Drift. Calculate the zero and calibration drift for the tests described in sections 9.2 and 9.3 

(see also Figure 2) as follows: 

100   Span

CurrentAnalyzerCal.Response InitialCal.Response QC Value (Eq. A-1) 

Where: 

CurrentAnalyzerCal.Response = Instrument response for current QC sample analyses; 

InitialCal.Response = Initial instrument response for calibration standard; 

QC Value = QC metric (zero drift or calibration drift), percent of span; 

Span = Span of the monitoring system. 

12.2 Analyzer Accuracy. Calculate the analyzer accuracy error for the tests described in section 

9.4 (see also Figure 2) as follows: 

100   IdealCal.Response

CurrentAnalyzerCal.Response InitialCal.Response Accuracy Value (Eq. A-2) 

Where: 

Accuracy Value = Percent difference of instrument response to the ideal response for the 

accuracy assessment standard; 

CurrentAnalyzerCal.Response = Instrument response for current QC sample analyses; 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

IdealCal.Response = Ideal instrument response for the accuracy assessment standard. 

13.0 Method Performance. 

13.1 Analytical Range. The analytical range is determined by the instrument design. For this 

method, a portion of the analytical range is selected by choosing the span of the monitoring 

system. The span of the monitoring system must be selected such that it encompasses the range 

of concentrations anticipated to occur in the catalyst sample. If applicable, the span must be 

selected such that the analyte concentration equivalent to the emission standard is not less than 

30 percent of the span. If the measured analyte concentration exceeds the concentration of the 

high-range calibration standard, the sample analysis is considered invalid. Additionally, if the 

measured analyte concentration is less than the concentration of the low-range calibration 

standard but above the detectable limit, the sample analysis results must be flagged with a 

footnote stating, in effect, that the analyte was detected but that the reported concentration is 

below the lower quantitation limit. 

13.2 Minimum Detectable Limit. The minimum detectable limit depends on the signal-to-noise 

ratio of the measurement system. For a well-designed system, the minimum detectable limit 

should be less than 2 percent of the span. 

13.3 Zero Drift. Less than ±2 percent of the span. 

13.4 Calibration Drift. Less than ±5 percent of the span. 

13.5 Analyzer Accuracy Error. Less than ±10 percent. 

14.0 Pollution Prevention. [Reserved] 

15.0 Waste Management. [Reserved] 

16.0 Alternative Procedures. [Reserved] 

17.0 References. 

1. U.S. Environmental Protection Agency. 1998. Test Methods for Evaluating Solid Waste, 

Physical/Chemical Methods. EPA Publication No. SW–846, Revision 5 (April 1998). Office of 

Solid Waste, Washington, DC. 

18.0 Tables, Diagrams, Flowcharts, and Validation Data. 

Date: 

Analytic Method Used: 

 Zeroa Low-Rangeb Mid-Rangec High-Ranged Accuracy Stde

Sample Run: 

1 

2 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

3 

Average 

Maximum Percent Deviation 

a

Average must be less than 0.25 percent of span. 

b

Average must be 1 to 20 percent of span. 

c

Average must be 40 to 60 percent of span. 

d

Average must be 80 to 100 percent of span. 

e

Average must be 20 to 80 percent of span. 

Figure 1. Data Recording Sheet for Analysis of Calibration Samples. 

Source Identification: 

Run Number: 

Test Personnel: 

Span: 

Date: 

 

Initial calibration 

response 

Current analyzer 

calibration response Drift (percent of span) 

Zero Standard 

Mid-range 

Standard 

 

 

Ideal calibration 

response 

Current analyzer 

calibration response 

Accuracy error 

(percent of ideal) 

Accuracy 

Standard 

 

Figure 2. Data Recording Sheet for System Calibration Drift Data. 

[70 FR 6970, Feb. 9, 2005] 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EO12866_RefineryRTR 2060 AQ75 NPRM Part63_SubpartCC_RegText_20140211 

Title 40: Protection of Environment 

PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR SOURCE CATEGORIES 

Subpart CC—National Emission Standards for Hazardous Air Pollutants From Petroleum 

Refineries 

§ 63.640 Applicability and designation of affected source. 

(a) This subpart applies to petroleum refining process units and to related emissions points 

that are specified in paragraphs (c)(1) through (9) of this section that are located at a plant site 

and that meet the criteria in paragraphs (a)(1) and (2) of this section: 

(1) Are located at a plant site that is a major source as defined in section 112(a) of the Clean 

Air Act; and 

(2) Emit or have equipment containing or contacting one or more of the hazardous air 

pollutants listed in table 1 of this subpart. 

(b)(1) If the predominant use of the flexible operation unit, as described in paragraphs 

(b)(1)(i) and (ii) of this section, is as a petroleum refining process unit, as defined in §63.641, 

then the flexible operation unit shall be subject to the provisions of this subpart. 

(i) Except as provided in paragraph (b)(1)(ii) of this section, the predominant use of the 

flexible operation unit shall be the use representing the greatest annual operating time. 

(ii) If the flexible operation unit is used as a petroleum refining process unit and for another 

purpose equally based on operating time, then the predominant use of the flexible operation unit 

shall be the use that produces the greatest annual production on a mass basis. 

(2) The determination of applicability of this subpart to petroleum refining process units 

that are designed and operated as flexible operation units shall be reported as specified in 

§63.655(h)(6)(i). 

(c) For the purposes of this subpart, the affected source shall comprise all emissions points, 

in combination, listed in paragraphs (c)(1) through (c)(9) of this section that are located at a 

single refinery plant site. 

(1) All miscellaneous process vents from petroleum refining process units meeting the 

criteria in paragraph (a) of this section; 

Deleted: 8

Deleted: 8
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) All storage vessels associated with petroleum refining process units meeting the criteria 

in paragraph (a) of this section; 

(3) All wastewater streams and treatment operations associated with petroleum refining 

process units meeting the criteria in paragraph (a) of this section; 

(4) All equipment leaks from petroleum refining process units meeting the criteria in 

paragraph (a) of this section; 

(5) All gasoline loading racks classified under Standard Industrial Classification code 2911 

meeting the criteria in paragraph (a) of this section; 

(6) All marine vessel loading operations located at a petroleum refinery meeting the criteria 

in paragraph (a) of this section and the applicability criteria of subpart Y, §63.560; 

(7) All storage vessels and equipment leaks associated with a bulk gasoline terminal or 

pipeline breakout station classified under Standard Industrial Classification code 2911 located 

within a contiguous area and under common control with a refinery meeting the criteria in 

paragraph (a) of this section; and 

(8) All heat exchange systems, as defined in this subpart. 

(9) All releases associated with the decoking operations of a delayed coking unit, as defined 

in this subpart. 

(d) The affected source subject to this subpart does not include the emission points listed in 

paragraphs (d)(1) through (d)(5) of this section. 

(1) Stormwater from segregated stormwater sewers; 

(2) Spills; 

(3) Any pump, compressor, pressure relief device, sampling connection system, open-ended 

valve or line, valve, or instrumentation system that is intended to operate in organic hazardous 

air pollutant service, as defined in §63.641 of this subpart, for less than 300 hours during the 

calendar year; 

(4) Catalytic cracking unit and catalytic reformer catalyst regeneration vents, and sulfur 

plant vents; and 

(5) Emission points routed to a fuel gas system, as defined in §63.641 of this subpart, 

provided that on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving 

gas from that fuel gas system are in compliance with §63.670. No other testing, monitoring, 

recordkeeping, or reporting is required for refinery fuel gas systems or emission points routed to 

refinery fuel gas systems. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(e) The owner or operator of a storage vessel constructed on or before August 18, 1994, 

shall follow the procedures specified in paragraphs (e)(1) and (e)(2) of this section to determine 

whether a storage vessel is part of a source to which this subpart applies. The owner or operator 

of a storage vessel constructed after August 18, 1994, shall follow the procedures specified in 

paragraphs (e)(1), (e)(2)(i), and (e)(2)(ii) of this section to determine whether a storage vessel is 

part of a source to which this subpart applies. 

(1) Where a storage vessel is used exclusively by a process unit, the storage vessel shall be 

considered part of that process unit. 

(i) If the process unit is a petroleum refining process unit subject to this subpart, then the 

storage vessel is part of the affected source to which this subpart applies. 

(ii) If the process unit is not subject to this subpart, then the storage vessel is not part of the 

affected source to which this subpart applies. 

(2) If a storage vessel is not dedicated to a single process unit, then the applicability of this 

subpart shall be determined according to the provisions in paragraphs (e)(2)(i) through (e)(2)(iii) 

of this section. 

(i) If a storage vessel is shared among process units and one of the process units has the 

predominant use, as determined by paragraphs (e)(2)(i)(A) and (e)(2)(i)(B) of this section, then 

the storage vessel is part of that process unit. 

(A) If the greatest input on a volume basis into the storage vessel is from a process unit that 

is located on the same plant site, then that process unit has the predominant use. 

(B) If the greatest input on a volume basis into the storage vessel is provided from a process 

unit that is not located on the same plant site, then the predominant use shall be the process unit 

that receives the greatest amount of material on a volume basis from the storage vessel at the 

same plant site. 

(ii) If a storage vessel is shared among process units so that there is no single predominant 

use, and at least one of those process units is a petroleum refining process unit subject to this 

subpart, the storage vessel shall be considered to be part of the petroleum refining process unit 

that is subject to this subpart. If more than one petroleum refining process unit is subject to this 

subpart, the owner or operator may assign the storage vessel to any of the petroleum refining 

process units subject to this subpart. 

(iii) If the predominant use of a storage vessel varies from year to year, then the 

applicability of this subpart shall be determined based on the utilization of that storage vessel 

during the year preceding August 18, 1995. This determination shall be reported as specified in 

§63.655(h)(6)(ii). 

(f) The owner or operator of a distillation unit constructed on or before August 18, 1994, 

shall follow the procedures specified in paragraphs (f)(1) through (f)(4) of this section to 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

determine whether a miscellaneous process vent from a distillation unit is part of a source to 

which this subpart applies. The owner or operator of a distillation unit constructed after August 

18, 1994, shall follow the procedures specified in paragraphs (f)(1) through (f)(5) of this section 

to determine whether a miscellaneous process vent from a distillation unit is part of a source to 

which this subpart applies. 

(1) If the greatest input to the distillation unit is from a process unit located on the same 

plant site, then the distillation unit shall be assigned to that process unit. 

(2) If the greatest input to the distillation unit is provided from a process unit that is not 

located on the same plant site, then the distillation unit shall be assigned to the process unit 

located at the same plant site that receives the greatest amount of material from the distillation 

unit. 

(3) If a distillation unit is shared among process units so that there is no single predominant 

use, as described in paragraphs (f)(1) and (f)(2) of this section, and at least one of those process 

units is a petroleum refining process unit subject to this subpart, the distillation unit shall be 

assigned to the petroleum refining process unit that is subject to this subpart. If more than one 

petroleum refining process unit is subject to this subpart, the owner or operator may assign the 

distillation unit to any of the petroleum refining process units subject to this rule. 

(4) If the process unit to which the distillation unit is assigned is a petroleum refining 

process unit subject to this subpart and the vent stream contains greater than 20 parts per million 

by volume total organic hazardous air pollutants, then the vent from the distillation unit is 

considered a miscellaneous process vent (as defined in §63.641 of this subpart) and is part of the 

source to which this subpart applies. 

(5) If the predominant use of a distillation unit varies from year to year, then the 

applicability of this subpart shall be determined based on the utilization of that distillation unit 

during the year preceding August 18, 1995. This determination shall be reported as specified in 

§63.655(h)(6)(iii). 

(g) The provisions of this subpart do not apply to the processes specified in paragraphs 

(g)(1) through (g)(7) of this section. 

(1) Research and development facilities, regardless of whether the facilities are located at 

the same plant site as a petroleum refining process unit that is subject to the provisions of this 

subpart; 

(2) Equipment that does not contain any of the hazardous air pollutants listed in table 1 of 

this subpart that is located within a petroleum refining process unit that is subject to this subpart; 

(3) Units processing natural gas liquids; 

(4) Units that are used specifically for recycling discarded oil; 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(5) Shale oil extraction units; 

(6) Ethylene processes; and 

(7) Process units and emission points subject to subparts F, G, H, and I of this part. 

(h) Sources subject to this subpart are required to achieve compliance on or before the dates 

specified in table 11 of this subpart, except as provided in paragraphs (h)(1) through (3) of this 

section. 

(1) Marine tank vessels at existing sources shall be in compliance with this subpart, except 

for §§63.657 through 63.661, no later than August 18, 1999, unless the vessels are included in an 

emissions average to generate emission credits. Marine tank vessels used to generate credits in 

an emissions average shall be in compliance with this subpart no later than August 18, 1998 

unless an extension has been granted by the Administrator as provided in §63.6(i). 

(2) Existing Group 1 floating roof storage vessels meeting the applicability criteria in item 1 

of the definition of Group 1 storage vessel shall be in compliance with §63.646 at the first 

degassing and cleaning activity after August 18, 1998, or August 18, 2005, whichever is first.

(3) An owner or operator may elect to comply with the provisions of §63.648(c) through (i) 

as an alternative to the provisions of §63.648(a) and (b). In such cases, the owner or operator 

shall comply no later than the dates specified in paragraphs (h)(3)(i) through (h)(3)(iii) of this 

section. 

(i) Phase I (see table 2 of this subpart), beginning on August 18, 1998; 

(ii) Phase II (see table 2 of this subpart), beginning no later than August 18, 1999; and 

(iii) Phase III (see table 2 of this subpart), beginning no later than February 18, 2001. 

(i) If an additional petroleum refining process unit is added to a plant site that is a major 

source as defined in section 112(a) of the Clean Air Act, the addition shall be subject to the 

requirements for a new source if it meets the criteria specified in paragraphs (i)(1) through (i)(3) 

of this section: 

(1) It is an addition that meets the definition of construction in §63.2 of subpart A of this 

part; 

(2) Such construction commenced after July 14, 1994; and 

(3) The addition has the potential to emit 10 tons per year or more of any hazardous air 

pollutant or 25 tons per year or more of any combination of hazardous air pollutants. 

Deleted: Except as provided in paragraphs (k), (l), 

or (m) of this section, s

Deleted: h)(6

Deleted: Except as provided in paragraphs 

(h)(1)(i) and (ii) of this section, new sources that 

commence construction or reconstruction after July 

14, 1994, shall be in compliance with this subpart 

upon initial startup or August 18, 1995, whichever is 

later.¶

(i) At new sources that commence construction or 

reconstruction after July 14, 1994, but on or before 

September 4, 2007, heat exchange systems shall be 

in compliance with the existing source requirements 

for heat exchange systems specified in §63.654 no 

later than October 29, 2012.¶

(ii) At new sources that commence construction or 

reconstruction after September 4, 2007, heat 

exchange systems shall be in compliance with the 

new source requirements in §63.654 upon initial 

startup or October 28, 2009, whichever is later.¶

(2) Except as provided in paragraphs (h)(3) through 

(h)(6) of this section, existing sources shall be in 

compliance with this subpart no later than August 

18, 1998, except as provided in §63.6(c)(5) of 

subpart A of this part, or unless an extension has 

been granted by the Administrator as provided in 

§63.6(i) of subpart A of this part.¶

(3) 

Deleted: 4

Deleted: of this subpart

Deleted: 5

Deleted: 

Deleted: 

Deleted: 5

Deleted: 5

Deleted: (6) Heat exchange systems at an existing 

source shall be in compliance with the existing 

source standards in §63.654 no later than October 

29, 2012.¶
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(j) If any change is made to a petroleum refining process unit subject to this subpart, the 

change shall be subject to the requirements for a new source if it meets the criteria specified in 

paragraphs (j)(1) and (j)(2) of this section: 

(1) It is a change that meets the definition of reconstruction in §63.2 of subpart A of this 

part; and 

(2) Such reconstruction commenced after July 14, 1994. 

(k) If an additional petroleum refining process unit is added to a plant site or a change is 

made to a petroleum refining process unit and the addition or change is determined to be subject 

to the new source requirements according to paragraphs (i) or (j) of this section it must comply 

with the requirements specified in paragraphs (k)(1) and (k)(2) of this section: 

(1) The reconstructed source, addition, or change shall be in compliance with the new 

source requirements in item (1), (2), or (3) of table 11 of this subpart, as applicable, upon initial 

startup of the reconstructed source or by August 18, 1995, whichever is later; and 

(2) The owner or operator of the reconstructed source, addition, or change shall comply 

with the reporting and recordkeeping requirements that are applicable to new sources. The 

applicable reports include, but are not limited to: 

(i) The application for approval of construction or reconstruction shall be submitted as soon 

as practical before the construction or reconstruction is planned to commence (but it need not be 

sooner than November 16, 1995); 

(ii) The Notification of Compliance Status report as required by §63.655(f) for a new 

source, addition, or change; 

(iii) Periodic Reports and other reports as required by §63.655(g) and (h); 

(iv) Reports and notifications required by §60.487 of subpart VV of part 60 or §63.182 of 

subpart H of this part. The requirements for subpart H are summarized in table 3 of this subpart; 

(v) Reports required by 40 CFR 61.357 of subpart FF; 

(vi) Reports and notifications required by §63.428(b), (c), (g)(1), (h)(1) through (h)(3), and 

(k) of subpart R. These requirements are summarized in table 4 of this subpart; and 

(vii) Reports and notifications required by §§63.565 and 63.567 of subpart Y of this part. 

These requirements are summarized in table 5 of this subpart. 

(l) If an additional petroleum refining process unit is added to a plant site or if a 

miscellaneous process vent, storage vessel, gasoline loading rack, marine tank vessel loading 

operation, heat exchange system, or decoking operation that meets the criteria in paragraphs 

(c)(1) through (9) of this section is added to an existing petroleum refinery or if another 

Deleted: or 

Deleted: 8
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

deliberate operational process change creating an additional Group 1 emissions point(s) (as 

defined in §63.641) is made to an existing petroleum refining process unit, and if the addition or 

process change is not subject to the new source requirements as determined according to 

paragraphs (i) or (j) of this section, the requirements in paragraphs (l)(1) through (4) of this 

section shall apply. Examples of process changes include, but are not limited to, changes in 

production capacity, or feed or raw material where the change requires construction or physical 

alteration of the existing equipment or catalyst type, or whenever there is replacement, removal, 

or addition of recovery equipment. For purposes of this paragraph and paragraph (m) of this 

section, process changes do not include: Process upsets, unintentional temporary process 

changes, and changes that are within the equipment configuration and operating conditions 

documented in the Notification of Compliance Status report required by §63.655(f). 

(1) The added emission point(s) and any emission point(s) within the added or changed 

petroleum refining process unit are subject to the requirements for an existing source. 

(2) The added emission point(s) and any emission point(s) within the added or changed 

petroleum refining process unit shall be in compliance with the applicable requirements in item 

(4) of table 11 of this subpart by the dates specified in paragraphs (l)(2)(i) or (l)(2)(ii) of this 

section. 

(i) If a petroleum refining process unit is added to a plant site or an emission point(s) is 

added to any existing petroleum refining process unit, the added emission point(s) shall be in 

compliance upon initial startup of any added petroleum refining process unit or emission point(s) 

or by the applicable compliance date in item (4) of table 11 of this subpart, whichever is later. 

(ii) If a deliberate operational process change to an existing petroleum refining process unit 

causes a Group 2 emission point to become a Group 1 emission point (as defined in §63.641), the 

owner or operator shall be in compliance upon initial startup or by August 18, 1998, whichever is 

later, unless the owner or operator demonstrates to the Administrator that achieving compliance 

will take longer than making the change. If this demonstration is made to the Administrator’s 

satisfaction, the owner or operator shall follow the procedures in paragraphs (m)(1) through 

(m)(3) of this section to establish a compliance date. 

(3) The owner or operator of a petroleum refining process unit or of a storage vessel, 

miscellaneous process vent, wastewater stream, gasoline loading rack, marine tank vessel 

loading operation, heat exchange system, or decoking operation meeting the criteria in 

paragraphs (c)(1) through (9) of this section that is added to a plant site and is subject to the 

requirements for existing sources shall comply with the reporting and recordkeeping 

requirements that are applicable to existing sources including, but not limited to, the reports 

listed in paragraphs (l)(3)(i) through (vii) of this section. A process change to an existing 

petroleum refining process unit shall be subject to the reporting requirements for existing sources 

including, but not limited to, the reports listed in paragraphs (l)(3)(i) through (l)(3)(vii) of this 

section. The applicable reports include, but are not limited to: 

(i) The Notification of Compliance Status report as required by §63.655(f) for the emission 

points that were added or changed; 

Deleted: 3

Deleted: , as applicable

Deleted: August 18, 1998

Deleted: or 

Deleted: 8
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) Periodic Reports and other reports as required by §63.655(g) and (h); 

(iii) Reports and notifications required by sections of subpart A of this part that are 

applicable to this subpart, as identified in table 6 of this subpart. 

(iv) Reports and notifications required by §63.182, or 40 CFR 60.487. The requirements of 

subpart H of this part are summarized in table 3 of this subpart; 

(v) Reports required by §61.357 of subpart FF; 

(vi) Reports and notifications required by §63.428(b), (c), (g)(1), (h)(1) through (h)(3), and 

(k) of subpart R. These requirements are summarized in table 4 of this subpart; and 

(vii) Reports and notifications required by §§63.565 and 63.567 of subpart Y. These 

requirements are summarized in table 5 of this subpart. 

(4) If pumps, compressors, pressure relief devices, sampling connection systems, openended valves or lines, valves, or instrumentation systems are added to an existing source, they 

are subject to the equipment leak standards for existing sources in §63.648. A notification of 

compliance status report shall not be required for such added equipment. 

(m) If a change that does not meet the criteria in paragraph (l) of this section is made to a 

petroleum refining process unit subject to this subpart, and the change causes a Group 2 emission 

point to become a Group 1 emission point (as defined in §63.641), then the owner or operator 

shall comply with the applicable requirements of this subpart for existing sources, as specified in 

item (4) of table 11 of this subpart, for the Group 1 emission point as expeditiously as 

practicable, but in no event later than 3 years after the emission point becomes Group 1. 

(1) The owner or operator shall submit to the Administrator for approval a compliance 

schedule, along with a justification for the schedule. 

(2) The compliance schedule shall be submitted within 180 days after the change is made, 

unless the compliance schedule has been previously submitted to the permitting authority. If it is 

not possible to determine until after the change is implemented whether the emission point has 

become Group 1, the compliance schedule shall be submitted within 180 days of the date when 

the affect of the change is known to the source. The compliance schedule may be submitted in 

the next Periodic Report if the change is made after the date the Notification of Compliance 

Status report is due. 

(3) The Administrator shall approve or deny the compliance schedule or request changes 

within 120 calendar days of receipt of the compliance schedule and justification. Approval is 

automatic if not received from the Administrator within 120 calendar days of receipt. 

(n) Overlap of subpart CC with other regulations for storage vessels. As applicable, 

paragraphs (n)(1), (n)(3), (n)(4), (n)(6), and (n)(7) of this section apply for Group 2 storage 

vessels and paragraphs (n)(2) and (n)(5) of this section apply for Group 1 storage vessels.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage 

vessel that is subject to the provisions of 40 CFR part 60, subpart Kb is required to comply only 

with the requirements of 40 CFR part 60, subpart Kb, except as provided in paragraph (n)(8) of 

this section. After the compliance dates specified in paragraph (h) of this section, a Group 2 

storage vessel that is subject to the provisions of CFR part 61, subpart Y is required to comply 

only with the requirements of 40 CFR part 60, subpart Y, except as provided in paragraph 

(n)(10) of this section.

(2) After the compliance dates specified in paragraph (h) of this section, a Group 1 storage 

vessel that is also subject to 40 CFR part 60, subpart Kb is required to comply only with either 

40 CFR part 60, subpart Kb, except as provided in paragraph (n)(8) of this section; or this 

subpart. After the compliance dates specified in paragraph (h) of this section, a Group 1 storage 

vessel that is also subject to 40 CFR part 61, subpart Y is required to comply only with either 40 

CFR part 61, subpart Y, except as provided in paragraph (n)(10) of this section; or this subpart.

(3) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage 

vessel that is part of a new source and is subject to 40 CFR 60.110b, but is not required to apply 

controls by 40 CFR 60.110b or 60.112b, is required to comply only with this subpart.

(4) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage 

vessel that is part of a new source and is subject to 40 CFR 61.270, but is not required to apply 

controls by 40 CFR 61.271, is required to comply only with this subpart. 

(5) After the compliance dates specified in paragraph (h) of this section, a Group 1 storage 

vessel that is also subject to the provisions of 40 CFR part 60, subparts K or Ka is required to 

only comply with the provisions of this subpart. 

(6) After compliance dates specified in paragraph (h) of this section, a Group 2 storage 

vessel that is subject to the control requirements of 40 CFR part 60, subparts K or Ka is required 

to comply only with the provisions of 40 CFR part 60, subparts K or Ka except as provided for in 

paragraph (n)(9) of this section. 

(7) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage 

vessel that is subject to 40 CFR part 60, subparts K or Ka, but not to the control requirements of 

40 CFR part 60, subparts K or Ka, is required to comply only with this subpart. 

(8) Storage vessels described by paragraph (n)(1) of this section are to comply with 40 CFR 

part 60, subpart Kb except as provided in paragraphs (n)(8)(i) through (n)(8)(vi) of this section.

Storage vessels described by paragraph (n)(2) electing to comply with part 60, subpart Kb of this 

chapter shall comply with subpart Kb except as provided in paragraphs (n)(8)(i) through 

(n)(8)(vii) of this section.

(i) Storage vessels that are to comply with §60.112b(a)(2) of subpart Kb are exempt from 

the secondary seal requirements of §60.112b(a)(2)(i)(B) during the gap measurements for the 

primary seal required by §60.113b(b) of subpart Kb. 

Deleted: 1 or Group 

Deleted: part of an existing source and is also 

Deleted: ,

Deleted: is part of a new source and 

Deleted: After the compliance dates specified in 

paragraph (h) of this section, a Group 2 storage 

vessel that is part of a new source and is subject to 

the control requirements in §60.112b of 40 CFR part 

60, subpart Kb is required to comply only with 40 

CFR part 60, subpart Kb except as provided in 

paragraph (n)(8) of this section.¶

(4) 

Deleted: s

Deleted: ) and (n)(3

Deleted: for 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) If the owner or operator determines that it is unsafe to perform the seal gap 

measurements required in §60.113b(b) of subpart Kb or to inspect the vessel to determine 

compliance with §60.113b(a) of subpart Kb because the roof appears to be structurally unsound 

and poses an imminent danger to inspecting personnel, the owner or operator shall comply with 

the requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of subpart G (only up to the 

compliance date specified in paragraph (h) of this section for compliance with §63.660, as 

applicable) or either §63.1063(c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of subpart WW. 

(iii) If a failure is detected during the inspections required by §60.113b(a)(2) or during the 

seal gap measurements required by §60.113b(b)(1), and the vessel cannot be repaired within 45 

days and the vessel cannot be emptied within 45 days, the owner or operator may utilize up to 

two extensions of up to 30 additional calendar days each. The owner or operator is not required 

to provide a request for the extension to the Administrator. 

(iv) If an extension is utilized in accordance with paragraph (n)(8)(iii) of this section, the 

owner or operator shall, in the next periodic report, identify the vessel, provide the information 

listed in §60.113b(a)(2) or §60.113b(b)(4)(iii), and describe the nature and date of the repair 

made or provide the date the storage vessel was emptied. 

(v) Owners and operators of storage vessels complying with subpart Kb of part 60 may 

submit the inspection reports required by §§60.115b(a)(3), (a)(4), and (b)(4) of subpart Kb as 

part of the periodic reports required by this subpart, rather than within the 30-day period 

specified in §§60.115b(a)(3), (a)(4), and (b)(4) of subpart Kb. 

(vi) The reports of rim seal inspections specified in §60.115b(b)(2) are not required if none 

of the measured gaps or calculated gap areas exceed the limitations specified in §60.113b(b)(4). 

Documentation of the inspections shall be recorded as specified in §60.115b(b)(3). 

(vii) To be in compliance with §60.112b(a)(2)(ii) of this chapter, floating roof storage 

vessels must be equipped with guidepole controls as described in Appendix I: Acceptable 

Controls for Slotted Guidepoles Under the Storage Tank Emissions Reduction Partnership 

Program (65 FR 19891). 

(viii) If a flare is used as a control device for a storage vessel, on and after [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER], the owner or operator must meet the requirements of §63.670 

instead of the requirements referenced from part 60, subpart Kb of this chapter for that flare. 

(9) Storage vessels described by paragraph (n)(6) of this section that are to comply with 40 

CFR part 60, subpart Ka, are to comply with only subpart Ka except as provided for in 

paragraphs (n)(9)(i) through (n)(9)(iv) of this section. 

(i) If the owner or operator determines that it is unsafe to perform the seal gap 

measurements required in §60.113a(a)(1) of subpart Ka because the floating roof appears to be 

structurally unsound and poses an imminent danger to inspecting personnel, the owner or 

operator shall comply with the requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

subpart G (only up to the compliance date specified in paragraph (h) of this section for 

compliance with §63.660, as applicable) or either §63.1063(c)(2)(iv)(A) or 

§63.1063(c)(2)(iv)(B) of subpart WW. 

(ii) If a failure is detected during the seal gap measurements required by §60.113a(a)(1) of 

subpart Ka, and the vessel cannot be repaired within 45 days and the vessel cannot be emptied 

within 45 days, the owner or operator may utilize up to 2 extensions of up to 30 additional 

calendar days each. 

(iii) If an extension is utilized in accordance with paragraph (n)(9)(ii) of this section, the 

owner or operator shall, in the next periodic report, identify the vessel, describe the nature and 

date of the repair made or provide the date the storage vessel was emptied. The owner or 

operator shall also provide documentation of the decision to utilize an extension including a 

description of the failure, documentation that alternate storage capacity is unavailable, and a 

schedule of actions that will ensure that the control equipment will be repaired or the vessel 

emptied as soon as possible. 

(iv) Owners and operators of storage vessels complying with subpart Ka of part 60 may 

submit the inspection reports required by §60.113a(a)(1)(i)(E) of subpart Ka as part of the 

periodic reports required by this subpart, rather than within the 60-day period specified in 

§60.113a(a)(1)(i)(E) of subpart Ka. 

(10) Storage vessels described by paragraph (n)(1) of this section are to comply with 40 

CFR part 61, subpart Y except as provided in paragraphs (n)(10)(i) through (n)(8)(vi) of this 

section. Storage vessels described by paragraph (n)(2) electing to comply with 40 CFR part 61, 

subpart Y shall comply with subpart Y except as provided for in paragraphs (n)(10)(i) through 

(n)(10)(viii) of this section. 

(i) Storage vessels that are to comply with §61.271(b) of this chapter are exempt from the 

secondary seal requirements of §61.271(b)(2)(ii) of this chapter during the gap measurements for 

the primary seal required by §61.272(b) of this chapter. 

(ii) If the owner or operator determines that it is unsafe to perform the seal gap 

measurements required in §61.272(b) of this chapter or to inspect the vessel to determine 

compliance with §61.272(a) of this chapter because the roof appears to be structurally unsound 

and poses an imminent danger to inspecting personnel, the owner or operator shall comply with 

the requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of subpart G (only up to the 

compliance date specified in paragraph (h) of this section for compliance with §63.660, as 

applicable) or either §63.1063(c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of subpart WW. 

(iii) If a failure is detected during the inspections required by §61.272(a)(2) of this chapter 

or during the seal gap measurements required by §61.272(b)(1) of this chapter, and the vessel 

cannot be repaired within 45 days and the vessel cannot be emptied within 45 days, the owner or 

operator may utilize up to two extensions of up to 30 additional calendar days each. The owner 

or operator is not required to provide a request for the extension to the Administrator. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iv) If an extension is utilized in accordance with paragraph (n)(10)(iii) of this section, the 

owner or operator shall, in the next periodic report, identify the vessel, provide the information 

listed in §61.272(a)(2) or §61.272(b)(4)(iii) of this chapter, and describe the nature and date of 

the repair made or provide the date the storage vessel was emptied. 

(v) Owners and operators of storage vessels complying with 40 CFR part 61, subpart Y may 

submit the inspection reports required by §61.275(a), (b)(1), and (d) of this chapter as part of the 

periodic reports required by this subpart, rather than within the 60-day period specified in 

§61.275(a), (b)(1), and (d) of this chapter. 

(vi) The reports of rim seal inspections specified in §61.275(d) of this chapter are not 

required if none of the measured gaps or calculated gap areas exceed the limitations specified in 

§61.272(b)(4) of this chapter. Documentation of the inspections shall be recorded as specified in 

§61.276(a) of this chapter. 

(vii) To be in compliance with §61.271(b)(3) of this chapter, floating roof storage vessels 

must be equipped with guidepole controls as described in Appendix I: Acceptable Controls for 

Slotted Guidepoles Under the Storage Tank Emissions Reduction Partnership Program (65 FR 

19891). 

(viii) If a flare is used as a control device for a storage vessel, on and after [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER], the owner or operator must meet the requirements of §63.670 

instead of the requirements referenced from part 61, subpart Y of this chapter for that flare. 

(o) Overlap of this subpart CC with other regulations for wastewater. 

(1) After the compliance dates specified in paragraph (h) of this section a Group 1 

wastewater stream managed in a piece of equipment that is also subject to the provisions of 40 

CFR part 60, subpart QQQ is required to comply only with this subpart. 

(2) After the compliance dates specified in paragraph (h) of this section a Group 1 or Group 

2 wastewater stream that is conveyed, stored, or treated in a wastewater stream management unit 

that also receives streams subject to the provisions of §§63.133 through 63.147 of subpart G 

wastewater provisions of this part shall comply as specified in paragraph (o)(2)(i) or (o)(2)(ii) of 

this section. Compliance with the provisions of paragraph (o)(2) of this section shall constitute 

compliance with the requirements of this subpart for that wastewater stream. 

(i) Comply with paragraphs (o)(2)(i)(A) through (D) of this section. 

(A) The provisions in §§63.133 through 63.140 of subpart G for all equipment used in the 

storage and conveyance of the Group 1 or Group 2 wastewater stream. 

(B) The provisions in both 40 CFR part 61, subpart FF and in §§63.138 and 63.139 of 

subpart G for the treatment and control of the Group 1 or Group 2 wastewater stream. 

Deleted: o)(2)(i)(C
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(C) The provisions in §§63.143 through 63.148 of subpart G for monitoring and inspections 

of equipment and for recordkeeping and reporting requirements. The owner or operator is not 

required to comply with the monitoring, recordkeeping, and reporting requirements associated 

with the treatment and control requirements in 40 CFR part 61, subpart FF, §§61.355 through 

61.357. 

(D) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable requirements of 40 CFR part 61, 

subpart FF and subpart G of this part, or the requirements of §63.670. 

(ii) Comply with paragraphs (o)(2)(ii)(A) through (C) of this section. 

(A) Comply with the provisions of §§63.133 through 63.148 and §§63.151 and 63.152 of 

subpart G. 

(B) For any Group 2 wastewater stream or organic stream whose benzene emissions are 

subject to control through the use of one or more treatment processes or waste management units 

under the provisions of 40 CFR part 61, subpart FF on or after December 31, 1992, comply with 

the requirements of §63.133 through §63.147 of subpart G for Group 1 wastewater streams. 

(C) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable requirements of 40 CFR part 61, 

subpart FF and subpart G of this part, or the requirements of §63.670. 

(p) Overlap of subpart CC with other regulations for equipment leaks. 

(1) After the compliance dates specified in paragraph (h) of this section, equipment leaks 

that are also subject to the provisions of 40 CFR parts 60 and 61 standards promulgated before 

September 4, 2007, are required to comply only with the provisions specified in this subpart. 

(2) Equipment leaks that are also subject to the provisions of 40 CFR part 60, subpart 

GGGa, are required to comply only with the provisions specified in 40 CFR part 60, subpart 

GGGa. Owners and operators of equipment leaks that are subject to the provisions of 40 CFR 

part 60, subpart GGGa and subject to this subpart may elect to monitor equipment leaks 

following the provisions in §63.661, provided that the equipment is in compliance with all other 

provisions of 40 CFR part 60, subpart GGGa.

(q) For overlap of subpart CC with local or State regulations, the permitting authority for 

the affected source may allow consolidation of the monitoring, recordkeeping, and reporting 

requirements under this subpart with the monitoring, recordkeeping, and reporting requirements 

Deleted: and (o)(2)(ii)(B
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

under other applicable requirements in 40 CFR parts 60, 61, or 63, and in any 40 CFR part 52 

approved State implementation plan provided the implementation plan allows for approval of 

alternative monitoring, reporting, or recordkeeping requirements and provided that the permit 

contains an equivalent degree of compliance and control. 

(r) Overlap of subpart CC with other regulations for gasoline loading racks. After the 

compliance dates specified in paragraph (h) of this section, a Group 1 gasoline loading rack that 

is part of a source subject to subpart CC and also is subject to the provisions of 40 CFR part 60, 

subpart XX is required to comply only with this subpart. 

§ 63.641 Definitions. 

All terms used in this subpart shall have the meaning given them in the Clean Air Act, 

subpart A of this part, and in this section. If the same term is defined in subpart A and in this 

section, it shall have the meaning given in this section for purposes of this subpart. 

Affected source means the collection of emission points to which this subpart applies as 

determined by the criteria in §63.640. 

Affirmative defense means, in the context of an enforcement proceeding, a response or 

defense put forward by a defendant, regarding which the defendant has the burden of proof, and 

the merits of which are independently and objectively evaluated in a judicial or administrative 

proceeding. 

Aliphatic means open-chained structure consisting of paraffin, olefin and acetylene 

hydrocarbons and derivatives. 

Annual average true vapor pressure means the equilibrium partial pressure exerted by the 

stored liquid at the temperature equal to the annual average of the liquid storage temperature for 

liquids stored above or below the ambient temperature or at the local annual average temperature 

reported by the National Weather Service for liquids stored at the ambient temperature, as 

determined: 

(1) In accordance with methods specified in §63.111 of subpart G of this part; 

(2) From standard reference texts; or 

(3) By any other method approved by the Administrator. 

Assist air means all air that intentionally is introduced prior to or at a flare tip through 

nozzles or other hardware conveyance for the purposes including, but not limited to, protecting 

the design of the flare tip, promoting turbulence for mixing or inducing air into the flame. Assist 

air includes premix assist air and perimeter assist air. Assist air does not include the surrounding 

ambient air. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Assist steam means all steam that intentionally is introduced prior to or at a flare tip through 

nozzles or other hardware conveyance for the purposes including, but not limited to, protecting 

the design of the flare tip, promoting turbulence for mixing or inducing air into the flame. Assist 

steam includes, but is not necessarily limited to, center steam, lower steam and upper steam. 

Boiler means any enclosed combustion device that extracts useful energy in the form of 

steam and is not an incinerator. 

By compound means by individual stream components, not by carbon equivalents. 

Car-seal means a seal that is placed on a device that is used to change the position of a 

valve (e.g., from opened to closed) in such a way that the position of the valve cannot be 

changed without breaking the seal. 

Center steam means the portion of assist steam introduced into the stack of a flare to reduce 

burnback. 

Closed blowdown system means a system used for depressuring process vessels that is not 

open to the atmosphere and is configured of piping, ductwork, connections, 

accumulators/knockout drums, and, if necessary, flow inducing devices that transport gas or 

vapor from process vessel to a control device or back into the process. 

Closed vent system means a system that is not open to the atmosphere and is configured of 

piping, ductwork, connections, and, if necessary, flow inducing devices that transport gas or 

vapor from an emission point to a control device or back into the process. If gas or vapor from 

regulated equipment is routed to a process (e.g., to a petroleum refinery fuel gas system), the 

process shall not be considered a closed vent system and is not subject to closed vent system 

standards. 

Combustion device means an individual unit of equipment such as a flare, incinerator, 

process heater, or boiler used for the combustion of organic hazardous air pollutant vapors. 

Combustion zone means the area of the flare flame where the combustion zone gas 

combines for combustion. 

Combustion zone gas means all gases and vapors found just after a flare tip. This gas 

includes all flare vent gas, total steam, and premix air. 

Connector means flanged, screwed, or other joined fittings used to connect two pipe lines or 

a pipe line and a piece of equipment. A common connector is a flange. Joined fittings welded 

completely around the circumference of the interface are not considered connectors for the 

purpose of this regulation. For the purpose of reporting and recordkeeping, connector means 

joined fittings that are accessible. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Continuous record means documentation, either in hard copy or computer readable form, of 

data values measured at least once every hour and recorded at the frequency specified in 

§63.655(i). 

Continuous recorder means a data recording device recording an instantaneous data value 

or an average data value at least once every hour. 

Control device means any equipment used for recovering, removing, or oxidizing organic 

hazardous air pollutants. Such equipment includes, but is not limited to, absorbers, carbon 

adsorbers, condensers, incinerators, flares, boilers, and process heaters. For miscellaneous 

process vents (as defined in this section), recovery devices (as defined in this section) are not 

considered control devices. 

Cooling tower means a heat removal device used to remove the heat absorbed in circulating 

cooling water systems by transferring the heat to the atmosphere using natural or mechanical 

draft. 

Cooling tower return line means the main water trunk lines at the inlet to the cooling tower 

before exposure to the atmosphere. 

Decoking operations means the sequence of steps conducted at the end of the delayed 

coking unit’s cooling cycle to open the coke drum to the atmosphere in order to remove coke 

from the coke drum. Decoking operations begin at the end of the cooling cycle when steam 

released from the coke drum is no longer discharged via the delayed coker vent to the unit’s 

blowdown system but instead is vented directly to the atmosphere. Decoking operations include 

atmospheric depressuring (venting), deheading, draining, and decoking (coke cutting). 

Delayed coker vent means a vent that is typically intermittent in nature, and usually occurs 

only during the cooling cycle of a delayed coking unit coke drum when vapor from the coke 

drums cannot be sent to the fractionator column for product recovery, but instead is routed to the 

atmosphere through the delayed coking unit’s blowdown system. The emissions from the 

decoking operations, which include direct atmospheric venting, deheading, draining, or decoking 

(coke cutting), are not considered to be delayed coker vents. 

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

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

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

coke drums associated with a single fractionator; the fractionator, including the bottoms receiver 

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

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

Distillate receiver means overhead receivers, overhead accumulators, reflux drums, and 

condenser(s) including ejector-condenser(s) associated with a distillation unit. 

Distillation unit means a device or vessel in which one or more feed streams are separated 

into two or more exit streams, each exit stream having component concentrations different from 

Deleted: initiation of the depressuring

Deleted: the decoking operation

Deleted: a closed

Deleted: or directly to the atmosphere in an open 

blowdown system

Deleted: phases of delayed coker 

Deleted: coke drum
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

those in the feed stream(s). The separation is achieved by the redistribution of the components 

between the liquid and the vapor phases by vaporization and condensation as they approach 

equilibrium within the distillation unit. Distillation unit includes the distillate receiver, reboiler, 

and any associated vacuum pump or steam jet. 

Emission point means an individual miscellaneous process vent, storage vessel, wastewater 

stream, equipment leak, decoking operation or heat exchange system associated with a petroleum 

refining process unit; an individual storage vessel or equipment leak associated with a bulk 

gasoline terminal or pipeline breakout station classified under Standard Industrial Classification 

code 2911; a gasoline loading rack classified under Standard Industrial Classification code 2911; 

or a marine tank vessel loading operation located at a petroleum refinery. 

Equipment leak means emissions of organic hazardous air pollutants from a pump, 

compressor, pressure relief device, sampling connection system, open-ended valve or line, valve, 

or instrumentation system “in organic hazardous air pollutant service” as defined in this section. 

Vents from wastewater collection and conveyance systems (including, but not limited to 

wastewater drains, sewer vents, and sump drains), tank mixers, and sample valves on storage 

tanks are not equipment leaks. 

Flame zone means the portion of a combustion chamber of a boiler or process heater 

occupied by the flame envelope created by the primary fuel. 

Flare means a combustion device lacking an enclosed combustion chamber that uses an 

uncontrolled volume of ambient air to burn gases. For the purposes of this rule, the definition of 

flare includes, but is not necessarily limited to, air-assisted flares, steam-assisted flares and nonassisted flares. 

Flare purge gas means gas introduced between a flare header’s water seal and the flare tip 

to prevent oxygen infiltration (backflow) into the flare tip. For a flare with no water seal, the 

function of flare purge gas is performed by flare sweep gas and, therefore, by definition, such a 

flare has no flare purge gas. 

Flare supplemental gas means all gas introduced to the flare in order to improve the 

combustible characteristics of combustion zone gas. 

Flare sweep gas means, for a flare with a flare gas recovery system, the minimum amount 

of gas necessary to maintain a constant flow of gas through the flare header in order to prevent 

oxygen buildup in the flare header; flare sweep gas in these flares is introduced prior to and 

recovered by the flare gas recovery system. For a flare without a flare gas recovery system, flare 

sweep gas means the minimum amount of gas necessary to maintain a constant flow of gas 

through the flare header and out the flare tip in order to prevent oxygen buildup in the flare 

header and to prevent oxygen infiltration (backflow) into the flare tip. 

Flare vent gas means all gas found just prior to the flare tip. This gas includes all flare 

waste gas (i.e., gas from facility operations that is directed to a flare for the purpose of disposing 

Deleted: or 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

of the gas), flare sweep gas, flare purge gas and flare supplemental gas, but does not include pilot 

gas, total steam or assist air. 

Flexible operation unit means a process unit that manufactures different products 

periodically by alternating raw materials or operating conditions. These units are also referred to 

as campaign plants or blocked operations. 

Flow indicator means a device that indicates whether gas is flowing, or whether the valve 

position would allow gas to flow, in a line. 

Fuel gas system means the offsite and onsite piping and control system that gathers gaseous 

streams generated by refinery operations, may blend them with sources of gas, if available, and 

transports the blended gaseous fuel at suitable pressures for use as fuel in heaters, furnaces, 

boilers, incinerators, gas turbines, and other combustion devices located within or outside of the 

refinery. The fuel is piped directly to each individual combustion device, and the system 

typically operates at pressures over atmospheric. The gaseous streams can contain a mixture of 

methane, light hydrocarbons, hydrogen and other miscellaneous species. 

Gasoline means any petroleum distillate or petroleum distillate/alcohol blend having a Reid 

vapor pressure of 27.6 kilopascals or greater that is used as a fuel for internal combustion 

engines. 

Gasoline loading rack means the loading arms, pumps, meters, shutoff valves, relief valves, 

and other piping and valves necessary to fill gasoline cargo tanks. 

Group 1 gasoline loading rack means any gasoline loading rack classified under Standard 

Industrial Classification code 2911 that is located within a bulk gasoline terminal that has a 

gasoline throughput greater than 75,700 liters per day. Gasoline throughput shall be the 

maximum calculated design throughput for the terminal as may be limited by compliance with 

enforceable conditions under Federal, State, or local law and discovered by the Administrator 

and any other person. 

Group 1 marine tank vessel means a vessel at an existing source loaded at any land- or seabased terminal or structure that loads liquid commodities with vapor pressures greater than or 

equal to 10.3 kilopascals in bulk onto marine tank vessels, that emits greater than 9.1 megagrams 

of any individual HAP or 22.7 megagrams of any combination of HAP annually after August 18, 

1999, or a vessel at a new source loaded at any land- or sea-based terminal or structure that loads 

liquid commodities with vapor pressures greater than or equal to 10.3 kilopascals onto marine 

tank vessels. 

Group 1 miscellaneous process vent means a miscellaneous process vent for which the total 

organic HAP concentration is greater than or equal to 20 parts per million by volume, and the 

total volatile organic compound emissions are greater than or equal to 33 kilograms per day for 

existing sources and 6.8 kilograms per day for new sources at the outlet of the final recovery 

device (if any) and prior to any control device and prior to discharge to the atmosphere. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Group 1 storage vessel means: 

(1) Prior to [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER]: 

(i) A storage vessel at an existing source that has a design capacity greater than or equal to 

177 cubic meters and stored-liquid maximum true vapor pressure greater than or equal to 10.4 

kilopascals and stored-liquid annual average true vapor pressure greater than or equal to 8.3 

kilopascals and annual average HAP liquid concentration greater than 4 percent by weight total 

organic HAP;

(ii) A storage vessel at a new source that has a design storage capacity greater than or equal 

to 151 cubic meters and stored-liquid maximum true vapor pressure greater than or equal to 3.4 

kilopascals and annual average HAP liquid concentration greater than 2 percent by weight total 

organic HAP; or

(iii) A storage vessel at a new source that has a design storage capacity greater than or equal 

to 76 cubic meters and less than 151 cubic meters and stored-liquid maximum true vapor 

pressure greater than or equal to 77 kilopascals and annual average HAP liquid concentration 

greater than 2 percent by weight total organic HAP. 

(2) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER]: 

(i) A storage vessel at an existing source that has a design capacity greater than or equal to 

151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or 

equal to 5.2 kilopascals (0.75 pounds per square inch) and annual average HAP liquid 

concentration greater than 4 percent by weight total organic HAP; 

(ii) A storage vessel at an existing source that has a design storage capacity greater than or 

equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) and 

stored-liquid maximum true vapor pressure greater than or equal to 13.1 kilopascals (1.9 pounds 

per square inch) and annual average HAP liquid concentration greater than 4 percent by weight 

total organic HAP; 

(iii) A storage vessel at a new source that has a design storage capacity greater than or equal 

to 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than 

or equal to 3.4 kilopascals (0.5 pounds per square inch) and annual average HAP liquid 

concentration greater than 2 percent by weight total organic HAP; or 

(iv) A storage vessel at a new source that has a design storage capacity greater than or equal 

to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) and storedliquid maximum true vapor pressure greater than or equal to 13.1 kilopascals (1.9 pounds per 

square inch) and annual average HAP liquid concentration greater than 2 percent by weight total 

organic HAP. 

Deleted: a

Deleted: a

Deleted: a
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Group 1 wastewater stream means a wastewater stream at a petroleum refinery with a total 

annual benzene loading of 10 megagrams per year or greater as calculated according to the 

procedures in 40 CFR 61.342 of subpart FF of part 61 that has a flow rate of 0.02 liters per 

minute or greater, a benzene concentration of 10 parts per million by weight or greater, and is not 

exempt from control requirements under the provisions of 40 CFR part 61, subpart FF. 

Group 2 gasoline loading rack means a gasoline loading rack classified under Standard 

Industrial Classification code 2911 that does not meet the definition of a Group 1 gasoline 

loading rack. 

Group 2 marine tank vessel means a marine tank vessel that does not meet the definition of 

a Group 1 marine tank vessel. 

Group 2 miscellaneous process vent means a miscellaneous process vent that does not meet 

the definition of a Group 1 miscellaneous process vent. 

Group 2 storage vessel means a storage vessel that does not meet the definition of a Group 

1 storage vessel. 

Group 2 wastewater stream means a wastewater stream that does not meet the definition of 

Group 1 wastewater stream. 

Halogenated vent stream or halogenated stream means a stream determined to have a mass 

rate of halogen atoms of 0.45 kilograms per hour or greater, determined by the procedures 

presented in §63.115(d)(2)(v). The following procedures may be used as alternatives to the 

procedures in §63.115(d)(2)(v)(A): 

(1) Process knowledge that halogen or hydrogen halides are present in a vent stream and 

that the vent stream is halogenated, or 

(2) Concentration of compounds containing halogen and hydrogen halides measured by 

Method 26 or 26A of part 60, Appendix A–8 of this chapter, or 

(3) Concentration of compounds containing hydrogen halides measured by Method 320 of 

Appendix A of this part. 

Halogens and hydrogen halides means hydrogen chloride (HCl), chlorine (Cl2), hydrogen 

bromide (HBr), bromine (Br2), and hydrogen fluoride (HF). 

Hazardous air pollutant or HAP means one of the chemicals listed in section 112(b) of the 

Clean Air Act. 

Heat exchange system means a device or collection of devices used to transfer heat from 

process fluids to water without intentional direct contact of the process fluid with the water (i.e., 

non-contact heat exchanger) and to transport and/or cool the water in a closed-loop recirculation 

system (cooling tower system) or a once-through system (e.g., river or pond water). For closed-
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

loop recirculation systems, the heat exchange system consists of a cooling tower, all petroleum 

refinery process unit heat exchangers that are in organic HAP service, as defined in this subpart, 

serviced by that cooling tower, and all water lines to and from these petroleum refinery process 

unit heat exchangers. For once-through systems, the heat exchange system consists of all heat 

exchangers that are in organic HAP service, as defined in this subpart, servicing an individual 

petroleum refinery process unit and all water lines to and from these heat exchangers. Sample 

coolers or pump seal coolers are not considered heat exchangers for the purpose of this definition 

and are not part of the heat exchange system. Intentional direct contact with process fluids results 

in the formation of a wastewater. 

Heat exchanger exit line means the cooling water line from the exit of one or more heat 

exchangers (where cooling water leaves the heat exchangers) to either the entrance of the cooling 

tower return line or prior to exposure to the atmosphere, in, as an example, a once-through 

cooling system, whichever occurs first. 

Incinerator means an enclosed combustion device that is used for destroying organic 

compounds. Auxiliary fuel may be used to heat waste gas to combustion temperatures. Any 

energy recovery section present is not physically formed into one manufactured or assembled 

unit with the combustion section; rather, the energy recovery section is a separate section 

following the combustion section and the two are joined by ducts or connections carrying flue 

gas. 

In heavy liquid service means that the piece of equipment is not in gas/vapor service or in 

light liquid service. 

In light liquid service means that the piece of equipment contains a liquid that meets the 

conditions specified in §60.593(d) of part 60, subpart GGG. 

In organic hazardous air pollutant service or in organic HAP service means that a piece of 

equipment either contains or contacts a fluid (liquid or gas) that is at least 5 percent by weight of 

total organic HAP as determined according to the provisions of §63.180(d) of this part and table 

1 of this subpart. The provisions of §63.180(d) also specify how to determine that a piece of 

equipment is not in organic HAP service. 

Leakless valve means a valve that has no external actuating mechanism. 

Lower steam means the portion of assist steam piped to an exterior annular ring near the 

lower part of a flare tip, which then flows through tubes to the flare tip, and ultimately exits the 

tubes at the flare tip. 

Maximum true vapor pressure means the equilibrium partial pressure exerted by the stored 

liquid at the temperature equal to the highest calendar-month average of the liquid storage 

temperature for liquids stored above or below the ambient temperature or at the local maximum 

monthly average temperature as reported by the National Weather Service for liquids stored at 

the ambient temperature, as determined: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) In accordance with methods specified in §63.111 of subpart G of this part; 

(2) From standard reference texts; or 

(3) By any other method approved by the Administrator. 

Miscellaneous process vent means a gas stream containing greater than 20 parts per million 

by volume organic HAP that is continuously or periodically discharged from a petroleum 

refining process unit meeting the criteria specified in §63.640(a). Miscellaneous process vents 

include gas streams that are discharged directly to the atmosphere, gas streams that are routed to 

a control device prior to discharge to the atmosphere, or gas streams that are diverted through a 

product recovery device prior to control or discharge to the atmosphere. Miscellaneous process 

vents include vent streams from: caustic wash accumulators, distillation tower 

condensers/accumulators, flash/knockout drums, reactor vessels, scrubber overheads, stripper 

overheads, vacuum pumps, steam ejectors, hot wells, high point bleeds, wash tower overheads, 

water wash accumulators, blowdown condensers/accumulators, and delayed coker vents. 

Miscellaneous process vents do not include: 

(1) Gaseous streams routed to a fuel gas system, provided that on and after [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER], any flares receiving gas from the fuel gas system are in 

compliance with §63.670; 

(2) Relief valve discharges regulated under §63.648; 

(3) Leaks from equipment regulated under §63.648; 

(4) [Reserved]; 

(5) In situ sampling systems (onstream analyzers) until [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER]. After this date, these sampling systems will be included in the definition of 

miscellaneous process vents; 

(6) Catalytic cracking unit catalyst regeneration vents; 

(7) Catalytic reformer regeneration vents; 

(8) Sulfur plant vents; 

(9) Vents from control devices such as scrubbers, boilers, incinerators, and electrostatic 

precipitators applied to catalytic cracking unit catalyst regeneration vents, catalytic reformer 

regeneration vents, and sulfur plant vents; 

(10) Vents from any stripping operations applied to comply with the wastewater provisions 

of this subpart, subpart G of this part, or 40 CFR part 61, subpart FF; 

Deleted: during normal operation of

Deleted: (

Deleted: )

Deleted: Episodic or nonroutine releases such as 

those associated with startup, shutdown, 

malfunction, maintenance, depressuring, and catalyst 

transfer operations
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(11) Emissions associated with delayed coking unit decoking operations; 

(12) Vents from storage vessels; 

(13) Emissions from wastewater collection and conveyance systems including, but not 

limited to, wastewater drains, sewer vents, and sump drains; and 

(14) Hydrogen production plant vents through which carbon dioxide is removed from 

process streams or through which steam condensate produced or treated within the hydrogen 

plant is degassed or deaerated. 

Net heating value means the energy released as heat when a compound undergoes complete 

combustion with oxygen to form gaseous carbon dioxide and gaseous water (also referred to as 

lower heating value). 

Operating permit means a permit required by 40 CFR parts 70 or 71. 

Organic hazardous air pollutant or organic HAP in this subpart, means any of the organic 

chemicals listed in table 1 of this subpart. 

Petroleum-based solvents means mixtures of aliphatic hydrocarbons or mixtures of one and 

two ring aromatic hydrocarbons. 

Perimeter assist air means the portion of assist air introduced at the perimeter of the flare 

tip or above the flare tip. Perimeter assist air includes air intentionally entrained in lower and 

upper steam. Perimeter assist air includes all assist air except premix assist air. 

Periodically discharged means discharges that are intermittent and associated with routine 

operations, maintenance activities, startups, shutdowns, malfunctions, or process upsets. 

Petroleum refining process unit means a process unit used in an establishment primarily 

engaged in petroleum refining as defined in the Standard Industrial Classification code for 

petroleum refining (2911), and used primarily for the following: 

(1) Producing transportation fuels (such as gasoline, diesel fuels, and jet fuels), heating fuels 

(such as kerosene, fuel gas distillate, and fuel oils), or lubricants; 

(2) Separating petroleum; or 

(3) Separating, cracking, reacting, or reforming intermediate petroleum streams. 

(4) Examples of such units include, but are not limited to, petroleum-based solvent units, 

alkylation units, catalytic hydrotreating, catalytic hydrorefining, catalytic hydrocracking, 

catalytic reforming, catalytic cracking, crude distillation, lube oil processing, hydrogen 

production, isomerization, polymerization, thermal processes, and blending, sweetening, and 

treating processes. Petroleum refining process units also include sulfur plants. 

Deleted: Coking unit vents

Deleted: coke drum depressuring at or below a 

coke drum outlet pressure of 15 pounds per square 

inch gauge, deheading, draining, or 

Deleted: (coke cutting) or pressure testing after 

decoking

Deleted: . Discharges associated with

Deleted: are not considered periodically 

discharged miscellaneous process vents and are 

therefore not regulated by the petroleum refinery 

miscellaneous process vent provisions
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Pilot gas means gas introduced into a flare tip that provides a flame to ignite the flare vent 

gas. 

Plant site means all contiguous or adjoining property that is under common control 

including properties that are separated only by a road or other public right-of-way. Common 

control includes properties that are owned, leased, or operated by the same entity, parent entity, 

subsidiary, or any combination thereof. 

Premix assist air means the portion of assist air that is introduced to the flare vent gas prior 

to the flare tip. Premix assist air also includes any air intentionally entrained in center steam.

Primary fuel means the fuel that provides the principal heat input (i.e., more than 50 

percent) to the device. To be considered primary, the fuel must be able to sustain operation 

without the addition of other fuels. 

Process heater means an enclosed combustion device that primarily transfers heat liberated 

by burning fuel directly to process streams or to heat transfer liquids other than water. 

Process unit means the equipment assembled and connected by pipes or ducts to process 

raw and/or intermediate materials and to manufacture an intended product. A process unit 

includes any associated storage vessels. For the purpose of this subpart, process unit includes, 

but is not limited to, chemical manufacturing process units and petroleum refining process units. 

Process unit shutdown means a work practice or operational procedure that stops production 

from a process unit or part of a process unit during which it is technically feasible to clear 

process material from a process unit or part of a process unit consistent with safety constraints 

and during which repairs can be accomplished. An unscheduled work practice or operational 

procedure that stops production from a process unit or part of a process unit for less than 24 

hours is not considered a process unit shutdown. An unscheduled work practice or operational 

procedure that would stop production from a process unit or part of a process unit for a shorter 

period of time than would be required to clear the process unit or part of the process unit of 

materials and start up the unit, or would result in greater emissions than delay of repair of leaking 

components until the next scheduled process unit shutdown is not considered a process unit 

shutdown. The use of spare equipment and technically feasible bypassing of equipment without 

stopping production are not considered process unit shutdowns. 

Recovery device means an individual unit of equipment capable of and used for the purpose 

of recovering chemicals for use, reuse, or sale. Recovery devices include, but are not limited to, 

absorbers, carbon adsorbers, and condensers. 

Reference control technology for gasoline loading racks means a vapor collection and 

processing system used to reduce emissions due to the loading of gasoline cargo tanks to 10 

milligrams of total organic compounds per liter of gasoline loaded or less. 

Reference control technology for marine vessels means a vapor collection system and a 

control device that reduces captured HAP emissions by 97 percent. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reference control technology for miscellaneous process vents means a combustion device 

used to reduce organic HAP emissions by 98 percent, or to an outlet concentration of 20 parts per 

million by volume. 

Reference control technology for storage vessels means either: 

(1) For Group 1 storage vessels complying with §63.660: 

(i) An internal floating roof meeting the specifications of §§63.1063(a)(1)(i) and (b); 

(ii) An external floating roof meeting the specifications of §63.1063(a)(1)(ii), (a)(2), and 

(b); 

(iii) An external floating roof converted to an internal floating roof meeting the 

specifications of §63.1063(a)(1)(i) and (b); or 

(iv) A closed-vent system to a control device that reduces organic HAP emissions by 95 

percent, or to an outlet concentration of 20 parts per million by volume (ppmv). 

(v) For purposes of emissions averaging, these four technologies are considered equivalent. 

(2) For all other storage vessels: 

(i) An internal floating roof meeting the specifications of §63.119(b) of subpart G except for 

§63.119(b)(5) and (b)(6); 

(ii) An external floating roof meeting the specifications of §63.119(c) of subpart G except 

for §63.119(c)(2); 

(iii) An external floating roof converted to an internal floating roof meeting the 

specifications of §63.119(d) of subpart G except for §63.119(d)(2); or 

(iv) A closed-vent system to a control device that reduces organic HAP emissions by 95

percent, or to an outlet concentration of 20 parts per million by volume. 

(v) For purposes of emissions averaging, these four technologies are considered equivalent. 

Reference control technology for wastewater means the use of: 

(1) Controls specified in §§61.343 through 61.347 of subpart FF of part 61; 

(2) A treatment process that achieves the emission reductions specified in table 7 of this 

subpart for each individual HAP present in the wastewater stream or is a steam stripper that 

meets the specifications in §63.138(g) of subpart G of this part; and 

Deleted: 

Deleted: 2

Deleted: 3

Deleted: 4

Deleted: -

Deleted: 5
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(3) A control device to reduce by 95 percent (or to an outlet concentration of 20 parts per 

million by volume for combustion devices) the organic HAP emissions in the vapor streams 

vented from treatment processes (including the steam stripper described in paragraph (2) of this 

definition) managing wastewater. 

Refinery fuel gas means a gaseous mixture of methane, light hydrocarbons, hydrogen, and 

other miscellaneous species (nitrogen, carbon dioxide, hydrogen sulfide, etc.) that is produced in 

the refining of crude oil and/or petrochemical processes and that is separated for use as a fuel in 

boilers and process heaters throughout the refinery. 

Relief valve means a valve used only to release an unplanned, nonroutine discharge. A relief 

valve discharge can result from an operator error, a malfunction such as a power failure or 

equipment failure, or other unexpected cause that requires immediate venting of gas from 

process equipment in order to avoid safety hazards or equipment damage. 

Research and development facility means laboratory and pilot plant operations whose 

primary purpose is to conduct research and development into new processes and products, where 

the operations are under the close supervision of technically trained personnel, and is not 

engaged in the manufacture of products for commercial sale, except in a de minimis manner. 

Seal means, for the purpose of complying with the requirements of §60.482-6(a)(2) of this 

chapter, that instrument monitoring of the open-ended valve or line conducted according to the 

method specified in §60.485(b) and, as applicable, §60.485(c) of this chapter indicates no 

readings of 500 parts per million or greater. For the purpose of complying with the requirements 

of §63.167(a)(2), seal means that instrument monitoring of the open-ended valve or line 

conducted according to the method specified in §60.180(b) and, as applicable, §60.180(c) 

indicates no readings of 500 parts per million or greater. 

Shutdown means the cessation of a petroleum refining process unit or a unit operation 

(including, but not limited to, a distillation unit or reactor) within a petroleum refining process 

unit for purposes including, but not limited to, periodic maintenance, replacement of equipment, 

or repair. 

Startup means the setting into operation of a petroleum refining process unit for purposes of 

production. Startup does not include operation solely for purposes of testing equipment. Startup 

does not include changes in product for flexible operation units. 

Storage vessel means a tank or other vessel that is used to store organic liquids. Storage 

vessel does not include: 

(1) Vessels permanently attached to motor vehicles such as trucks, railcars, barges, or ships; 

(2) Pressure vessels designed to operate in excess of 204.9 kilopascals and without 

emissions to the atmosphere; 

(3) Vessels with capacities smaller than 40 cubic meters; 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) Bottoms receiver tanks; or 

(5) Wastewater storage tanks. Wastewater storage tanks are covered under the wastewater 

provisions. 

Temperature monitoring device means a unit of equipment used to monitor temperature and 

having an accuracy of ±1 percent of the temperature being monitored expressed in degrees 

Celsius or ±0.5 °C, whichever is greater. 

Total annual benzene means the total amount of benzene in waste streams at a facility on an 

annual basis as determined in §61.342 of 40 CFR part 61, subpart FF. 

Total organic compounds or TOC, as used in this subpart, means those compounds 

excluding methane and ethane measured according to the procedures of Method 18 of 40 CFR 

part 60, appendix A. Method 25A may be used alone or in combination with Method 18 to 

measure TOC as provided in §63.645 of this subpart. 

Total steam means the total of all steam that is supplied to a flare and includes, but is not 

limited to, lower steam, center steam and upper steam. 

Upper steam means the portion of assist steam introduced via nozzles located on the 

exterior perimeter of the upper end of the flare tip. 

Wastewater means water or wastewater that, during production or processing, comes into 

direct contact with or results from the production or use of any raw material, intermediate 

product, finished product, byproduct, or waste product and is discharged into any individual 

drain system. Examples are feed tank drawdown; water formed during a chemical reaction or 

used as a reactant; water used to wash impurities from organic products or reactants; water used 

to cool or quench organic vapor streams through direct contact; and condensed steam from jet 

ejector systems pulling vacuum on vessels containing organics. 

§ 63.642 General standards. 

(a) Each owner or operator of a source subject to this subpart is required to apply for a part 

70 or part 71 operating permit from the appropriate permitting authority. If the EPA has 

approved a State operating permit program under part 70, the permit shall be obtained from the 

State authority. If the State operating permit program has not been approved, the source shall 

apply to the EPA Regional Office pursuant to part 71. 

(b) The emission standards set forth in this subpart shall apply at all times.

(c) Table 6 of this subpart specifies the provisions of subpart A of this part that apply and 

those that do not apply to owners and operators of sources subject to this subpart. 

(d) Initial performance tests and initial compliance determinations shall be required only as 

specified in this subpart. 

Deleted: [Reserved]
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Performance tests and compliance determinations shall be conducted according to the 

schedule and procedures specified in this subpart. 

(2) The owner or operator shall notify the Administrator of the intention to conduct a 

performance test at least 30 days before the performance test is scheduled. 

(3) Performance tests shall be conducted at maximum representative operating capacity for 

the process. During the performance test, an owner or operator shall operate the control device at 

either maximum or minimum representative operating conditions for monitored control device 

parameters, whichever results in lower emission reduction. An owner or operator shall not 

conduct a performance test during startup, shutdown, periods when the control device is 

bypassed or periods when the process, monitoring equipment or control device is not operating 

properly. The owner/operator may not conduct performance tests during periods of malfunction. 

The owner or operator must record the process information that is necessary to document 

operating conditions during the test and include in such record an explanation to support that the 

test was conducted at maximum representative operating capacity.Upon request, the owner or 

operator shall make available to the Administrator such records as may be necessary to 

determine the conditions of performance tests.

(4) Data shall be reduced in accordance with the EPA-approved methods specified in the 

applicable section or, if other test methods are used, the data and methods shall be validated 

according to the protocol in Method 301 of appendix A of this part. 

(e) All applicable records shall be maintained as specified in §63.655(i). 

(f) All reports required under this subpart shall be sent to the Administrator at the addresses 

listed in §63.13 of subpart A of this part. If acceptable to both the Administrator and the owner 

or operator of a source, reports may be submitted on electronic media. 

(g) The owner or operator of an existing source subject to the requirements of this subpart 

shall control emissions of organic HAP’s to the level represented by the following equation: 

  

      

 

       

2 1C 2

A 1 2 1 2 1C 2 1

EMV EWW EWW

E 0.02 EPV EPV 0.05 ES ES EGLR EGLR (R) EMV 

where: 

EA = Emission rate, megagrams per year, allowed for the source. 

0.02Σ EPV1 = Sum of the residual emissions, megagrams per year, from all Group 1 

miscellaneous process vents, as defined in §63.641. 

Σ EPV2 = Sum of the emissions, megagrams per year, from all Group 2 process vents, as 

defined in §63.641. 

Deleted: according to the provisions of §63.7(e) 

except that performance tests shall be conducted 

Deleted: Each owner or operator of a source 

subject to this subpart shall keep copies of all 

applicable reports and records required by this 

subpart for at least 5 years except as otherwise 

specified in this subpart.

Moved down [1]: All applicable records shall be 

maintained in such a manner that they can be readily 

accessed within 24 hours. Records may be 

maintained in hard copy or computer-readable form 

including, but not limited to, on paper, microfilm, 

computer, 

Deleted: floppy disk, magnetic tape, or microfiche.¶
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

0.05Σ ES1 = Sum of the residual emissions, megagrams per year, from all Group 1 storage 

vessels, as defined in §63.641. 

Σ ES2 = Sum of the emissions, megagrams per year, from all Group 2 storage vessels, as 

defined in §63.641. 

Σ EGLR1C = Sum of the residual emissions, megagrams per year, from all Group 1 gasoline 

loading racks, as defined in §63.641. 

Σ EGLR2 = Sum of the emissions, megagrams per year, from all Group 2 gasoline loading 

racks, as defined in §63.641. 

(R)Σ EMV1 = Sum of the residual emissions megagrams per year, from all Group 1 marine 

tank vessels, as defined in §63.641. 

R = 0.03 for existing sources, 0.02 for new sources. 

Σ EMV2 = Sum of the emissions, megagrams per year from all Group 2 marine tank vessels, 

as defined in §63.641. 

Σ EWW1C = Sum of the residual emissions from all Group 1 wastewater streams, as defined 

in §63.641. This term is calculated for each Group 1 stream according to the equation for EWWic

in §63.652(h)(6). 

Σ EWW2 = Sum of emissions from all Group 2 wastewater streams, as defined in §63.641. 

The emissions level represented by this equation is dependent on the collection of emission 

points in the source. The level is not fixed and can change as the emissions from each emission 

point change or as the number of emission points in the source changes. 

(h) The owner or operator of a new source subject to the requirements of this subpart shall 

control emissions of organic HAP’s to the level represented by the equation in paragraph (g) of 

this section. 

(i) The owner or operator of an existing source shall demonstrate compliance with the 

emission standard in paragraph (g) of this section by following the procedures specified in 

paragraph (k) of this section for all emission points, or by following the emissions averaging 

compliance approach specified in paragraph (l) of this section for specified emission points and 

the procedures specified in paragraph (k)(1) of this section. 

(j) The owner or operator of a new source shall demonstrate compliance with the emission 

standard in paragraph (h) of this section only by following the procedures in paragraph (k) of this 

section. The owner or operator of a new source may not use the emissions averaging compliance 

approach. 

Deleted: for all other emission points within the 

source
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(k) The owner or operator of an existing source may comply, and the owner or operator of a 

new source shall comply, with the applicable provisions in §§63.643 through 63.645, 63.646 or 

63.660, 63.647, 63.650, and 63.651, as specified in §63.640(h).

(1) The owner or operator using this compliance approach shall also comply with the 

requirements of §§63.648 and/or 63.649 or 63.661, 63.654, 63.655, 63.657, 63.658, 63.670 and 

63.671, as applicable. 

(2) The owner or operator using this compliance approach is not required to calculate the 

annual emission rate specified in paragraph (g) of this section. 

(l) The owner or operator of an existing source may elect to control some of the emission 

points within the source to different levels than specified under §§63.643 through 63.645, 63.646 

or 63.660, 63.647, 63.650, and 63.651, as applicable according to §63.640(h), by using an 

emissions averaging compliance approach as long as the overall emissions for the source do not 

exceed the emission level specified in paragraph (g) of this section. The owner or operator using 

emissions averaging shall meet the requirements in paragraphs (l)(1) and (2) of this section. 

(1) Calculate emission debits and credits for those emission points involved in the emissions 

average according to the procedures specified in §63.652; and 

(2) Comply with the requirements of §§63.648 and/or 63.649 or 63.661, 63.654, 63.652, 

63.653, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable. 

(m) A State may restrict the owner or operator of an existing source to using only the 

procedures in paragraph (k) of this section to comply with the emission standard in paragraph (g) 

of this section. Such a restriction would preclude the source from using an emissions averaging 

compliance approach. 

(n) At all times, the owner or operator must operate and maintain any affected source, 

including associated air pollution control equipment and monitoring equipment, in a manner 

consistent with safety and good air pollution control practices for minimizing emissions. The 

general duty to minimize emissions does not require the owner operator to make any further 

efforts to reduce emissions if levels required by the applicable standard have been achieved. 

