***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

EO12866_RefineryRTR 2060 AQ75 NPRM Part 63Subpart UUU CC Y Part60Subpart J Ja_RegText_201402 21

Title 40: Protection of Environment

PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS FOR SOURCE CATEGORIES Subpart UUU—National Emission Standards fo r 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 es tablishes 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 gasolin e, 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 inte rmediate 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 (b) [Reserved] Deleted: 12***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***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 con tinuous 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 ve nt stream away from a control device used to comply with the requireme nts 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 fo r 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 writte n 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 brie f 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 achie ve 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 w ith 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 contro l 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 em ission 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 Nick el (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 operat e 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 lim its 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 th i s 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: 

##   

#  
xy oxy r a r c 

### %O Q K %O %CO %CO Q K Q K %CO %CO Q K R 3 2 2 3 2 2 1 

### 2               

    (Eq. 1)

Where:

R c = Coke burn-off rate, kg/hr (lb/hr); Q r

= 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 Q r ; Q a = Volumetric flow rate of air to catalytic cr acking 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***

%CO 2 = Carbon dioxide concentration in regenerator exhaust, percent by volume (dry basis); %CO = Carbon monoxide concentration in regenerator exhaust, percent by volume (dry basis);

%O 2 = Oxygen concentration in regenerator exhaust, percent by volume (dry basis);

K 1 = Material balance and conversion factor, 0.2 982 (kg-min)/(hr-dscm-%) (0.0186 (lb-min)/(hrdscf-%));

K 2 = Material balance and conversion factor, 2. 088 (kg-min)/(hr-dscm) (0.1303 (lb-min)/(hrdscf));

K 3 = Material balance and conversion factor, 0.0 994 (kg-min)/(hr-dscm-%) (0.0062 (lb-min)/(hrdscf-%)); Q oxy = Volumetric flow rate of oxygen-enriched ai r stream to regenerator, as determined from instruments in the catalytic cracking unit control room, dscm/min (dscf/min); and

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

c sd s 

### R Q C K E  

 (Eq. 2)

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

C s = Concentration of PM, g/dscm (lb/dscf); Q sd = Volumetric flow rate of the catalytic cr acking unit catalyst regenerator flue gas as measured by Method 2 in appendix A to part 60 of this chapter, dscm/hr (dscf/hr);

R c = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr); and K = Conversion factor, 1.0 (kg 2 /g)/(1,000 kg) (1,000 lb/(1,000 lb)).



### ' 0

. 1 K R H A E

c

s 

###           (Eq. 3)

Where:

E s = 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 procedur es for determining the heat input rate ;
R c = 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 (kg 2 /g)/(1,000 kg) (10 3 lb/(1,000 lb)).



###          

st st 

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

Where: Opacity L imit = Maximum permissible hourly average opacity, percent, or 10 percent, whichever is greater; Opacity st = Hourly average opacity measured during the source test, percent; and

PMEmR st = 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:

sd Ni Ni1 

### Q C E   (Eq. 5)

Where:

E Ni1 = Mass emission rate of Ni, mg/hr (lb/hr); and

C Ni = 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   Ni/hr g 13 (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 lb/ k 1

Field Code Changed Deleted: l Deleted: runs Deleted: s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: Opacity 1 = Opacity value for use in Equation 7 of this section, percent, or 10 percent, whichever is greater; and

NiEmR1 st = 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.

st st mon 1 1 

### E-Cat Q Opacity ng Limit Ni Operati   

, (Eq. 7)

Where: Ni Operating Limit 1 = Maximum permissible hourly average Ni operating limit, percent-acfmppmw, i.e., your site-specific Ni operating limit; Q mon,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-Cat st = Ni concentration on equilibrium catal yst 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 us ing 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 sd Ni Ni 

### R Q C E 2 

### 

 (Eq. 8)

Where:

E Ni2 = Normalized mass emission rate of Ni, mg/kg coke (lb/1,000 lbs coke).

st st 2 

### Opacity NiEmR2 Opacity   coke mg/kg 1.0 (Eq. 9)

Where: Opacity 2 = Opacity value for use in Equation 10 of this section, percent, or 10 percent, whichever is greater; and

NiEmR2 st = 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.

st c st mon st 2 2 

### R Q E-Cat Opacity ng Limit Ni Operati

, , 

###    (Eq. 10) Deleted: lbs/1,000 lbs of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Where: Ni Operating Limit 2 = Maximum permissible hourly average Ni operating limit, percent-ppmwacfm-hr/kg coke, i.e., your site-specific Ni operating limit; and

R c,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 emissi on 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, maintena nce, and monitoring pl an 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:



### E-Cat Q Opacity ng Value Ni Operati mon 1 

###    (Eq. 11)

Where: Ni Operating Value 1 = Maximum permissible hourly averag e Ni standard operating value, %- acfm-ppmw; Opacity = Hourly average opacity, percent; Q mon = 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 Q E-Cat Opacity ng Value Ni Operati  

 (Eq. 12)

Where: Ni Operating Value 2 = Maximum permissible hourly averag e 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 operat e at all times according to the procedures in the plan. (4) The emission limitations a nd 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 (O 2 ) 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 “C O 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 str eams are introduced into the flame zone. (iv) If you elect to comply with the alternative li mit 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 emissi on 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 alte rnative 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 purg ing 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 pu rging 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 operat e 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:

s c 4 

### Q M K E  (Eq. 1)

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

K 4 = Constant, 6.0 × 10 − 5 (kilograms per milligram)(minutes per hour);

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

#  

s methane TOC 5 

### Q C C K E 6 1

  (Eq. 2)

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

K 5 = 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);

C TOC = 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;

C methane = 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 C methane equals zero; and Q s = Vent stream flow rate, dry standard cubic meters per minute, at a temperature of 20 degrees C.



### % 100    i o i 

### E E E %reduction (Eq. 3)

Where:

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

E o = 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 (O 2 ) content in the gas stream using Equation 4 of this section as follows: 

#          

   2 methane TOC %O NMTOC, 

### %O C C C 20.9% 17.9% 6 1

2 3 (Eq. 4)

Where:

C NMTOC, 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 provi ded in paragraph (a)(1)(i) of this section (Option 1); or (ii) You elect the TOC percent reduction or conc entration 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 emissi on 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 em ission 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 reactor s in the catalytic reforming unit are regenerated in separate regeneration systems, then thes e 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 st andard 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 operat e 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) thro ugh (iv) of this section to determine initial compliance with the emission limitations. (i) Correct the measured HCl concentration for oxygen (O 2 ) content in the gas stream using Equation 1 of this section as follows:

HCl 2 %O HCl, 

### C %O C        

  20.9% 17.9%

2 3 (Eq. 1)

Where:

C HCl,3%O2 = Concentration of HCl on a dry basis in ppmv corrected to 3 percent oxygen or 1 ppmv, whichever is greater;

C HCl = Concentration of HCl on a dry basis in ppmv, as measured by Method 26A in 40 CFR part 60, appendix A; and

%O 2 = 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 em ission reduction from the mass emission rates using Equation 3 of this section as follows:

s HCl 6 HCl 

### Q C K E  (Eq. 2)

Where:

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

K 6 = 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 Q s = Vent stream flow rate, dscm/min, at a temperature of 20 degrees C.



### % 100

, , , 

### 

  i HCl o HCl i HCl



### E E E ion HCl%reduct (Eq. 3)

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

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

E HCl,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 it HCl,RegLim

e HCl,AveTub mit HCl,ppmvLi 

### C C C C 9

. 0 (Eq. 4)

Where:

C HCl,ppmvLimit = Maximum permissible HCl concentratio n for the HCl concentration operating limit, ppmv;

C HCl,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

C HCl,RegLimit = Maximum permissible outlet HCl concen tration 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
e HCl,AveTub HCl,%Limit 

### ion %HClReduct ion %HClReduct C C 100 100 9

. 0 (Eq. 5)

Where:

C HCl,%Limit = Maximum permissible HCl concentration fo r the percent reduction operating limit, ppmv; %HCl Reduction Limit = Minimum permissible HCl reduction for the applicable catalytic reforming unit as listed in Table 22 of th is subpart, either 97 or 92 percent; and

%HCl Reduction Test = 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 emissi on 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 em ission 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 operat e 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 (O 2 ) 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 AM ENDMENTS 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 alternat ive 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 meas adj 

### %O C C 9

. 20 9

. 20 (Eq. 1)

Where:

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

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

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

%O 2 = oxygen concentration measured on a dry basis, percent. (5) Demonstrate initial compliance with each emissi on 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 em ission 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 alte rnative 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 mo nitor was continuously operating and the pilot light was continuously present during each 1-hour period. (C) Maintain the net heating value of the gas bei ng 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 alte rnative limit in paragr aph (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 averag e 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, y ou 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 ma intenance 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 th e 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 repor ting 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 indi cative 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 syste ms 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 oper ated 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 ma lfunction 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 docum entation, 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 occurren ce 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 pract ice standard where initial compliance is not demonstrated using a performance test, opacity ob servation, 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 test s 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 shutdow n unless specified by the Administrator or an applicable subpart. You may not conduct perfor mance tests during periods of malfunction. You must record the process inform ation that is necessary to do cument 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 obse rvations, 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 w ithin 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 pr operties. Examples of analytical methods include, but are not limited to: (i) Use of material balances based on pro cess 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 li mitations 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 equilib rium 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 ma ximum level. You must make this adjustment using Equation 1 of this section as follows:

st st 

### Ecat NiEmR1 Ecat-Limit   Ni/hr g 13 (Eq. 1)

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

NiEmR1 st = 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

Ecat st = Average equilibrium Ni concentration from laboratory test results, mg/kg. (2) If you must meet the HAP metal emission li mitations 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 ope rating 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   off