Determination of whether a source is operating in compliance with operation and maintenance 

requirements will be based on information available to the Administrator which may include, but 

is not limited to, monitoring results, review of operation and maintenance procedures, review of 

operation and maintenance records, and inspection of the source. 

(o) [Reserved] 

(p) In response to an action to enforce the standards set forth in §§63.643 through 63.648, 

§§63.650 through 63.654, and §63.657 through 63.671, the owner or operator may assert an 

affirmative defense to a claim for civil penalties for violations of such standards that are caused 

by malfunction, as defined at §63.2. Appropriate penalties may be assessed if the owner or 

Deleted: miscellaneous process vent

Deleted: the storage vessel provisions in §

Deleted: , the wastewater provisions in §

Deleted: the gasoline loading rack provisions in §

Deleted: the marine tank vessel loading operation 

provisions in §

Deleted: of this subpart.

Deleted: §§

Deleted: l)(

Deleted: and 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

operator fails to meet the burden of proving all of the requirements in the affirmative defense. 

The affirmative defense shall not be available for claims for injunctive relief. 

(1) Assertion of affirmative defense. To establish the affirmative defense in any action to 

enforce such a standard, the owner or operator must timely meet the reporting requirements in 

paragraph (p)(2) of this section, and must prove by a preponderance of evidence that: 

(i) The violation: 

(A) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control 

equipment, process equipment, or a process to operate in a normal or usual manner; and 

(B) Could not have been prevented through careful planning, proper design or better 

operation and maintenance practices; and 

(C) Did not stem from any activity or event that could have been foreseen and avoided, or 

planned for; and 

(D) Was not part of a recurring pattern indicative of inadequate design, operation, or 

maintenance; and 

(ii) Repairs were made as expeditiously as possible when the violation occurred; and 

(iii) The frequency, amount, and duration of the violation (including any bypass) were 

minimized to the maximum extent practicable; and 

(iv) If the violation resulted from a bypass of control equipment or a process, then the 

bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and 

(v) All possible steps were taken to minimize the impact of the violation on ambient air 

quality, the environment and human health; and 

(vi) All emissions monitoring and control systems were kept in operation if at all possible, 

consistent with safety and good air pollution control practices; and 

(vii) All of the actions in response to the violation were documented by properly signed, 

contemporaneous operating logs; and 

(viii) At all times, the affected source was operated in a manner consistent with good 

practices for minimizing emissions; and 

(ix) A written root cause analysis has been prepared, the purpose of which is to determine, 

correct, and eliminate the primary causes of the malfunction and the violation resulting from the 

malfunction event at issue. The analysis shall also specify, using best monitoring methods and 

engineering judgment, the amount of any emissions that were the result of the malfunction. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) Report. The owner or operator seeking to assert an affirmative defense shall submit a 

written report to the Administrator, with all necessary supporting documentation, that explains 

how it has met the requirements set forth in paragraph (p)(1) of this section. This affirmative 

defense report shall be included in the first Periodic Report otherwise required after the initial 

occurrence of the violation of the relevant standard (which may be the end of any applicable 

averaging period). If such Periodic Report is due less than 45 days after the initial occurrence of 

the violation, the affirmative defense report may be included in the second Periodic Report due 

after the initial occurrence of the violation of the relevant standard. 

§ 63.643 Miscellaneous process vent provisions. 

(a) The owner or operator of a Group 1 miscellaneous process vent as defined in §63.641 

shall comply with the requirements of either paragraphs (a)(1) or (a)(2) of this section. 

(1) Reduce emissions of organic HAP’s using a flare. On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of 

§63.11(b) of subpart A or the requirements of §63.670. 

(2) Reduce emissions of organic HAP’s, using a control device, by 98 weight-percent or to 

a concentration of 20 parts per million by volume, on a dry basis, corrected to 3 percent oxygen, 

whichever is less stringent. Compliance can be determined by measuring either organic HAP’s or 

TOC’s using the procedures in §63.645. 

(b) If a boiler or process heater is used to comply with the percentage of reduction 

requirement or concentration limit specified in paragraph (a)(2) of this section, then the vent 

stream shall be introduced into the flame zone of such a device, or in a location such that the 

required percent reduction or concentration is achieved. Testing and monitoring is required only 

as specified in §§63.644(a) and 63.645 of this subpart. 

§ 63.644 Monitoring provisions for miscellaneous process vents. 

(a) Except as provided in paragraph (b) of this section, each owner or operator of a Group 1 

miscellaneous process vent that uses a combustion device to comply with the requirements in 

§63.643(a) shall install the monitoring equipment specified in paragraph (a)(1), (a)(2), (a)(3), or 

(a)(4) of this section, depending on the type of combustion device used. All monitoring 

equipment shall be installed, calibrated, maintained, and operated according to manufacturer’s 

specifications or other written procedures that provide adequate assurance that the equipment 

will monitor accurately and must meet the applicable minimum accuracy, calibration and quality 

control requirements specified in table 13 of this subpart. 

(1) Where an incinerator is used, a temperature monitoring device equipped with a 

continuous recorder is required. 

Deleted: that meets

Deleted: of this part
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) Where an incinerator other than a catalytic incinerator is used, a temperature monitoring 

device shall be installed in the firebox or in the ductwork immediately downstream of the firebox 

in a position before any substantial heat exchange occurs. 

(ii) Where a catalytic incinerator is used, temperature monitoring devices shall be installed 

in the gas stream immediately before and after the catalyst bed. 

(2) Where a flare is used prior to [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

a device (including but not limited to a thermocouple, an ultraviolet beam sensor, or an infrared 

sensor) capable of continuously detecting the presence of a pilot flame is required, or the 

requirements of §63.670 shall be met. Where a flare is used on and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the requirements of §63.670 shall be met. 

(3) Any boiler or process heater with a design heat input capacity greater than or equal to 44 

megawatt or any boiler or process heater in which all vent streams are introduced into the flame 

zone is exempt from monitoring. 

(4) Any boiler or process heater less than 44 megawatts design heat capacity where the vent 

stream is not introduced into the flame zone is required to use a temperature monitoring device in 

the firebox equipped with a continuous recorder. 

(b) An owner or operator of a Group 1 miscellaneous process vent may request approval to 

monitor parameters other than those listed in paragraph (a) of this section. The request shall be 

submitted according to the procedures specified in §63.655(h). Approval shall be requested if the 

owner or operator: 

(1) Uses a control device other than an incinerator, boiler, process heater, or flare; or 

(2) Uses one of the control devices listed in paragraph (a) of this section, but seeks to 

monitor a parameter other than those specified in paragraph (a) of this section. 

(c) The owner or operator of a Group 1 miscellaneous process vent using a vent system that 

contains bypass lines that could divert a vent stream away from the control device used to 

comply with paragraph (a) of this section shall comply with either paragraph (c)(1) or (2) of this 

section. Use of the bypass at any time to divert a Group 1 miscellaneous process vent stream is 

an emissions standards violation. Equipment such as low leg drains, high point bleeds, and 

equipment subject to §63.648 are not subject to this paragraph. 

(1) Install, operate, calibrate, and maintain a continuous parameter monitoring system for 

flow, as specified in paragraphs (c)(1)(i) through (iii) of this section. 

(i) Install a continuous parameter monitoring system for flow at the entrance to any bypass 

line. The continuous parameter monitoring system must record the volume of the gas stream that 

Deleted: c)(

Deleted: , analyzer vents, open-ended valves or 

lines, pressure relief valves needed for safety reasons

Deleted: , and operate

Deleted: indicator that determines whether a vent 

stream flow is present at least once every hour

Deleted: Records shall be generated as specified in 

§63.655(h) and (i). The 

Deleted: indicator shall be installed 

Deleted: that could divert the vent stream away 

from the control device to the atmosphere; or
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

bypassed the control device and must meet the applicable minimum accuracy, calibration and 

quality control requirements specified in table 13 of this subpart. 

(ii) Equip the continuous parameter monitoring system for flow with an alarm system that 

will alert an operator immediately and automatically when flow is detected in the bypass line. 

Locate the alarm such that an operator can easily detect and recognize the alert. 

(iii) Reports and records shall be generated as specified in §63.655(g) and (i).

(2) Secure the bypass line valve in the non-diverting position with a car-seal or a lock-andkey type configuration. A visual inspection of the seal or closure mechanism shall be performed 

at least once every month to ensure that the valve is maintained in the non-diverting position and

that the vent stream is not diverted through the bypass line. 

(d) The owner or operator shall establish a range that ensures compliance with the emissions 

standard for each parameter monitored under paragraphs (a) and (b) of this section. In order to 

establish the range, the information required in §63.655(f)(3) shall be submitted in the 

Notification of Compliance Status report. 

(e) Each owner or operator of a control device subject to the monitoring provisions of this 

section shall operate the control device in a manner consistent with the minimum and/or 

maximum operating parameter value or procedure required to be monitored under paragraphs (a) 

and (b) of this section. Operation of the control device in a manner that constitutes a period of 

excess emissions, as defined in §63.655(g)(6), or failure to perform procedures required by this 

section shall constitute a violation of the applicable emission standard of this subpart. 

§ 63.645 Test methods and procedures for miscellaneous process vents. 

(a) To demonstrate compliance with §63.643, an owner or operator shall follow §63.116 

except for §63.116 (a)(1), (d) and (e) of subpart G of this part except as provided in paragraphs 

(b) through (d) and paragraph (i) of this section. 

(b) All references to §63.113(a)(1) or (a)(2) in §63.116 of subpart G of this part shall be 

replaced with §63.643(a)(1) or (a)(2), respectively. 

(c) In §63.116(c)(4)(ii)(C) of subpart G of this part, organic HAP’s in the list of HAP’s in 

table 1 of this subpart shall be considered instead of the organic HAP’s in table 2 of subpart F of 

this part. 

(d) All references to §63.116(b)(1) or (b)(2) shall be replaced with paragraphs (d)(1) and 

(d)(2) of this section, respectively. 

(1) Any boiler or process heater with a design heat input capacity of 44 megawatts or 

greater. 

Deleted: closed

Deleted: closed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) Any boiler or process heater in which all vent streams are introduced into the flame 

zone. 

(e) For purposes of determining the TOC emission rate, as specified under paragraph (f) of 

this section, the sampling site shall be after the last product recovery device (as defined in 

§63.641 of this subpart) (if any recovery devices are present) but prior to the inlet of any control 

device (as defined in §63.641 of this subpart) that is present, prior to any dilution of the process 

vent stream, and prior to release to the atmosphere. 

(1) Methods 1 or 1A of 40 CFR part 60, Appendix A-1, as appropriate, shall be used for 

selection of the sampling site. For vents smaller than 0.10 meter in diameter, sample at the center 

of the vent. 

(2) No traverse site selection method is needed for vents smaller than 0.10 meter in 

diameter. 

(f) Except as provided in paragraph (g) of this section, an owner or operator seeking to 

demonstrate that a process vent TOC mass flow rate is less than 33 kilograms per day for an 

existing source or less than 6.8 kilograms per day for a new source in accordance with the Group 

2 process vent definition of this subpart shall determine the TOC mass flow rate by the following 

procedures: 

(1) The sampling site shall be selected as specified in paragraph (e) of this section. 

(2) The gas volumetric flow rate shall be determined using Methods 2, 2A, 2C, 2D, or 2F of 

40 CFR part 60, Appendix A-1 or Method 2G of 40 CFR part 60, Appendix A-2, as appropriate. 

(3) Method 18 or Method 25A of 40 CFR part 60, appendix A shall be used to measure 

concentration; alternatively, any other method or data that has been validated according to the 

protocol in Method 301 of appendix A of this part may be used. If Method 25A is used, and the 

TOC mass flow rate calculated from the Method 25A measurement is greater than or equal to 33 

kilograms per day for an existing source or 6.8 kilograms per day for a new source, Method 18 

may be used to determine any non-VOC hydrocarbons that may be deducted to calculate the 

TOC (minus non-VOC hydrocarbons) concentration and mass flow rate. The following 

procedures shall be used to calculate parts per million by volume concentration: 

(i) The minimum sampling time for each run shall be 1 hour in which either an integrated 

sample or four grab samples shall be taken. If grab sampling is used, then the samples shall be 

taken at approximately equal intervals in time, such as 15-minute intervals during the run. 

(ii) The TOC concentration (CTOC) is the sum of the concentrations of the individual 

components and shall be computed for each run using the following equation if Method 18 is 

used: 

Deleted: a

Deleted: 2D

Deleted: a
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

X

C

C

x

i

n

j

ji

TOC

    















 1 1

where: 

CTOC = Concentration of TOC (minus methane and ethane), dry basis, parts per million by 

volume. 

Cji = Concentration of sample component j of the sample i, dry basis, parts per million by 

volume. 

n = Number of components in the sample. 

x = Number of samples in the sample run. 

(4) The emission rate of TOC (minus methane and ethane) (ETOC) shall be calculated using 

the following equation if Method 18 is used: 

s

n

j

E K2 CjM jQ



 



  1

where: 

E = Emission rate of TOC (minus methane and ethane) in the sample, kilograms per day. 

K2 = Constant, 5.986 × 10−5

 (parts per million)−1 (gram-mole per standard cubic meter) 

(kilogram per gram) (minute per day), where the standard temperature (standard cubic meter) is 

at 20 °C. 

Cj = Concentration on a dry basis of organic compound j in parts per million as measured by 

Method 18 of 40 CFR part 60, appendix A, as indicated in paragraph (f)(3) of this section. Cj

includes all organic compounds measured minus methane and ethane. 

Mj = Molecular weight of organic compound j, gram per gram-mole. 

Qs = Vent stream flow rate, dry standard cubic meters per minute, at a temperature of 20 °C. 

(5) If Method 25A is used, the emission rate of TOC (ETOC) shall be calculated using the 

following equation: 

ETOC  K2CTOCMQs

where: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

ETOC =Emission rate of TOC (minus methane and ethane) in the sample, kilograms per day. 

K2 =Constant, 5.986×10–5 (parts per million)−1

 (gram-mole per standard cubic meter) 

(kilogram per gram)(minute per day), where the standard temperature (standard cubic meter) is at 

20 °C. 

CTOC = Concentration of TOC on a dry basis in parts per million volume as measured by 

Method 25A of 40 CFR part 60, appendix A, as indicated in paragraph (f)(3) of this section. 

M = Molecular weight of organic compound used to express units of CTOC, gram per grammole. 

Qs = Vent stream flow rate, dry standard cubic meters per minute, at a temperature of 20 °C. 

(g) Engineering assessment may be used to determine the TOC emission rate for the 

representative operating condition expected to yield the highest daily emission rate. 

(1) Engineering assessment includes, but is not limited to, the following: 

(i) Previous test results provided the tests are representative of current operating practices at 

the process unit. 

(ii) Bench-scale or pilot-scale test data representative of the process under representative 

operating conditions. 

(iii) TOC emission rate specified or implied within a permit limit applicable to the process 

vent. 

(iv) Design analysis based on accepted chemical engineering principles, measurable process 

parameters, or physical or chemical laws or properties. Examples of analytical methods include, 

but are not limited to: 

(A) Use of material balances based on process stoichiometry to estimate maximum TOC 

concentrations; 

(B) Estimation of maximum flow rate based on physical equipment design such as pump or 

blower capacities; and 

(C) Estimation of TOC concentrations based on saturation conditions. 

(v) All data, assumptions, and procedures used in the engineering assessment shall be 

documented. 

(h) The owner or operator of a Group 2 process vent shall recalculate the TOC emission rate 

for each process vent, as necessary, whenever process changes are made to determine whether 

the vent is in Group 1 or Group 2. Examples of process changes include, but are not limited to, 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

changes in production capacity, production rate, or catalyst type, or whenever there is 

replacement, removal, or addition of recovery equipment. For purposes of this paragraph, 

process changes do not include: process upsets; unintentional, temporary process changes; and 

changes that are within the range on which the original calculation was based. 

(1) The TOC emission rate shall be recalculated based on measurements of vent stream flow 

rate and TOC as specified in paragraphs (e) and (f) of this section, as applicable, or on best 

engineering assessment of the effects of the change. Engineering assessments shall meet the 

specifications in paragraph (g) of this section. 

(2) Where the recalculated TOC emission rate is greater than 33 kilograms per day for an 

existing source or greater than 6.8 kilograms per day for a new source, the owner or operator 

shall submit a report as specified in §63.655(f), (g), or (h) and shall comply with the appropriate 

provisions in §63.643 by the dates specified in §63.640. 

(i) A compliance determination for visible emissions shall be conducted within 150 days of 

the compliance date using Method 22 of 40 CFR part 60, appendix A, to determine visible 

emissions. 

§ 63.646 Storage vessel provisions. 

Upon a demonstration of compliance with the standards in §63.660 by the compliance dates 

specified in §63.640(h), the standards in this section shall no longer apply. 

(a) Each owner or operator of a Group 1 storage vessel subject to this subpart shall comply 

with the requirements of §§63.119 through 63.121 except as provided in paragraphs (b) through 

(l) of this section. 

(b) As used in this section, all terms not defined in §63.641 shall have the meaning given 

them in 40 CFR part 63, subparts A or G. The Group 1 storage vessel definition presented in 

§63.641 shall apply in lieu of the Group 1 storage vessel definitions presented in tables 5 and 6 

of §63.119 of subpart G of this part. 

(1) An owner or operator may use good engineering judgment or test results to determine 

the stored liquid weight percent total organic HAP for purposes of group determination. Data, 

assumptions, and procedures used in the determination shall be documented. 

(2) When an owner or operator and the Administrator do not agree on whether the annual 

average weight percent organic HAP in the stored liquid is above or below 4 percent for a 

storage vessel at an existing source or above or below 2 percent for a storage vessel at a new 

source, an appropriate method (based on the type of liquid stored) as published by EPA or a 

consensus-based standards organization shall be used. Consensus-based standards organizations 

include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. 

Box CB700, West Conshohocken, Pennsylvania 19428–B2959, (800) 262–1373, 

http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th 

floor, Washington, DC 20036, (202) 293–8020, http://www.ansi.org), the American Gas 

Deleted: Method 18 of 40 CFR part 60, appendix 

A
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 

824–7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016–5990, (800) 843–2763, http://www.asme.org), the 

American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005–4070, (202) 

682–8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 

Travis Street, Suite 1675, Houston, TX 77002, (713) 356–0060, http://www.naesb.org).

(c) The following paragraphs do not apply to storage vessels at existing sources subject to 

this subpart: §63.119 (b)(5), (b)(6), (c)(2), and (d)(2). 

(d) References shall apply as specified in paragraphs (d)(1) through (d)(10) of this section. 

(1) All references to §63.100(k) of subpart F of this part (or the schedule provisions and the 

compliance date) shall be replaced with §63.640(h), 

(2) All references to April 22, 1994 shall be replaced with August 18, 1995. 

(3) All references to December 31, 1992 shall be replaced with July 15, 1994. 

(4) All references to the compliance dates specified in §63.100 of subpart F shall be 

replaced with §63.640 (h) through (m). 

(5) All references to §63.150 in §63.119 of subpart G of this part shall be replaced with 

§63.652. 

(6) All references to §63.113(a)(2) of subpart G shall be replaced with §63.643(a)(2) of this 

subpart. 

(7) All references to §63.126(b)(1) of subpart G shall be replaced with §63.422(b) of 

subpart R of this part. 

(8) All references to §63.128(a) of subpart G shall be replaced with §63.425, paragraphs (a) 

through (c) and (e) through (h) of subpart R of this part. 

(9) All references to §63.139(d)(1) in §63.120(d)(1)(ii) of subpart G are not applicable. For 

sources subject to this subpart, such references shall mean that 40 CFR 61.355 is applicable. 

(10) All references to §63.139(c) in §63.120(d)(1)(ii) of subpart G are not applicable. For 

sources subject to this subpart, such references shall mean that §63.647 of this subpart is 

applicable. 

(e) When complying with the inspection requirements of §63.120 of subpart G of this part, 

owners and operators of storage vessels at existing sources subject to this subpart are not 

required to comply with the provisions for gaskets, slotted membranes, and sleeve seals. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(f) The following paragraphs (f)(1), (f)(2), and (f)(3) of this section apply to Group 1 

storage vessels at existing sources: 

(1) If a cover or lid is installed on an opening on a floating roof, the cover or lid shall 

remain closed except when the cover or lid must be open for access. 

(2) Rim space vents are to be set to open only when the floating roof is not floating or when 

the pressure beneath the rim seal exceeds the manufacturer’s recommended setting. 

(3) Automatic bleeder vents are to be closed at all times when the roof is floating except 

when the roof is being floated off or is being landed on the roof leg supports. 

(g) Failure to perform inspections and monitoring required by this section shall constitute a 

violation of the applicable standard of this subpart. 

(h) References in §§63.119 through 63.121 to §63.122(g)(1), §63.151, and references to 

initial notification requirements do not apply. 

(i) References to the Implementation Plan in §63.120, paragraphs (d)(2) and (d)(3)(i) shall 

be replaced with the Notification of Compliance Status report. 

(j) References to the Notification of Compliance Status report in §63.152(b) mean the 

Notification of Compliance Status required by §63.655(f). 

(k) References to the Periodic Reports in §63.152(c) mean the Periodic Report required by 

§63.655(g). 

(l) The State or local permitting authority can waive the notification requirements of 

§§63.120(a)(5), 63.120(a)(6), 63.120(b)(10)(ii), and 63.120(b)(10)(iii) for all or some storage 

vessels at petroleum refineries subject to this subpart. The State or local permitting authority may 

also grant permission to refill storage vessels sooner than 30 days after submitting the 

notifications in §63.120(a)(6) or §63.120(b)(10)(iii) for all storage vessels at a refinery or for 

individual storage vessels on a case-by-case basis. 

§ 63.647 Wastewater provisions. 

(a) Except as provided in paragraphs (b) and (c) of this section, each owner or operator of a 

Group 1 wastewater stream shall comply with the requirements of §§61.340 through 61.355 of 

this chapter for each process wastewater stream that meets the definition in §63.641. 

(b) As used in this section, all terms not defined in §63.641 shall have the meaning given 

them in the Clean Air Act or in 40 CFR part 61, subpart FF, §61.341. 

(c) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 YEARS 

Deleted: 40 CFR part 61, subpart FF
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable requirements of part 61, subpart FF 

of this chapter, or the requirements of §63.670. 

(d) Each owner or operator required under subpart FF of 40 CFR part 61 to perform 

periodic measurement of benzene concentration in wastewater, or to monitor process or control 

device operating parameters shall operate in a manner consistent with the minimum or maximum 

(as appropriate) permitted concentration or operating parameter values. Operation of the process, 

treatment unit, or control device resulting in a measured concentration or operating parameter 

value outside the permitted limits shall constitute a violation of the emission standards. Failure to 

perform required leak monitoring for closed vent systems and control devices or failure to repair 

leaks within the time period specified in subpart FF of 40 CFR part 61 shall constitute a violation 

of the standard. 

§ 63.648 Equipment leak standards. 

(a) Each owner or operator of an existing source subject to the provisions of this subpart 

shall comply with the provisions of part 60, subpart VV of this chapter and paragraph (b) of this 

section except as provided in paragraphs (a)(1), (a)(2), and (c) through (i) of this section. Each 

owner or operator of a new source subject to the provisions of this subpart shall comply with 

subpart H of this part except as provided in paragraphs (c) through (i) of this section. As an 

alternative to the monitoring requirements of part 60, subpart VV of this chapter or subpart H of 

this part, as applicable, the owner or operator may elect to monitor equipment leaks following 

the provisions in §63.661.

(1) For purposes of compliance with this section, the provisions of 40 CFR part 60, subpart 

VV apply only to equipment in organic HAP service, as defined in §63.641 of this subpart. 

(2) Calculation of percentage leaking equipment components for subpart VV of 40 CFR 

part 60 may be done on a process unit basis or a sourcewide basis. Once the owner or operator 

has decided, all subsequent calculations shall be on the same basis unless a permit change is 

made. 

(3) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable requirements of part 60, subpart 

VV of this chapter, or the requirements of §63.670. 

(b) The use of monitoring data generated before August 18, 1995 to qualify for less frequent 

monitoring of valves and pumps as provided under 40 CFR part 60 subpart VV or subpart H of 

this part and paragraph (c) of this section (i.e., quarterly or semiannually) is governed by the 

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

Deleted: 40 CFR 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Monitoring data must meet the test methods and procedures specified in §60.485(b) of 

40 CFR part 60, subpart VV or §63.180(b)(1) through (b)(5) of subpart H of this part except for 

minor departures. 

(2) Departures from the criteria specified in §60.485(b) of 40 CFR part 60 subpart VV or 

§63.180(b)(1) through (b)(5) of subpart H of this part or from the monitoring frequency specified 

in subpart VV or in paragraph (c) of this section (such as every 6 weeks instead of monthly or 

quarterly) are minor and do not significantly affect the quality of the data. An example of a 

minor departure is monitoring at a slightly different frequency (such as every 6 weeks instead of 

monthly or quarterly). Failure to use a calibrated instrument is not considered a minor departure. 

(c) In lieu of complying with the existing source provisions of paragraph (a) in this section, 

an owner or operator may elect to comply with the requirements of §§63.161 through 63.169, 

63.171, 63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 of subpart H of this part except as 

provided in paragraphs (c)(1) through (c)(11) and (e) through (i) of this section. 

(1) The instrument readings that define a leak for light liquid pumps subject to §63.163 of 

subpart H of this part and gas/vapor and light liquid valves subject to §63.168 of subpart H of 

this part are specified in table 2 of this subpart. 

(2) In phase III of the valve standard, the owner or operator may monitor valves for leaks as 

specified in paragraphs (c)(2)(i) or (c)(2)(ii) of this section. 

(i) If the owner or operator does not elect to monitor connectors, then the owner or operator 

shall monitor valves according to the frequency specified in table 8 of this subpart. 

(ii) If an owner or operator elects to monitor connectors according to the provisions of 

§63.649, paragraphs (b), (c), or (d), then the owner or operator shall monitor valves at the 

frequencies specified in table 9 of this subpart. If an owner or operator elects to comply with 

§63.649, the owner or operator cannot also elect to comply with §63.661.

(3) The owner or operator shall decide no later than the first required monitoring period 

after the phase I compliance date specified in §63.640(h) whether to calculate the percentage 

leaking valves on a process unit basis or on a sourcewide basis. Once the owner or operator has 

decided, all subsequent calculations shall be on the same basis unless a permit change is made. 

(4) The owner or operator shall decide no later than the first monitoring period after the 

phase III compliance date specified in §63.640(h) whether to monitor connectors according to 

the provisions in §63.649, paragraphs (b), (c), or (d). 

(5) Connectors in gas/vapor service or light liquid service are subject to the requirements for 

connectors in heavy liquid service in §63.169 of subpart H of this part (except for the agitator 

provisions). The leak definition for valves, connectors, and instrumentation systems subject to 

§63.169 is 1,000 parts per million. 

Deleted: 10
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(6) In phase III of the pump standard, except as provided in paragraph (c)(7) of this section, 

owners or operators that achieve less than 10 percent of light liquid pumps leaking or three light 

liquid pumps leaking, whichever is greater, shall monitor light liquid pumps monthly. 

(7) Owners or operators that achieve less than 3 percent of light liquid pumps leaking or one 

light liquid pump leaking, whichever is greater, shall monitor light liquid pumps quarterly. 

(8) An owner or operator may make the election described in paragraphs (c)(3) and (c)(4) of 

this section at any time except that any election to change after the initial election shall be treated 

as a permit modification according to the terms of part 70 of this chapter. 

(9) When complying with the requirements of §63.168(e)(3)(i), non-repairable valves shall 

be included in the calculation of percent leaking valves the first time the valve is identified as 

leaking and non-repairable. Otherwise, a number of non-repairable valves up to a maximum of 1 

percent per year of the total number of valves in organic HAP service up to a maximum of 3 

percent may be excluded from calculation of percent leaking valves for subsequent monitoring 

periods. When the number of non-repairable valves exceeds 3 percent of the total number of 

valves in organic HAP service, the number of non-repairable valves exceeding 3 percent of the 

total number shall be included in the calculation of percent leaking valves. 

(10) If in phase III of the valve standard any valve is designated as being leakless, the owner 

or operator has the option of following the provisions of 40 CFR 60.482–7(f). If an owner or 

operator chooses to comply with the provisions of 40 CFR 60.482–7(f), the valve is exempt from 

the valve monitoring provisions of §63.168 of subpart H of this part. 

(11) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable requirements of §§63.172 and 

63.180, or the requirements of §63.670. 

(d) Upon startup of new sources, the owner or operator shall comply with §63.163(a)(1)(ii) 

of subpart H of this part for light liquid pumps and §63.168(a)(1)(ii) of subpart H of this part for 

gas/vapor and light liquid valves. 

(e) For reciprocating pumps in heavy liquid service and agitators in heavy liquid service, 

owners and operators are not required to comply with the requirements in §63.169 of subpart H 

of this part. 

(f) Reciprocating pumps in light liquid service are exempt from §§63.163 and 60.482 if 

recasting the distance piece or reciprocating pump replacement is required. 

(g) Compressors in hydrogen service are exempt from the requirements of paragraphs (a) 

and (c) of this section if an owner or operator demonstrates that a compressor is in hydrogen 

service. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Each compressor is presumed not to be in hydrogen service unless an owner or operator 

demonstrates that the piece of equipment is in hydrogen service. 

(2) For a piece of equipment to be considered in hydrogen service, it must be determined 

that the percentage hydrogen content can be reasonably expected always to exceed 50 percent by 

volume. 

(i) For purposes of determining the percentage hydrogen content in the process fluid that is 

contained in or contacts a compressor, the owner or operator shall use either: 

(A) Procedures that conform to those specified in §60.593(b)(2) of 40 part 60, subpart 

GGG. 

(B) Engineering judgment to demonstrate that the percentage content exceeds 50 percent by 

volume, provided the engineering judgment demonstrates that the content clearly exceeds 50 

percent by volume. 

(1) When an owner or operator and the Administrator do not agree on whether a piece of 

equipment is in hydrogen service, the procedures in paragraph (g)(2)(i)(A) of this section shall 

be used to resolve the disagreement. 

(2) If an owner or operator determines that a piece of equipment is in hydrogen service, the 

determination can be revised only by following the procedures in paragraph (g)(2)(i)(A) of this 

section. 

(h) Each owner or operator of a source subject to the provisions of this subpart must 

maintain all records for a minimum of 5 years. 

(i) Reciprocating compressors are exempt from seal requirements if recasting the distance 

piece or compressor replacement is required. 

(j) Except as specified in paragraph (j)(4) of this section, the owner or operator must comply 

with the requirements specified in paragraphs (j)(1) and (2) of this section for relief valves in 

organic HAP gas or vapor service instead of the pressure relief device requirements of §60.482-4 

or §63.165, as applicable. Except as specified in paragraph (j)(4) of this section, the owner or 

operator must also comply with the requirements specified in paragraph (j)(3) of this section for 

all relief valves in organic HAP service. 

(1) Operating requirements. Except during a pressure release, operate each relief valve in 

organic HAP gas or vapor service with an instrument reading of less than 500 ppm above 

background as detected by Method 21 of 40 CFR part 60, appendix A. 

(2) Pressure release requirements. For relief valves in organic HAP gas or vapor service, 

the owner or operator must comply with either paragraph (j)(2)(i) or (ii) of this section following 

a pressure release. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) If the relief valve does not consist of or include a rupture disk, conduct instrument 

monitoring, as specified in §60.485(b) or §63.180(c), as applicable, no later than 5 calendar days 

after the relief valve returns to organic HAP gas or vapor service following a pressure release to 

verify that the relief valve is operating with an instrument reading of less than 500 ppm. 

(ii) If the relief valve consists of or includes a rupture disk, install a replacement disk as 

soon as practicable after a pressure release, but no later than 5 calendar days after the pressure 

release. The owner or operator must also conduct instrument monitoring, as specified in 

§60.485(b) or §63.180(c), as applicable, no later than 5 calendar days after the relief valve 

returns to organic HAP gas or vapor service following a pressure release to verify that the relief 

valve is operating with an instrument reading of less than 500 ppm. 

(3) Pressure release management. Except as specified in paragraph (j)(4) of this section, 

emissions of organic HAP to the atmosphere from relief valves in organic HAP service are 

prohibited, and on or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the owner or 

operator shall comply with the requirements specified in paragraphs (j)(3)(i) and (ii) of this 

section for all relief valves in organic HAP service. 

(i) The owner or operator must equip each relief valve in organic HAP service with a 

device(s) or use a monitoring system that is capable of: 1) identifying the pressure release; 2) 

recording the time and duration of each pressure release; and 3) notifying operators immediately 

that a pressure release is occurring. The device or monitoring system may be either specific to 

the pressure relief device itself or may be associated with the process system or piping, sufficient 

to indicate a pressure release to the atmosphere. Examples of these types of devices and systems 

include, but are not limited to, a rupture disk indicator, magnetic sensor, motion detector on the 

pressure relief valve stem, flow monitor, or pressure monitor. 

 (ii) If any relief valve in organic HAP service vents or releases to atmosphere as a result of 

a pressure release event, the owner or operator must calculate the quantity of organic HAP 

released during each pressure release event and report this quantity as required in 

§63.655(g)(10)(iii). Calculations may be based on data from the relief valve monitoring alone or 

in combination with process parameter monitoring data and process knowledge. 

(4) Relief valves routed to a control device. If all releases and potential leaks from a relief 

valve in organic HAP service are routed through a closed vent system to a control device, the 

owner or operator is not required to comply with paragraphs (j)(1), (2) or (3) (if applicable) of 

this section. Both the closed vent system and control device (if applicable) must meet the 

requirements of §63.644. When complying with this paragraph, all references to “Group 1 

miscellaneous process vent” in 63.644 mean “relief valve.” 

Deleted: pressure releases

Deleted: excess emissions
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§ 63.649 Alternative means of emission limitation: Connectors in gas/vapor service and 

light liquid service. 

(a) If an owner or operator elects to monitor valves according to the provisions of 

§63.648(c)(2)(ii), the owner or operator shall implement one of the connector monitoring 

programs specified in paragraphs (b), (c), or (d) of this section. 

(b) Random 200 connector alternative. The owner or operator shall implement a random 

sampling program for accessible connectors of 2.0 inches nominal diameter or greater. The 

program does not apply to inaccessible or unsafe-to-monitor connectors, as defined in §63.174 of 

subpart H. The sampling program shall be implemented source-wide. 

(1) Within the first 12 months after the phase III compliance date specified in §63.640(h), a 

sample of 200 connectors shall be randomly selected and monitored using Method 21 of 40 CFR 

part 60, appendix A. 

(2) The instrument reading that defines a leak is 1,000 parts per million. 

(3) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 

calendar days after the leak is detected except as provided in paragraph (e) of this section. A first 

attempt at repair shall be made no later than 5 calendar days after the leak is detected. 

(4) If a leak is detected, the connector shall be monitored for leaks within the first 3 months 

after its repair. 

(5) After conducting the initial survey required in paragraph (b)(1) of this section, the owner 

or operator shall conduct subsequent monitoring of connectors at the frequencies specified in 

paragraphs (b)(5)(i) through (b)(5)(iv) of this section. 

(i) If the percentage leaking connectors is 2.0 percent or greater, the owner or operator shall 

survey a random sample of 200 connectors once every 6 months. 

(ii) If the percentage leaking connectors is 1.0 percent or greater but less than 2.0 percent, 

the owner or operator shall survey a random sample of 200 connectors once per year. 

(iii) If the percentage leaking connectors is 0.5 percent or greater but less than 1.0 percent, 

the owner or operator shall survey a random sample of 200 connectors once every 2 years. 

(iv) If the percentage leaking connectors is less than 0.5 percent, the owner or operator shall 

survey a random sample of 200 connectors once every 4 years. 

(6) Physical tagging of the connectors to indicate that they are subject to the monitoring 

provisions is not required. Connectors may be identified by the area or length of pipe and need 

not be individually identified. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(c) Connector inspection alternative. The owner or operator shall implement a program to 

monitor all accessible connectors in gas/vapor service that are 2.0 inches (nominal diameter) or 

greater and inspect all accessible connectors in light liquid service that are 2 inches (nominal 

diameter) or greater as described in paragraphs (c)(1) through (c)(7) of this section. The program 

does not apply to inaccessible or unsafe-to-monitor connectors. 

(1) Within 12 months after the phase III compliance date specified in §63.640(h), all 

connectors in gas/vapor service shall be monitored using Method 21 of 40 CFR part 60 appendix 

A. The instrument reading that defines a leak is 1,000 parts per million. 

(2) All connectors in light liquid service shall be inspected for leaks. A leak is detected if 

liquids are observed to be dripping at a rate greater than three drops per minute. 

(3) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 

calendar days after the leak is detected except as provided in paragraph (e) of this section. A first 

attempt at repair shall be made no later than 5 calendar days after the leak is detected. 

(4) If a leak is detected, connectors in gas/vapor service shall be monitored for leaks within 

the first 3 months after repair. Connectors in light liquid service shall be inspected for indications 

of leaks within the first 3 months after repair. A leak is detected if liquids are observed to be 

dripping at a rate greater than three drops per minute. 

(5) After conducting the initial survey required in paragraphs (c)(1) and (c)(2) of this 

section, the owner or operator shall conduct subsequent monitoring at the frequencies specified 

in paragraphs (c)(5)(i) through (c)(5)(iii) of this section. 

(i) If the percentage leaking connectors is 2.0 percent or greater, the owner or operator shall 

monitor or inspect, as applicable, the connectors once per year. 

(ii) If the percentage leaking connectors is 1.0 percent or greater but less than 2.0 percent, 

the owner or operator shall monitor or inspect, as applicable, the connectors once every 2 years. 

(iii) If the percentage leaking connectors is less than 1.0 percent, the owner or operator shall 

monitor or inspect, as applicable, the connectors once every 4 years. 

(6) The percentage leaking connectors shall be calculated for connectors in gas/vapor 

service and for connectors in light liquid service. The data for the two groups of connectors shall 

not be pooled for the purpose of determining the percentage leaking connectors. 

(i) The percentage leaking connectors shall be calculated as follows: 

% CL = [(CL−CAN)/Ct+Cc)]×100 

where: 

% CL = Percentage leaking connectors. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

CL = Number of connectors including nonrepairables, measured at 1,000 parts per million or 

greater, by Method 21 of 40 CFR part 60, appendix A. 

CAN = Number of allowable nonrepairable connectors, as determined by monitoring, not to 

exceed 3 percent of the total connector population, Ct. 

Ct = Total number of monitored connectors, including nonrepairables, in the process unit. 

Cc = Optional credit for removed connectors=0.67×net number (i.e., the total number of 

connectors removed minus the total added) of connectors in organic HAP service removed from 

the process unit after the applicability date set forth in §63.640(h)(4)(iii) for existing process 

units, and after the date of start-up for new process units. If credits are not taken, then Cc = 0. 

(ii) Nonrepairable connectors shall be included in the calculation of percentage leaking 

connectors the first time the connector is identified as leaking and nonrepairable. Otherwise, a 

number of nonrepairable connectors up to a maximum of 1 percent per year of the total number 

of connectors in organic HAP service up to a maximum of 3 percent may be excluded from 

calculation of percentage leaking connectors for subsequent monitoring periods. 

(iii) If the number of nonrepairable connectors exceeds 3 percent of the total number of 

connectors in organic HAP service, the number of nonrepairable connectors exceeding 3 percent 

of the total number shall be included in the calculation of the percentage leaking connectors. 

(7) Physical tagging of the connectors to indicate that they are subject to the monitoring 

provisions is not required. Connectors may be identified by the area or length of pipe and need 

not be individually identified. 

(d) Subpart H program. The owner or operator shall implement a program to comply with 

the provisions in §63.174 of this part. 

(e) Delay of repair of connectors for which leaks have been detected is allowed if repair is 

not technically feasible by normal repair techniques without a process unit shutdown. Repair of 

this equipment shall occur by the end of the next process unit shutdown. 

(1) Delay of repair is allowed for equipment that is isolated from the process and that does 

not remain in organic HAP service. 

(2) Delay of repair for connectors is also allowed if: 

(i) The owner or operator determines that emissions of purged material resulting from 

immediate repair would be greater than the fugitive emissions likely to result from delay of 

repair, and 

(ii) When repair procedures are accomplished, the purged material would be collected and 

destroyed or recovered in a control device. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(f) Any connector that is designated as an unsafe-to-repair connector is exempt from the 

requirements of paragraphs (b)(3) and (b)(4), (c)(3) and (c)(4), or (d) of this section if: 

(1) The owner or operator determines that repair personnel would be exposed to an 

immediate danger as a consequence of complying with paragraphs (b)(3) and (b)(4), (c)(3) and 

(c)(4), of this section; or 

(2) The connector will be repaired before the end of the next scheduled process unit 

shutdown. 

(g) The owner or operator shall maintain records to document that the connector monitoring 

or inspections have been conducted as required and to document repair of leaking connectors as 

applicable. 

§ 63.650 Gasoline loading rack provisions. 

(a) Except as provided in paragraphs (b) through (d) of this section, each owner or operator 

of a Group 1 gasoline loading rack classified under Standard Industrial Classification code 2911 

located within a contiguous area and under common control with a petroleum refinery shall 

comply with subpart R, §§63.421, 63.422(a) through (c) and (e), 63.425(a) through (c) and (i), 

63.425(e) through (h), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3), and (k). 

(b) As used in this section, all terms not defined in §63.641 shall have the meaning given 

them in subpart A or in 40 CFR part 63, subpart R. The §63.641 definition of “affected source” 

applies under this section. 

(c) Gasoline loading racks regulated under this subpart are subject to the compliance dates 

specified in §63.640(h). 

(d) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable requirements of subpart R of this 

part, or the requirements of §63.670. 

§ 63.651 Marine tank vessel loading operation provisions. 

(a) Except as provided in paragraphs (b) through (e) of this section, each owner or operator 

of a marine tank vessel loading operation located at a petroleum refinery shall comply with the 

requirements of §§63.560 through 63.568. 

(b) As used in this section, all terms not defined in §63.641 shall have the meaning given 

them in subpart A or in 40 CFR part 63, subpart Y. The §63.641 definition of “affected source” 

applies under this section. 

Deleted: c

Deleted: d
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(c) The notification reports under §63.567(b) are not required. 

(d) The compliance time of 4 years after promulgation of 40 CFR part 63, subpart Y does 

not apply. The compliance time is specified in §63.640(h)(1). 

(e) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable requirements of subpart Y of this 

part, or the requirements of §63.670. 

§ 63.652 Emissions averaging provisions. 

(a) This section applies to owners or operators of existing sources who seek to comply with 

the emission standard in §63.642(g) by using emissions averaging according to §63.642(l) rather 

than following the provisions of §§63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 

63.651. Existing marine tank vessel loading operations located at the Valdez Marine Terminal 

source may not comply with the standard by using emissions averaging. 

(b) The owner or operator shall develop and submit for approval an Implementation Plan 

containing all of the information required in §63.653(d) for all points to be included in an 

emissions average. The Implementation Plan shall identify all emission points to be included in 

the emissions average. This must include any Group 1 emission points to which the reference 

control technology (defined in §63.641) is not applied and all other emission points being 

controlled as part of the average. 

(c) The following emission points can be used to generate emissions averaging credits if 

control was applied after November 15, 1990 and if sufficient information is available to 

determine the appropriate value of credits for the emission point: 

(1) Group 2 emission points; 

(2) Group 1 storage vessels, Group 1 wastewater streams, Group 1 gasoline loading racks, 

Group 1 marine tank vessels, and Group 1 miscellaneous process vents that are controlled by a 

technology that the Administrator or permitting authority agrees has a higher nominal efficiency 

than the reference control technology. Information on the nominal efficiencies for such 

technologies must be submitted and approved as provided in paragraph (i) of this section; and 

(3) Emission points from which emissions are reduced by pollution prevention measures. 

Percentages of reduction for pollution prevention measures shall be determined as specified in 

paragraph (j) of this section. 

(i) For a Group 1 emission point, the pollution prevention measure must reduce emissions 

more than the reference control technology would have had the reference control technology 

Deleted: 3

Deleted: and §§
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

been applied to the emission point instead of the pollution prevention measure except as 

provided in paragraph (c)(3)(ii) of this section. 

(ii) If a pollution prevention measure is used in conjunction with other controls for a Group 

1 emission point, the pollution prevention measure alone does not have to reduce emissions more 

than the reference control technology, but the combination of the pollution prevention measure 

and other controls must reduce emissions more than the reference control technology would have 

had it been applied instead. 

(d) The following emission points cannot be used to generate emissions averaging credits: 

(1) Emission points already controlled on or before November 15, 1990 unless the level of 

control is increased after November 15, 1990, in which case credit will be allowed only for the 

increase in control after November 15, 1990; 

(2) Group 1 emission points that are controlled by a reference control technology unless the 

reference control technology has been approved for use in a different manner and a higher 

nominal efficiency has been assigned according to the procedures in paragraph (i) of this section. 

For example, it is not allowable to claim that an internal floating roof meeting only the 

specifications stated in the reference control technology definition in §63.641 (i.e., that meets the 

specifications of §63.119(b) of subpart G but does not have controlled fittings per §63.119 (b)(5) 

and (b)(6) of subpart G) applied to a storage vessel is achieving greater than 95 percent control; 

(3) Emission points on shutdown process units. Process units that are shut down cannot be 

used to generate credits or debits; 

(4) Wastewater that is not process wastewater or wastewater streams treated in biological 

treatment units. These two types of wastewater cannot be used to generate credits or debits. 

Group 1 wastewater streams cannot be left undercontrolled or uncontrolled to generate debits. 

For the purposes of this section, the terms “wastewater” and “wastewater stream” are used to 

mean process wastewater; and 

(5) Emission points controlled to comply with a State or Federal rule other than this subpart, 

unless the level of control has been increased after November 15, 1990 above what is required by 

the other State or Federal rule. Only the control above what is required by the other State or 

Federal rule will be credited. However, if an emission point has been used to generate emissions 

averaging credit in an approved emissions average, and the point is subsequently made subject to 

a State or Federal rule other than this subpart, the point can continue to generate emissions 

averaging credit for the purpose of complying with the previously approved average. 

(e) For all points included in an emissions average, the owner or operator shall: 

(1) Calculate and record monthly debits for all Group 1 emission points that are controlled 

to a level less stringent than the reference control technology for those emission points. 

Equations in paragraph (g) of this section shall be used to calculate debits. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) Calculate and record monthly credits for all Group 1 or Group 2 emission points that are 

overcontrolled to compensate for the debits. Equations in paragraph (h) of this section shall be 

used to calculate credits. Emission points and controls that meet the criteria of paragraph (c) of 

this section may be included in the credit calculation, whereas those described in paragraph (d) 

of this section shall not be included. 

(3) Demonstrate that annual credits calculated according to paragraph (h) of this section are 

greater than or equal to debits calculated for the same annual compliance period according to 

paragraph (g) of this section. 

(i) The initial demonstration in the Implementation Plan that credit-generating emission 

points will be capable of generating sufficient credits to offset the debits from the debitgenerating emission points must be made under representative operating conditions. 

(ii) After the compliance date, actual operating data will be used for all debit and credit 

calculations. 

(4) Demonstrate that debits calculated for a quarterly (3-month) period according to 

paragraph (g) of this section are not more than 1.30 times the credits for the same period 

calculated according to paragraph (h) of this section. Compliance for the quarter shall be 

determined based on the ratio of credits and debits from that quarter, with 30 percent more debits 

than credits allowed on a quarterly basis. 

(5) Record and report quarterly and annual credits and debits in the Periodic Reports as 

specified in §63.655(g)(8). Every fourth Periodic Report shall include a certification of 

compliance with the emissions averaging provisions as required by §63.655(g)(8)(iii). 

(f) Debits and credits shall be calculated in accordance with the methods and procedures 

specified in paragraphs (g) and (h) of this section, respectively, and shall not include emissions 

from the following: 

(1) More than 20 individual emission points. Where pollution prevention measures (as 

specified in paragraph (j)(1) of this section) are used to control emission points to be included in 

an emissions average, no more than 25 emission points may be included in the average. For 

example, if two emission points to be included in an emissions average are controlled by 

pollution prevention measures, the average may include up to 22 emission points. 

(2) [Reserved]

(3) For emission points for which continuous monitors are used, periods of excess emissions 

as defined in §63.655(g)(6)(i). For these periods, the calculation of monthly credits and debits 

shall be adjusted as specified in paragraphs (f)(3)(i) through (f)(3)(iii) of this section. 

(i) No credits would be assigned to the credit-generating emission point. 

(ii) Maximum debits would be assigned to the debit-generating emission point. 

Deleted: Periods of startup, shutdown, and 

malfunction as described in the source’s startup, 

shutdown, and malfunction plan required by 

§63.6(e)(3) of subpart A of this part.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) The owner or operator may use the procedures in paragraph (l) of this section to 

demonstrate to the Administrator that full or partial credits or debits should be assigned. 

(g) Debits are generated by the difference between the actual emissions from a Group 1 

emission point that is uncontrolled or is controlled to a level less stringent than the reference 

control technology, and the emissions allowed for Group 1 emission point. Debits shall be 

calculated as follows: 

(1) The overall equation for calculating sourcewide debits is: 

       

   

  



  



      

n

i

iACTUAL iu

n

i

iACTUAL iC

n

i

iACTUAL iu

n

i

iACTUAL iu

EMV EMV

Debits EPV EPV ES ES EGLR EGLR

1

1 1 1

0.03

0.02 0.05

where: 

Debits and all terms of the equation are in units of megagrams per month, and 

EPViACTUAL = Emissions from each Group 1 miscellaneous process vent i that is 

uncontrolled or is controlled to a level less stringent than the reference control technology. This 

is calculated according to paragraph (g)(2) of this section. 

(0.02) EPViu = Emissions from each Group 1 miscellaneous process vent i if the reference 

control technology had been applied to the uncontrolled emissions, calculated according to 

paragraph (g)(2) of this section. 

ESiACTUAL = Emissions from each Group 1 storage vessel i that is uncontrolled or is 

controlled to a level less stringent than the reference control technology. This is calculated 

according to paragraph (g)(3) of this section. 

(0.05) ESiu = Emissions from each Group 1 storage vessel i if the reference control 

technology had been applied to the uncontrolled emissions, calculated according to paragraph 

(g)(3) of this section. 

EGLRiACTUAL = Emissions from each Group 1 gasoline loading rack i that is uncontrolled or 

is controlled to a level less stringent than the reference control technology. This is calculated 

according to paragraph (g)(4) of this section. 

EGLRic = Emissions from each Group 1 gasoline loading rack i if the reference control 

technology had been applied to the uncontrolled emissions. This is calculated according to 

paragraph (g)(4) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EMVACTUAL = Emissions from each Group 1 marine tank vessel i that is uncontrolled or is 

controlled to a level less stringent than the reference control technology. This is calculated 

according to paragraph (g)(5) of this section. 

(0.03) EMViu = Emissions from each Group 1 marine tank vessel i if the reference control 

technology had been applied to the uncontrolled emissions calculated according to paragraph 

(g)(5) of this section. 

n = The number of Group 1 emission points being included in the emissions average. The 

value of n is not necessarily the same for each kind of emission point. 

(2) Emissions from miscellaneous process vents shall be calculated as follows: 

(i) For purposes of determining miscellaneous process vent stream flow rate, organic HAP 

concentrations, and temperature, the sampling site shall be after the final product recovery 

device, if any recovery devices are present; before any control device (for miscellaneous process 

vents, recovery devices shall not be considered control devices); and before discharge to the 

atmosphere. Method 1 or 1A of part 60, appendix A shall be used for selection of the sampling 

site. 

(ii) The following equation shall be used for each miscellaneous process vent i to calculate 

EPViu: 

  













   

 n

j

EPViu Qh CjM j

1

9 2.494 10

where: 

EPViu = Uncontrolled process vent emission rate from miscellaneous process vent i, 

megagrams per month. 

Q = Vent stream flow rate, dry standard cubic meters per minute, measured using Methods 

2, 2A, 2C, or 2D of part 60 appendix A, as appropriate. 

h = Monthly hours of operation during which positive flow is present in the vent, hours per 

month. 

Cj = Concentration, parts per million by volume, dry basis, of organic HAP j as measured 

by Method 18 of part 60 appendix A. 

Mj = Molecular weight of organic HAP j, gram per gram-mole. 

n = Number of organic HAP’s in the miscellaneous process vent stream. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(A) The values of Q, Cj, and Mj shall be determined during a performance test conducted 

under representative operating conditions. The values of Q, Cj, and Mj shall be established in the 

Notification of Compliance Status report and must be updated as provided in paragraph 

(g)(2)(ii)(B) of this section. 

(B) If there is a change in capacity utilization other than a change in monthly operating 

hours, or if any other change is made to the process or product recovery equipment or operation 

such that the previously measured values of Q, Cj, and Mj are no longer representative, a new 

performance test shall be conducted to determine new representative values of Q, Cj, and Mj. 

These new values shall be used to calculate debits and credits from the time of the change 

forward, and the new values shall be reported in the next Periodic Report. 

(iii) The following procedures and equations shall be used to calculate EPViACTUAL: 

(A) If the vent is not controlled by a control device or pollution prevention measure, 

EPViACTUAL = EPViu, where EPViu is calculated according to the procedures in paragraphs 

(g)(2)(i) and (g)(2)(ii) of this section. 

(B) If the vent is controlled using a control device or a pollution prevention measure 

achieving less than 98-percent reduction, 





 



    100%

1 Percent reduction EPViACTUAL EPViu

(1) The percent reduction shall be measured according to the procedures in §63.116 of 

subpart G if a combustion control device is used. For a flare meeting the criteria in §63.116(a) of 

subpart G or §63.670 of this subpart, as applicable, or a boiler or process heater meeting the 

criteria in §63.645(d) of this subpart or §63.116(b) of subpart G, the percentage of reduction 

shall be 98 percent. If a noncombustion control device is used, percentage of reduction shall be 

demonstrated by a performance test at the inlet and outlet of the device, or, if testing is not 

feasible, by a control design evaluation and documented engineering calculations. 

(2) For determining debits from miscellaneous process vents, product recovery devices shall 

not be considered control devices and cannot be assigned a percentage of reduction in calculating 

EPViACTUAL. The sampling site for measurement of uncontrolled emissions is after the final 

product recovery device. 

(3) Procedures for calculating the percentage of reduction of pollution prevention measures 

are specified in paragraph (j) of this section. 

(3) Emissions from storage vessels shall be calculated as specified in §63.150(g)(3) of 

subpart G. 

(4) Emissions from gasoline loading racks shall be calculated as follows: 

Formatted: Italic

Formatted: Italic
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) The following equation shall be used for each gasoline loading rack i to calculate 

EGLRiu: 

  T

SPMG EGLRiu

7 1.20 10  

where: 

EGLRiu = Uncontrolled transfer HAP emission rate from gasoline loading rack i, 

megagrams per month 

S = Saturation factor, dimensionless (see table 33 of subpart G). 

P = Weighted average rack partial pressure of organic HAP’s transferred at the rack during 

the month, kilopascals. 

M = Weighted average molecular weight of organic HAP’s transferred at the gasoline 

loading rack during the month, gram per gram-mole. 

G = Monthly volume of gasoline transferred from gasoline loading rack, liters per month. 

T = Weighted rack bulk liquid loading temperature during the month, degrees kelvin 

(degrees Celsius °C + 273). 

(ii) The following equation shall be used for each gasoline loading rack i to calculate the 

weighted average rack partial pressure: 

  

G

P G

P

j

j n

 j



 1

where: 

Pj = Maximum true vapor pressure of individual organic HAP transferred at the rack, 

kilopascals. 

G = Monthly volume of organic HAP transferred, liters per month, and 







j n

G Gj

1

Gj = Monthly volume of individual organic HAP transferred at the gasoline loading rack, 

liters per month. 

n = Number of organic HAP’s transferred at the gasoline loading rack. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) The following equation shall be used for each gasoline loading rack i to calculate the 

weighted average rack molecular weight: 

  

G

M G

M

j

j n

 j



 1

where: 

Mj = Molecular weight of individual organic HAP transferred at the rack, gram per grammole. 

G, Gj, and n are as defined in paragraph (g)(4)(ii) of this section. 

(iv) The following equation shall be used for each gasoline loading rack i to calculate the 

monthly weighted rack bulk liquid loading temperature: 

  

G

T G

T

j

j n

 j



 1

Tj = Average annual bulk temperature of individual organic HAP loaded at the gasoline 

loading rack, kelvin (degrees Celsius °C+273). 

G, Gj, and n are as defined in paragraph (g)(4)(ii) of this section. 

(v) The following equation shall be used to calculate EGLRic: 

EGLRic G

8 1 10  

G is as defined in paragraph (g)(4)(ii) of this section. 

(vi) The following procedures and equations shall be used to calculate EGLRiACTUAL: 

(A) If the gasoline loading rack is not controlled, EGLRiACTUAL = EGLRiu, where EGLRiu is 

calculated using the equations specified in paragraphs (g)(4)(i) through (g)(4)(iv) of this section. 

(B) If the gasoline loading rack is controlled using a control device or a pollution prevention 

measure not achieving the requirement of less than 10 milligrams of TOC per liter of gasoline 

loaded, 





 



    100%

1 Percent reduction EGLRiACTUAL EGLRiu
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) The percent reduction for a control device shall be measured according to the procedures 

and test methods specified in §63.128(a) of subpart G. If testing is not feasible, the percentage of 

reduction shall be determined through a design evaluation according to the procedures specified 

in §63.128(h) of subpart G. 

(2) Procedures for calculating the percentage of reduction for pollution prevention measures 

are specified in paragraph (j) of this section. 

(5) Emissions from marine tank vessel loading shall be calculated as follows: 

(i) The following equation shall be used for each marine tank vessel i to calculate EMViu: 

    



m

i

EMViu Qi Fi Pi

1

where: 

EMViu = Uncontrolled marine tank vessel HAP emission rate from marine tank vessel i, 

megagrams per month. 

Qi = Quantity of commodity loaded (per vessel type), liters. 

Fi = Emission factor, megagrams per liter. 

Pi = Percent HAP. 

m = Number of combinations of commodities and vessel types loaded. 

Emission factors shall be based on test data or emission estimation procedures specified in 

§63.565(l) of subpart Y. 

(ii) The following procedures and equations shall be used to calculate EMViACTUAL: 

(A) If the marine tank vessel is not controlled, EMViACTUAL = EMViu, where EMViu is 

calculated using the equations specified in paragraph (g)(5)(i) of this section. 

(B) If the marine tank vessel is controlled using a control device or a pollution prevention 

measure achieving less than 97-percent reduction, 





 



    100%

1 Percent reduction EMViACTUAL EMViu

(1) The percent reduction for a control device shall be measured according to the procedures 

and test methods specified in §63.565(d) of subpart Y. If testing is not feasible, the percentage of 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

reduction shall be determined through a design evaluation according to the procedures specified 

in §63.128(h) of subpart G. 

(2) Procedures for calculating the percentage of reduction for pollution prevention measures 

are specified in paragraph (j) of this section. 

(h) Credits are generated by the difference between emissions that are allowed for each 

Group 1 and Group 2 emission point and the actual emissions from a Group 1 or Group 2 

emission point that has been controlled after November 15, 1990 to a level more stringent than 

what is required by this subpart or any other State or Federal rule or statute. Credits shall be 

calculated as follows: 

(1) The overall equation for calculating sourcewide credits is: 

    

    

  

    

   

 

 

 

 

 

 

 

 

 

  

   

   

   

    

m

i

iBASE iACTUAL

n

i

ic iACTUAL

m

i

iBASE iACTUAL

n

i

iu iACTUAL

m

i

iBASE iACTUAL

n

i

ic iACTUAL

m

i

iBASE iACTUAL

n

i

iu iACTUAL

m

i

iBASE iACTUAL

n

i

iu iACTUAL

D EWW1 EWW1 D EWW2 EWW2

D EMV1 EMV1 D EMV2 EMV2

D EGLR EGLR1 D EGLR2 EGLR2

D ES1 ES1 D ES2 ES2

Credits D EPV1 EPV1 D EPV2 EPV2

1 1

1 1

1 1

1 1

1 1

0.03

0.05

0.02

where: 

Credits and all terms of the equation are in units of megagrams per month, the baseline date 

is November 15, 1990, and 

D = Discount factor = 0.9 for all credit-generating emission points except those controlled 

by a pollution prevention measure, which will not be discounted. 

EPV1iACTUAL = Emissions for each Group 1 miscellaneous process vent i that is controlled 

to a level more stringent than the reference control technology, calculated according to paragraph 

(h)(2) of this section. 

(0.02) EPV1iu = Emissions from each Group 1 miscellaneous process vent i if the reference 

control technology had been applied to the uncontrolled emissions. EPV1iu is calculated 

according to paragraph (h)(2) of this section. 

EPV2iBASE = Emissions from each Group 2 miscellaneous process vent; at the baseline date, 

as calculated in paragraph (h)(2) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EPV2iACTUAL = Emissions from each Group 2 miscellaneous process vent that is controlled, 

calculated according to paragraph (h)(2) of this section. 

ES1iACTUAL = Emissions from each Group 1 storage vessel i that is controlled to a level 

more stringent than the reference control technology, calculated according to paragraph (h)(3) of 

this section. 

(0.05) ES1iu = Emissions from each Group 1 storage vessel i if the reference control 

technology had been applied to the uncontrolled emissions. ES1iu is calculated according to 

paragraph (h)(3) of this section. 

ES2iACTUAL = Emissions from each Group 2 storage vessel i that is controlled, calculated 

according to paragraph (h)(3) of this section. 

ES2iBASE = Emissions from each Group 2 storage vessel i at the baseline date, as calculated 

in paragraph (h)(3) of this section. 

EGLR1iACTUAL = Emissions from each Group 1 gasoline loading rack i that is controlled to 

a level more stringent than the reference control technology, calculated according to paragraph 

(h)(4) of this section. 

EGLRic = Emissions from each Group 1 gasoline loading rack i if the reference control 

technology had been applied to the uncontrolled emissions. EGLRiu is calculated according to 

paragraph (h)(4) of this section. 

EGRL2iACTUAL = Emissions from each Group 2 gasoline loading rack i that is controlled, 

calculated according to paragraph (h)(4) of this section. 

EGLR2iBASE = Emissions from each Group 2 gasoline loading rack i at the baseline date, as 

calculated in paragraph (h)(4) of this section. 

EMV1iACTUAL = Emissions from each Group 1 marine tank vessel i that is controlled to a 

level more stringent than the reference control technology, calculated according to paragraph 

(h)(4) of this section. 

(0.03)EMV1iu = Emissions from each Group 1 marine tank vessel i if the reference control 

technology had been applied to the uncontrolled emissions. EMV1iu is calculated according to 

paragraph (h)(5) of this section. 

EMV2iACTUAL = Emissions from each Group 2 marine tank vessel i that is controlled, 

calculated according to paragraph (h)(5) of this section. 

EMV2iBASE = Emissions from each Group 2 marine tank vessel i at the baseline date, as 

calculated in paragraph (h)(5) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EWW1iACTUAL = Emissions from each Group 1 wastewater stream i that is controlled to a 

level more stringent than the reference control technology, calculated according to paragraph 

(h)(6) of this section. 

EWW1ic = Emissions from each Group 1 wastewater stream i if the reference control 

technology had been applied to the uncontrolled emissions, calculated according to paragraph 

(h)(6) of this section. 

EWW2iACTUAL = Emissions from each Group 2 wastewater stream i that is controlled, 

calculated according to paragraph (h)(6) of this section. 

EWW2iBASE = Emissions from each Group 2 wastewater stream i at the baseline date, 

calculated according to paragraph (h)(6) of this section. 

n = Number of Group 1 emission points included in the emissions average. The value of n is 

not necessarily the same for each kind of emission point. 

m = Number of Group 2 emission points included in the emissions average. The value of m 

is not necessarily the same for each kind of emission point. 

(i) For an emission point controlled using a reference control technology, the percentage of 

reduction for calculating credits shall be no greater than the nominal efficiency associated with 

the reference control technology, unless a higher nominal efficiency is assigned as specified in 

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

(ii) For an emission point controlled to a level more stringent than the reference control 

technology, the nominal efficiency for calculating credits shall be assigned as described in 

paragraph (i) of this section. A reference control technology may be approved for use in a 

different manner and assigned a higher nominal efficiency according to the procedures in 

paragraph (i) of this section. 

(iii) For an emission point controlled using a pollution prevention measure, the nominal 

efficiency for calculating credits shall be determined as described in paragraph (j) of this section. 

(2) Emissions from process vents shall be determined as follows: 

(i) Uncontrolled emissions from miscellaneous process vents, EPV1iu, shall be calculated 

according to the procedures and equation for EPViu in paragraphs (g)(2)(i) and (g)(2)(ii) of this 

section. 

(ii) Actual emissions from miscellaneous process vents controlled using a technology with 

an approved nominal efficiency greater than 98 percent or a pollution prevention measure 

achieving greater than 98 percent emission reduction, EPV1iACTUAL, shall be calculated 

according to the following equation: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***





 



    100%

1 Nominal efficiency% EPV1iACTUAL EPV1iu

(iii) The following procedures shall be used to calculate actual emissions from Group 2 

process vents, EPV2iACTUAL: 

(A) For a Group 2 process vent controlled by a control device, a recovery device applied as 

a pollution prevention project, or a pollution prevention measure, if the control achieves a 

percentage of reduction less than or equal to a 98 percent reduction, 





 



    100%

1 Percent reduction EPV2iACTUAL EPV2iu

(1) EPV2iu shall be calculated according to the equations and procedures for EPViu in 

paragraphs (g)(2)(i) and (g)(2)(ii) of this section except as provided in paragraph (h)(2)(iii)(A)(3) 

of this section. 

(2) The percentage of reduction shall be calculated according to the procedures in 

paragraphs (g)(2)(iii)(B)(1) through (g)(2)(iii)(B)(3) of this section except as provided in 

paragraph (h)(2)(iii)(A)(4) of this section. 

(3) If a recovery device was added as part of a pollution prevention project, EPV2iu shall be 

calculated prior to that recovery device. The equation for EPViu in paragraph (g)(2)(ii) of this 

section shall be used to calculate EPV2iu; however, the sampling site for measurement of vent 

stream flow rate and organic HAP concentration shall be at the inlet of the recovery device. 

(4) If a recovery device was added as part of a pollution prevention project, the percentage 

of reduction shall be demonstrated by conducting a performance test at the inlet and outlet of that 

recovery device. 

(B) For a Group 2 process vent controlled using a technology with an approved nominal 

efficiency greater than a 98 percent or a pollution prevention measure achieving greater than 98 

percent reduction, 





 



    100%

1 Nominal efficiency% EPV2iACTUAL EPV2iu

(iv) Emissions from Group 2 process vents at baseline, EPV2iBASE, shall be calculated as 

follows: 

(A) If the process vent was uncontrolled on November 15, 1990, EPV2iBASE = EPV2iu, and 

shall be calculated according to the procedures and equation for EPViu in paragraphs (g)(2)(i) 

and (g)(2)(ii) of this section. 

(B) If the process vent was controlled on November 15, 1990, 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***





 



    100%

1 Percent reduction EPV2BASE EPV2iu

where EPV2iu is calculated according to the procedures and equation for EPViu in 

paragraphs (g)(2)(i) and (g)(2)(ii) of this section. The percentage of reduction shall be calculated 

according to the procedures specified in paragraphs (g)(2)(iii)(B)(1) through (g)(2)(iii)(B)(3) of 

this section. 

(C) If a recovery device was added to a process vent as part of a pollution prevention 

project initiated after November 15, 1990, EPV2iBASE = EPV2iu, where EPV2iu is calculated 

according to paragraph (h)(2)(iii)(A)(3) of this section. 

(3) Emissions from storage vessels shall be determined as specified in §63.150(h)(3) of 

subpart G, except as follows: 

(i) For storage vessels complying with §63.646: 

(A) All references to §63.119(b) in §63.150(h)(3) of subpart G shall be replaced with: 

§63.119(b) or §63.119(b) except for §63.119(b)(5) and (b)(6). 

(B) All references to §63.119(c) in §63.150(h)(3) of subpart G shall be replaced with: 

§63.119(c) or §63.119(c) except for §63.119(c)(2). 

(C) All references to §63.119(d) in §63.150(h)(3) of subpart G shall be replaced with: 

§63.119(d) or §63.119(d) except for §63.119(d)(2). 

(ii) For storage vessels complying with §63.660: 

(A) Sections 63.1063(a)(1)(i), (a)(2), and (b) or §§63.1063(a)(1)(i) and (b) shall apply 

instead of §63.119(b) in §63.150(h)(3) of subpart G. 

(B) Sections 63.1063(a)(1)(ii), (a)(2), and (b) shall apply instead of §63.119(c) in 

§63.150(h)(3) of subpart G. 

(C) Sections 63.1063(a)(1)(i), (a)(2), and (b) or §§63.1063(a)(1)(i) and (b) shall apply 

instead of §63.119(d) in §63.150(h)(3) of subpart G. 

(4) Emissions from gasoline loading racks shall be determined as follows: 

(i) Uncontrolled emissions from Group 1 gasoline loading racks, EGLR1iu, shall be 

calculated according to the procedures and equations for EGLRiu as described in paragraphs 

(g)(4)(i) through (g)(4)(iv) of this section. 

(ii) Emissions from Group 1 gasoline loading racks if the reference control technology had 

been applied, EGLRic, shall be calculated according to the procedures and equations in paragraph 

(g)(4)(v) of this section. 

Deleted: 

Deleted: ii

Deleted: iii
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) Actual emissions from Group 1 gasoline loading racks controlled to less than 10 

milligrams of TOC per liter of gasoline loaded; EGLRiACTUAL, shall be calculated according to 

the following equation: 





 



    100%

1 Nominal efficiency% EGLR1iACTUAL EGLR1iu

(iv) The following procedures shall be used to calculate actual emissions from Group 2 

gasoline loading racks, EGLR2iACTUAL: 

(A) For a Group 2 gasoline loading rack controlled by a control device or a pollution 

prevention measure achieving emissions reduction but where emissions are greater than the 10 

milligrams of TOC per liter of gasoline loaded requirement, 





 



    100%

1 Percent reduction EGLR2iACTUAL EGLR2iu

(1) EGLR2iu shall be calculated according to the equations and procedures for EGLRiu in 

paragraphs (g)(4)(i) through (g)(4)(iv) of this section. 

(2) The percentage of reduction shall be calculated according to the procedures in 

paragraphs (g)(4)(vi)(B)(1) and (g)(4)(vi)(B)(2) of this section. 

(B) For a Group 2 gasoline loading rack controlled by using a technology with an approved 

nominal efficiency greater than 98 percent or a pollution prevention measure achieving greater 

than a 98-percent reduction, 





 



    100%

1 Nominal efficiency EGLR2iACTUAL EGLR2iu

(v) Emissions from Group 2 gasoline loading racks at baseline, EGLR2iBASE, shall be 

calculated as follows: 

(A) If the gasoline loading rack was uncontrolled on November 15, 1990, EGLR2iBASE = 

EGLR2iu, and shall be calculated according to the procedures and equations for EGLRiu in 

paragraphs (g)(4)(i) through (g)(4)(iv) of this section. 

(B) If the gasoline loading rack was controlled on November 15, 1990, 





 



    100%

1 Percent reduction EGLR2iBASE EGLR2iu

where EGLR2iu is calculated according to the procedures and equations for EGLRiu in 

paragraphs (g)(4)(i) through (g)(4)(iv) of this section. Percentage of reduction shall be calculated 

according to the procedures in paragraphs (g)(4)(vi)(B)(1) and (g)(4)(vi)(B)(2) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(5) Emissions from marine tank vessels shall be determined as follows: 

(i) Uncontrolled emissions from Group 1 marine tank vessels, EMV1iu, shall be calculated 

according to the procedures and equations for EMViu as described in paragraph (g)(5)(i) of this 

section. 

(ii) Actual emissions from Group 1 marine tank vessels controlled using a technology or 

pollution prevention measure with an approved nominal efficiency greater than 97 percent, 

EMViACTUAL, shall be calculated according to the following equation: 





 



    100%

1 Nominal efficiency EMV1iACTUAL EMV1iu

(iii) The following procedures shall be used to calculate actual emissions from Group 2 

marine tank vessels, EMV2iACTUAL: 

(A) For a Group 2 marine tank vessel controlled by a control device or a pollution 

prevention measure achieving a percentage of reduction less than or equal to 97 percent 

reduction, 





 



    100%

1 Percent reduction EMV2iACTUAL EMV2iu

(1) EMV2iu shall be calculated according to the equations and procedures for EMViu in 

paragraph (g)(5)(i) of this section. 

(2) The percentage of reduction shall be calculated according to the procedures in 

paragraphs (g)(5)(ii)(B)(1) and (g)(5)(ii)(B)(2) of this section. 

(B) For a Group 2 marine tank vessel controlled using a technology or a pollution 

prevention measure with an approved nominal efficiency greater than 97 percent, 





 



    100%

1 Nominal efficiency EMV2iACTUAL EMV2iu

(iv) Emissions from Group 2 marine tank vessels at baseline, EMV2iBASE, shall be 

calculated as follows: 

(A) If the marine terminal was uncontrolled on November 15, 1990, EMV2iBASE equals 

EMV2iu, and shall be calculated according to the procedures and equations for EMViu in 

paragraph (g)(5)(i) of this section. 

(B) If the marine tank vessel was controlled on November 15, 1990, 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***





 



    100%

1 Percent reduction EMV2iBASE EMV2iu

where EMV2iu is calculated according to the procedures and equations for EMViu in 

paragraph (g)(5)(i) of this section. Percentage of reduction shall be calculated according to the 

procedures in paragraphs (g)(5)(ii)(B)(1) and (g)(5)(ii)(B)(2) of this section. 

(6) Emissions from wastewater shall be determined as follows: 

(i) For purposes of paragraphs (h)(4)(ii) through (h)(4)(vi) of this section, the following 

terms will have the meaning given them in paragraphs (h)(6)(i)(A) through (h)(6)(i)(C) of this 

section. 