- burn coke mg/kg 1.0 (Eq. 2)

Where:

NiEmR2 st = 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 catal yst 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 maxi mum 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 assessmen t 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 SO 2 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 s ource subject to the NSPS that has al ready 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 in itial 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, y ou 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, calibra te, 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. Yo u must have a minimum of four successive cycles of operation to have a valid hour of da ta (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 requir ement, if applicable. You must use all the data collected during all other periods in assessing the operation of the c ontrol 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 th e 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 de vice (or exiting the catalyst regenerator if you do not use an add-on control device). (iii) Calculate and record the hourly average actua l 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 other air gas 

### P Temp Q Q Q atm 1 K 293 dscfm scfm 1.12 (Eq. 1)

Where Q gas = 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); Q air = Volumetric flow rate of air to regenerator, as determined from the control room instrumentations, dscfm; Q other = Volumetric flow rate of other gases ente ring 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.); Temp gas = 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

P vent = 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 P vent = 1 atm. (2) You may use this alternative to calculating Q r , 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 fl ow rate using Equation 2 of this section as follows: 

#  

2 2 oxy xy air

r 

### %O %CO %CO Q %O Q Q

   

  

 100 100

79 (Eq. 2)

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

Q r

= 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);

%O xy = Oxygen concentration in oxygen-enriched air stream, percent by volume (dry basis); Q oxy = Volumetric flow rate of oxygen-enriched ai r stream to regenerator as determined from the catalytic cracking unit control room in strumentations, dscm/min (dscf/min);

%CO 2 = Carbon dioxide concentration in regenerator exhaust, percent by volume (dry basis); CO = Carbon monoxide concentration in regenerator exhaust, percent by volume (dry basis); and

%O 2 = 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 leas t 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 leas t 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 da ta 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 co ntinuous emission monitoring system, a TOC continuous emission monitoring system, or HC l 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 co mply 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 th e affected source will c ontinuously comply with the emission limitations and the schedule for this demonstration. You must certify that you will establish an operating limit for the monitored pa rameter(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 requ irements 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) ap proved by the Administrator; and (iii) You are required by this subpart to insta ll, 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 r econstruction 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 submissi on, 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 requir ed information has been submitted previously, you do not have to provide a separate notificati on 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 st atus, 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 prepar e 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 op erating 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, th e 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 concentratio n 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 manuf acturer'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 monitori ng 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 th e 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 m onitor 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 en d 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 perm itting regulations pursuant to part 70 or 71 of this chapter, and if the permitting authority has established dates fo r 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 cont inuous 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 deviatio n 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 th e 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 test ed. 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 pr eparation 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 informatio n 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 reduc tions. During this pre-approved time period, the emission control device may be taken out of service while maintenan ce 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 appli cable 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 app licable 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 informa tion in paragraphs (j)(2)(i) through (v) of this section. (i) A description of the planned routine maintena nce 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 maintenan ce until the next unit turnaround. (v) Actions you will take to minimize emissi ons 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 evaluatio n 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 e ach 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 suppor ted 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 li mited to, flash drives) by registered letter to the EPA. The electronic media must be clear ly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: WebF IRE 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 completi ng 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 owne r 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 re gistered 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 evalua tion 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 sup porting 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 th e 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 stan dard, record and retain a list of the affected sources or equipment, an estimate of the volu me 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 sy stem 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 mo nitoring 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 subj ect 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 ch anges that affect emission control system performance including, but not limited to, the locati on 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 St ate, 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 meth ods 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 sh all 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 objectivel y 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 ad ditional 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, re generator (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 refo rming unit and ancillary equipm ent 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 re move 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 co ntinues 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, operati ng 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 de vices 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 gase ous 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 appr oved alternative method.

Incinerator means an enclosed combustion device that is used for destroying organic compounds, with or without heat recovery. Auxili ary 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 injecti on, or caustic injection control device that treats (in-situ) the catalytic reformi ng 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 emis sions 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, emis sions of particulate matter that serve as a surrogate measure of the total emissions of pa rticulate 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 limite d to: antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium as measured by Methods 5, 5B or 5F in A ppendix 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 stream s 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 wh ich 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, emi ssions 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 concentr ation, 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—Operat ing 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 tocomply 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 tocomply with a sitespecific opacity limit Cyclone or electrostatic precipitator Maintain the 3-hou r 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-hou r 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 tocomply 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-hou r 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 y our catal y tic crackin g 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 device 1 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 scrubber 2

, coke burn-off rate or the gas flow rate entering or exiting the control device 1

, 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 y our catal y tic crackin g unit is . . . Deleted: And

Deleted: 2. Option 1: NSPS limi ts 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 scrubber 2 , the coke burn-off rate or the gas flow rate entering or exiting the control device 1

, 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 reg e nerator 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 y our catal y tic crackin g unit is . . . Deleted: And

Deleted: device 1 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 device 1

. 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 device 1 ; or continuous parameter monitoring systems to measure and record the coke burn-off rate or the gas flow rate entering or exiting the control device 1 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 scrubber 2 , gas flow rate entering or exiting the control device 1 , 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 y our catal y tic crackin g 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 rate 1
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 device 1

. 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 device 1 ; or continuous parameter monitoring systems to measure and record the coke burn-off rate or the gas flow rate entering or exiting the control device 1 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 scrubber 2 , gas flow rate entering or exiting the control device 1 , 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 y our catal y tic crackin g 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 rate 1***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 A ppendix 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 A ppendix A -2 to part 60 of this chapter, as applicable. c. Conduct gas molecular weight analysis. Method 3, 3A, or 3B in A ppendix A -2 to part 60 of this chapter, as applicable. d. Measure moisture content of the stack gas. Method 4 in A ppendix 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, A ppendix A -3 ) to determine PM emissions and associated moisture content for units without wet scrubbers. Method 5
or 5B (40 CFR part 60, A ppendix 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 o p acit y 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 CFRpart 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 A ppendix A to this subpart 1 ; or EPA Method 6010B or 6020 or EPA Method 7520 or 7521 in SW

– 846 2 ; 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, A ppendix A

8 ).

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 (notapplicable 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 EP A 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; CO 2 , O 2 , 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; CO 2 , O 2 , 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; CO 2 , O 2 , 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; CO 2 , O 2 , 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 sc rubber), 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; CO 2 , O 2 , 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; CO 2 , O 2 , 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—Conti nuous 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-minuteaverage 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-fuelsare 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-minuteaverage 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-minuteaverage 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—Continuo us 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 thePM 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 §63.1572 1 ; 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 §63.1572 1 ; 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 week 2 ; collecting the hourly average gas flow rate monitoring data according to §63.1572 1 ; 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 thedaily 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 Nioperating 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 week 2 ; 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 week 2 ; 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 §63.1572 1 ; determining and recording equilibrium catalyst Ni concentration at least once a week 2 ; 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 Nioperating 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 thedaily 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 dailyaverage 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 y ou 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 Particle s (Instrumental Analyzer Procedure) in A ppendix 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, Dir ect 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 HA P 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 ex ceed 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—Conti nuous 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, opera te, 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 complia nce 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 z one, 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—Conti nuous 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 Cata lytic 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 exi s ting

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 ],
c ollecting 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 applicablecatalytic 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 contin u ous 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 contin u ous 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. , Chlorsorb TM 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 Chlorsorb TM System); and the weekly average chloride level on the sorbent l eaving the adsorption system must not exceed the design or manufacturer's recommended limit (1.8 weight percent for the Chlorsorb TM System). [70 FR 6955, Feb. 9, 2005]

Table 24 to Subpart UUU of Part 63—Continuo us 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 rejuvenation 1 ; 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 HC l outlet concentration limit. Colormetric tube sampling system to measure the HC l 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 HC l 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 HC l 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., Chlorsorb TM 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 Cata lytic 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 toentering 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 toentering 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 ofthe 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 thescrubber 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 theexhaust 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., Chlorsorb TM 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. Govern ment 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. C opies 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 §63.1572 1 ; 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 rate 2 and total water (or scrubbing liquid) flow rate monitoring data according to §63.1572; and determining andrecording the hourly average liquidto-gas ratio; and determining andrecording 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 §63.1572 1 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 rate 2 and total water (or scrubbing liquid) flow rate monitoring data according to §63.1572; and determining andrecording the hourly average liquidto-gas ratio; and determining andrecording 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 theexhaust 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 ad sorption 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., Chlorsorb TM 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 Chlorsorb TM 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 3 ; 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 Chlorsorb TM 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 C h lorsorb TM 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 Chlorsorb TM 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 yo u 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 me thod 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, Determin ation 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 Pub lication 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: Clorsorb TM