(A) Correctly suppressed means that a wastewater stream is being managed according to 

the requirements of §§61.343 through 61.347 or §61.342(c)(l)(iii) of 40 CFR part 61, subpart FF, 

as applicable, and the emissions from the waste management units subject to those requirements 

are routed to a control device that reduces HAP emissions by 95 percent or greater. 

(B) Treatment process has the meaning given in §61.341 of 40 CFR part 61, subpart FF 

except that it does not include biological treatment units. 

(C) Vapor control device means the control device that receives emissions vented from a 

treatment process or treatment processes. 

(ii) The following equation shall be used for each wastewater stream i to calculate EWWic: 

       







     

s

m

i i m im

s

m

EWWic QiHi Frm Fem HAPim Q H Fr HAP 1

8

1

8 6.0 10 1 0.05 6.0 10

where: 

EWWic = Monthly wastewater stream emission rate if wastewater stream i were controlled 

by the reference control technology, megagrams per month. 

Qi = Average flow rate for wastewater stream i, liters per minute. 

Hi = Number of hours during the month that wastewater stream i was generated, hours per 

month. 

Frm =Fraction removed of organic HAP m in wastewater, from table 7 of this subpart, 

dimensionless. 

Fem =Fraction emitted of organic HAP m in wastewater from table 7 of this subpart, 

dimensionless. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

s = Total number of organic HAP’s in wastewater stream i. 

HAPim = Average concentration of organic HAP m in wastewater stream i, parts per million 

by weight. 

(A) HAPim shall be determined for the point of generation or at a location downstream of 

the point of generation. Wastewater samples shall be collected using the sampling procedures 

specified in Method 25D of 40 CFR part 60, appendix A. Where feasible, samples shall be taken 

from an enclosed pipe prior to the wastewater being exposed to the atmosphere. When sampling 

from an enclosed pipe is not feasible, a minimum of three representative samples shall be 

collected in a manner to minimize exposure of the sample to the atmosphere and loss of organic 

HAP’s prior to sampling. The samples collected may be analyzed by either of the following 

procedures: 

(1) A test method or results from a test method that measures organic HAP concentrations 

in the wastewater, and that has been validated pursuant to section 5.1 or 5.3 of Method 301 of 

appendix A of this part may be used; or 

(2) Method 305 of appendix A of this part may be used to determine Cim, the average 

volatile organic HAP concentration of organic HAP m in wastewater stream i, and then HAPim

may be calculated using the following equation: HAPim = Cim/Fmm, where Fmm for organic HAP 

m is obtained from table 7 of this subpart. 

(B) Values for Qi, HAPim, and Cim shall be determined during a performance test conducted 

under representative conditions. The average value obtained from three test runs shall be used. 

The values of Qi, HAPim, and Cim shall be established in the Notification of Compliance Status 

report and must be updated as provided in paragraph (h)(6)(i)(C) of this section. 

(C) If there is a change to the process or operation such that the previously measured values 

of Qi, HAPim, and Cim are no longer representative, a new performance test shall be conducted to 

determine new representative values of Qi, HAPim, and Cim. These new values shall be used to 

calculate debits and credits from the time of the change forward, and the new values shall be 

reported in the next Periodic Report. 

(iii) The following equations shall be used to calculate EWW1iACTUAL for each Group 1 

wastewater stream i that is correctly suppressed and is treated to a level more stringent than the 

reference control technology. 

(A) If the Group 1 wastewater stream i is controlled using a treatment process or series of 

treatment processes with an approved nominal reduction efficiency for an individually speciated 

HAP that is greater than that specified in table 7 of this subpart, and the vapor control device 

achieves a percentage of reduction equal to 95 percent, the following equation shall be used: 

          







     

s

m

i i im im

s

m

EWW1iACTUAL QiHi Fem HAPim PRim Q H HAP PR 1

8

1

8 6.0 10 1 0.05 6.0 10
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: 

EWWiACTUAL = Monthly wastewater stream emission rate if wastewater stream i is treated 

to a level more stringent than the reference control technology, megagrams per month. 

PRim = The efficiency of the treatment process, or series of treatment processes, that treat 

wastewater stream i in reducing the emission potential of organic HAP m in wastewater, 

dimensionless, as calculated by: 

im in

im in im out

im HAP

HAP HAP PR



   

Where: 

HAPim-in = Average concentration of organic HAP m, parts per million by weight, as 

defined and determined according to paragraph (h)(6)(ii)(A) of this section, in the wastewater 

entering the first treatment process in the series. 

HAPim-out = Average concentration of organic HAP m, parts per million by weight, as 

defined and determined according to paragraph (h)(6)(ii)(A) of this section, in the wastewater 

exiting the last treatment process in the series. 

All other terms are as defined and determined in paragraph (h)(6)(ii) of this section. 

(B) If the Group 1 wastewater stream i is not controlled using a treatment process or series 

of treatment processes with an approved nominal reduction efficiency for an individually 

speciated HAP that is greater than that specified in table 7 of this subpart, but the vapor control 

device has an approved nominal efficiency greater than 95 percent, the following equation shall 

be used: 

         







   

 



     

s

m

i i im m

s

m

iACTUAL i i m im m Q H HAP A Nominal efficiency% EWW1 Q H Fe HAP A 1

8

1

8 6.0 10

100

6.0 10 1 1

Where: 

Nominal efficiency = Approved reduction efficiency of the vapor control device, 

dimensionless, as determined according to the procedures in §63.652(i). 

Am = The efficiency of the treatment process, or series of treatment processes, that treat 

wastewater stream i in reducing the emission potential of organic HAP m in wastewater, 

dimensionless. 

All other terms are as defined and determined in paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of 

this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) If a steam stripper meeting the specifications in the definition of reference control 

technology for wastewater is used, Am shall be equal to the value of Frm given in table 7 of this 

subpart. 

(2) If an alternative control device is used, the percentage of reduction must be determined 

using the equation and methods specified in paragraph (h)(6)(iii)(A) of this section for 

determining PRim. If the value of PRim is greater than or equal to the value of Frm given in table 7 

of this subpart, then Am equals Frm unless a higher nominal efficiency has been approved. If a 

higher nominal efficiency has been approved for the treatment process, the owner or operator 

shall determine EWW1iACTUAL according to paragraph (h)(6)(iii)(B) of this section rather than 

paragraph (h)(6)(iii)(A) of this section. If PRim is less than the value of FRm given in table 7 of 

this subpart, emissions averaging shall not be used for this emission point. 

(C) If the Group 1 wastewater stream i is controlled using a treatment process or series of 

treatment processes with an approved nominal reduction efficiency for an individually speciated 

hazardous air pollutant that is greater than that specified in table 7 of this subpart, and the vapor 

control device has an approved nominal efficiency greater than 95 percent, the following 

equation shall be used: 

         







   

 



     

s

m

i i im im

s

m

iACTUAL i i m im im Q H HAP PR Nominal efficiency% EWW1 Q H Fe HAP PR 1

8

1

8 6.0 10

100

6.0 10 1 1

where all terms are as defined and determined in paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of 

this section. 

(iv) The following equation shall be used to calculate EWW2iBASE for each Group 2 

wastewater stream i that on November 15, 1990 was not correctly suppressed or was correctly 

suppressed but not treated: 

  

  

s

m

EWW iBASE QiHi Fem HAPim

1

8 2 6.0 10

Where: 

EWW2iBASE = Monthly wastewater stream emission rate if wastewater stream i is not 

correctly suppressed, megagrams per month. 

Qi, Hi, s, Fem, and HAPim are as defined and determined according to paragraphs (h)(6)(ii) 

and (h)(6)(iii)(A) of this section. 

(v) The following equation shall be used to calculate EWW2iBASE for each Group 2 

wastewater stream i on November 15, 1990 was correctly suppressed. EWW2iBASE shall be 

calculated as if the control methods being used on November 15, 1990 are in place and any 

control methods applied after November 15, 1990 are ignored. However, values for the 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

parameters in the equation shall be representative of present production levels and stream 

properties. 

         







   

 



     

s

m

i i im im

i

s

m

iBASE i i m im im Q H HAP PR R EWW2 Q H Fe HAP PR 1

8

1

8 6.0 10

100%

6.0 10 1 1

where Ri is calculated according to paragraph (h)(6)(vii) of this section and all other terms 

are as defined and determined according to paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of this section. 

(vi) For Group 2 wastewater streams that are correctly suppressed, EWW2iACTUAL shall be 

calculated according to the equation for EWW2iBASE in paragraph (h)(6)(v) of this section. 

EWW2iACTUAL shall be calculated with all control methods in place accounted for. 

(vii) The reduction efficiency, Ri, of the vapor control device shall be demonstrated 

according to the following procedures: 

(A) Sampling sites shall be selected using Method 1 or 1A of 40 CFR part 60, appendix A, 

as appropriate. 

(B) The mass flow rate of organic compounds entering and exiting the control device shall 

be determined as follows: 

(1) The time period for the test shall not be less than 3 hours during which at least three runs 

are conducted. 

(2) A run shall consist of a 1-hour period during the test. For each run: 

(i) The volume exhausted shall be determined using Methods 2, 2A, 2C, or 2D of 40 CFR 

part 60 appendix A, as appropriate; 

(ii) The organic concentration in the vent stream entering and exiting the control device 

shall be determined using Method 18 of 40 CFR part 60, appendix A. Alternatively, any other 

test method validated according to the procedures in Method 301 of appendix A of this part may 

be used. 

(3) The mass flow rate of organic compounds entering and exiting the control device during 

each run shall be calculated as follows: 

































     

n

p

aip i

m

p

a Vap C MW m E 1 1

6 10

0.0416

































     

n

p

bip i

m

p

b Vbp C MW m E 1 1

6 10

0.0416
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: 

Ea = Mass flow rate of organic compounds exiting the control device, kilograms per hour. 

Eb = Mass flow rate of organic compounds entering the control device, kilograms per hour. 

Vap = Average volumetric flow rate of vent stream exiting the control device during run p at 

standards conditions, cubic meters per hour. 

Vbp = Average volumetric flow rate of vent stream entering the control device during run p 

at standards conditions, cubic meters per hour. 

p = Run. 

m = Number of runs. 

Caip = Concentration of organic compound i measured in the vent stream exiting the control 

device during run p as determined by Method 18 of 40 CFR part 60 appendix A, parts per 

million by volume on a dry basis. 

Cbip = Concentration of organic compound i measured in the vent stream entering the 

control device during run p as determined by Method 18 of 40 CFR part 60, appendix A, parts 

per million by volume on a dry basis. 

MWi = Molecular weight of organic compound i in the vent stream, kilograms per 

kilogram-mole. 

n = Number of organic compounds in the vent stream. 

0.0416 = Conversion factor for molar volume, kilograms-mole per cubic meter at 293 

kelvin and 760 millimeters mercury absolute. 

(C) The organic reduction efficiency for the control device shall be calculated as follows: 

100  

b

b a

E

E E R

Where: 

R = Total organic reduction efficiency for the control device, percentage. 

Eb = Mass flow rate of organic compounds entering the control device, kilograms per hour. 

Ea = Mass flow rate of organic compounds exiting the control device, kilograms per hour. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) The following procedures shall be followed to establish nominal efficiencies. The 

procedures in paragraphs (i)(1) through (i)(6) of this section shall be followed for control 

technologies that are different in use or design from the reference control technologies and 

achieve greater percentages of reduction than the percentages of efficiency assigned to the 

reference control technologies in §63.641. 

(1) In those cases where the owner or operator is seeking permission to take credit for use of 

a control technology that is different in use or design from the reference control technology, and 

the different control technology will be used in more than three applications at a single plant site, 

the owner or operator shall submit the information specified in paragraphs (i)(1)(i) through 

(i)(1)(iv) of this section to the Administrator in writing: 

(i) Emission stream characteristics of each emission point to which the control technology is 

or will be applied including the kind of emission point, flow, organic HAP concentration, and all 

other stream characteristics necessary to design the control technology or determine its 

performance; 

(ii) Description of the control technology including design specifications; 

(iii) Documentation demonstrating to the Administrator’s satisfaction the control efficiency 

of the control technology. This may include performance test data collected using an appropriate 

EPA method or any other method validated according to Method 301 of appendix A of this part. 

If it is infeasible to obtain test data, documentation may include a design evaluation and 

calculations. The engineering basis of the calculation procedures and all inputs and assumptions 

made in the calculations shall be documented; and 

(iv) A description of the parameter or parameters to be monitored to ensure that the control 

technology will be operated in conformance with its design and an explanation of the criteria 

used for selection of that parameter (or parameters). 

(2) The Administrator shall determine within 120 calendar days whether an application 

presents sufficient information to determine nominal efficiency. The Administrator reserves the 

right to request specific data in addition to the items listed in paragraph (i)(1) of this section. 

(3) The Administrator shall determine within 120 calendar days of the submittal of 

sufficient data whether a control technology shall have a nominal efficiency and the level of that 

nominal efficiency. If, in the Administrator’s judgment, the control technology achieves a level 

of emission reduction greater than the reference control technology for a particular kind of 

emission point, the Administrator will publish a Federal Register notice establishing a nominal 

efficiency for the control technology. 

(4) The Administrator may grant conditional permission to take emission credits for use of 

the control technology on requirements that may be necessary to ensure operation and 

maintenance to achieve the specified nominal efficiency. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(5) In those cases where the owner or operator is seeking permission to take credit for use of 

a control technology that is different in use or design from the reference control technology and 

the different control technology will be used in no more than three applications at a single plant 

site, the information listed in paragraphs (i)(1)(i) through (i)(1)(iv) of this section can be 

submitted to the permitting authority for the source for approval instead of the Administrator. 

(i) In these instances, use and conditions for use of the control technology can be approved 

by the permitting authority. The permitting authority shall follow the procedures specified in 

paragraphs (i)(2) through (i)(4) of this section except that, in these instances, a 

Federal Register notice is not required to establish the nominal efficiency for the different 

technology. 

(ii) If, in reviewing the submittal, the permitting authority believes the control technology 

has broad applicability for use by other sources, the permitting authority shall submit the 

information provided in the application to the Director of the EPA Office of Air Quality 

Planning and Standards. The Administrator shall review the technology for broad applicability 

and may publish a Federal Register notice; however, this review shall not affect the permitting 

authority’s approval of the nominal efficiency of the control technology for the specific 

application. 

(6) If, in reviewing an application for a control technology for an emission point, the 

Administrator or permitting authority determines the control technology is not different in use or 

design from the reference control technology, the Administrator or permitting authority shall 

deny the application. 

(j) The following procedures shall be used for calculating the efficiency (percentage of 

reduction) of pollution prevention measures: 

(1) A pollution prevention measure is any practice that meets the criteria of paragraphs 

(j)(1)(i) and (j)(1)(ii) of this section. 

(i) A pollution prevention measure is any practice that results in a lesser quantity of organic 

HAP emissions per unit of product released to the atmosphere prior to out-of-process recycling, 

treatment, or control of emissions while the same product is produced. 

(ii) Pollution prevention measures may include: Substitution of feedstocks that reduce HAP 

emissions, alterations to the production process to reduce the volume of materials released to the 

environment, equipment modifications; housekeeping measures, and in-process recycling that 

returns waste materials directly to production as raw materials. Production cutbacks do not 

qualify as pollution prevention. 

(2) The emission reduction efficiency of pollution prevention measures implemented after 

November 15, 1990 can be used in calculating the actual emissions from an emission point in the 

debit and credit equations in paragraphs (g) and (h) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) For pollution prevention measures, the percentage of reduction used in the equations in 

paragraphs (g)(2) and (g)(3) of this section and paragraphs (h)(2) through (h)(4) of this section is 

the difference in percentage between the monthly organic HAP emissions for each emission 

point after the pollution prevention measure for the most recent month versus monthly emissions 

from the same emission point before the pollution prevention measure, adjusted by the volume of 

product produced during the two monthly periods. 

(ii) The following equation shall be used to calculate the percentage of reduction of a 

pollution prevention measure for each emission point. 

 

100%





B

pp

pp B

B

E

P

E P

E

Percent reduction

Where: 

Percent reduction = Efficiency of pollution prevention measure (percentage of organic HAP 

reduction). 

EB = Monthly emissions before the pollution prevention measure, megagrams per month, 

determined as specified in paragraphs (j)(2)(ii)(A), (j)(2)(ii)(B), and (j)(2)(ii)(C) of this section. 

Epp = Monthly emissions after the pollution prevention measure, megagrams per month, as 

determined for the most recent month, determined as specified in paragraphs (j)(2)(ii)(D) or 

(j)(2)(ii)(E) of this section. 

PB = Monthly production before the pollution prevention measure, megagrams per month, 

during the same period over which EB is calculated. 

Ppp = Monthly production after the pollution prevention measure, megagrams per month, as 

determined for the most recent month. 

(A) The monthly emissions before the pollution prevention measure, EB, shall be 

determined in a manner consistent with the equations and procedures in paragraphs (g)(2), (g)(3), 

(g)(4), and (g)(5) of this section for miscellaneous process vents, storage vessels, gasoline 

loading racks, and marine tank vessels. 

(B) For wastewater, EB shall be calculated as follows: 

     







 



  

n

i

s

m

EB QBiHBi FemHAPBim

1 1

8 6.0 10

where: 

n = Number of wastewater streams. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

QBi = Average flow rate for wastewater stream i before the pollution prevention measure, 

liters per minute. 

HBi = Number of hours per month that wastewater stream i was discharged before the 

pollution prevention measure, hours per month. 

s = Total number of organic HAP’s in wastewater stream i. 

Fem = Fraction emitted of organic HAP m in wastewater from table 7 of this subpart, 

dimensionless. 

HAPBim = Average concentration of organic HAP m in wastewater stream i, defined and 

determined according to paragraph (h)(6)(ii)(A)(2) of this section, before the pollution 

prevention measure, parts per million by weight, as measured before the implementation of the 

pollution measure. 

(C) If the pollution prevention measure was implemented prior to July 14, 1994, records 

may be used to determine EB. 

(D) The monthly emissions after the pollution prevention measure, Epp, may be determined 

during a performance test or by a design evaluation and documented engineering calculations. 

Once an emissions-to-production ratio has been established, the ratio can be used to estimate 

monthly emissions from monthly production records. 

(E) For wastewater, Epp shall be calculated using the following equation: 

     







 



  

n

i

s

m

Epp QppiHppi FemHAPppim

1 1

8 6.0 10

where n, Q, H, s, Fem, and HAP are defined and determined as described in paragraph 

(j)(2)(ii)(B) of this section except that Qppi, Hppi, and HAPppim shall be determined after the 

pollution prevention measure has been implemented. 

(iii) All equations, calculations, test procedures, test results, and other information used to 

determine the percentage of reduction achieved by a pollution prevention measure for each 

emission point shall be fully documented. 

(iv) The same pollution prevention measure may reduce emissions from multiple emission 

points. In such cases, the percentage of reduction in emissions for each emission point must be 

calculated. 

(v) For the purposes of the equations in paragraphs (h)(2) through (h)(6) of this section used 

to calculate credits for emission points controlled more stringently than the reference control 

technology, the nominal efficiency of a pollution prevention measure is equivalent to the 

percentage of reduction of the pollution prevention measure. When a pollution prevention 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

measure is used, the owner or operator of a source is not required to apply to the Administrator 

for a nominal efficiency and is not subject to paragraph (i) of this section. 

(k) The owner or operator shall demonstrate that the emissions from the emission points 

proposed to be included in the average will not result in greater hazard or, at the option of the 

State or local permitting authority, greater risk to human health or the environment than if the 

emission points were controlled according to the provisions in §§63.643 through 63.645, 63.646 

or 63.660, 63.647, 63.650, and 63.651, as applicable. 

(1) This demonstration of hazard or risk equivalency shall be made to the satisfaction of the 

State or local permitting authority. 

(i) The State or local permitting authority may require owners and operators to use specific 

methodologies and procedures for making a hazard or risk determination. 

(ii) The demonstration and approval of hazard or risk equivalency may be made according 

to any guidance that the EPA makes available for use. 

(2) Owners and operators shall provide documentation demonstrating the hazard or risk 

equivalency of their proposed emissions average in their Implementation Plan. 

(3) An emissions averaging plan that does not demonstrate an equivalent or lower hazard or 

risk to the satisfaction of the State or local permitting authority shall not be approved. The State 

or local permitting authority may require such adjustments to the emissions averaging plan as are 

necessary in order to ensure that the average will not result in greater hazard or risk to human 

health or the environment than would result if the emission points were controlled according to 

§§63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable. 

(4) A hazard or risk equivalency demonstration shall: 

(i) Be a quantitative, bona fide chemical hazard or risk assessment; 

(ii) Account for differences in chemical hazard or risk to human health or the environment; 

and 

(iii) Meet any requirements set by the State or local permitting authority for such 

demonstrations. 

(l) For periods of excess emissions, an owner or operator may request that the provisions of 

paragraphs (l)(1) through (l)(4) of this section be followed instead of the procedures in 

paragraphs (f)(3)(i) and (f)(3)(ii) of this section. 

(1) The owner or operator shall notify the Administrator of excess emissions in the Periodic 

Reports as required in §63.655(g)(6). 

Deleted: and §§

Deleted: and §§
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) The owner or operator shall demonstrate that other types of monitoring data or 

engineering calculations are appropriate to establish that the control device for the emission point 

was operating in such a fashion to warrant assigning full or partial credits and debits. This 

demonstration shall be made to the Administrator’s satisfaction, and the Administrator may 

establish procedures for demonstrating compliance that are acceptable. 

(3) The owner or operator shall provide documentation of the period of excess emissions 

and the other type of monitoring data or engineering calculations to be used to demonstrate that 

the control device for the emission point was operating in such a fashion to warrant assigning full 

or partial credits and debits. 

(4) The Administrator may assign full or partial credit and debits upon review of the 

information provided. 

§ 63.653 Monitoring, recordkeeping, and implementation plan for emissions averaging. 

(a) For each emission point included in an emissions average, the owner or operator shall 

perform testing, monitoring, recordkeeping, and reporting equivalent to that required for Group 1 

emission points complying with §§63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 

63.651, as applicable. The specific requirements for miscellaneous process vents, storage vessels, 

wastewater, gasoline loading racks, and marine tank vessels are identified in paragraphs (a)(1) 

through (7) of this section. 

(1) The source shall implement the following testing, monitoring, recordkeeping, and 

reporting procedures for each miscellaneous process vent equipped with a flare, incinerator, 

boiler, or process heater: 

(i) Conduct initial performance tests to determine the percentage of reduction as specified in 

§63.645 of this subpart and §63.116 of subpart G; and 

(ii) Monitor the operating parameters specified in §63.644, as appropriate for the specific 

control device. 

(2) The source shall implement the following procedures for each miscellaneous process 

vent, equipped with a carbon adsorber, absorber, or condenser but not equipped with a control 

device: 

(i) Determine the flow rate and organic HAP concentration using the methods specified in 

§63.115 (a)(1) and (a)(2), §63.115 (b)(1) and (b)(2), and §63.115(c)(3) of subpart G; and 

(ii) Monitor the operating parameters specified in §63.114 of subpart G, as appropriate for 

the specific recovery device. 

(3) The source shall implement the following procedures for each storage vessel controlled 

with an internal floating roof, external roof, or a closed vent system with a control device, as 

appropriate to the control technique: 

Deleted: and §§

Deleted: a)(
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) Perform the monitoring or inspection procedures in §63.646 and either §63.120 of 

subpart G or §63.1063 of subpart WW, as applicable; and 

(ii) For closed vent systems with control devices, conduct an initial design evaluation as 

specified in §63.646 and either §63.120(d) of subpart G or §63.985(b) of subpart SS, as 

applicable. 

(4) For each gasoline loading rack that is controlled, perform the testing and monitoring 

procedures specified in §§63.425 and 63.427 of subpart R of this part except §63.425(d) or 

§63.427(c). 

(5) For each marine tank vessel that is controlled, perform the compliance, monitoring, and 

performance testing, procedures specified in §§63.563, 63.564, and 63.565 of subpart Y of this 

part. 

(6) The source shall implement the following procedures for wastewater emission points, as 

appropriate to the control techniques: 

(i) For wastewater treatment processes, conduct tests as specified in §61.355 of subpart FF 

of part 60; 

(ii) Conduct inspections and monitoring as specified in §§61.343 through 61.349 and 

§61.354 of 40 CFR part 61, subpart FF. 

(7) If an emission point in an emissions average is controlled using a pollution prevention 

measure or a device or technique for which no monitoring parameters or inspection procedures 

are specified in §§63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as 

applicable, the owner or operator shall establish a site-specific monitoring parameter and shall 

submit the information specified in §63.655(h)(4) in the Implementation Plan. 

(b) Records of all information required to calculate emission debits and credits and records 

required by §63.655 shall be retained for 5 years. 

(c) Notifications of Compliance Status report, Periodic Reports, and other reports shall be 

submitted as required by §63.655. 

(d) Each owner or operator of an existing source who elects to comply with §63.655(g) and 

(h) by using emissions averaging for any emission points shall submit an Implementation Plan. 

(1) The Implementation Plan shall be submitted to the Administrator and approved prior to 

implementing emissions averaging. This information may be submitted in an operating permit 

application, in an amendment to an operating permit application, in a separate submittal, in a 

Notification of Compliance Status Report, in a Periodic Report or in any combination of these 

documents. If an owner or operator submits the information specified in paragraph (d)(2) of this 

section at different times, and/or in different submittals, later submittals may refer to earlier 

submittals instead of duplicating the previously submitted information. 

Deleted: of this subpart 

Deleted: of this subpart 

Deleted: and §§
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) The Implementation Plan shall include the information specified in paragraphs (d)(2)(i) 

through (d)(2)(ix) of this section for all points included in the average. 

(i) The identification of all emission points in the planned emissions average and notation of 

whether each emission point is a Group 1 or Group 2 emission point as defined in §63.641. 

(ii) The projected annual emission debits and credits for each emission point and the sum 

for the emission points involved in the average calculated according to §63.652. The annual 

projected credits must be greater than the projected debits, as required under §63.652(e)(3). 

(iii) The specific control technology or pollution prevention measure that will be used for 

each emission point included in the average and date of application or expected date of 

application. 

(iv) The specific identification of each emission point affected by a pollution prevention 

measure. To be considered a pollution prevention measure, the criteria in §63.652(j)(1) must be 

met. If the same pollution prevention measure reduces or eliminates emissions from multiple 

emission points in the average, the owner or operator must identify each of these emission 

points. 

(v) A statement that the compliance demonstration, monitoring, inspection, recordkeeping, 

and reporting provisions in paragraphs (a), (b), and (c) of this section that are applicable to each 

emission point in the emissions average will be implemented beginning on the date of 

compliance. 

(vi) Documentation of the information listed in paragraphs (d)(2)(vi)(A) through 

(d)(2)(vi)(D) of this section for each emission point included in the average. 

(A) The values of the parameters used to determine whether each emission point in the 

emissions average is Group 1 or Group 2. 

(B) The estimated values of all parameters needed for input to the emission debit and credit 

calculations in §63.652 (g) and (h). These parameter values or, as appropriate, limited ranges for 

the parameter values, shall be specified in the source’s Implementation Plan as enforceable 

operating conditions. Changes to these parameters must be reported in the next Periodic Report. 

(C) The estimated percentage of reduction if a control technology achieving a lower 

percentage of reduction than the efficiency of the reference control technology, as defined in 

§63.641, is or will be applied to the emission point. 

(D) The anticipated nominal efficiency if a control technology achieving a greater 

percentage emission reduction than the efficiency of the reference control technology is or will 

be applied to the emission point. The procedures in §63.652(i) shall be followed to apply for a 

nominal efficiency. 

(vii) The information specified in §63.655(h)(4) for: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(A) Each miscellaneous process vent controlled by a pollution prevention measure or 

control technique for which monitoring parameters or inspection procedures are not specified in 

paragraphs (a)(1) or (a)(2) of this section; and 

(B) Each storage vessel controlled by a pollution prevention measure or a control technique 

other than an internal or external floating roof or a closed vent system with a control device. 

(viii) Documentation of the information listed in paragraphs (d)(2)(viii)(A) through 

(d)(2)(viii)(G) of this section for each process wastewater stream included in the average. 

(A) The information used to determine whether the wastewater stream is a Group 1 or 

Group 2 wastewater stream. 

(B) The estimated values of all parameters needed for input to the wastewater emission 

credit and debit calculations in §63.652(h)(6). 

(C) The estimated percentage of reduction if the wastewater stream is or will be controlled 

using a treatment process or series of treatment processes that achieves an emission reduction 

less than or equal to the emission reduction specified in table 7 of this subpart. 

(D) The estimated percentage of reduction if a control technology achieving less than or 

equal to 95 percent emission reduction is or will be applied to the vapor stream(s) vented and 

collected from the treatment processes. 

(E) The estimated percentage of reduction if a pollution prevention measure is or will be 

applied. 

(F) The anticipated nominal efficiency if the owner or operator plans to apply for a nominal 

efficiency under §63.652(i). A nominal efficiency shall be applied for if: 

(1) A control technology is or will be applied to the wastewater stream and achieves an 

emission reduction greater than the emission reduction specified in table 7 of this subpart; or 

(2) A control technology achieving greater than 95 percent emission reduction is or will be 

applied to the vapor stream(s) vented and collected from the treatment processes. 

(G) For each pollution prevention measure, treatment process, or control device used to 

reduce air emissions of organic HAP from wastewater and for which no monitoring parameters 

or inspection procedures are specified in §63.647, the information specified in §63.655(h)(4) 

shall be included in the Implementation Plan. 

(ix) Documentation required in §63.652(k) demonstrating the hazard or risk equivalency of 

the proposed emissions average. 

(3) The Administrator shall determine within 120 calendar days whether the 

Implementation Plan submitted presents sufficient information. The Administrator shall either 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

approve the Implementation Plan, request changes, or request that the owner or operator submit 

additional information. Once the Administrator receives sufficient information, the 

Administrator shall approve, disapprove, or request changes to the plan within 120 calendar 

days. 

§ 63.654 Heat exchange systems. 

(a) Except as specified in paragraph (b) of this section, the owner or operator of a heat 

exchange system that meets the criteria in §63.640(c)(8) must comply with the requirements of 

paragraphs (c) through (g) of this section. 

(b) A heat exchange system is exempt from the requirements in paragraphs (c) through (g) 

of this section if all heat exchangers within the heat exchange system either: 

(1) Operate with the minimum pressure on the cooling water side at least 35 kilopascals 

greater than the maximum pressure on the process side; or 

(2) Employ an intervening cooling fluid containing less than 5 percent by weight of total 

organic HAP, as determined according to the provisions of §63.180(d) of this part and table 1 of 

this subpart, between the process and the cooling water. This intervening fluid must serve to 

isolate the cooling water from the process fluid and must not be sent through a cooling tower or 

discharged. For purposes of this section, discharge does not include emptying for maintenance 

purposes. 

(c) The owner or operator must perform monitoring to identify leaks of total strippable 

volatile organic compounds (VOC) from each heat exchange system subject to the requirements 

of this subpart according to the procedures in paragraphs (c)(1) through (6) of this section. 

(1) Monitoring locations for closed-loop recirculation heat exchange systems. For each 

closed loop recirculating heat exchange system, collect and analyze a sample from the location(s) 

described in either paragraph (c)(1)(i) or (c)(1)(ii) of this section. 

(i) Each cooling tower return line or any representative riser within the cooling tower prior 

to exposure to air for each heat exchange system. 

(ii) Selected heat exchanger exit line(s) so that each heat exchanger or group of heat 

exchangers within a heat exchange system is covered by the selected monitoring location(s). 

(2) Monitoring locations for once-through heat exchange systems. For each once-through 

heat exchange system, collect and analyze a sample from the location(s) described in paragraph 

(c)(2)(i) of this section. The owner or operator may also elect to collect and analyze an additional 

sample from the location(s) described in paragraph (c)(2)(ii) of this section. 

(i) Selected heat exchanger exit line(s) so that each heat exchanger or group of heat 

exchangers within a heat exchange system is covered by the selected monitoring location(s). The 

selected monitoring location may be at a point where discharges from multiple heat exchange 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

systems are combined provided that the combined cooling water flow rate at the monitoring 

location does not exceed 40,000 gallons per minute. 

(ii) The inlet water feed line for a once-through heat exchange system prior to any heat 

exchanger. If multiple heat exchange systems use the same water feed (i.e., inlet water from the 

same primary water source), the owner or operator may monitor at one representative location 

and use the monitoring results for that sampling location for all heat exchange systems that use 

that same water feed. 

(3) Monitoring method. Determine the total strippable hydrocarbon concentration (in parts 

per million by volume (ppmv) as methane) at each monitoring location using the “Air Stripping 

Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions 

from Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, 

Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental 

Quality, January 31, 2003 (incorporated by reference—see § 63.14) using a flame ionization 

detector (FID) analyzer for on-site determination as described in Section 6.1 of the Modified El 

Paso Method. 

(4) Monitoring frequency and leak action level for existing sources. For a heat exchange 

system at an existing source, the owner or operator must comply with the monitoring frequency 

and leak action level as defined in paragraph (c)(4)(i) of this section or comply with the 

monitoring frequency and leak action level as defined in paragraph (c)(4)(ii) of this section. The 

owner or operator of an affected heat exchange system may choose to comply with paragraph 

(c)(4)(i) of this section for some heat exchange systems at the petroleum refinery and comply 

with paragraph (c)(4)(ii) of this section for other heat exchange systems. However, for each 

affected heat exchange system, the owner or operator of an affected heat exchange system must 

elect one monitoring alternative that will apply at all times. If the owner or operator intends to 

change the monitoring alternative that applies to a heat exchange system, the owner or operator 

must notify the Administrator 30 days in advance of such a change. All “leaks” identified prior 

to changing monitoring alternatives must be repaired. The monitoring frequencies specified in 

paragraphs (c)(4)(i) and (ii) of this section also apply to the inlet water feed line for a oncethrough heat exchange system, if monitoring of the inlet water feed is elected as provided in 

paragraph (c)(2)(ii) of this section. 

(i) Monitor monthly using a leak action level defined as a total strippable hydrocarbon 

concentration (as methane) in the stripping gas of 6.2 ppmv. 

(ii) Monitor quarterly using a leak action level defined as a total strippable hydrocarbon 

concentration (as methane) in the stripping gas of 3.1 ppmv unless repair is delayed as provided 

in paragraph (f) of this section. If a repair is delayed as provided in paragraph (f) of this section, 

monitor monthly. 

(5) Monitoring frequency and leak action level for new sources. For a heat exchange system 

at a new source, the owner or operator must monitor monthly using a leak action level defined as 

a total strippable hydrocarbon concentration (as methane) in the stripping gas of 3.1 ppmv. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(6) Leak definition. A leak is defined as described in paragraph (c)(6)(i) or (c)(6)(ii) of this 

section, as applicable. 

(i) For once-through heat exchange systems for which the inlet water feed is monitored as 

described in paragraph (c)(2)(ii) of this section, a leak is detected if the difference in the 

measurement value of the sample taken from a location specified in paragraph (c)(2)(i) of this 

section and the measurement value of the corresponding sample taken from the location 

specified in paragraph (c)(2)(ii) of this section equals or exceeds the leak action level. 

(ii) For all other heat exchange systems, a leak is detected if a measurement value of the 

sample taken from a location specified in either paragraph (c)(1)(i), (c)(1)(ii), or (c)(2)(i) of this 

section equals or exceeds the leak action level. 

(d) If a leak is detected, the owner or operator must repair the leak to reduce the measured 

concentration to below the applicable action level as soon as practicable, but no later than 45 

days after identifying the leak, except as specified in paragraphs (e) and (f) of this section. Repair 

includes re-monitoring at the monitoring location where the leak was identified according to the 

method specified in paragraph (c)(3) of this section to verify that the measured concentration is 

below the applicable action level. Actions that can be taken to achieve repair include but are not 

limited to: 

(1) Physical modifications to the leaking heat exchanger, such as welding the leak or 

replacing a tube; 

(2) Blocking the leaking tube within the heat exchanger; 

(3) Changing the pressure so that water flows into the process fluid; 

(4) Replacing the heat exchanger or heat exchanger bundle; or 

(5) Isolating, bypassing, or otherwise removing the leaking heat exchanger from service 

until it is otherwise repaired. 

(e) If the owner or operator detects a leak when monitoring a cooling tower return line 

under paragraph (c)(1)(i) of this section, the owner or operator may conduct additional 

monitoring of each heat exchanger or group of heat exchangers associated with the heat 

exchange system for which the leak was detected as provided under paragraph (c)(1)(ii) of this 

section. If no leaks are detected when monitoring according to the requirements of paragraph 

(c)(1)(ii) of this section, the heat exchange system is considered to meet the repair requirements 

through re-monitoring of the heat exchange system as provided in paragraph (d) of this section. 

(f) The owner or operator may delay the repair of a leaking heat exchanger when one of the 

conditions in paragraph (f)(1) or (f)(2) of this section is met and the leak is less than the delay of 

repair action level specified in paragraph (f)(3) of this section. The owner or operator must 

determine if a delay of repair is necessary as soon as practicable, but no later than 45 days after 

first identifying the leak. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) If the repair is technically infeasible without a shutdown and the total strippable 

hydrocarbon concentration is initially and remains less than the delay of repair action level for all 

monthly monitoring periods during the delay of repair, the owner or operator may delay repair 

until the next scheduled shutdown of the heat exchange system. If, during subsequent monthly 

monitoring, the delay of repair action level is exceeded, the owner or operator must repair the 

leak within 30 days of the monitoring event in which the leak was equal to or exceeded the delay 

of repair action level. 

(2) If the necessary equipment, parts, or personnel are not available and the total strippable 

hydrocarbon concentration is initially and remains less than the delay of repair action level for all 

monthly monitoring periods during the delay of repair, the owner or operator may delay the 

repair for a maximum of 120 calendar days. The owner or operator must demonstrate that the 

necessary equipment, parts, or personnel were not available. If, during subsequent monthly 

monitoring, the delay of repair action level is exceeded, the owner or operator must repair the 

leak within 30 days of the monitoring event in which the leak was equal to or exceeded the delay 

of repair action level. 

(3) The delay of repair action level is a total strippable hydrocarbon concentration (as 

methane) in the stripping gas of 62 ppmv. The delay of repair action level is assessed as 

described in paragraph (f)(3)(i) or (f)(3)(ii) of this section, as applicable. 

(i) For once-through heat exchange systems for which the inlet water feed is monitored as 

described in paragraph (c)(2)(ii) of this section, the delay of repair action level is exceeded if the 

difference in the measurement value of the sample taken from a location specified in paragraph 

(c)(2)(i) of this section and the measurement value of the corresponding sample taken from the 

location specified in paragraph (c)(2)(ii) of this section equals or exceeds the delay of repair 

action level. 

(ii) For all other heat exchange systems, the delay of repair action level is exceeded if a 

measurement value of the sample taken from a location specified in either paragraphs (c)(1)(i), 

(c)(1)(ii), or (c)(2)(i) of this section equals or exceeds the delay of repair action level. 

(g) To delay the repair under paragraph (f) of this section, the owner or operator must 

record the information in paragraphs (g)(1) through (4) of this section. 

(1) The reason(s) for delaying repair. 

(2) A schedule for completing the repair as soon as practical. 

(3) The date and concentration of the leak as first identified and the results of all subsequent 

monthly monitoring events during the delay of repair. 

(4) An estimate of the potential strippable hydrocarbon emissions from the leaking heat 

exchange system or heat exchanger for each required delay of repair monitoring interval 

following the procedures in paragraphs (g)(4)(i) through (iv) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) Determine the leak concentration as specified in paragraph (c) of this section and convert 

the stripping gas leak concentration (in ppmv as methane) to an equivalent liquid concentration, 

in parts per million by weight (ppmw), using equation 7-1 from “Air Stripping Method 

(Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from 

Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, 

Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental 

Quality, January 31, 2003 (incorporated by reference—see § 63.14) and the molecular weight of 

16 grams per mole (g/mol) for methane. 

(ii) Determine the mass flow rate of the cooling water at the monitoring location where the 

leak was detected. If the monitoring location is an individual cooling tower riser, determine the 

total cooling water mass flow rate to the cooling tower. Cooling water mass flow rates may be 

determined using direct measurement, pump curves, heat balance calculations, or other 

engineering methods. Volumetric flow measurements may be used and converted to mass flow 

rates using the density of water at the specific monitoring location temperature or using the 

default density of water at 25 degrees Celsius, which is 997 kilograms per cubic meter or 8.32 

pounds per gallon. 

(iii) For delay of repair monitoring intervals prior to repair of the leak, calculate the 

potential strippable hydrocarbon emissions for the leaking heat exchange system or heat 

exchanger for the monitoring interval by multiplying the leak concentration in the cooling water, 

ppmw, determined in (g)(4)(i) of this section, by the mass flow rate of the cooling water 

determined in (g)(4)(ii) of this section and by the duration of the delay of repair monitoring 

interval. The duration of the delay of repair monitoring interval is the time period starting at 

midnight on the day of the previous monitoring event or at midnight on the day the repair would 

have had to be completed if the repair had not been delayed, whichever is later, and ending at 

midnight of the day the of the current monitoring event. 

(iv) For delay of repair monitoring intervals ending with a repaired leak, calculate the 

potential strippable hydrocarbon emissions for the leaking heat exchange system or heat 

exchanger for the final delay of repair monitoring interval by multiplying the duration of the 

final delay of repair monitoring interval by the leak concentration and cooling water flow rates 

determined for the last monitoring event prior to the re-monitoring event used to verify the leak 

was repaired. The duration of the final delay of repair monitoring interval is the time period 

starting at midnight of the day of the last monitoring event prior to re-monitoring to verify the 

leak was repaired and ending at the time of the re-monitoring event that verified that the leak was 

repaired. 

§ 63.655 Reporting and recordkeeping requirements. 

(a) Each owner or operator subject to the wastewater provisions in §63.647 shall comply 

with the recordkeeping and reporting provisions in §§61.356 and 61.357 of 40 CFR part 61, 

subpart FF unless they are complying with the wastewater provisions specified in paragraph 

(o)(2)(ii) of §63.640. There are no additional reporting and recordkeeping requirements for 

wastewater under this subpart unless a wastewater stream is included in an emissions average. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Recordkeeping and reporting for emissions averages are specified in §63.653 and in paragraphs 

(f)(5) and (g)(8) of this section. 

(b) Each owner or operator subject to the gasoline loading rack provisions in §63.650 shall 

comply with the recordkeeping and reporting provisions in §63.428 (b) and (c), (g)(1), (h)(1) 

through (h)(3), and (k) of subpart R. These requirements are summarized in table 4 of this 

subpart. There are no additional reporting and recordkeeping requirements for gasoline loading 

racks under this subpart unless a loading rack is included in an emissions average. 

Recordkeeping and reporting for emissions averages are specified in §63.653 and in paragraphs 

(f)(5) and (g)(8) of this section. 

(c) Each owner or operator subject to the marine tank vessel loading operation standards in 

§63.651 shall comply with the recordkeeping and reporting provisions in §§63.567(a) and 

63.567(c) through (k) of subpart Y. These requirements are summarized in table 5 of this 

subpart. There are no additional reporting and recordkeeping requirements for marine tank vessel 

loading operations under this subpart unless marine tank vessel loading operations are included 

in an emissions average. Recordkeeping and reporting for emissions averages are specified in 

§63.653 and in paragraphs (f)(5) and (g)(8) of this section. 

(d) Each owner or operator subject to the equipment leaks standards in §63.648 shall 

comply with the recordkeeping and reporting provisions in paragraphs (d)(1) through (d)(6) of 

this section. 

(1) Sections 60.486 and 60.487 of subpart VV of part 60 except as specified in paragraph 

(d)(1)(i) of this section; or §§63.181 and 63.182 of subpart H of this part except for §§63.182(b), 

(c)(2), and (c)(4). 

(i) The signature of the owner or operator (or designate) whose decision it was that a repair 

could not be effected without a process shutdown is not required to be recorded. Instead, the 

name of the person whose decision it was that a repair could not be effected without a process 

shutdown shall be recorded and retained for 2 years. 

(ii) [Reserved] 

(2) The Notification of Compliance Status report required by §63.182(c) of subpart H and 

the initial semiannual report required by §60.487(b) of 40 CFR part 60, subpart VV shall be 

submitted within 150 days of the compliance date specified in §63.640(h); the requirements of 

subpart H of this part are summarized in table 3 of this subpart. 

(3) An owner or operator who determines that a compressor qualifies for the hydrogen 

service exemption in §63.648 shall also keep a record of the demonstration required by §63.648. 

(4) An owner or operator must keep a list of identification numbers for valves that are 

designated as leakless per §63.648(c)(10). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(5) An owner or operator must identify, either by list or location (area or refining process 

unit), equipment in organic HAP service less than 300 hours per year within refining process 

units subject to this subpart. 

(6) An owner or operator must keep a list of reciprocating pumps and compressors 

determined to be exempt from seal requirements as per §§63.648 (f) and (i). 

(e) Each owner or operator of a source subject to this subpart shall submit the reports listed 

in paragraphs (e)(1) through (e)(3) of this section except as provided in paragraph (h)(5) of this 

section, and shall keep records as described in paragraph (i) of this section. 

(1) A Notification of Compliance Status report as described in paragraph (f) of this section; 

(2) Periodic Reports as described in paragraph (g) of this section; and 

(3) Other reports as described in paragraph (h) of this section. 

(f) Each owner or operator of a source subject to this subpart shall submit a Notification of 

Compliance Status report within 150 days after the compliance dates specified in §63.640(h) 

with the exception of Notification of Compliance Status reports submitted to comply with 

§63.640(l)(3) and for storage vessels subject to the compliance schedule specified in 

§63.640(h)(2). Notification of Compliance Status reports required by §63.640(l)(3) and for 

storage vessels subject to the compliance dates specified in §63.640(h)(2) shall be submitted 

according to paragraph (f)(6) of this section. This information may be submitted in an operating 

permit application, in an amendment to an operating permit application, in a separate submittal, 

or in any combination of the three. If the required information has been submitted before the date 

150 days after the compliance date specified in §63.640(h), a separate Notification of 

Compliance Status report is not required within 150 days after the compliance dates specified in 

§63.640(h). If an owner or operator submits the information specified in paragraphs (f)(1) 

through (f)(5) of this section at different times, and/or in different submittals, later submittals 

may refer to earlier submittals instead of duplicating and resubmitting the previously submitted 

information. Each owner or operator of a gasoline loading rack classified under Standard 

Industrial Classification Code 2911 located within a contiguous area and under common control 

with a petroleum refinery subject to the standards of this subpart shall submit the Notification of 

Compliance Status report required by subpart R of this part within 150 days after the compliance 

dates specified in §63.640(h) of this subpart. 

(1) The Notification of Compliance Status report shall include the information specified in 

paragraphs (f)(1)(i) through (f)(1)(vii) of this section. 

(i) For storage vessels, this report shall include the information specified in paragraphs 

(f)(1)(i)(A) through (f)(1)(i)(D) of this section. 

(A) Identification of each storage vessel subject to this subpart, and for each Group 1 

storage vessel subject to this subpart, the information specified in paragraphs (f)(1)(i)(A)(1) 

through (f)(1)(i)(A)(3) of this section. This information is to be revised each time a Notification 

Deleted: 4

Deleted: 4
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

of Compliance Status report is submitted for a storage vessel subject to the compliance schedule 

specified in §63.640(h)(2) or to comply with §63.640(l)(3). 

(1) For each Group 1 storage vessel complying with §63.646 that is not included in an 

emissions average, the method of compliance (i.e., internal floating roof, external floating roof, 

or closed vent system and control device). 

(2) For storage vessels subject to the compliance schedule specified in §63.640(h)(2) that 

are not complying with §63.646, the anticipated compliance date. 

(3) For storage vessels subject to the compliance schedule specified in §63.640(h)(2) that 

are complying with §63.646 and the Group 1 storage vessels described in §63.640(l), the actual 

compliance date. 

(B) If a closed vent system and a control device other than a flare is used to comply with 

§63.646 or §63.660, the owner or operator shall submit: 

(1) A description of the parameter or parameters to be monitored to ensure that the control 

device is being properly operated and maintained, an explanation of the criteria used for 

selection of that parameter (or parameters), and the frequency with which monitoring will be 

performed; and either 

(2) The design evaluation documentation specified in §63.120(d)(1)(i) of subpart G or 

§63.985(b)(1)(i) of subpart SS (as applicable), if the owner or operator elects to prepare a design 

evaluation; or 

(3) If the owner or operator elects to submit the results of a performance test, identification 

of the storage vessel and control device for which the performance test will be submitted, and 

identification of the emission point(s) that share the control device with the storage vessel and 

for which the performance test will be conducted. 

(C) If a closed vent system and control device other than a flare is used, the owner or 

operator shall submit: 

(1) The operating range for each monitoring parameter. The specified operating range shall 

represent the conditions for which the control device is being properly operated and maintained. 

(2) If a performance test is conducted instead of a design evaluation, results of the 

performance test demonstrating that the control device achieves greater than or equal to the 

required control efficiency. A performance test conducted prior to the compliance date of this 

subpart can be used to comply with this requirement, provided that the test was conducted using 

EPA methods and that the test conditions are representative of current operating practices. 

(D) If a closed vent system and a flare is used, the owner or operator shall submit: 

(1) Flare design (e.g., steam-assisted, air-assisted, or nonassisted); 

Deleted: 4

Deleted: 4

Deleted: 4
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) All visible emission readings, heat content determinations, flow rate measurements, and 

exit velocity determinations made during the compliance determination required by §63.120(e) 

of subpart G or §63.987(b) of subpart SS or §63.670(h), as applicable; and 

(3) All periods during the compliance determination when the pilot flame is absent. 

(ii) For miscellaneous process vents, identification of each miscellaneous process vent 

subject to this subpart, whether the process vent is Group 1 or Group 2, and the method of 

compliance for each Group 1 miscellaneous process vent that is not included in an emissions 

average (e.g., use of a flare or other control device meeting the requirements of §63.643(a)). 

(iii) For miscellaneous process vents controlled by control devices required to be tested 

under §63.645 of this subpart and §63.116(c) of subpart G of this part, performance test results 

including the information in paragraphs (f)(1)(iii)(A) and (B) of this section. Results of a 

performance test conducted prior to the compliance date of this subpart can be used provided that 

the test was conducted using the methods specified in §63.645 and that the test conditions are 

representative of current operating conditions. 

(A) The percentage of reduction of organic HAP’s or TOC, or the outlet concentration of 

organic HAP’s or TOC (parts per million by volume on a dry basis corrected to 3 percent 

oxygen), determined as specified in §63.116(c) of subpart G of this part; and 

(B) The value of the monitored parameters specified in table 10 of this subpart, or a sitespecific parameter approved by the permitting authority, averaged over the full period of the 

performance test, 

(iv) For miscellaneous process vents controlled by flares, initial compliance test results 

including the information in paragraphs (f)(1)(iv)(A) and (B) of this section; 

(A) All visible emission readings, heat content determinations, flow rate measurements, and 

exit velocity determinations made during the compliance determination required by §63.645 of 

this subpart and §63.116(a) of subpart G of this part or §63.670(h) of this subpart, as applicable, 

and 

(B) A statement of whether a flame was present at the pilot light over the full period of the 

compliance determination. 

(v) For equipment leaks complying with §63.648(c) (i.e., complying with the requirements 

of subpart H of this part), the Notification of Compliance Report Status report information 

required by §63.182(c) of subpart H and whether the percentage of leaking valves will be 

reported on a process unit basis or a sourcewide basis. 

(vi) For each heat exchange system, identification of the heat exchange systems that are 

subject to the requirements of this subpart. For heat exchange systems at existing sources, the 

owner or operator shall indicate whether monitoring will be conducted as specified in 

§63.654(c)(4)(i) or §63.654(c)(4)(ii). 

Deleted: of this part

Deleted: performance
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(vii) For relief valves in organic HAP service, a description of the monitoring system to be 

implemented, including the relief valves and process parameters to be monitored, and a 

description of the alarms or other methods by which operators will be notified of a pressure 

release. 

(2) If initial performance tests are required by §§63.643 through 63.653 of this subpart, the 

Notification of Compliance Status report shall include one complete test report for each test 

method used for a particular source. On and after [THE DATE 3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], performance tests shall be submitted according to paragraph (h)(9) of this section.

(i) For additional tests performed using the same method, the results specified in paragraph 

(f)(1) of this section shall be submitted, but a complete test report is not required. 

(ii) A complete test report shall include a sampling site description, description of sampling 

and analysis procedures and any modifications to standard procedures, quality assurance 

procedures, record of operating conditions during the test, record of preparation of standards, 

record of calibrations, raw data sheets for field sampling, raw data sheets for field and laboratory 

analyses, documentation of calculations, and any other information required by the test method. 

(iii) Performance tests are required only if specified by §§63.643 through 63.653 of this 

subpart. Initial performance tests are required for some kinds of emission points and controls. 

Periodic testing of the same emission point is not required. 

(3) For each monitored parameter for which a range is required to be established under 

§63.120(d) of subpart G or §63.985(b) of subpart SS for storage vessels or §63.644 for 

miscellaneous process vents, the Notification of Compliance Status report shall include the 

information in paragraphs (f)(3)(i) through (f)(3)(iii) of this section. 

(i) The specific range of the monitored parameter(s) for each emission point; 

(ii) The rationale for the specific range for each parameter for each emission point, 

including any data and calculations used to develop the range and a description of why the range 

ensures compliance with the emission standard. 

(A) If a performance test is required by this subpart for a control device, the range shall be 

based on the parameter values measured during the performance test supplemented by 

engineering assessments and manufacturer’s recommendations. Performance testing is not 

required to be conducted over the entire range of permitted parameter values. 

(B) If a performance test is not required by this subpart for a control device, the range may 

be based solely on engineering assessments and manufacturers’ recommendations. 

(iii) A definition of the source’s operating day for purposes of determining daily average 

values of monitored parameters. The definition shall specify the times at which an operating day 

begins and ends. 

Deleted: of this part
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) Results of any continuous monitoring system performance evaluations shall be included 

in the Notification of Compliance Status report. 

(5) For emission points included in an emissions average, the Notification of Compliance 

Status report shall include the values of the parameters needed for input to the emission credit 

and debit equations in §63.652(g) and (h), calculated or measured according to the procedures in 

§63.652(g) and (h), and the resulting credits and debits for the first quarter of the year. The first 

quarter begins on the compliance date specified in §63.640. 

(6) Notification of Compliance Status reports required by §63.640(l)(3) and for storage 

vessels subject to the compliance dates specified in §63.640(h)(2) shall be submitted no later 

than 60 days after the end of the 6-month period during which the change or addition was made 

that resulted in the Group 1 emission point or the existing Group 1 storage vessel was brought 

into compliance, and may be combined with the periodic report. Six-month periods shall be the 

same 6-month periods specified in paragraph (g) of this section. The Notification of Compliance 

Status report shall include the information specified in paragraphs (f)(1) through (f)(5) of this 

section. This information may be submitted in an operating permit application, in an amendment 

to an operating permit application, in a separate submittal, as part of the periodic report, or in any 

combination of these four. If the required information has been submitted before the date 60 days 

after the end of the 6-month period in which the addition of the Group 1 emission point took 

place, a separate Notification of Compliance Status report is not required within 60 days after the 

end of the 6-month period. If an owner or operator submits the information specified in 

paragraphs (f)(1) through (f)(5) of this section at different times, and/or in different submittals, 

later submittals may refer to earlier submittals instead of duplicating and resubmitting the 

previously submitted information. 

(g) The owner or operator of a source subject to this subpart shall submit Periodic Reports 

no later than 60 days after the end of each 6-month period when any of the information specified 

in paragraphs (g)(1) through (7) of this section or paragraphs (g)(9) through (12) of this section is 

collected. The first 6-month period shall begin on the date the Notification of Compliance Status 

report is required to be submitted. A Periodic Report is not required if none of the events

identified in paragraph (g)(1) through (7) of this section or paragraphs (g)(9) through (12) of this 

section occurred during the 6-month period unless emissions averaging is utilized. Quarterly 

reports must be submitted for emission points included in emission averages, as provided in 

paragraph (g)(8) of this section. An owner or operator may submit reports required by other 

regulations in place of or as part of the Periodic Report required by this paragraph if the reports 

contain the information required by paragraphs (g)(1) through (12) of this section. 

(1) For storage vessels, Periodic Reports shall include the information specified for Periodic 

Reports in paragraph (g)(2) through (g)(5) of this section. Information related to gaskets, slotted 

membranes, and sleeve seals is not required for storage vessels that are part of an existing source

complying with §63.646. 

(2) Internal floating roofs. (i) An owner or operator who elects to comply with §63.646 by 

using a fixed roof and an internal floating roof or by using an external floating roof converted to 

Deleted: 4

Deleted: compliance exceptions

Deleted: 6

Deleted: occur

Deleted: compliance exceptions

Deleted: 6

Deleted: 9

Deleted: except that information
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

an internal floating roof shall submit the results of each inspection conducted in accordance with 

§63.120(a) of subpart G in which a failure is detected in the control equipment. 

(A) For vessels for which annual inspections are required under §63.120(a)(2)(i) or 

(a)(3)(ii) of subpart G, the specifications and requirements listed in paragraphs (g)(2)(i)(A)(1) 

through (3) of this section apply. 

(1) A failure is defined as any time in which the internal floating roof is not resting on the 

surface of the liquid inside the storage vessel and is not resting on the leg supports; or there is 

liquid on the floating roof; or the seal is detached from the internal floating roof; or there are 

holes, tears, or other openings in the seal or seal fabric; or there are visible gaps between the seal 

and the wall of the storage vessel. 

(2) Except as provided in paragraph (g)(2)(i)(C) of this section, each Periodic Report shall 

include the date of the inspection, identification of each storage vessel in which a failure was 

detected, and a description of the failure. The Periodic Report shall also describe the nature of 

and date the repair was made or the date the storage vessel was emptied. 

(3) If an extension is utilized in accordance with §63.120(a)(4) of subpart G, the owner or 

operator shall, in the next Periodic Report, identify the vessel; include the documentation 

specified in §63.120(a)(4) of subpart G; and describe the date the storage vessel was emptied and 

the nature of and date the repair was made. 

(B) For vessels for which inspections are required under §63.120(a)(2)(ii), (a)(3)(i), or 

(a)(3)(iii) of subpart G (i.e., internal inspections), the specifications and requirements listed in 

paragraphs (g)(2)(i)(B)(1) and (2) of this section apply. 

(1) A failure is defined as any time in which the internal floating roof has defects; or the 

primary seal has holes, tears, or other openings in the seal or the seal fabric; or the secondary seal 

(if one has been installed) has holes, tears, or other openings in the seal or the seal fabric; or, for 

a storage vessel that is part of a new source, the gaskets no longer close off the liquid surface 

from the atmosphere; or, for a storage vessel that is part of a new source, the slotted membrane 

has more than a 10 percent open area. 

(2) Each Periodic Report shall include the date of the inspection, identification of each 

storage vessel in which a failure was detected, and a description of the failure. The Periodic 

Report shall also describe the nature of and date the repair was made. 

(ii) An owner or operator who elects to comply with §63.660 by using a fixed roof and an 

internal floating roof shall submit the results of each inspection conducted in accordance with 

§63.1063(c)(1), (d)(1), and (d)(2) of subpart WW in which a failure is detected in the control 

equipment. For vessels for which inspections are required under §63.1063(c) and (d), the 

specifications and requirements listed in paragraphs (g)(2)(ii)(A) through (g)(2)(ii)(C) of this 

section apply. 

(A) A failure is defined in §63.1063(d)(1) of subpart WW. 

Deleted: of this part 

Deleted: i

Deleted: of this part

Deleted: g)(2)(i)(C

Deleted: A

Deleted: B

Deleted: C

Deleted: of this part

Deleted: of this part

Deleted: ii

Deleted: of this part 

Deleted: ii)(A

Deleted: g)(

Deleted: )(ii)(B

Deleted: A

Deleted: B
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(B) Each Periodic Report shall include a copy of the inspection record required by 

§63.1065(b) of subpart WW when a failure occurs. 

(C) An owner or operator who elects to use an extension in accordance with §63.1063(e)(2) 

of subpart WW shall, in the next Periodic Report, submit the documentation required by 

§63.1063(e)(2).

(3) External floating roofs. (i) An owner or operator who elects to comply with §63.646 by 

using an external floating roof shall meet the periodic reporting requirements specified in 

paragraphs (g)(3)(i)(A) and (B) of this section. 

(A) The owner or operator shall submit, as part of the Periodic Report, documentation of the 

results of each seal gap measurement made in accordance with §63.120(b) of subpart G in which 

the seal and seal gap requirements of §63.120(b)(3), (b)(4), (b)(5), or (b)(6) of subpart G are not 

met. This documentation shall include the information specified in paragraphs (g)(3)(i)(A)(1) 

through (4) of this section. 

(1) The date of the seal gap measurement. 

(2) The raw data obtained in the seal gap measurement and the calculations described in 

§63.120(b)(3) and (b)(4) of subpart G. 

(3) A description of any seal condition specified in §63.120(b)(5) or (b)(6) of subpart G that 

is not met. 

(4) A description of the nature of and date the repair was made, or the date the storage 

vessel was emptied. 

(B) If an extension is utilized in accordance with §63.120(b)(7)(ii) or (b)(8) of subpart G, 

the owner or operator shall, in the next Periodic Report, identify the vessel; include the 

documentation specified in §63.120(b)(7)(ii) or (b)(8) of subpart G, as applicable; and describe 

the date the vessel was emptied and the nature of and date the repair was made. 

(C) The owner or operator shall submit, as part of the Periodic Report, documentation of 

any failures that are identified during visual inspections required by §63.120(b)(10) of subpart G.

This documentation shall meet the specifications and requirements in paragraphs (g)(3)(i)(C)(1) 

and (2) of this section. 

(1) A failure is defined as any time in which the external floating roof has defects; or the 

primary seal has holes or other openings in the seal or the seal fabric; or the secondary seal has 

holes, tears, or other openings in the seal or the seal fabric; or, for a storage vessel that is part of 

a new source, the gaskets no longer close off the liquid surface from the atmosphere; or, for a 

storage vessel that is part of a new source, the slotted membrane has more than 10 percent open 

area. 

Deleted: ) through (g)(3)(iii

Deleted: i

Deleted: of this part 

Deleted: of this part 

Deleted: g)(3)(i)(D

Deleted: A

Deleted: B

Deleted: of this part

Deleted: C

Deleted: of this part 

Deleted: D

Deleted: ii

Deleted: of this part

Deleted: of this part

Deleted: iii

Deleted: of this part.

Deleted: iii)(A

Deleted: g)(3)(iii)(B

Deleted: A
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) Each Periodic Report shall include the date of the inspection, identification of each 

storage vessel in which a failure was detected, and a description of the failure. The Periodic 

Report shall also describe the nature of and date the repair was made. 

(ii) An owner or operator who elects to comply with §63.660 by using an external floating 

roof shall meet the periodic reporting requirements specified in paragraphs (g)(3)(ii)(A) and (B) 

of this section. 

(A) For vessels for which inspections are required under §63.1063(c)(2), (d)(1), and (d)(3) 

of subpart WW, the owner or operator shall submit, as part of the Periodic Report, a copy of the 

inspection record required by §63.1065(b) of subpart WW when a failure occurs. A failure is 

defined in §63.1063(d)(1). 

(B) An owner or operator who elects to use an extension in accordance with §63.1063(e)(2) 

or §63.1063(c)(2)(iv)(B) of subpart WW shall, in the next Periodic Report, submit the 

documentation required by those paragraphs. 

(4) An owner or operator who elects to comply with §63.646 or §63.660 by using an 

external floating roof converted to an internal floating roof shall comply with the periodic 

reporting requirements of paragraph (g)(2)(i) of this section. 

(5) An owner or operator who elects to comply with §63.646 or §63.660 by installing a 

closed vent system and control device shall submit, as part of the next Periodic Report, the 

information specified in paragraphs (g)(5)(i) through (g)(5)(iii) of this section, as applicable. 

(i) The Periodic Report shall include the information specified in paragraphs (g)(5)(i)(A) 

and (B) of this section for those planned routine maintenance operations that would require the 

control device not to meet the requirements of either §63.119(e)(1) or (2) of subpart G, 

§63.985(a) and (b) of subpart SS, or §63.670, as applicable. 

(A) A description of the planned routine maintenance that is anticipated to be performed for 

the control device during the next 6 months. This description shall include the type of 

maintenance necessary, planned frequency of maintenance, and lengths of maintenance periods. 

(B) A description of the planned routine maintenance that was performed for the control 

device during the previous 6 months. This description shall include the type of maintenance 

performed and the total number of hours during those 6 months that the control device did not 

meet the requirements of either §63.119(e)(1) or (2) of subpart G, §63.985(a) and (b) of subpart 

SS, or §63.670, as applicable, due to planned routine maintenance. 

(ii) If a control device other than a flare is used, the Periodic Report shall describe each 

occurrence when the monitored parameters were outside of the parameter ranges documented in 

the Notification of Compliance Status report. The description shall include: Identification of the 

control device for which the measured parameters were outside of the established ranges, and 

causes for the measured parameters to be outside of the established ranges. 

Deleted: (B

Deleted: B

Deleted: g)(5)(i)(

Deleted: e)(

Deleted: this part

Deleted: 

Deleted: e)(

Deleted: this part
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) If a flare is used prior to [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER] 

and prior to electing to comply with the requirements in §63.670, the Periodic Report shall 

describe each occurrence when the flare does not meet the general control device requirements 

specified in §63.11(b) of subpart A of this part and shall include: Identification of the flare that 

does not meet the general requirements specified in §63.11(b) of subpart A of this part, and 

reasons the flare did not meet the general requirements specified in §63.11(b) of subpart A of 

this part. 

(iv) If a flare is used on and after compliance with the requirements in §63.670 is elected, 

which can be no later than [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the Periodic Report 

shall include the items specified in paragraph (g)(11) of this section. 

(v) An owner or operator who elects to comply with §63.660 by installing an alternate 

control device as described in §63.1064 of subpart WW shall submit, as part of the next Periodic 

Report, a written application as described in §63.1066(b)(3) of subpart WW. 

(6) For miscellaneous process vents for which continuous parameter monitors are required 

by this subpart, periods of excess emissions shall be identified in the Periodic Reports and shall 

be used to determine compliance with the emission standards. 

(i) Period of excess emission means any of the following conditions: 

(A) An operating day when the daily average value of a monitored parameter, except 

presence of a flare pilot flame, is outside the range specified in the Notification of Compliance 

Status report. Monitoring data recorded during periods of monitoring system breakdown, repairs, 

calibration checks and zero (low-level) and high-level adjustments shall not be used in 

computing daily average values of monitored parameters. 

(B) An operating day when all pilot flames of a flare are absent. 

(C) An operating day when monitoring data required to be recorded in paragraphs (i)(3)(i) 

and (ii) of this section are available for less than 75 percent of the operating hours. 

(D) For data compression systems approved under paragraph (h)(5)(iii) of this section, an 

operating day when the monitor operated for less than 75 percent of the operating hours or a day 

when less than 18 monitoring values were recorded. 

(ii) For miscellaneous process vents, excess emissions shall be reported for the operating 

parameters specified in table 10 of this subpart unless other site-specific parameter(s) have been 

approved by the operating permit authority. 

(iii) For closed vent systems, include the records of periods when vent stream flow was 

detected in the bypass line or diverted from the control device, a flow indicator was not operating 

or a bypass of the system was indicated, as specified in paragraph (i)(4) of this section.

Deleted: 

Deleted: Periods of startup and shutdown that meet 

the definition of §63.641, and malfunction that meet 

the definition in §63.2 and periods of performance 

testing and monitoring system calibration shall not 

be considered periods of excess emissions. 

Malfunctions may include process unit, control 

device, or monitoring system malfunctions.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(7) If a performance test for determination of compliance for a new emission point subject 

to this subpart or for an emission point that has changed from Group 2 to Group 1 is conducted 

during the period covered by a Periodic Report, the results of the performance test shall be 

included in the Periodic Report. 

(i) Results of the performance test shall include the identification of the source tested, the 

date of the test, the percentage of emissions reduction or outlet pollutant concentration reduction 

(whichever is needed to determine compliance) for each run and for the average of all runs, and 

the values of the monitored operating parameters. 

(ii) The complete test report shall be maintained onsite. 

(8) The owner or operator of a source shall submit quarterly reports for all emission points 

included in an emissions average. 

(i) The quarterly reports shall be submitted no later than 60 calendar days after the end of 

each quarter. The first report shall be submitted with the Notification of Compliance Status 

report no later than 150 days after the compliance date specified in §63.640. 

(ii) The quarterly reports shall include: 

(A) The information specified in this paragraph and in paragraphs (g)(2) through (g)(7) of 

this section for all storage vessels and miscellaneous process vents included in an emissions 

average; 

(B) The information required to be reported by §63.428 (h)(1), (h)(2), and (h)(3) for each 

gasoline loading rack included in an emissions average, unless this information has already been 

submitted in a separate report; 

(C) The information required to be reported by §63.567(e)(4) and (j)(3) of subpart Y for 

each marine tank vessel loading operation included in an emissions average, unless the 

information has already been submitted in a separate report; 

(D) Any information pertaining to each wastewater stream included in an emissions average 

that the source is required to report under the Implementation Plan for the source; 

(E) The credits and debits calculated each month during the quarter; 

(F) A demonstration that debits calculated for the quarter are not more than 1.30 times the 

credits calculated for the quarter, as required under §§63.652(e)(4); 

(G) The values of any inputs to the credit and debit equations in §63.652 (g) and (h) that 

change from month to month during the quarter or that have changed since the previous quarter; 

and 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(H) Any other information the source is required to report under the Implementation Plan 

for the source. 

(iii) Every fourth quarterly report shall include the following: 

(A) A demonstration that annual credits are greater than or equal to annual debits as 

required by §63.652(e)(3); and 

(B) A certification of compliance with all the emissions averaging provisions in §63.652 of 

this subpart. 

(9) For heat exchange systems, Periodic Reports must include the following information: 

(i) The number of heat exchange systems at the plant site subject to the monitoring 

requirements in §63.654. 

(ii) The number of heat exchange systems at the plant site found to be leaking. 

(iii) For each monitoring location where the total strippable hydrocarbon concentration was 

determined to be equal to or greater than the applicable leak definitions specified in 

§ 63.654(c)(6), identification of the monitoring location (e.g., unique monitoring location or heat 

exchange system ID number), the measured total strippable hydrocarbon concentration, the date 

the leak was first identified, and, if applicable, the date the source of the leak was identified; 

(iv) For leaks that were repaired during the reporting period (including delayed repairs), 

identification of the monitoring location associated with the repaired leak, the total strippable 

hydrocarbon concentration measured during re-monitoring to verify repair, and the re-monitoring 

date (i.e., the effective date of repair); and 

(v) For each delayed repair, identification of the monitoring location associated with the 

leak for which repair is delayed, the date when the delay of repair began, the date the repair is 

expected to be completed (if the leak is not repaired during the reporting period), the total 

strippable hydrocarbon concentration and date of each monitoring event conducted on the 

delayed repair during the reporting period, and an estimate of the potential strippable 

hydrocarbon emissions over the reporting period associated with the delayed repair. 

(10) For relief valves, Periodic Reports must include the information specified in 

paragraphs (g)(10)(i) through (iii) of this section. 

(i) For relief valves in organic HAP gas or vapor service, pursuant to §63.648(j), report any 

instrument reading of 500 ppm or greater, more than 5 days after the relief valve returns to 

service after a pressure release. 

(ii) For relief valves in organic HAP gas or vapor service subject to §63.648(j)(2), report 

confirmation that all monitoring to show compliance was conducted within the reporting period. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) For relief valves in organic HAP service, report each pressure release to the 

atmosphere, including duration of the pressure release and estimate of quantity of substances 

released. 

(11) For flares subject to §63.670, Periodic Reports must include the information specified 

in paragraphs (g)(11)(i) through (iii) of this section. 

(i) Records as specified in paragraph (i)(9)(i) of this section for each period when regulated 

material is routed to a flare and a pilot flame is not present. 

(ii) Visible emission records as specified in paragraph (i)(9)(ii) of this section for each 

period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes. 

(iii) The 15-minute block periods for which the applicable operating limits specified in 

§63.670(d) through (f) are not met. Indicate the date and time for the period, the 15-minute block 

average operating parameters determined following the methods in §63.670(k) through (o) as 

applicable, and an indication of whether the three criteria in §63.670(e)(vi) were all met for that 

15minute block period. 

(iv) Records as specified in paragraph (i)(9)(x) of this section for each period when a 

halogenated vent stream as defined in §63.641 is discharged to the flare. 

(12) If a source fails to meet an applicable standard, report such events in the Periodic 

Report. Report the number of failures to meet an applicable standard. For each instance, report 

the date, time and duration of each failure. For each failure the report must include a list of the 

affected sources or equipment, an estimate of the quantity of each regulated pollutant emitted 

over any emission limit, and a description of the method used to estimate the emissions. 

(13) Any changes in the information provided in a previous Notification of Compliance 

Status report. 

(h) Other reports shall be submitted as specified in subpart A of this part and as follows: 

(1) [Reserved]

(2) For storage vessels, notifications of inspections as specified in paragraphs (h)(2)(i) and 

(h)(2)(ii) of this section.

(i) In order to afford the Administrator the opportunity to have an observer present, the 

owner or operator shall notify the Administrator of the refilling of each Group 1 storage vessel 

that has been emptied and degassed. 

(A) Except as provided in paragraphs (h)(2)(i) (B) and (C) of this section, the owner or 

operator shall notify the Administrator in writing at least 30 calendar days prior to filling or 

refilling of each storage vessel with organic HAP’s to afford the Administrator the opportunity to 

inspect the storage vessel prior to refilling. 