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-1 08, 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 (SO 2 ) 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 SO 2 (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 SO 2 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 SO 2 (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 SO 2 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—Continuo us 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 SO 2 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 SO 2 (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 SO 2 (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 (O 2 ) emissions. Calculate the reduced sulfur emissions as SO 2 (dry basis) at zero percent excess air. Exception: You can use an instrument having an air or SO 2 dilution and oxidation system to convert the reduced sulfur to SO 2 for continuously monitoring and recording the concentration (dry basis) at zero percent excess air of the resultant SO 2 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 O 2 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 SO 2 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 SO 2 (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 SO 2 (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 O 2 emissions for each exhaust stack. Calculate the reduced sulfur emissions as SO 2 (dry basis), at zero percent excess air. Exception: You can use an instrument having an air or O 2 dilution and oxidation system to convert the reduced sulfur to SO 2 for continuously monitoring and recording the concentration (dry basis) at zero percent excess air of the resultant SO 2 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 O 2 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 SO 2 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 SO 2 concentration (for an oxidation or reduction system followed by incineration) or measure the concentration of reduced sulfur (or SO 2 if you use an instrument to convert the reduced sulfur to SO 2 ) for a reduction control system without incineration. Data from continuous emission monitoring system. Collect SO 2 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 O 2 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 O 2 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 SO 2 if you use an instrument to convert the reduced sulfur to SO 2 ) 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 (m 2 ) or 54 square feet, you must use the centroid of the cross section as the sampling point. If the cross-sectional area is 5 m 2 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 SO 2 equivalent for each run after correcting for moisture and oxygen. The arithmetic average of the SO 2 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 p p mv (dry basis) SO 2 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 SO 2 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 SO 2 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 SO 2 (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 SO 2 (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 SO 2 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 SO 2 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 SO 2 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 SO 2 (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 SO 2 (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 SO 2 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 SO 2 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 SO 2 (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—Continuo us 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 SO 2 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 SO 2 monitoring data (dry basis, percent excess air) according to §63.1572; determining and recording each 12-hour rolling average concentration of SO 2 ; maintaining each 12-hour rolling average concentration of SO 2 at or below the applicable emission limitation; and reporting any 12- hour rolling average concentration of SO 2 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 SO 2 (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 O 2 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 SO 2 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 SO 2 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 SO 2 ; maintaining each 12-hour rolling average concentration of SO 2 at or below the applicable emission limitation; and reporting any 12-hour rolling average concentration of SO 2 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 SO 2 (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 O 2 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 SO 2 concentration (dry basis) at zero percent oxygen or reduced sulfur compounds calculated as ppmv SO 2 (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 O 2 monitoring data according to §63.1572; and maintaining the average O 2 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 Fr om 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 sha ll 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 O 2 monitor for correcting the data for excess air. The requirements in 40 CFR 60.105a(d).

3. CO 2 , O 2 , 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 . SO 2 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 O 2 monitor for correcting the data for excess air. A ppendix B); span value of 500 ppm SO 2 , or if using Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the highest O 2 concentration ; use Methods 6 or 6C (40 CFR part 60, Appendix A4) for certifying the SO 2 monitor and Methods 3A or 3B (40 CFR part 60, A ppendix A -2 ) for certifying the O 2 monitor; and procedure 1 (40 CFR part 60, A ppendix F) except relative accuracy test audits are required annually instead of quarterly. 7 . Reduced sulfur and O 2 continuous emission monitoring system for sulfur recovery unit with reduction control system not followed by incineration; this monitor must include an O 2 monitor for correcting the data for excess air unless exempted. Performance specification 5 (40 CFR part 60, A ppendix 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 O 2 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, A ppendix A -2 ) for certifying the O 2 monitor ; if Method 3A or 3B yields O 2 concentrations below 0.25 percent during the performance evaluation, the O 2 concentration can be assumed to be zero and the O 2 monitor is not required; and procedure 1 (40 CFR part 60, A ppendix F), except relative accuracy test audits, are required annually instead of quarterly. 8 . Instrument with an air or O 2 dilution and oxidation system to convert reduced sulfur to SO 2 for continuously monitoring the concentration of SO 2 instead of reduced sulfur monitor and O 2 monitor. Performance specification 5 (40 CFR part 60, A ppendix B); span value of 375 ppm SO 2 or if using Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the highest O 2 concentration ; use Methods 15 or 15A for certifying the reduced sulfur monitor and 3A or 3B for certifying the O 2 monitor; and procedure 1 (40 CFR part 60, A ppendix 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 O 2 monitor for correcting the data for excess air. Performance specification 5 (40 CFR part 60, appendix B).

10 . O 2 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. O 2 monitor for oxygen concentration Install, operate, and maintain each O 2 monitor Deleted: a

Deleted: a

Deleted: a

Deleted: 5 Deleted: a

Deleted: a Deleted: O 2 monitor

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 O 2 monitor must be selected between 20 and 100 percent; conduct performance evaluations for O 2 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 O 2 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 opera ting, confirm that the meters read zero. Conduct a calibration check at least annually; conduct calibration checks following any pe riod 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 complywith 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 paramete r monitoring system for gas flow rate as close as practical to the continuou s opacity monitoring system; and if you don’t use a continuous opacity monitoring system, install the continuous paramete r 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 temp erature 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
sensors 2 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 sc rubbers 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 requi rement 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 emi ssion 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 th e 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 aff ected 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 engineeringassessment (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 requirem ent 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) Applica tion 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/V E 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 Te st 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 complyingwith §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) COM S 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 SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2 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 Re sults 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 CM S 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 Availab i l ity 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 SO 2 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 flu o rescent (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 detect or 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 wa velength. 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 proportion al 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 measuremen t 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 meas urement system output reading from the initial value for the mid-range calibration standard afte r 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 si ze effects are substantially < 1 percent for most elements. The calibration standards should be prepar ed 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 si ze 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 li mitations 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 bery llium (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 ruptur e. 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 equiva lent to grind/mix catalyst and binders, if used, to produce uniform particle samples. 6.1.2 Sample Press/Fluxer. Stainless steel, or equi valent 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-fo u rth 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 a ccuracy 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 di spersive 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 calibra tion drift test by analyzing the analyte concentration output by the measurement systemwith 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 perfo rmed 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 f ile 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 .Response InitialCal esponse lyzerCal.R CurrentAna 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    esponse IdealCal.R .Response InitialCal esponse lyzerCal.R CurrentAna alue Accuracy V (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 equiva lent 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 analys is 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 samp le 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 det ectable 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: Zero a Low-Range b Mid-Range c High-Range d Accuracy Std e 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 SOUR CE 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 so urce 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 repr esenting 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 oper ation 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 petrol eum refining process units meeting the criteria in paragraph (a) of this section; (3) All wastewater streams and treatment opera tions associated with petroleum refining process units meeting the criteria in paragraph (a) of this section; (4) All equipment leaks from petroleum refini ng 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 ap plicability criteria of subpart Y, §63.560; (7) All storage vessels and equipment leaks asso ciated with a bulk gasoline terminal or pipeline breakout station classified under Standa rd 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 op erations 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 YE ARS 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 provi sions 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 un it constructed on or before August 18, 1994, shall follow the procedures specified in paragra phs (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 fr om 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 un it 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 distilla tion 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 di stillation 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 distilla tion 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 proce ss 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 refi ning 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) S ources 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. Ma rine 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 applicabilit y 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 potentia l 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 reconstructe d 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 reconstruc tion 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 §63.4 28(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, gaso line 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 exis ting 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 ch ange creating an additional Gr oup 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 Complian ce 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 para graphs (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 petrol eum 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 th is 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 comp ly with the reporting and recordkeeping requirements that are applicable to existing so urces including, but not limited to, the reports listed in paragraphs (l)(3)(i) through (vii) of th is 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 repor t 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 §63.4 28(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 s ource. 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 compli ance 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, su bpart 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 subj ect 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 subj ect 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) electin g 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 th at it is unsafe to perform the seal gap measurements required in §60.113b(b) of subpar t 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 re port, identify the vessel, provide the information listed in §60.113b(a)(2) or §60.113b(b)(4)(iii), a nd 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 re quired 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 speci fied 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 ga p 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 w ith paragraph (n)(9)(ii) of this section, the owner or operator shall, in the next periodic re port, 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 c ontrol 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 th at 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 re port, 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 equipmen t 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 pa ragraph (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 th at 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 comp ly 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 th e same term is defined in subpart A and in this section, it shall have the me aning 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 object ively 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 an nual average of the liquid storage temperature for liquids stored above or below the ambient temper ature or at the local annual average temperature reported by the National Weather Service for li quids 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 intr oduced 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 sy stem 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), recove ry 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 (ven ting), deheading, draining, and decoking (coke cutting). Delayed coker vent means a vent that is typically interm ittent 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. Distillati on unit includes the distillate receiver, reboiler, and any associated vacuum pump or steam jet. Emission point means an individual miscellaneous pro cess vent, storage vessel, wastewater stream, equipment leak , decoking operation or heat exchange system associated with a petroleum refining process unit; an indivi dual storage vessel or equipment leak associated with a bulk gasoline terminal or pipeline breakout station cl assified under Standard Industrial Classification code 2911; a gasoline loading rack classified un der 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 co nnection 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, ai r-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 infiltr ation (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 dir ected 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 fl are 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 opera ting conditions. These units are also referred to as campaign plants or blocked operations.

Flow indicator means a device that indicates whether ga s 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 pr essures for use as fuel in heaters, furnaces, boilers, incinerators, gas turbines, and other comb ustion 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 atmospheri c. The gaseous streams can contain a mixture of methane, light hydrocarbons, hydrogen and other miscellaneous species.

Gasoline means any petroleum distillate or petroleu m distillate/alcohol blend having a Reid vapor pressure of 27.6 kilopascals or greater th at 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 locat ed 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 co mmodities 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 th an 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-liqui d 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 equalto 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 ye ar or greater as calculated according to the procedures in 40 CFR 61.342 of subpart FF of pa rt 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 pro cedures 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 (Cl 2 ), hydrogen bromide (HBr), bromine (Br 2 ), 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 an d all water lines to and from these heat exchangers. Sample coolers or pump seal coolers are not considered h eat 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 ex posure 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 h eat 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 en ergy 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 pr essure 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 specifi ed 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 applie d 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 intentionall y entrained in lower and upper steam. Perimeter assist air includes all assist air except premix assist air. Periodically discharged means discharges that are intermi ttent 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 th e Standard Industrial Classification code for petroleum refining (2911), and used primarily for the following: (1) Producing transportation fuels (such as gasolin e, 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 re forming intermediate petroleum streams. (4) Examples of such units include, but are not limited to, petroleum-based solvent units, alkylation units, catalytic hydrotreating, cataly tic 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 pur pose of this subpart, process unit includes, but is not limited to, chemical manufacturing pro cess 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 dela y of repair of leaking components until the next scheduled process un it shutdown is not considered a process unit shutdown. The use of spare equipment and techni cally 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 ro of 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 specifica tions of §63.119(b) of subpart G except for §63.119(b)(5) and (b)(6); ( ii ) An external floating roof meeting the speci fications 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 wa stewater 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 proces ses 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 stor age 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 su pplied 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 pr oduct 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 pa rt 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 th is subpart shall apply at all times. (c) Table 6 of this subpart specifies the provisi ons 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 complian ce 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 main tained 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 sour ce 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 1 2 1C 2 1 2 1 A 

### EWW EWW EMV EMV R EGLR EGLR ES ES EPV EPV E ) ( 05

. 0 02

. 0

where:

E A = Emission rate, megagrams per year, allowed for the source.

0.02 Σ EPV 1 = Sum of the residual emissions, megagrams per year, from all Group 1 miscellaneous process vents, as defined in §63.641.

Σ EPV 2 = 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***

0.05 Σ ES 1 = Sum of the residual emissions, megagrams per year, from all Group 1 storage vessels, as defined in §63.641.

Σ ES 2 = Sum of the emissions, megagrams per year, from all Group 2 storage vessels, as defined in §63.641.

Σ EGLR 1C = Sum of the residual emissions, megagrams per year, from all Group 1 gasoline loading racks, as defined in §63.641.

Σ EGLR 2 = Sum of the emissions, megagrams per year, from all Group 2 gasoline loading racks, as defined in §63.641. (R) Σ EMV 1 = 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 EMV 2 = Sum of the emissions, megagrams per y ear from all Group 2 marine tank vessels, as defined in §63.641.

Σ EWW 1C = Sum of the residual emissions from al l Group 1 wastewater streams, as defined in §63.641. This term is calculated for each Group 1 stream according to the equation for EWW ic in §63.652(h)(6).

Σ EWW 2 = Sum of emissions from all Group 2 wastew ater 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 po ints, 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 invol ved 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 precl ude 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 equi pment 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 in formation 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 fo r 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 mu st 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 indi cative 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 syste ms 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 ma lfunction 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 paragr aph (p)(1) of this sec tion. This affirmative defense report shall be included in the first Pe riodic 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 vi olation 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 requir ements 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 pa ragraph (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 monito ring 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 he at 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 para graph (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 incine rator, 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 co mply 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 th at 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 app licable 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, A ppendix 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 sp ecified 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, A ppendix 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) concentr ation 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 in tervals in time, such as 15-mi nute intervals during the run. (ii) The TOC concentration (C TOC ) 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:

C TOC = Concentration of TOC (minus methane and ethane), dry basis, parts per million by volume.

C

ji = 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) (E TOC ) shall be calculated using the following equation if Method 18 is used:

s n

j j j 2 

### Q M C K E      

 

# 

 1

where: E = Emission rate of TOC (minus methane an d ethane) in the sample, kilograms per day.

K 2 = 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.

C

j = 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. C j includes all organic compounds measured minus methane and ethane.

M

j = Molecular weight of organic compound j, gram per gram-mole. Q s = 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 (E TOC ) shall be calculated using the following equation:

s TOC 2 TOC 

### MQ C K E 

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

E TOC =Emission rate of TOC (minus methane and ethane) in the sample, kilograms per day.

K 2 =Constant, 5.986×10 –5 (parts per million) − 1 (gram-mole per standard cubic meter) (kilogram per gram)(minute per day), where the stan dard temperature (standard cubic meter) is at 20 °C.

C TOC = 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 C TOC , gram per grammole. Q s = 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 repr esentative of the process under representative operating conditions. (iii) TOC emission rate specified or implied wi thin 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 pr operties. 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 concentratio ns based on saturation conditions. (v) All data, assumptions, and procedures us ed 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, temporar y 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 Soci ety of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016–5990, (8 00) 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 Am erican 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 para graphs (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 subp art 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 ex isting sources subject to this subpart are not required to comply with the provisions for ga skets, 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), a nd (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 inspectio ns 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 Complia nce 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 su bpart. 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 paragraph s (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 th at 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 concentr ation 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 sectio n, 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 sect ion (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 diff erent 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 owne r 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 la ter 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 s ourcewide 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 la ter 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, conne ctors, 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 va lves 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 th e calculation of percent leaking valves. (10) If in phase III of the valve standard any va lve is designated as being leakless, the owner or operator has the option of following the provi sions 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 serv ice are exempt from §§63.163 and 60.482 if recasting the distance piece or recipro cating 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 th is 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 para graph (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 includ es 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 con duct 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 AM ENDMENTS 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 capab le of: 1) identifying th e 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 i ndicator, 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 indi cate 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 li ght 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 co mpliance 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 define s 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:

% C L = [(C L − C AN )/C t +C c )]×100

where:

% C L = Percentage leaking connectors.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

C L = Number of connectors including nonrepairables, measured at 1,000 parts per million or greater, by Method 21 of 40 CFR part 60, appendix A.

C AN = Number of allowable nonrepairable connectors, as determined by monitoring, not to exceed 3 percent of the total connector population, C t . C t

= Total number of monitored connectors, including nonrepairables, in the process unit.

C c = 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 C c = 0. (ii) Nonrepairable connectors shall be included in the calculation of percentage leaking connectors the first time the connector is identifi ed 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 connect ors 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 indi cate 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 fug itive 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 unde r 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 standa rd 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 a nd 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 au thority 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 pollutio n 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 th e 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 t echnology 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 vess el 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 St ate or Federal rule othe r 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 emis sion 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 emission s 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 referen ce control technology for those emission points. Equations in paragraph (g) of this sect ion 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. Equatio ns in paragraph (h) of this section shall be used to calculate credits. Emission points and contro ls 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 cred its and debits in the Periodic Reports as specified in §63.655(g)(8). Every fourth Peri odic Report shall include a certification of compliance with the emissions averaging provisions as re quired 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 sec tion, 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 poi nts 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 include d 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 mo nitors 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 controll ed 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 iu iACTUAL n

i iC iACTUAL n

i iu iACTUAL n

i iu iACTUAL

EMV EMV EGLR EGLR ES ES EPV EPV Debits

1 1 1 1 03

. 0 05

. 0 02

. 0

where: Debits and all terms of the equation are in units of megagrams per month, and

EPV iACTUAL = Emissions from each Group 1 miscellaneous process vent i that is uncontrolled or is controlled to a level less stri ngent than the reference control technology. This is calculated according to paragraph (g)(2) of this section. (0.02) EPV iu = 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.

ES iACTUAL = 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) ES iu = 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.

EGLR iACTUAL = 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.

EGLR ic = 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***

EMV ACTUAL = 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) EMV iu = 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 proce ss 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 EPV iu : 

#             

# 

  n

j j j iu 

### M C Qh EPV

1 9 

### 10 494

. 2

where:

EPV iu = 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 op eration during which positive flow is present in the vent, hours per month.

C

j = Concentration, parts per million by volume, dry basis, of organic HAP j as measured by Method 18 of part 60 appendix A.