Deleted: Reports of startup, shutdown, and 

malfunction required by §63.10(d)(5). Records and 

reports of startup, shutdown, and malfunction are not 

required if they pertain solely to Group 2 emission 

points, as defined in §63.641, that are not included in 

an emissions average. For purposes of this 

paragraph, startup and shutdown shall have the 

meaning defined in §63.641, and malfunction shall 

have the meaning defined in §63.2; and

Deleted: ;
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(B) Except as provided in paragraph (h)(2)(i)(C) of this section, if the internal inspection 

required by §63.120(a)(2), §63.120(a)(3), or §63.120(b)(10) of subpart G or §63.1063(d)(1) of 

subpart WW is not planned and the owner or operator could not have known about the inspection 

30 calendar days in advance of refilling the vessel with organic HAP, the owner or operator shall 

notify the Administrator at least 7 calendar days prior to refilling of the storage vessel. 

Notification may be made by telephone and immediately followed by written documentation 

demonstrating why the inspection was unplanned. This notification, including the written 

documentation, may also be made in writing and sent so that it is received by the Administrator 

at least 7 calendar days prior to the refilling. 

(C) The State or local permitting authority can waive the notification requirements of 

paragraphs (h)(2)(i)(A) and/or (h)(2)(i)(B) of this section for all or some storage vessels at 

petroleum refineries subject to this subpart. The State or local permitting authority may also 

grant permission to refill storage vessels sooner than 30 days after submitting the notification 

required by paragraph (h)(2)(i)(A) of this section, or sooner than 7 days after submitting the 

notification required by paragraph (h)(2)(i)(B) of this section for all storage vessels, or for 

individual storage vessels on a case-by-case basis. 

(ii) In order to afford the Administrator the opportunity to have an observer present, the 

owner or operator of a storage vessel equipped with an external floating roof shall notify the 

Administrator of any seal gap measurements. The notification shall be made in writing at least 30 

calendar days in advance of any gap measurements required by §63.120(b)(1) or (b)(2) of 

subpart G or §63.1062(d)(3) of subpart WW. The State or local permitting authority can waive 

this notification requirement for all or some storage vessels subject to the rule or can allow less 

than 30 calendar days’ notice. 

(3) For owners or operators of sources required to request approval for a nominal control 

efficiency for use in calculating credits for an emissions average, the information specified in 

§63.652(h). 

(4) The owner or operator who requests approval to monitor a different parameter than 

those listed in §63.644 for miscellaneous process vents or who is required by §63.653(a)(8) to 

establish a site-specific monitoring parameter for a point in an emissions average shall submit the 

information specified in paragraphs (h)(4)(i) through (h)(4)(iii) of this section. For new or 

reconstructed sources, the information shall be submitted with the application for approval of 

construction or reconstruction required by §63.5(d) of subpart A and for existing sources, and the 

information shall be submitted no later than 18 months prior to the compliance date. The 

information may be submitted in an operating permit application, in an amendment to an 

operating permit application, or in a separate submittal. 

(i) A description of the parameter(s) to be monitored to determine whether excess emissions 

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

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

parameter can be used to determine excess emissions and the schedule for this demonstration. 

The owner or operator must certify that they will establish a range for the monitored parameter 

Deleted: of this part

Deleted: ’s

Deleted: 

Deleted: this part
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

as part of the Notification of Compliance Status report required in paragraphs (e) and (f) of this 

section. 

(iii) The frequency and content of monitoring, recording, and reporting if: monitoring and 

recording are not continuous; or if periods of excess emissions, as defined in paragraph (g)(6) of 

this section, will not be identified in Periodic Reports required under paragraphs (e) and (g) of 

this section. The rationale for the proposed monitoring, recording, and reporting system shall be 

included. 

(5) An owner or operator may request approval to use alternatives to the continuous 

operating parameter monitoring and recordkeeping provisions listed in paragraph (i) of this 

section. 

(i) Requests shall be submitted with the Application for Approval of Construction or 

Reconstruction for new sources and no later than 18 months prior to the compliance date for 

existing sources. The information may be submitted in an operating permit application, in an 

amendment to an operating permit application, or in a separate submittal. Requests shall contain 

the information specified in paragraphs (h)(5)(iii) through (h)(5)(iv) of this section, as applicable. 

(ii) The provisions in §63.8(f)(5)(i) of subpart A of this part shall govern the review and 

approval of requests. 

(iii) An owner or operator may request approval to use an automated data compression 

recording system that does not record monitored operating parameter values at a set frequency 

(for example, once every hour) but records all values that meet set criteria for variation from 

previously recorded values. 

(A) The requested system shall be designed to: 

(1) Measure the operating parameter value at least once every hour. 

(2) Record at least 24 values each day during periods of operation. 

(3) Record the date and time when monitors are turned off or on. 

(4) Recognize unchanging data that may indicate the monitor is not functioning properly, 

alert the operator, and record the incident. 

(5) Compute daily average values of the monitored operating parameter based on recorded 

data. 

(B) The request shall contain a description of the monitoring system and data compression 

recording system including the criteria used to determine which monitored values are recorded 

and retained, the method for calculating daily averages, and a demonstration that the system 

meets all criteria of paragraph (h)(5)(iii)(A) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iv) An owner or operator may request approval to use other alternative monitoring systems 

according to the procedures specified in §63.8(f) of subpart A of this part. 

(6) The owner or operator shall submit the information specified in paragraphs (h)(6)(i) 

through (h)(6)(iii) of this section, as applicable. For existing sources, this information shall be 

submitted in the initial Notification of Compliance Status report. For a new source, the 

information shall be submitted with the application for approval of construction or reconstruction 

required by §63.5(d) of subpart A of this part. The information may be submitted in an operating 

permit application, in an amendment to an operating permit application, or in a separate 

submittal. 

(i) The determination of applicability of this subpart to petroleum refining process units that 

are designed and operated as flexible operation units. 

(ii) The determination of applicability of this subpart to any storage vessel for which use 

varies from year to year. 

(iii) The determination of applicability of this subpart to any distillation unit for which use 

varies from year to year. 

(7) The owner or operator of a heat exchange system at an existing source must notify the 

Administrator at least 30 calendar days prior to changing from one of the monitoring options 

specified in §63.654(c)(4) to the other. 

(8) For fenceline monitoring systems subject to §63.658, within 45 calendar days after the 

end of each semiannual reporting period, each owner or operator shall submit the following 

information to the EPA’s Compliance and Emissions Data Reporting Interface (CEDRI) that is 

accessed through the EPA’s Central Data Exchange (CDX) (www.epa.gov/cdx). The owner or 

operator need not transmit this data prior to obtaining 12 months of data. 

(i) Individual sample results for each monitor for each sampling episode during the 

semiannual reporting period. For the first reporting period and for any period in which a passive 

monitor is added or moved, the owner or operator shall report the coordinates of all of the 

passive monitor locations. The owner or operator shall determine the coordinates using an 

instrument with an accuracy of at least 3 meters. Coordinates shall be in decimal degrees with at 

least five decimal places. 

(ii) The biweekly 12-month rolling average concentration difference (Δc) values for 

benzene for the semiannual reporting period. 

(iii) Notation for each biweekly value that indicates whether background correction was 

used, all measurements in the sampling period were below detection, or whether an outlier was 

removed from the sampling period data set. 

(9) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], if required to submit the results of a 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

performance test or CEMS performance evaluation, the owner or operator shall submit the 

results using EPA’s Electronic Reporting Tool (ERT) according to the procedures in paragraphs 

(h)(9)(i) and (ii) of this section. 

(i) Within 60 days after the date of completing each performance test as required by this 

subpart, the owner or operator shall submit the results of the performance tests according to the 

method specified by either paragraph (h)(9)(i)(A) or (h)(9)(i)(B) of this section. 

(A) For data collected using test methods supported by EPA’s ERT as listed on the EPA’s 

ERT website (http://www.epa.gov/ttn/chief/ert/index.html), the owner or operator must submit 

the results of the performance test to the CEDRI accessed through the EPA’s CDX 

(http://cdx.epa.gov/epa_home.asp), unless the Administrator approves another approach. 

Performance test data must be submitted in a file format generated through the use of the EPA’s 

ERT. If an owner or operator claims that some of the performance test information being 

submitted is confidential business information (CBI), the owner or operator must submit a 

complete file generated through the use of the EPA’s ERT, including information claimed to be 

CBI, on a compact disc or other commonly used electronic storage media (including, but not 

limited to, flash drives) by registered letter to the EPA. The electronic media must be clearly 

marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE 

Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with 

the CBI omitted must be submitted to the EPA via CDX as described earlier in this paragraph. 

(B) For data collected using test methods that are not supported by the EPA’s ERT as listed 

on the EPA’s ERT website, the owner or operator must submit the results of the performance test 

to the Administrator at the appropriate address listed in §63.13. 

(ii) Within 60 days after the date of completing each CEMS performance evaluation as 

required by this subpart, the owner or operator must submit the results of the performance 

evaluation according to the method specified by either paragraph (h)(9)(ii)(A) or (h)(9)(ii)(B) of 

this section. 

(A) For data collection of relative accuracy test audit (RATA) pollutants that are supported 

by the EPA’s ERT as listed on the ERT website, the owner or operator must submit the results of 

the performance evaluation to the CEDRI that is accessed through the EPA’s CDX, unless the 

Administrator approves another approach. Performance evaluation data must be submitted in a 

file format generated through the use of the EPA’s ERT. If an owner or operator claims that 

some of the performance evaluation information being submitted is CBI, the owner or operator 

must submit a complete file generated through the use of the EPA’s ERT, including information 

claimed to be CBI, on a compact disc or other commonly used electronic storage media 

(including, but not limited to, flash drives) by registered letter to the EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: 

WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be submitted to the EPA via CDX as described earlier in this 

paragraph. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(B) For any performance evaluation data with RATA pollutants that are not supported by 

the EPA’s ERT as listed on the EPA’s ERT website the owner or operator must submit the 

results of the performance evaluation to the Administrator at the appropriate address listed in 

§63.13. 

(i) Recordkeeping. Each owner or operator of a source subject to this subpart shall keep 

copies of all applicable reports and records required by this subpart for at least 5 years except as 

otherwise specified in paragraphs (i)(1) through (11) of this section. All applicable records shall 

be maintained in such a manner that they can be readily accessed within 24 hours. Records may 

be maintained in hard copy or computer-readable form including, but not limited to, on paper, 

microfilm, computer, flash drive, floppy disk, magnetic tape, or microfiche. 

(1) Each owner or operator subject to the storage vessel provisions in §63.646 shall keep the 

records specified in §63.123 of subpart G of this part except as specified in paragraphs (i)(1)(i) 

through (iv) of this section. Each owner or operator subject to the storage vessel provisions in 

§63.660 shall keep records as specified in paragraphs (i)(1)(v) and (vi) of this section.

(i) Records related to gaskets, slotted membranes, and sleeve seals are not required for 

storage vessels within existing sources. 

(ii) All references to §63.122 in §63.123 of subpart G of this part shall be replaced with 

§63.655(e).

(iii) All references to §63.150 in §63.123 of subpart G of this part shall be replaced with 

§63.652. 

(iv) If a storage vessel is determined to be Group 2 because the weight percent total organic 

HAP of the stored liquid is less than or equal to 4 percent for existing sources or 2 percent for 

new sources, a record of any data, assumptions, and procedures used to make this determination 

shall be retained. 

(v) Each owner or operator of a Group 1 storage vessel subject to the provisions in §63.660 

shall keep records as specified in §63.1065. 

(vi) Each owner or operator of a Group 2 storage vessel shall keep the records specified in 

§63.1065(a) of subpart WW. If a storage vessel is determined to be Group 2 because the weight 

percent total organic HAP of the stored liquid is less than or equal to 4 percent for existing 

sources or 2 percent for new sources, a record of any data, assumptions, and procedures used to 

make this determination shall be retained. 

(2) Each owner or operator required to report the results of performance tests under 

paragraphs (f) and (g)(7) of this section shall retain a record of all reported results as well as a 

complete test report, as described in paragraph (f)(2)(ii) of this section for each emission point 

tested. 

Moved (insertion) [1]

Deleted: i)(1)(

Deleted: ,
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(3) Each owner or operator required to continuously monitor operating parameters under 

§63.644 for miscellaneous process vents or under §§63.652 and 63.653 for emission points in an 

emissions average shall keep the records specified in paragraphs (i)(3)(i) through (i)(3)(v) of this 

section unless an alternative recordkeeping system has been requested and approved under 

paragraph (h) of this section. 

(i) The monitoring system shall measure data values at least once every hour. 

(ii) The owner or operator shall record either: 

(A) Each measured data value; or 

(B) Block average values for 1 hour or shorter periods calculated from all measured data 

values during each period. If values are measured more frequently than once per minute, a single 

value for each minute may be used to calculate the hourly (or shorter period) block average 

instead of all measured values. 

(iii) Daily average values of each continuously monitored parameter shall be calculated for 

each operating day and retained for 5 years except as specified in paragraph (i)(3)(iv) of this 

section. 

(A) The daily average shall be calculated as the average of all values for a monitored 

parameter recorded during the operating day. The average shall cover a 24-hour period if 

operation is continuous, or the number of hours of operation per day if operation is not 

continuous. 

(B) The operating day shall be the period defined in the Notification of Compliance Status 

report. It may be from midnight to midnight or another daily period. 

(iv) If all recorded values for a monitored parameter during an operating day are within the 

range established in the Notification of Compliance Status report, the owner or operator may 

record that all values were within the range and retain this record for 5 years rather than 

calculating and recording a daily average for that day. For these days, the records required in 

paragraph (i)(3)(ii) of this section shall also be retained for 5 years. 

(v) Monitoring data recorded during periods of monitoring system breakdowns, repairs, 

calibration checks, and zero (low-level) and high-level adjustments shall not be included in any 

average computed under this subpart. Records shall be kept of the times and durations of all such 

periods and any other periods during process or control device operation when monitors are not 

operating. 

(4) For each closed vent system that contains bypass lines that could divert a vent stream 

away from the control device and to the atmosphere, or cause air intrusion into the control 

device, the owner or operator shall keep a record of the information specified in either paragraph 

(i)(4)(i) or (ii) of this section, as applicable. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) The owner or operator shall maintain records of any alarms triggered because flow was 

detected in the bypass line, including the date and time the alarm was triggered and the duration 

of the flow in the bypass line. The owner or operator shall also maintain records of all periods 

when the vent stream is diverted from the control device or air intrudes into the control device. 

The owner or operator shall include an estimate of the volume of gas, the concentration of 

organic HAP in the gas and the resulting emissions of organic HAP that bypassed the control 

device. 

(ii) Where a seal mechanism is used to comply with §63.644(c)(2), hourly records of flow 

are not required. In such cases, the owner or operator shall record the date that the monthly 

visual inspection of the seals or closure mechanisms is completed. The owner or operator shall 

also record the occurrence of all periods when the seal or closure mechanism is broken, the 

bypass line valve position has changed or the key for a lock-and-key type lock has been checked 

out. The owner or operator shall include an estimate of the volume of gas, the concentration of 

organic HAP in the gas and the resulting emissions of organic HAP that bypassed the control 

device. 

(5) The owner or operator of a heat exchange system subject to this subpart shall comply 

with the recordkeeping requirements in paragraphs (i)(5)(i) through (v) of this section and retain 

these records for 5 years. 

(i) Identification of all petroleum refinery process unit heat exchangers at the facility and 

the average annual HAP concentration of process fluid or intervening cooling fluid estimated 

when developing the Notification of Compliance Status report. 

(ii) Identification of all heat exchange systems subject to the monitoring requirements in 

§63.654 and identification of all heat exchange systems that are exempt from the monitoring 

requirements according to the provisions in §63.654(b). For each heat exchange system that is 

subject to the monitoring requirements in §63.654, this must include identification of all heat 

exchangers within each heat exchange system, and, for closed-loop recirculation systems, the 

cooling tower included in each heat exchange system. 

(iii) Results of the following monitoring data for each required monitoring event: 

(A) Date/time of event. 

(B) Barometric pressure. 

(C) El Paso air stripping apparatus water flow milliliter/minute (ml/min) and air flow, 

ml/min, and air temperature, °Celsius. 

(D) FID reading (ppmv). 

(E) Length of sampling period. 

(F) Sample volume. 

Deleted: 4
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(G) Calibration information identified in Section 5.4.2 of the “Air Stripping Method 

(Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from 

Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, 

Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental 

Quality, January 31, 2003 (incorporated by reference—see §63.14). 

(iv) The date when a leak was identified, the date the source of the leak was identified, and 

the date when the heat exchanger was repaired or taken out of service. 

(v) If a repair is delayed, the reason for the delay, the schedule for completing the repair, the 

heat exchange exit line flow or cooling tower return line average flow rate at the monitoring 

location (in gallons/minute), and the estimate of potential strippable hydrocarbon emissions for 

each required monitoring interval during the delay of repair. 

(6) All other information required to be reported under paragraphs (a) through (h) of this 

section shall be retained for 5 years. 

(7) Each owner or operator subject to the delayed coking unit decoking operations 

provisions in §63.657 must maintain records of the average pressure for the 5-minute period 

prior to venting to the atmosphere, draining, or deheading the coke drum for each cooling cycle 

for each coke drum. 

(8) For fenceline monitoring systems subject to §63.658, each owner or operator shall keep 

the records specified in paragraphs (i)(8)(i) through (ix) of this section on an ongoing basis. 

(i) Coordinates of all passive monitors, including replicate samplers and field blanks, and 

the meteorological station. The owner or operator shall determine the coordinates using an 

instrument with an accuracy of at least 3 meters. The coordinates shall be in decimal degrees 

with at least five decimal places. 

(ii) The start and stop times and dates for each sample, as well as the tube identifying 

information. 

(iii) Daily unit vector wind direction, calculated daily sigma theta, daily average 

temperature and daily average barometric pressure measurements. 

(iv) For each outlier determined in accordance with Section 9.2 of Method 325A of 

Appendix A of this part, the sampler location of and the concentration of the outlier and the 

evidence used to conclude that the result is an outlier. 

(v) For samples that will be adjusted for a background, the location of and the concentration 

measured simultaneously by the background sampler, and the perimeter samplers to which it 

applies. 

Deleted: 5
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(vi) Individual sample results, the calculated Δc for benzene for each sampling episode and 

the two samples used to determine it, whether background correction was used, and the 12-

month rolling average Δc calculated after each sampling episode. 

(vii) Method detection limit for each sample, including co-located samples and blanks. 

(viii) Documentation of corrective action taken each time the action level was exceeded. 

(ix) Other records as required by Methods 325A and 325B of Appendix A of this part. 

(9) For each flare subject to §63.670, each owner or operator shall keep the records 

specified in paragraphs (i)(9)(i) through (vii) of this section up-to-date and readily accessible, as 

applicable. 

(i) Retain records of the output of the monitoring device used to detect the presence of a 

pilot flame as required in §63.670(b) for a minimum of 2 years. Retain records of periods during 

which the pilot flame is not present when regulated material is routed to a flare for a minimum of 

5 years. 

(ii) Daily visible emissions observations, as required in §63.670(c), as well as any 

observations required in §63.670(h). The record must identify whether the visible emissions 

observation was performed, the results of each observation, total duration of observed visible 

emissions, and whether it was a 5-minute or 2-hour observation. If the owner or operator 

performs visible emissions observations more than one time during a day, the record must also 

identify the date and time of day each visible emissions observation was performed. 

(iii) The 15-minute block average cumulative flows for flare vent gas and, if applicable, 

total steam, perimeter assist air, and premix assist air specified to be monitored under §63.670(i), 

along with the date and time interval for the 15-minute block. If multiple monitoring locations 

are used to determine cumulative vent gas flow, total steam, perimeter assist air, and premix 

assist air, retain records of the 15-minute block average flows for each monitoring location for a 

minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in 

subsequent calculations for a minimum of 5 years. If pressure and temperature monitoring is 

used, retain records of the 15-minute block average temperature, pressure and molecular weight 

of the flare vent gas or assist gas stream for each measurement location used to determine the 15-

minute block average cumulative flows for a minimum of 2 years, and retain the 15-minute block 

average cumulative flows that are used in subsequent calculations for a minimum of 5 years. 

(iv) The flare vent gas compositions specified to be monitored under §63.670(j). Retain 

records of individual component concentrations from each compositional analyses for a 

minimum of 2 years. If NHVvg or total hydrocarbon analyzer is used, retain records of the 15-

minute block average values for a minimum of 5 years. 

(v) Each 15-minute block average operating parameter calculated following the methods 

specified in §63.670(k) through (m), as applicable. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(vi) The 15-minute block average olefins, hydrogen, and olefins plus hydrogen 

concentration in the combustion zone used to determine if the criteria in §63.670(e)(4) are met. If 

process knowledge and engineering calculations are used, retain records of the information used 

in the assessment and records of all compositional analyses required in §63.670(o)(ii). Identify 

all 15-minute block averages for which all three criteria in §63.670(e)(4) are met or are assumed 

to be met. 

 (vii) All periods during which operating values are outside of the applicable operating 

limits specified in §63.670(d) through (f) when regulated material is being routed to the flare. 

(viii) All periods during which the owner or operator does not perform flare monitoring 

according to the procedures in §63.670(g) through (j). 

(ix) Records of periods when there is flow of vent gas to the flare, but when there is no flow 

of regulated material to the flare, including the start and stop time and dates of periods of no 

regulated material flow. 

(x) All periods during which a halogenated vent stream, as defined in §63.641, is discharged 

to the flare. Records shall include the start time and date of the event, the end time and date of 

the event, and an estimate of the cumulative flow of the halogenated vent stream over the 

duration of the event. 

(10) If the owner or operator elects to comply with §63.661, the owner or operator shall 

keep the records described in paragraphs (i)(10)(i) through (v) of this section. 

(i) The equipment and process units for which the owner or operator chooses to use the 

optical gas imaging instrument. 

(ii) All records required by part 60, Appendix K of this chapter, as applicable. 

(iii) A video record to document the leak survey results. The video record must include a 

time and date stamp for each monitoring event. 

(iv) Identification of the equipment screened and the time and date of the screening. 

(v) Documentation of repairs attempted and repairs delayed. If repair of a leak is confirmed 

using the optical gas imaging instrument, then instead of the maximum instrument reading 

measured by Method 21 of part 60, Appendix A–7 of this chapter, the owner or operator shall 

keep a video record following repair to confirm the equipment is repaired. 

(11) Other records must be kept as specified in paragraphs (i)(11)(i) through (iii) of this 

section. 

(i) In the event that an affected unit fails to meet an applicable standard, record the number 

of failures. For each failure, record the date, time and duration of each failure. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) For each failure to meet an applicable standard, record and retain a list of the affected 

sources or equipment, an estimate of the volume of each regulated pollutant emitted over any 

emission limit and a description of the method used to estimate the emissions. 

(iii) Record actions taken to minimize emissions in accordance with §63.642(n), and any 

corrective actions taken to return the affected unit to its normal or usual manner of operation. 

§ 63.656 Implementation and enforcement. 

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

such as the applicable State, local, or Tribal agency. If the U.S. EPA Administrator has delegated 

authority to a State, local, or Tribal agency, then that agency, in addition to the U.S. EPA, has the 

authority to implement and enforce this subpart. Contact the applicable U.S. EPA Regional 

Office to find out if implementation and enforcement of this subpart is delegated to a State, local, 

or Tribal agency. 

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

or Tribal agency under subpart E of this part, the authorities contained in paragraph (c) of this 

section are retained by the Administrator of U.S. EPA and cannot be transferred to the State, 

local, or Tribal agency. 

(c) The authorities that cannot be delegated to state, local, or Tribal agencies are as 

specified in paragraphs (c)(1) through (5) of this section. 

(1) Approval of alternatives to the requirements in §§63.640, 63.642(g) through (l), 63.643, 

63.646 through 63.652, 63.654, 63.657 through 63.661, and 63.670. Where these standards 

reference another subpart, the cited provisions will be delegated according to the delegation 

provisions of the referenced subpart. Where these standards reference another subpart and 

modify the requirements, the requirements shall be modified as described in this subpart. 

Delegation of the modified requirements will also occur according to the delegation provisions 

of the referenced subpart. 

(2) Approval of major alternatives to test methods under §63.7(e)(2)(ii) and (f), as defined 

in §63.90, and as required in this subpart. 

(3) Approval of major alternatives to monitoring under §63.8(f), as defined in §63.90, and 

as required in this subpart. 

(4) Approval of major alternatives to recordkeeping and reporting under §63.10(f), as 

defined in §63.90, and as required in this subpart. 

(5) Approval of the corrective action plan under §63.658(h). 

Deleted: S

Deleted: 4

Deleted: 654
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§ 63.657 Delayed coking unit decoking operation standards. 

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

closed blowdown system until the coke drum vessel pressure is 2 pounds per square inch gauge 

(psig) or less prior to venting to the atmosphere, draining or deheading the coke drum at the end 

of the cooling cycle. 

(b) Each owner or operator of a delayed coking unit shall install, operate, calibrate, and 

maintain a continuous parameter monitoring system to determine the coke drum vessel pressure. 

The pressure monitoring system must be capable of measuring a pressure of 2 psig within ±0.5 

psig. 

(c) The owner or operator of a delayed coking unit shall determine the coke drum vessel 

pressure on a 5-minute rolling average basis while the coke drum is vented to the closed 

blowdown system to demonstrate compliance the requirement in paragraph (a) of this section. 

Pressure readings after initiating steps to isolate the coke drum from the closed blowdown 

system just prior to atmospheric venting, draining, or deheading the coke drum shall not be used 

in determining the average coke drum vessel pressure for the purpose of compliance with the 

requirement in paragraph (a) of this section. 

§ 63.658 Fenceline monitoring provisions. 

(a) The owner or operator shall conduct sampling along the facility property boundary and 

analyze the samples in accordance with Methods 325A and 325B of Appendix A of this part. 

(b) The target analyte is benzene. 

(c) The owner or operator shall determine passive monitor locations in accordance with 

Section 8.2 of Method 325A of Appendix A of this part. General guidance for siting passive 

monitors can be found in EPA-454/R-98-004, Quality Assurance Handbook for Air Pollution 

Measurement Systems, Volume II: Part 1: Ambient Air Quality Monitoring Program Quality 

System Development, August 1998 (incorporated by reference-see §63.14). Alternatively, the 

owner or operator may elect to place monitors at 2 kilometers intervals as measured along the 

property boundary, provided additional monitors are located, if necessary, as required in Section 

8.2.2.5 in Method 325A of Appendix A of this part. 

(1) As it pertains to this subpart, known emission source, as used in Section 8.2.2.5 in 

Method 325A of Appendix A of this part for siting passive monitors means a wastewater 

treatment unit or a Group 1 storage vessel. 

(2) The owner or operator may collect one or more background samples if the owner or 

operator believes that an offsite upwind source or an onsite source excluded under §63.640(g) 

may influence the sampler measurements. If the owner or operator elects to collect one or more 

background samples, the owner of operator must develop and submit a site-specific monitoring 

plan for approval according to the requirements in paragraph (i) of this section. Upon approval of 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

the site-specific monitoring plant, the background sampler(s) should be operated co-currently 

with the routine samplers. 

(3) The owner or operator shall collect at least one co-located duplicate sample for every 10 

field samples per sampling episode and at least two field blanks per sampling episode, as 

described in Section 9.3 in Method 325A of Appendix A of this part. The co-located duplicates 

may be collected at any one of the perimeter sampling locations. 

(4) The owner or operator shall follow the procedure in Section 9.6 of Method 325B of 

Appendix A of this part to determine the detection limit of benzene for each sampler used to 

collect samples, background samples (if the owner or operator elects to do so), co-located 

samples and blanks. 

(d) The owner or operator shall use a dedicated meteorological station in accordance with 

Section 8.3 of Method 325A of Appendix A of this part. 

(1) The owner or operator shall collect and record hourly average meteorological data, 

including wind speed, wind direction and temperature. 

(2) The owner or operator shall follow the calibration and standardization procedures for 

meteorological measurements in EPA-454/B-08-002, Quality Assurance Handbook for Air 

Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 

(Final), March 2008 (incorporated by reference—see §63.14). 

(e) The length of the sampling episode must be fourteen days, unless a shorter sampling 

episode is determined to be necessary under paragraph (g) or (i) of this section. A sampling 

episode is defined as the period during which the owner or operator collects the sample and does 

not include the time required to analyze the sample. 

(f) Within 30 days of completion of each sampling episode, the owner or operator shall 

determine whether the results are above or below the action level as follows: 

(1) For each sampling episode, the owner or operator shall determine the highest and lowest 

sample results for benzene from the sample pool and calculate the difference in concentration 

(Δc). 

(i) The owner or operator shall adhere to the following procedures when one or more 

samples for the sampling episode are below the method detection limit for benzene: 

(A) If the lowest detected value of benzene is below detection, the owner or operator shall 

use zero as the lowest sample result when calculating Δc. 

(B) If all sample results are below the method detection limit, the owner or operator shall 

use the method detection limit as the highest sample result. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) If the owner or operator identifies an offsite upwind source or an onsite source excluded 

under §63.640(g) that contributes to the benzene concentration at any passive monitor and 

collects background samples according to an approved site-specific monitoring plan, the owner 

or operator shall determine Δc using the calculation protocols outlined in the approved sitespecific monitoring plan and in paragraph (i) of this section. 

(2) The owner or operator shall average the Δc values collected over the twelve months 

prior to and including the most recent sampling episode. The owner or operator shall update this 

value after receiving the results of each sampling episode. 

(3) The action level for benzene is 9 micrograms per cubic meter (μg/m3). If the 12-month 

rolling average Δc value for benzene is less than 9 μg/m3, the concentration is below the action 

level. If the 12-month rolling average Δc value for benzene is equal to or greater than 9 μg/m3, 

the concentration is above the action level, and the owner or operator shall conduct a root cause 

analysis and corrective action in accordance with paragraph (g) of this section. 

(g) Within 5 days of determining that the action level has been exceeded for any 12-month 

rolling average and no longer than 35 days after completion of the sampling episode, the owner 

or operator shall initiate a root cause analysis to determine the cause of such exceedance and to 

determine appropriate corrective action, as described in paragraphs (g)(1) through (4) of this 

section. The root cause analysis and corrective action analysis shall be completed no later than 

45 days after determining there is an exceedance. Root cause analysis and corrective action may 

include, but is not limited to: 

(1) Leak inspection using Method 21 of part 60, Appendix A-7 of this chapter and repairing 

any leaks found. 

(2) Leak inspection using optical gas imaging as specified in §63.661 and repairing any 

leaks found. 

(3) Visual inspection to determine the cause of the high benzene emissions and 

implementing repairs to reduce the level of emissions. 

(4) Employing progressively more frequent sampling, analysis and meteorology (e.g., using 

shorter sampling episodes for Methods 325A and 325B of Appendix A of this part, or using 

active sampling techniques), or employing additional monitors to determine contributing offsite 

sources. 

(h) If, upon completion of the corrective actions described in paragraph (g) of this section, 

the action level is exceeded for the next sampling episode following the completion of the 

corrective action, the owner or operator shall develop a corrective action plan that describes the 

corrective action(s) completed to date, additional measures that the owner or operator proposes 

to employ to reduce fenceline concentrations below the action level, and a schedule for 

completion of these measures. The owner or operator shall submit the corrective action plan to 

the Administrator within 60 days after determining the action level was exceeded during the 

sampling episode following the completion of the initial corrective action. The Administrator 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

shall approve or disapprove the plan in 90 days. The plan shall be considered approved if the 

Administrator either approves the plan in writing, or fails to disapprove the plan in writing. The 

90-day period shall begin when the Administrator receives the plan. 

(i) An owner or operator may request approval from the Administrator for a site-specific 

monitoring plan to account for offsite upwind sources or onsite sources excluded under 

§63.640(g) according to the requirements in paragraphs (i)(1) through (4) of this section. 

(1) The owner or operator shall prepare and submit a site-specific monitoring plan and 

receive approval of the site-specific monitoring plan prior to using the near-field source 

alternative calculation for determining Δc provided in paragraph (i)(2) of this section. The sitespecific monitoring plan shall include, at a minimum, the elements specified in paragraphs 

(i)(1)(i) through (v) of this section. 

(i) Identification of the near-field source or sources. For onsite sources, documentation that 

the onsite source is excluded under §63.640(g) and identification of the specific provision in 

§63.640(g) that applies to the source. 

(ii) Location of the additional monitoring stations that shall be used to determine the 

uniform background concentration and the near-field source concentration contribution. 

(iii) Identification of the fenceline monitoring locations impacted by the near-field source. If 

more than one near-field source is present, identify for each monitoring location, the near field 

source or sources that are expected to contribute to fenceline concentration at that monitoring 

location. 

(iv) A description of (including sample calculations illustrating) the planned data reduction 

and calculations to determine the near-field source concentration contribution for each 

monitoring location. 

(v) If more frequent monitoring is proposed or if a monitoring station other than a passive 

diffusive tub monitoring station is proposed, provide a detailed description of the measurement 

methods, measurement frequency, and recording frequency proposed for determining the 

uniform background or near-field source concentration contribution. 

(2) When an approved site-specific monitoring plan is used, the owner or operator shall 

determine Δc for comparison with the 9 μg/m3 action level using the requirements specified in 

paragraphs (2)(i) through (iii) of this section. 

(i) For each monitoring location, calculate Δci using the following equation. 

Δci  MFCi  NFS i UB

where: 

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Δci = The fenceline concentration, corrected for background, at measurement location i, 

micrograms per cubic meter (μg/m3). 

MFCi = The measured fenceline concentration at measurement location i, μg/m3. 

NFSi = The near-field source contributing concentration at measurement location i 

determined using the additional measurements and calculation procedures included in the sitespecific monitoring plan, μg/m3

. For monitoring locations that are not included in the sitespecific monitoring plan as impacted by a near-field source, use NFSi = 0 μg/m3

. 

UB = The uniform background concentration determined using the additional measurements 

specified included in the site-specific monitoring plan, μg/m3. If no additional measurement 

location is specified in the site-specific monitoring plan for determining the uniform background 

concentration, use UB = 0 μg/m3. 

(ii) When one or more samples for the sampling episode are below the method detection 

limit for benzene, adhere to the following procedures: 

(A) If the benzene concentration at the monitoring location used for the uniform 

background concentration is below detection, the owner or operator shall use zero for UB for that 

monitoring period. 

(B) If the benzene concentration at the monitoring location(s) used to determine the nearfield source contributing concentration is below detection, the owner or operator shall use zero 

for the monitoring location concentration when calculating NFSi for that monitoring period. 

(C) If a fenceline monitoring location sample result is below the method detection limit, the 

owner or operator shall use the method detection limit as the sample result. 

(iii) Determine Δc for the monitoring period as the maximum value of Δci from all of the 

fenceline monitoring locations for that monitoring period. 

(3) The site-specific monitoring plan shall be submitted and approved as described in 

paragraphs (i)(3)(i) through (iv) of this section. 

(i) The site-specific monitoring plan must be submitted to the Administrator for approval. 

(ii) The site-specific monitoring plan shall also be submitted to the following address: U.S. 

Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies 

and Programs Division, U.S. EPA Mailroom (E143–01), Attention: Refinery Sector Lead, 109 

T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard 

copies may also be submitted to refineryrtr@epa.gov. 

(ii) The Administrator shall approve or disapprove the plan in 90 days. The plan shall be 

considered approved if the Administrator either approves the plan in writing, or fails to 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

disapprove the plan in writing. The 90-day period shall begin when the Administrator receives 

the plan. 

(iii) If the Administrator finds any deficiencies in the site-specific monitoring plan and 

disapproves the plan in writing, the owner or operator may revise and resubmit the site-specific 

monitoring plan following the requirements in paragraphs (i)(3)(i) and (ii) of this section. The 

90-day period starts over with the resubmission of the revised monitoring plan. 

(4) The approval by the Administrator of a site-specific monitoring plan will be based on 

the completeness, accuracy and reasonableness of the request process for a site-specific 

monitoring plan. Factors that the EPA will consider in reviewing the request for a site-specific 

monitoring plan include, but are not limited to, those described in paragraphs (i)(4)(i) through (v) 

of this section. 

(i) The identification of the near-field source or sources. For onsite sources, the 

documentation provided that the onsite source is excluded under §63.640(g). 

(ii) The monitoring location selected to determine the uniform background concentration or 

an indication that no uniform background concentration monitor will be used. 

(iii) The location(s) selected for additional monitoring to determine the near-field source 

concentration contribution. 

(iv) The identification of the fenceline monitoring locations impacted by the near-field 

source or sources. 

(v) The appropriateness of the planned data reduction and calculations to determine the 

near-field source concentration contribution for each monitoring location. 

(vi) If more frequent monitoring is proposed or if a monitoring station other than a passive 

diffusive tub monitoring station is proposed, the adequacy of the description of the measurement 

methods, measurement frequency, and recording frequency proposed and the adequacy of the 

rationale for using the alternative monitoring frequency or method. 

(j) The owner or operator shall comply with the applicable recordkeeping and reporting 

requirements in §63.655(h) and (i). 

§ 63.659 [Reserved] 

§ 63.660 Storage vessel provisions. 

On and after the applicable compliance date for a Group 1 storage vessel located at a new or 

existing source as specified in §63.640(h), the owner or operator of a Group 1 storage vessel that 

is part of a new or existing source shall comply with the requirements in subpart WW or subpart 

SS of this part according to the requirements in paragraphs (a) through (i) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(a) As used in this section, all terms not defined in §63.641 shall have the meaning given 

them in subpart A, subpart WW, or subpart SS of this part. The definitions of “Group 1 storage 

vessel” (item 2) and “storage vessel” in §63.641 shall apply in lieu of the definition of “storage 

vessel” in §63.1061. 

(1) An owner or operator may use good engineering judgment or test results to determine 

the stored liquid weight percent total organic HAP for purposes of group determination. Data, 

assumptions, and procedures used in the determination shall be documented. 

(2) When an owner or operator and the Administrator do not agree on whether the annual 

average weight percent organic HAP in the stored liquid is above or below 4 percent for a 

storage vessel at an existing source or above or below 2 percent for a storage vessel at a new 

source, an appropriate method (based on the type of liquid stored) as published by EPA or a 

consensus-based standards organization shall be used. Consensus-based standards organizations 

include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. 

Box CB700, West Conshohocken, Pennsylvania 19428–B2959, (800) 262–1373, 

http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th 

floor, Washington, DC 20036, (202) 293–8020, http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 

824–7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016–5990, (800) 843–2763, http://www.asme.org), the 

American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005–4070, (202) 

682–8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 

Travis Street, Suite 1675, Houston, TX 77002, (713) 356–0060, http://www.naesb.org). 

(b) In addition to the options presented in §§63.1063(a)(2)(vii)(A), 63.1063(a)(2)(vii)(B), 

and 63.1064, an external floating roof storage vessel may comply with §63.1063(a)(2)(vii) using 

a flexible enclosure system as described in item 6 of Appendix I: Acceptable Controls for Slotted 

Guidepoles Under the Storage Tank Emissions Reduction Partnership Program (65 FR 19893). 

(c) For the purposes of this subpart, references shall apply as specified in paragraphs (c)(1) 

through (6) of this section. 

(1) All references to “the proposal date for a referencing subpart” and “the proposal date of 

the referencing subpart” in subpart WW of this part mean [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. 

(2) All references to “promulgation of the referencing subpart” and “the promulgation date 

of the referencing subpart” in subpart WW of this part mean [THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. 

(3) All references to “promulgation date of standards for an affected source or affected 

facility under a referencing subpart” in subpart SS of this part mean [THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) All references to “the proposal date of the relevant standard established pursuant to 

CAA section 112(f)” in subpart SS of this part mean [INSERT DATE OF PUBLICATION IN 

THE FEDERAL REGISTER]. 

(5) All references to “the proposal date of a relevant standard established pursuant to CAA 

section 112(d)” in subpart SS of this part mean July 14, 1994. 

(6) All references to the “required control efficiency” in subpart SS of this part mean 

reduction of organic HAP emissions by 95 percent or to an outlet concentration of 20 ppmv. 

(d) For an existing storage vessel fixed roof that meets the definition of Group 1 storage 

vessel (item 2) in §63.641 but not the definition of Group 1 storage vessel (item 1) in §63.641, 

the requirements of §63.1062 do not apply until the next time the storage vessel is completely 

emptied and degassed, or [THE DATE 10 YEARS AFTER PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], whichever occurs first. 

(e) Failure to perform inspections and monitoring required by this section shall constitute a 

violation of the applicable standard of this subpart. 

(f) References in §63.1066(a) to initial startup notification requirements do not apply. 

(g) References to the Notification of Compliance Status in §63.999(b) mean the Notification 

of Compliance Status required by §63.655(f). 

(h) References to the Periodic Reports in §§63.1066(b) and 63.999(c) mean the Periodic 

Report required by §63.655(g). 

(i) If a flare is used as a control device, the flare shall meet the requirements of §63.670 

instead of the flare requirements in §63.987. 

§ 63.661 Alternative means of emission limitation: Monitoring equipment leaks using 

optical gas imaging. 

(a) Applicability. The owner or operator may only use an optical gas imaging instrument to 

screen for leaking equipment, as required by §63.648, if the requirements in paragraphs (a)(1) 

through (3) of this section are met. 

(1) The owner or operator may only use the optical gas imaging instrument as an alternative 

to provisions in §63.648 that would otherwise require monitoring according to §60.485(b) or 

§63.180(b)(1) through (5), as applicable. The owner or operator shall continue to comply with all 

other requirements in §63.648 (e.g., weekly inspections of pumps; for relief valves, installation 

of a device that is capable of identifying and recording the time and duration of each pressure 

release, if applicable; sampling connection system requirements). 

(2) The owner or operator must be in compliance with the fenceline monitoring provisions 

of §63.658. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(3) The optical gas imaging instrument must be able to meet all of the criteria and 

requirements specified in part 60, Appendix K of this chapter, and the owner or operator shall 

conduct monitoring according to part 60, Appendix K of this chapter. 

(b) Compliance requirements. The owner or operator shall meet the requirements of 

paragraphs (b)(1) through (3) of this section. 

(1) The owner or operator shall identify the equipment and process units for which the 

optical gas imaging instrument will be used to identify leaks. 

(2) The owner or operator shall repair leaking equipment as required in the applicable 

section of part 60, subpart VV of this chapter or subpart H of this part. 

(3) Monitoring to confirm repair of leaking equipment must be conducted using the 

procedures referenced in paragraph (a)(2) of this section. 

(c) Recordkeeping. The owner or operator shall comply with the applicable requirements in 

§63.655(i). 

§§ 63.662-63.669 [Reserved] 

§ 63.670 Requirements for flare control devices. 

On or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the owner or operator of a 

flare used as a control device for an emission point subject to this subpart shall meet the 

applicable requirements for flares as specified in paragraphs (a) through (q) of this section and 

the applicable requirements in §63.671. The owner or operator may elect to comply with the 

requirements of paragraph (r) of this section in lieu of the requirements in paragraphs (g) through 

(o) of this section, as applicable. 

(a) Halogenated vent streams. The owner or operator shall not use a flare to control 

halogenated vent streams as defined in §63.641. 

 (b) Pilot flame presence. The owner or operator shall operate each flare with a pilot flame 

present at all times when regulated material is routed to the flare. The pilot system must be 

equipped with an automated device to relight the pilot if extinguished. The owner or operator 

shall monitor for the presence of a pilot flame as specified in paragraph (h) of this section. 

(c) Visible emissions. Each flare must be designed for and operated with no visible 

emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours. 

The owner or operator shall monitor for visible emissions from the flare as specified in 

paragraph (i) of this section. 

(d) Flare tip velocity. For each flare, the owner or operator shall comply with either 

paragraph (d)(1) or (d)(2) of this section, provided the appropriate monitoring systems are in-
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

place. If a total hydrocarbon analyzer is used for compositional analysis as allowed under section 

(g)(4) of this section, then the owner or operator must comply with paragraph (d)(1) of this 

section. 

(1) Except as provided in paragraph (d)(2) of this section, the actual flare tip velocity (Vtip) 

must be less than 60 feet per second when regulated material is being routed to the flare. The 

owner or operator shall monitor Vtip using the procedures specified in paragraph (i) and (k) of 

this section. 

(2) Vtip must be less than 400 feet per second and also less than the maximum allowed flare 

tip velocity (Vmax) as calculated according to the following equation at all times regulated 

material is being routed to the flare. The owner or operator shall monitor Vtip using the 

procedures specified in paragraph (i) and (k) of this section and monitor gas composition and 

determine NHVvg using the procedures specified in paragraphs (j) and (l) of this section. 

  850

1,212 10

  vg

max

NHV

Log V

where: 

Vmax = Maximum allowed flare tip velocity, ft/sec. 

NHVvg = Net heating value of flare vent gas, as determined by paragraph (l)(4) of this 

section, Btu/scf. 

1,212 = Constant. 

850 = Constant. 

(e) Target combustion zone gas properties. For each flare, the owner or operator shall 

comply with the applicable requirements in either paragraph (f)(1), (2), or (3) of this section. The 

owner or operator may elect to comply with any of these applicable requirements at any time 

(e.g., may elect to comply with the requirements in paragraph (e)(1) during certain flow 

conditions and comply with the requirements in paragraph (e)(2) or (e)(3) under different flow 

conditions) provided that the owner or operator has the appropriate monitoring equipment to 

determine compliance with the specified requirement. 

(1) The net heating value of flare combustion zone gas (NHVcz) must be greater than or 

equal to the target values in paragraphs (e)(1)(i) or (ii), as applicable, when regulated material is 

being routed to the flare. The owner or operator shall monitor and calculate NHVcz as specified 

in paragraph (m) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

NHVcz value is 380 British thermal units per standard cubic feet (Btu/scf). 

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target NHVcz value is 270 Btu/scf. 

(2) The lower flammability limit of the combustion zone gas (LFLcz) must be less than or 

equal to the target values in paragraphs (e)(2)(i) or (ii), as applicable, when regulated material is 

being routed to the flare. The owner or operator shall monitor and calculate LFLcz as specified in 

paragraph (n) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

LFLcz value is 0.11 volume fraction. 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target LFLcz value is 0.15 volume fraction. 

(3) The total volumetric fraction of hydrogen and combustible organic components present 

in the combustion zone gas (Ccz), as propane, must be greater than or equal to the target values in 

paragraphs (e)(3)(i) or (ii), as applicable, when regulated material is being routed to the flare. 

The owner or operator shall monitor and calculate Ccz as specified in paragraph (l) of this 

section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target Ccz

value is 0.23 volume fraction as propane. 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target Ccz value is 0.18 volume fraction as propane. 

(4) More stringent combustion zone gas target properties apply only during those flare flow 

periods when all three conditions in paragraphs (e)(4)(i) through (iii) simultaneously exist. The 

owner or operator shall monitor and calculate hydrogen and cumulative olefin combustion zone 

concentrations as specified in paragraph (o) of this section: 

(i) The concentration of hydrogen in the combustion zone is greater than 1.2 percent by 

volume. 

(ii) The cumulative concentration of olefins in the combustion zone is greater than 2.5 

percent by volume. 

(iii) The cumulative concentration of olefins in the combustion zone plus the concentration 

of hydrogen in the combustion zone is greater than 7.4 percent by volume. 

(f) Target dilution parameters for flares with perimeter assist air. For each flare actively 

receiving perimeter assist air, the owner or operator shall comply with the applicable 

requirements in either paragraph (f)(1), (2), or (3) of this section in addition to complying with 

the target combustion zone gas properties as specified in paragraph (e) of this section. The owner 

or operator may elect to comply with any of these applicable requirements at any time (e.g., may 

elect to comply with the requirements in paragraph (f)(1) during certain flow conditions and 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

comply with the requirements in paragraph (f)(2) or (f)(3) under different flow conditions) 

provided that the owner or operator has the appropriate monitoring equipment to determine 

compliance with the specified requirement. 

(1) The net heating value dilution parameter (NHVdil) must be greater than or equal to the 

target values in paragraphs (f)(1)(i) or (ii), as applicable, when regulated material is being routed 

to the flare. The owner or operator shall monitor and calculate NHVdil as specified in paragraph 

(o) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

NHVdil value is 31 British thermal units per square foot (Btu/ft2). 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target NHVdil value is 22 Btu/ft2. 

(2) The lower flammability limit dilution parameter (LFLdil) must be less than or equal to 

the target values in paragraphs (f)(2)(i) or (ii), as applicable, when regulated material is being 

routed to the flare. The owner or operator shall monitor and calculate LFLdil as specified in 

paragraph (o) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

LFLdil value is 1.6 volume fraction per foot (volume fraction/ft). 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target LFLdil value is 2.2 volume fraction/ft. 

(3) The combustibles concentration dilution parameter (Cdil) must be greater than or equal to 

the target values in paragraphs (f)(3)(i) or (ii), as applicable, when regulated material is being 

routed to the flare. The owner or operator shall monitor and calculate Cdil as specified in 

paragraph (o) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

Cdil value is 0.015 volume fraction-ft. 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target Ccz value is 0.012 volume fraction-ft. 

(g) Pilot flame monitoring. The owner or operator shall continuously monitor the presence 

of the pilot flame(s) using a device (including, but not limited to, a thermocouple, ultraviolet 

beam sensor, or infrared sensor) capable of detecting that the pilot flame(s) is present. 

(h) Visible emissions monitoring. The owner or operator shall monitor visible emissions 

while regulated materials are vented to the flare. An initial visible emissions demonstration must 

be conducted using an observation period of 2 hours using Method 22 at 40 CFR part 60, 

Appendix A-7. Subsequent visible emissions observations must be conducted at a minimum of 

once per day using an observation period of 5 minutes using Method 22 at 40 CFR part 60, 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Appendix A-7. If at any time the owner or operator sees visible emissions, even if the minimum 

required daily visible emission monitoring has already been performed, the owner or operator 

shall immediately begin an observation period of 5 minutes using Method 22 at 40 CFR part 60, 

Appendix A-7. If visible emissions are observed for more than one continuous minute during any 

5-minute observation period, the observation period using Method 22 at 40 CFR part 60, 

Appendix A-7 must be extended to 2 hours. 

(i) Flare vent gas, steam assist and air assist flow rate monitoring. The owner or operator 

shall install, operate, calibrate, and maintain a monitoring system capable of continuously 

measuring, calculating, and recording the volumetric flow rate in the flare header or headers that 

feed the flare. If assist air or assist steam is used, the owner or operator shall install, operate, 

calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and 

recording the volumetric flow rate of assist air and/or assist steam used with the flare. If pre-mix 

assist air and perimeter assist are both used, the owner or operator shall install, operate, calibrate, 

and maintain a monitoring system capable of separately measuring, calculating, and recording 

the volumetric flow rate of premix assist air and perimeter assist air used with the flare 

(1) The flow rate monitoring systems must be able to correct for the temperature and 

pressure of the system and output parameters in standard conditions (i.e., a temperature of 20 °C 

[68 °F] and a pressure of 1 atm). The flare vent gas flow rate monitoring system(s) must also be 

able to output flow in actual conditions for use in the flare tip velocity calculation. 

(2) Mass flow monitors may be used for determining volumetric flow rate of flare vent gas 

provided the molecular weight of the flare vent gas is determined using compositional analysis as 

specified in paragraph (j) of this section so that the mass flow rate can be converted to 

volumetric flow at standard conditions using the following equation. 

MWt

Q Q mass

vol

 385.3 

where: 

Qvol = Volumetric flow rate, standard cubic feet per second. 

Qmass = Mass flow rate, pounds per second. 

385.3 = Conversion factor, standard cubic feet per pound-mole. 

MWt = Molecular weight of the gas at the flow monitoring location, pounds per poundmole. 

(3) Mass flow monitors may be used for determining volumetric flow rate of assist air or 

assist steam. Use equation in paragraph (i)(2) of this section to convert mass flow rates to 

volumetric flow rates. Use a molecular weight of 18 pounds per pound-mole for assist steam and 

use a molecular weight of 29 pounds per pound-mole for assist air. 

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) Continuous pressure/temperature monitoring system(s) and appropriate engineering 

calculations may be used in lieu of a continuous volumetric flow monitoring systems provided 

the molecular weight of the gas is known. For assist steam, use a molecular weight of 18 pounds 

per pound-mole. For assist air, use a molecular weight of 29 pounds per pound-mole. For flare 

vent gas, molecular weight must be determined using compositional analysis as specified in 

paragraph (j) of this section. 

(j) Flare vent gas composition monitoring. The owner or operator shall determine the 

concentration of individual components in the flare vent gas using either the methods provided in 

paragraphs (j)(1) or (j)(2) of this section, to assess compliance with the operating limits in 

paragraph (e) of this section and, if applicable, paragraphs (d) and (f) of this section. 

Alternatively, the owner or operator may elect to directly monitor the net heating value of the 

flare vent gas following the methods provided in paragraphs (j)(3) of this section or the 

combustibles concentration following the methods provided in paragraphs (j)(4) of this section.. 

The owner or operator electing to directly monitor the net heating value of the flare vent gas 

must comply with the net heating value operating limits in paragraph (e) and, if applicable, 

paragraph (f) of this section. The owner or operator electing to directly monitor the combustibles 

concentration in the flare vent gas must comply with the combustibles concentration operating 

limits in paragraph (e) and, if applicable, paragraph (f) of this section, and must comply with the 

maximum velocity requirements in paragraph (d)(1) of this section. 

(1) Except as provided in paragraph (j)(5) of this section, the owner or operator shall install, 

operate, calibrate, and maintain a monitoring system capable of continuously measuring (i.e., at 

least once every 15-minutes), calculating, and recording the individual component concentrations 

present in the flare vent gas. 

(2) Except as provided in paragraph (j)(5) of this section, the owner or operator shall install, 

operate, and maintain a grab sampling system capable of collecting an evacuated canister sample 

for subsequent compositional analysis at least once every eight hours while there is flow of 

regulated material to the flare. Subsequent compositional analysis of the samples must be 

performed according to EPA Method 18, ASTM D1945-03, or UOP539-12. 

(3) The owner or operator shall install, operate, calibrate, and maintain a monitoring system 

capable of continuously measuring, calculating, and recording NHVvg. at standard conditions. 

(4) The owner or operator shall install, operate, calibrate, and maintain a monitoring system 

capable of continuously measuring, calculating, and recording total hydrocarbon content (as 

propane) as a surrogate for combustibles concentration. 

(5) Direct compositional monitoring is not required for pipeline quality natural gas streams. 

In lieu of monitoring the composition of a pipeline quality natural gas stream, the following 

composition can be used for any pipeline quality natural gas stream. 

(i) 93.2 volume percent (vol %) methane. 

(ii) 3.2 vol % ethane. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) 0.6 vol % propane. 

(iv) 0.3 vol % butane. 

(v) 2.0 vol % hydrogen. 

(vi) 0.7 vol % nitrogen.

(k) Calculation methods for determining compliance with Vtip operating limits. The owner 

or operator shall determine Vtip on a 15-minute block average basis according to the following 

requirements. 

(1) The owner or operator shall use design and engineering principles to determine the 

unobstructed cross sectional area of the flare tip. The unobstructed cross sectional area of the 

flare tip is the total tip area that vent gas can pass through. This area does not include any 

stability tabs, stability rings, and upper steam or air tubes because vent gas does not exit through 

them. 

(2) The owner or operator shall determine the cumulative volumetric flow of vent gas for 

each 15-minute block average period using the data from the continuous flow monitoring system 

required in paragraph (i) of this section according to the following requirements, as applicable. 

(i) Use set 15-minute time periods starting at 12 midnight to 12:15 AM, 12:15 AM to 12:30 

AM and so on concluding at 11:45 PM to midnight when calculating 15-minute block average 

flow volumes. 

(ii) If continuous pressure/temperature monitoring system(s) and engineering calculations 

are used as allowed under paragraph (i)(4) of this section, the owner of operator shall, at a 

minimum, determine the 15-minute block average temperature and pressure from the monitoring 

system and use those values to perform the engineering calculations to determine the cumulative 

flow over the 15-minute block average period. Alternatively, the owner or operator may divide 

the 15-minute block average period into equal duration subperiods (e.g., three 5-minute periods) 

and determine the average temperature and pressure for each subperiod, perform engineering 

calculations to determine the flow for each subperiod, then add the volumetric flows for the 

subperiods to determine the cumulative volumetric flow of vent gas for the 15-minute block 

average period. 

(3) The 15-minute block average Vtip shall be calculated using the following equation. 

 900  Area

Q V cum

tip

where: 

Vtip = Flare tip velocity, feet per second. 

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Qcum = Cumulative volumetric flow over 15-minute block average period, actual cubic feet. 

Area = Unobstructed area of the flare tip, square feet. 

900 = Conversion factor, seconds per 15-minute block average. 

(4) If the owner or operator chooses to comply with paragraph (d)(2) of this section, the 

owner or operator shall also determine the net heating value of the flare following the 

requirements in paragraph (j) and (l) of this section and calculate Vmax using the equation in 

paragraph (d)(2) of this section in order to compare Vtip to Vmax on a 15-minute block average 

basis. 

(l) Calculation methods for determining flare vent gas parameters. The owner or operator 

shall determine the net heating value, lower flammability limit, combustibles concentration vent 

gas (NHVvg, LFLvg, and Cvg, respectively) based on the composition monitoring data on a 15-

minute block average basis according to the following requirements. 

(1) Use set 15-minute time periods starting at 12 midnight to 12:15 AM, 12:15 AM to 12:30 

AM and so on concluding at 11:45 PM to midnight when calculating 15-minute block averages. 

(2) When a continuous monitoring system is used to determine flare vent gas composition, 

net heating value, or total hydrocarbon content: 

(i) Use the results from the first sample collected during an event, (for periodic flare vent 

gas flow events) for the first and second 15-minute block associated with that event. 

(ii) For all other 15-minute block periods, use the results that are available from the most 

recent sample prior to the 15-minute block period for that 15-minute block period. For the 

purpose of this requirement, use the time that the results become available rather than the time 

the sample was collected. For example, if a sample is collected at 12:25 AM and the analysis is 

completed at 12:38 AM, the results are available at 12:38 AM and these results would be used to 

determine compliance during the 15-minute block period from 12:45 AM to 1:00 AM. 

(3) When grab samples are used to determine flare vent gas composition: 

(i) Use the analytical results from the first grab sample collected for an event for all 15-

minute periods from the start of the event through the 15-minute block prior to the 15-minute 

block in which a subsequent grab sample is collected. 

(ii) Use the results from subsequent grab sampling events for all 15 minute periods starting 

with the 15-minute block in which the sample was collected and ending with the 15-minute 

block prior to the 15-minute block in which the next grab sample is collected. For the purpose of 

this requirement, use the time the sample was collected rather than the time the analytical results 

become available. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) The owner or operator shall determine NHVvg from compositional analysis data by 

using the following equation. If the owner or operator uses a monitoring system(s) capable of 

continuously measuring, calculating, and recording NHVvg, as provided in paragraph (j)(3) of 

this section, the owner or operator shall use the NHVvg as determined by the continuous NHVvg

monitor. 





n

i

vg iNHVi NHV x

1

where: 

NHVvg = Net heating value of flare vent gas, Btu/scf. 

i = Individual component in flare vent gas. 

n = Number of components in flare vent gas. 

xi = Concentration of component i in flare vent gas, volume fraction. 

NHVi = Net heating value of component i according to table 12 of this subpart, Btu/scf. If 

the component is not specified in table 12 of this subpart, the heats of combustion may be 

determined using any published values where the net enthalpy per mole of offgas is based on 

combustion at 25 °C and 1 atmosphere (or constant pressure) with offgas water in the gaseous 

state, but the standard temperature for determining the volume corresponding to one mole of vent 

gas is 20 °C. 

(5) The owner or operator shall calculate LFLvg using the following equation: 

 













  n

i i

vg

LFL

χ

LFL

i

1

1

where: 

LFLvg = Lower flammability limit of flare vent gas, volume fraction. 

n = Number of components in the vent gas. 

i = Individual component in the vent gas. 

χi = Concentration of component i in the vent gas, volume percent (vol %). 

LFLi = Lower flammability limit of component i according to table 12 of this subpart, vol 

%. If the component is not specified in table 12 of this subpart, the owner or operator shall use 

Field Code Changed

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

the LFL value as published in Appendix A of Flammability Characteristics of Combustible 

Gases and Vapors, U.S. Bureau of Mines, Bulletin 627, 1965 (incorporated by reference—see 

§63.14). All inerts, including nitrogen, shall be assumed to have an infinite lower flammability 

limit (e.g., LFLN2 = ∞, so that χN2/ LFLN2 = 0). 

(6) The owner or operator shall calculate Cvg using the following equation. If the owner or 

operator uses a total hydrocarbon analyzer, the owner or operator may substitute the “∑χi” term 

in the following equation with the total volumetric hydrocarbon concentration present in the flare 

vent gas (vol % as propane), and the owner or operator may choose to ignore the concentration 

of hydrogen in the flare vent gas. 

100%

1 3 



 



  



 



 





h

n

i

i i

vg

χ

CMN χ

C

Where: 

Cvg = Total volumetric fraction of hydrogen and combustible organic components present in 

the flare vent gas, volume fraction. For the purposes of Cvg, carbon dioxide is not considered to 

be a combustible organic component, but carbon monoxide may be included in Cvg. 

n = Number of individual combustible organic components in flare vent gas. 

i = Individual combustible organic component in flare vent gas. 

χi = Concentration of combustible organic component i in flare vent gas, vol %. 

CMNi = Carbon mole number of combustible organic component i in flare vent gas, mole 

carbon atoms per mole of compound. E.g., CMN for ethane (C2H6) is 2; CMN for propane 

(C3H8) is 3. 

χh = Concentration of hydrogen in flare vent gas, vol %. 

100% = Constant, used to convert volume percent to volume fraction. 

(m) Calculation methods for determining combustion zone parameters. The owner or 

operator shall determine the net heating value, lower flammability limit and combustibles 

concentration of the combustion zone gas (NHVcz, LFLcz, and Ccz, respectively) based on the 

vent gas and assist gas flow rates on a 15-minute block average basis according to the following 

requirements. For periods when there is no assist steam flow or premix assist air flow, the 

combustion zone parameters are equal to the vent gas parameters. 

(1) The owner or operator shall calculate NHVcz using the following equation: 

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

  vg s a,premix

vg vg

cz Q Q Q

Q NHV

NHV

 

 

where: 

NHVcz = Net heating value of combustion zone gas, Btu/scf. 

NHVvg = Net heating value of flare vent gas for the 15-minute block period, Btu/scf. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

(2) The owner or operator shall calculate LFLcz using the following equation: 

 

vg

vg vg s a,premix

cz Q

LFL Q Q Q LFL   

where: 

LFLcz = Lower flammability limit of combustion zone gas, volume fraction. 

LFLvg = Lower flammability limit of flare vent gas determined for the 15-minute block 

period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

(3) The owner or operator shall calculate Ccz using the following equation: 

  vg s a,premix

vg vg

cz Q Q Q

Q C

C

 

 

where: 

Ccz = Combustibles concentration in the combustion zone gas, volume fraction. 

Field Code Changed

Field Code Changed

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Cvg = Combustibles concentration of flare vent gas determined for the 15-minute block 

period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

(n) Calculation methods for determining dilution parameters. The owner or operator shall 

determine the net heating value, lower flammability limit and combustibles concentration 

dilution parameters (NHVdil, LFLdil, and Cdil, respectively) based on the vent gas and perimeter 

assist air flow rates on a 15-minute block average basis according to the following requirements 

only during periods when perimeter assist air is used. For 15-minute block periods when there is 

no cumulative volumetric flow of perimeter assist air, the dilution parameters do not need to be 

calculated. 

(1) The owner or operator shall calculate NHVdil using the following equation: 

  vg s a,premix a,perimeter

vg vg

dil Q Q Q Q

Q Diam NHV

NHV

  

  

where: 

NHVdil = Net heating value of combustion zone gas, Btu/ft2

NHVvg = Net heating value of flare vent gas determined for the 15-minute block period, 

Btu/scf. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, 

ft. Use the area as determined in paragraph (k)(1) of this section and determine the diameter as 

Diam  2 Area π

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

Qa,perimiter = Cumulative volumetric flow of perimeter assist air during the 15-minute block 

period, scf. 

(2) The owner or operator shall calculate LFLdil using the following equation: 

Field Code Changed

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

 

Q Diam

LFL Q Q Q Q LFL

vg

vg vg s a,premix a,perimeter

dil 

    

where: 

LFLdil = Lower flammability limit of combustion zone gas, ft-1. 

LFLvg = Lower flammability limit of flare vent gas determined for the 15-minute block 

period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, 

ft. Use the area as determined in paragraph (k)(1) of this section and determine the diameter as 

Diam  2 Area π

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

Qa,perimiter = Cumulative volumetric flow of perimeter assist air during the 15-minute block 

period, scf. 

(3) The owner or operator shall calculate Cdil using the following equation: 

  vg s a,premix a,perimeter

vg vg

dil Q Q Q Q

Q Diam C

C

  

  

where: 

Ccz = Combustibles concentration in the combustion zone gas, volume fraction. 

Cvg = Combustibles concentration of flare vent gas determined for the 15-minute block 

period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, 

ft. Use the area as determined in paragraph (k)(1) of this section and determine the diameter as 

Diam  2 Area π

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

Qa,perimiter = Cumulative volumetric flow of perimeter assist air during the 15-minute block 

period, scf. 

(o) Special provisions for assessing olefins and hydrogen combustion zone concentrations. 

The owner or operator shall determine the olefins and hydrogen content of the flare vent gas and 

calculate the combustion zone concentrations for the purposes of assessing the criteria in 

paragraph (e)(4) of this section on a 15-minute block average according to the following 

requirements. 

(1) The olefins concentration shall be determined as the cumulative sum of the following 

flare gas constituents: ethylene, acetylene, propylene, propadiene, all isomers of n- or iso-butene, 

and all isomers of butadiene. 

(2) If individual component concentrations are determined following the methods specified 

in paragraphs (j)(1) or (j)(2) of this section, the measured vent gas concentrations shall be used to 

determine the hydrogen, olefins, and hydrogen plus olefins concentration in the combustion zone 

using the following general equation. The methods specified in paragraphs (l)(1) through (3) of 

this section, as applicable, shall be used to assign the vent gas concentration results to a specific 

15-minute block period. 

  vg s a,premix

vg vg

cz Q Q Q

Q A

A

 

 

where: 

Acz = Concentration of target compound(s) “A” (representing either the olefins 

concentration, the hydrogen concentration, or the sum of the olefins and hydrogen concentration) 

in the combustion zone gas, volume fraction. 

Avg = Concentration of target compound(s) “A” (representing either the olefins 

concentration, the hydrogen concentration, or the sum of the olefins and hydrogen concentration) 

in the flare vent gas determined for the 15-minute block period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(3) If NHVvg or total hydrocarbon monitoring systems are used as provided in paragraphs 

(j)(3) or (j)(4) of this section, the owner or operator may elect to determine the hydrogen and 

olefins concentrations using any of the following methods. 

(i) The owner or operator may elect to assume the hydrogen concentration, the olefins 

concentration, and the olefins plus hydrogen concentration in the combustion zone gas exceed all 

three criteria in (e)(4) at all times without making specific measurements of olefins or hydrogen 

concentrations. 

(ii) The owner or operator may elect to use process knowledge and engineering calculations 

to determine the highest flare vent gas concentrations of olefins and hydrogen that can 

reasonably be expected to be discharged to the flare and the highest concentration of olefins plus 

hydrogen that can reasonably be expected to be discharged to the flare while the flare vent gas 

concentrations exceed the target combustion zone concentrations in paragraphs (e)(4)(i) and (ii) 

of this section at the same time. The owner or operator shall take daily flare vent gas samples for 

fourteen days or for 7 flaring events, whichever results in the greatest number of grab samples to 

verify that the calculated values are representative of the highest concentrations that reasonably 

be expected to be discharged to the flare. 

(A) If the highest flare vent gas concentrations of olefins, hydrogen, and olefins plus 

hydrogen that can reasonably be expected to be discharged to the flare do not exceed all three 

combustion zone concentration criteria in paragraph (e)(4) of this section, for example, if the 

flare does not service any process units that contain olefins, then the engineering assessment is 

sufficient to document that all three criteria in paragraph (e)(4) of this section are not met and 

that the more stringent operating limits do not apply at any time. 

(B) If the highest flare vent gas concentrations of olefins, hydrogen, and olefins plus 

hydrogen that can reasonably be expected to be discharged to the flare exceed all three 

combustion zone concentration criteria in paragraph (e)(4), then the owner or operator will use 

the concentrations determined from the engineering analysis as the vent gas concentrations that 

exist in the vent gas at all times and use the equation in paragraph (o)(2) of this section to 

determine the combustion zone concentrations of olefins, 

(C) If the operation of process units connected to the flares change or new connections are 

made to the flare and these changes can reasonably be expected to alter the highest vent gas 

concentrations of olefins, hydrogen, and/or olefins plus hydrogen received by the flare, a new 

engineering assessment and sampling period for verification will be conducted following the 

requirements of paragraph (o)(3)(ii) of this section. 

(p) Flare monitoring records. The owner or operator shall keep the records specified in 

§63.655(i)(9). 

(q) Reporting. The owner or operator shall comply with the reporting requirements 

specified in §63.655(g)(11). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(r) Alternative means of emissions limitation. An owner or operator may request approval 

from the Administrator for site-specific operating limits that shall apply specifically to a selected 

flare. Site-specific operating limits include alternative threshold values for the parameters 

specified in paragraphs (d) through (f) of this section as well as threshold values for operating 

parameters other than those specified in paragraphs (d) through (f) of this section. The owner or 

operator must demonstrate that the flare achieves 96.5 percent combustion efficiency (or 98 

percent destruction efficiency) using the site-specific operating limits based on a performance 

test as described in paragraph (r)(1) of this section. The request shall include information as 

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

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

(1) The owner or operator shall prepare and submit a site-specific test plan and receive 

approval of the site-specific test plan prior to conducting any flare performance test intended for 

use in developing site-specific operating limits. The site-specific test plan shall include, at a 

minimum, the elements specified in paragraphs (r)(1)(i) through (ix) of this section. Upon 

approval of the site-specific test plan, the owner or operator shall conduct a performance test for 

the flare following the procedures described in the site-specific test plan. 

(i) The design and dimensions of the flare, flare type (air-assisted only, steam-assisted only, 

air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being flared, 

including quantity of gas flared, frequency of flaring events (if periodic), expected net heating 

value of flare vent gas, minimum total steam assist rate. 

(ii) The operating conditions (vent gas compositions, vent gas flow rates and assist flow 

rates, if applicable) likely to be encountered by the flare during normal operations and the 

operating conditions for the test period. 

(iii) A description of (including sample calculations illustrating) the planned data reduction 

and calculations to determine the flare combustion or destruction efficiency. 

(iv) Site-specific operating parameters to be monitored continuously during the flare 

performance test. These parameters may include but are not limited to vent gas flow rate, steam 

and/or air assist flow rates, and flare vent gas composition. If new operating parameters are 

proposed for use other than those specified in paragraphs (d) through (f) of this section, an 

explanation of the relevance of the proposed operating parameter(s) as an indicator of flare 

combustion performance and why the alternative operating parameter(s) can adequately ensure 

that the flare achieves the required combustion efficiency. 

(v) A detailed description of the measurement methods, monitored pollutant(s), 

measurement locations, measurement frequency, and recording frequency proposed for both 

emission measurements and flare operating parameters. 

(vi) A description of (including sample calculations illustrating) the planned data reduction 

and calculations to determine the flare operating parameters. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(vii) The minimum number and length of test runs and range of operating values to be 

evaluated during the performance test. A sufficient number of test runs shall be conducted to 

identify the point at which the combustion/destruction efficiency of the flare deteriorates. 

(viii) If the flare can receive vent gases containing olefins and hydrogen above the levels 

specified for the combustion zone gas in paragraph (e)(4) of this section, a sufficient number of 

tests must be conducted while exceeding these limits to assess whether more stringent operating 

limits are required under these conditions. 

(ix) Test schedule. 

(2) The request for flare-specific operating limits shall include sufficient and appropriate 

data, as determined by the Administrator, to allow the Administrator to confirm that the selected 

site-specific operating limit(s) adequately ensures that the flare destruction efficiency is 98 

percent or greater or that the flare combustion efficiency is 96.5 percent or greater at all times. At 

a minimum, the request shall contain the information described in paragraphs (r)(2)(i) through 

(iv) of this section. 

(i) The design and dimensions of the flare, flare type (air-assisted only, steam-assisted only, 

air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being flared, 

including quantity of gas flared, frequency of flaring events (if periodic), expected net heating 

value of flare vent gas, minimum total steam assist rate. 

(ii) Results of each performance test run conducted, including, at a minimum: 

(A) The measured combustion/destruction efficiency. 

(B) The measured or calculated operating parameters for each test run. If operating 

parameters are calculated, the raw data from which the parameters are calculated must be 

included in the test report. 

(C) Measurement location descriptions for both emission measurements and flare operating 

parameters. 

(D) Description of sampling and analysis procedures (including number and length of test 

runs) and any modifications to standard procedures. If there were deviations from the approved 

test plan, a detailed description of the deviations and rationale why the test results or calculation 

procedures used are appropriate. 

(E) Operating conditions (e.g., vent gas composition, assist rates, etc.) that occurred during 

the test. 

(F) Quality assurance procedures. 

(G) Records of calibrations. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(H) Raw data sheets for field sampling. 

(I) Raw data sheets for field and laboratory analyses. 

(J) Documentation of calculations 

(iii) The selected flare-specific operating limit values based on the performance test results, 

including the averaging time for the operating limit(s), and rationale why the selected values and 

averaging times are sufficiently stringent to ensure proper flare performance. If new operating 

parameters or averaging times are proposed for use other than those specified in paragraphs (d) 

through (f) of this section, an explanation of why the alternative operating parameter(s) or 

averaging time(s) adequately ensures the flare achieves the required combustion efficiency. 

(iv) The means by which the owner or operator will document on-going, continuous 

compliance with the selected flare-specific operating limit(s), including the specific 

measurement location and frequencies, calculation procedures, and records to be maintained. 

(3) The request shall be submitted as described in paragraphs (r)(3)(i) through (iv) of this 

section. 

(i) The owner or operator may request approval from the Administrator at any time upon 

completion of a performance test conducted following the methods in an approved site-specific 

test plan for an operating limit(s) that shall apply specifically to that flare. 