M

j = 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, C j , and M j shall be determined during a performance test conducted under representative operating conditions. The values of Q, C j , and M j 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, C j , and M j are no longer representative, a new performance test shall be conducted to determine new representative values of Q, C j , and M j . 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 EPV iACTUAL : (A) If the vent is not controlled by a control device or pollution prevention measure, EPV iACTUAL = EPV iu , where EPV iu 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 contro l device or a pollution prevention measure achieving less than 98-percent reduction,
     

   % 100 1 duction Percent re EPV EPV iu iACTUAL

( 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 pr ocess vents, product recovery devices shall not be considered control devices and cannot be assigned a percentage of reduction in calculating EPV iACTUAL . 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 r acks 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 EGLR iu : 

#   T SPMG EGLR iu 7 10 20

. 1   

where:

EGLR iu = 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 G P P j n j j 

#  



###  1

where:

P

j = Maximum true vapor pressure of individual organic HAP transferred at the rack, kilopascals. G = Monthly volume of organic HAP transferred, liters per month, and 

##  

 n

j j G G

1
G

j = 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 G M M j n j j 

#  



###  1

where:

M

j = Molecular weight of individual organic HAP transferred at the rack, gram per grammole.
G, G j , 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 G T T j n j j 

#  



###  1

T

j = Average annual bulk temperature of individual organic HAP loaded at the gasoline loading rack, kelvin (degrees Celsius °C+273). G, G j , and n are as defined in paragraph (g)(4)(ii) of this section. (v) The following equation shall be used to calculate EGLR ic :

G EGLR ic 8 10 1 

  G is as defined in paragraph (g)(4)(ii) of this section. (vi) The following procedures and equations shall be used to calculate EGLR iACTUAL : (A) If the gasoline loading rack is not controlled, EGLR iACTUAL = EGLR iu , where EGLR iu is calculated using the equations specified in paragrap hs (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 th an 10 milligrams of TOC per liter of gasoline loaded,
     

   % 100 1 duction Percent re EGLR EGLR iu iACTUAL***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 EMV iu : 

##     

## 

  m

i i i i iu P F Q EMV

1
where:

EMV iu = Uncontrolled marine tank vessel HAP emission rate from marine tank vessel i, megagrams per month. Q i = Quantity of commodity loaded (per vessel type), liters.

F i = Emission factor, megagrams per liter.

P i = 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 EMV iACTUAL : (A) If the marine tank vessel is not controlled, EMV iACTUAL = EMV iu , where EMV iu 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 duction Percent re EMV EMV iu iACTUAL
( 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 St ate or Federal rule or statute. Credits shall be calculated as follows: (1) The overall equation for calculating sourcewide credits is: 

##                      

##         



        



 

 

 

 

 

 

 

 

 

 

m

i iACTUAL iBASE n

i iACTUAL ic m

i iACTUAL iBASE n

i iACTUAL iu m

i iACTUAL iBASE n

i iACTUAL ic m

i iACTUAL iBASE n

i iACTUAL iu m

i iACTUAL iBASE n

i iACTUAL iu

EWW2 EWW2 D EWW1 EWW1 D EMV2 EMV2 D EMV1 EMV1 D EGLR2 EGLR2 D EGLR1 EGLR D ES2 ES2 D ES1 ES1 D EPV2 EPV2 D EPV1 EPV1 D Credits

1 1 1 1 1 1 1 1 1

1

03

. 0 05

. 0 02

. 0

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-gen erating emission points except those controlled by a pollution prevention measure, which will not be discounted.

EPV1 iACTUAL = 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) EPV1 iu = Emissions from each Group 1 miscellaneous process vent i if the reference control technology had been applied to the uncontrolled emissions. EPV1 iu is calculated according to paragraph (h)(2) of this section.

EPV2 iBASE = 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***

EPV2 iACTUAL = Emissions from each Group 2 miscellane ous process vent that is controlled, calculated according to paragraph (h)(2) of this section.

ES1 iACTUAL = Emissions from each Group 1 storage ve ssel 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) ES1 iu = Emissions from each Group 1 storage vessel i if the reference control technology had been applied to the uncontrolled emissions. ES1 iu is calculated according to paragraph (h)(3) of this section.

ES2 iACTUAL = Emissions from each Group 2 storage vessel i that is controlled, calculated according to paragraph (h)(3) of this section.

ES2 iBASE = Emissions from each Group 2 storage vessel i at the baseline date, as calculated in paragraph (h)(3) of this section.

EGLR1 iACTUAL = 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.

EGLR ic = Emissions from each Group 1 gasoline loading rack i if the reference control technology had been applied to the uncontrolled emissions. EGLR iu is calculated according to paragraph (h)(4) of this section.

EGRL2 iACTUAL = Emissions from each Group 2 gasoline loading rack i that is controlled, calculated according to paragraph (h)(4) of this section.

EGLR2 iBASE = Emissions from each Group 2 gasoline loading rack i at the baseline date, as calculated in paragraph (h)(4) of this section.

EMV1 iACTUAL = 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)EMV1 iu = Emissions from each Group 1 marine tank vessel i if the reference control technology had been applied to the uncontrolled emissions. EMV1 iu is calculated according to paragraph (h)(5) of this section.

EMV2 iACTUAL = Emissions from each Group 2 marine tank vessel i that is controlled, calculated according to paragraph (h)(5) of this section.

EMV2 iBASE = 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***

EWW1 iACTUAL = 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.

EWW1 ic = 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.

EWW2 iACTUAL = Emissions from each Group 2 wastewater stream i that is controlled, calculated according to paragraph (h)(6) of this section.

EWW2 iBASE = 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 great er 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 calculati ng 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, EPV1 iu , shall be calculated according to the procedures and equation for EPV iu in paragraphs (g)(2)(i) and (g)(2)(ii) of this section. (ii) Actual emissions from miscellaneous pro cess 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, EPV1 iACTUAL , shall be calculated according to the following equation:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

     

   % 100 1 ficiency% Nominal ef EPV1 EPV1 iu iACTUAL
(iii) The following procedures shall be used to calculate actual emissions from Group 2 process vents, EPV2 iACTUAL : (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 duction Percent re EPV2 EPV2 iu iACTUAL
( 1 ) EPV2 iu shall be calculated according to the equations and procedures for EPV iu in paragraphs (g)(2)(i) and (g)(2)(ii) of this sec tion 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, EPV2 iu shall be calculated prior to that recovery device. The equation for EPV iu in paragraph (g)(2)(ii) of this section shall be used to calculate EPV2 iu ; 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 ficiency% Nominal ef EPV2 EPV2 iu iACTUAL

(iv) Emissions from Group 2 process vents at baseline, EPV2 iBASE , shall be calculated as follows: (A) If the process vent was uncontrolled on November 15, 1990, EPV2 iBASE = EPV2 iu , and shall be calculated according to the procedures and equation for EPV iu 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 duction Percent re EPV2 EPV2 iu BASE

where EPV2 iu is calculated according to the procedures and equation for EPV iu 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, EPV2 iBASE = EPV2 iu , where EPV2 iu 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 r acks shall be determined as follows: (i) Uncontrolled emissions from Group 1 gasoline loading racks, EGLR1 iu , shall be calculated according to the procedures and equations for EGLR iu 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, EGLR ic , 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; EGLR iACTUAL , shall be calculated according to the following equation:
     

   % 100 1 ficiency% Nominal ef EGLR1 EGLR1 iu iACTUAL
(iv) The following procedures shall be used to calculate actual emissions from Group 2 gasoline loading racks, EGLR2 iACTUAL : (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 duction Percent re EGLR2 EGLR2 iu iACTUAL
( 1 ) EGLR2 iu shall be calculated according to the equations and procedures for EGLR iu 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 ficiency Nominal ef EGLR2 EGLR2 iu iACTUAL
(v) Emissions from Group 2 gasoline loading racks at baseline, EGLR2 iBASE , shall be calculated as follows: (A) If the gasoline loading rack was uncontrolled on November 15, 1990, EGLR2 iBASE = EGLR2 iu , and shall be calculated according to the procedures and equations for EGLR iu 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 duction Percent re EGLR2 EGLR2 iu iBASE

where EGLR2 iu is calculated according to the procedures and equations for EGLR iu 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, EMV1 iu , shall be calculated according to the procedures and equations for EMV iu as described in paragraph (g)(5)(i) of this section. (ii) Actual emissions from Group 1 marine ta nk vessels controlled using a technology or pollution prevention measure with an approved nom inal efficiency greater than 97 percent, EMV iACTUAL , shall be calculated according to the following equation:
     

   % 100 1 ficiency Nominal ef EMV1 EMV1 iu iACTUAL
(iii) The following procedures shall be used to calculate actual emissions from Group 2 marine tank vessels, EMV2 iACTUAL : (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 duction Percent re EMV2 EMV2 iu iACTUAL
( 1 ) EMV2 iu shall be calculated according to the equations and procedures for EMV iu 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 ficiency Nominal ef EMV2 EMV2 iu iACTUAL
(iv) Emissions from Group 2 marine tank vessels at baseline, EMV2 iBASE , shall be calculated as follows: (A) If the marine terminal was uncontrolled on November 15, 1990, EMV2 iBASE equals EMV2 iu , and shall be calculated according to the procedures and equations for EMV iu 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 duction Percent re EMV2 EMV2 iu iBASE

where EMV2 iu is calculated according to the procedures and equations for EMV iu 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 para graphs (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 includ e 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 fo r each wastewater stream i to calculate EWW ic : 

#      

#     

##  

 

   

   s

m im m i i s

m im m m i i ic HAP Fr H Q HAP Fe Fr H Q EWW

1 8

1 8 10 0

. 6 05

. 0 1 10 0

. 6

where:

EWW ic = Monthly wastewater stream emission rate if wastewater stream i were controlled by the reference control technology, megagrams per month. Q i = Average flow rate for wastewater stream i, liters per minute.