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

must continue to comply with the applicable standards for flares in this subpart until the 

requirements in 40 CFR 63.6(g)(1) are met and a notice is published in the Federal Register 

allowing use of such an alternative means of emission limitation. 

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

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

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

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

submitted to refineryrtr@epa.gov. 

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

address the deficiencies and be re-submitted for approval within 45 days of receipt of the notice 

of deficiencies. The owner or operator must comply with the revised request as submitted until it 

is approved. 

(4) The approval process for a request for a flare-specific operating limit(s) is described in 

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

(i) Approval by the Administrator of a flare-specific operating limit(s) request will be based 

on the completeness, accuracy and reasonableness of the request. Factors that the EPA will 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

consider in reviewing the request for approval include, but are not limited to, those described in 

paragraphs (r)(4)(i)(A) through (C) of this section. 

(A) The description of the flare design and operating characteristics. 

(B) If a new operating parameter(s) other than those specified in paragraphs (d) through (f) 

of this section is proposed, the explanation of how the proposed operating parameter(s) serves a 

good indicator(s) of flare combustion performance. 

(C) The results of the flare performance test and the establishment of operating limits that 

ensures that the flare destruction efficiency is 98 percent or greater or that the flare combustion 

efficiency is 96.5 percent or greater at all times. 

(D) The completeness of the flare performance test report. 

(ii) If the request is approved by the Administrator, a flare-specific operating limit(s) will be 

established at the level(s) demonstrated in the approved request. 

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

address the deficiencies and be re-submitted for approval. 

§ 63.671 Requirements for flare monitoring systems. 

(a) Operation of CPMS. For each CPMS installed to comply with applicable provisions in 

§63.670, the owner or operator shall install, operate, calibrate, and maintain the CPMS as 

specified in paragraphs (a)(1) through (8) of this section. 

(1) All monitoring equipment must meet the minimum accuracy, calibration and quality 

control requirements specified in table 13 of this subpart. 

(2) The owner or operator shall ensure the readout (that portion of the CPMS that provides a 

visual display or record) or other indication of the monitored operating parameter from any 

CPMS required for compliance is readily accessible onsite for operational control or inspection 

by the operator of the source. 

(3) All CPMS must complete a minimum of one cycle of operation (sampling, analyzing 

and data recording) for each successive 15-minute period. 

(4) Except for maintenance periods, instrument adjustments or checks to maintain precision 

and accuracy, calibration checks, and zero and span adjustments, the owner or operator shall 

operate all CPMS and collect data continuously when regulated emissions are routed to the flare. 

(5) The owner or operator shall operate, maintain, and calibrate each CPMS according to 

the CPMS monitoring plan specified in paragraph (b) of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(6) For each CPMS, the owner or operator shall comply with the out-of-control procedures 

described in paragraphs (c) of this section. The CPMS monitoring plan must be submitted to the 

Administrator for approval upon request. 

(7) The owner or operator shall reduce data from a CPMS as specified in paragraph (d) of 

this section. 

(8) The CPMS must be capable of measuring the appropriate parameter over the range of 

values expected for that measurement location. The data recording system associated with each 

CPMS must have a resolution that is equal to or better than the required system accuracy. 

 (b) CPMS monitoring plan. The owner or operator shall develop and implement a CPMS 

quality control program documented in a CPMS monitoring plan. The owner or operator shall 

have the CPMS monitoring plan readily available on-site at all times and shall submit a copy of 

the CPMS monitoring plan to the Administrator upon request by the Administrator. The CPMS 

monitoring plan must contain the information listed in paragraphs (b)(1) through (5) of this 

section. 

(1) Identification of the specific flare being monitored and the flare type (air-assisted only, 

steam-assisted only, air- and steam-assisted, pressure-assisted, or non-assisted). 

(2) Identification of the parameter to be monitored by the CPMS and the expected 

parameter range, including worst case and normal operation. 

(3) Description of the monitoring equipment, including the information specified in (c)(3)(i) 

through (viii) of this section. 

(i) Manufacturer and model number for all monitoring equipment components. 

(ii) Performance specifications, as provided by the manufacturer, and any differences 

expected for this installation and operation. 

(iii) The location of the CPMS sampling probe or other interface and a justification of how 

the location meets the requirements of paragraph (a)(1) of this section. 

(iv) Placement of the CPMS readout, or other indication of parameter values, indicating 

how the location meets the requirements of paragraph (a)(2) of this section. 

(v) Span of the analyzer. The span must encompass all expected concentrations and meet 

the requirements of paragraph (b)(10) of this section. 

(vi) How data outside of the analyzer’s span will be handled and the corrective action that 

will be taken to reduce and eliminate such occurrences in the future. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(vii) Identification of the parameter detected by the parametric signal analyzer and the 

algorithm used to convert these values into the operating parameter monitored to demonstrate 

compliance, if the parameter detected is different from the operating parameter monitored. 

(4) Description of the data collection and reduction systems, including the information 

specified in paragraphs (b)(4)(i) through (iii) of this section. 

(i) A copy of the data acquisition system algorithm used to reduce the measured data into 

the reportable form of the standard and to calculate the applicable averages. 

(ii) Identification of whether the algorithm excludes data collected during CPMS 

breakdowns, out-of-control periods, repairs, maintenance periods, instrument adjustments or 

checks to maintain precision and accuracy, calibration checks, and zero (low-level), mid-level (if 

applicable) and high-level adjustments. 

(iii) If the data acquisition algorithm does not exclude data collected during CPMS 

breakdowns, out-of-control periods, repairs, maintenance periods, instrument adjustments or 

checks to maintain precision and accuracy, calibration checks, and zero (low-level), mid-level (if 

applicable) and high-level adjustments, a description of the procedure for excluding this data 

when the averages calculated as specified in paragraph (e) of this section are determined. 

(5) Routine quality control and assurance procedures, including descriptions of the 

procedures listed in paragraphs (c)(5)(i) through (vi) of this section and a schedule for 

conducting these procedures. The routine procedures must provide an assessment of CPMS 

performance. 

(i) Initial and subsequent calibration of the CPMS and acceptance criteria. 

(ii) Determination and adjustment of the calibration drift of the CPMS. 

(iii) Daily checks for indications that the system is responding. If the CPMS system 

includes an internal system check, the owner or operator may use the results to verify the system 

is responding, as long as the owner or operator checks the internal system results daily for proper 

operation and the results are recorded. 

(iv) Preventive maintenance of the CPMS, including spare parts inventory. 

(v) Data recording, calculations and reporting. 

(vi) Program of corrective action for a CPMS that is not operating properly. 

(c) Out-of-control periods. For each CPMS, the owner or operator shall comply with the 

out-of-control procedures described in paragraphs (c)(1) and (2) of this section. 

(1) A CPMS is out-of-control if the zero (low-level), mid-level (if applicable) or high-level 

calibration drift exceeds two times the accuracy requirement of table 13 of this subpart. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) When the CPMS is out of control, the owner or operator shall take the necessary 

corrective action and repeat all necessary tests that indicate the system is out of control. The 

owner or operator shall take corrective action and conduct retesting until the performance 

requirements are below the applicable limits. The beginning of the out-of-control period is the 

hour a performance check (e.g., calibration drift) that indicates an exceedance of the performance 

requirements established in this section is conducted. The end of the out-of-control period is the 

hour following the completion of corrective action and successful demonstration that the system 

is within the allowable limits. The owner or operator shall not use data recorded during periods 

the CPMS is out of control in data averages and calculations, used to report emissions or 

operating levels, as specified in paragraph (d)(3) of this section. 

(d) CPMS data reduction. The owner or operator shall reduce data from a CPMS as 

specified in paragraphs (d)(1) through (3) of this section. 

(1) The owner or operator may round the data to the same number of significant digits used 

in that operating limit. 

(2) Periods of non-operation of the process unit (or portion thereof) resulting in cessation of 

the emissions to which the monitoring applies must not be included in the 15-minute block 

averages. 

(3) Periods when the CPMS is out of control must not be included in the 15-minute block 

averages. 

(e) Additional requirements for gas chromatographs. For monitors used to determine 

compositional analysis for net heating value per §63.670(j)(1), the gas chromatograph must also 

meet the requirements of paragraphs (e)(1) through (3) of this section. 

(1) The quality assurance requirements are in table 13 of this subpart. 

(2) The calibration gases must meet one of the following options: 

(i) The owner or operator must use a calibration gas or multiple gases that include all of the 

compounds that exist in the flare gas stream. All of the calibration gases may be combined in one 

cylinder. If multiple calibration gases are necessary to cover all compounds, the owner or 

operator must calibrate the instrument on all of the gases. 

(ii) The owner or operator must use a surrogate calibration gas consisting of C1 through C7 

normal hydrocarbons. All of the calibration gases may be combined in one cylinder. If multiple 

calibration gases are necessary to cover all compounds, the owner or operator must calibrate the 

instrument on all of the gases. 

(3) If the owner or operator chooses to use a surrogate calibration gas under paragraph 

(e)(2)(ii) of this section, the owner or operator must comply with the following paragraphs. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) Use the response factor for the nearest normal hydrocarbon (i.e., n-alkane) in the 

calibration mixture to quantify unknown components detected in the analysis. 

(ii) Unknown compounds that elute after n-heptane must either be identified and quantified 

using an identical compound standard, or the owner or operator must extend the calibration range 

to include the additional normal hydrocarbons necessary to perform the unknown hydrocarbon 

quantitation procedure. 

§§ 63.672-63.679 [Reserved] 

Appendix to Subpart CC of Part 63—Tables 

Table 1—Hazardous Air Pollutants 

Chemical name CAS No.a

Benzene 71432 

Biphenyl 92524 

Butadiene (1,3) 106990 

Carbon disulfide 75150 

Carbonyl sulfide 463581 

Cresol (mixed isomersb) 1319773 

Cresol (m-) 108394 

Cresol (o-) 95487 

Cresol (p-) 106445 

Cumene 98828 

Dibromoethane (1,2) (ethylene dibromide) 106934 

Dichloroethane (1,2) 107062 

Diethanolamine 111422 

Ethylbenzene 100414 

Ethylene glycol 107211 

Hexane 110543 

Methanol 67561 

Methyl isobutyl ketone (hexone) 108101 

Methyl tert butyl ether 1634044 

Naphthalene 91203 

Phenol 108952 

Toluene 108883 

Trimethylpentane (2,2,4) 540841 

Xylene (mixed isomersb) 1330207 

xylene (m-) 108383 

xylene (o-) 95476 

xylene (p-) 106423 

a

CAS number = Chemical Abstract Service registry number assigned to specific 

compounds, isomers, or mixtures of compounds. 

Deleted: §§ 63.657
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

b

Isomer means all structural arrangements for the same number of atoms of each element 

and does not mean salts, esters, or derivatives. 

Table 2—Leak Definitions for Pumps and Valves 

Standarda Phase Leak definition (parts per million) 

§63.163 (pumps) I 10,000 

 II 5,000 

 III 2,000 

§63.168 (valves) I 10,000 

 II 1,000 

 III 1,000 

a

Subpart H of this part. 

Table 3—Equipment Leak Recordkeeping and Reporting Requirements for Sources Complying 

With §63.648 of Subpart CC by Compliance With Subpart H of this Parta

Reference 

(section of 

subpart H of 

this part) Description Comment 

63.181(a) Recordkeeping system 

requirements 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 

63.181(b) Records required for process 

unit equipment 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 

63.181(c) Visual inspection 

documentation 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 

63.181(d) Leak detection record 

requirements 

Except for §63.181(d)(8). 

63.181(e) Compliance requirements 

for pressure tests for batch 

product process equipment 

trains 

This subsection does not apply to subpart 

CC. 

63.181(f) Compressor compliance test 

records. 

63.181(g) Closed-vent systems and 

control device record 

requirements. 

63.181(h) Process unit quality 

improvement program 

records. 

63.181(i) Heavy liquid service 

determination record. 

63.181(j) Equipment identification 

record. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

63.181(k) Enclosed-vented process 

unit emission limitation 

record requirements. 

63.182(a) Reports. 

63.182(b) Initial notification report 

requirements. 

Not required. 

63.182(c) Notification of compliance 

status report 

Except in §63.182(c); change “within 90 

days of the compliance dates” to “within 150 

days of the compliance dates”; except in 

§§63.182 (c)(2) and (c)(4). 

63.182(d) Periodic report Except for §§63.182 (d)(2)(vii), (d)(2)(viii), 

and (d)(3). 

a

This table does not include all the requirements delineated under the referenced sections. 

See referenced sections for specific requirements. 

Table 4—Gasoline Distribution Emission Point Recordkeeping and Reporting Requirementsa

Reference 

(section of 

subpart R) Description Comment 

63.428(b) or (k) Records of test results for each 

gasoline cargo tank loaded at the 

facility 

63.428(c) Continuous monitoring data 

recordkeeping requirements 

63.428(g)(1) Semiannual report loading rack 

information 

Required to be submitted with the 

Periodic Report required under 40 CFR 

part 63, subpart CC. 

63.428(h)(1) 

through (h)(3) 

Excess emissions report loading 

rack information 

Required to be submitted with the 

Periodic Report required under 40 CFR 

part 63, subpart CC. 

a

This table does not include all the requirements delineated under the referenced sections. 

See referenced sections for specific requirements. 

Table 5—Marine Vessel Loading Operations Recordkeeping and Reporting Requirementsa

Reference 

(section of 

subpart Y) Description Comment 

63.562(e)(2) Operation and maintenance 

plan for control equipment and 

monitoring equipment 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reference 

(section of 

subpart Y) Description Comment 

63.565(a) Performance test/site test plan The information required under this 

paragraph is to be submitted with the 

Notification of Compliance Status report 

required under 40 CFR part 63, subpart 

CC. 

63.565(b) Performance test data 

requirements 

63.567(a) General Provisions (subpart A) 

applicability 

63.567(c) Request for extension of 

compliance 

63.567(d) Flare recordkeeping 

requirements 

63.567(e) Summary report and excess 

emissions and monitoring 

system performance report 

requirements 

The information required under this 

paragraph is to be submitted with the 

Periodic Report required under 40 CFR 

part 63, subpart CC. 

63.567(f) Vapor collection system 

engineering report 

63.567(g) Vent system valve bypass 

recordkeeping requirements 

63.567(h) Marine vessel vapor-tightness 

documentation 

63.567(i) Documentation file 

maintenance 

63.567(j) Emission estimation reporting 

and recordkeeping procedures 

a

This table does not include all the requirements delineated under the referenced sections. 

See referenced sections for specific requirements. 

Table 6—General Provisions Applicability to Subpart CCa

Reference 

Applies to 

subpart CC Comment 

63.1(a)(1) Yes 

63.1(a)(2) Yes 

63.1(a)(3) Yes 

63.1(a)(4) Yes 

63.1(a)(5) No Reserved. 

63.1(a)(6) Yes Except the correct mail drop (MD) number is C404–04. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reference 

Applies to 

subpart CC Comment 

63.1(a)(7)–

63.1(a)(9) 

No Reserved. 

63.1(a)(10) Yes 

63.1(a)(11) Yes 

63.1(a)(12) Yes 

63.1(b)(1) Yes 

63.1(b)(2) No Reserved. 

63.1(b)(3) No 

63.1(c)(1) Yes 

63.1(c)(2) No Area sources are not subject to subpart CC. 

63.1(c)(3)–

63.1(c)(4) 

No Reserved. 

63.1(c)(5) Yes Except that sources are not required to submit notifications 

overridden by this table. 

63.1(d) No Reserved. 

63.1(e) No No CAA section 112(j) standard applies to the affected 

sources under subpart CC. 

63.2 Yes §63.641 of subpart CC specifies that if the same term is 

defined in subparts A and CC, it shall have the meaning given 

in subpart CC. 

63.3 Yes 

63.4(a)(1)–

63.4(a)(2) 

Yes 

63.4(a)(3)–

63.4(a)(5) 

No Reserved. 

63.4(b) Yes 

63.4(c) Yes 

63.5(a) Yes 

63.5(b)(1) Yes 

63.5(b)(2) No Reserved. 

63.5(b)(3) Yes 

63.5(b)(4) Yes Except the cross-reference to §63.9(b) is changed to 

§63.9(b)(4) and (5). Subpart CC overrides §63.9 (b)(2). 

63.5(b)(5) No Reserved. 

63.5(b)(6) Yes 

63.5(c) No Reserved. 

63.5(d)(1)(i) Yes Except that the application shall be submitted as soon as 

practicable before startup, but no later than 90 days after the 

promulgation date of subpart CC if the construction or 

reconstruction had commenced and initial startup had not 

occurred before the promulgation of subpart CC. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reference 

Applies to 

subpart CC Comment 

63.5(d)(1)(ii) Yes Except that for affected sources subject to subpart CC, 

emission estimates specified in §63.5(d)(1)(ii)(H) are not 

required, and §63.5(d)(1)(ii)(G) and (I) are Reserved and do 

not apply. 

63.5(d)(1)(iii) No Subpart CC §63.655(f) specifies Notification of Compliance 

Status report requirements. 

63.5(d)(2) Yes 

63.5(d)(3) Yes 

63.5(d)(4) Yes 

63.5(e) Yes 

63.5(f) Yes Except that the cross-reference in §63.5(f)(2) to §63.9(b)(2) 

does not apply.

63.6(a) Yes 

63.6(b)(1)–

63.6(b)(5) 

No Subpart CC specifies compliance dates and notifications for 

sources subject to subpart CC. 

63.6(b)(6) No Reserved. 

63.6(b)(7) Yes 

63.6(c)(1)–

63.6(c)(2) 

No §63.640 of subpart CC specifies the compliance date. 

63.6(c)(3)–

63.6(c)(4) 

No Reserved. 

63.6(c)(5) Yes 

63.6(d) No Reserved. 

63.6(e)(1)(i) and 

(ii) 

No See §63.642(n) for general duty requirement.

63.6(e)(1)(iii) Yes 

63.6(e)(2) No Reserved. 

63.6(e)(3)(i) No

63.6(e)(3)(ii) No Reserved. 

63.6(e)(3)(iii)–

63.6(e)(3)(ix) 

No

63.6 (f)(1) No

63.6(f)(2) Yes Except the phrase “as specified in §63.7(c)” in 

§63.6(f)(2)(iii)(D) does not apply because subpart CC does 

not require a site-specific test plan. 

63.6(gf)(3) Yes Except the cross-references to §63.6(f)(1) and §63.6(e)(1)(i) 

are changed to §63.642(n). 

63.6(g) Yes 

63.6(h)(1) No 

63.6(h)(2) Yes Except §63.6(h)(2)(ii), which is reserved. 

63.6(h)(3) No Reserved. 

63.6(h)(4) No Notification of visible emission test not required in subpart 

CC. 

Deleted: Yes

Deleted: Except the startup, shutdown, or 

malfunction plan does not apply to Group 2 emission 

points that are not part of an emissions averaging 

group.b

Deleted: Yes

Deleted: Except the startup, shutdown, or 

malfunction plan does not apply to Group 2 emission 

points that are not part of an emissions averaging 

group.b

Deleted: Yes

Deleted: Except the reports specified in 

§63.6(e)(3)(iv) do not need to be reported within 2 

and 7 days of commencing and completing the 

action, respectively, but must be included in the next 

periodic report.

Deleted: Yes

Deleted: Except for the heat exchange system 

standards, which apply at all times.

Deleted: and (3)

Deleted: 63.6(h)(1) and 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reference 

Applies to 

subpart CC Comment 

63.6(h)(5) No Visible emission requirements and timing is specified in 

§63.645(i) of subpart CC. 

63.6(h)(6) Yes 

63.6(h)(7) No Subpart CC does not require opacity standards. 

63.6(h)(8) Yes 

63.6(h)(9) No Subpart CC does not require opacity standards. 

63.6(i) Yes Except for §63.6(i)(15), which is reserved. 

63.6(j) Yes 

63.7(a)(1) Yes 

63.7(a)(2) Yes Except test results must be submitted in the Notification of 

Compliance Status report due 150 days after compliance date, 

as specified in §63.655(f) of subpart CC. 

63.7(a)(3) Yes 

63.7(a)(4) Yes 

63.7(b) Yes Except subpart CC requires notification of performance test at 

least 30 days (rather than 60 days) prior to the performance 

test. 

63.7(c) No Subpart CC does not require a site-specific test plan. 

63.7(d) Yes 

63.7(e)(1) No See §63.642(d)(3).

63.7(e)(2)–

63.7(e)(4) 

Yes 

63.7(f) No Subpart CC specifies applicable methods and provides 

alternatives without additional notification or approval. 

63.7(g) No Performance test reporting specified in §63.655(f). 

63.7(h)(1) Yes 

63.7(h)(2) Yes 

63.7(h)(3) Yes Yes, except site-specific test plans shall not be required, and 

where §63.7(g)(3) specifies submittal by the date the sitespecific test plan is due, the date shall be 90 days prior to the 

Notification of Compliance Status report in §63.655(f). 

63.7(h)(4)(i) Yes 

63.7(h)(4)(ii) No Site-specific test plans are not required in subpart CC. 

63.7(h)(4)(iii) 

and (iv) 

Yes 

63.7(h)(5) Yes 

63.8(a)(1) and 

(2) 

Yes 

63.8(a)(3) No Reserved. 

63.8(a)(4) Yes Except that for a flare complying with §63.670, the crossreference to §63.11 in this paragraph does not include 

§63.11(b).

63.8(b) Yes 

Deleted: No

Deleted: Subpart

Deleted: Yes

Deleted: Except the performance test must be 

conducted at the maximum representative capacity 

as specified in §63.642(d)(3) of subpart CC.

Deleted: Except §63.8(a)(3), which is reserved.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reference 

Applies to 

subpart CC Comment 

63.8(c)(1) Yes Except §63.8(c)(1)(i) and §63.8(c)(iii).

63.8(c)(1)(i) No See §63.642(n). 

63.8(c)(1)(iii) No 

63.8(c)(2) Yes 

63.8(c)(3) Yes Except that verification of operational status shall, at a 

minimum, include completion of the manufacturer’s written 

specifications or recommendations for installation, operation, 

and calibration of the system or other written procedures that 

provide adequate assurance that the equipment would monitor 

accurately. 

63.8(c)(4) Yes Except that for sources other than flares, subpart CC specifies 

the monitoring cycle frequency specified in §63.8(c)(4)(ii) is 

“once every hour” rather than “for each successive 15-minute 

period.” 

63.8(c)(5)–

63.8(c)(8) 

No Subpart CC specifies continuous monitoring system 

requirements. 

63.8(d) No Subpart CC specifies quality control procedures for 

continuous monitoring systems.

63.8(e) Yes

63.8(f)(1) Yes 

63.8(f)(2) Yes 

63.8(f)(3) Yes 

63.8(f)(4)(i) No Timeframe for submitting request is specified in 

§63.655(h)(5)(i) of subpart CC. 

63.8(f)(4)(ii) Yes 

63.8(f)(4)(iii) No Timeframe for submitting request is specified in 

§63.655(h)(5)(i) of subpart CC. 

63.8(f)(5) Yes 

63.8(f)(6) No Subpart CC does not require continuous emission monitors. 

63.8(g) No Subpart CC specifies data reduction procedures in 

§§63.655(i)(3) and 63.671(d). 

63.9(a) Yes Except that the owner or operator does not need to send a 

copy of each notification submitted to the Regional Office of 

the EPA as stated in §63.9(a)(4)(ii). 

63.9(b)(1) Yes Except the notification of compliance status report specified 

in §63.655(f) of subpart CC may also serve as the initial 

compliance notification required in §63.9(b)(1)(iii). 

63.9(b)(2) No A separate Initial Notification report is not required under 

subpart CC. 

63.9(b)(3) No Reserved. 

63.9(b)(4) Yes Except for subparagraphs §63.9(b)(4)(ii) through (iv), which 

are reserved. 

63.9(b)(5) Yes 

Deleted: No

Deleted: Subpart CC does not require performance 

evaluations; however, this shall not abrogate the 

Administrator’s authority to require performance 

evaluation under section 114 of the Clean Air Act.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reference 

Applies to 

subpart CC Comment 

63.9(c) Yes 

63.9(d) Yes 

63.9(e) No Subpart CC requires notification of performance test at least 

30 days (rather than 60 days) prior to the performance test 

and does not require a site-specific test plan. 

63.9(f) No Subpart CC does not require advanced notification of visible 

emissions test. 

63.9(g) No 

63.9(h) No Subpart CC §63.655(f) specifies Notification of Compliance 

Status report requirements. 

63.9(i) Yes 

63.9(j) No 

63.10(a) Yes 

63.10(b)(1) No §63.655(i) of subpart CC specifies record retention 

requirements. 

63.10(b)(2)(i) No

63.10(b)(2)(ii) No See §63.655(i)(11) for recordkeeping of (1) date, time and 

duration; (2) listing of affected source or equipment, and an 

estimate of the volume of each regulated pollutant emitted 

over the standard; and (3) actions to minimize emissions and 

correct the failure.

63.10(b)(2)(iii) No 

63.10(b)(2)(iv) No

63.10(b)(2)(v) No

63.10(b)(2)(vi) Yes 

63.10(b)(2)(vii) No §63.655(i) of subpart CC specifies records to be kept for 

parameters measured with continuous monitors.

63.10(b)(2)(viii) Yes 

63.10(b)(2)(ix) Yes 

63.10(b)(2)(x) Yes 

63.10(b)(2)(xi) No 

63.10(b)(2)(xii) Yes 

63.10(b)(2)(xiii) No 

63.10(b)(2)(xiv) Yes 

63.10(b)(3) No 

63.10(c)(1)–

63.10(c)(6) 

No 

63.10(c)(7) and 

63.10(c)(8) 

Yes 

63.10(c)(9) No Reserved. 

63.10(c)(10)–

63.10(c)(11) 

No See §63.655(i)(11) for malfunctions recordkeeping 

requirements.

Deleted: Yes

Deleted: Yes

Deleted: Yes

Deleted: Yes

Deleted: 9

Deleted: 15
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Reference 

Applies to 

subpart CC Comment 

63.10(c)(12)–

63.10(c)(15) 

No 

63.10(d)(1) Yes 

63.10(d)(2) No §63.655(f) of subpart CC specifies performance test 

reporting. 

63.10(d)(3) No Results of visible emissions test are included in Compliance 

Status Report as specified in §63.655(f). 

63.10(d)(4) Yes 

63.10(d)(5) No See §63.655(g)(12) for malfunctions reporting requirements. 

63.10(e) No 

63.10(f) Yes 

63.11 Yes Except that flares complying with §63.670 are not subject to 

the requirements of §63.11(b). 

63.12–63.16 Yes 

a

Wherever subpart A specifies “postmark” dates, submittals may be sent by methods other 

than the U.S. Mail (e.g., by fax or courier). Submittals shall be sent by the specified dates, but a 

postmark is not required. 

Table 7—Fraction Measured (FM), Fraction Emitted (FE), and Fraction Removed (FR) for HAP 

Compounds in Wastewater Streams 

Chemical name CAS No.a Fm Fe Fr 

Benzene 71432 1

.00 

0

.80 

0

.99 

Biphenyl 92524 0

.86 

0

.45 

0

.99 

Butadiene (1,3) 106990 1

.00 

0

.98 

0

.99 

Carbon disulfide 75150 1

.00 

0

.92 

0

.99 

Cumene 98828 1

.00 

0

.88 

0

.99 

Dichloroethane (1,2-) (Ethylene dichloride) 107062 1

.00 

0

.64 

0

.99 

Ethylbenzene 100414 1

.00 

0

.83 

0

.99 

Hexane 110543 1

.00 

1

.00 

0

.99 

Methanol 67561 0

.85 

0

.17 

0

.31 

Methyl isobutyl ketone (hexone) 108101 0

.98 

0

.53 

0

.99 

Deleted: )(i

Deleted: Yesb

Deleted: Except that reports required by 

§63.10(d)(5)(i) may be submitted at the same time as 

periodic reports specified in §63.655(g) of subpart 

CC.

Deleted: 63.10(d)(5)(ii) ... [5]

Deleted: 11

Deleted: b The plan, and any records or reports of 

startup, shutdown, and malfunction do not apply to 

Group 2 emission points that are not part of an 

emissions averaging group.¶
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Chemical name CAS No.a Fm Fe Fr 

Methyl tert butyl ether 163404

4 

1

.00 

0

.57 

0

.99 

Naphthalene 91203 0

.99 

0

.51 

0

.99 

Trimethylpentane (2,2,4) 540841 1

.00 

1

.00 

0

.99 

xylene (m-) 108383 1

.00 

0

.82 

0

.99 

xylene (o-) 95476 1

.00 

0

.79 

0

.99 

xylene (p-) 106423 1

.00 

0

.82 

0

.99 

a

CAS numbers refer to the Chemical Abstracts Service registry number assigned to specific 

compounds, isomers, or mixtures of compounds. 

Table 8—Valve Monitoring Frequency for Phase III 

Performance level 

Leaking valves Valve monitoring frequency a (%) 

≥4 Monthly or QIP.b

<4 Quarterly. 

<3 Semiannual. 

<2 Annual. 

a

Percent leaking valves is calculated as a rolling average of two consecutive monitoring 

periods. 

b

QIP=Quality improvement program. Specified in §63.175 of subpart H of this part. 

Table 9—Valve Monitoring Frequency for Alternative 

Performance level 

Leaking valves Valve monitoring frequency under §63.649 alternative a (%) 

≥5 Monthly or QIP.b

<5 Quarterly. 

<4 Semiannual. 

<3 Annual. 

a

Percent leaking valves is calculated as a rolling average of two consecutive monitoring 

periods. 

b

QIP=Quality improvement program. Specified in §63.175 of subpart H of this part. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 10—Miscellaneous Process Vents—Monitoring, Recordkeeping and Reporting 

Requirements for Complying With 98 Weight-Percent Reduction of Total Organic HAP 

Emissions or a Limit of 20 Parts Per Million by Volume 

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

Thermal incinerator Firebox temperatureb

(63.644(a)(1)(i)) 

1. Continuous recordsc. 

 2. Record and report the firebox 

temperature averaged over the full 

period of the performance test—NCSd

. 

 3. Record the daily average firebox 

temperature for each operating daye

. 

 4. Report all daily average 

temperatures that are outside the range 

established in the NCS or operating 

permit and all operating days when 

insufficient monitoring data are 

collectedf

—PRg. 

Catalytic incinerator Temperature upstream and 

downstream of the catalyst 

bed (63.644(a)(1)(ii)) 

1. Continuous recordsc

. 

 2. Record and report the upstream and 

downstream temperatures and the 

temperature difference across the 

catalyst bed averaged over the full 

period of the performance test—NCSd

. 

 3. Record the daily average upstream 

temperature and temperature 

difference across the catalyst bed for 

each operating daye

. 

 4. Report all daily average upstream 

temperatures that are outside the range 

established in the NCS or operating 

permit—PRg

. 

 5. Report all daily average 

temperature differences across the 

catalyst bed that are outside the range 

established in the NCS or operating 

permit—PRg

. 

 6. Report all operating days when 

insufficient monitoring data are 

collectedf

. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

Boiler or process heater 

with a design heat capacity 

less than 44 megawatts 

where the vent stream is 

not introduced into the 

flame zoneh,i

Firebox temperatureb

(63.644(a)(4)) 

1. Continuous recordsc. 

 2. Record and report the firebox 

temperature averaged over the full 

period of the performance test—NCSd

. 

 3. Record the daily average firebox 

temperature for each operating daye

. 

 4. Report all daily average firebox 

temperatures that are outside the range 

established in the NCS or operating 

permit and all operating days when 

insufficient monitoring data are 

collectedf

—PRg. 

Flare (if meeting the 

requirements of 63.643 

and 63.644)

Presence of a flame at the 

pilot light (63.644(a)(2)) 

1. Hourly records of whether the 

monitor was continuously operating 

and whether a pilot flame was 

continuously present during each 

hour. 

 2. Record and report the presence of a 

flame at the pilot light over the full 

period of the compliance 

determination—NCSd

. 

 3. Record the times and durations of 

all periods when all pilot flames for a 

flare are absent or the monitor is not 

operating. 

 4. Report the times and durations of 

all periods when all pilot flames for a 

flare are absent or the monitor is not 

operating. 

Flare (if meeting the 

requirements of 63.670 

and 63.671) 

The parameters specified in 

63.670 

1. Records as specified in 

63.655(i)(9). 

2. Report information as specified in 

63.655(g)(11)—PRg. 

All control devices Volume of the gas stream

diverted to the atmosphere 

from the control device 

(63.644(c)(1)) or 

1. Continuous recordsc

.

Deleted: Presence

Deleted: flow

Deleted: Hourly

Deleted: of whether the flow indicator was 

operating and whether flow was detected at any time 

during each hour.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

 2. Record and report the times and 

durations of all periods when the vent 

stream is diverted through a bypass 

line or the monitor is not operating—

PRg

. 

 Monthly inspections of 

sealed valves 

(63.644(c)(2))

1. Records that monthly inspections 

were performed. 

 2. Record and report all monthly 

inspections that show the valves are 

not closed or the seal has been 

changed—PRg

. 

a

Regulatory citations are listed in parentheses. 

b

Monitor may be installed in the firebox or in the ductwork immediately downstream of the 

firebox before any substantial heat exchange is encountered. 

c

“Continuous records” is defined in §63.641. 

d

NCS = Notification of Compliance Status Report described in §63.655. 

e

The daily average is the average of all recorded parameter values for the operating day. If 

all recorded values during an operating day are within the range established in the NCS or 

operating permit, a statement to this effect can be recorded instead of the daily average. 

f

When a period of excess emission is caused by insufficient monitoring data, as described in 

§63.655(g)(6)(i)(C) or (D), the duration of the period when monitoring data were not collected 

shall be included in the Periodic Report. 

g

PR = Periodic Reports described in §63.655(g). 

h

No monitoring is required for boilers and process heaters with a design heat capacity ≥44 

megawatts or for boilers and process heaters where all vent streams are introduced into the flame 

zone. No recordkeeping or reporting associated with monitoring is required for such boilers and 

process heaters. 

i

Process vents that are routed to refinery fuel gas systems are not regulated under this 

subpart provided that on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

any flares receiving gas from that fuel gas system are in compliance with §63.670. No 

monitoring, recordkeeping, or reporting is required for boilers and process heaters that combust 

refinery fuel gas. 

Deleted: [

Deleted: )]
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Table 11—Compliance Dates and Requirements 

If the construction/ 

reconstruction 

datea is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as provided 

in... 

(1) After [INSERT 

THE DATE OF 

PUBLICATION OF 

THESE 

PROPOSED 

AMENDMENTS 

IN THE FEDERAL 

REGISTER] 

(i) Requirements for new 

sources in §§63.640 

through 63.642, §63.647, 

§§63.650 through 

63.653, and §§63.656 

through 63.660 

(a) Upon initial startup 

or [THE DATE OF 

PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER], 

whichever is later 

(1) §63.640(k), (l) 

and (m) 

(ii) The new source 

requirements in §63.654 

for heat exchange 

systems 

(a) Upon initial startup 

or October 28, 2009, 

whichever is later 

(1) §63.640(k), (l) 

and (m) 

(2) After September 

4, 2007 but on or 

before [INSERT 

THE DATE OF 

PUBLICATION OF 

THESE 

PROPOSED 

AMENDMENTS 

IN THE FEDERAL 

REGISTER] 

(i) Requirements for new 

sources in §§63.640 

through 63.653 and 

63.656b,c

(a) Upon initial startup (1) §63.640(k), (l) 

and (m) 

(ii) Requirements for 

new sources in §§63.640 

through 63.645, 

§§63.647 through 

63.653, and §§63.656, 

through 63.658b

(a) On or before [THE 

DATE 3 YEARS 

AFTER THE DATE 

OF PUBLICATION 

OF THE FINAL 

RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iii) Requirements for 

new sources in §63.660c

(a) On or before [THE 

DATE 90 DAYS 

AFTER THE DATE 

OF PUBLICATION 

OF THE FINAL 

RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iv) The new source 

requirements in §63.654 

for heat exchange 

systems 

(a) Upon initial startup 

or October 28, 2009, 

whichever is later 

(1) §63.640(k), (l) 

and (m) 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

If the construction/ 

reconstruction 

datea is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as provided 

in... 

(3) After July 14, 

1994 but on or 

before September 4, 

2007 

(i) Requirements for new 

sources in §§63.640 

through 63.653 and 

63.656d,e

(a) Upon initial startup 

or August 18, 1995, 

whichever is later 

(1) §63.640(k), (l) 

and (m) 

(ii) Requirements for 

new sources in §§63.640 

through 63.645, 

§§63.647 through 

63.653, and §§63.656, 

through 63.658d

(a) On or before [THE 

DATE 3 YEARS 

AFTER THE DATE 

OF PUBLICATION 

OF THE FINAL 

RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iii) Requirements for 

new sources in §63.660e

(a) On or before [THE 

DATE 90 DAYS 

AFTER THE DATE 

OF PUBLICATION 

OF THE FINAL 

RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iv) The existing source 

requirements in §63.654 

for heat exchange 

systems 

(a) On or before 

October 29, 2012 

(1) §63.640(k), (l) 

and (m) 

(4) On or before 

July 14, 1994 

(i) Requirements for 

existing sources in 

§§63.640 through 63.653 

and 63.656f,g

(a) On or before 

August 18, 1998 

(1) §63.640(k), (l) 

and (m) 

(2) §63.6(c)(5) of 

subpart A of this part 

or unless an 

extension has been 

granted by the 

Administrator as 

provided in §63.6(i) 

of subpart A of this 

part 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

If the construction/ 

reconstruction 

datea is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as provided 

in... 

(ii) Requirements for 

existing sources in 

§§63.640 through 

63.645, §§63.647 

through 63.653, and 

§§63.656 through 

63.658f

(a) On or before [THE 

DATE 3 YEARS 

AFTER THE DATE 

OF PUBLICATION 

OF THE FINAL 

RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iii) Requirements for 

existing sources in 

§63.660g

(a) On or before [THE 

DATE 90 DAYS 

AFTER THE DATE 

OF PUBLICATION 

OF THE FINAL 

RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iii) The existing source 

requirements in §63.654 

for heat exchange 

systems 

(a) On or before 

October 29, 2012 

(1) §63.640(k), (l) 

and (m) 

a

 For purposes of this table, the construction/reconstruction date means the date of 

construction or reconstruction of an entire affected source or the date of a process unit addition 

or change meeting the criteria in §63.640(i) or (j). If a process unit addition or change does not 

meet the criteria in §63.640(i) or (j), the process unit shall comply with the applicable 

requirements for existing sources. 

b

 Between the compliance dates in items (2)(i)(a) and (2)(ii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (2)(i) or item (2)(ii) of this 

table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance 

with the requirements in item (2)(ii) of this table. 

c

 Between the compliance dates in items (2)(i)(a) and (2)(iii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (2)(i) or item (2)(iii) of this 

table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance 

with the requirements in item (2)(iii) of this table. 

d

 Between the compliance dates in items (3)(i)(a) and (3)(ii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (3)(i) or item (3)(ii) of this 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance 

with the requirements in item (3)(ii) of this table. 

e

 Between the compliance dates in items (3)(i)(a) and (3)(iii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (3)(i) or item (3)(iii) of this 

table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance 

with the requirements in item (3)(iii) of this table. 

f

 Between the compliance dates in items (4)(i)(a) and (4)(ii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (4)(i) or item (4)(ii) of this 

table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance 

with the requirements in item (4)(ii) of this table. 

g

 Between the compliance dates in items (4)(i)(a) and (4)(iii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (4)(i) or item (4)(iii) of this 

table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance 

with the requirements in item (4)(iii) of this table. 

Table 12— Individual Component Properties 

Component 

Molecular 

Formula 

MWi

(pounds per 

poundmole) 

CMNi

(mole per 

mole) 

NHVi

(British thermal 

units per standard 

cubic foot) 

LFLi

(volume 

%) 

Acetylene C2H2 26.04 2 1,404 2.5 

Benzene C6H6 78.11 6 3,591 1.3 

1,2-Butadiene C4H6 54.09 4 2,794 2.0 

1,3-Butadiene C4H6 54.09 4 2,690 2.0 

iso-Butane C4H10 58.12 4 2,957 1.8 

n-Butane C4H10 58.12 4 2,968 1.8 

cis-Butene C4H8 56.11 4 2,830 1.6 

iso-Butene C4H8 56.11 4 2,928 1.8 

trans-Butene C4H8 56.11 4 2,826 1.7 

Carbon Dioxide CO2 44.01 1 0 ∞

Carbon Monoxide CO 28.01 1 316 12.5 

Cyclopropane C3H6 42.08 3 2,185 2.4 

Ethane C2H6 30.07 2 1,595 3.0 

Ethylene C2H4 28.05 2 1,477 2.7 

Hydrogen H2 2.02 0 274 4.0 

Methane CH4 16.04 1 896 5.0 

Methyl-Acetylene C3H4 40.06 3 2,088 1.7 

Nitrogen N2 28.01 0 0 ∞

Oxygen O2 32.00 0 0 ∞

Pentane+ (C5+) C5H12 72.15 5 3,655 1.4 

Propadiene C3H4 40.06 3 2,066 2.16 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Component 

Molecular 

Formula 

MWi

(pounds per 

poundmole) 

CMNi

(mole per 

mole) 

NHVi

(British thermal 

units per standard 

cubic foot) 

LFLi

(volume 

%) 

Propane C3H8 44.10 3 2,281 2.1 

Propylene C3H6 42.08 3 2,150 2.4 

Water H2O 18.02 0 0 ∞

Table 13—Calibration and Quality Control Requirements for CPMS 

Parameter Accuracy requirements Calibration requirements 

Temperat

ure 

±1 percent over the normal range 

of temperature measured or 

2.8 degrees Celsius (5 

degrees Fahrenheit), 

whichever is greater, for noncryogenic temperature ranges. 

±2.5 percent over the normal 

range of temperature 

measured or 2.8 degrees 

Celsius (5 degrees 

Fahrenheit), whichever is 

greater, for cryogenic 

temperature ranges. 

Performance evaluation annually and 

following any period of more than 24 

hours throughout which the 

temperature exceeded the maximum 

rated temperature of the sensor, or the 

data recorder was off scale. Visual 

inspections and checks of CPMS 

operation every 3 months, unless the 

CPMS has a redundant temperature 

sensor. 

Select a representative measurement 

location. 

Flow Rate ±5 percent over the normal range 

of flow measured or 1.9 liters 

per minute (0.5 gallons per 

minute), whichever is greater, 

for liquid flow rate. 

±5 percent over the normal range 

of flow measured or 280 liters 

per minute (10 cubic feet per 

minute), whichever is greater, 

for gas flow rate. 

±5 percent over the normal range 

measured for mass flow rate. 

Performance evaluation annually and 

following any period of more than 24 

hours throughout which the flow rate 

exceeded the maximum rated flow rate 

of the sensor, or the data recorder was 

off scale. Checks of all mechanical 

connections for leakage monthly. 

Visual inspections and checks of 

CPMS operation every 

3 months, unless the CPMS has a 

redundant flow sensor. 

Select a representative measurement 

location where swirling flow or 

abnormal velocity distributions due to 

upstream and downstream 

disturbances at the point of 

measurement are minimized. 

Pressure ±5 percent over the normal range 

measured or 0.12 kilopascals 

(0.5 inches of water column), 

whichever is greater. 

Checks for obstructions at least once each 

process operating day (e.g., pressure 

tap pluggage). 

Performance evaluation annually and 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

following any period of more than 24 

hours throughout which the pressure 

exceeded the maximum rated pressure 

of the sensor, or the data recorder was 

off scale. Checks of all mechanical 

connections for leakage monthly. 

Visual inspection of all components 

for integrity, oxidation and galvanic 

corrosion every 3 months, unless the 

CPMS has a redundant pressure 

sensor. 

Select a representative measurement 

location that minimizes or eliminates 

pulsating pressure, vibration, and 

internal and external corrosion. 

Net 

Heating Value 

by Calorimeter 

±2 percent of span Specify calibration requirements in your 

site specific CPMS monitoring plan. 

Calibration requirements should 

follow manufacturer’s 

recommendations at a minimum. 

Temperature control (heated and/or cooled 

as necessary) the sampling system to 

ensure proper year-round operation. 

Where feasible, select a sampling location 

at least two equivalent diameters 

downstream from and 0.5 equivalent 

diameters upstream from the nearest 

disturbance. Select the sampling 

location at least two equivalent duct 

diameters from the nearest control 

device, point of pollutant generation, 

air in-leakages, or other point at which 

a change in the pollutant concentration 

or emission rate occurs. 

Net 

Heating Value 

by Gas 

Chromatograph 

As specified in Performance 

Specification 9 of 40 CFR 

part 60, Appendix B. 

Follow the procedure in Performance 

Specification 9 of 40 CFR part 60, 

Appendix B. 

Net 

Heating Value 

by Total 

Hydrocarbon 

Monitor 

Calibration drift ≤ 3% of 

instrument span at each level. 

Cylinder Gas Audit Accuracy ≤

5% of instrument span at each 

level. 

Calibration drift check daily. Follow the 

procedure in Sections 4.1 and 4.2 of 

Procedure 1 in 40 CFR part 60, 

Appendix F. 

Cylinder gas audit quarterly. Follow the 

procedure in Section 5.1.2 of 

Procedure 1 in 40 CFR part 60, 

Appendix F, except the audit shall be 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

performed every quarter. 

For both the calibration drift and error 

tests, the calibration gases should be 

injected into the sampling system as 

close to the sampling probe outlet as 

practical and must pass through all 

filters, scrubbers, conditioners, and 

other monitor components used during 

normal sampling. 

Select a measurement location that meets 

the requirements of Section 3.1 of 

Performance Specification 8A of 

Appendix B to 40 CFR part 60. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EO12866_RefineryRTR 2060 AQ75 NPRM Part60Subpart_Ja_RegText_20140128 

Title 40: Protection of Environment 

PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

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

Reconstruction, or Modification Commenced After May 14, 2007 

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

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

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

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

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

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

refinery. 

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

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

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

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

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

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

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

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

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

following dates: 

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

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

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

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

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

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

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

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

§60.101a. 

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

apply. As provided in §60.14(f), the special provisions set forth under this subpart shall 

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. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

lines). 

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

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

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

(iv) Connections made for flare gas sulfur removal. 

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

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

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

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

the pipe/connection being replaced/moved. 

(vii) Connections that interconnect two or more flares. 

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

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

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

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

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

section. 

§ 60.101a Definitions. 

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

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

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

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

unit. Ancillary equipment includes, but is not limited to, storage tanks, product loading 

operations, wastewater treatment systems, steam- or electricity-producing units (including coke 

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

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

with increasing pressure set points so that discharges will be initially directed to the first flare in 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

three) flares would exceed their capacities. 

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

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

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

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

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

§60.104a. 

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

other contaminant from petroleum derivatives. 

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

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

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

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

thresholds. 

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

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

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

feasibility, safety and secondary impacts. 

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

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

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

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

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

coker quench water tank; process piping and associated equipment such as pumps, valves and 

connectors; and the coke drum blowdown recovery compressor system. 

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

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

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

flare unless it maintains a water seal. 

Flare means a combustion device that uses an uncontrolled volume of air to burn gases. The flare 

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

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

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

the interconnected flare gas header system and the interconnected flare gas header system. 

Deleted: Delayed coking unit means one or more 

refinery process units in which high molecular 

weight petroleum derivatives are thermally cracked 

and petroleum coke is produced in a series of closed, 

batch system reactors.¶

Deleted: to

Deleted: flare 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

knockout pot that is part of the flare. 

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

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

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

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

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

to produce a synthetic fuel gas. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

the combustion air enters the process heater or air preheat. For the purposes of this subpart, a 

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

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

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

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

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

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

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

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

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

marine tank vessel loading operations or asphalt processing units (i.e., asphalt blowing stills). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

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

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

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

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

draft process heater, including induced draft systems. 

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

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

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

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

converting the SO2 to a sulfur product. 

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

and coal. 

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

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

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

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

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

petroleum refinery. 

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

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

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

instead of steam. 

Process upset gas means any gas generated by a petroleum refinery process unit or by ancillary 

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

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

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

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

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

disulfide. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

the H2S to a sulfur product. 

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

processing operation is conducted. 

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

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

excess of specified thresholds. 

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

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

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

and must maintain a water seal.

Sour water means water that contains sulfur compounds (usually H2S) at concentrations of 10 

parts per million by weight or more.

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

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

vessels downstream of the initial Claus reactor sulfur pits. 

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

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

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

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

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

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

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

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

completely segregated sour gas treatment systems are separate affected facilities. 

Sweep gas means the gas introduced in a flare gas header system to maintain a constant flow of 

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

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

§ 60.102a Emissions limitations. 

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

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

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

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

180 days after initial startup, whichever comes first. 

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

discharge into the atmosphere from any FCCU or FCU: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

section. 

(i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke burn-off or, if a PM continuous 

emission monitoring system (CEMS) is used, 0.040 grain per dry standard cubic feet (gr/dscf) 

corrected to 0 percent excess air for each modified or reconstructed FCCU. 

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

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

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

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

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

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

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

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

rolling average basis. 

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

an hourly average basis. 

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

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

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

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

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

fall below the level established during the most recent performance test; and 

(ii) The daily average exhaust coke burn-off rate must not exceed the level established during the 

most recent performance test. 

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

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

most recent performance test; and 

(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. 

Deleted: per Megagram (

Deleted: /Mg)(

Deleted: /Mg

Deleted: ;
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

below the level established during the most recent performance test. 

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

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

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

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

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

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

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

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

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

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

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

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

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

process train or release point individually or comply with the applicable emission limit in 

paragraphs (f)(1)(i) or (f)(1)(ii) of this section as a flow rate weighted average for a group of 

release points from the sulfur recovery plant provided that flow is monitored as specified in 

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

shall comply with the applicable emission limit in paragraphs (f)(1)(i) or (f)(1)(ii) of this section 

for each process train or release point individually. For a sulfur recovery plant with a design 

production capacity greater than 20 long LTD and a reduction control system not followed by 

incineration, the owner or operator shall also comply with the H2S emission limit in paragraph 

(f)(1)(iii) of this section for each individual release point.

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

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

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

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

monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for non-Claus 

sulfur recovery plants, this SO2 emissions limit is 250 ppmv (dry basis) at zero percent excess 

air. 

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

Deleted: :

Deleted: by 

Deleted: olume

Deleted: of sulfur dioxide (SO2) 

Deleted: 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

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: 

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

excess air); 

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

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

incineration and k1 = 1.2 for converting to the reduced sulfur compounds limit for a sulfur 

recovery plant with a reduction control system not followed by incineration; and 

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

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

elects not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for 

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

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

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

containing reduced sulfur compounds in excess of the emission limit calculated using Equation 1 

of this section. For Claus units that use only ambient air in the Claus burner or for non-Claus 

sulfur recovery plants, this reduced sulfur compounds emission limit is 300 ppmv calculated as 

ppmv SO2 (dry basis) at 0-percent excess air.

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

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

containing hydrogen sulfide (H2S) in excess of 10 ppmv calculated as ppmv SO2 (dry basis) at 

zero percent excess air.

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

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

this section. If the sulfur recovery plant consists of multiple process trains or release points, the 

owner or operator may comply with the applicable emission limit for each process train or 

release point individually or comply with the applicable emission limit in paragraphs (f)(2)(i) or 

(f)(2)(ii) of this section as a flow rate weighted average for a group of release points from the 

sulfur recovery plant provided that flow is monitored as specified in §60.106a(a)(7); if flow is 

not monitored as specified in §60.106a(a)(7), the owner or operator shall comply with the 

applicable emission limit in paragraphs (f)(2)(i) or (f)(2)(ii) of this section for each process train 

or release point individually. For a sulfur recovery plant with a design production capacity of 20 

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

shall also comply with the H2S emission limit in paragraph (f)(2)(iii) of this section for each 

individual release point.

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

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

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

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

elect not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for 

Deleted: of reduced sulfur compounds and 10 

ppmv of H2S, each

Deleted: ; or

Deleted: For systems using oxygen enrichment, 

the owner or operator shall calculate the applicable 

emission limit using Equation 1 of this section:

Deleted: 

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).¶

Deleted: :
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

non-Claus sulfur recovery plants, this SO2 emission limit is 2,500 ppmv (dry basis) at zero 

percent excess air. 

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

Where: 

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

excess air); 

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

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

incineration and k1 = 1.2 for converting to the reduced sulfur compounds limit for a sulfur 

recovery plant with a reduction control system not followed by incineration; and 

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

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

elects not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for 

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

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

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

containing reduced sulfur compounds in excess of the emission limit calculated using Equation 2 

of this section. For Claus units that use only ambient air in the Claus burner or for non-Claus 

sulfur recovery plants, this reduced sulfur compounds emission limit is 3,000 ppmv calculated as 

ppmv SO2 (dry basis) at zero percent excess air.

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

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

containing H2S in excess of 100 ppmv calculated as ppmv SO2 (dry basis) at zero percent excess 

air.

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

maintenance of the sulfur pit, which shall not exceed 240 hours per year. The owner or operator 

must document the time periods during which the sulfur pit vents were not controlled and 

measures taken to minimize emissions during these periods. Examples of these measures include 

not adding fresh sulfur or shutting off vent fans. 

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

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

(1) Except as provided in (g)(1)(iii) of this section, for each fuel gas combustion device, the 

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

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

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

owner or operator shall comply with the fuel gas concentration limit in paragraph (g)(1)(ii) of 

this section for all fuel gas streams combusted in these units.

Deleted: in excess of

Deleted: by volume

Deleted: of SO2 

Deleted: 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

Field Code Changed

Deleted: in excess of

Deleted: by 

Deleted: olume

Deleted: of reduced sulfur compounds and 100 

ppm by volume of hydrogen sulfide (H2S), each 

Deleted: by volume 

Deleted: ; or

Deleted: 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: P

Deleted: during which the emission limits in 

paragraphs (f)(1) and (2) shall not apply, 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

average basis; or 

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

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

H2S in excess of 60 ppmv determined daily on a 365 successive calendar day rolling average 

basis. 

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

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

section. 

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

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

to the atmosphere any emissions of NOX in excess of the applicable limits in paragraphs 

(g)(2)(i) through (iv) of this section. 

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

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

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

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

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

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

average basis; or 

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

determined daily on a 30-day rolling average basis. 

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

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

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

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

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

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

average basis; or 

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

basis. 

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

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

limits with which to comply at all times: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

operating day rolling average basis; or 

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

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER



  0.06 0.35

 (Eq. 3) 

Where: 

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

basis); 

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

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

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

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

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

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

limits with which to comply at all times: 

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

operating day rolling average basis; or 

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

gas gas oil oil

gas gas oil oil

NOx Q HHV Q HHV

Q HHV Q HHV

ER



  0.11 0.40

 (Eq. 4) 

Where: 

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

basis); 

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

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

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

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

(h) [Reserved] 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

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

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

NOX burners); or 

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

or 

(iii) A co-fired process heater; or 

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

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

operating conditions. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

operator will use to minimize NOX emissions. 

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

site-specific emissions limit. 

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

of this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

that affected facility. 

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

comply with the request as submitted until it is approved. 

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

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

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

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

submitted to refinerynsps@epa.gov. 

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

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

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

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

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

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

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

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

considered for reducing NOX emissions; 

(C) The combustion modification option selected; and 

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

concentration) at which the NOX emission level was established. 

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

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

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

address the deficiencies and be re-submitted for approval. 

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

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

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

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

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

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

the flare for each affected flare. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

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

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

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

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

recovery at the source. 

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

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

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

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

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

(vii) of this section. 

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

through (G) of this section. 

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

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

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

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

secondary). 

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

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

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

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

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

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

capacities); flare header(s) and subheader(s); assist system; and ignition system. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

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

location and type of each monitor. 

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

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

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

maintenance and quality assurance procedures. 

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

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

or malfunction: 

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

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

water seal liquid level monitoring). 

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

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

capacity of each compressor. 

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

recovered. 

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

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

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

maximum time period cannot be further reduced. 

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

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

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

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

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

different operating conditions provided that the management plan includes: 

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

those specifically delineated in the plan; 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

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

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

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

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

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

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

management plan. 

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

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

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

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

management plan. 

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

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

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

of this section. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

comply with the updated plan as submitted. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

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

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

(1) For a flare: 

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

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

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

hour period; or 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

and corrective action analysis may be conducted. 

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

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

analysis and corrective action analysis may be conducted. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

root cause analysis and corrective action analysis may be conducted. 

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

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

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

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

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

single corrective action analysis may be conducted. 

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

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

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

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

(3) of this section. 

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

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

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

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

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

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

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

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

as practicable. 

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

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

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

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

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

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

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

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

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

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

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

paragraph (h) of this section and the requirements of §60.107a(a)(2) by November 13, 2012 or at 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

11, 2015. 

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

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

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

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

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

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

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

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

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

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

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

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

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

refinerynsps@epa.gov. 

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

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

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

leakage or other emergency malfunctions is exempt from this limit. 

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

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

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

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

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

combustion device or a flare. 

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

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

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

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

section. 

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

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

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

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

emission limitation. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

demonstrated. 

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

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

demonstrated. 

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

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

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

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

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

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

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

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

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

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

requirements. 

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

equivalent means of emission limitation. 

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

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

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

notice in the Federal Register and provide the opportunity for public hearing if the Administrator 

judges that the request may be approved. 

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

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

Register. 

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

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

111(h)(1) of the CAA. 

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

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

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

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

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

§ 60.104a Performance tests. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(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 and conduct a performance test for each flare to demonstrate initial 

compliance with the H2S concentration requirement in §60.103a(h) according to the 

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

test and to subsequent performance tests required by paragraph (b) of this section (or as required 

by the Administrator), but does not apply to performance tests conducted for the purpose of 

obtaining supplemental data because of continuous monitoring system breakdowns, repairs, 

calibration checks and zero and span adjustments. 

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

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

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

shall conduct a PM performance test at least annually (i.e., once per calendar year, with an 

interval of at least 8 months but no more than 16 months between annual tests) and furnish the 

Administrator a written report of the results of each test. 

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

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

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

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

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

procedures: 

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

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

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

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

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

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

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

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

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

emissions limit in §63.102a(b)(1). 

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

less than 60 minutes. 

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

c

s sd

KR

c Q E 

 (Eq. 5) 

Deleted: , flare

Deleted: once every 12 months
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: 

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

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

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

cubic feet per hour); 

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

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

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

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

Where: 

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

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

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

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

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

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

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

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

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

exhaust, percent by volume (dry basis); 

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

volume (dry basis); 

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

volume (dry basis); 

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

coking burner, percent by volume (dry basis); 

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

K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hrdscf)]; and 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

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

 

2 2

a xy oxy

r %CO %CO %O

Q %O Q Q        100

79 100

 (Eq. 7) 

Where: 

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

any emission control or energy recovery system that burns auxiliary fuel, dscm/min (dscf/min); 

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

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

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

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

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

percent by volume (dry basis); 

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

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

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

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

volume (dry basis); and 

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

coking burner, percent by volume (dry basis). 

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

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

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

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

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

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

be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

 

    2

c adj meas %O C C 20.9

20.9

 (Eq. 8) 

Where: 

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

g/dscm; 

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

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

20.9 = O2 concentration in air, percent; and 

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

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

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

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

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

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

the three test runs. 

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

coke burn-off emissions limit in §60.102a(b)(1) shall establish a site-specific opacity operating 

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

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

reduce the data to 6-minute averages. 

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

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















  

st

st PMEmR Opacity Li mit Opacity 1 lb / 1,000 lb coke burn

 (Eq. 9) 

Deleted: and elects to comply with the COMS 

alternative monitoring option in §60.105a(d) 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: 

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

is greater; 

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

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

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

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

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

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

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

hourly averages for each test run. 

(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 emissions limits for sulfur 

recovery plants in §§60.102a(f)(1)(i) and 60.102a(f)(2)(i) and the reduced sulfur compounds and 

H2S emissions limits for sulfur recovery plants in §§60.102a(f)(1)(ii), 60.102a(f)(1)(iii), 

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

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

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

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

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

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

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

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

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

part 60. 

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

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

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

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

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

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

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

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

Deleted: and H2S 

Deleted: , 60.102a(f)(1)(iii), 60.102a(f)(1)(iii),

Deleted: , and 60.102a(f)(2)(iii)

Deleted: §

Deleted: §
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

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

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

subpart is used to determine the applicable emissions limit, determine the average O2 

concentration of the air/oxygen mixture supplied to the Claus burner, in percent by volume (dry 

basis), for the performance test using all hourly average O2 concentrations determined during the 

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

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

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

procedures: 

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

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

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

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

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

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

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

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

part 60. 

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

than 1 hour. 

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

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

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

source of fuel gas that previously demonstrated compliance. 

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

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

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

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

appendix A-4 to part 60. 

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

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

§60.107a(c)(6) or (d)(8), the owner or operator shall establish the O2 operating limit or O2 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

operating curve based on the performance test results according to the requirements in paragraph 

(i)(6)(i) or (ii) of this section, respectively. 

(i) If a single O2 operating limit will be used: 

(A) Conduct the performance test following the methods provided in paragraphs (i)(1), (2), (3) 

and (5) of this section when the process heater is firing at no less than 70 percent of the rated 

heat capacity. For co-fired process heaters, conduct at least one of the test runs while the process 

heater is being supplied by both fuel gas and fuel oil and conduct at least one of the test runs 

while the process heater is being supplied solely by fuel gas. 

(B) Each test will consist of three test runs. Calculate the NOX concentration for the 

performance test as the average of the NOX concentrations from each of the three test runs. If the 

NOX concentration for the performance test is less than or equal to the numerical value of the 

applicable NOX emissions limit (regardless of averaging time), then the test is considered to be a 

valid test. 

(C) Determine the average O2 concentration for each test run of a valid test. 

(D) Calculate the O2 operating limit as the average O2 concentration of the three test runs from a 

valid test. 

(ii) If an O2 operating curve will be used: 

(A) Conduct a performance test following the methods provided in paragraphs (i)(1), (2), (3) and 

(5) of this section at a representative condition for each operating range for which different O2 

operating limits will be established. Different operating conditions may be defined as different 

firing rates (e.g., above 50 percent of rated heat capacity and at or below 50 percent of rated heat 

capacity) and/or, for co-fired process heaters, different fuel mixtures (e.g., primarily gas fired, 

primarily oil fired, and equally co-fired, i.e., approximately 50 percent of the input heating value 

is from fuel gas and approximately 50 percent of the input heating value is from fuel oil). 

Performance tests for different operating ranges may be conducted at different times. 

(B) Each test will consist of three test runs. Calculate the NOX concentration for the 

performance test as the average of the NOX concentrations from each of the three test runs. If the 

NOX concentration for the performance test is less than or equal to the numerical value of the 

applicable NOX emissions limit (regardless of averaging time), then the test is considered to be a 

valid test. 

(C) If an operating curve is developed for different firing rates, conduct at least one test when the 

process heater is firing at no less than 70 percent of the rated heat capacity and at least one test 

under turndown conditions (i.e., when the process heater is firing at 50 percent or less of the 

rated heat capacity). If O2 operating limits are developed for co-fired process heaters based only 

on overall firing rates (and not by fuel mixtures), conduct at least one of the test runs for each 

test while the process heater is being supplied by both fuel gas and fuel oil and conduct at least 

one of the test runs while the process heater is being supplied solely by fuel gas. 

(D) Determine the average O2 concentration for each test run of a valid test. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(E) Calculate the O2 operating limit for each operating range as the average O2 concentration of 

the three test runs from a valid test conducted at the representative conditions for that given 

operating range. 

(F) Identify the firing rates for which the different operating limits apply. If only two operating 

limits are established based on firing rates, the O2 operating limits established when the process 

heater is firing at no less than 70 percent of the rated heat capacity must apply when the process 

heater is firing above 50 percent of the rated heat capacity and the O2 operating limits 

established for turndown conditions must apply when the process heater is firing at 50 percent or 

less of the rated heat capacity. 

(G) Operating limits associated with each interval will be valid for 2 years or until another 

operating limit is established for that interval based on a more recent performance test specific 

for that interval, whichever occurs first. Owners and operators must use the operating limits 

determined for a given interval based on the most recent performance test conducted for that 

interval. 

(7) The owner or operator of a process heater complying with a NOX limit in terms of 

lb/MMBtu as provided in §60.102a(g)(2)(i)(B), (g)(2)(ii)(B), (g)(2)(iii)(B) or (g)(2)(iv)(B) or a 

process heater with a rated heat capacity between 40 and 100 MMBtu/hr that elects to 

demonstrate continuous compliance with a maximum excess O2 limit, as provided in 

§60.107a(c)(6) or (d)(8), shall determine heat input to the process heater in MMBtu/hr during 

each performance test run by measuring fuel gas flow rate, fuel oil flow rate (as applicable) and 

heating value content according to the methods provided in §60.107a(d)(5), (d)(6), and (d)(4) or 

(d)(7), respectively. 

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

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

(j) The owner or operator shall determine compliance with the applicable H2S emissions limit in 

§60.102a(g)(1) for a fuel gas combustion device or the concentration requirement in §60.103a(h) 

for a flare according to the following test methods and procedures: 

(1) [Reserved]

(2) [Reserved]

(3) [Reserved]

(4) EPA Method 11, 15 or 15A of Appendix A-5 to part 60 or EPA Method 16 of Appendix A-6 

to part 60 for determining the H2S concentration for affected facilities using an H2S monitor as 

specified in §60.107a(a)(2). The method ANSI/ASME PTC 19.10-1981 (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 15A of Appendix A-5 to part 

60. The owner or operator may demonstrate compliance based on the mixture used in the fuel 

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

combustion device or flare. 

Deleted: Method 1 of appendix A-1 to part 60 for 

sample and velocity traverses;

Deleted: Method 2 of appendix A-1 to part 60 for 

velocity and volumetric flow rate;

Deleted: 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;
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) For Method 11 of appendix A-5 to part 60, the sampling time and sample volume must be at 

least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal sampling times must be 

taken at about 1-hour intervals. The arithmetic average of these two samples constitutes a run. 

For most fuel gases, sampling times exceeding 20 minutes may result in depletion of the 

collection solution, although fuel gases containing low concentrations of H2S may necessitate 

sampling for longer periods of time. 

(ii) For Method 15 of appendix A-5 to part 60, at least three injects over a 1-hour period 

constitutes a run. 

(iii) For Method 15A of appendix A-5 to part 60, a 1-hour sample constitutes a run. The method 

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

see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. 

(iv) If monitoring is conducted at a single point in a common source of fuel gas as allowed under 

§60.107a(a)(2)(iv), only one performance test is required. That is, performance tests are not 

required when a new affected fuel gas combustion device or flare is added to a common source 

of fuel gas that previously demonstrated compliance. 

§ 60.105a Monitoring of emissions and operations for fluid catalytic cracking units (FCCU) and 

fluid coking units (FCU). 

(a) FCCU and FCU subject to PM emissions limit. Each owner or operator subject to the 

provisions of this subpart shall monitor each FCCU and FCU subject to the PM emissions limit 

in §60.102a(b)(1) according to the requirements in paragraph (b), (c), (d), or (e) of this section. 

(b) Control device operating parameters. Each owner or operator of a FCCU or FCU subject to 

the PM per coke burn-off emissions limit in §60.102a(b)(1) that uses a control device other than 

fabric filter or cyclone shall comply with the requirements in paragraphs (b)(1) and (2) of this 

section. 

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

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

to the applicable requirements in paragraphs (b)(1)(i) through (v) of this section. 

(i) For units controlled using an electrostatic precipitator, the owner or operator shall use CPMS 

to measure and record the hourly average total power input and secondary current to the entire 

system. 

(ii) For units controlled using a wet scrubber, the owner or operator shall use CPMS to measure 

and record the hourly average pressure drop, liquid feed rate, and exhaust gas flow rate. As an 

alternative to a CPMS, the owner or operator must comply with the requirements in either 

paragraph (b)(1)(ii)(A) or (B) of this section. 

(A) As an alternative to pressure drop, the owner or operator of a jet ejector type wet scrubber or 

other type of wet scrubber equipped with atomizing spray nozzles must conduct a daily check of 

the air or water pressure to the spray nozzles and record the results of each check. Faulty (e.g., 

Deleted: voltage
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

leaking or plugged) air or water lines must be repaired within 12 hours of identification of an 

abnormal pressure reading.

(B) As an alternative to exhaust gas flow rate, the owner or operator shall comply with the 

approved alternative for monitoring exhaust gas flow rate in 40 CFR 63.1573(a) of the National 

Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking 

Units, Catalytic Reforming Units, and Sulfur Recovery Units. 

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

manufacturer's specifications and requirements. 

(iv) The owner or operator shall determine and record the average coke burn-off rate and hours 

of operation for each FCCU or FCU using the procedures in §60.104a(d)(4)(iii). 

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

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

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

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

of this section. 

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

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

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

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

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

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

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

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

maintained to meet the emission limitation. 

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

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

proposed monitoring, recording, and reporting requirements. 

(D) Supporting calculations. 

(E) Averaging time for the alternative operating parameter. 

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

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

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

control or energy recovery system that burns auxiliary fuels. A CO monitor is not required for 

determining coke burn-off rate when no auxiliary fuel is burned and a continuous CO monitor is 

not required in accordance with §60.105a(h)(3).

(i) The owner or operator shall install, operate and maintain each CO2 and O2 monitor according 

to Performance Specifications 3 and 4 of Appendix B to part 60. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) The owner or operator shall conduct performance evaluations of each CO2 and O2 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 EPA Method 3 of Appendix A-3 to part 60 and 

EPA Method 10, 10A or 10B of Appendix A-4 to part 60 for conducting the relative accuracy 

evaluations. 

(iii) If a CO monitor is required, the owner or operator shall install, operate, and maintain each 

CO monitor according to Performance Specification 4 or 4A of Appendix B to part 60. If this CO 

monitor also serves to demonstrate compliance with the CO emissions limit in §60.102a(b)(4), 

the span value for this instrument is 1,000 ppmv; otherwise, the span value for this instrument 

should be set at approximately 2 times the typical CO concentration expected in the FCCU of 

FCU flue gas prior to any emission control or energy recovery system that burns auxiliary fuels. 

(iv) If a CO monitor is required, the owner or operator shall conduct performance evaluations of 

each CO monitor according to the requirements in §60.13(c) and Performance Specification 4 of 

Appendix B to part 60. The owner or operator shall use Method 10, 10A, or 10B of Appendix 

A–3 to part 60 for conducting the relative accuracy evaluations. 

(v) The owner or operator shall comply with the quality assurance requirements of procedure 1 

of appendix F to part 60, including quarterly accuracy determinations for CO2 and CO monitors, 

annual accuracy determinations for O2 monitors, and daily calibration drift tests. 

(c) Bag leak detection systems. Each owner or operator shall install, operate, and maintain a bag 

leak detection system for each baghouse or similar fabric filter control device that is used to 

comply with the PM per coke burn-off emissions limit in §60.102a(b)(1) for an FCCU or FCU 

according to paragraph (c)(1) of this section; prepare and operate by a site-specific monitoring 

plan according to paragraph (c)(2) of this section; take action according to paragraph (c)(3) of 

this section; and record information according to paragraph (c)(4) of this section. 

(1) Each bag leak detection system must meet the specifications and requirements in paragraphs 

(c)(1)(i) through (viii) of this section. 

(i) The bag leak detection system must be certified by the manufacturer to be capable of 

detecting PM emissions at concentrations of 0.00044 grains per actual cubic foot or less. 

(ii) The bag leak detection system sensor must provide output of relative PM loadings. The 

owner or operator shall continuously record the output from the bag leak detection system using 

electronic or other means (e.g., using a strip chart recorder or a data logger). 

(iii) The bag leak detection system must be equipped with an alarm system that will sound when 

the system detects an increase in relative particulate loading over the alarm set point established 

according to paragraph (c)(1)(iv) of this section, and the alarm must be located such that it can be 

heard by the appropriate plant personnel. 

(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. 

Deleted: , O2

Deleted: CO
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(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 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(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. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(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. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(h) FCCU and fluid coking units subject to CO emissions limit. Except as specified in paragraph 

(h)(3) of this section, the owner or operator shall install, operate, calibrate, and maintain an 

instrument for continuously monitoring and recording the concentration by volume (dry basis) of 

CO emissions into the atmosphere from each FCCU and FCU subject to the CO emissions limit 

in §60.102a(b)(4). 

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

Performance Specification 4 or 4A of appendix B to part 60. The span value for this instrument 

is 1,000 ppmv CO. 

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

to the requirements in §60.13(c) and Performance Specification 4 or 4A of appendix B to part 60. 

The owner or operator shall use Methods 10, 10A, or 10B of appendix A-4 to part 60 for 

conducting the relative accuracy evaluations. 

(3) A CO CEMS need not be installed if the owner or operator demonstrates that all hourly 

average CO emissions are and will remain less than 50 ppmv (dry basis) corrected to 0 percent 

excess air. The Administrator may revoke this exemption from monitoring upon a determination 

that CO emissions on an hourly average basis have exceeded 50 ppmv (dry basis) corrected to 0 

percent excess air, in which case a CO CEMS shall be installed within 180 days. 

(i) The demonstration shall consist of continuously monitoring CO emissions for 30 days using 

an instrument that meets the requirements of Performance Specification 4 or 4A of appendix B to 

part 60. The span value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative accuracy 

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

instruments that are identical to Method 10 of appendix A-4 to part 60 and employ the sample 

conditioning system of Method 10A of appendix A-4 to part 60, the alternative relative accuracy 

test procedure in section 10.1 of Performance Specification 2 of appendix B to part 60 may be 

used in place of the relative accuracy test. 

(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. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) For a FCCU or FCU with no post-combustion control device, the temperature and O2 

concentration of the exhaust gas stream exiting the unit. 

(ii) For a FCCU or FCU with a post-combustion control device, the temperature and O2 

concentration of the exhaust gas stream exiting the control device. 

(i) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess 

emissions for a FCCU or FCU subject to the emissions limitations in §60.102a(b) are defined as 

specified in paragraphs (i)(1) through (6) of this section. Note: Determine all averages, except for 

opacity, as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 3-

hour average as the arithmetic average of three contiguous 1-hour averages. 