H i = Number of hours during the month that wa stewater stream i was generated, hours per month.

Fr m =Fraction removed of organic HAP m in wastewater, from table 7 of this subpart, dimensionless.

Fe m =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.

HAP im = Average concentration of organic HAP m in wastewater stream i, parts per million by weight. (A) HAP im 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 C im , the average volatile organic HAP concentration of organic HA P m in wastewater stream i, and then HAP im may be calculated using th e following equation: HAP im = C im /Fm m , where Fm m for organic HAP m is obtained from table 7 of this subpart. (B) Values for Q i , HAP im , and C im 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 Q i , HAP im , and C im 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 Q i , HAP im , and C im are no longer representative, a new pe rformance test shall be conducted to determine new representative values of Q i , HAP im , and C im . 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 EWW1 iACTUAL for each Group 1 wastewater stream i that is correctly suppressed an d 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 tabl e 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 im im i i s

m im im m i i iACTUAL PR HAP H Q PR HAP Fe H Q EWW1

1 8

1 8 10 0

. 6 05

. 0 1 10 0

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

Where:

EWW iACTUAL = Monthly wastewater stream emission ra te if wastewater stream i is treated to a level more stringent than the reference control technology, megagrams per month.

PR im = 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:

in im out im in im im HAP HAP HAP PR

    

Where:

HAP im-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.

HAP im-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 nom inal 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 m im i i s

m m im m i i iACTUAL A HAP H Q ficiency% Nominal ef A HAP Fe H Q EWW1

1 8

1 8 10 0

. 6 100 1 1 10 0

. 6

Where: Nominal efficiency = Approved reduction efficiency of the vapor control device, dimensionless, as determined according to the procedures in §63.652(i).

A m = 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, A m shall be equal to the value of Fr m 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 PR im . If the value of PR im is greater than or equal to the value of Fr m given in table 7 of this subpart, then A m equals Fr m

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 EWW1 iACTUAL according to paragraph (h)(6)(iii)(B) of this section rather than paragraph (h)(6)(iii)(A) of this section. If PR im is less than the value of FR m given in table 7 of this subpart, emissions av eraging shall not be used for this emission point. (C) If the Group 1 wastewater stream i is cont rolled 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 sp ecified 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 im im i i s

m im im m i i iACTUAL PR HAP H Q ficiency% Nominal ef PR HAP Fe H Q EWW1

1 8

1 8 10 0

. 6 100 1 1 10 0

. 6

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 EWW2 iBASE 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 im m i i iBASE HAP Fe H Q EWW

1 8 10 0

. 6 2

Where:

EWW2 iBASE = Monthly wastewater stream emission rate if wastewater stream i is not correctly suppressed, megagrams per month. Q i , H i , s, Fe m , and HAP im 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 EWW2 iBASE for each Group 2 wastewater stream i on November 15, 1990 was correctly suppressed. EWW2 iBASE 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 im im i i i s

m im im m i i iBASE PR HAP H Q R PR HAP Fe H Q EWW2

1 8

1 8 10 0

. 6 % 100 1 1 10 0

. 6

where R i is calculated according to paragraph (h)(6)(vii) of this section and all other terms are as defined and determined according to paragrap hs (h)(6)(ii) and (h)(6)(iii)(A) of this section. (vi) For Group 2 wastewater streams that are correctly suppressed, EWW2 iACTUAL shall be calculated according to the equation for EWW2 iBASE in paragraph (h)(6)(v) of this section. EWW2 iACTUAL shall be calculated with all control methods in place accounted for. (vii) The reduction efficiency, R i , 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 st ream 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 i aip m

p ap a MW C V m E

1 1 6 10

0416

. 0

               

  

#  



 n

p i bip m

p bp b MW C V m E

1 1 6 10

0416

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

Where:

E a = Mass flow rate of organic compounds exiting the control device, kilograms per hour.

E b = Mass flow rate of organic compounds entering the control device, kilograms per hour.

V ap = Average volumetric flow rate of vent stream exiting the control device during run p at standards conditions, cubic meters per hour.

V bp = 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.

C aip = 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.

C bip = 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.

MW i = 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 a b E E E R

Where: R = Total organic reduction efficiency for the control device, percentage.

E b = Mass flow rate of organic compounds entering the control device, kilograms per hour.

E a = 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 techno logy including design specifications; (iii) Documentation demonstrating to the Admini strator’s satisfaction the control efficiency of the control technology. This may include perfor mance 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 nomi nal efficiency. The Administrator reserves the right to request specific data in addition to the it ems 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 ju dgment, 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 pe rmission 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 sour ce for approval instead of the Administrator. (i) In these instances, use and conditions for us e of the control technol ogy can be approved by the permitting authority. The permitting auth ority 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 perm itting 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 pe rmitting 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 practi ce 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 includ e: 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 po llution 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 mont hly 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 B pp B E P P E E duction Percent re

Where: Percent reduction = Efficiency of pollution prevention measure (percentage of organic HAP reduction).

E B = 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.

E pp = 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.

P B = Monthly production before the pollution prevention measure, megagrams per month, during the same period over which E B is calculated.

P pp = 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, E B , shall be determined in a manner consistent with the equati ons 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, E B shall be calculated as follows: 

#    

   

###         n

i s

m Bim m Bi Bi B 

### HAP Fe H Q E

1 1 8 

### 10 0

. 6

where:

n = Number of wastewater streams.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Q Bi = Average flow rate for wastewater stream i before the pollution prevention measure, liters per minute.

H Bi = 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.

Fe m = Fraction emitted of organic HAP m in wa stewater from table 7 of this subpart, dimensionless.

HAP Bim = 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 E B . (D) The monthly emissions after the pollution prevention measure, E pp , 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, E pp shall be calculated using the following equation: 

#    

   

###         n

i s

m ppim m ppi ppi pp 

### HAP Fe H Q E

1 1 8 

### 10 0

. 6

where n, Q, H, s, Fe m , and HAP are defined and determined as described in paragraph (j)(2)(ii)(B) of this section except that Q ppi , H ppi , and HAP ppim 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 ma y 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 controlle d 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 docu mentation 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 pe rmitting authority shall not be approved. The State or local permitting authority may require such adju stments 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 chem ical 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 Admi nistrator 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 establis h that the control device for the emission point was operating in such a fashion to warrant assi gning full or partial credits and debits. This demonstration shall be made to the Administra tor’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 opera ting 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 th e percentage of reduc tion 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 de vices, 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, condu ct 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 s ite-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 pe rmit application, in a separate submittal, in a Notification of Compliance Status Report, in a Pe riodic 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 pr ojected 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 emissi on 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 demonstra tion, monitoring, inspection, recordkeeping, and reporting provisions in paragraphs (a), (b), and (c) of this section that are applicable to each emission point in the emissi ons 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 paramete r 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 li sted in paragraphs (d)(2)(viii)(A) through (d)(2)(viii)(G) of this section for each process wastewater stream incl uded in the average. (A) The information used to determine whethe r 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 reducti on 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 wi ll 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 redu ction 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 wastew ater 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 subm itted 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 contai ning 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 coolin g 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 monito ring 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 repr esentative 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 hy drocarbon concentration (in parts per million by volume (ppmv) as methane) at each monitoring location using the “Air Stripping Method (Modified El Paso Method) for Determin ation 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 inparagraphs (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 dela yed 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 para graph (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 wa ter 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 wh en 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 exchan ger when one of the conditions in paragraph (f)(1) or (f)(2) of this sec tion 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 le ss 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 le ss 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 fi rst 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 specifi c 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 mon itoring 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 interval s 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 monitori ng 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 re quirements are summarized in table 4 of this subpart. There are no additional reporting and re cordkeeping 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 re cordkeeping requirements for marine tank vessel loading operations under this subpart unless mari ne 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 de signate) 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 th at 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 lis t 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 afte r the compliance dates specified in §63.640(h) with the exception of Notification of Complian ce 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 amendm ent to an operating permit appli cation, 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 duplic ating 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)(vi i ) 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 in formation 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), an d 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 whic h the performance test will be submitted, and identification of the emission point(s) that shar e 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 de vice 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

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( 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 HA P’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 au thority, 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 conten t 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. Fo r heat exchange systems at existing sources, the owner or operator shall indicate whether mon itoring will be conducted as specified in §63.654(c)(4)(i) or §63.654(c)(4)(ii). Deleted: of this part

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(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 accord ing 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 samp ling 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 ot her 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 emissi ons average, the Notification of Compliance Status report shall include the values of the para meters 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 specifi ed 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 su bmittal, 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 paragraph s (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 Period ic Report is not required if none of the events identified in paragraph (g)(1) through ( 7 ) of this section or paragraph s (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 stor age 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

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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 detach ed 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 th e internal floating roof has defects; or the primary seal has holes, tears, or other openings in th e 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 da te 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 paragra phs (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