(1) If a CPMS is used according to §60.105a(b)(1), all 3-hour periods during which the average 

PM control device operating characteristics, as measured by the continuous monitoring systems 

under §60.105a(b)(1), fall below the levels established during the performance test. If the 

alternative to pressure drop CPMS is used for the owner or operator of a jet ejector type wet 

scrubber or other type of wet scrubber equipped with atomizing spray nozzles, each day in which 

abnormal pressure readings are not corrected within 12 hours of identification.

(2) If a bag leak detection system is used according to §60.105a(c), each day in which the cause 

of an alarm is not alleviated within the time period specified in §60.105a(c)(3). 

(3) If a PM CEMS is used according to §60.105a(d), all 7-day periods during which the average 

PM emission rate, as measured by the continuous PM monitoring system under §60.105a(d) 

exceeds 0.040 gr/dscf corrected to 0 percent excess air for a modified or reconstructed FCCU, 

0.020 gr/dscf corrected to 0 percent excess air for a newly constructed FCCU, or 0.040 gr/dscf 

for an affected fluid coking unit. 

(4) 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. 

(5) 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. 

(6) 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. 

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

continuous monitoring system under §60.105a(h) exceeds 500 ppmv or, if applicable, all 1-hour 

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

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

during the performance test. 

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

Deleted: 3

Deleted: 4

Deleted: 5

Deleted: 6

Deleted: 1A
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(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 value for the SO2 monitor is two times the applicable SO2 emission limit at the 

highest O2 concentration in the air/oxygen stream used in the Claus burner, if applicable. 

(ii) The owner or operator shall install, operate, and maintain each SO2 CEMS according to 

Performance Specification 2 of appendix B to part 60. 

(iii) The owner or operator shall conduct performance evaluations of each SO2 monitor 

according to the requirements in §60.13(c) and Performance Specification 2 of appendix B to 

part 60. The owner or operator shall use Methods 6 or 6C of appendix A-4 to part 60 and Method 

3 or 3A of appendix A-2 of part 60 for conducting the relative accuracy evaluations. The method 

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

see §60.17) is an acceptable alternative to EPA Method 6. 

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

Performance Specification 3 of appendix B to part 60. 

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

(vi) The owner or operator shall conduct performance evaluations for the O2 monitor according 

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

owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to part 60 for conducting the 

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

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

Method 3B of appendix A–2 to part 60. 

(vii) The owner or operator shall comply with the applicable quality assurance procedures of 

appendix F to part 60 for each monitor, including annual accuracy determinations for each O2 

monitor, and daily calibration drift determinations. 

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

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

(i) The span value for the reduced sulfur compounds monitor is two times the applicable reduced 

sulfur compounds emission limit as SO2 at the highest O2 concentration in the air/oxygen stream 

used in the Claus burner, if applicable. 

Deleted: s

Deleted: this

Deleted: are

Deleted: and between 10 and 25 percent

Deleted: , inclusive

Deleted: compound and H2S

Deleted: , H2S,

Deleted: s

Deleted: this

Deleted: are

Deleted: , two times the H2S emission limit, and 

between 10 and 25 percent

Deleted: , inclusive
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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

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

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

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

of appendix B to part 60. The owner or operator shall use Methods 15 or 15A of appendix A-5 to 

part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-

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

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

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

Performance Specification 3 of appendix B to part 60. 

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

(vi) The owner or operator shall conduct performance evaluations for the O2 monitor according 

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

owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the 

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

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

Method 3B of appendix A-2 to part 60. 

(vii) The owner or operator shall comply with the applicable quality assurance procedures of 

appendix F to part 60 for each monitor, including annual accuracy determinations for each O2 

monitor, and daily calibration drift determinations. 

(3) In place of the reduced sulfur compounds monitor required in paragraph (a)(2) of this section, 

the owner or operator may 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 reduced sulfur compounds 

emission limit as SO2 at the highest O2 concentration in the air/oxygen stream used in the Claus 

burner, if applicable. 

(ii) The owner or operator shall conduct performance evaluations of each SO2 monitor according 

to the requirements in §60.13(c) and Performance Specification 5 of appendix B to part 60. The 

owner or operator shall use Methods 15 or 15A of appendix A-5 to part 60 for conducting the 

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

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

Method 15A of appendix A-5 to part 60. 

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

Performance Specification 3 of appendix B to part 60. 

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

Deleted: (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.¶

Deleted: vi

Deleted: vii

Deleted: viii

Deleted: ix

Deleted: shall

Deleted: SO2 emission limit
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(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. 

(4) For sulfur recovery plants that are subject to the H2S emission limit in §60.102a(f)(1)(iii) or 

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

instrument for continuously monitoring and recording the concentration of H2S, and O2 

emissions into the atmosphere. The H2S emissions shall be calculated as SO2 (dry basis, zero 

percent excess air). 

(i) The span value for this monitor is two times the applicable H2S emission limit. 

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

Performance Specification 7 of appendix B to part 60. 

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

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

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

16 of appendix A–6 to part 60 for conducting the relative accuracy evaluations. The method 

ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—

see §60.17) is an acceptable alternative to EPA Method 15A of appendix A–5 to part 60. 

(iv) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. 

(v) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive. 

(vi) The owner or operator shall conduct performance evaluations for the O2 monitor according 

to the requirements of §60.13(c) and Performance Specification 3 of appendix B to part 60. The 

owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 3B of appendix A–2 to part 60. 

(vii) The owner or operator shall comply with the applicable quality assurance procedures of 

appendix F to part 60 for each monitor, including annual accuracy determinations for each O2 

monitor, and daily calibration drift determinations.. 

(5) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner and that 

elects to monitor O2 concentration of the air/oxygen mixture supplied to the Claus burner, the 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

owner or operator shall install, operate, calibrate, and maintain an instrument for continuously 

monitoring and recording the O2 concentration of the air/oxygen mixture supplied to the Claus 

burner in order to determine the allowable emissions limit. 

(i) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. 

(ii) The span value for the O2 monitor shall be 100 percent. 

(iii) The owner or operator shall conduct performance evaluations for the O2 monitor according 

to the requirements of §60.13(c) and Performance Specification 3 of appendix B to part 60. The 

owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 3B of appendix A–2 to part 60. 

(iv) The owner or operator shall comply with the applicable quality assurance procedures of 

appendix F to part 60 for each monitor, including annual accuracy determinations for each O2 

monitor, and daily calibration drift determinations. 

(v) The owner or operator shall use the hourly average O2 concentration from this monitor for 

use in Equation 1 or 2 of §60.102a(f), as applicable, for each hour and determine the allowable 

emission limit as the arithmetic average of 12 contiguous 1-hour averages (i.e., the rolling 12-

hour average). 

(6) As an alternative to the O2 monitor required in paragraph (a)(5) of this section, the owner or 

operator may install, calibrate, operate, and maintain a CPMS to measure and record the 

volumetric gas flow rate of ambient air and oxygen-enriched gas supplied to the Claus burner 

and calculate the hourly average O2 concentration of the air/oxygen mixture used in the Claus 

burner as specified in paragraphs (a)(6)(i) through (iv) of this section in order to determine the 

allowable emissions limit as specified in paragraphs (a)(6)(v) of this section. 

(i) The owner or operator shall install, calibrate, operate and maintain each flow monitor 

according to the manufacturer’s procedures and specifications and the following requirements. 

(A) The owner or operator shall install locate the monitor in a position that provides a 

representative measurement of the total gas flow rate. 

(B) Use a flow sensor with a measurement sensitivity of no more than 5 percent of the flow rate 

or 10 cubic feet per minute, whichever is greater. 

(C) Use a flow monitor that is maintainable online, is able to continuously correct for 

temperature, pressure and, for ambient air flow monitor, moisture content, and is able to record 

dry flow in standard conditions (as defined in §60.2) over one-minute averages. 

(D) At least quarterly, perform a visual inspection of all components of the monitor for physical 

and operational integrity and all electrical connections for oxidation and galvanic corrosion if the 

flow monitor is not equipped with a redundant flow sensor. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(E) Recalibrate the flow monitor in accordance with the manufacturer's procedures and 

specifications biennially (every two years) or at the frequency specified by the manufacturer.

(ii) The owner or operator shall use 20.9 percent as the oxygen content of the ambient air. 

(iii) The owner or operator shall use product specifications (e.g., as reported in material safety 

data sheets) for percent oxygen for purchased oxygen. For oxygen produced onsite, the percent 

oxygen shall be determined by periodic measurements or process knowledge. 

(iv) The owner or operator shall calculate the hourly average O2 concentration of the air/oxygen 

mixture used in the Claus burner using Equation 10 of this section 



















   

air oxy

air 2,oxy oxy

2 Q Q

Q %O Q %O20.9

 (Eq. 10) 

Where: 

%O2 = O2 concentration of the air/oxygen mixture used in the Claus burner, percent by volume 

(dry basis); 

20.9 = O2 concentration in air, percent dry basis; 

Qair = Volumetric flow rate of ambient air used in the Claus burner, dscfm; 

%O2,oxy = O2 concentration in the enriched oxygen stream, percent dry basis; and 

Qoxy = Volumetric flow rate of enriched oxygen stream used in the Claus burner, dscfm. 

(v) The owner or operator shall use the hourly average O2 concentration determined using 

Equation 8 of this section for use in Equation 1 or 2 of §60.102a(f), as applicable, for each hour 

and determine the allowable emission limit as the arithmetic average of 12 contiguous 1-hour 

averages (i.e., the rolling 12-hour average). 

(7) Owners or operators of a sulfur recovery plant that elects to comply with the SO2 emission 

limit in §60.102a(f)(1)(i) or §60.102a(f)(2)(i) or the reduced sulfur compounds emission limit in 

§60.102a(f)(1)(ii) or §60.102a(f)(2)(ii) as a flow rate weighted average for a group of release 

points from the sulfur recovery plant rather than for each process train or release point 

individually shall install, calibrate, operate, and maintain a CPMS to measure and record the 

volumetric gas flow rate of each release point within the group of release points from the sulfur 

recovery plant as specified in paragraphs (a)(7)(i) through (iv) of this section. 

(i) The owner or operator shall install, calibrate, operate and maintain each flow monitor 

according to the manufacturer’s procedures and specifications and the following requirements. 

(A) The owner or operator shall install locate the monitor in a position that provides a 

representative measurement of the total gas flow rate. 

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(B) Use a flow sensor with a measurement sensitivity of no more than 5 percent of the flow rate 

or 10 cubic feet per minute, whichever is greater. 

(C) Use a flow monitor that is maintainable online, is able to continuously correct for 

temperature, pressure, and moisture content, and is able to record dry flow in standard conditions 

(as defined in §60.2) over one-minute averages. 

(D) At least quarterly, perform a visual inspection of all components of the monitor for physical 

and operational integrity and all electrical connections for oxidation and galvanic corrosion if the 

flow monitor is not equipped with a redundant flow sensor. 

(E) Recalibrate the flow monitor in accordance with the manufacturer's procedures and 

specifications biennially (every two years) or at the frequency specified by the manufacturer.

(ii) The owner or operator shall correct the flow to 0 percent excess air using Equation 11 of this 

section: 

  

    c

2 adj meas

%O Q Q 20.920.9

 (Eq. 11) 

Where: 

Qadj = Volumetric flow rate adjusted to 0 percent excess air, dry standard cubic feet per minute 

(dscfm); 

Cmeas = Volumetric flow rate measured by the flow meter corrected to dry standard conditions, 

dscfm; 

20.9c = 20.9 percent O2−0.0 percent O2 (defined O2 correction basis), percent; 

20.9 = O2 concentration in air, percent; and 

%O2 = O2 concentration measured on a dry basis, percent. 

(iii) The owner or operator shall calculate the flow weighted average SO2 or reduced sulfur 

compounds concentration for each hour using Equation 12 of this section: 

 











 N

n

adj,n

N

n

n adj,n

ave

Q

C Q

C

1

1

 (Eq. 12) 

Where: 

Cave = Flow weighted average concentration of the pollutant, ppmv (dry basis, zero percent 

excess air). The pollutant is either SO2 [if complying with the SO2 emission limit in 

Field Code Changed

Field Code Changed
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§60.102a(f)(1)(i) or §60.102a(f)(2)(i)] or reduced sulfur compounds [if complying with the 

reduced sulfur compounds emission limit in §60.102a(f)(1)(ii) or §60.102a(f)(2)(ii)]; 

N = Number of release points within the group of release points from the sulfur recovery plant 

for which emissions averaging is elected; 

Cn = Pollutant concentration in the nth release point within the group of release points from the 

sulfur recovery plant for which emissions averaging is elected, ppmv (dry basis, zero percent 

excess air); 

Qadj,n = Volumetric flow rate of the nth release point within the group of release points from the 

sulfur recovery plant for which emissions averaging is elected, dry standard cubic feet per 

minute (dscfm, adjusted to 0 percent excess air). 

(iv) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner, the 

owner or operator shall use Equation 10 of this section and the hourly emission limits determined 

in paragraphs (a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant concentration to 

determine the flow weighted average hourly emission limit for each hour. The allowable 

emission limit shall be calculated as the arithmetic average of 12 contiguous 1-hour averages 

(i.e., the rolling 12-hour average). 

(b) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess 

emissions for sulfur recovery plants subject to the emissions limitations in §60.102a(f) are 

defined as specified in paragraphs (b)(1) through (3) of this section. Note: Determine all 

averages as the arithmetic average of the applicable 1-hour averages, e.g., determine the rolling 

12-hour average as the arithmetic average of 12 contiguous 1-hour averages. 

(1) All 12-hour periods during which the average concentration of SO2 as measured by the SO2 

continuous monitoring system required under paragraph (a)(1) of this section exceeds the 

applicable emission limit (dry basis, zero percent excess air); or 

(2) All 12-hour periods during which the average concentration of reduced sulfur compounds (as 

SO2) as measured by the reduced sulfur compounds continuous monitoring system required 

under paragraph (a)(2) or (a)(3) of this section exceeds the applicable emission limit; or 

(3) All 12-hour periods during which the average concentration of H2S as measured by the H2S 

continuous monitoring system required under paragraph (a)(4) of this section exceeds the 

applicable emission limit (dry basis, 0 percent excess air). 

§ 60.107a Monitoring of emissions and operations for fuel gas combustion devices and flares. 

(a) Fuel gas combustion devices subject to SO2 or H2S limit and flares subject to H2S 

concentration requirements. The owner or operator of a fuel gas combustion device that is 

subject to §60.102a(g)(1) and elects to comply with the SO2 emission limits in §60.102a(g)(1)(i) 

shall comply with the requirements in paragraph (a)(1) of this section. The owner or operator of 

a fuel gas combustion device that is subject to §60.102a(g)(1) and elects to comply with the H2S 

concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration 

requirement in §60.103a(h) shall comply with paragraph (a)(2) of this section. 

Deleted: 2
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) The owner or operator of a fuel gas combustion device that elects to comply with the SO2 

emissions limits in §60.102a(g)(1)(i) shall install, operate, calibrate and maintain an instrument 

for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of 

SO2 emissions into the atmosphere. The monitor must include an O2 monitor for correcting the 

data for excess air. 

(i) The owner or operator shall install, operate, and maintain each SO2 monitor according to 

Performance Specification 2 of appendix B to part 60. The span value for the SO2 monitor is 50 

ppmv SO2. 

(ii) The owner or operator shall conduct performance evaluations for the SO2 monitor according 

to the requirements of §60.13(c) and Performance Specification 2 of appendix B to part 60. The 

owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 6 or 6A of appendix A-4 to part 60. Samples taken by Method 6 of appendix A-4 to part 

60 shall be taken at a flow rate of approximately 2 liters/min for at least 30 minutes. The relative 

accuracy limit shall be 20 percent or 4 ppmv, whichever is greater, and the calibration drift limit 

shall be 5 percent of the established span value. 

(iii) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value for the O2 monitor must 

be selected between 10 and 25 percent, inclusive. 

(iv) The owner or operator shall conduct performance evaluations for the O2 monitor according 

to the requirements of §60.13(c) and Performance Specification 3 of appendix B to part 60. The 

owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to part 60 for conducting the 

relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust 

Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA 

Method 3B of appendix A-2 to part 60. 

(v) The owner or operator shall comply with the applicable quality assurance procedures in 

appendix F to part 60, including quarterly accuracy determinations for SO2 monitors, annual 

accuracy determinations for O2 monitors, and daily calibration drift tests. 

(vi) Fuel gas combustion devices having a common source of fuel gas may be monitored at only 

one location (i.e., after one of the combustion devices), if monitoring at this location accurately 

represents the SO2 emissions into the atmosphere from each of the combustion devices. 

(2) The owner or operator of a fuel gas combustion device that elects to comply with the H2S 

concentration limits in §60.102a(g)(1)(ii) or a flare that is subject to the H2S concentration 

requirement in §60.103a(h) shall install, operate, calibrate and maintain an instrument for 

continuously monitoring and recording the concentration by volume (dry basis) of H2S in the 

fuel gases before being burned in any fuel gas combustion device or flare. 

(i) The owner or operator shall install, operate and maintain each H2S monitor according to 

Performance Specification 7 of Appendix B to part 60. The span value for this instrument is 300 

ppmv H2S. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) The owner or operator shall conduct performance evaluations for each H2S monitor 

according to the requirements of §60.13(c) and Performance Specification 7 of appendix B to 

part 60. The owner or operator shall use Method 11, 15, or 15A of appendix A-5 to part 60 or 

Method 16 of appendix A-6 to part 60 for conducting the relative accuracy evaluations. The 

method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by 

reference—see §60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 

60. 

(iii) The owner or operator shall comply with the applicable quality assurance procedures in 

appendix F to part 60 for each H2S monitor. 

(iv) Fuel gas combustion devices or flares having a common source of fuel gas may be 

monitored at only one location, if monitoring at this location accurately represents the 

concentration of H2S in the fuel gas being burned in the respective fuel gas combustion devices 

or flares. 

(v) The owner or operator of a flare subject to §60.103a(c) through (e) may use the instrument 

required in paragraph (e)(1) of this section to demonstrate compliance with the H2S 

concentration requirement in §60.103a(h) if the owner or operator complies with the 

requirements of paragraph (e)(1)(i) through (iv) and if the instrument has a span (or dual span, if 

necessary) capable of accurately measuring concentrations between 20 and 300 ppmv. If the 

instrument required in paragraph (e)(1) of this section is used to demonstrate compliance with 

the H2S concentration requirement, the concentration directly measured by the instrument must 

meet the numeric concentration in §60.103a(h). 

(vi) The owner or operator of modified flare that meets all three criteria in paragraphs 

(a)(2)(vi)(A) through (C) of this section shall comply with the requirements of paragraphs 

(a)(2)(i) through (v) of this section no later than November 11, 2015. The owner or operator shall 

comply with the approved alternative monitoring plan or plans pursuant to §60.13(i) until the 

flare is in compliance with requirements of paragraphs (a)(2)(i) through (v) of this section. 

(A) The flare was an affected facility subject to subpart J of this part prior to becoming an 

affected facility under §60.100a. 

(B) The owner or operator had an approved alternative monitoring plan or plans pursuant to 

§60.13(i) for all fuel gases combusted in the flare. 

(C) The flare did not have in place on or before September 12, 2012 an instrument for 

continuously monitoring and recording the concentration by volume (dry basis) of H2S in the 

fuel gases that is capable of complying with the requirements of paragraphs (a)(2)(i) through (v) 

of this section. 

(3) The owner or operator of a fuel gas combustion device or flare is not required to comply with 

paragraph (a)(1) or (2) of this section for fuel gas streams that are exempt under 

§§60.102a(g)(1)(iii) or 60.103a(h) or, for fuel gas streams combusted in a process heater, other 

fuel gas combustion device or flare that are inherently low in sulfur content. Fuel gas streams 

meeting one of the requirements in paragraphs (a)(3)(i) through (iv) of this section will be 

considered inherently low in sulfur content. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) Pilot gas for heaters and flares. 

(ii) Fuel gas streams that meet a commercial-grade product specification for sulfur content of 30 

ppmv or less. In the case of a liquefied petroleum gas (LPG) product specification in the 

pressurized liquid state, the gas phase sulfur content should be evaluated assuming complete 

vaporization of the LPG and sulfur containing-compounds at the product specification 

concentration. 

(iii) Fuel gas streams produced in process units that are intolerant to sulfur contamination, such 

as fuel gas streams produced in the hydrogen plant, catalytic reforming unit, isomerization unit, 

and HF alkylation process units. 

(iv) Other fuel gas streams that an owner or operator demonstrates are low-sulfur according to 

the procedures in paragraph (b) of this section. 

(4) If the composition of an exempt fuel gas stream changes, the owner or operator must follow 

the procedures in paragraph (b)(3) of this section. 

(b) Exemption from H2S monitoring requirements for low-sulfur fuel gas streams. The owner or 

operator of a fuel gas combustion device or flare may apply for an exemption from the H2S 

monitoring requirements in paragraph (a)(2) of this section for a fuel gas stream that is inherently 

low in sulfur content. A fuel gas stream that is demonstrated to be low-sulfur is exempt from the 

monitoring requirements of paragraphs (a)(1) and (2) of this section until there are changes in 

operating conditions or stream composition. 

(1) The owner or operator shall submit to the Administrator a written application for an 

exemption from monitoring. The application must contain the following information: 

(i) A description of the fuel gas stream/system to be considered, including submission of a 

portion of the appropriate piping diagrams indicating the boundaries of the fuel gas 

stream/system and the affected fuel gas combustion device(s) or flare(s) to be considered; 

(ii) A statement that there are no crossover or entry points for sour gas (high H2S content) to be 

introduced into the fuel gas stream/system (this should be shown in the piping diagrams); 

(iii) An explanation of the conditions that ensure low amounts of sulfur in the fuel gas stream 

(i.e., control equipment or product specifications) at all times; 

(iv) The supporting test results from sampling the requested fuel gas stream/system 

demonstrating that the sulfur content is less than 5 ppmv H2S. Sampling data must include, at 

minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas 

streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be 

collected unless other additional information would support reduced sampling. The owner or 

operator shall use detector tubes (“length-of-stain tube” type measurement) following the “Gas 

Processors Association Standard 2377-86, Test for Hydrogen Sulfide and Carbon Dioxide in 

Natural Gas Using Length of Stain Tubes,” 1986 Revision (incorporated by reference—see 

§60.17), using tubes with a maximum span between 10 and 40 ppmv inclusive when 1≤N≤10, 

where N = number of pump strokes, to test the applicant fuel gas stream for H2S; and 

Deleted: with ranges 0-10/0-100 ppm (N = 10/1)
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(v) A description of how the 2 weeks (or seven samples for infrequently operated fuel gas 

streams/systems) of monitoring results compares to the typical range of H2S concentration (fuel 

quality) expected for the fuel gas stream/system going to the affected fuel gas combustion device 

or flare (e.g., the 2 weeks of daily detector tube results for a frequently operated loading rack 

included the entire range of products loaded out and, therefore, should be representative of 

typical operating conditions affecting H2S content in the fuel gas stream going to the loading 

rack flare). 

(2) The effective date of the exemption is the date of submission of the information required in 

paragraph (b)(1) of this section. 

(3) No further action is required unless refinery operating conditions change in such a way that 

affects the exempt fuel gas stream/system (e.g., the stream composition changes). If such a 

change occurs, the owner or operator shall follow the procedures in paragraph (b)(3)(i), 

(b)(3)(ii), or (b)(3)(iii) of this section. 

(i) If the operation change results in a sulfur content that is still within the range of 

concentrations included in the original application, the owner or operator shall conduct an H2S 

test on a grab sample and record the results as proof that the concentration is still within the 

range. 

(ii) If the operation change results in a sulfur content that is outside the range of concentrations 

included in the original application, the owner or operator may submit new information 

following the procedures of paragraph (b)(1) of this section within 60 days (or within 30 days 

after the seventh grab sample is tested for infrequently operated process units). 

(iii) If the operation change results in a sulfur content that is outside the range of concentrations 

included in the original application and the owner or operator chooses not to submit new 

information to support an exemption, the owner or operator must begin H2S monitoring using 

daily stain sampling to demonstrate compliance using length-of-stain tubes with a maximum 

span between 200 and 400 ppmv inclusive when 1≤N≤5, where N = number of pump strokes. 

The owner or operator must begin monitoring according to the requirements in paragraphs (a)(1) 

or (a)(2) of this section as soon as practicable, but in no case later than 180 days after the 

operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv is an 

exceedance of the 3-hour H2S concentration limit. The owner or operator of a fuel gas 

combustion device must also determine a rolling 365-day average using the stain sampling 

results; an average H2S concentration of 5 ppmv must be used for days within the rolling 365-

day period prior to the operation change. 

(c) Process heaters complying with the NOX concentration-based limit. The owner or operator of 

a process heater subject to the NOX emissions limit in §60.102a(g)(2) and electing to comply 

with the applicable emissions limit in §60.102a(g)(2)(i)(A), (g)(2)(ii)(A), (g)(2)(iii)(A) or 

(g)(2)(iv)(A) shall install, operate, calibrate and maintain an instrument for continuously 

monitoring and recording the concentration (dry basis, 0-percent excess air) of NOX emissions 

into the atmosphere according to the requirements in paragraphs (c)(1) through (5) of this 

section, except as provided in paragraph (c)(6) of this section. The monitor must include an O2 

monitor for correcting the data for excess air. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Except as provided in paragraph (c)(6) of this section, the owner or operator shall install, 

operate and maintain each NOX monitor according to Performance Specification 2 of Appendix 

B to part 60. The span value of this NOX monitor must be between 2 and 3 times the applicable 

emissions limit, inclusive. 

(2) The owner or operator shall conduct performance evaluations of each NOX monitor 

according to the requirements in §60.13(c) and Performance Specification 2 of appendix B to 

part 60. The owner or operator shall use Methods 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 

60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, 

“Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable 

alternative to EPA Method 7 or 7C of appendix A-4 to part 60. 

(3) The owner or operator shall install, operate, and maintain each O2 monitor according to 

Performance Specification 3 of appendix B to part 60. The span value of this O2 monitor must be 

selected between 10 and 25 percent, inclusive. 

(4) The owner or operator shall conduct performance evaluations of each O2 monitor according 

to the requirements in §60.13(c) and Performance Specification 3 of appendix B to part 60. 

Method 3, 3A, or 3B of appendix A-2 to part 60 shall be used for conducting the relative 

accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas 

Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 

3B of appendix A-2 to part 60. 

(5) The owner or operator shall comply with the quality assurance requirements in Procedure 1 

of appendix F to part 60 for each NOX and O2 monitor, including quarterly accuracy 

determinations for NOX monitors, annual accuracy determinations for O2 monitors, and daily 

calibration drift tests. 

(6) The owner or operator of a process heater that has a rated heating capacity of less than 100 

MMBtu and is equipped with combustion modification-based technology to reduce NOX 

emissions (i.e., low-NOX burners, ultra-low-NOX burners) may elect to comply with the 

monitoring requirements in paragraphs (c)(1) through (5) of this section or, alternatively, the 

owner or operator of such a process heater shall conduct biennial performance tests according to 

the requirements in §60.104a(i), establish a maximum excess O2 operating limit or operating 

curve according to the requirements in §60.104a(i)(6) and comply with the O2 monitoring 

requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O2 

operating curve is used (i.e., if different O2 operating limits are established for different 

operating ranges), the owner or operator of the process heater must also monitor fuel gas flow 

rate, fuel oil flow rate (as applicable) and heating value content according to the methods 

provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section, respectively. 

(d) Process heaters complying with the NOX heating value-based or mass-based limit. The 

owner or operator of a process heater subject to the NOX emissions limit in §60.102a(g)(2) and 

electing to comply with the applicable emissions limit in §60.102a(g)(2)(i)(B) or (g)(2)(ii)(B) 

shall install, operate, calibrate and maintain an instrument for continuously monitoring and 

recording the concentration (dry basis, 0-percent excess air) of NOX emissions into the 

atmosphere and shall determine the F factor of the fuel gas stream no less frequently than once 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

per day according to the monitoring requirements in paragraphs (d)(1) through (4) of this section. 

The owner or operator of a co-fired process heater subject to the NOX emissions limit in 

§60.102a(g)(2) and electing to comply with the heating value-based limit in 

§60.102a(g)(2)(iii)(B) or (g)(2)(iv)(B) shall install, operate, calibrate and maintain an instrument 

for continuously monitoring and recording the concentration (dry basis, 0-percent excess air) of 

NOX emissions into the atmosphere according to the monitoring requirements in paragraph 

(d)(1) of this section; install, operate, calibrate and maintain an instrument for continuously 

monitoring and recording the flow rate of the fuel gas and fuel oil fed to the process heater 

according to the monitoring requirements in paragraph (d)(5) and (6) of this section; for fuel gas 

streams, determine gas composition according to the requirements in paragraph (d)(4) of this 

section or the higher heating value according to the requirements in paragraph (d)(7) of this 

section; and for fuel oil streams, determine the heating value according to the monitoring 

requirements in paragraph (d)(7) of this section. 

(1) Except as provided in paragraph (d)(8) of this section, the owner or operator shall install, 

operate and maintain each NOX monitor according to the requirements in paragraphs (c)(1) 

through (5) of this section. The monitor must include an O2 monitor for correcting the data for 

excess air. 

(2) Except as provided in paragraph (d)(3) of this section, the owner or operator shall sample and 

analyze each fuel stream fed to the process heater using the methods and equations in section 

12.3.2 of EPA Method 19 of Appendix A-7 to part 60 to determine the F factor on a dry basis. If 

a single fuel gas system provides fuel gas to several process heaters, the F factor may be 

determined at a single location in the fuel gas system provided it is representative of the fuel gas 

fed to the affected process heater(s). 

(3) As an alternative to the requirements in paragraph (d)(2) of this section, the owner or 

operator of a gas-fired process heater shall install, operate and maintain a gas composition 

analyzer and determine the average F factor of the fuel gas using the factors in Table 1 of this 

subpart and Equation 13 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. 13) 

Where: 

Fd = F factor on dry basis at 0-percent excess air, dscf/MMBtu. 

Xi = mole or volume fraction of each component in the fuel gas. 

MEVi = molar exhaust volume, dry standard cubic feet per mole (dscf/mol). 

MHCi = molar heat content, Btu per mole (Btu/mol). 

1,000,000 = unit conversion, Btu per MMBtu. 

Deleted: 10

Deleted: 10
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) The owner or operator shall conduct performance evaluations of each compositional monitor 

according to the requirements in Performance Specification 9 of Appendix B to part 60. Any of 

the following methods shall be used for conducting the relative accuracy evaluations: 

(i) EPA Method 18 of Appendix A-6 to part 60; 

(ii) ASTM D1945-03 (Reapproved 2010)(incorporated by reference-see §60.17); 

(iii) ASTM D1946-90 (Reapproved 2006)(incorporated by reference-see §60.17); 

(iv) ASTM D6420-99 (Reapproved 2004)(incorporated by reference-see §60.17); 

(v) GPA 2261-00 (incorporated by reference-see §60.17); or 

(vi) ASTM UOP539-97 (incorporated by reference-see §60.17). 

(5) The owner or operator shall install, operate and maintain fuel gas flow monitors according to 

the manufacturer's recommendations. For volumetric flow meters, temperature and pressure 

monitors must be installed in conjunction with the flow meter or in a representative location to 

correct the measured flow to standard conditions (i.e., 68 °F and 1 atmosphere). For mass flow 

meters, use gas compositions determined according to paragraph (d)(4) of this section to 

determine the average molecular weight of the fuel gas and convert the mass flow to a 

volumetric flow at standard conditions (i.e., 68 °F and 1 atmosphere). The owner or operator 

shall conduct performance evaluations of each fuel gas flow monitor according to the 

requirements in §60.13 and Performance Specification 6 of Appendix B to part 60. Any of the 

following methods shall be used for conducting the relative accuracy evaluations: 

(i) EPA Method 2, 2A, 2B, 2C or 2D of Appendix A-2 to part 60; 

(ii) ASME MFC-3M-2004 (incorporated by reference-see §60.17); 

(iii) ANSI/ASME MFC-4M-1986 (Reaffirmed 2008) (incorporated by reference-see §60.17); 

(iv) ASME MFC-6M-1998 (Reaffirmed 2005) (incorporated by reference-see §60.17); 

(v) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006) (incorporated by reference-see §60.17); 

(vi) ASME MFC-11M-2006 (incorporated by reference-see §60.17); 

(vii) ASME MFC-14M-2003 (incorporated by reference-see §60.17); 

(viii) ASME MFC-18M-2001 (incorporated by reference-see §60.17); 

(ix) AGA Report No. 3, Part 1 (incorporated by reference-see §60.17); 

(x) AGA Report No. 3, Part 2 (incorporated by reference-see §60.17); 

(xi) AGA Report No. 11 (incorporated by reference-see §60.17); 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(xii) AGA Report No. 7 (incorporated by reference-see §60.17); and 

(xiii) API Manual of Petroleum Measurement Standards, Chapter 22, Section 2 (incorporated by 

reference-see §60.17). 

(6) The owner or operator shall install, operate and maintain each fuel oil flow monitor according 

to the manufacturer's recommendations. The owner or operator shall conduct performance 

evaluations of each fuel oil flow monitor according to the requirements in §60.13 and 

Performance Specification 6 of Appendix B to part 60. Any of the following methods shall be 

used for conducting the relative accuracy evaluations: 

(i) Any one of the methods listed in paragraph (d)(5) of this section that are applicable to fuel oil 

( i.e., “fluids”); 

(ii) ANSI/ASME-MFC-5M-1985 (Reaffirmed 2006) (incorporated by reference-see §60.17); 

(iii) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006) (incorporated by reference-see §60.17); 

(iv) ASME MFC-16-2007 (incorporated by reference-see §60.17); 

(v) ASME MFC-22-2007 (incorporated by reference-see §60.17); or 

(vi) ISO 8316 (incorporated by reference-see §60.17). 

(7) The owner or operator shall determine the higher heating value of each fuel fed to the process 

heater using any of the applicable methods included in paragraphs (d)(7)(i) through (ix) of this 

section. If a common fuel supply system provides fuel gas or fuel oil to several process heaters, 

the higher heating value of the fuel in each fuel supply system may be determined at a single 

location in the fuel supply system provided it is representative of the fuel fed to the affected 

process heater(s). The higher heating value of each fuel fed to the process heater must be 

determined no less frequently than once per day except as provided in paragraph (d)(7)(x) of this 

section. 

(i) ASTM D240-02 (Reapproved 2007) (incorporated by reference-see §60.17). 

(ii) ASTM D1826-94 (Reapproved 2003) (incorporated by reference-see §60.17). 

(iii) ASTM D1945-03 (Reapproved 2010) (incorporated by reference-see §60.17). 

(iv) ASTM D1946-90 (Reapproved 2006) (incorporated by reference-see §60.17). 

(v) ASTM D3588-98 (Reapproved 2003) (incorporated by reference-see §60.17). 

(vi) ASTM D4809-06 (incorporated by reference-see §60.17). 

(vii) ASTM D4891-89 (Reapproved 2006) (incorporated by reference-see §60.17). 

(viii) GPA 2172-09 (incorporated by reference-see §60.17). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ix) Any of the methods specified in section 2.2.7 of Appendix D to part 75. 

(x) If the fuel oil supplied to the affected co-fired process heater originates from a single storage 

tank, the owner or operator may elect to use the storage tank sampling method in section 2.2.4.2 

of Appendix D to part 75 instead of daily sampling, except that the most recent value for heating 

content must be used. 

(8) The owner or operator of a process heater that has a rated heating capacity of less than 100 

MMBtu and is equipped with combustion modification based technology to reduce NOX 

emissions (i.e., low-NOX burners or ultra-low NOX burners) may elect to comply with the 

monitoring requirements in paragraphs (d)(1) through (7) of this section or, alternatively, the 

owner or operator of such a process heater shall conduct biennial performance tests according to 

the requirements in §60.104a(i), establish a maximum excess O2 operating limit or operating 

curve according to the requirements in §60.104a(i)(6) and comply with the O2 monitoring 

requirements in paragraphs (c)(3) through (5) of this section to demonstrate compliance. If an O2 

operating curve is used (i.e., if different O2 operating limits are established for different 

operating ranges), the owner or operator of the process heater must also monitor fuel gas flow 

rate, fuel oil flow rate (as applicable) and heating value content according to the methods 

provided in paragraphs (d)(5), (d)(6), and (d)(4) or (d)(7) of this section, respectively. 

(e) Sulfur monitoring for assessing root cause analysis threshold for affected flares. Except as 

described in paragraphs (e)(4) and (h) of this section, the owner or operator of an affected flare 

subject to §60.103a(c) through (e) shall determine the total reduced sulfur concentration for each 

gas line directed to the affected flare in accordance with either paragraph (e)(1), (e)(2) or (e)(3) 

of this section. Different options may be elected for different gas lines. If a monitoring system is 

in place that is capable of complying with the requirements related to either paragraph (e)(1), 

(e)(2) or (e)(3) of this section, the owner or operator of a modified flare must comply with the 

requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section upon startup of the 

modified flare. If a monitoring system is not in place that is capable of complying with the 

requirements related to either paragraph (e)(1), (e)(2) or (e)(3) of this section, the owner or 

operator of a modified flare must comply with the requirements related to either paragraph 

(e)(1), (e)(2) or (e)(3) of this section no later than November 11, 2015 or upon startup of the 

modified flare, whichever is later. 

(1) Total reduced sulfur monitoring requirements. The owner or operator shall install, operate, 

calibrate and maintain an instrument or instruments for continuously monitoring and recording 

the concentration of total reduced sulfur in gas discharged to the flare. 

(i) The owner or operator shall install, operate and maintain each total reduced sulfur monitor 

according to Performance Specification 5 of Appendix B to part 60. The span value should be 

determined based on the maximum sulfur content of gas that can be discharged to the flare (e.g., 

roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 

5,000 ppmv. A single dual range monitor may be used to comply with the requirements of this 

paragraph and paragraph (a)(2) of this section provided the applicable span specifications are 

met. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) The owner or operator shall conduct performance evaluations of each total reduced sulfur 

monitor according to the requirements in §60.13(c) and Performance Specification 5 of 

Appendix B to part 60. The owner or operator of each total reduced sulfur monitor shall use EPA 

Method 15A of Appendix A-5 to part 60 for conducting the relative accuracy evaluations. The 

method ANSI/ASME PTC 19.10-1981 (incorporated by reference-see §60.17) is an acceptable 

alternative to EPA Method 15A of Appendix A-5 to part 60. The alternative relative accuracy 

procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 

(cylinder gas audits) may be used for conducting the relative accuracy evaluations, except that it 

is not necessary to include as much of the sampling probe or sampling line as practical. 

(iii) The owner or operator shall comply with the applicable quality assurance procedures in 

Appendix F to part 60 for each total reduced sulfur monitor. 

(2) H2S monitoring requirements. The owner or operator shall install, operate, calibrate, and 

maintain an instrument or instruments for continuously monitoring and recording the 

concentration of H2S in gas discharged to the flare according to the requirements in paragraphs 

(e)(2)(i) through (iii) of this section and shall collect and analyze samples of the gas and 

calculate total sulfur concentrations as specified in paragraphs (e)(2)(iv) through (ix) of this 

section. 

(i) The owner or operator shall install, operate and maintain each H2S monitor according to 

Performance Specification 7 of Appendix B to part 60. The span value should be determined 

based on the maximum sulfur content of gas that can be discharged to the flare (e.g., roughly 1.1 

to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv. 

A single dual range H2S monitor may be used to comply with the requirements of this paragraph 

and paragraph (a)(2) of this section provided the applicable span specifications are met. 

(ii) The owner or operator shall conduct performance evaluations of each H2S monitor according 

to the requirements in §60.13(c) and Performance Specification 7 of Appendix B to part 60. The 

owner or operator shall use EPA Method 11, 15 or 15A of Appendix A-5 to part 60 for 

conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 

(incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 15A of 

Appendix A-5 to part 60. The alternative relative accuracy procedures described in section 16.0 

of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for 

conducting the relative accuracy evaluations, except that it is not necessary to include as much of 

the sampling probe or sampling line as practical. 

(iii) The owner or operator shall comply with the applicable quality assurance procedures in 

Appendix F to part 60 for each H2S monitor. 

(iv) In the first 10 operating days after the date the flare must begin to comply with 

§60.103a(c)(1), the owner or operator shall collect representative daily samples of the gas 

discharged to the flare. The samples may be grab samples or integrated samples. The owner or 

operator shall take subsequent representative daily samples at least once per week or as required 

in paragraph (e)(2)(ix) of this section. 

Deleted: For flares that routinely have flow, the

Deleted: . For flares that do not receive routine 

flow, the alternative relative accuracy procedures 

described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 (cylinder 

gas audits) may be used for conducting the relative 

accuracy evaluations

Deleted: For flares that routinely have flow, t

Deleted: . For flares that do not receive routine 

flow, the alternative relative accuracy procedures 

described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 (cylinder 

gas audits) may be used for conducting the relative 

accuracy evaluations
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(v) The owner or operator shall analyze each daily sample for total sulfur using either EPA 

Method 15A of Appendix A-5 to part 60, EPA Method 16A of Appendix A-6 to part 60, ASTM 

Method D4468-85 (Reapproved 2006) (incorporated by reference—see §60.17) or ASTM 

Method D5504-08 (incorporated by reference—see §60.17). 

(vi) The owner or operator shall develop a 10-day average total sulfur-to-H2S ratio and 95-

percent confidence interval as follows: 

(A) Calculate the ratio of the total sulfur concentration to the H2S concentration for each day 

during which samples are collected. 

(B) Determine the 10-day average total sulfur-to-H2S ratio as the arithmetic average of the daily 

ratios calculated in paragraph (e)(2)(vi)(A) of this section. 

(C) Determine the acceptable range for subsequent weekly samples based on the 95-percent 

confidence interval for the distribution of daily ratios based on the 10 individual daily ratios 

using Equation 14 of this section. 

AR Ratio SDev  Avg  2.262 (Eq. 14) 

Where: 

AR = Acceptable range of subsequent ratio determinations, unitless. 

RatioAvg = 10-day average total sulfur-to-H2S concentration ratio, unitless. 

2.262 = t-distribution statistic for 95-percent 2-sided confidence interval for 10 samples (9 

degrees of freedom). 

SDev = Standard deviation of the 10 daily average total sulfur-to-H2S concentration ratios used 

to develop the 10-day average total sulfur-to-H2S concentration ratio, unitless. 

(vii) For each day during the period when data are being collected to develop a 10-day average, 

the owner or operator shall estimate the total sulfur concentration using the measured total sulfur 

concentration measured for that day. 

(viii) For all days other than those during which data are being collected to develop a 10-day 

average, the owner or operator shall multiply the most recent 10-day average total sulfur-to-H2S 

ratio by the daily average H2S concentrations obtained using the monitor as required by 

paragraph (e)(2)(i) through (iii) of this section to estimate total sulfur concentrations. 

(ix) If the total sulfur-to-H2S ratio for a subsequent weekly sample is outside the acceptable 

range for the most recent distribution of daily ratios, the owner or operator shall develop a new 

10-day average ratio and acceptable range based on data for the outlying weekly sample plus 

data collected over the following 9 operating days. 

(3) SO2 monitoring requirements. The owner or operator shall install, operate, calibrate and 

maintain an instrument for continuously monitoring and recording the concentration of SO2 from 

Deleted: 11

Deleted: 11
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

a process heater or other fuel gas combustion device that is combusting gas representative of the 

fuel gas in the flare gas line according to the requirements in paragraph (a)(1) of this section, 

determine the F factor of the fuel gas at least daily according to the requirements in paragraphs 

(d)(2) through (4) of this section, determine the higher heating value of the fuel gas at least daily 

according to the requirements in paragraph (d)(7) of this section and calculate the total sulfur 

content (as SO2 ) in the fuel gas using Equation 15 of this section. 

TSFG  CSO2  Fd  HHVFG (Eq. 15) 

Where: 

TSFG = Total sulfur concentration, as SO2, in the fuel gas, ppmv. 

CSO2 = Concentration of SO2 in the exhaust gas, ppmv (dry basis at 0-percent excess air). 

Fd = F factor gas on dry basis at 0-percent excess air, dscf/MMBtu. 

HHVFG = Higher heating value of the fuel gas, MMBtu/scf. 

(4) Exemptions from sulfur monitoring requirements. Flares identified in paragraphs (e)(4)(i) 

through (iv) of this section are exempt from the requirements in paragraphs (e)(1) through (3) of 

this section. For each such flare, except as provided in paragraph (e)(4)(iv), engineering 

calculations shall be used to calculate the SO2 emissions in the event of a discharge that may 

trigger a root cause analysis under §60.103a(c)(1). 

(i) Flares that can only receive: 

(A) Fuel gas streams that are inherently low in sulfur content as described in paragraph (a)(3)(i) 

through (iv) of this section; and/or 

(B) Fuel gas streams that are inherently low in sulfur content for which the owner or operator has 

applied for an exemption from the H2S monitoring requirements as described in paragraph (b) of 

this section. 

(ii) Emergency flares, provided that for each such flare, the owner or operator complies with the 

monitoring alternative in paragraph (g) of this section. 

(iii) Flares equipped with flare gas recovery systems designed, sized and operated to capture all 

flows except those resulting from startup, shutdown or malfunction, provided that for each such 

flare, the owner or operator complies with the monitoring alternative in paragraph (g) of this 

section. 

(iv) Secondary flares that receive gas diverted from the primary flare. In the event of a discharge 

from the secondary flare, the sulfur content measured by the sulfur monitor on the primary flare 

should be used to calculate SO2 emissions, regardless of whether or not the monitoring 

alternative in paragraph (g) of this section is selected for the secondary flare. 

Deleted: 12

Deleted: 12
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(f) Flow monitoring for flares. Except as provided in paragraphs (f)(2) and (h) of this section, the 

owner or operator of an affected flare subject to §60.103a(c) through (e) shall install, operate, 

calibrate and maintain, in accordance with the specifications in paragraph (f)(1) of this section, a 

CPMS to measure and record the flow rate of gas discharged to the flare. If a flow monitor is not 

already in place, the owner or operator of a modified flare shall comply with the requirements of 

this paragraph by no later than November 11, 2015 or upon startup of the modified flare, 

whichever is later. 

(1) The owner or operator shall install, calibrate, operate and maintain each flow monitor 

according to the manufacturer's procedures and specifications and the following requirements. 

(i) Locate the monitor in a position that provides a representative measurement of the total gas 

flow rate. 

(ii) Use a flow sensor with a measurement sensitivity of no more than 5 percent of the flow rate 

or 10 cubic feet per minute, whichever is greater. 

(iii) Use a flow monitor that is maintainable online, is able to continuously correct for 

temperature and pressure and is able to record flow in standard conditions (as defined in §60.2) 

over one-minute averages. 

(iv) At least quarterly, perform a visual inspection of all components of the monitor for physical 

and operational integrity and all electrical connections for oxidation and galvanic corrosion if the 

flow monitor is not equipped with a redundant flow sensor. 

(v) Recalibrate the flow monitor in accordance with the manufacturer's procedures and 

specifications biennially (every two years) or at the frequency specified by the manufacturer. 

(2) Emergency flares, secondary flares and flares equipped with flare gas recovery systems 

designed, sized and operated to capture all flows except those resulting from startup, shutdown 

or malfunction are not required to install continuous flow monitors; provided, however, that for 

any such flare, the owner or operator shall comply with the monitoring alternative in paragraph 

(g) of this section. 

(g) Alternative monitoring for certain flares equipped with water seals. The owner or operator of 

an affected flare subject to §60.103a(c) through (e) that can be classified as either an emergency 

flare, a secondary flare or a flare equipped with a flare gas recovery system designed, sized and 

operated to capture all flows except those resulting from startup, shutdown or malfunction may, 

as an alternative to the sulfur and flow monitoring requirements of paragraphs (e) and (f) of this 

section, install, operate, calibrate and maintain, in accordance with the requirements in 

paragraphs (g)(1) through (7) of this section, a CPMS to measure and record the pressure in the 

flare gas header between the knock-out pot and water seal and to measure and record the water 

seal liquid level. If the required monitoring systems are not already in place, the owner or 

operator of a modified flare shall comply with the requirements of this paragraph by no later than 

November 11, 2015 or upon startup of the modified flare, whichever is later. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Locate the pressure sensor(s) in a position that provides a representative measurement of the 

pressure and locate the liquid seal level monitor in a position that provides a representative 

measurement of the water column height. 

(2) Minimize or eliminate pulsating pressure, vibration and internal and external corrosion. 

(3) Use a pressure sensor and level monitor with a minimum tolerance of 1.27 centimeters of 

water. 

(4) Using a manometer, check pressure sensor calibration quarterly. 

(5) Conduct calibration checks any time the pressure sensor exceeds the manufacturer's specified 

maximum operating pressure range or install a new pressure sensor. 

(6) In a cascaded flare system that employs multiple secondary flares, pressure and liquid level 

monitoring is required only on the first secondary flare in the system (i.e., the secondary flare 

with the lowest pressure release set point). 

(7) This alternative monitoring option may be elected only for flares with four or fewer pressure 

exceedances required to be reported under §60.108a(d)(5) (“reportable pressure exceedances”) in 

any 365 consecutive calendar days. Following the fifth reportable pressure exceedance in a 365-

day period, the owner or operator must comply with the sulfur and flow monitoring requirements 

of paragraphs (e) and (f) of this section as soon as practical, but no later than 180 days after the 

fifth reportable pressure exceedance in a 365-day period. 

(h) Alternative monitoring for flares located in the BAAQMD or SCAQMD. An affected flare 

subject to this subpart located in the BAAQMD may elect to comply with the monitoring 

requirements in both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 

as an alternative to complying with the requirements of paragraphs (e) and (f) of this section. An 

affected flare subject to this subpart located in the SCAQMD may elect to comply with the 

monitoring requirements in SCAQMD Rule 1118 as an alternative to complying with the 

requirements of paragraphs (e) and (f) of this section. 

(i) Excess emissions. For the purpose of reports required by §60.7(c), periods of excess 

emissions for fuel gas combustion devices subject to the emissions limitations in §60.102a(g) 

and flares subject to the concentration requirement in §60.103a(h) are defined as specified in 

paragraphs (i)(1) through (5) of this section. Determine a rolling 3-hour or a rolling daily average 

as the arithmetic average of the applicable 1-hour averages (e.g., a rolling 3-hour average is the 

arithmetic average of three contiguous 1-hour averages). Determine a rolling 30-day or a rolling 

365-day average as the arithmetic average of the applicable daily averages (e.g., a rolling 30-day 

average is the arithmetic average of 30 contiguous daily averages). 

(1) SO2 or H2S limits for fuel gas combustion devices. (i) If the owner or operator of a fuel gas 

combustion device elects to comply with the SO2 emission limits in §60.102a(g)(1)(i), each 

rolling 3-hour period during which the average concentration of SO2 as measured by the SO2 

continuous monitoring system required under paragraph (a)(1) of this section exceeds 20 ppmv, 

and each rolling 365-day period during which the average concentration of SO2 as measured by 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

the SO2 continuous monitoring system required under paragraph (a)(1) of this section exceeds 8 

ppmv. 

(ii) If the owner or operator of a fuel gas combustion device elects to comply with the H2S 

concentration limits in §60.102a(g)(1)(ii), each rolling 3-hour period during which the average 

concentration of H2S as measured by the H2S continuous monitoring system required under 

paragraph (a)(2) of this section exceeds 162 ppmv and each rolling 365-day period during which 

the average concentration as measured by the H2S continuous monitoring system under 

paragraph (a)(2) of this section exceeds 60 ppmv. 

(iii) If the owner or operator of a fuel gas combustion device becomes subject to the 

requirements of daily stain tube sampling in paragraph (b)(3)(iii) of this section, each day during 

which the daily concentration of H2S exceeds 162 ppmv and each rolling 365-day period during 

which the average concentration of H2S exceeds 60 ppmv. 

(2) H2S concentration limits for flares. (i) Each rolling 3-hour period during which the average 

concentration of H2S as measured by the H2S continuous monitoring system required under 

paragraph (a)(2) of this section exceeds 162 ppmv. 

(ii) If the owner or operator of a flare becomes subject to the requirements of daily stain tube 

sampling in paragraph (b)(3)(iii) of this section, each day during which the daily concentration of 

H2S exceeds 162 ppmv. 

(3) Rolling 30-day average NOX limits for fuel gas combustion devices. Each rolling 30-day 

period during which the average concentration of NOX as measured by the NOX continuous 

monitoring system required under paragraph (c) or (d) of this section exceeds: 

(i) For a natural draft process heater, 40 ppmv and, if monitored according to §60.107a(d), 0.040 

lb/MMBtu; 

(ii) For a forced draft process heater, 60 ppmv and, if monitored according to §60.107a(d), 0.060 

lb/MMBtu; and 

(iii) For a co-fired process heater electing to comply with the NOX limit in 

§60.102a(g)(2)(iii)(A) or (g)(2)(iv)(A), 150 ppmv. 

(iv) The site-specific limit determined by the Administrator under §60.102a(i). 

(4) Daily NOX limits for fuel gas combustion devices. Each day during which the concentration 

of NOX as measured by the NOX continuous monitoring system required under paragraph (d) of 

this section exceeds the daily average emissions limit calculated using Equation 3 in 

§60.102a(g)(2)(iii)(B) or Equation 4 in §60.102a(g)(2)(iv)(B). 

(5) Daily O2 limits for fuel gas combustion devices. Each day during which the concentration of 

O2 as measured by the O2 continuous monitoring system required under paragraph (c)(6) or 

(d)(8) of this section exceeds the O2 operating limit or operating curve determined during the 

most recent biennial performance test. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§ 60.108a Recordkeeping and reporting requirements. 

(a) Each owner or operator subject to the emissions limitations in §60.102a shall comply with the 

notification, recordkeeping, and reporting requirements in §60.7 and other requirements as 

specified in this section. 

(b) Each owner or operator subject to an emissions limitation in §60.102a shall notify the 

Administrator of the specific monitoring provisions of §§60.105a, 60.106a and 60.107a with 

which the owner or operator intends to comply. Each owner or operator of a co-fired process 

heater subject to an emissions limitation in §60.102a(g)(2)(iii) or (iv) shall submit to the 

Administrator documentation showing that the process heater meets the definition of a co-fired 

process heater in §60.101a. Notifications required by this paragraph shall be submitted with the 

notification of initial startup required by §60.7(a)(3). 

(c) The owner or operator shall maintain the following records: 

(1) A copy of the flare management plan. 

(2) Records of information to document conformance with bag leak detection system operation 

and maintenance requirements in §60.105a(c). 

(3) Records of bag leak detection system alarms and actions according to §60.105a(c). 

(4) For each FCCU and fluid coking unit subject to the monitoring requirements in 

§60.105a(b)(1), records of the average coke burn-off rate and hours of operation. 

(5) For each fuel gas stream to which one of the exemptions listed in §60.107a(a)(3) applies, 

records of the specific exemption determined to apply for each fuel stream. If the owner or 

operator applies for the exemption described in §60.107a(a)(3)(iv), the owner or operator must 

keep a copy of the application as well as the letter from the Administrator granting approval of 

the application. 

(6) Records of discharges greater than 500 lb SO2 in any 24-hour period from any affected flare, 

discharges greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion 

device or sulfur recovery plant and discharges to an affected flare in excess of 500,000 scf above 

baseline in any 24-hour period as required by §60.103a(c). If the monitoring alternative provided 

in §60.107a(g) is selected, the owner or operator shall record any instance when the flare gas line 

pressure exceeds the water seal liquid depth, except for periods attributable to compressor 

staging that do not exceed the staging time specified in §60.103a(a)(3)(vii)(C). The following 

information shall be recorded no later than 45 days following the end of a discharge exceeding 

the thresholds: 

(i) A description of the discharge. 

(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-
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

hour period. For a flare, record the measured or calculated cumulative quantity of gas discharged 

to the flare over the discharge duration. If the discharge duration exceeds 24 hours, record the 

quantity of gas discharged to the flare for each 24-hour period. Engineering calculations are 

allowed for fuel gas combustion devices, but are not allowed for flares, except for those 

complying with the alternative monitoring requirements in §60.107a(g). 

(iv) For each discharge greater than 500 lb SO2 in any 24-hour period from a flare, the measured 

total sulfur concentration or both the measured H2S concentration and the estimated total sulfur 

concentration in the fuel gas at a representative location in the flare inlet. 

(v) For each discharge greater than 500 lb SO2 in excess of the applicable short-term emissions 

limit in §60.102a(g)(1) from a fuel gas combustion device, either the measured concentration of 

H2S in the fuel gas or the measured concentration of SO2 in the stream discharged to the 

atmosphere. Process knowledge can be used to make these estimates for fuel gas combustion 

devices, but cannot be used to make these estimates for flares, except as provided in 

§60.107a(e)(4). 

(vi) For each discharge greater than 500 lb SO2 in excess of the allowable limits from a sulfur 

recovery plant, either the measured concentration of reduced sulfur or SO2 discharged to the 

atmosphere. 

(vii) For each discharge greater than 500 lb SO2 in any 24-hour period from any affected flare or 

discharge greater than 500 lb SO2 in excess of the allowable limits from a fuel gas combustion 

device or sulfur recovery plant, the cumulative quantity of H2S and SO2 released into the 

atmosphere. For releases controlled by flares, assume 99-percent conversion of reduced sulfur or 

total sulfur to SO2 . For fuel gas combustion devices, assume 99-percent conversion of H2S to 

SO2. 

(viii) The steps that the owner or operator took to limit the emissions during the discharge. 

(ix) The root cause analysis and corrective action analysis conducted as required in §60.103a(d), 

including an identification of the affected facility, the date and duration of the discharge, a 

statement noting whether the discharge resulted from the same root cause(s) identified in a 

previous analysis and either a description of the recommended corrective action(s) or an 

explanation of why corrective action is not necessary under §60.103a(e). 

(x) For any corrective action analysis for which corrective actions are required in §60.103a(e), a 

description of the corrective action(s) completed within the first 45 days following the discharge 

and, for action(s) not already completed, a schedule for implementation, including proposed 

commencement and completion dates. 

(xi) For each discharge from any affected flare that is the result of a planned startup or shutdown 

of a refinery process unit or ancillary equipment connected to the affected flare, a statement that 

a root cause analysis and corrective action analysis are not necessary because the owner or 

operator followed the flare management plan. 

(7) If the owner or operator elects to comply with §60.107a(e)(2) for a flare, records of the H2S 

and total sulfur analyses of each grab or integrated sample, the calculated daily total sulfur-to-
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

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 listed in 

paragraph (c)(6) of this section. For a flare complying with the monitoring alternative under 

§60.107a(g), following the fifth discharge required to be recorded under paragraph (c)(6) of this 

section and reported under this paragraph, the owner or operator shall include notification that 

monitoring systems will be installed according to §60.107a(e) and (f) within 180 days following 

the fifth discharge. 

(6) For any periods for which monitoring data are not available, any changes made in operation 

of the emission control system during the period of data unavailability which could affect the 

ability of the system to meet the applicable emission limit. Operations of the control system and 

affected facility during periods of data unavailability are to be compared with operation of the 

control system and affected facility before and following the period of data unavailability. 

(7) A written statement, signed by a responsible official, certifying the accuracy and 

completeness of the information contained in the report. 

§ 60.109a Delegation of authority. 

(a) This subpart can be implemented and enforced by the U.S. EPA or a delegated authority such 

as a State, local, or tribal agency. You should contact your U.S. EPA Regional Office to find out 

if this subpart is delegated to a State, local, or tribal agency within your State. 

(b) In delegating implementation and enforcement authority of this subpart to a state, local or 

tribal agency, the approval authorities contained in paragraphs (b)(1) through (4) of this section 

are retained by the Administrator of the U.S. EPA and are not transferred to the state, local or 

tribal agency. 

(1) Approval of a major change to test methods under §60.8(b). A “major change to test method” 

is defined in 40 CFR 63.90. 

(2) Approval of a major change to monitoring under §60.13(i). A “major change to monitoring” 

is defined in 40 CFR 63.90. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(3) Approval of a major change to recordkeeping/reporting under §60.7(b) through (f). A “major 

change to recordkeeping/reporting” is defined in 40 CFR 63.90. 

(4) Approval of an application for an alternative means of emission limitation under §60.103a(j) 

of this subpart. 

Table 1 to Subpart Ja of Part 60—Molar Exhaust Volumes and Molar Heat Content of Fuel Gas 

Constituents 

Constituent 

MEVa 

dscf/mol 

MHCb 

Btu/mol 

Methane (CH4) 7.29 842 

Ethane (C2H6) 12.96 1,475 

Hydrogen (H2) 1.61 269 

Ethene (C2H4) 11.34 1,335 

Propane (C3H8) 18.62 2,100 

Propene (C3H6) 17.02 1,947 

Butane (C4H10) 24.30 2,717 

Butene (C4H8) 22.69 2,558 

Inerts 0.85 0 

a MEV = molar exhaust volume, dry standard cubic feet per gram-mole (dscf/g-mol) at standard 

conditions of 68 °F and 1 atmosphere. 

b MHC = molar heat content (higher heating value basis), Btu per gram-mole (Btu/g-mol). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EO12866_RefineryRTR 2060 AQ75 NPRM Part60Subpart_J_Regtext_20140128 

Title 40: Protection of Environment 

PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

Subpart J—Standards of Performance for Petroleum Refineries 

§ 60.100 Applicability, designation of affected facility, and reconstruction. 

(a) The provisions of this subpart are applicable to the following affected facilities in 

petroleum refineries: fluid catalytic cracking unit catalyst regenerators, fuel gas combustion 

devices, and all Claus sulfur recovery plants except Claus plants with a design capacity for sulfur 

feed of 20 long tons per day (LTD) or less. The Claus sulfur recovery plant need not be 

physically located within the boundaries of a petroleum refinery to be an affected facility, 

provided it processes gases produced within a petroleum refinery. 

(b) Any fluid catalytic cracking unit catalyst regenerator or fuel gas combustion device 

under paragraph (a) of this section other than a flare which commences construction, 

reconstruction or modification after June 11, 1973, and on or before May 14, 2007, or any fuel 

gas combustion device under paragraph (a) of this section that is also a flare which commences 

construction, reconstruction or modification after June 11, 1973, and on or before June 24, 2008, 

or any Claus sulfur recovery plant under paragraph (a) of this section which commences 

construction, reconstruction or modification after October 4, 1976, and on or before May 14, 

2007, is subject to the requirements of this subpart except as provided under paragraphs (c) 

through (e) of this section. 

(c) Any fluid catalytic cracking unit catalyst regenerator under paragraph (b) of this section 

which commences construction, reconstruction, or modification on or before January 17, 1984, is 

exempted from §60.104(b). 

(d) Any fluid catalytic cracking unit in which a contact material reacts with petroleum 

derivatives to improve feedstock quality and in which the contact material is regenerated by 

burning off coke and/or other deposits and that commences construction, reconstruction, or 

modification on or before January 17, 1984, is exempt from this subpart. 

(e) Owners or operators may choose to comply with the applicable provisions of subpart Ja 

of this part to satisfy the requirements of this subpart for an affected facility. 

(f) For purposes of this subpart, under §60.15, the “fixed capital cost of the new 

components” includes the fixed capital cost of all depreciable components which are or will be 

replaced pursuant to all continuous programs of component replacement which are commenced 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

within any 2-year period following January 17, 1984. For purposes of this paragraph, 

“commenced” means that an owner or operator has undertaken a continuous program of 

component replacement or that an owner or operator has entered into a contractual obligation to 

undertake and complete, within a reasonable time, a continuous program of component 

replacement. 

§ 60.101 Definitions. 

As used in this subpart, all terms not defined herein shall have the meaning given them in 

the Act and in subpart A. 

(a) Petroleum refinery means any facility engaged in producing gasoline, kerosene, 

distillate fuel oils, residual fuel oils, lubricants, or other products through distillation of 

petroleum or through redistillation, cracking or reforming of unfinished petroleum derivatives. 

(b) Petroleum means the crude oil removed from the earth and the oils derived from tar 

sands, shale, and coal. 

(c) Process gas means any gas generated by a petroleum refinery process unit, except fuel 

gas and process upset gas as defined in this section. 

(d) Fuel gas means any gas which is generated at a petroleum refinery and which is 

combusted. Fuel gas includes natural gas when the natural gas is combined and combusted in any 

proportion with a gas generated at a refinery. Fuel gas does not include gases generated by 

catalytic cracking unit catalyst regenerators and fluid coking burners. Fuel gas does not include 

vapors that are collected and combusted in a thermal oxidizer or flare installed to control 

emissions from wastewater treatment units or marine tank vessel loading operations. 

(e) Process upset gas means any gas generated by a petroleum refinery process unit as a 

result of start-up, shut-down, upset or malfunction. 

(f) Refinery process unit means any segment of the petroleum refinery in which a specific 

processing operation is conducted. 

(g) Fuel gas combustion device means any equipment, such as process heaters, boilers and 

flares used to combust fuel gas, except facilities in which gases are combusted to produce sulfur 

or sulfuric acid. 

(h) Coke burn-off means the coke removed from the surface of the fluid catalytic cracking 

unit catalyst by combustion in the catalyst regenerator. The rate of coke burn-off is calculated by 

the formula specified in §60.106. 

(i) Claus sulfur recovery plant means a process unit which recovers sulfur from hydrogen 

sulfide by a vapor-phase catalytic reaction of sulfur dioxide and hydrogen sulfide. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(j) Oxidation control system means an emission control system which reduces emissions 

from sulfur recovery plants by converting these emissions to sulfur dioxide. 

(k) Reduction control system means an emission control system which reduces emissions 

from sulfur recovery plants by converting these emissions to hydrogen sulfide. 

(l) Reduced sulfur compounds means hydrogen sulfide (H2S), carbonyl sulfide (COS) and 

carbon disulfide (CS2). 

(m) Fluid catalytic cracking unit means a refinery process unit in which petroleum 

derivatives are continuously charged; hydrocarbon molecules in the presence of a catalyst 

suspended in a fluidized bed are fractured into smaller molecules, or react with a contact material 

suspended in a fluidized bed to improve feedstock quality for additional processing; and the 

catalyst or contact material is continuously regenerated by burning off coke and other deposits. 

The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material 

stripper, catalyst or contact material recovery equipment, and regenerator equipment for 

controlling air pollutant emissions and for heat recovery. 

(n) Fluid catalytic cracking unit catalyst regenerator means one or more regenerators 

(multiple regenerators) which comprise that portion of the fluid catalytic cracking unit in which 

coke burn-off and catalyst or contact material regeneration occurs, and includes the regenerator 

combustion air blower(s). 

(o) Fresh feed means any petroleum derivative feedstock stream charged directly into the 

riser or reactor of a fluid catalytic cracking unit except for petroleum derivatives recycled within 

the fluid catalytic cracking unit, fractionator, or gas recovery unit. 

(p) Contact material means any substance formulated to remove metals, sulfur, nitrogen, or 

any other contaminant from petroleum derivatives. 

(q) Valid day means a 24-hour period in which at least 18 valid hours of data are obtained. 

A “valid hour” is one in which at least 2 valid data points are obtained. 

§ 60.102 Standard for particulate matter. 

Each owner or operator of any fluid catalytic cracking unit catalyst regenerator that is 

subject to the requirements of this subpart shall comply with the emission limitations set forth in 

this section on and after the date on which the initial performance test, required by §60.8, is 

completed, but not later than 60 days after achieving the maximum production rate at which the 

fluid catalytic cracking unit catalyst regenerator will be operated, or 180 days after initial startup, 

whichever comes first. 

(a) No owner or operator subject to the provisions of this subpart shall discharge or cause 

the discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Particulate matter in excess of 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in the catalyst 

regenerator. 

(2) Gases exhibiting greater than 30 percent opacity, except for one six-minute average 

opacity reading in any one hour period. 

(b) Where the gases discharged by the fluid catalytic cracking unit catalyst regenerator pass 

through an incinerator or waste heat boiler in which auxiliary or supplemental liquid or solid 

fossil fuel is burned, particulate matter in excess of that permitted by paragraph (a)(1) of this 

section may be emitted to the atmosphere, except that the incremental rate of particulate matter 

emissions shall not exceed 43 grams per Gigajoule (g/GJ) (0.10 lb/million British thermal units 

(Btu)) of heat input attributable to such liquid or solid fossil fuel. 

§ 60.103 Standard for carbon monoxide. 

Each owner or operator of any fluid catalytic cracking unit catalyst regenerator that is 

subject to the requirements of this subpart shall comply with the emission limitations set forth in 

this section on and after the date on which the initial performance test, required by §60.8, is 

completed, but not later than 60 days after achieving the maximum production rate at which the 

fluid catalytic cracking unit catalyst regenerator will be operated, or 180 days after initial startup, 

whichever comes first. 

(a) No owner or operator subject to the provisions of this subpart shall discharge or cause 

the discharge into the atmosphere from any fluid catalytic cracking unit catalyst regenerator any 

gases that contain carbon monoxide (CO) in excess of 500 ppm by volume (dry basis). 

§ 60.104 Standards for sulfur oxides. 

Each owner or operator that is subject to the requirements of this subpart shall comply with 

the emission limitations set forth in this section on and after the date on which the initial 

performance test, required by §60.8, is completed, but not later than 60 days after achieving the 

maximum production rate at which the affected facility will be operated, or 180 days after initial 

startup, whichever comes first. 

(a) No owner or operator subject to the provisions of this subpart shall: 

(1) Burn in any fuel gas combustion device any fuel gas that contains hydrogen sulfide 

(H2S) in excess of 230 mg/dscm (0.10 gr/dscf). The combustion in a flare of process upset gases 

or fuel gas that is released to the flare as a result of relief valve leakage or other emergency 

malfunctions is exempt from this paragraph. 

(2) Discharge or cause the discharge of any gases into the atmosphere from any Claus sulfur 

recovery plant containing in excess of: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) For an oxidation control system or a reduction control system followed by incineration, 

250 ppm by volume (dry basis) of sulfur dioxide (SO2) at zero percent excess air. 

(ii) For a reduction control system not followed by incineration, 300 ppm by volume of 

reduced sulfur compounds and 10 ppm by volume of hydrogen sulfide (H2S), each calculated as 

ppm SO2 by volume (dry basis) at zero percent excess air. 

(b) Each owner or operator that is subject to the provisions of this subpart shall comply with 

one of the following conditions for each affected fluid catalytic cracking unit catalyst 

regenerator: 

(1) With an add-on control device, reduce SO2 emissions to the atmosphere by 90 percent or 

maintain SO2 emissions to the atmosphere less than or equal to 50 ppm by volume (ppmv), 

whichever is less stringent; or 

(2) Without the use of an add-on control device to reduce SO2 emission, maintain sulfur 

oxides emissions calculated as SO2 to the atmosphere less than or equal to 9.8 kg/Mg (20 lb/ton) 

coke burn-off; or 

(3) Process in the fluid catalytic cracking unit fresh feed that has a total sulfur content no 

greater than 0.30 percent by weight. 

(c) Compliance with paragraph (b)(1), (b)(2), or (b)(3) of this section is determined daily on 

a 7-day rolling average basis using the appropriate procedures outlined in §60.106. 

(d) A minimum of 22 valid days of data shall be obtained every 30 rolling successive 

calendar days when complying with paragraph (b)(1) of this section. 

§ 60.105 Monitoring of emissions and operations. 

(a) Continuous monitoring systems shall be installed, calibrated, maintained, and operated 

by the owner or operator subject to the provisions of this subpart as follows: 

(1) For fluid catalytic cracking unit catalyst regenerators subject to §60.102(a)(2), an 

instrument for continuously monitoring and recording the opacity of emissions into the 

atmosphere. The instrument shall be spanned at 60, 70, or 80 percent opacity. 

(2) For fluid catalytic cracking unit catalyst regenerators subject to §60.103(a), an 

instrument for continuously monitoring and recording the concentration by volume (dry basis) of 

CO emissions into the atmosphere, except as provided in paragraph (a)(2) (ii) of this section. 

(i) The span value for this instrument is 1,000 ppm CO. 

(ii) A CO continuous monitoring system need not be installed if the owner or operator 

demonstrates that the average CO emissions are less than 50 ppm (dry basis) and also files a 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

written request for exemption to the Administrator and receives such an exemption. The 

demonstration shall consist of continuously monitoring CO emissions for 30 days using an 

instrument that shall meet the requirements of Performance Specification 4 of appendix B of this 

part. The span value shall be 100 ppm CO instead of 1,000 ppm, and the relative accuracy limit 

shall be 10 percent of the average CO emissions or 5 ppm CO, whichever is greater. For 

instruments that are identical to Method 10 and employ the sample conditioning system of 

Method 10A, the alternative relative accuracy test procedure in §10.1 of Performance 

Specification 2 may be used in place of the relative accuracy test. 

(3) For fuel gas combustion devices subject to §60.104(a)(1), either an instrument for 

continuously monitoring and recording the concentration by volume (dry basis, zero percent 

excess air) of SO2 emissions into the atmosphere or monitoring as provided in paragraph (a)(4) 

of this section). The monitor shall include an oxygen monitor for correcting the data for excess. 

(i) The span values for this monitor are 50 ppm SO2 and 25 percent oxygen (O2). 

(ii) The SO2 monitoring level equivalent to the H2S standard under §60.104(a)(1) shall be 

20 ppm (dry basis, zero percent excess air). 

(iii) The performance evaluations for this SO2 monitor under §60.13(c) shall use 

Performance Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the 

relative accuracy evaluations. Method 6 samples shall be taken at a flow rate of approximately 2 

liters/min for at least 30 minutes. The relative accuracy limit shall be 20 percent or 4 ppm, 

whichever is greater, and the calibration drift limit shall be 5 percent of the established span 

value. 

(iv) Fuel gas combustion devices having a common source of fuel gas may be monitored at 

only one location (i.e., after one of the combustion devices), if monitoring at this location 

accurately represents the SO2 emissions into the atmosphere from each of the combustion 

devices. 

(4) Instead of the SO2 monitor in paragraph (a)(3) of this section for fuel gas combustion 

devices subject to §60.104(a)(1), an instrument for continuously monitoring and recording the 

concentration (dry basis) of H2S in fuel gases before being burned in any fuel gas combustion 

device. 

(i) The span value for this instrument is 425 mg/dscm H2S. 

(ii) Fuel gas combustion devices having a common source of fuel gas may be monitored at 

only one location, if monitoring at this location accurately represents the concentration of H2S in 

the fuel gas being burned. 

(iii) The performance evaluations for this H2S monitor under §60.13(c) shall use 

Performance Specification 7. Method 11, 15, 15A, or 16 shall be used for conducting the relative 

accuracy evaluations. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iv) The owner or operator of a fuel gas combustion device is not required to comply with 

paragraph (a)(3) or (4) of this section for fuel gas streams that are exempt under §60.104(a)(1) 

and fuel gas streams combusted in a fuel gas combustion device that are inherently low in sulfur 

content. Fuel gas streams meeting one of the requirements in paragraphs (a)(4)(iv)(A) through 

(D) of this section will be considered inherently low in sulfur content. If the composition of a 

fuel gas stream changes such that it is no longer exempt under §60.104(a)(1) or it no longer 

meets one of the requirements in paragraphs (a)(4)(iv)(A) through (D) of this section, the owner 

or operator must begin continuous monitoring under paragraph (a)(3) or (4) of this section within 

15 days of the change. 

(A) Pilot gas for heaters and flares. 

(B) Fuel gas streams that meet a commercial-grade product specification for sulfur content 

of 30 ppmv or less. In the case of a liquefied petroleum gas (LPG) product specification in the 

pressurized liquid state, the gas phase sulfur content should be evaluated assuming complete 

vaporization of the LPG and sulfur containing-compounds at the product specification 

concentration. 

(C) Fuel gas streams produced in process units that are intolerant to sulfur contamination, 

such as fuel gas streams produced in the hydrogen plant, the catalytic reforming unit, the 

isomerization unit, and HF alkylation process units. 

(D) Other fuel gas streams that an owner or operator demonstrates are low-sulfur according 

to the procedures in paragraph (b) of this section. 

(5) For Claus sulfur recovery plants with oxidation control systems or reduction control 

systems followed by incineration subject to §60.104(a)(2)(i), an instrument for continuously 

monitoring and recording the concentration (dry basis, zero percent excess air) of SO2 emissions 

into the atmosphere. The monitor shall include an oxygen monitor for correcting the data for 

excess air. 

(i) The span values for this monitor are 500 ppm SO2 and 25 percent O2. 

(ii) The performance evaluations for this SO2 monitor under §60.13(c) shall use 

Performance Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the 

relative accuracy evaluations. 

(6) For Claus sulfur recovery plants with reduction control systems not followed by 

incineration subject to §60.104(a)(2)(ii), an instrument for continuously monitoring and 

recording the concentration of reduced sulfur and O2 emissions into the atmosphere. The reduced 

sulfur emissions shall be calculated as SO2 (dry basis, zero percent excess air). 

(i) The span values for this monitor are 450 ppm reduced sulfur and 25 percent O2. 

(ii) The performance evaluations for this reduced sulfur (and O2) monitor under §60.13(c) 

shall use Performance Specification 5 of appendix B of this part(and Performance Specification 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

3 of appendix B of this part for the O2 analyzer). Methods 15 or 15A and Method 3 shall be used 

for conducting the relative accuracy evaluations. If Method 3 yields O2 concentrations below 

0.25 percent during the performance specification test, the O2 concentration may be assumed to 

be zero and the reduced sulfur CEMS need not include an O2 monitor. 

(7) In place of the reduced sulfur monitor under paragraph (a)(6) of this section, an 

instrument using an air or O2 dilution and oxidation system to convert the reduced sulfur to SO2

for continuously monitoring and recording the concentration (dry basis, zero percent excess air) 

of the resultant SO2 . The monitor shall include an oxygen monitor for correcting the data for 

excess oxygen. 

(i) The span values for this monitor are 375 ppm SO2 and 25 percent O2. 

(ii) For reporting purposes, the SO2 exceedance level for this monitor is 250 ppm (dry basis, 

zero percent excess air). 

(iii) The performance evaluations for this SO2 (and O2) monitor under §60.13(c) shall use 

Performance Specification 5. Methods 15 or 15A and Method 3 shall be used for conducting the 

relative accuracy evaluations. 

(8) An instrument for continuously monitoring and recording concentrations of SO2 in the 

gases at both the inlet and outlet of the SO2 control device from any fluid catalytic cracking unit 

catalyst regenerator for which the owner or operator seeks to comply specifically with the 90 

percent reduction option under §60.104(b)(1). 

(i) The span value of the inlet monitor shall be set at 125 percent of the maximum estimated 

hourly potential SO2 emission concentration entering the control device, and the span value of 

the outlet monitor shall be set at 50 percent of the maximum estimated hourly potential SO2

emission concentration entering the control device. 

(ii) The performance evaluations for these SO2 monitors under §60.13(c) shall use 

Performance Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the 

relative accuracy evaluations. 

(9) An instrument for continuously monitoring and recording concentrations of SO2 in the 

gases discharged into the atmosphere from any fluid catalytic cracking unit catalyst regenerator 

for which the owner or operator seeks to comply specifically with the 50 ppmv emission limit 

under §60.104 (b)(1). 

(i) The span value of the monitor shall be set at 50 percent of the maximum hourly potential 

SO2 emission concentration of the control device. 

(ii) The performance evaluations for this SO2 monitor under §60.13 (c) shall use 

Performance Specification 2. Methods 6 or 6C and 3 or 3A shall be used for conducting the 

relative accuracy evaluations. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(10) An instrument for continuously monitoring and recording concentrations of oxygen 

(O2) in the gases at both the inlet and outlet of the sulfur dioxide control device (or the outlet 

only if specifically complying with the 50 ppmv standard) from any fluid catalytic cracking unit 

catalyst regenerator for which the owner or operator has elected to comply with §60.104(b)(1). 

The span of this continuous monitoring system shall be set at 10 percent. 

(11) The continuous monitoring systems under paragraphs (a)(8), (a)(9), and (a)(10) of this 

section are operated and data recorded during all periods of operation of the affected facility 

including periods of startup, shutdown, or malfunction, except for continuous monitoring system 

breakdowns, repairs, calibration checks, and zero and span adjustments. 

(12) The owner or operator shall use the following procedures to evaluate the continuous 

monitoring systems under paragraphs (a)(8), (a)(9), and (a)(10) of this section. 

(i) Method 3 or 3A and Method 6 or 6C for the relative accuracy evaluations under the 

§60.13(e) performance evaluation. 

(ii) appendix F, Procedure 1, including quarterly accuracy determinations and daily 

calibration drift tests. 

(13) When seeking to comply with §60.104(b)(1), when emission data are not obtained 

because of continuous monitoring system breakdowns, repairs, calibration checks and zero and 

span adjustments, emission data will be obtained by using one of the following methods to 

provide emission data for a minimum of 18 hours per day in at least 22 out of 30 rolling 

successive calendar days. 

(i) The test methods as described in §60.106(k); 

(ii) A spare continuous monitoring system; or 

(iii) Other monitoring systems as approved by the Administrator. 

(b) An owner or operator may demonstrate that a fuel gas stream combusted in a fuel gas 

combustion device subject to §60.104(a)(1) that is not specifically exempted in §60.105(a)(4)(iv) 

is inherently low in sulfur. A fuel gas stream that is determined to be low-sulfur is exempt from 

the monitoring requirements in paragraphs (a)(3) and (4) of this section until there are changes in 

operating conditions or stream composition. 

(1) The owner or operator shall submit to the Administrator a written application for an 

exemption from monitoring. The application must contain the following information: 

(i) A description of the fuel gas stream/system to be considered, including submission of a 

portion of the appropriate piping diagrams indicating the boundaries of the fuel gas 

stream/system, and the affected fuel gas combustion device(s) to be considered; 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) A statement that there are no crossover or entry points for sour gas (high H2S content) to 

be introduced into the fuel gas stream/system (this should be shown in the piping diagrams); 

(iii) An explanation of the conditions that ensure low amounts of sulfur in the fuel gas 

stream (i.e., control equipment or product specifications) at all times; 

(iv) The supporting test results from sampling the requested fuel gas stream/system 

demonstrating that the sulfur content is less than 5 ppmv. Sampling data must include, at 

minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas 

streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be 

collected unless other additional information would support reduced sampling. The owner or 

operator shall use detector tubes (“length-of-stain tube” type measurement) following the “Gas 

Processors Association Standard 2377-86, Test for Hydrogen Sulfide and Carbon Dioxide in 

Natural Gas Using Length of Stain Tubes,” 1986 Revision (incorporated by reference—see 

§60.17), using tubes with a maximum span between 10 and 40 ppmv inclusive when 1≤N≤10, 

where N = number of pump strokes, to test the applicant fuel gas stream for H2S; and 

(v) A description of how the 2 weeks (or seven samples for infrequently operated fuel gas 

streams/systems) of monitoring results compares to the typical range of H2S concentration (fuel 

quality) expected for the fuel gas stream/system going to the affected fuel gas combustion device 

(e.g., the 2 weeks of daily detector tube results for a frequently operated loading rack included 

the entire range of products loaded out, and, therefore, should be representative of typical 

operating conditions affecting H2S content in the fuel gas stream going to the loading rack flare). 

(2) The effective date of the exemption is the date of submission of the information required 

in paragraph (b)(1) of this section). 

(3) No further action is required unless refinery operating conditions change in such a way 

that affects the exempt fuel gas stream/system (e.g., the stream composition changes). If such a 

change occurs, the owner or operator will follow the procedures in paragraph (b)(3)(i), (b)(3)(ii), 

or (b)(3)(iii) of this section. 

(i) If the operation change results in a sulfur content that is still within the range of 

concentrations included in the original application, the owner or operator shall conduct an H2S 

test on a grab sample and record the results as proof that the concentration is still within the 

range. 

(ii) If the operation change results in a sulfur content that is outside the range of 

concentrations included in the original application, the owner or operator may submit new 

information following the procedures of paragraph (b)(1) of this section within 60 days (or 

within 30 days after the seventh grab sample is tested for infrequently operated process units). 

(iii) If the operation change results in a sulfur content that is outside the range of 

concentrations included in the original application and the owner or operator chooses not to 

submit new information to support an exemption, the owner or operator must begin H2S 

monitoring using daily stain sampling to demonstrate compliance using length-of stain tubes 

Deleted: with ranges 0–10/0–100 ppm (N = 10/1) 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

with a maximum span between 200 and 400 ppmv inclusive when 1≤N≤5, where N = number of 

pump strokes. The owner or operator must begin monitoring according to the requirements in 

paragraphs (a)(1) or (a)(2) of this section as soon as practicable but in no case later than 180 days 

after the operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv 

is an exceedance of the 3-hour H2S concentration limit. 

(c) The average coke burn-off rate (Mg (tons) per hour) and hours of operation shall be 

recorded daily for any fluid catalytic cracking unit catalyst regenerator subject to §60.102, 

§60.103, or §60.104(b)(2). 

(d) For any fluid catalytic cracking unit catalyst regenerator under §60.102 that uses an 

incinerator-waste heat boiler to combust the exhaust gases from the catalyst regenerator, the 

owner or operator shall record daily the rate of combustion of liquid or solid fossil-fuels and the 

hours of operation during which liquid or solid fossil-fuels are combusted in the incineratorwaste heat boiler. 

(e) For the purpose of reports under §60.7(c), periods of excess emissions that shall be 

determined and reported are defined as follows: 

NOTE: All averages, except for opacity, shall be determined as the arithmetic average of the 

applicable 1-hour averages, e.g., the rolling 3-hour average shall be determined as the arithmetic 

average of three contiguous 1-hour averages. 

(1) Opacity. All 1-hour periods that contain two or more 6-minute periods during which the 

average opacity as measured by the continuous monitoring system under §60.105(a)(1) exceeds 

30 percent. 

(2) Carbon monoxide. All 1-hour periods during which the average CO concentration as 

measured by the CO continuous monitoring system under §60.105(a)(2) exceeds 500 ppm. 

(3) Sulfur dioxide from fuel gas combustion. (i) All rolling 3-hour periods during which the 

average concentration of SO2 as measured by the SO2 continuous monitoring system under 

§60.105(a)(3) exceeds 20 ppm (dry basis, zero percent excess air); or 

(ii) All rolling 3-hour periods during which the average concentration of H2S as measured 

by the H2S continuous monitoring system under §60.105(a)(4) exceeds 230 mg/dscm (0.10 

gr/dscf). 

(4) Sulfur dioxide from Claus sulfur recovery plants. (i) All 12-hour periods during which 

the average concentration of SO2 as measured by the SO2 continuous monitoring system under 

§60.105(a)(5) exceeds 250 ppm (dry basis, zero percent excess air); or 

(ii) All 12-hour periods during which the average concentration of reduced sulfur (as SO2) 

as measured by the reduced sulfur continuous monitoring system under §60.105(a)(6) exceeds 

300 ppm; or 

Deleted: 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.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) All 12-hour periods during which the average concentration of SO2 as measured by the 

SO2 continuous monitoring system under §60.105(a)(7) exceeds 250 ppm (dry basis, zero 

percent excess air). 

§ 60.106 Test methods and procedures. 

(a) In conducting the performance tests required in §60.8, the owner or operator shall use as 

reference methods and procedures the test methods in appendix A of this part or other methods 

and procedures as specified in this section, except as provided in §60.8(b). 

(b) The owner or operator shall determine compliance with the particulate matter (PM) 

standards in §60.102(a) as follows: 

(1) The emission rate (E) of PM shall be computed for each run using the following 

equation: 

c

s sd

KR

c Q E 

Where: 

E = Emission rate of PM, kg/Mg (lb/ton) of coke burn-off. 

cs = Concentration of PM, g/dscm (gr/dscf). 

Qsd = Volumetric flow rate of effluent gas, dscm/hr (dscf/hr). 

Rc = Coke burn-off rate, Mg/hr (ton/hr) coke. 

K=Conversion factor, 1,000 g/kg (7,000 gr/lb). 

(2) Method 5B or 5F is to be used to determine particulate matter emissions and associated 

moisture content from affected facilities without wet FGD systems; only Method 5B is to be 

used after wet FGD systems. The sampling time for each run shall be at least 60 minutes and the 

sampling rate shall be at least 0.015 dscm/min (0.53 dscf/min), except that shorter sampling 

times may be approved by the Administrator when process variables or other factors preclude 

sampling for at least 60 minutes. 

(3) The coke burn-off rate (Rc) shall be computed for each run using the following equation: 

Rc = K1Qr (%CO2 + %CO) + K2Qa −K3Qr (%CO/2 + %CO2 + %O2) + K3Qoxy (%Ooxy) 

Where: 

Rc = Coke burn-off rate, kilograms per hour (kg/hr) (lb/hr). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Qr = Volumetric flow rate of exhaust gas from fluid catalytic cracking unit regenerator before 

entering the emission control system, dscm/min (dscf/min). 

Qa = Volumetric flow rate of air to fluid catalytic cracking unit regenerator, as determined from 

the fluid catalytic cracking unit control room instrumentation, dscm/min (dscf/min). 

Qoxy = Volumetric flow rate of O2 enriched air to fluid catalytic cracking unit regenerator, as 

determined from the fluid catalytic cracking unit control room instrumentation, dscm/min 

(dscf/min). 

%CO2 = Carbon dioxide concentration in fluid catalytic cracking unit regenerator exhaust, 

percent by volume (dry basis). 

%CO = CO concentration in FCCU regenerator exhaust, percent by volume (dry basis). 

%O2 = O2 concentration in fluid catalytic cracking unit regenerator exhaust, percent by volume 

(dry basis). 

%Ooxy = O2 concentration in O2 enriched air stream inlet to the fluid catalytic cracking unit 

regenerator, percent by volume (dry basis). 

K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hrdscf-%)]. 

K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hrdscf)]. 

K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) [0.00624 (lbmin)/(hr-dscf-%)]. 

(i) Method 2 shall be used to determine the volumetric flow rate (Qr). 

(ii) The emission correction factor, integrated sampling and analysis procedure of Method 

3B shall be used to determine CO2, CO, and O2 concentrations. 

(4) Method 9 and the procedures of §60.11 shall be used to determine opacity. 

(c) If auxiliary liquid or solid fossil-fuels are burned in an incinerator-waste heat boiler, the 

owner or operator shall determine the emission rate of PM permitted in §60.102(b) as follows: 

(1) The allowable emission rate (Es) of PM shall be computed for each run using the 

following equation: 

  Es  F  A H Rc

Where: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Es = Emission rate of PM allowed, kg/Mg (lb/ton) of coke burn-off in catalyst regenerator. 

F = Emission standard, 1.0 kg/Mg (2.0 lb/ton) of coke burn-off in catalyst regenerator. 

A = Allowable incremental rate of PM emissions, 43 g/GJ (0.10 lb/million Btu). 

H = Heat input rate from solid or liquid fossil fuel, GJ/hr (million Btu/hr). 

Rc = Coke burn-off rate, Mg coke/hr (ton coke/hr). 

(2) Procedures subject to the approval of the Administrator shall be used to determine the 

heat input rate. 

(3) The procedure in paragraph (b)(3) of this section shall be used to determine the coke 

burn-off rate (Rc). 

(d) The owner or operator shall determine compliance with the CO standard in §60.103(a) 

by using the integrated sampling technique of Method 10 to determine the CO concentration (dry 

basis). The sampling time for each run shall be 60 minutes. 

(e)(1) The owner or operator shall determine compliance with the H2S standard in 

§60.104(a)(1) as follows: Method 11, 15, 15A, or 16 shall be used to determine the H2S 

concentration. The gases entering the sampling train should be at about atmospheric pressure. If 

the pressure in the refinery fuel gas lines is relatively high, a flow control valve may be used to 

reduce the pressure. If the line pressure is high enough to operate the sampling train without a 

vacuum pump, the pump may be eliminated from the sampling train. The sample shall be drawn 

from a point near the centroid of the fuel gas line. 

(i) For Method 11, the sampling time and sample volume shall be at least 10 minutes and 

0.010 dscm (0.35 dscf). Two samples of equal sampling times shall be taken at about 1-hour 

intervals. The arithmetic average of these two samples shall constitute a run. For most fuel gases, 

sampling times exceeding 20 minutes may result in depletion of the collection solution, although 

fuel gases containing low concentrations of H2S may necessitate sampling for longer periods of 

time. 

(ii) For Method 15 or 16, at least three injects over a 1-hour period shall constitute a run. 

(iii) For Method 15A, a 1-hour sample shall constitute a run. 

(2) Where emissions are monitored by §60.105(a)(3), compliance with §60.104(a)(1) shall 

be determined using Method 6 or 6C and Method 3 or 3A. The method ANSI/ASME PTC 19.10-

1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an 

acceptable alternative to EPA Method 6. A 1-hour sample shall constitute a run. Method 6 

samples shall be taken at a rate of approximately 2 liters/min. The ppm correction factor (Method 

6) and the sampling location in paragraph (f)(1) of this section apply. Method 4 shall be used to 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

determine the moisture content of the gases. The sampling point for Method 4 shall be adjacent 

to the sampling point for Method 6 or 6C. 

(f) The owner or operator shall determine compliance with the SO2 and the H2S and reduced 

sulfur standards in §60.104(a)(2) as follows: 

(1) Method 6 shall be used to determine the SO2 concentration. The concentration in 

mg/dscm obtained by Method 6 or 6C is multiplied by 0.3754 to obtain the concentration in ppm. 

The sampling point in the duct shall be the centroid of the cross section if the cross-sectional area 

is less than 5.00 m2

 (53.8 ft2) or at a point no closer to the walls than 1.00 m (39.4 in.) if the 

cross-sectional area is 5.00 m2 or more and the centroid is more than 1 m from the wall. The 

sampling time and sample volume shall be at least 10 minutes and 0.010 dscm (0.35 dscf) for 

each sample. Eight samples of equal sampling times shall be taken at about 30-minute intervals. 

The arithmetic average of these eight samples shall constitute a run. For Method 6C, a run shall 

consist of the arithmetic average of four 1-hour samples. Method 4 shall be used to determine the 

moisture content of the gases. The sampling point for Method 4 shall be adjacent to the sampling 

point for Method 6 or 6C. The sampling time for each sample shall be equal to the time it takes 

for two Method 6 samples. The moisture content from this sample shall be used to correct the 

corresponding Method 6 samples for moisture. For documenting the oxidation efficiency of the 

control device for reduced sulfur compounds, Method 15 shall be used following the procedures 

of paragraph (f)(2) of this section. 

(2) Method 15 shall be used to determine the reduced sulfur and H2S concentrations. Each 

run shall consist of 16 samples taken over a minimum of 3 hours. The sampling point shall be the 

same as that described for Method 6 in paragraph (f)(1) of this section. To ensure minimum 

residence time for the sample inside the sample lines, the sampling rate shall be at least 3.0 lpm 

(0.10 cfm). The SO2 equivalent for each run shall be calculated after being corrected for moisture 

and oxygen as the arithmetic average of the SO2 equivalent for each sample during the run. 

Method 4 shall be used to determine the moisture content of the gases as the paragraph (f)(1) of 

this section. The sampling time for each sample shall be equal to the time it takes for four 

Method 15 samples. 

(3) The oxygen concentration used to correct the emission rate for excess air shall be 

obtained by the integrated sampling and analysis procedure of Method 3 or 3A. The samples 

shall be taken simultaneously with the SO2, reduced sulfur and H2S, or moisture samples. The 

SO2, reduced sulfur, and H2S samples shall be corrected to zero percent excess air using the 

equation in paragraph (h)(6) of this section. 

(g) Each performance test conducted for the purpose of determining compliance under 

§60.104(b) shall consist of all testing performed over a 7-day period using Method 6 or 6C and 

Method 3 or 3A. To determine compliance, the arithmetic mean of the results of all the tests shall 

be compared with the applicable standard. 

(h) For the purpose of determining compliance with §60.104(b)(1), the following 

calculation procedures shall be used: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Calculate each 1-hour average concentration (dry, zero percent oxygen, ppmv) of sulfur 

dioxide at both the inlet and the outlet to the add-on control device as specified in §60.13(h). 

These calculations are made using the emission data collected under §60.105(a). 

(2) Calculate a 7-day average (arithmetic mean) concentration of sulfur dioxide for the inlet 

and for the outlet to the add-on control device using all of the 1-hour average concentration 

values obtained during seven successive 24-hour periods. 

(3) Calculate the 7-day average percent reduction using the following equation: 

Rso2 = 100(Cso2(i)−Cso2(o))/Cso2(i) 

where: 

Rso2 = 7-day average sulfur dioxide emission reduction, percent 

Cso2(i) = sulfur dioxide emission concentration determined in §60.106(h)(2) at the inlet to 

the add-on control device, ppmv 

Cso2(o) = sulfur dioxide emission concentration determined in §60.106(h)(2) at the outlet 

to the add-on control device, ppmv 

100 = conversion factor, decimal to percent 

(4) Outlet concentrations of sulfur dioxide from the add-on control device for compliance 

with the 50 ppmv standard, reported on a dry, O2-free basis, shall be calculated using the 

procedures outlined in §60.106(h)(1) and (2) above, but for the outlet monitor only. 

(5) If supplemental sampling data are used for determining the 7-day averages under 

paragraph (h) of this section and such data are not hourly averages, then the value obtained for 

each supplemental sample shall be assumed to represent the hourly average for each hour over 

which the sample was obtained. 

(6) For the purpose of adjusting pollutant concentrations to zero percent oxygen, the 

following equation shall be used: 

Cadj = Cmeas [20.9c/(20.9−%O2)] 

where: 

Cadj = pollutant concentration adjusted to zero percent oxygen, ppm or g/dscm 

Cmeas = pollutant concentration measured on a dry basis, ppm or g/dscm 

20.9c = 20.9 percent oxygen−0.0 percent oxygen (defined oxygen correction basis), percent
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

20.9 = oxygen concentration in air, percent 

%O2 = oxygen concentration measured on a dry basis, percent 

(i) For the purpose of determining compliance with §60.104(b)(2), the following reference 

methods and calculation procedures shall be used except as provided in paragraph (i)(12) of this 

section: 

(1) One 3-hour test shall be performed each day. 

(2) For gases released to the atmosphere from the fluid catalytic cracking unit catalyst 

regenerator: 

(i) Method 8 as modified in §60.106(i)(3) for moisture content and for the concentration of 

sulfur oxides calculated as sulfur dioxide, 

(ii) Method 1 for sample and velocity traverses, 

(iii) Method 2 calculation procedures (data obtained from Methods 3 and 8) for velocity and 

volumetric flow rate, and 

(iv) Method 3 for gas analysis. 

(3) Method 8 shall be modified by the insertion of a heated glass fiber filter between the 

probe and first impinger. The probe liner and glass fiber filter temperature shall be maintained 

above 160 °C (320 °F). The isopropanol impinger shall be eliminated. Sample recovery 

procedures described in Method 8 for container No. 1 shall be eliminated. The heated glass fiber 

filter also shall be excluded; however, rinsing of all connecting glassware after the heated glass 

fiber filter shall be retained and included in container No. 2. Sampled volume shall be at least 1 

dscm. 

(4) For Method 3, the integrated sampling technique shall be used. 

(5) Sampling time for each run shall be at least 3 hours. 

(6) All testing shall be performed at the same location. Where the gases discharged by the 

fluid catalytic cracking unit catalyst regenerator pass through an incinerator-waste heat boiler in 

which auxiliary or supplemental gaseous, liquid, or solid fossil fuel is burned, testing shall be 

conducted at a point between the regenerator outlet and the incinerator-waste heat boiler. An 

alternative sampling location after the waste heat boiler may be used if alternative coke burn-off 

rate equations, and, if requested, auxiliary/supplemental fuel SOX credits, have been submitted to 

and approved by the Administrator prior to sampling. 

(7) Coke burn-off rate shall be determined using the procedures specified under paragraph 

(b)(3) of this section, unless paragraph (i)(6) of this section applies. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(8) Calculate the concentration of sulfur oxides as sulfur dioxide using equation 8-3 in 

Section 6.5 of Method 8 to calculate and report the total concentration of sulfur oxides as sulfur 

dioxide (Csox). 

(9) Sulfur oxides emission rate calculated as sulfur dioxide shall be determined for each test 

run by the following equation: 

Where: 

ESOx = sulfur oxides emission rate calculated as sulfur dioxide, kg/hr (lb/hr) 

CSOx = sulfur oxides emission concentration calculated as sulfur dioxide, g/dscm (gr/dscf) 

Qsd = dry volumetric stack gas flow rate corrected to standard conditions, dscm/hr (dscf/hr) 

K=1,000 g/kg (7,000 gr/lb) 

(10) Sulfur oxides emissions calculated as sulfur dioxide shall be determined for each test 

run by the following equation: 

Where: 

RSOx = Sulfur oxides emissions calculated as kg sulfur dioxide per Mg (lb/ton) coke burn-off. 

ESOx = Sulfur oxides emission rate calculated as sulfur dioxide, kg/hr (lb/hr). 

Rc = Coke burn-off rate, Mg/hr (ton/hr). 

(11) Calculate the 7-day average sulfur oxides emission rate as sulfur dioxide per Mg (ton) 

of coke burn-off by dividing the sum of the individual daily rates by the number of daily rates 

summed. 

(12) An owner or operator may, upon approval by the Administrator, use an alternative 

method for determining compliance with §60.104(b)(2), as provided in §60.8(b). Any requests 

for approval must include data to demonstrate to the Administrator that the alternative method 

would produce results adequate for the determination of compliance. 

(j) For the purpose of determining compliance with §60.104(b)(3), the following analytical 

methods and calculation procedures shall be used: 

(1) One fresh feed sample shall be collected once per 8-hour period. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) Fresh feed samples shall be analyzed separately by using any one of the following 

applicable analytical test methods: ASTM D129-64, 78, or 95, ASTM D1552-83 or 95, ASTM 

D2622-87, 94, or 98, or ASTM D1266-87, 91, or 98. (These methods are incorporated by 

reference: see §60.17.) The applicable range of some of these ASTM methods is not adequate to 

measure the levels of sulfur in some fresh feed samples. Dilution of samples prior to analysis 

with verification of the dilution ratio is acceptable upon prior approval of the Administrator. 

(3) If a fresh feed sample cannot be collected at a single location, then the fresh feed sulfur 

content shall be determined as follows: 

(i) Individual samples shall be collected once per 8-hour period for each separate fresh feed 

stream charged directly into the riser or reactor of the fluid catalytic cracking unit. For each 

sample location the fresh feed volumetric flow rate at the time of collecting the fresh feed sample 

shall be measured and recorded. The same method for measuring volumetric flow rate shall be 

used at all locations. 

(ii) Each fresh feed sample shall be analyzed separately using the methods specified under 

paragraph (j)(2) of this section. 

(iii) Fresh feed sulfur content shall be calculated for each 8-hour period using the following 

equation: 

where: 

Sf = fresh feed sulfur content expressed in percent by weight of fresh feed. 

n = number of separate fresh feed streams charged directly to the riser or reactor of the fluid 

catalytic cracking unit. 

Qf = total volumetric flow rate of fresh feed charged to the fluid catalytic cracking unit. 

Si = fresh feed sulfur content expressed in percent by weight of fresh feed for the “ith” sampling 

location. 

Qi = volumetric flow rate of fresh feed stream for the “ith” sampling location. 

(4) Calculate a 7-day average (arithmetic mean) sulfur content of the fresh feed using all of 

the fresh feed sulfur content values obtained during seven successive 24-hour periods. 

(k) The test methods used to supplement continuous monitoring system data to meet the 

minimum data requirements in §60.104(d) will be used as described below or as otherwise 

approved by the Administrator. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Methods 6, 6B, or 8 are used. The sampling location(s) are the same as those specified 

for the monitor. 

(2) For Method 6, the minimum sampling time is 20 minutes and the minimum sampling 

volume is 0.02 dscm (0.71 dscf) for each sample. Samples are taken at approximately 60-minute 

intervals. Each sample represents a 1-hour average. A minimum of 18 valid samples is required 

to obtain one valid day of data. 

(3) For Method 6B, collection of a sample representing a minimum of 18 hours is required 

to obtain one valid day of data. 

(4) For Method 8, the procedures as outlined in this section are used. The equivalent of 16 

hours of sampling is required to obtain one valid day of data. 

§ 60.107 Reporting and recordkeeping requirements. 

(a) Each owner or operator subject to §60.104(b) shall notify the Administrator of the 

specific provisions of §60.104(b) with which the owner or operator seeks to comply. Notification 

shall be submitted with the notification of initial startup required by §60.7(a)(3). If an owner or 

operator elects at a later date to comply with an alternative provision of §60.104(b), then the 

Administrator shall be notified by the owner or operator in the report described in paragraph (c) 

of this section. 

(b) Each owner or operator subject to §60.104(b) shall record and maintain the following 

information: 

(1) If subject to §60.104(b)(1), 

(i) All data and calibrations from continuous monitoring systems located at the inlet and 

outlet to the control device, including the results of the daily drift tests and quarterly accuracy 

assessments required under appendix F, Procedure 1; 

(ii) Measurements obtained by supplemental sampling (refer to §60.105(a)(13) and 

§60.106(k)) for meeting minimum data requirements; and 

(iii) The written procedures for the quality control program required by appendix F, 

Procedure 1. 

(2) If subject to §60.104(b)(2), measurements obtained in the daily Method 8 testing, or 

those obtained by alternative measurement methods, if §60.106(i)(12) applies. 

(3) If subject to §60.104(b)(3), data obtained from the daily feed sulfur tests. 

(4) Each 7-day rolling average compliance determination. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(c) Each owner or operator subject to §60.104(b) shall submit a report except as provided by 

paragraph (d) of this section. The following information shall be contained in the report: 

(1) Any 7-day period during which: 

(i) The average percent reduction and average concentration of sulfur dioxide on a dry, O2-

free basis in the gases discharged to the atmosphere from any fluid cracking unit catalyst 

regenerator for which the owner or operator seeks to comply with §60.104(b)(1) is below 90 

percent and above 50 ppmv, as measured by the continuous monitoring system prescribed under 

§60.105(a)(8), or above 50 ppmv, as measured by the outlet continuous monitoring system 

prescribed under §60.105(a)(9). The average percent reduction and average sulfur dioxide 

concentration shall be determined using the procedures specified under §60.106(h); 

(ii) The average emission rate of sulfur dioxide in the gases discharged to the atmosphere 

from any fluid catalytic cracking unit catalyst regenerator for which the owner or operator seeks 

to comply with §60.104(b)(2) exceeds 9.8 kg SOX per 1,000 kg coke burn-off, as measured by 

the daily testing prescribed under §60.106(i). The average emission rate shall be determined 

using the procedures specified under §60.106(i); and 

(iii) The average sulfur content of the fresh feed for which the owner or operator seeks to 

comply with §60.104(b)(3) exceeds 0.30 percent by weight. The fresh feed sulfur content, a 7-

day rolling average, shall be determined using the procedures specified under §60.106(j). 

(2) Any 30-day period in which the minimum data requirements specified in §60.104(d) are 

not obtained. 

(3) For each 7-day period during which an exceedance has occurred as defined in 

paragraphs (c)(1)(i) through (c)(1)(iii) and (c)(2) of this section: 

(i) The date that the exceedance occurred; 

(ii) An explanation of the exceedance; 

(iii) Whether the exceedance was concurrent with a startup, shutdown, or malfunction of the 

fluid catalytic cracking unit or control system; and 

(iv) A description of the corrective action taken, if any. 

(4) If subject to §60.104(b)(1), 

(i) The dates for which and brief explanations as to why fewer than 18 valid hours of data 

were obtained for the inlet continuous monitoring system; 

(ii) The dates for which and brief explanations as to why fewer than 18 valid hours of data 

were obtained for the outlet continuous monitoring system; 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) Identification of times when hourly averages have been obtained based on manual 

sampling methods; 

(iv) Identification of the times when the pollutant concentration exceeded full span of the 

continuous monitoring system; and 

(v) Description of any modifications to the continuous monitoring system that could affect 

the ability of the continuous monitoring system to comply with Performance Specifications 2 or 

3. 

(vi) Results of daily drift tests and quarterly accuracy assessments as required under 

appendix F, Procedure 1. 

(5) If subject to §60.104(b)(2), for each day in which a Method 8 sample result required by 

§60.106(i) was not obtained, the date for which and brief explanation as to why a Method 8 

sample result was not obtained, for approval by the Administrator. 

(6) If subject to §60.104(b)(3), for each 8-hour period in which a feed sulfur measurement 

required by §60.106(j) was not obtained, the date for which and brief explanation as to why a 

feed sulfur measurement was not obtained, for approval by the Administrator. 

(d) For any periods for which sulfur dioxide or oxides emissions data are not available, the 

owner or operator of the affected facility shall submit a signed statement indicating if any 

changes were made in operation of the emission control system during the period of data 

unavailability which could affect the ability of the system to meet the applicable emission limit. 

Operations of the control system and affected facility during periods of data unavailability are to 

be compared with operation of the control system and affected facility before and following the 

period of data unavailability. 

(e) For each fuel gas stream combusted in a fuel gas combustion device subject to 

§60.104(a)(1), if an owner or operator determines that one of the exemptions listed in 

§60.105(a)(4)(iv) applies to that fuel gas stream, the owner or operator shall maintain records of 

the specific exemption chosen for each fuel gas stream. If the owner or operator applies for the 

exemption described in §60.105(a)(4)(iv)(D), the owner or operator must keep a copy of the 

application as well as the letter from the Administrator granting approval of the application. 

(f) The owner or operator of an affected facility shall submit the reports required under this 

subpart to the Administrator semiannually for each six-month period. All semiannual reports 

shall be postmarked by the 30th day following the end of each six-month period. 

(g) The owner or operator of the affected facility shall submit a signed statement certifying 

the accuracy and completeness of the information contained in the report. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

§ 60.108 Performance test and compliance provisions. 

(a) Section 60.8(d) shall apply to the initial performance test specified under paragraph (c) 

of this section, but not to the daily performance tests required thereafter as specified in 

§60.108(d). Section 60.8(f) does not apply when determining compliance with the standards 

specified under §60.104(b). Performance tests conducted for the purpose of determining 

compliance under §60.104(b) shall be conducted according to the applicable procedures 

specified under §60.106. 

(b) Owners or operators who seek to comply with §60.104(b)(3) shall meet that standard at 

all times, including periods of startup, shutdown, and malfunctions. 

(c) The initial performance test shall consist of the initial 7-day average calculated for 

compliance with §60.104(b)(1), (b)(2), or (b)(3). 

(d) After conducting the initial performance test prescribed under §60.8, the owner or 

operator of a fluid catalytic cracking unit catalyst regenerator subject to §60.104(b) shall conduct 

a performance test for each successive 24-hour period thereafter. The daily performance tests 

shall be conducted according to the appropriate procedures specified under §60.106. In the event 

that a sample collected under §60.106(i) or (j) is accidentally lost or conditions occur in which 

one of the samples must be discontinued because of forced shutdown, failure of an irreplaceable 

portion of the sample train, extreme meteorological conditions, or other circumstances, beyond 

the owner or operators' control, compliance may be determined using available data for the 7-day 

period. 

(e) Each owner or operator subject to §60.104(b) who has demonstrated compliance with 

one of the provisions of §60.104(b) but a later date seeks to comply with another of the 

provisions of §60.104(b) shall begin conducting daily performance tests as specified under 

paragraph (d) of this section immediately upon electing to become subject to one of the other 

provisions of §60.104(b). The owner or operator shall furnish the Administrator with a written 

notification of the change in the semiannual report required by §60.107(f). 

§ 60.109 Delegation of authority. 

(a) In delegating implementation and enforcement authority to a State under section 111(c) 

of the Act, the authorities contained in paragraph (b) of this section shall be retained by the 

Administrator and not transferred to a State. 

(b) Authorities which shall not be delegated to States: 

(1) Section 60.105(a)(13)(iii), 

(2) Section 60.106(i)(12). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EO12866_RefineryRTR 2060 AQ75 NPRM Part63SubpartY_RegText_20140128 

Subpart Y—National Emission Standards for Marine Tank Vessel Loading Operations 

PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 

FOR SOURCE CATEGORIES 

§ 63.560 Applicability and designation of affected source. 

(a) Maximum achievable control technology (MACT) standards. (1) The provisions of this 

subpart pertaining to the MACT standards in § 63.562(b) and (d) of this subpart are applicable to 

existing and new sources with emissions of 10 or 25 tons, as that term is defined in § 63.561, 

except as specified in paragraph (d) of this section, and are applicable to new sources with 

emissions less than 10 and 25 tons, as that term is defined in § 63.561, except as specified in 

paragraph (d) of this section. 

(2) Existing sources with emissions less than 10 and 25 tons are not subject to the emissions 

standards in § 63.562(b) and (d). 

(3) The recordkeeping requirements of § 63.567(j)(4) and the emission estimation 

requirements of § 63.565(l) apply to existing sources with emissions less than 10 and 25 tons. 

(4) Existing sources with emissions less than 10 and 25 tons must meet the submerged fill 

standards of 46 CFR 153.282. 

(b) Reasonably available control technology (RACT) standards. (1) The provisions of this 

subpart pertaining to RACT standards in § 63.562(c) and (d) of this subpart are applicable to 

sources with throughput of 10 M barrels or 200 M barrels, as that term is defined in § 63.561, 

except as specified in paragraph (d) of this section. 

(2) Sources with throughput less than 10 M barrels and 200 M barrels, as that term is 

defined in § 63.561, are not subject to the emissions standards in § 63.562(c) and (d). 

(c) General Provisions applicability. Owners or operators of affected sources, as that term 

is defined in § 63.561, of this subpart must comply with the requirements of subpart A of this 

part in accordance with the provisions for applicability of subpart A to this subpart in Table 1 of 

this section. 

(d) Exemptions from MACT and RACT standards. (1) This subpart does not apply to 

emissions resulting from marine tank vessel loading operations, as that term is defined in 

§ 63.561, of commodities with vapor pressures less than 10.3 kilopascals (kPa) (1.5 pounds per 

square inch, absolute) (psia) at standard conditions, 20 °C and 760 millimeters Hg (mm Hg). 

Deleted: This submerged fill requirement does not 

apply to petroleum refineries.
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) The provisions of this subpart pertaining to the MACT standards in § 63.562(b)(2), (3) 

and (4) and to the RACT standards in § 63.562(c)(3) and (4) do not apply to marine tank vessel 

loading operations where emissions are reduced by using a vapor balancing system, as that term 

is defined in § 63.561. The provisions pertaining to the vapor collection system, ship-to-shore 

compatibility, and vapor tightness of marine tank vessels in § 63.562(b)(1) and (c)(2) do apply. 

(3) The provisions of this subpart pertaining to the MACT standards in § 63.562(b)(2), (3), 

and (4) do not apply to marine tank vessel loading operations that are contiguous with refinery 

operations at sources subject to and complying with subpart CC of this part, National Emissions 

Standards for Organic Hazardous Air Pollutants from Petroleum Refineries, except to the extent 

that any such provisions of this subpart are made applicable by subpart CC of this part. 

(4) The provisions of this subpart pertaining to the MACT standards in § 63.562(b) and (d) 

do not apply to benzene emissions from marine tank vessel loading operations that are subject to 

and complying with 40 CFR part 61, subpart BB, National Emissions Standards for Benzene 

Emissions from Benzene Transfer Operations, except that benzene emissions or other HAP 

emissions (i.e., nonbenzene HAP emissions) from marine tank vessel loading operations that are 

not subject to subpart BB are subject to the provisions of this subpart. 

(5) The provisions of this subpart pertaining to the MACT standards in § 63.562(b) and (d) 

do not apply to marine tank vessel loading operations at loading berths that only transfer liquids 

containing organic HAP as impurities, as that term is defined in § 63.561. 

(6) The provisions of this subpart do not apply to marine tank vessel loading operations at 

existing offshore loading terminals, as that term is defined in § 63.561, however existing 

offshore loading terminals must meet the submerged fill standards of 46 CFR 153.282. 

(7) The provisions of this subpart do not apply to ballasting operations, as that term is 

defined in § 63.561. 

(e) Compliance dates—(1) MACT standards compliance dates, except the Valdez Marine 

Terminal (VMT) source. (i) A new or existing source with emissions of 10 or 25 tons, except the 

VMT source, and a new source with emissions less than 10 and 25 tons, except the VMT source, 

that has an initial startup date on or before September 20, 1999 shall comply with the provisions 

of this subpart pertaining to the MACT standards in § 63.562(b) no later than 4 years after the 

effective date. 

(ii) A new source with emissions of 10 or 25 tons, except the VMT source, and a new 

source with emissions less than 10 and 25 tons, except the VMT source, that has an initial startup 

date after September 20, 1999 shall comply with provisions of this subpart pertaining to the 

MACT standards in § 63.562(b) immediately upon startup. 

(iii) A source with emissions less than 10 and 25 tons that increases its emissions 

subsequent to September 20, 1999 such that it becomes a source with emissions of 10 or 25 tons 

shall comply with the provisions of this subpart pertaining to the MACT standards in § 63.562(b) 

within 3 years following the exceedance of the threshold level. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iv) Existing sources with emissions less than 10 and 25 tons, and existing offshore loading 

terminals, shall comply with the submerged fill requirements in paragraph (a)(4) and (d)(6) of 

this section by April 23, 2012. 

(2) RACT standards compliance dates, except the VMT source. (i) A source with throughput 

of 10 M barrels or 200 M barrels, except the VMT source, with an initial startup date on or 

before September 21, 1998 shall comply with § 63.562(c)(1) no later than 2 years after the 

effective date. 

(ii) A source with throughput of 10 M barrels or 200 M barrels, except the VMT source, 

with an initial startup date on or before September 21, 1998 shall comply with the provisions of 

this subpart pertaining to the RACT standards in § 63.562(c) other than § 63.562(c)(1), no later 

than 3 years after the effective date. 

(iii) A source with throughput of 10 M barrels or 200 M barrels, except the VMT source, 

with an initial startup date after September 21, 1998 shall comply with the provisions of this 

subpart pertaining to the RACT standards in § 63.562(c) immediately upon startup. 

(iv) A source with throughput less than 10 M barrels and 200 M barrels that increases its 

throughput subsequent to September 21, 1998 such that it becomes a source with throughput of 

10 M barrels or 200 M barrels shall comply with the provisions of this subpart pertaining to the 

RACT standards in § 63.562(c) within 3 years following the exceedance of the threshold levels. 

(v) A source with throughput of 10 M barrels or 200 M barrels may apply for approval from 

the Administrator for an extension of the compliance date of up to 1 year if it can demonstrate 

that the additional time is necessary for installation of the control device. 

(3) MACT and RACT compliance dates for the VMT source. The VMT source, as that term 

is defined in § 63.561, shall comply with the provisions of this subpart pertaining to the MACT 

and RACT standards in § 63.562(d) no later than 30 months after the effective date. 

TABLE 1 TO § 63.560—GENERAL PROVISIONS APPLICABILITY TO SUBPART Y 

Reference 

Applies to 

affected 

sources in 

subpart Y Comment 

63.1(a)(1) Yes Additional terms are defined in § 63.561; when overlap 

between subparts A and Y occurs, subpart Y takes 

precedence. 

63.1(a)(2) Yes 

63.1(a)(3) Yes 

63.1(a)(4) Yes Subpart Y clarifies the applicability of each paragraph in 

subpart A to sources subject to subpart Y in this table. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

.63.1(a)(5) No Reserved. 

63.1(a)(6) Yes 

63.1(a)(7) Yes 

63.1(a)(8) Yes 

63.1(a)(9) No Reserved. 

63.1(a)(10) Yes 

63.1(a)(11) Yes § 63.567(a) also allows report submissions via facsimile 

and on electronic media. 

63.1(a)(12) Yes 

63.1(a)(13) Yes 

63.1(a)(14) Yes 

63.1(b)(1) Yes 

63.1(b)(2) Yes 

63.1(b)(3) No § 63.560 specifies applicability. 

63.1(c)(1) Yes Subpart Y clarifies the applicability of each paragraph in 

subpart A to sources subject to subpart Y in this table. 

63.1(c)(2) Yes Subpart Y is not applicable to area sources. 

63.1(c)(3) No Reserved. 

63.1(c)(4) Yes 

63.1(c)(5) No § 63.560 specifies applicability. 

63.1(d) No Reserved. 

63.1(e) Yes 

63.2 Yes Additional terms are defined in § 63.561; when overlap 

between subparts A and Y occurs, subpart Y takes 

precedence. 

63.3 Yes Other units used in subpart Y are defined in the text of 

subpart Y. 

63.4(a)(1) Yes 

63.4(a)(2) Yes 

63.4(a)(3) Yes 

63.4(a)(4) No Reserved. 

63.4(a)(5) Yes 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

63.4(b) Yes 

63.4(c) Yes 

63.5(a) Yes 

63.5(b)(1)(i) Yes 

63.5(b)(1)(ii) No 

63.5(b)(2) No Reserved. 

63.5(b)(3) Yes 

63.5(b)(4)-(5) No 

63.5(b)(6) Yes 

63.5(c) No Reserved. 

63.5(d)(1)(i) No See § 63.566(b)(2). 

63.5(d)(1)(ii)(A)(H) Yes 

63.5(d)(1)(ii)(I) No Reserved. 

63.5(d)(1)(ii)(J) Yes 

63.5(d)(1)(iii) Yes 

63.5(d)(2)-(4) Yes 

63.5(e) Yes 

63.5(f)(1)(i) and (ii) Yes 

63.5(f)(1)(iii) and 

(iv) 

No 

63.5(f)(2) No See § 63.566(c). 

63.6(a)(1) Yes 

63.6(a)(2) No § 63.560 specifies applicability. 

63.6(b)(1)-(5) No § 63.560(e) specifies compliance dates for sources. 

63.6(b)(6) No Reserved. 

63.6(b)(7) No § 63.560(e) specifies compliance dates for sources. 

63.6(c)(1) No § 63.560(e) specifies compliance dates for sources. 

63.6(c)(2) No 

63.6(c)(3)-(4) No Reserved. 

63.6(c)(5) No § 63.560(e) specifies compliance dates for sources. 

63.6(d) No Reserved. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

63.6(e) No See § 63.562(e). 

63.6(f)(1) No. 

63.6(f)(2)(i) Yes 

63.6(f)(2)(ii) No 

63.6(f)(2)(iii) Yes 

63.6(f)(2)(iv) Yes 

63.6(f)(2)(v) No See § 63.562(e)(1). 

63.6(f)(3) Yes 

63.6(g) Yes 

63.6(h) No No opacity monitoring is required under subpart Y. 

63.6(i)(1)-(3) Yes 

63.6(i)(4)(i)(A) No 

63.6(i)(4)(i)(B) Yes 

63.6(i)(4)(ii) No 

63.6(i)(5)-(12) Yes 

63.6(i)(13) No 

63.6(i)(14) Yes 

63.6(i)(15) No Reserved. 

63.6(i)(16) Yes 

63.6(j) Yes 

63.7(a)(1) Yes 

63.7(a)(2)(i)-(iv) No See § 63.563(b)(1). 

63.7(a)(2)(v) Yes 

63.7(a)(2)(vi) No 

63.7(a)(2)(vii)-(viii) No Reserved. 

63.7(a)(2)(ix) No 

63.7(a)(3) Yes 

63.7(b) Yes 

63.7(c)(1)-(2) Yes The site-specific test plan must be submitted only if 

requested by the Administrator. 

63.7(c)(3)(i)-(ii)(A) Yes 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

63.7(c)(3)(ii)(B) No See § 63.565(m)(2). 

63.7(c)(3)(iii) Yes 

63.7(c)(4) Yes 

63.7(d) Yes 

63.7(e)(1) No See 63.563(b)(1). Any cross reference to 63.7(e)(1) in any 

other general provision incorporated by reference shall be 

treated as a cross-reference to 63.563(b)(1). 

63.7(e)(2)-(4) Yes. 

63.7(f) Yes 

63.7(g)(1) Yes 

63.7(g)(2) No Reserved. 

63.7(g)(3) Yes 

63.7(h) Yes 

63.8(a)(1)-(2) Yes 

63.8(a)(3) No Reserved. 

63.8(a)(4) Yes 

63.8(b)(1) Yes 

63.8(b)(2) No 

63.8(b)(3) Yes 

63.8(c)(1) No. 

63.8(c)(2) Yes 

63.8(c)(3) Yes 

63.8(c)(4) No See § 63.564(a)(3). 

63.8(c)(5) No 

63.8(c)(6) Yes See also performance specifications for continuous 

monitoring systems § 63.564(a)(4). 

63.8(c)(7)(i)(A)-(B) Yes See also § 63.564(a)(5). 

63.8(c)(7)(i)(C) No 

63.8(c)(7)(ii) Yes 

63.8(c)(8) No See § 63.564(a)(5). 

63.8(d) No See § 63.562(e)(2)(iv). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

63.8(e)(1)-(4) Yes 

63.8(e)(5)(i) Yes 

63.8(e)(5)(ii) No 

63.8(f)(1) Yes 

63.8(f)(2)(i)-(vii) Yes 

63.8(f)(2)(viii) No 

63.8(f)(2)(ix) Yes 

63.8(f)(3)-(6) Yes 

63.8(g) Yes 

63.9(a)(1) Yes 

63.9(a)(2) Yes 

63.9(a)(3) Yes 

63.9(a)(4) Yes 

63.9(b)(1)(i) Yes 

63.9(b)(1)(ii) No See § 63.567(b)(1) 

63.9(b)(1)(iii) Yes 

63.9(b)(2) No See § 63.567(b)(2). 

63.9(b)(3) No See § 63.567(b)(3). 

63.9(b)(4) No See § 63.567(b)(4). 

63.9(b)(5) No See § 63.567(b)(4). 

63.9(c) No See § 63.567(c). 

63.9(d) No 

63.9(e) Yes 

63.9(f) No 

63.9(g)(1) Yes 

63.9(g)(2) No 

63.9(g)(3) Yes 

63.9(h)(1)-(3) Yes 

63.9(h)(4) No Reserved. 

63.9(h)(5)-(6) Yes 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

63.9(i) Yes 

63.9(j) Yes 

63.10(a) Yes 

63.10(b)(1) Yes 

63.10(b)(2)(i)-(ii) No See 63.567(m). 

63.10(b)(2)(iii) Yes. 

63.10(b)(2)(iv) No 

63.10(b)(2)(v) No 

63.10(b)(2)(vi)-

(xiv) 

Yes 

63.10(b)(3) No See § 63.567(j)(4). 

63.10(c)(1) Yes 

63.10(c)(2)-(4) No Reserved. 

63.10(c)(5) Yes 

63.10(c)(6) No See § 63.564(a)(5). 

63.10(c)(7) No 

63.10(c)(8) Yes 

63.10(c)(9) No Reserved. 

63.10(c)(10)-(11) No See 63.567(m) for reporting malfunctions. Any crossreference to 63.10(c)(10) or 63.10(c)(11) in any other 

general provision incorporated by reference shall be treated 

as a cross-reference to 63.567(m). 

63.10(c)(12)-(13) Yes. 

63.10(c)(14) No See § 63.562(d)(2)(iv). 

63.10(c)(15) No 

63.10(d)(1)-(2) Yes 

63.10(d)(3) No See § 63.567(d). 

63.10(d)(4) Yes 

63.10(d)(5) No 

63.(10)(e)(1) Yes 

63.10(e)(2)(i) Yes 

63.10(e)(2)(ii) No 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

63.10(e)(3)(i)-(v) No See § 63.567(e) 

63.10(e)(3)(vi). Yes 

63.10(e)(3)(vii)-

(viii) 

No See § 63.567(e) 

63.10(e)(4) No 

63.10(f) Yes 

63.11 Yes 

63.12-63.15 Yes 

§ 63.561 Definitions. 

As used in this subpart, all terms not defined herein shall have the meaning given them in 

the Clean Air Act or in subpart A of this part. 

Affected source means a source with emissions of 10 or 25 tons, a new source with 

emissions less than 10 and 25 tons, a new major source offshore loading terminal, a source with 

throughput of 10 M barrels or 200 M barrels, or the VMT source, that is subject to the emissions 

standards in § 63.562. 

Affirmative defense means, in the context of an enforcement proceeding, a response or a 

defense put forward by a defendant, regarding which the defendant has the burden of proof, and 

the merits of which are independently and objectively evaluated in a judicial or administrative 

proceeding. 

Air pollution control device or control device means a combustion device or vapor recovery 

device. 

Ballasting operations means the introduction of ballast water into a cargo tank of a tankship 

or oceangoing barge. 

Baseline operating parameter means a minimum or maximum value of a process parameter, 

established for a control device during a performance test where the control device is meeting the 

required emissions reduction or established as the manufacturer recommended operating 

parameter, that, if achieved by itself or in combination with one or more other operating 

parameters, determines if a control device is operating properly. 

Boiler means a device that combusts any fuel and produces steam or heats water or any 

other heat transfer medium. This term includes any duct burner that combusts fuel and is part of 

a combined cycle system. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Car-seal means a seal that is placed on a device used to change the position of a valve (e.g., 

from open to closed) in such a way that the position of the valve cannot be changed without 

breaking the seal. 

Combustion device means all equipment, including, but not limited to, thermal incinerators, 

catalytic incinerators, flares, boilers, and process heaters used for combustion or destruction of 

organic vapors. 

Commenced means, with respect to construction of an air pollution control device, that an 

owner or operator has undertaken a continuous program of construction or that an owner or 

operator has entered into a contractual obligation to undertake and complete, within a reasonable 

time, a continuous program of construction. 

Commodity means a distinct product that a source loads onto marine tank vessels. 

Continuous means, with respect to monitoring, reading and recording (either in hard copy or 

computer readable form) of data values measured at least once every 15 minutes. 

Crude oil means a naturally occurring mixture consisting predominantly of hydrocarbons 

and/or sulfur, nitrogen, and oxygen derivatives of hydrocarbons that is removed from the earth in 

a liquid state or is capable of being so removed. 

Exceedance or Variance means, with respect to parametric monitoring, the operating 

parameter of the air pollution control device that is monitored as an indication of proper 

operation of the control device is outside the acceptable range or limits for the baseline 

parameter given in § 63.563(b)(4) through (9). 

Excess emissions means, with respect to emissions monitoring, the concentration of the 

outlet stream of the air pollution control device is outside the acceptable range or limits for the 

baseline concentration given in § 63.563(b)(4) through (9). 

Flow indicator means a device that indicates whether gas flow is present in a line or vent 

system. 

Gasoline means any petroleum distillate or petroleum distillate/alcohol blend having a Reid 

vapor pressure of 27.6 kPa (4.0 psia) or greater, that is used as a fuel for internal combustion 

engines. 

Impurity means HAP substances that are present in a commodity or that are produced in a 

process coincidentally with the primary product or commodity and that are 0.5 percent total HAP 

by weight or less. An impurity does not serve a useful purpose in the production or use of the 

primary product or commodity and is not isolated. 

Leak means a reading of 10,000 parts per million volume (ppmv) or greater as methane that 

is determined using the test methods in Method 21, appendix A of part 60 of this chapter. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Lightering or Lightering operation means the offshore transfer of a bulk liquid cargo from 

one marine tank vessel to another vessel. 

Loading berth means the loading arms, pumps, meters, shutoff valves, relief valves, and 

other piping and valves necessary to fill marine tank vessels. The loading berth includes those 

items necessary for an offshore loading terminal. 

Loading cycle means the time period from the beginning of filling a single marine tank 

vessel until commodity flow to the marine tank vessel ceases. 

Maintenance allowance means a period of time that an affected source is allowed to 

perform maintenance on the loading berth without controlling emissions from marine tank vessel 

loading operations. 

Marine tank vessel loading operation means any operation under which a commodity is 

bulk loaded onto a marine tank vessel from a terminal, which may include the loading of 

multiple marine tank vessels during one loading operation. Marine tank vessel loading operations 

do not include refueling of marine tank vessels. 

Marine vessel or Marine tank vessel means any tank ship or tank barge that transports liquid 

product such as gasoline or crude oil in bulk. 

Nonvapor-tight means any marine tank vessel that does not pass the required vaportightness test. 

Offshore loading terminal means a location that has at least one loading berth that is 0.81 

km (0.5 miles) or more from the shore that is used for mooring a marine tank vessel and loading 

liquids from shore. 

Primary fuel means the fuel that provides the principal heat input to the device. To be 

considered primary, the fuel must be able to sustain operation of the device without the addition 

of other fuels. 

Process heater means a device that transfers heat liberated by burning fuel to fluids 

contained in tubes, including all fluids except water that are heated to produce steam. 

Recovery device means an individual unit of equipment, including, but not limited to, a 

carbon adsorber, condenser/refrigeration unit, or absorber that is capable of and used for the 

purpose of removing vapors and recovering liquids or chemicals. 

Routine loading means, with respect to the VMT source, marine tank vessel loading 

operations that occur as part of normal facility operation over a loading berth when no loading 

berths are inoperable due to maintenance. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Secondary fuel means any fuel other than the primary fuel. The secondary fuel provides 

supplementary heat in addition to the heat provided by the primary fuel and is generally fired 

through a burner other than the primary burner. 

Source(s) means any location where at least one dock or loading berth is bulk loading onto 

marine tank vessels, except offshore drilling platforms and lightering operations. 

Source(s) with emissions less than 10 and 25 tons means major source(s) having aggregate 

actual HAP emissions from marine tank vessel loading operations at all loading berths as 

follows: 

(1) Prior to the compliance date, of less than 9.1 Mg (10 tons) of each individual HAP 

calculated on a 24-month annual average basis after September 19, 1997 and less than 22.7 Mg 

(25 tons) of all HAP combined calculated on a 24-month annual average basis after September 

19, 1997, as determined by emission estimation in § 63.565(l) of this subpart; and 

(2) After the compliance date, of less than 9.1 Mg (10 tons) of each individual HAP 

calculated annually after September 20, 1999 and less than 22.7 Mg (25 tons) of all HAP 

combined calculated annually after September 20, 1999, as determined by emission estimation in 

§ 63.565(l) of this subpart. 

Source(s) with emissions of 10 or 25 tons means major source(s) having aggregate actual 

HAP emissions from marine tank vessels loading operations at all loading berths as follows: 

(1) Prior to the compliance date, emissions of 9.1 Mg (10 tons) or more of each individual 

HAP calculated on a 24-month annual average basis after September 19, 1997 or of 22.7 Mg (25 

tons) or more of all HAP combined calculated on a 24-month annual average basis after 

September 19, 1997, as determined by emission estimation in § 63.565(l); or 

(2) After the compliance date, emissions of 9.1 Mg (10 tons) or more of each individual 

HAP calculated annually after September 20, 1999 or of 22.7 Mg (25 tons) or more of all HAP 

combined calculated annually after September 20, 1999, as determined by emission estimation in 

§ 63.565(l). 

Source(s) with throughput less than 10 M barrels and 200 M barrels means source(s) 

having aggregate loading from marine tank vessel loading operations at all loading berths as 

follows: 

(1) Prior to the compliance date, of less than 1.6 billion liters (10 million (M) barrels) of 

gasoline on a 24-month annual average basis and of less than 32 billion liters (200 M barrels) of 

crude oil on a 24-month annual average basis after September 19, 1996; and 

(2) After the compliance date, of less than 1.6 billion liters (10 M barrels) of gasoline 

annually and of less than 32 billion liters (200 M barrels) of crude oil annually after September 

21, 1998. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Source(s) with throughput of 10 M barrels or 200 M barrels means source(s) having 

aggregate loading from marine tank vessel loading operations at all loading berths as follows: 

(1) Prior to the compliance date, of 1.6 billion liters (10 M barrels) or more of gasoline on a 

24-month annual average basis or of 32 billion liters (200 M barrels) or more of crude oil on a 

24-month annual average basis after September 19, 1996; or 

(2) After the compliance date, of 1.6 billion liters (10 M barrels) or more of gasoline 

annually or of 32 billion liters (200 M barrels) or more of crude oil annually after September 21, 

1998. 

Terminal means all loading berths at any land or sea based structure(s) that loads liquids in 

bulk onto marine tank vessels. 

Twenty-four-month (24-month) annual average basis means annual HAP emissions, with 

respect to MACT standards, or annual loading throughput, with respect to RACT standards, from 

marine tank vessel loading operations averaged over a 24-month period. 

Valdez Marine Terminal (VMT) source means the major source that is permitted under the 

Trans-Alaska Pipeline Authorization Act (TAPAA) (43 U.S.C. § 1651 et seq. ). The source is 

located in Valdez, Alaska in Prince William Sound. 

Vapor balancing system means a vapor collection system or piping system that is designed 

to collect organic HAP vapors displaced from marine tank vessels during marine tank vessel 

loading operations and that is designed to route the collected organic HAP vapors to the storage 

vessel from which the liquid being loaded originated or to compress collected organic HAP 

vapors and commingle with the raw feed of a process unit. 

Vapor collection system means any equipment located at the source, i.e., at the terminal, 

that is not open to the atmosphere, that is composed of piping, connections, and flow inducing 

devices, and that is used for containing and transporting vapors displaced during the loading of 

marine tank vessels to a control device or for vapor balancing. This does not include the vapor 

collection system that is part of any marine vessel vapor collection manifold system. 

Vapor-tight marine vessel means a marine tank vessel that has demonstrated within the 

preceding 12 months to have no leaks. A marine tank vessel loaded at less than atmospheric 

pressure is assumed to be vapor tight for the purpose of this standard. 

Volatile organic compounds or VOC is as defined in 40 CFR 51.100(s) of this chapter. 

§ 63.562 Standards. 

(a) The emissions limitations in paragraphs (b), (c), and (d) of this section apply during 

marine tank vessel loading operations. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(b) MACT standards, except for the VMT source —(1)(i) Vapor collection system of the 

terminal. The owner or operator of a new source with emissions less than 10 and 25 tons and an 

existing or new source with emissions of 10 or 25 tons shall equip each terminal with a vapor 

collection system that is designed to collect HAP vapors displaced from marine tank vessels 

during marine tank vessel loading operations and to prevent HAP vapors collected at one loading 

berth from passing through another loading berth to the atmosphere, except for those 

commodities exempted under § 63.560(d). 

(ii) Ship-to-shore compatibility. The owner or operator of a new source with emissions less 

than 10 and 25 tons and an existing or new source with emissions of 10 or 25 tons shall limit 

marine tank vessel loading operations to those vessels that are equipped with vapor collection 

equipment that is compatible with the terminal's vapor collection system, except for those 

commodities exempted under § 63.560(d). 

(iii) Vapor tightness of marine vessels. The owner or operator of a new source with 

emissions less than 10 and 25 tons and an existing or new source with emissions of 10 or 25 tons 

shall limit marine tank vessel loading operations to those vessels that are vapor tight and to those 

vessels that are connected to the vapor collection system, except for those commodities 

exempted under § 63.560(d). 

(2) MACT standards for existing sources with emissions of 10 or 25 tons. The owner or 

operator of an existing source with emissions of 10 or 25 tons, except offshore loading terminals 

and the VMT source, shall reduce captured HAP emissions from marine tank vessel loading 

operations by 97 weight-percent, as determined using methods in § 63.565 (d) and (l). 

(3) MACT standards for new sources. The owner or operator of a new source with 

emissions less than 10 and 25 tons or a new source with emissions of 10 or 25 tons, except 

offshore loading terminals and the VMT source, shall reduce HAP emissions from marine tank 

vessel loading operations by 98 weight-percent, as determined using methods in § 63.565 (d) and 

(l). 

(4) MACT standards for new major source offshore loading terminals. The owner or 

operator of a new major source offshore loading terminal shall reduce HAP emissions from 

marine tank vessel loading operations by 95 weight-percent, as determined using methods in 

§ 63.565 (d) and (l). 

(5) Prevention of carbon adsorber emissions during regeneration. The owner or operator of 

a source subject to paragraph (b)(2), (3), or (4) shall prevent HAP emissions from escaping to the 

atmosphere from the regeneration of the carbon bed when using a carbon adsorber to control 

HAP emissions from marine tank vessel loading operations. 

(6) Maintenance allowance for loading berths. The owner or operator of a source subject to 

paragraph (b)(2), (3) or (4), may apply for approval to the Administrator for a maintenance 

allowance for loading berths based on a percent of annual throughput or annual marine tank 

vessel loading operation time for commodities not exempted in § 63.560(d). The owner or 

operator shall maintain records for all maintenance performed on the air pollution control 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

equipment. The Administrator will consider the following in approving the maintenance 

allowance: 

(i) The owner or operator expects to be in violation of the emissions standards due to 

maintenance; 

(ii) Due to conditions beyond the reasonable control of the owner or operator, compliance 

with the emissions standards during maintenance would result in unreasonable economic 

hardship; 

(iii) The economic hardship cannot be justified by the resulting air quality benefit; 

(iv) The owner or operator has given due consideration to curtailing marine vessel loading 

operations during maintenance; 

(v) During the maintenance allowance, the owner or operator will endeavor to reduce 

emissions from other loading berths that are controlled as well as from the loading berth the 

owner or operator is seeking the maintenance allowance; and 

(vi) During the maintenance allowance, the owner or operator will monitor and report 

emissions from the loading berth to which the maintenance allowance applies. 

(c) RACT standards, except the VMT source —(1) Commencement of construction. The 

owner or operator of a source with throughput of 10 M barrels or 200 M barrels, except the VMT 

source, with an initial startup date on or before September 21, 1998 shall provide the Agency no 

later than 2 years after the effective date with proof that it has commenced construction of its 

vapor collection system and air pollution control device. 

(2)(i) Vapor collection system of the terminal. The owner or operator of a source with 

throughput of 10 M barrels or 200 M barrels shall equip each terminal with a vapor collection 

system that is designed to collect VOC vapors displaced from marine tank vessels during loading 

and to prevent VOC vapors collected at one loading berth from passing through another loading 

berth to the atmosphere, except for those commodities exempted under § 63.560(d). 

(ii) Ship-to-shore compatibility. The owner or operator of a source with throughput of 10 M 

barrels or 200 M barrels shall limit marine tank vessel loading operations to those vessels that are 

equipped with vapor collection equipment that is compatible with the terminal's vapor collection 

system, except for those commodities exempted under § 63.560(d). 

(iii) Vapor tightness of marine vessels. The owner or operator of a source with throughput 

of 10 M barrels or 200 M barrels shall limit marine tank vessel loading operations to those 

vessels that are vapor-tight and to those vessels that are connected to the vapor collection system, 

except for those commodities exempted under § 63.560(d). 

(3) RACT standard for sources with throughput of 10 M or 200 M barrels, except the VMT 

source. The owner or operator of a source with throughput of 10 M barrels or 200 M barrels, 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

except the VMT source, shall reduce captured VOC emissions from marine tank vessel loading 

operations by 98 weight-percent when using a combustion device or reduce captured VOC 

emissions by 95 weight-percent when using a recovery device, as determined using methods in 

§ 63.565(d) and (l). 

(4) The owner or operator of a source with throughput of 10 M barrels or 200 M barrels, 

except the VMT source, may meet the requirements of paragraph (c)(3) by reducing gasoline 

loading emissions to, at most, 1,000 ppmv outlet VOC concentration. 

(5) Prevention of carbon adsorber emissions during regeneration. The owner or operator of 

a source with throughput of 10 M barrels or 200 M barrels shall prevent HAP emissions from 

escaping to the atmosphere from the regeneration of the carbon bed when using a carbon 

adsorber to control HAP emissions from marine tank vessel loading operations. 

(6) Maintenance allowance for loading berths. The owner or operator of a source with 

throughput of 10 M barrels or 200 M barrels may apply for approval to the Administrator for a 

maintenance allowance for loading berths based on a percent of annual throughput or annual 

marine tank vessel loading operation time for commodities not exempted in § 63.560(d). The 

owner or operator shall maintain records for all maintenance performed on the air pollution 

control equipment. The Administrator will consider the following in approving the maintenance 

allowance: 

(i) The owner or operator expects to be in violation of the emissions standards due to 

maintenance; 

(ii) Due to conditions beyond the reasonable control of the owner or operator, compliance 

with the emissions standards during maintenance would result in unreasonable economic 

hardship; 

(iii) The economic hardship cannot be justified by the resulting air quality benefit; 

(iv) The owner or operator has given due consideration to curtailing marine vessel loading 

operations during maintenance; 

(v) During the maintenance allowance, the owner or operator will endeavor to reduce 

emissions from other loading berths that are controlled as well as from the loading berth the 

owner or operator is seeking the maintenance allowance; and 

(vi) During the maintenance allowance, the owner or operator will monitor and report 

emissions from the loading berth to which the maintenance allowance applies. 

(d) MACT and RACT standards for the VMT source —(1)(i) Vapor collection system of the 

terminal. The owner or operator of the VMT source shall equip each terminal subject under 

paragraph (d)(2) with a vapor collection system that is designed to collect HAP vapors displaced 

from marine tank vessels during marine tank vessel loading operations and to prevent HAP 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

vapors collected at one loading berth from passing through another loading berth to the 

atmosphere, except for those commodities exempted under § 63.560(d). 

(ii) Ship-to-shore compatibility. The owner or operator of the VMT source shall limit 

marine tank vessel loading operations at berths subject under paragraph (d)(2) of this section to 

those vessels that are equipped with vapor collection equipment that is compatible with the 

terminal's vapor collection system, except for those commodities exempted under § 63.560(d). 

(iii) Vapor tightness of marine vessels. The owner or operator of the VMT source shall limit 

marine tank vessel loading operations at berths subject under paragraph (d)(2) of this section to 

those vessels that are vapor-tight and to those vessels that are connected to the vapor collection 

system, except for those commodities exempted under § 63.560(d). 

(2) The owner or operator of the VMT source shall reduce captured HAP and VOC 

emissions by 98 weight-percent, as determined using methods in § 63.565(d) and (l) for loading 

berths subject under this paragraph according to paragraphs (d)(2)(i), (ii), (iii), and (iv): 

(i) The owner or operator of the VMT source shall equip at least two loading berths and any 

additional berths indicated pursuant to paragraph (d)(2)(iii) with a vapor collection system and 

air pollution control device and shall load marine tank vessels over loading berths equipped with 

a vapor collection system and control device to the maximum extent practicable. The owner or 

operator shall equip all loading berths that will be used for routine loading after March 19, 1998 

with a vapor collection system and control device if the annual average daily loading rate for all 

loading berths exceeds the limits in paragraphs (d)(2)(i)(A), (B), and (C) of this section. 

(A) For 1995, 1,630,000 barrels per day; and 

(B) For 1996, 1,546,000 barrels per day; and 

(C) For 1997, 1,445,000 barrels per day. 

(ii) Maximum extent practicable means that the total annual average daily loading over all 

loading berths not equipped with a vapor collection system and control device shall not exceed 

the totals in paragraphs (d)(2)(ii)(A) and (B): 

(A) Loading allowances for marine tank vessel loading operations at loading berths not 

equipped with control devices. The following maximum annual average daily loading rate for 

routine loading at loading berths not equipped with control devices in any of the following years 

shall not exceed: 

( 1 ) For 1998, 275,000 barrels per day; 

( 2 ) For 1999, 205,000 barrels per day; 

( 3 ) For 2000, 118,000 barrels per day; 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

( 4 ) For 2001, 39,000 barrels per day; and 

( 5 ) For 2002 and subsequent years, no marine tank vessel loading operations shall be 

performed at berths not equipped with a vapor collection system and control device, except as 

allowed for maintenance under paragraph (B). 

(B) Maintenance allowances for loading berths subject under paragraph (d)(2)(i).

Beginning in the year 2000, the owner or operator of the VMT source may have a maximum of 

40 calendar days per calendar year use of loading berths not equipped with a vapor collection 

system and control device, in accordance with the limits in paragraph (d)(2)(ii)(B)( a ), ( b ), or ( 

c ), to allow for maintenance of loading berths subject to paragraph (d)(2)(i). Beginning in the 

year 2002, the total annual average daily loading of crude oil over all loading berths not 

equipped with a vapor collection system and control device shall not exceed the amount stated in 

paragraph (d)(2)(ii)(B)( b ). The 40 days allowed for maintenance shall be converted into a 

compliance measure of annual average daily loading over the loading berths not equipped with a 

vapor collection system and control device as follows: 

( 1 ) If the total annual average daily volume of crude oil loaded at the facility was greater 

than or equal to 1,100,000 barrels per day in the prior calendar year, the maintenance allowance 

shall not exceed an annual average daily loading of 60,000 barrels per day. 