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(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 w ith §63.120(b)(7)(ii) or (b)(8) of subpart G, the owner or operator shall, in the next Pe riodic 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 th e 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
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( 2 ) Each Periodic Report shall include the da te 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 requ ired 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 subm it, 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 info rmation 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

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(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 complian ce 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 comp ly 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 descri bed 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 sha ll 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 hi gh-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 submitte d 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 wastewat er 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 em issions 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 th e 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 th e delay of repair began, the date the repair is expected to be completed (if the leak is not re paired 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 serv ice, 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 Re ports 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 th e applicable operating limits specified in §63.670(d) through (f) are not met. Indicate the da te 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 inspectio ns 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 no tification 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 stor age 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 monitori ng 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 w ill establish a range for the monitored parameter Deleted: of this part

Deleted: ’s

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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) th rough (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 su bpart 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 ( Δ c) 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 we re 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 sup ported by EPA’s ERT as listed on the EPA’s ERT website (http://www.epa.gov/ttn/chief/ert/inde x.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.a sp), 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 mu st 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 comp leting each CEMS performance evaluation as required by this subpart, the owner or operato r must submit the results of the performance evaluation according to the method specified by ei ther 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 re gistered 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 Admini strator 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-readab le 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)(

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(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 defi ned 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 pa rameter 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 a nd 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 by pass 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 emissi ons 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 emissi ons 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 syst ems 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 da ta 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 opera tor 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 Δ c 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 Δ c 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 th is 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 assi st 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 bloc k 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 NHV vg 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 compositiona l 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 ve nt gas to the flare, but when there is no flow of regulated material to the flare, including th e 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, Appe ndix 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 volu me 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 subpar t. 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 s tate, 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 me thods 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 vess el 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 is olate 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 samp ling 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 ar e 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 ( Δ c). (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 Δ c. (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 Δ c 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 Δ c 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/m 3 ). If the 12-month rolling average Δ c value for benzene is less than 9 μg/m 3 , the concentration is below the action level. If the 12-month rolling average Δ c value for benzene is equal to or greater than 9 μg/m 3

, 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 deve lop 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 th e 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 para graphs (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 monitori ng plan prior to using the near-field source alternative calculation for determining Δ c 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 s ources. 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 st ations that shall be used to determine the uniform background concentration and the near-field source concentration contribution. (iii) Identification of the fencel ine 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 calcu lations 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, pr ovide 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 Δ c for comparison with the 9 μg/m 3 action level using the requirements specified in paragraphs (2)(i) through (iii) of this section. (i) For each monitoring location, calculate Δ c i using the following equation.



### UB NFS MFC Δ c i i i 

###   

where: Field Code Changed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Δ c i = The fenceline concentration, corrected for background, at measurement location i, micrograms per cubic meter (μg/m 3 ).

MFC i = The measured fenceline concentration at measurement location i, μg/m 3

. NFS i = The near-field source contributing concentration at measurement location idetermined using the additional measurements and calculation procedures included in the sitespecific monitoring plan, μg/m 3 . For monitoring locations that are not included in the sitespecific monitoring plan as impact ed by a near-field source, use NFS i = 0 μg/m 3

. UB = The uniform background concentration dete rmined using the additional measurements specified included in the site-specific monitoring plan, μg/m 3 . If no additional measurement location is specified in the site-specific monito ring plan for determining the uniform background concentration, use UB = 0 μg/m 3

. (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 mo nitoring 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 de tection, the owner or operator shall use zero for the monitoring location concentration when calculating NFS i for that monitoring period. (C) If a fenceline monitoring location sample re sult is below the method detection limit, the owner or operator shall use the method detection limit as the sample result. (iii) Determine Δ c for the monitoring period as the maximum value of Δ c i 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 pe riod shall begin when the Administrator receives the plan. (iii) If the Administrator finds any deficienci es in the site-specific monitoring plan and disapproves the plan in writing, the owner or oper ator may revise and resubmit the site-specific monitoring plan following the requirements in para graphs (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 s ite-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 consid er 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 so urce 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 Soci ety of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016–5990, (8 00) 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 Am erican 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 re ferencing 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 AM ENDMENTS 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 star tup 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 AF TER 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 visibl e 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 (V tip ) must be less than 60 feet per second when regulated material is being routed to the flare. The owner or operator shall monitor V tip using the procedures specified in paragraph (i) and (k) of this section. (2) V tip must be less than 400 feet per second and also less than the maximum allowed flare tip velocity (V max ) as calculated according to the following equation at all times regulated material is being routed to the flare. The owner or operator shall monitor V tip using the procedures specified in paragraph (i) and (k) of this section and monitor gas composition and determine NHV vg using the procedures specified in paragraphs (j) and (l) of this section. 

##   850 212 , 1

10 

### 

 vg max 

### NHV V Log

where:

V max = Maximum allowed flare tip velocity, ft/sec.

NHV vg = 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 requiremen ts in paragraph (e)(1) during certain flow conditions and comply with the requirements in pa ragraph (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 (NHV cz ) 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 NHV cz as specified in paragraph (m) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target NHV cz 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 NHV cz value is 270 Btu/scf. (2) The lower flammability limit of the combustion zone gas (LFL cz ) 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 LFL cz as specified in paragraph (n) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target LFL cz 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 LFL cz value is 0.15 volume fraction. (3) The total volumetric fraction of hydrogen and combustible organic components present in the combustion zone gas (C cz ), 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 C cz as specified in paragraph (l) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target C cz 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 C cz 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 fl ares 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 (NHV dil ) 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 NHV dil as specified in paragraph (o) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target NHV dil value is 31 British thermal units per square foot (Btu/ft 2 ). (ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this section, the target NHV dil value is 22 Btu/ft 2

. (2) The lower flammability limit dilution parameter (LFL dil ) 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 LFL dil as specified in paragraph (o) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target LFL dil 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 LFL dil value is 2.2 volume fraction/ft. (3) The combustibles concentration dilution parameter (C dil ) 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 C dil as specified in paragraph (o) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target C dil 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 C cz 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 visibl e 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 operato r 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 ai r 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 ow ner or operator shall install, operate, calibrate, and maintain a monitoring system capable of se parately 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 conditio ns using the following equation.



### M W t Q Q mass

vol 

### 385.3 



where: Q vol = Volumetric flow rate, standard cubic feet per second. Q mass = 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 contin uous 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 pr ovided in paragraphs (j)(4) of this section.. The owner or operator electing to directly mon itor 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, paragr aph (f) of this section, and must comply with the maximum velocity requirements in pa ragraph (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 re cording 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, opera te, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording NHV vg. at standard conditions. (4) The owner or operator shall install, opera te, 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 pi peline 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 V tip operating limits. The owner or operator shall determine V tip 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 ga s 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 V tip shall be calculated using the following equation.



### 900   A rea Q V cum

tip

where:

V tip = Flare tip velocity, feet per second. Field Code Changed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Q cum = 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 V max using the equation in paragraph (d)(2) of this section in order to compare V tip to V max 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 fla mmability limit, combustibles concentration vent gas (NHV vg , LFL vg , and C vg , 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 th e 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 bl ock 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 gr ab sample collected for an event for all 15- minute periods from the start of the event thro ugh 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 samp ling 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 NHV vg 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 NHV vg , as provided in paragraph (j)(3) of this section, the owner or operator shall use the NHV vg as determined by the continuous NHV vg monitor. 

# 

 

###  n

i i i vg 

### NHV x NHV

1

where:

NHV vg = Net heating value of flare vent gas, Btu/scf. i = Individual component in flare vent gas. n = Number of components in flare vent gas.

x i = Concentration of component i in flare vent gas, volume fraction.

NHV i = 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 LFL vg using the following equation:



# 

 

###          n

i i vg 

### LFL χ LFL

i

1 

### 1

where:

LFL vg = Lower flammability limit of flare vent gas, volume fraction. n = Number of components in the vent gas. i = Individual component in the vent gas.

χ

i = Concentration of component i in the vent gas, volume percent (vol %).

LFL i = 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., LFL N2 = ∞ , so that χ N2 / LFL N2 = 0). (6) The owner or operator shall calculate C vg using the following equation. If the owner or operator uses a total hydrocarbon analyzer, the owner or operator may substitute the “ ∑χ i ” term in the following equation with the total volumetr ic 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

3 1              

 

## 

 h n

i i i

vg χ χ CMN

C

Where:

C vg = Total volumetric fraction of hydrogen and combustible organic components present in the flare vent gas, volume fraction. For the purposes of C vg , carbon dioxide is not considered to be a combustible organic component, but carbon monoxide may be included in C vg . n = Number of individual combustible organic components in flare vent gas. i = Individual combustible organic component in flare vent gas.

χ

i = Concentration of combustible organic component i in flare vent gas, vol %.

CMN i = Carbon mole number of combustible organic component i in flare vent gas, mole carbon atoms per mole of compound. E.g., CMN for ethane (C 2 H 6 ) is 2; CMN for propane (C 3 H 8 ) is 3.