( 2 ) If the total annual average daily volume of crude oil loaded at the facility was less than 

1,100,000 barrels per day and greater than or equal to 550,000 barrels per day in the prior 

calendar year, the maintenance allowance for the calendar year shall not exceed Qm : 

Where: 

Qm = maintenance allowance, barrels per day 

P = prior calendar year's average daily volume of crude oil loaded at the facility, barrels per day. 

( 3 ) If the total annual average daily volume of crude oil loaded at the facility was less than 

550,000 barrels per day in the prior calendar year, there shall be no maintenance allowance. 

(iii) If the average daily loading rate for the loading berths not equipped with a vapor 

collection system and control device is greater than the combined amounts in any year listed in 

paragraphs (d)(2)(i)(A), (B), and (C) and (d)(2)(ii)(A) and (B), then the owner or operator of the 

VMT source shall equip all loading berths used for routine loading with a vapor collection 

system and control device within 2 years of the exceedance except that in an emergency situation 

the Administrator may, instead of requiring controls, approve an alternative plan to reduce 

loading over the unequipped berth(s) to a level which will ensure compliance with the applicable 

limit. Beginning in the year 2002, the owner or operator of the VMT source shall equip all 

uncontrolled loading berths used for marine tank vessel loading operations beyond the 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

maintenance allowance in paragraph (d)(2)(ii)(B) with a vapor collection system and control 

device. 

(iv) The owner or operator of the VMT source shall develop a program to communicate to 

relevant facility operations and marine transportation personnel and engage their active and 

consistent participation in honoring the intent and goal of minimizing loaded volumes over the 

unequipped berths and maximizing the loaded volumes at the berths equipped with a vapor 

collection system and control device to prevent exceedance of the load volume limits in 

paragraphs (d)(2)(ii)(A) and (B). This program is to be presented semi-annually during the first 

year of compliance and annually thereafter until the use of unequipped berths for routine loading 

is no longer required. 

(e) Operation and maintenance requirements for air pollution control equipment and 

monitoring equipment for affected sources. At all times, owners or operators of affected sources 

shall operate and maintain a source, including associated air pollution control equipment, in a 

manner consistent with safety and good air pollution control practices for minimizing emissions. 

Determination of whether acceptable operation and maintenance procedures are being used will 

be based on information available to the Administrator which may include, but is not limited to, 

monitoring results, review of operation and maintenance procedures, review of operation and 

maintenance records, and inspection of the source. 

(1) The Administrator will determine compliance with design, equipment, work practice, or 

operational emission standards by evaluating an owner or operator's conformance with operation 

and maintenance requirements. 

(2) The owner or operator of an affected source shall develop a written operation and 

maintenance plan that describes in detail a program of corrective action for varying (i.e., 

exceeding baseline parameters) air pollution control equipment and monitoring equipment, based 

on monitoring requirements in § 63.564, used to comply with these emissions standards. The 

plan shall also identify all routine or otherwise predictable continuous monitoring system 

(thermocouples, pressure transducers, continuous emissions monitors (CEMS), etc.) variances. 

(i) The plan shall specify procedures (preventive maintenance) to be followed to ensure that 

pollution control equipment and monitoring equipment functions properly and variances of the 

control equipment and monitoring equipment are minimal. 

(ii) The plan shall identify all operating parameters to be monitored and recorded for the air 

pollution control device as indicators of proper operation and shall establish the frequency at 

which the parameters will be monitored (see § 63.564). 

(iii) Owners or operators of affected sources shall incorporate a standardized inspection 

schedule for each component of the control device used to comply with the emissions standards 

in § 63.562(b), (c), and (d). To satisfy the requirements of this paragraph, the owner or operator 

may use the inspection schedule recommended by the vendor of the control system or any other 

technical publication regarding the operation of the control system. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iv) Owners or operators shall develop and implement a continuous monitoring system 

(CMS) quality control program. The owner or operator shall develop and submit to the 

Administrator for approval upon request a site-specific performance evaluation test plan for the 

CMS performance evaluation required in § 63.8(e) of subpart A of this part. Each quality control 

program shall include, at a minimum, a written protocol that describes procedures for initial and 

any subsequent calibration of the CMS; determination and adjustment of the calibration drift of 

the CMS; preventive maintenance of the CMS, including spare parts inventory; data recording, 

calculations, and reporting; and accuracy audit procedures, including sampling and analysis 

methods. The owner or operation shall maintain records of the procedures that are part of the 

quality control program developed and implemented for CMS. 

(3) Based on the results of the determination made under paragraph (e)(2), the 

Administrator may require that an owner or operator of an affected source make changes to the 

operation and maintenance plan for that source. Revisions may be required if the plan: 

(i) Does not address a variance of the air pollution control equipment or monitoring 

equipment that has occurred that increases emissions; 

(ii) Fails to provide for operation during a variance of the air pollution control equipment or 

the monitoring equipment in a manner consistent with safety and good air pollution control 

practices; or 

(iii) Does not provide adequate procedures for correcting a variance of the air pollution 

control equipment or monitoring equipment as soon as reasonable. 

(4) If the operation and maintenance plan fails to address or inadequately addresses a 

variance event at the time the plan was initially developed, the owner or operator shall revise the 

operation and maintenance plan within 45 working days after such an event occurs. The revised 

plan shall include procedures for operating and maintaining the air pollution control equipment 

or monitoring equipment during similar variance events and a program for corrective action for 

such events. 

(5) The operation and maintenance plan shall be developed by the source's compliance date. 

The owner or operator shall keep the written operation and maintenance plan on record to be 

made available for inspection, upon request, by the Administrator for the life of the source. In 

addition, if the operation and maintenance plan is revised, the owner or operator shall keep 

previous (i.e., superseded) versions of the plan on record to be made available for inspection 

upon request by the Administrator for a period of 5 years after each revision to the plan. 

(6) To satisfy the requirements of the operation and maintenance plan, the owner or 

operator may use the source's standard operating procedures (SOP) manual, an Occupational 

Safety and Health Administration (OSHA) plan, or other existing plans provided the alternative 

plans meet the requirements of this section and are made available for inspection when requested 

by the Administrator. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(7) In response to an action to enforce the standards set forth in this subpart, you may assert 

an affirmative defense to a claim for civil penalties for exceedances of such standards that are 

caused by a malfunction, as defined in § 63.2. Appropriate penalties may be assessed, however, 

if the respondent fails to meet its burden of proving all the requirements in the affirmative 

defense. The affirmative defense shall not be available for claims for injunctive relief. 

(i) To establish the affirmative defense in any action to enforce such a limit, the owners or 

operators of a facility must timely meet the notification requirements of paragraph (e)(7)(ii) of 

this section, and must prove by a preponderance of evidence that: 

(A) The excess emissions were caused by a sudden, infrequent, and unavoidable failure of 

air pollution control and monitoring equipment, or a process to operate in a normal and usual 

manner; and could not have been prevented through careful planning, proper design or better 

operation and maintenance practices; and did not stem from any activity or event that could have 

been foreseen and avoided, or planned for; and were not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; 

(B) Repairs were made as expeditiously as possible when the applicable emission 

limitations were being exceeded. Off-shift and overtime labor were used, to the extent 

practicable to make these repairs; 

(C) The frequency, amount and duration of the excess emissions (including any bypass) 

were minimized to the maximum extent practicable during periods of such emissions; 

(D) If the excess emissions resulted from a bypass of control equipment or a process, then 

the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; 

(E) All possible steps were taken to minimize the impact of the excess emissions on 

ambient air quality, the environment, and human health; 

(F) All emissions monitoring and control systems were kept in operation if at all possible, 

consistent with safety and good air pollution control practices; 

(G) All of the actions in response to the excess emissions were documented by properly 

signed, contemporaneous operating logs; 

(H) At all times, the affected facility was operated in a manner consistent with good 

practices for minimizing emissions; and 

(I) The owner or operator has prepared a written root cause analysis, the purpose of which is 

to determine, correct, and eliminate the primary causes of the malfunction and the excess 

emissions resulting from the malfunction event at issue. The analysis shall also specify, using the 

best monitoring methods and engineering judgment, the amount of excess emissions that were 

the result of the malfunction. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(ii) Notification. The owner or operator of the facility experiencing an exceedance of its 

emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile 

(FAX) transmission as soon as possible, but no later than 2 business days after the initial 

occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil 

penalties for that malfunction. The owner or operator seeking to assert an affirmative defense 

shall also submit a written report to the Administrator within 45 days of the initial occurrence of 

the exceedance of the standard in this subpart to demonstrate, with all necessary supporting 

documentation, that it has met the requirements set forth in paragraph (e)(7)(i) of this section. 

The owner or operator may seek an extension of this deadline for up to 30 additional days by 

submitting a written request to the Administrator before the expiration of the 45 day period. Until 

a request for an extension has been approved by the Administrator, the owner or operator is 

subject to the requirement to submit such report within 45 days of the initial occurrence of the 

exceedance. 

§ 63.563 Compliance and performance testing. 

(a) The following procedures shall be used to determine compliance with the emissions 

limits under § 63.562(b)(1), (c)(2), and (d)(1): 

(1) Vent stream by-pass requirements for the terminal's vapor collection system. (i) In 

accordance with § 63.562(b)(1)(i), (c)(2)(i), and (d)(1)(i), each valve in the terminal's vapor 

collection system that would route displaced vapors to the atmosphere, either directly or 

indirectly, shall be secured closed during marine tank vessel loading operations either by using a 

car-seal or a lock-and-key type configuration, or the by-pass line from the valve shall be 

equipped with a flow indicator, except for those valves used for pressure/vacuum relief, 

analyzers, instrumentation devices, sampling, and venting for maintenance. Marine tank vessel 

loading operations shall not be performed with open by-pass lines. 

(ii) Repairs shall be made to valves, car-seals, or closure mechanisms no later than 15 days 

after a change in the position of the valve or a break in the car-seal or closure mechanism is 

detected or no later than prior to the next marine tank vessel loading operation, whichever is 

later. 

(2) Ship-to-shore compatibility of vapor collection systems. Following the date on which the 

initial performance test is completed, marine tank vessel loading operations must be performed 

only if the marine tank vessel's vapor collection equipment is compatible to the terminal's vapor 

collection system; marine tank vessel loading operations must be performed only when the 

marine tank vessel's vapor collection equipment is connected to the terminal's vapor collection 

system, as required in § 63.562(b)(1)(ii), (c)(2)(ii), and (d)(1)(ii). 

(3) Pressure/vacuum settings for the marine tank vessel's vapor collection equipment.

During the initial performance test required in paragraph (b)(1) of this section, the owner or 

operator of an affected source shall demonstrate compliance with operating pressure 

requirements of 33 CFR 154.814 using the procedures in § 63.565(b). 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) Vapor-tightness requirements of the marine vessel. The owner or operator of an affected 

source shall use the procedures in paragraph (a)(4)(i), (ii), (iii), or (iv) of this section to ensure 

that marine tank vessels are vapor tight, as required in § 63.562(b)(1)(iii), (c)(2)(iii), and 

(d)(1)(iii). 

(i) Pressure test documentation for determining vapor tightness of the marine vessel. The 

owner or operator of a marine tank vessel, who loads commodities containing HAP not 

determined to be exempt under § 63.560(d) at an affected source, shall provide a copy of the 

vapor-tightness pressure test documentation described in § 63.567(i) for each marine tank vessel 

prior to loading. The date of the test listed in the documentation must be within the preceding 12 

months, and the test must be conducted in accordance with the procedures in § 63.565(c)(1). 

Following the date on which the initial performance test is completed, the affected source must 

check vapor-tightness pressure test documentation for marine tank vessels loaded at positive 

pressure. 

(ii) Leak test documentation for determining vapor tightness of the marine vessel. If no 

documentation of the vapor tightness pressure test as described in paragraph (a)(4)(i) of this 

section is available, the owner or operator of a marine tank vessel, who loads commodities 

containing HAP not determined to be exempt under § 63.560(d) at an affected source, shall 

provide the leak test documentation described in § 63.567(i) for each marine tank vessel prior to 

loading. The date of the test listed in the documentation must be within the preceding 12 months, 

and the test must be conducted in accordance with the procedures in § 63.565(c)(2). If the marine 

tank vessel has failed its most recent vapor-tightness leak test at that terminal, the owner or 

operator of the non-vapor-tight marine tank vessel shall provide documentation that the leaks 

detected during the previous vapor-tightness test have been repaired and documented with a 

successful vapor-tightness leak test described in § 63.565(c)(2) conducted during loading. If the 

owner or operator of the marine tank vessel can document that repair is technically infeasible 

without cleaning and gas freeing or dry-docking the vessel, the owner or operator of the affected 

source may load the marine tank vessel. Following the date on which the initial performance test 

is completed, an affected source must check the vapor-tightness leak test documentation for 

marine tank vessels loaded at positive pressure. 

(iii) Leak test performed during loading using Method 21 for determining vapor tightness of 

the marine vessel. If no documentation of vapor tightness as described in paragraphs (a)(4)(i) or 

(ii) of this section is available, the owner or operator of a marine tank vessel, who loads 

commodities containing HAP not determined to be exempt under § 63.560(d) at an affected 

source, shall perform a leak test of the marine tank vessel during marine tank vessel loading 

operation using the procedures described in § 63.565(c)(2). 

(A) If no leak is detected, the owner or operator of a marine tank vessel shall complete the 

documentation described in § 63.567(i) prior to departure of the vessel. 

(B) If a leak is detected, the owner or operator of the marine tank vessel shall document the 

vapor-tightness failure for the marine tank vessel prior to departure of the vessel. The leaking 

component shall be repaired prior to the next marine tank vessel loading operation at a controlled 

terminal unless the repair is technically infeasible without cleaning and gas freeing or dry-
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

docking the vessel. If the owner or operator of the vessel provides documentation that repair of 

such equipment is technically infeasible without cleaning and gas freeing or dry-docking the 

vessel, the equipment responsible for the leak will be excluded from future Method 21 tests until 

repairs are effected. A copy of this documentation shall be maintained by the owner or operator 

of the affected source. Repair of the equipment responsible for the leak shall occur the next time 

the vessel is cleaned and gas freed or dry-docked. For repairs that are technically feasible without 

dry-docking the vessel, the owner or operator of the affected source shall not load the vessel 

again unless the marine tank vessel owner or operator can document that the equipment 

responsible for the leak has been repaired. 

(iv) Negative pressure loading. The owner or operator of an affected source shall ensure 

that a marine tank vessel is loaded with the product tank below atmospheric pressure (i.e., at 

negative gauge pressure). The pressure shall be measured between the facility's vapor connection 

and its manual isolation valve, and the measured pressure must be below atmospheric pressure. 

Following the date on which the initial performance test is completed, marine tank vessel loading 

operations for nonvapor-tight vessels must be performed below atmospheric pressure (i.e., at 

negative gauge pressure) in the product tank. 

(b) Compliance determination for affected sources. The following procedures shall be used 

to determine compliance with the emissions limits under § 63.562(b), (c), and (d). 

(1) Initial performance test. An initial performance test shall be conducted using the 

procedures listed in § 63.7 of subpart A of this part according to the applicability in Table 1 of 

§ 63.560, the procedures listed in this section, and the test methods listed in § 63.565. The initial 

performance test shall be conducted within 180 days after the compliance date for the specific 

affected source. During this performance test, sources subject to MACT standards under 

§ 63.562(b)(2), (3), (4), and (5), and (d)(2) shall determine the reduction of HAP emissions, as 

VOC, for all combustion or recovery devices other than flares. Performance tests shall be 

conducted under such conditions as the Administrator specifies to the owner or operator based on 

representative performance of the affected source for the period being tested. Upon request, the 

owner or operator shall make available to the Administrator such records as may be necessary to 

determine the conditions of performance tests. Sources subject to RACT standards under 

§ 63.562(c)(3), (4), and (5), and (d)(2) shall determine the reduction of VOC emissions for all 

combustion or recovery devices other than flares. 

(2) Performance test exemptions. An initial performance test required in this section and in 

§ 63.565(d) and the continuous monitoring in § 63.564(e) is not required in the following cases: 

(i) When a boiler or process heater with a design heat input capacity of 44 Megawatts or 

less is used to comply with § 63.562(b)(2), (3), or (4), (c)(3) or (4), or (d)(2) and the vent stream 

is used as the primary fuel or with the primary fuel; 

(ii) When a boiler or process heater with a design heat input capacity of 44 Megawatts or 

greater is used to comply with § 63.562(b)(2), (3) or (4), (c)(3) or (4), or (d)(2); or 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(iii) When a boiler subject to 40 CFR part 266, subpart H, “Hazardous Waste Burned in 

Industrial Furnaces,” that has demonstrated 99.99 percent destruction or recovery efficiency is 

used to comply with § 63.562(b)(2), (3), or (4), (c)(3) or (4), or (d)(2). 

(3) Operation and maintenance inspections. If the 3-hour or 3-cycle block average 

operating parameters in paragraphs (b)(4) through (9) of this section, outside the acceptable 

operating ranges, are measured and recorded, i.e., variances of the pollution control device or 

monitoring equipment, the owner or operator of the affected source shall perform an unscheduled 

inspection of the control device and monitoring equipment and review of the parameter 

monitoring data. The owner or operator of the affected source shall perform an inspection and 

review when total parameter variance time for the control device is greater than 10 percent of the 

operating time for marine tank vessel loading operations on a 30-day, rolling-average basis. The 

inspection and review shall be conducted within 24 hours after passing the allowable variance 

time of 10 percent. The inspection checklist from the requirements of § 63.562(e)(2)(iii) and the 

monitoring data from requirements in §§ 63.562(e)(2)(ii) and 63.564 should be used to identify 

any maintenance problems that may be associated with the variance. The unscheduled inspection 

should encompass all components of the control device and monitoring equipment that can be 

inspected while in operation. If any maintenance problem is identified during the inspection, the 

owner or operator of the affected source must take corrective action (e.g., adjustments to 

operating controls, etc.) as soon as practicable. If no immediate maintenance problems are 

identified from the inspection performed while the equipment is operating, a complete inspection 

in accordance with § 63.562(e)(2) must be conducted prior to the next marine tank vessel loading 

operation and corrective action (e.g., replacement of defective parts) must be taken as soon as 

practicable for any maintenance problem identified during the complete inspection. 

(4) Combustion device, except flare. During the initial performance test required in 

paragraph (b)(1) of this section, the owner or operator shall determine the efficiency of and/or 

the outlet VOC concentration from the combustion device used to comply with § 63.562(b)(2), 

(3), and (4), (c)(3) and (4), and (d)(2) using the test methods in § 63.565(d). The owner or 

operator shall comply with paragraph (b)(4)(i) or (ii) of this section. 

(i) Outlet VOC concentration limit for required percent combustion efficiency. The owner 

or operator shall establish as an operating parameter the baseline VOC concentration using the 

procedures described in § 63.565(g). Following the date on which the initial performance test is 

completed, the facility shall be operated with a block average outlet VOC concentration as 

determined in § 63.564(e)(1) no more than 20 percent above the baseline VOC concentration. 

(ii) Baseline temperature for required percent combustion efficiency. The owner or operator 

shall establish as an operating parameter the baseline temperature using the procedures described 

in § 63.565(f). Following the date on which the initial performance test is completed, the facility 

shall be operated with the block average temperature as determined in § 63.564(e)(2) or (3) no 

more than 28 °C (50 °F) below the baseline temperature. 

(5) Flare. During the initial performance test required in paragraph (b)(1) of this section, the 

owner or operator shall establish that the flare used to comply with the emissions standards in 

§ 63.562(b)(2), (3), and (4), (c)(3) and (4), and (d)(2) is in compliance with the design 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

requirements for flares cited in § 63.565(e). Following the date on which the initial determination 

of compliance is established, the facility shall operate with the presence of a pilot flame in the 

flare, as determined in § 63.564(f). 

(6) Carbon adsorber. During the initial performance test required in paragraph (b)(1) of this 

section, the owner or operator shall determine the efficiency of and/or the outlet VOC 

concentration from the recovery device used to comply with § 63.562(b)(2), (3), (4), and (5), 

(c)(3), (4), and (5), and (d)(2) using the test methods in § 63.565(d). The owner or operator shall 

comply with paragraph (b)(6)(i) as well as either paragraph (b)(6)(ii) or (iii) of this section. The 

owner or operator of affected sources complying with paragraph (b)(6)(ii)(B) or (C) of this 

section shall conduct a performance test once each year. 

(i) Compliance determination for carbon bed regeneration. Desorbed hydrocarbons from 

regeneration of the off-line carbon bed shall be vented to the on-line carbon bed. 

(ii) Baseline parameters for required percent recovery efficiency. The owner or operator 

shall comply with paragraph (b)(6)(ii)(A), (B), or (C) of this section. 

(A) Outlet VOC concentration limit for required percent recovery efficiency. The owner or 

operator shall establish as an operating parameter the baseline VOC concentration using the 

procedures described in § 63.565(g). Following the date on which the initial performance test is 

completed, the facility shall be operated with a block average outlet VOC concentration as 

determined in § 63.564(g)(1) no more than 20 percent above the baseline VOC concentration. 

(B) Carbon adsorbers with vacuum regeneration. The owner or operator shall establish as 

operating parameters the baseline regeneration time for the vacuum stage of carbon bed 

regeneration using the procedures described in § 63.565(h) and shall establish the baseline 

vacuum pressure (negative gauge pressure) using the procedures described in § 63.565(i). 

Following the date on which the initial performance test is completed, the facility shall be 

operated with block average regeneration time of the vacuum stage of carbon bed regeneration as 

determined in § 63.564(g)(2) no more than 20 percent below the baseline regeneration time, and 

the facility shall be operated with the block average vacuum pressure (negative gauge pressure) 

as determined in § 63.564(g)(2) no more than 20 percent above the baseline vacuum pressure. 

(C) Carbon adsorbers with steam regeneration. The owner or operator shall establish as 

operating parameters the baseline total stream flow using the procedures described in § 63.565(j) 

and a baseline carbon bed temperature after cooling of the bed using the procedures in 

§ 63.565(f)(2). Following the date on which the initial performance test is completed, the facility 

shall be operated with the total stream flow, as determined in § 63.564(g)(3), no more than 20 

percent below the baseline stream flow and with the carbon bed temperature (measured within 15 

minutes after completion of the cooling cycle), as determined in § 63.564(g)(3), no more than 10 

percent or 5.6 °C (10 °F) above the baseline carbon bed temperature, whichever is less stringent. 

(iii) Outlet VOC concentration of 1,000 ppmv for gasoline loading. Following the date on 

which the initial performance test is completed, the facility shall operate with a block average 

outlet VOC concentration as determined in § 63.564(g)(1) of no more than 1,200 ppmv VOC. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(7) Condenser/refrigeration unit. During the initial performance test required in paragraph 

(b)(1) of this section, the owner or operator shall determine the efficiency of and/or the outlet 

VOC concentration from the recovery device used to comply with § 63.562(b)(2), (3), and (4), 

(c)(3) and (4), and (d)(2) using the test methods in § 63.565(d). The owner or operator shall 

comply with either paragraph (b)(7)(i), (ii), or (iii) of this section. 

(i) VOC outlet concentration limit for required percent recovery efficiency. The owner or 

operator shall establish as an operating parameter the baseline VOC concentration using the 

procedures described in § 63.565(g). Following the date on which the initial performance test is 

completed, the facility shall be operated with a block average outlet VOC concentration as 

determined in § 63.564(h)(2) no more than 20 percent above the baseline VOC concentration. 

(ii) Baseline temperature for required percent recovery efficiency. The owner or operator 

shall establish as an operating parameter the baseline temperature using the procedures described 

in § 63.565(f). Following the date on which the initial performance test is completed, the facility 

shall operate with a block average temperature, as determined in § 63.564(h)(1), no more than 28 

°C (50 °F) above the baseline temperature. 

(iii) Baseline parameters for 1,000 ppmv VOC concentration limit for gasoline loading. The 

owner or operator shall monitor either the outlet VOC concentration or the outlet temperature of 

the unit. For sources monitoring temperature, the owner or operator shall establish as an 

operating parameter the baseline temperature using the procedures described in § 63.565(f). 

Following the date on which the initial performance test is completed, the facility shall operate 

with a block average outlet VOC concentration, as determined in § 63.564(h)(2), of no more than 

1,200 ppmv VOC or with a block average temperature, as determined in § 63.564(h)(1), no more 

than 28 °C (50 °F) above the baseline temperature. 

(8) Absorber. During the initial performance test required in paragraph (b)(1) of this 

section, the owner or operator shall determine the efficiency of the absorber and/or the outlet 

VOC concentration from the recovery device used to comply with § 63.562(b)(2), (3), and (4), 

(c)(3) and (4), and (d)(2) using the test methods in § 63.565(d). The owner or operator shall 

comply with either paragraph (b)(8)(i) or (ii) of this section. 

(i) VOC outlet concentration limit for required percent recovery efficiency. The owner or 

operator shall establish as an operating parameter the baseline VOC concentration using the 

procedures described in § 63.565(g). Following the date on which the initial performance test is 

completed, the facility shall be operated with a block average outlet VOC concentration as 

determined in § 63.564(i)(1) no more than 20 percent above the baseline VOC concentration. 

(ii) Baseline liquid-to-vapor ratio for required percent recovery efficiency. The owner or 

operator shall establish as an operating parameter the baseline liquid flow to vapor flow (L/V) 

ratio using the procedures described in § 63.565(k). Following the date on which the initial 

performance test is completed, the facility shall operate with a block average L/V ratio, as 

determined in § 63.564(i)(2), no more than 20 percent below the baseline L/V ratio. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(9) Alternative control devices. For sources complying with § 63.562(b)(2), (3), and (4), 

(c)(3) and (4), and (d)(2) with the use of a control technology other than the devices discussed in 

paragraphs (b)(4) through (8) of this section, the owner or operator of an affected source shall 

provide to the Administrator information describing the design and operation of the air pollution 

control system, including recommendations for the operating parameter(s) to be monitored to 

indicate proper operation and maintenance of the air pollution control system. Based on this 

information, the Administrator shall determine the operating parameter(s) to be established 

during the performance test. During the initial performance test required in paragraph (b)(1) of 

this section, the owner or operator shall determine the efficiency of the air pollution control 

system using the test methods in § 63.565(d). The device shall achieve at least the percent 

destruction efficiency or recovery efficiency required under § 63.562(b)(2), (3), and (4), (c)(3) 

and (4), and (d)(2). The owner or operator shall establish the operating parameter(s) approved by 

the Administrator. Following the date on which the initial performance test is complete, the 

facility shall operate either above or below a maximum or minimum operating parameter, as 

appropriate. 

(10) Emission estimation. The owner or operator of a source subject to § 63.562(b)(2), (3), 

and (4) shall use the emission estimation procedures in § 63.565(l) to calculate HAP emissions. 

(c) Leak detection and repair for vapor collection systems and control devices. The 

following procedures are required for all sources subject to § 63.562(b), (c), or (d). 

(1) Annual leak detection and repair for vapor collection systems and control devices. The 

owner or operator of an affected source shall inspect and monitor all ductwork and piping and 

connections to vapor collection systems and control devices once each calendar year using 

Method 21. 

(2) Ongoing leak detection and repair for vapor collection systems and control devices. If 

evidence of a potential leak is found by visual, audible, olfactory, or any other detection method, 

all ductwork and piping and connections to vapor collection systems and control devices shall be 

inspected to the extent necessary to positively identify the potential leak and any potential leaks 

shall be monitored within 5 days by Method 21. Each detection of a leak shall be recorded, and 

the leak shall be tagged until repaired. 

(3) When a leak is detected, a first effort to repair the vapor collection system and control 

device shall be made within 15 days or prior to the next marine tank vessel loading operation, 

whichever is later. 

[61 FR 48399, Sept. 19, 1995, as amended at 76 FR 22597, Apr. 21, 2011] 

§ 63.564 Monitoring requirements. 

(a)(1) The owner or operator of an affected source shall comply with the monitoring 

requirements in § 63.8 of subpart A of this part in accordance with the provisions for 

applicability of subpart A to this subpart in Table 1 of § 63.560 and the monitoring requirements 

in this section. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(2) Each owner or operator of an affected source shall monitor the parameters specified in 

this section. All monitoring equipment shall be installed such that representative measurements 

of emissions or process parameters from the source are obtained. For monitoring equipment 

purchased from a vendor, verification of the operational status of the monitoring equipment shall 

include completion of the manufacturer's written specifications or recommendations for 

installation, operation, and calibration of the system. 

(3) Except for system breakdowns, out-of-control periods, repairs, maintenance periods, 

calibration checks, and zero (low-level) and high-level calibration drift adjustments, all 

continuous parametric monitoring systems (CPMS) and CEMS shall be in continuous operation 

while marine tank vessel loading operations are occuring and shall meet minimum frequency of 

operation requirements. Sources monitoring by use of CEMS and CPMS shall complete a 

minimum of one cycle of operation (sampling, analyzing, and/or data recording) for each 

successive 15-minute period. 

(4) The owner or operator of a CMS installed in accordance with these emissions standards 

shall comply with the performance specifications either in performance specification (PS) 8 in 40 

CFR part 60, appendix B for CEMS or in § 63.7(c)(6) of subpart A of this part for CPMS. 

(5) A CEMS is out of control when the measured values (i.e., daily calibrations, multipoint 

calibrations, and performance audits) exceed the limits specified in either PS 8 or in § 63.8(c)(7) 

of subpart A of this part. The owner or operator of a CEMS that is out of control shall submit all 

information concerning out of control periods, including start and end dates and hours and 

descriptions of corrective actions taken, in the excess emissions and continuous monitoring 

system performance report required in § 63.567(e). 

(b) Vapor collection system of terminal. Owners or operators of a source complying with 

§ 63.563(a)(1) that uses a vapor collection system that contains valves that could divert a vent 

stream from a control device used to comply with the provisions of this subpart shall comply 

with paragraph (b)(1), (2), or (3) of this section. 

(1) Measure and record the vent stream flowrate of each by-pass line once every 15 

minutes. The owner or operator shall install, calibrate, maintain, and operate a flow indicator and 

data recorder. The flow indicator shall be installed immediately downstream of any valve (i.e., 

entrance to by-pass line) that could divert the vent stream from the control device to the 

atmosphere. 

(2) Measure the vent stream flowrate of each by-pass line once every 15 minutes. The 

owner or operator shall install, calibrate, maintain, and operate a flow indicator with either an 

audio or visual alarm. The flow indicator and alarm shall be installed immediately downstream 

of any valve (i.e., entrance to by-pass line) that could divert the vent stream from the control 

device to the atmosphere. The alarm shall be checked every 6 months to demonstrate that it is 

functioning properly. 

(3) Visually inspect the seal or closure mechanism once during each marine tank vessel 

loading operation and at least once every month to ensure that the valve is maintained in the 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

closed position and that the vent stream is not diverted through the by-pass line; record all times 

when the car seals have been broken and the valve position has been changed. Each by-pass line 

valve shall be secured in the closed position with a car-seal or a lock-and-key type configuration. 

(c) Pressure/vacuum settings for the marine tank vessel's vapor collection equipment.

Owners or operators of a source complying with § 63.563(a)(3) shall measure continuously the 

operating pressure of the marine tank vessel during loading. 

(d) Loading at negative pressure. Owners or operators of a source complying with 

§ 63.563(a)(4)(iv) that load vessels at less than atmospheric pressure (i.e., negative gauge 

pressure) shall measure and record the loading pressure. The owner or operator shall install, 

calibrate, maintain, and operate a recording pressure measurement device (magnehelic gauge or 

equivalent device) and an audible and visible alarm system that is activated when the pressure 

vacuum specified in § 63.563(a)(4)(iv) is not attained. The owner or operator shall place the 

alarm system so that it can be seen and heard where cargo transfer is controlled. The owner or 

operator shall verify the accuracy of the pressure device once each calendar year with a reference 

pressure monitor (traceable to National Institute of Standards and Technology (NIST) standards 

or an independent pressure measurement device dedicated for this purpose). 

(e) Combustion device, except flare. For sources complying with § 63.563(b)(4), use of a 

combustion device except a flare, the owner or operator shall comply with paragraph (e)(1), (2), 

or (3) of this section. Owners or operators complying with paragraphs (e)(2) or (3) shall also 

comply with paragraph (e)(4) of this section. 

(1) Outlet VOC concentration. Monitor the VOC concentrations at the exhaust point of the 

combustion device and record the output from the system. For sources monitoring the outlet 

VOC concentration established during the performance test, a data acquisition system shall 

record a concentration every 15 minutes and shall compute and record an average concentration 

each cycle (same time period or cycle as the performance test) and a 3-cycle block average 

concentration every third cycle. For sources monitoring the 1,000 ppmv VOC concentration for 

gasoline loading, a data acquisition system shall record a concentration every 15 minutes and 

shall compute and record an average concentration each hour and a 3-hour block average 

concentration every third hour. The owner or operator will install, calibrate, operate, and 

maintain a CEMS consistent with the requirements of PS 8 to measure the VOC concentration. 

The daily calibration requirements are required only on days when marine tank vessel loading 

operations occur. 

(2) Operating temperature determined during performance testing. If the baseline 

temperature was established during the performance test, the data acquisition system shall record 

the temperature every 15 minutes and shall compute and record an average temperature each 

cycle (same time period or cycle of the performance test) and a 3-cycle block average every third 

cycle. 

(3) Manufacturer's recommended operating temperature. If the baseline temperature is 

based on the manufacturer recommended operating temperature, the data acquisition system shall 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

record the temperature every 15 minutes and shall compute and record an average temperature 

each hour and a 3-hour block average every third hour. 

(4) Temperature monitor. The owner or operator shall install, calibrate, operate, and 

maintain a temperature monitor accurate to within ±5.6 °C (±10 °F) or within 1 percent of the 

baseline temperature, whichever is less stringent, to measure the temperature. The monitor shall 

be installed at the exhaust point of the combustion device but not within the combustion zone. 

The owner or operator shall verify the accuracy of the temperature monitor once each calendar 

year with a reference temperature monitor (traceable to National Institute of Standards and 

Technology (NIST) standards or an independent temperature measurement device dedicated for 

this purpose). During accuracy checking, the probe of the reference device shall be at the same 

location as that of the temperature monitor being tested. 

(f) Flare. For sources complying with § 63.563(b)(5), use of a flare, the owner or operator 

shall monitor and record continuously the presence of the flare pilot flame. The owner or 

operator shall install, calibrate, maintain, and operate a heat sensing device (an ultraviolet beam 

sensor or thermocouple) at the pilot light to indicate the presence of a flame during the entire 

loading cycle. 

(g) Carbon adsorber. For sources complying with § 63.563(b)(6), use of a carbon adsorber, 

the owner or operator shall comply with paragraph (g)(1), (2), or (3) of this section. 

(1) Outlet VOC concentration. Monitor the VOC concentrations at the exhaust point of each 

carbon adsorber unit and record the output from the system. For sources monitoring the outlet 

VOC concentration established during the performance test, a data acquisition system shall 

record a concentration every 15 minutes and shall compute and record an average concentration 

each cycle (same time period or cycle as the performance test) and a 3-cycle block average 

concentration every third cycle. For sources monitoring the 1,000 ppmv VOC concentration for 

gasoline loading, a data acquisition system shall record a concentration every 15 minutes and 

shall compute and record an average concentration each hour and a 3-hour block average 

concentration every third hour. The owner or operator will install, calibrate, operate, and 

maintain a CEMS consistent with the requirements of PS 8 to measure the VOC concentration. 

The daily calibration requirements are required only on days when marine tank vessel loading 

operations occur. 

(2) Carbon adsorbers with vacuum regeneration. Monitor and record the regeneration time 

for carbon bed regeneration and monitor and record continuously the vacuum pressure of the 

carbon bed regeneration cycle. The owner or operator will record the time when the carbon bed 

regeneration cycle begins and when the cycle ends for a single carbon bed and will calculate a 3-

cycle block average every third cycle. The owner or operator shall install, calibrate, maintain, 

and operate a recording pressure measurement device (magnehelic gauge or equivalent device). 

A data acquisition system shall record and compute a 3-cycle (carbon bed regeneration cycle) 

block average vacuum pressure every third cycle. The owner or operator shall verify the 

accuracy of the pressure device once each calendar year with a reference pressure monitor 

(traceable to National Institute of Standards and Technology (NIST) standards or an independent 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

pressure measurement device dedicated for this purpose). During accuracy checking, the probe 

of the reference device shall be at the same location as that of the pressure monitor being tested. 

(3) Carbon adsorbers with steam regeneration. Monitor and record the total stream mass 

flow and monitor and record the carbon bed temperature after regeneration (but within 15 

minutes of completion of the cooling cycle). The owner or operator will install, calibrate, 

maintain, and operate an integrating stream flow monitoring device that is accurate within ±10 

percent and that is capable of recording the total stream mass flow for each regeneration cycle. 

The owner or operator will install, calibrate, maintain, and operate a temperature monitor 

accurate to within ±5.6 °C (10 °F) or within 1 percent of the baseline carbon bed temperature, 

whichever is less stringent, to measure the carbon bed temperature. The monitor shall be 

installed at the exhaust point of the carbon bed. The data acquisition system shall record the 

carbon bed temperature after each cooling cycle (measured within 15 minutes of completion of 

the cooling cycle). The owner or operator shall verify the accuracy of the temperature monitor 

once each calendar year with a reference temperature monitor (traceable to National Institute of 

Standards and Technology (NIST) standards or an independent temperature measurement device 

dedicated for this purpose). During accuracy checking, the probe of the reference device shall be 

at the same location as that of the temperature monitor being tested. 

(h) Condenser/refrigeration unit. For sources complying with § 63.563(b)(7), use of a 

condenser/refrigeration unit, the owner or operator shall comply with either paragraph (h)(1) or 

(2) of this section. 

(1) Baseline temperature. Monitor and record the temperature at the outlet of the unit. The 

owner or operator shall install, calibrate, operate, and maintain a temperature monitor accurate to 

within ±5.6 °C (±10 °F) or within 1 percent of the baseline temperature, whichever is less 

stringent, to measure the temperature. The monitor shall be installed at the exhaust point of the 

condenser/refrigeration unit. For sources monitoring the temperature established during the 

performance test, the data acquisition system shall record the temperature every 15 minutes and 

shall compute and record an average temperature each cycle (same time period or cycle of the 

performance test) and a 3-hour block average every third cycle. For sources monitoring the 

manufacturer recommended temperature, the data acquisition system shall record the 

temperature every 15 minutes and shall compute and record an average temperature each hour 

and a 3-hour block average every third hour. The owner or operator shall verify the accuracy of 

the temperature monitor once each calendar year with a reference temperature monitor (traceable 

to National Institute of Standards and Technology (NIST) standards or an independent 

temperature measurement device dedicated for this purpose). During accuracy checking, the 

probe of the reference device shall be at the same location as that of the temperature monitor 

being tested. 

(2) Outlet VOC concentration. Monitor the VOC concentrations at the outlet of the unit and 

record the output from the system. For sources monitoring the outlet VOC concentration 

established during the performance test, a data acquisition system shall record a concentration 

every 15 minutes and shall compute and record an average concentration each cycle (same time 

period or cycle as the performance test) and a 3-cycle block average concentration every third 

cycle. For sources monitoring the 1,000 ppmv VOC concentration for gasoline loading, a data 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

acquisition system shall record a concentration every 15 minutes and shall compute and record 

an average concentration each hour and a 3-hour block average concentration every third hour. 

The owner or operator will install, calibrate, operate, and maintain a VOC CEMS consistent with 

the requirements of PS 8 to measure the VOC concentration. The daily calibration requirements 

are required only on days when marine tank vessel loading operations occur. 

(i) Absorber. For sources complying with § 63.563(b)(8), use of an absorber, the owner or 

operator shall comply with either paragraph (i)(1) or (2) of this section. 

(1) Outlet VOC concentration. Monitor the VOC concentrations at the outlet of the absorber 

and record the output from the system. For sources monitoring the outlet VOC concentration 

established during the performance test, a data acquisition system shall record a concentration 

every 15 minutes and shall compute and record an average concentration each cycle (same time 

period or cycle as the performance test) and a 3-cycle block average concentration every third 

cycle. For sources monitoring the 1,000 ppmv VOC concentration for gasoline loading, a data 

acquisition system shall record a concentration every 15 minutes and shall compute and record 

an average concentration each hour and a 3-hour block average concentration every third hour. 

The owner or operator will install, calibrate, operate, and maintain a VOC CEMS consistent with 

the requirements of PS 8. The daily calibration requirements are required only on days when 

marine tank vessel loading operations occur. 

(2) L/V ratio. Monitor and record the inlet liquid flowrate and the inlet gas flowrate to the 

absorber and record the calculated L/V ratio. The owner or operator shall install, calibrate, 

maintain, and operate liquid and gas flow indicators. For sources monitoring the L/V ratio 

established during the performance test, a data acquisition system shall record the flowrates and 

calculated ratio every 15 minutes and shall compute and record an average ratio each cycle 

(same time period or cycle as the performance test) and a 3-cycle block average ratio every third 

cycle. For sources monitoring the manufacturer recommended L/V ratio, a data acquisition 

system shall record the flowrates and calculated ratio every 15 minutes and shall compute and 

record an average ratio each hour and a 3-hour average ratio every third hour. The liquid and gas 

flow indicators shall be installed immediately upstream of the respective inlet lines to the 

absorber. 

(j) Alternate monitoring procedures. Alternate procedures to those described in this section 

may be used upon application to, and approval by, the Administrator. The owner or operator 

shall comply with the procedures for use of an alternative monitoring method in § 63.8(f). 

§ 63.565 Test methods and procedures. 

(a) Performance testing. The owner or operator of an affected source in § 63.562 shall 

comply with the performance testing requirements in § 63.7 of subpart A of this part in 

accordance with the provisions for applicability of subpart A to this subpart in Table 1 of 

§ 63.560 and the performance testing requirements in this section. 

(b) Pressure/vacuum settings of marine tank vessel's vapor collection equipment. For the 

purpose of determining compliance with § 63.563(a)(3), the following procedures shall be used: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(1) Calibrate and install a pressure measurement device (liquid manometer, magnehelic 

gauge, or equivalent instrument) capable of measuring up to the maximum relief set pressure of 

the pressure-vacuum vents; 

(2) Connect the pressure measurement device to a pressure tap in the terminal's vapor 

collection system, located as close as possible to the connection with the marine tank vessel; and 

(3) During the performance test required in § 63.563(b)(1), record the pressure every 5 

minutes while a marine tank vessel is being loaded and record the highest instantaneous pressure 

and vacuum that occurs during each loading cycle. 

(c) Vapor-tightness test procedures for the marine tank vessel. When testing a vessel for 

vapor tightness to comply with the marine vessel vapor-tightness requirements of 

§ 63.563(a)(4)(i), the owner or operator of a source shall use the methods in either paragraph 

(c)(1) or (2) in this section. 

(1) Pressure test for the marine tank vessel. (i) Each product tank shall be pressurized with 

dry air or inert gas to no more than the pressure of the lowest pressure relief valve setting. 

(ii) Once the pressure is obtained, the dry air or inert gas source shall be shut off. 

(iii) At the end of one-half hour, the pressure in the product tank and piping shall be 

measured. The change in pressure shall be calculated using the following formula: 

P=Pi −Pf 

Where: 

P=change in pressure, inches of water. 

Pi =pressure in tank when air/gas source is shut off, inches of water. 

Pf =pressure in tank at the end of one-half hour after air/gas source is shut off, inches of water. 

(iv) The change in pressure, P, shall be compared to the pressure drop calculated using the 

following formula: 

PM=0.861 Pia L/V 

Where: 

PM=maximum allowable pressure change, inches of water. 

Pia =pressure in tank when air/gas source is shut off, psia. 

L=maximum permitted loading rate of vessel, barrels per hour. 

V=total volume of product tank, barrels. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(v) If P≤PM, the vessel is vapor tight. 

(vi) If P<PM, the vessel is not vapor tight and the source of the leak must be identified and 

repaired prior to retesting. 

(2) Leak test for the marine tank vessel. Each owner or operator of a source complying with 

§§ 63.563(a)(4)(ii) or (iii) shall use Method 21 as the vapor-tightness leak test for marine tank 

vessels. The test shall be conducted during the final 20 percent of loading of each product tank of 

the marine vessel, and it shall be applied to any potential sources of vapor leaks on the vessel. 

(d) Combustion (except flare) and recovery control device performance test procedures. (1) 

All testing equipment shall be prepared and installed as specified in the appropriate test methods. 

(2) All testing shall be performed during the last 20 percent of loading of a tank or 

compartment. 

(3) All emission testing intervals shall consist of each 5 minute period during the 

performance test. For each interval, the following shall be performed: 

(i) Readings. The reading from each measurement instrument shall be recorded. 

(ii) Sampling Sites. Method 1 or 1A of appendix A of part 60 of this chapter, as appropriate, 

shall be used for selection of sampling sites. Sampling sites shall be located at the inlet and outlet 

of the combustion device or recovery device except for owners or operators complying with the 

1,000 ppmv VOC emissions limit for gasoline vapors under § 63.563(b)(6) or (7), where the 

sampling site shall be located at the outlet of the recovery device. 

(iii) Volume exhausted. The volume exhausted shall be determined using Method 2, 2A, 2C, 

or 2D of appendix A of part 60 of this chapter, as appropriate. 

(4) Combustion devices, except flares. The average VOC concentration in the vent upstream 

and downstream of the control device shall be determined using Method 25 of appendix A of 

part 60 of this chapter for combustion devices, except flares. The average VOC concentration 

shall correspond to the volume measurement by taking into account the sampling system 

response time. 

(5) Recovery devices. The average VOC concentration in the vent upstream and 

downstream of the control device shall be determined using Method 25A of appendix A of part 

60 of this chapter for recovery devices. The average VOC concentration shall correspond to the 

volume measurement by taking into account the sampling system response time. 

(6) The VOC mass at the inlet and outlet of the combustion or recovery device during each 

testing interval shall be calculated as follows: 

Mj =FKVs CVOC 

Where: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Mj =mass of VOC at the inlet and outlet of the combustion or recovery device during testing 

interval j, kilograms (kg). 

F=10−6

 =conversion factor, (cubic meters VOC/cubic meters air)(1/ppmv) (m3 VOC/m3

air)(1/ppmv). 

K=density, kilograms per cubic meter (kg/m3

 VOC), standard conditions, 20 °C and 760 mm Hg. 

Vs =volume of air-vapor mixture at the inlet and outlet of the combustion or recovery device, 

cubic meters (m3

 ) at standard conditions, 20 °C and 760 mm Hg. 

CVOC =VOC concentration (as measured) at the inlet and outlet of the combustion or recovery 

device, ppmv, dry basis. 

s=standard conditions, 20 °C and 760 mm Hg. 

(7) The VOC mass emission rates at the inlet and outlet of the recovery or combustion 

device shall be calculated as follows: 

Where: 

Ei , Eo =mass flow rate of VOC at the inlet (i) and outlet (o) of the recovery or combustion 

device, kilogram per hour (kg/hr). 

Mij , Moj =mass of VOC at the inlet (i) or outlet (o) during testing interval j, kg. 

T=Total time of all testing intervals, hour. 

n=number of testing intervals. 

(8) Where Method 25 or 25A is used to measure the percent reduction in VOC, the percent 

reduction across the combustion or recovery device shall be calculated as follows: 

Where: 

R=control efficiency of control device, percent. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Ei =mass flow rate of VOC at the inlet to the combustion or recovery device as calculated under 

paragraph (c)(7) of this section, kg/hr. 

Eo =mass flow rate of VOC at the outlet of the combustion or recovery device, as calculated 

under paragraph (c)(7) of this section, kg/hr. 

(9) Repeat the procedures in paragraph (d)(1) through (d)(8) of this section 3 times. The 

arithmetic average percent efficiency of the three runs shall determine the overall efficiency of 

the control device. 

(10) Use of methods other than Method 25 or Method 25A shall be validated pursuant to 

Method 301 of appendix A of part 63 of this chapter. 

(e) Performance test for flares. When a flare is used to comply with § 63.562(b)(2), (3), and 

(4), (c)(3) and (4), and (d)(2), the source must demonstrate that the flare meets the requirements 

of § 63.11 of subpart A of this part. In addition, a performance test according to Method 22 of 

appendix A of part 63 shall be performed to determine visible emissions. The observation period 

shall be at least 2 hours and shall be conducted according to Method 22. Performance testing 

shall be conducted during three complete loading cycles with a separate test run for each loading 

cycle. The observation period for detecting visible emissions shall encompass each loading 

cycle. Integrated sampling to measure process vent stream flow rate shall be performed 

continuously during each loading cycle. The owner or operator shall record all visible emission 

readings, heat content determinations, flow rate measurements, maximum permitted velocity 

calculations, and exit velocity determinations made during the performance test. 

(f) Baseline temperature. The procedures in this paragraph shall be used to determine the 

baseline temperature required in § 63.563(b)(4), (6), and (7) for combustion devices, carbon 

adsorber beds, and condenser/refrigeration units, respectively, and to monitor the temperature as 

required in § 63.564(e), (g), and (h). The owner or operator shall comply with either paragraph 

(f)(1) or (2) of this section. 

(1) Baseline temperature from performance testing. The owner or operator shall establish 

the baseline temperature as the temperature at the outlet point of the unit averaged over three test 

runs from paragraph (d) of this section. Temperature shall be measured every 15 minutes. 

(2) Baseline temperature from manufacturer. The owner or operator shall establish the 

baseline temperature as the manufacturer recommended minimum operating temperature for 

combustion devices, maximum operating temperature for condenser units, and maximum 

operating temperature for carbon beds of carbon adsorbers. 

(g) Baseline outlet VOC concentration. The procedures in this paragraph shall be used to 

determine the outlet VOC concentration required in § 63.563(b)(4), (6), (7), and (8) for 

combustion devices except flare, carbon adsorbers, condenser/refrigeration units, and absorbers, 

respectively, and to monitor the VOC concentration as required in § 63.564(e), (g), (h), and (i). 

The owner or operator shall use the procedures outlined in Method 25A. For the baseline VOC 

concentration, the arithmetic average of the outlet VOC concentration from three test runs from 

paragraph (d) of this section shall be calculated for the control device. The VOC concentration 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

shall be measured at least every 15 minutes. Compliance testing of VOC CEMS shall be 

performed using PS 8. 

(h) Baseline regeneration time for carbon bed regeneration. The procedures in this 

paragraph shall be used to demonstrate the baseline regeneration time for the vacuum stage of 

carbon bed regeneration required in § 63.563(b)(6) for a carbon adsorber and to monitor the 

regeneration time for the vacuum regeneration as required in § 63.564(g). The owner or operator 

shall comply with paragraph (h)(1) or (2). 

(1) Baseline regeneration time from performance testing. The owner or operator shall 

establish the baseline regeneration time as the length of time for the vacuum stage of carbon bed 

regeneration averaged over three test runs from paragraph (d) of this section. 

(2) Baseline regeneration time from manufacturer recommendation. The owner or operator 

shall establish the baseline regeneration time as the manufacturer recommended minimum 

regeneration time for the vacuum stage of carbon bed regeneration. 

(i) Baseline vacuum pressure for carbon bed regeneration. The procedures in this paragraph 

shall be used to demonstrate the baseline vacuum pressure for the vacuum stage of carbon bed 

regeneration required in § 63.563(b)(6) for a carbon adsorber and to monitor the vacuum 

pressure as required in § 63.564(g). The owner or operator shall establish the baseline vacuum 

pressure as the manufacturer recommended minimum vacuum for carbon bed regeneration. 

(j) Baseline total stream flow. The procedures in this paragraph shall be used to demonstrate 

the baseline total stream flow for steam regeneration required in § 63.563(b)(6) for a carbon 

adsorber and to monitor the total stream flow as required in § 63.564(g). The owner or operator 

shall establish the baseline stream flow as the manufacturer recommended minimum total stream 

flow for carbon bed regeneration. 

(k) Baseline L/V ratio. The procedures in this paragraph shall be used to determine the 

baseline L/V ratio required in § 63.563(b)(8) for an absorber and to monitor the L/V ratio as 

required in § 63.564(i). The owner or operator shall comply with either paragraph (k)(1) or (2) of 

this section. 

(1) Baseline L/V ratio from performance test. The owner or operator shall establish the 

baseline L/V ratio as the calculated value of the inlet liquid flow divided by the inlet gas flow to 

the absorber averaged over three test runs using the procedures in paragraph (d) of this section. 

(2) Baseline L/V ratio from manufacturer. The owner or operator shall establish the baseline 

L/V ratio as the manufacturer recommended minimum L/V ratio for absorber operation. 

(l) Emission estimation procedures. For sources with emissions less than 10 or 25 tons and 

sources with emissions of 10 or 25 tons, the owner or operator shall calculate an annual estimate 

of HAP emissions, excluding commodities exempted by § 63.560(d), from marine tank vessel 

loading operations. Emission estimates and emission factors shall be based on test data, or if test 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

data is not available, shall be based on measurement or estimating techniques generally accepted 

in industry practice for operating conditions at the source. 

(m) Alternate test procedures. (1) Alternate test procedures to those described in this section 

may be used upon application to, and approval by, the Administrator. 

(2) If the owner or operator intends to demonstrate compliance by using an alternative to 

any test method specified, the owner or operator shall refrain from conducting the performance 

test until the Administrator approves the use of the alternative method when the Administrator 

approves the site-specific test plan (if review of the site-specific test plan is requested) or until 

after the alternative method is approved (see § 63.7(f) of subpart A of this part). If the 

Administrator does not approve the site-specific test plan (if review is requested) or the use of 

the alternative method within 30 days before the test is scheduled to begin, the performance test 

dates specified in § 63.563(b)(1) shall be extended such that the owner or operator shall conduct 

the performance test within 60 calendar days after the Administrator approves the site-specific 

test plan or after use of the alternative method is approved. Notwithstanding the requirements in 

the preceding two sentences, the owner or operator may proceed to conduct the performance test 

as required in this section (without the Administrator's prior approval of the site-specific test 

plan) if he/she subsequently chooses to use the specified testing and monitoring methods instead 

of an alternative. 

§ 63.566 Construction and reconstruction. 

(a) The owner or operator of an affected source shall fulfill all requirements for construction 

or reconstruction of a source in § 63.5 of subpart A of this part in accordance with the provisions 

for applicability of subpart A to this subpart in Table 1 of § 63.560 and construction or 

reconstruction requirements in this section. 

(b)(1) Application for approval of construction or reconstruction. The provisions of this 

paragraph and § 63.5(d)(1)(ii) and (iii), (2), (3), and (4) of subpart A implement section 112(i)(1) 

of the Act. 

(2) General application requirements. An owner or operator who is subject to the 

requirements of § 63.5(b)(3) of subpart A shall submit to the Administrator an application for 

approval of the construction of a new source, the reconstruction of a source, or the reconstruction 

of a source not subject to the emissions standards in § 63.562 such that the source becomes an 

affected source. The application shall be submitted as soon as practicable before the construction 

or reconstruction is planned to commence. The application for approval of construction or 

reconstruction may be used to fulfill the initial notification requirements of § 63.567(b)(3). The 

owner or operator may submit the application for approval well in advance of the date 

construction or reconstruction is planned to commence in order to ensure a timely review by the 

Administrator and that the planned commencement date will not be delayed. 

(c) Approval of construction or reconstruction based on prior State preconstruction review.

The owner or operator shall submit to the Administrator the request for approval of construction 

or reconstruction under this paragraph and § 63.5(f)(1) of subpart A of this part no later than the 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

application deadline specified in paragraph (b)(2) of this section. The owner or operator shall 

include in the request information sufficient for the Administrator's determination. The 

Administrator will evaluate the owner or operator's request in accordance with the procedures 

specified in § 63.5(e) of subpart A of this part. The Administrator may request additional 

relevant information after the submittal of a request for approval of construction or 

reconstruction. 

§ 63.567 Recordkeeping and reporting requirements. 

(a) The owner or operator of an affected source shall fulfill all reporting and recordkeeping 

requirements in §§ 63.9 and 63.10 of subpart A of this part in accordance with the provisions for 

applicability of subpart A to this subpart in Table 1 of § 63.560 and fulfill all reporting and 

recordkeeping requirements in this section. These reports will be made to the Administrator at 

the appropriate address identified in § 63.13 of subpart A of this part. 

(1) Reports required by subpart A and this section may be sent by U.S. mail, facsimile (fax), 

or by another courier. 

(i) Submittals sent by U.S. mail shall be postmarked on or before the specified date. 

(ii) Submittals sent by other methods shall be received by the Administrator on or before the 

specified date. 

(2) If acceptable to both the Administrator and the owner or operator of a source, reports 

may be submitted on electronic media. 

(b) Notification requirements. The owner or operator of an affected source shall fulfill all 

notification requirements in § 63.9 of subpart A of this part in accordance with the provisions for 

applicability of that section to this subpart in Table 1 of § 63.560 and the notification 

requirements in this paragraph. 

(1) Applicability. If a source that otherwise would not be subject to the emissions standards 

subsequently increases its HAP emissions calculated on a 24-month annual average basis after 

September 19, 1997 or increases its annual HAP emissions after September 20, 1999 or 

subsequently increases its gasoline or crude loading throughput calculated on a 24-month annual 

average basis after September 19, 1996 or increases its gasoline or crude loading annual 

throughput after September 21, 1998 such that the source becomes subject to the emissions 

standards, such source shall be subject to the notification requirements of § 63.9 of subpart A of 

this part and the notification requirements of this paragraph. 

(2) Initial notification for sources with startup before the effective date. The owner or 

operator of a source with initial startup before the effective date shall notify the Administrator in 

writing that the source is subject to the relevant standard. The notification shall be submitted not 

later than 365 days after the effective date of the emissions standards and shall provide the 

following information: 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(i) The name and address of the owner or operator; 

(ii) The address (i.e., physical location) of the source; 

(iii) An identification of this emissions standard that is the basis of the notification and the 

source's compliance date; 

(iv) A brief description of the nature, size, design, and method of operation of the source; 

(v) A statement that the source is a major source. 

(3) Initial notification for sources with startup after the effective date. The owner or 

operator of a new or reconstructed source or a source that has been reconstructed such that it is 

subject to the emissions standards that has an initial startup after the effective date but before the 

compliance date, and for which an application for approval of construction or reconstruction is 

not required under § 63.5(d) of subpart A of this part and § 63.566 of this subpart, shall notify 

the Administrator in writing that the source is subject to the standard no later than 365 days or 

120 days after initial startup, whichever occurs before notification of the initial performance test 

in § 63.9(e) of subpart A of this part. The notification shall provide all the information required 

in paragraph (b)(2) of this section, delivered or postmarked with the notification required in 

paragraph (b)(4) of this section. 

(4) Initial notification requirements for constructed/reconstructed sources. After the 

effective date of these standards, whether or not an approved permit program is effective in the 

State in which a source subject to these standards is (or would be) located, an owner or operator 

subject to the notification requirements of § 63.5 of subpart A of this part and § 63.566 of this 

subpart who intends to construct a new source subject to these standards, reconstruct a source 

subject to these standards, or reconstruct a source such that it becomes subject to these standards, 

shall comply with paragraphs (b)(4)(i), (ii), (iii), and (iv) of this section. 

(i) Notify the Administrator in writing of the intended construction or reconstruction. The 

notification shall be submitted as soon as practicable before the construction or reconstruction is 

planned to commence. The notification shall include all the information required for an 

application for approval of construction or reconstruction as specified in § 63.5 of subpart A of 

this part. The application for approval of construction or reconstruction may be used to fulfill the 

requirements of this paragraph. 

(ii) Submit a notification of the date when construction or reconstruction was commenced, 

delivered or postmarked not later than 30 days after such date, if construction was commenced 

after the effective date. 

(iii) Submit a notification of the anticipated date of startup of the source, delivered or 

postmarked not more than 60 days nor less than 30 days before such date; 

(iv) Submit a notification of the actual date of startup of the source, delivered or postmarked 

within 15 calendar days after that date. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(5) Additional initial notification requirements. (i) The owner or operator of sources subject 

to § 63.562(b)(2), (3), and (4), MACT standards, shall also include in the initial notification 

report required by paragraph (b)(2) and (3) the 24-month annual average or the annual actual 

HAP emissions from marine tank vessel loading operations, as appropriate, at all loading berths, 

as calculated according to the procedures in § 63.565(l). Emissions will be reported by 

commodity and type of marine tank vessel (barge or tanker) loaded. 

(ii) As an alternative to reporting the information in paragraph (b)(5)(i) of this section, the 

source may submit documentation showing that all HAP-containing marine tank vessel loading 

operations, not exempt by § 63.560(d), occurred using vapor tight vessels that comply with the 

procedures of § 63.563(a) and that the emissions were routed to control devices meeting the 

requirements specified in § 63.563(b). 

(c) Request for extension of compliance. If the owner or operator has installed BACT or 

technology to meet LAER consistent with § 63.6(i)(5) of subpart A of this part, he/she may 

submit to the Administrator (or State with an approved permit program) a request for an 

extension of compliance as specified in § 63.6(i)(4)(i)(B), (i)(5), and (i)(6) of subpart A of this 

part. 

(d) Reporting for performance testing of flares. The owner or operator of a source required 

to conduct an opacity performance test shall report the opacity results and other information 

required by § 63.565(e) and § 63.11 of subpart A of this part with the notification of compliance 

status. 

(e) Summary reports and excess emissions and monitoring system performance reports —

(1) Schedule for summary report and excess emissions and monitoring system performance 

reports. Excess emissions and parameter monitoring exceedances are defined in § 63.563(b). The 

owner or operator of a source subject to these emissions standards that is required to install a 

CMS shall submit an excess emissions and continuous monitoring system performance report 

and/or a summary report to the Administrator once each year, except, when the source 

experiences excess emissions, the source shall comply with a semi-annual reporting format until 

a request to reduce reporting frequency under paragraph (e)(2) of this section is approved. 

(2) Request to reduce frequency of excess emissions and continuous monitoring system 

performance reports. An owner or operator who is required to submit excess emissions and 

continuous monitoring system performance and summary reports on a semi-annual basis may 

reduce the frequency of reporting to annual if the following conditions are met: 

(i) For 1 full year the sources's excess emissions and continuous monitoring system 

performance reports continually demonstrate that the source is in compliance; and 

(ii) The owner or operator continues to comply with all recordkeeping and monitoring 

requirements specified in this subpart and subpart A of this part. 

(3) The frequency of reporting of excess emissions and continuous monitoring system 

performance and summary reports required may be reduced only after the owner or operator 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

notifies the Administrator in writing of his or her intention to make such a change and the 

Administrator does not object to the intended change. In deciding whether to approve a reduced 

frequency of reporting, the Administrator may review information concerning the source's entire 

previous performance history during the 5-year recordkeeping prior to the intended change, 

including performance test results, monitoring data, and evaluations of an owner or operator's 

conformance with operation maintenance requirements. Such information may be used by the 

Administrator to make a judgement about the source's potential for noncompliance in the future. 

If the Administrator will notify the owner or operator in writing within 45 days after receiving 

notice of the owner or operator's intention. The notification from the Administrator to the owner 

or operator will specify the grounds on which the disapproval is based. In the absence of a notice 

of disapproval within 45 days, approval is automatically granted. 

(4) Content and submittal dates for excess emissions and monitoring system performance 

reports. All excess emissions and monitoring system performance reports and all summary 

reports, if required per paragraph (e)(5) and (6) of this section, shall be delivered or postmarked 

within 30 days following the end of each calendar year, or within 30 days following the end of 

each six month period, if appropriate. Written reports of excess emissions or exceedances of 

process or control system parameters shall include all information required in § 63.10(c)(5) 

through (13) of subpart A of this part as applicable in Table 1 of § 63.560 and information from 

any calibration tests in which the monitoring equipment is not in compliance with PS 8 or other 

methods used for accuracy testing of temperature, pressure, or flow monitoring devices. The 

written report shall also include the name, title, and signature of the responsible official who is 

certifying the accuracy of the report. When no excess emissions or exceedances have occurred or 

monitoring equipment has not been inoperative, repaired, or adjusted, such information shall be 

stated in the report. This information will be kept for a minimum of 5 years and made readily 

available to the Administrator or delegated State authority upon request. 

(5) If the total duration of excess emissions or control system parameter exceedances for the 

reporting period is less than 5 percent of the total operating time for the reporting period, and 

CMS downtime for the reporting period is less than 10 percent of the total operating time for the 

reporting period, only the summary report of § 63.10(e)(3)(vi) of subpart A of this part shall be 

submitted, and the full excess emissions and continuous monitoring system performance report 

of paragraph (e)(4) of this section need not be submitted unless required by the Administrator. 

(6) If the total duration of excess emissions or process or control system parameter 

exceedances for the reporting period is 5 percent or greater of the total operating time for the 

reporting period, or the total CMS downtime for the reporting period is 10 percent or greater of 

the total operating time for the reporting period, both the summary report of § 63.10(e)(3)(vi) of 

subpart A of this part and the excess emissions and continuous monitoring system performance 

report of paragraph (e)(4) of this section shall be submitted. 

(f) Vapor collection system of the terminal. Each owner or operator of an affected source 

shall submit with the initial performance test and maintain in an accessible location on site an 

engineering report describing in detail the vent system, or vapor collection system, used to vent 

each vent stream to a control device. This report shall include all valves and vent pipes that could 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

vent the stream to the atmosphere, thereby bypassing the control device, and identify which 

valves are car-sealed opened and which valves are car-sealed closed. 

(g) If a vent system, or vapor collection system, containing valves that could divert the 

emission stream away from the control device is used, each owner or operator of an affected 

source shall keep for at least 5 years up-to-date, readily accessible continuous records of: 

(1) All periods when flow bypassing the control device is indicated if flow indicators are 

installed under § 63.563(a)(1) and § 63.564(b), and 

(2) All times when maintenance is performed on car-sealed valves, when the car-seal is 

broken, and when the valve position is changed (i.e., from open to closed for valves in the vent 

piping to the control device and from closed to open for valves that vent the stream directly or 

indirectly to the atmosphere bypassing the control device) if valves are monitored under 

§ 63.564(b). 

(h) The owner or operator of an affected source shall keep the vapor-tightness 

documentation required under § 63.563(a)(4) on file at the source in a permanent form available 

for inspection. 

(i) Vapor tightness test documentation for marine tank vessels. The owner or operator of an 

affected source shall maintain a documentation file for each marine tank vessel loaded at that 

source to reflect current test results as determined by the appropriate method in § 63.565(c)(1) 

and (2). Updates to this documentation file shall be made at least once per year. The owner or 

operator shall include, as a minimum, the following information in this documentation: 

(1) Test title; 

(2) Marine vessel owner and address; 

(3) Marine vessel identification number; 

(4) Loading time, according to § 63.563(a)(4)(ii) or (iii), if appropriate; 

(5) Testing location; 

(6) Date of test; 

(7) Tester name and signature; 

(8) Test results from § 63.565(c)(1) or (2), as appropriate; 

(9) Documentation provided under § 63.563(a)(4)(ii) and (iii)(B) showing that the repair of 

leaking components attributed to a failure of a vapor-tightness test is technically infeasible 

without dry-docking the vessel; and 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(10) Documentation that a marine tank vessel failing a pressure test or leak test has been 

repaired. 

(j) Emission estimation reporting and recordkeeping procedures. The owner or operator of 

each source complying with the emission limits specified in § 63.562(b)(2), (3), and (4) shall 

comply with the following provisions: 

(1) Maintain records of all measurements, calculations, and other documentation used to 

identify commodities exempted under § 63.560(d); 

(2) Keep readily accessible records of the emission estimation calculations performed in 

§ 63.565(l) for 5 years; and 

(3) Submit an annual report of the source's HAP control efficiency calculated using the 

procedures specified in § 63.565(l), based on the source's actual throughput. 

(4) Owners or operators of marine tank vessel loading operations specified in § 63.560(a)(3) 

shall retain records of the emissions estimates determined in § 65.565(l) and records of their 

actual throughputs by commodity, for 5 years. 

(k) Leak detection and repair of vapor collection systems and control devices. When each 

leak of the vapor collection system, or vapor collection system, and control device is detected 

and repaired as specified in § 63.563(c) the following information required shall be maintained 

for 5 years: 

(1) Date of inspection; 

(2) Findings (location, nature, and severity of each leak); 

(3) Leak determination method; 

(4) Corrective action (date each leak repaired, reasons for repair interval); and 

(5) Inspector name and signature. 

(l) The owner or operator of the VMT source required by § 63.562(d)(2)(iv) to develop a 

program, shall submit annual reports on or before January 31 of each year to the Administrator 

certifying the annual average daily loading rate for the previous calendar year. Beginning on 

January 31, 1996, for the reported year 1995, the annual report shall specify the annual average 

daily loading rate over all loading berths. Beginning on January 31, 1999, for the reported year 

1998, the annual report shall specify the annual average daily loading rate over all loading 

berths, over each loading berth equipped with a vapor collection system and control device, and 

over each loading berth not equipped with a vapor collection system and control device. The 

annual average daily loading rate under this section is calculated as the total amount of crude oil 

loaded during the calendar year divided by 365 days or 366 days, as appropriate. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(m) The number, duration, and a brief description for each type of malfunction which 

occurred during the reporting period and which caused or may have caused any applicable 

emission limitation to be exceeded shall be stated in a semiannual report. The report must also 

include a description of actions taken by an owner or operator during a malfunction of an 

affected source to minimize emissions in accordance with § 63.562(e), including actions taken to 

correct a malfunction. The report, to be certified by the owner or operator or other responsible 

official, shall be submitted semiannually and delivered or postmarked by the 30th day following 

the end of each calendar half. 

(n)(1) As of January 1, 2012 and within 60 days after the date of completing each 

performance test, as defined in § 63.2, and as required in this subpart, you must submit 

performance test data, except opacity data, electronically to EPA's Central Data Exchange by 

using the ERT (see http://www.epa.gov/ttn/chief/ert/ert tool.html/ ) or other compatible 

electronic spreadsheet. Only data collected using test methods compatible with ERT are subject 

to this requirement to be submitted electronically into EPA's WebFIRE database. 

(2) All reports required by this subpart not subject to the requirements in paragraph (n)(1) of 

this section must be sent to the Administrator at the appropriate address listed in § 63.13. If 

acceptable to both the Administrator and the owner or operator of a source, these reports may be 

submitted on electronic media. The Administrator retains the right to require submittal of reports 

subject to paragraph (n)(1) of this section in paper format. 

§ 63.568 Implementation and enforcement. 

(a) This subpart can be implemented and enforced by the U.S. EPA, or a delegated authority 

such as the applicable State, local, or Tribal agency. If the U.S. EPA Administrator has delegated 

authority to a State, local, or Tribal agency, then that agency, in addition to the U.S. EPA, has the 

authority to implement and enforce this subpart. Contact the applicable U.S. EPA Regional 

Office to find out if implementation and enforcement of this subpart is delegated to a State, local, 

or Tribal agency. 

(b) In delegating implementation and enforcement authority of this subpart to a State, local, 

or Tribal agency under subpart E of this part, the authorities contained in paragraph (c) of this 

section are retained by the Administrator of U.S. EPA and cannot be transferred to the State, 

local, or Tribal agency. 

(c) The authorities that cannot be delegated to State, local, or Tribal agencies are as 

specified in paragraphs (c)(1) through (4) of this section. 

(1) Approval of alternatives to the requirements in §§ 63.560 and 63.562(a) through (d). 

(2) Approval of major alternatives to test methods for under § 63.7(e)(2)(ii) and (f), as 

defined in § 63.90, and as required in this subpart. 

(3) Approval of major alternatives to monitoring under § 63.8(f), as defined in § 63.90, and 

as required in this subpart. 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

(4) Approval of major alternatives to recordkeeping and reporting under § 63.10(f), as 

defined in § 63.90, and as required in this subpart. 
Page 49: [1] Deleted Author 

2. Option 1: 

NSPS 

requirements not 

subject to the 

NSPS for PM in 

40 CFR 60.102. 

Continuous opacity 

monitoring system.

Not applicable Not applicable. 

3. Option 2: PM 

limit not subject 

to the NSPS for 

PM in 40 CFR 

60.102. 

ab. Continuous 

opacity monitoring 

system. used to 

comply with a sitespecific opacity 

limit 

ElectrostaticCyclone, 

fabric filter, or 

electrostatic 

precipitator 

Maintain the hourly3-hour rolling 

average opacity of emissions from 

your catalyst regenerator vent no 

higher than the site-specific opacity 

limit established during the 

performance test. 

Page 59: [2] Deleted Author 

 (2) If you use a wet scrubber of the non-venturi jet-ejector design, you're not required to 

install and operate a continuous parameter monitoring system for pressure drop. 

Page 62: [3] Deleted Author 

 c. Measure opacity 

of emissions. 

Continuous 

opacity 

monitoring 

system. 

You must collect opacity monitoring data 

every 10 seconds during the entire period of 

the Method 5B or 5F performance test and 

reduce the data to 6-minute averages. 

3. Option 

2: PM 

limit 

a. Measure PM 

emissions. 

See item 2. of 

this table. 

See item 2. of this table. 

 b. Compute coke 

burn-off rate and 

PM emission rate. 

Equations 1 and 

2 of §63.1564. 

Page 133: [4] Deleted Author 

 k. If you use a continuous 

emission monitoring system, 

measure TRS concentration. 

Data from 

continuous 

emission 

monitoring 

system. 

Collect TRS data every 15 

minutes for 24 consecutive 

operating hours. Reduce the 

data to 1-hour averages 

computed from four or more 

data points equally spaced 

over each 1-hour period. 

Page 314: [5] Deleted Author 
63.10(d)(5)(ii) Yes Except that actions taken during a startup, shutdown, or 

malfunction that are not consistent with the startup, 

shutdown, and malfunction plan and that cause the source to 

exceed any applicable emission limitation do not need to be 

reported within 2 and 7 days of commencing and completing 

the action, respectively, but must be included in the next 

periodic report.