χ

h = Concentration of hydrogen in flare vent gas, vol %. 100% = Constant, used to convert volume percent to volume fraction. (m) Calculation methods fo r determining combustion zone parameters . The owner or operator shall determine the ne t heating value, lower flammability limit and combustibles concentration of the combustion zone gas (NHV cz , LFL cz , and C cz , respectively) based on the vent gas and assist gas flow rates on a 15-minut e block average basis according to the following requirements. For periods when there is no assi st 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 NHV cz using the following equation: Field Code Changed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***


#   a,premix s vg vg vg
cz Q Q Q NHV Q NHV   



where:

NHV cz = Net heating value of combustion zone gas, Btu/scf.

NHV vg = Net heating value of flare vent gas for the 15-minute block period, Btu/scf. Q vg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. Q s = Cumulative volumetric flow of total stea m during the 15-minute block period, scf. Q a,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. (2) The owner or operator shall calculate LFL cz using the following equation: 

#  

vg a,premix s vg vg
cz 

### Q Q Q Q LFL LFL   



where:

LFL cz = Lower flammability limit of combustion zone gas, volume fraction.

LFL vg = Lower flammability limit of flare vent gas determined for the 15-minute block period, volume fraction. Q vg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. Q s = Cumulative volumetric flow of total stea m during the 15-minute block period, scf. Q a,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. (3) The owner or operator shall calculate C cz using the following equation:



#   a,premix s vg vg vg
cz Q Q Q C Q C   



where:

C cz = 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***

C vg = Combustibles concentration of flare vent gas determined for the 15-minute block period, volume fraction. Q vg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. Q s = Cumulative volumetric flow of total stea m during the 15-minute block period, scf. Q a,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 flamma bility limit and combus tibles concentration dilution parameters (NHV dil , LFL dil , and C dil , respectively) based on the vent gas and perimeter assist air flow rates on a 15-minute block aver age 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 NHV dil using the following equation: 

#  

r a,perimete a,premix s vg vg vg dil Q Q Q Q NHV Diam Q NHV     



where:

NHV dil = Net heating value of combustion zone gas, Btu/ft 2

NHV vg = Net heating value of flare vent gas determined for the 15-minute block period, Btu/scf. Q vg = 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

π Area Diam   2

Q s = Cumulative volumetric flow of total stea m during the 15-minute block period, scf. Q a,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. Q a,perimiter = Cumulative volumetric flow of perime ter assist air during the 15-minute block period, scf. (2) The owner or operator shall calculate LFL dil using the following equation: Field Code Changed

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

#  

Diam Q Q Q Q Q LFL LFL

vg r a,perimete a,premix s vg vg dil 

###     



where:

LFL dil = Lower flammability limit of combustion zone gas, ft -1

. LFL vg = Lower flammability limit of flare vent gas determined for the 15-minute block period, volume fraction. Q vg = 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

π Area Diam   2

Q s = Cumulative volumetric flow of total stea m during the 15-minute block period, scf. Q a,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. Q a,perimiter = Cumulative volumetric flow of perime ter assist air during the 15-minute block period, scf. (3) The owner or operator shall calculate C dil using the following equation:



#  

r a,perimete a,premix s vg vg vg dil Q Q Q Q C Diam Q C     



where:

C cz = Combustibles concentration in the combustion zone gas, volume fraction.

C vg = Combustibles concentration of flare vent gas determined for the 15-minute block period, volume fraction. Q vg = 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

π Area Diam   2

Q s = Cumulative volumetric flow of total stea m 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***

Q a,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. Q a,perimiter = Cumulative volumetric flow of perime ter 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. 

#   a,premix s vg vg vg
cz Q Q Q A Q A   



where:

A cz = 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.

A vg = 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. Q vg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. Q s = Cumulative volumetric flow of total stea m during the 15-minute block period, scf. Q a,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 NHV vg 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 paragra ph (e)(4) of this section, for example, if the flare does not service any process units that cont ain 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 paragr aph (e)(4), then the owner or operator will use the concentrations determined from the engineerin g 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 olef ins plus hydrogen received by the flare, a new engineering assessment and sampling period fo r 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 li mits that shall apply specifically to a selected flare. Site-specific operating limits include a lternative threshold valu es 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 paragra phs (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-s pecific operating limits based on a performance test as described in paragraph (r)(1) of this s ection. 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 op erating 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 compositio ns, 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 calcula tions 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 ga s 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 calcu lations 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/dest ruction efficiency of the flare deteriorates. (viii) If the flare can receive vent gases co ntaining 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 lim its to assess whether more stringent operating limits are required under these conditions. (ix) Test schedule. (2) The request for flare-specific operating li mits shall include sufficient and appropriate data, as determined by the Administrator, to allo w the Administrator to confirm that the selected site-specific operating limit(s) adequately ensure s that the flare destruction efficiency is 98 percent or greater or that the flare combustion effici ency 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 bot h emission measurements and flare operating parameters. (D) Description of sampling and analysis pr ocedures (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., ve nt gas composition, assist rate s, 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 lim it(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-specifi c 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 an y 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 comp ly with the revised request as submitted until it is approved. (4) The approval process for a request for a flar e-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 incl ude, 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 Administ rator, 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 read out (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 wh en 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 Administrato r upon request by the Administrator. The CPMS monitoring plan must contain the information lis ted in paragraphs (b)(1) through (5) of this section. (1) Identification of the specific flare being m onitored 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 handle d and the correc tive 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 diff erent from the operating parameter monitored. (4) Description of the data collection and reduction systems, in cluding 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 algorith m excludes data collected during CPMS breakdowns, out-of-control periods, repairs, main tenance 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, main tenance 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 descrip tion 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-lev el), 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 an d conduct retesting until the performance requirements are below the applicable limits. Th e 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 ope rator 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 spec ified 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 inst rument 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 compound s, 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 operato r 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-hept ane 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 isomers b ) 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 isomers b ) 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

Standard a 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 Part a

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 Po int Recordkeeping and Reporting Requirements a

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 Requirements a

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 es timation 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 CC a

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 em ission 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 require ments 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 additiona l 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, andwhere §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 St atus 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 subm itting 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 su bmitting 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 requi re 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 ma y also serve as the initial compliance notification required in §63.9(b)(1)(iii). 63.9(b)(2) No A separate Initial Notifi cation 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 subpar t CC specifies performance test reporting. 63.10(d)(3) No Results of visible emissi ons 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 se nt by the specified dates, but a postmark is not required. Table 7—Fraction Measured (F M ), Fraction Emitted (F E ), and Fraction Removed (FR) for HAP Compounds in Wastewater Streams

Chemical name CAS No. a F m F e 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: Yes b
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 F m F e 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 Valve monitoring frequency Leaking valves a (%) ≥ 4 Monthly or QIP. b <4 Quarterly. <3 Semiannual. <2 Annual.

a Percent leaking valves is calculated as a ro lling 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 Valve monitoring frequency under §63.649 alternative Leaking valves a (%) ≥ 5 Monthly or QIP. b <5 Quarterly. <4 Semiannual. <3 Annual.

a Percent leaking valves is calculated as a ro lling 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 Wei ght-Percent Reduction of Total Organic HAP Emissions or a Limit of 20 Parts Per Million by Volume

Control device Parameters to be monitored a Recordkeeping and reporting requirements for monitored parameters Thermal incinerator Firebox temperature b (63.644(a)(1)(i)) 1. Continuous records c

. 2. Record and report the firebox temperature averaged over the full period of the performance test—NCS d

. 3. Record the daily average firebox temperature for each operating day e

. 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 collected f —PR g

. Catalytic incinerator Temperature upstream and downstream of the catalyst bed (63.644(a)(1)(ii)) 1. Continuous records c

.

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—NCS d

. 3. Record the daily average upstream temperature and temperature difference across the catalyst bed for each operating day e

. 4. Report all daily average upstream temperatures that are outside the range established in the NCS or operating permit—PR g

. 5. Report all daily average temperature differences across the catalyst bed that are outside the range established in the NCS or operating permit—PR g

. 6. Report all operating days when insufficient monitoring data are collected f

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

Control device Parameters to be monitored a 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 zone h,i Firebox temperature b (63.644(a)(4)) 1. Continuous records c

.

2. Record and report the firebox temperature averaged over the full period of the performance test—NCS d

. 3. Record the daily average firebox temperature for each operating day e

. 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 collected f —PR g

. 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—NCS d

. 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)—PR g

. All control devices Volume of the gas stream diverted to the atmosphere from the control device (63.644(c)(1)) or 1. Continuous records c

. 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 monitored a 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— PR g

. 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—PR g

.

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 pe riod 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 ga s 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 date a 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 63.656 b,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 63.658 b (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 §63.660 c (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 date a 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 63.656 d,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 63.658 d (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 §63.660 e (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 63.656 f,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 date a 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 63.658 f (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 §63.660 g (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 reconstr uction of an entire affe cted 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 requi rements in item (2)(i) or item (2)(ii) of this table. The requirements in item (2)(i) of this ta ble 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 requi rements in item (2)(i) or item (2)(iii) of this table. The requirements in item (2)(i) of this ta ble 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 requi rements 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 ta ble 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 requi rements in item (3)(i) or item (3)(iii) of this table. The requirements in item (3)(i) of this ta ble 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 requi rements in item (4)(i) or item (4)(ii) of this table. The requirements in item (4)(i) of this ta ble 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 requi rements in item (4)(i) or item (4)(iii) of this table. The requirements in item (4)(i) of this ta ble no longer apply after demonstrated compliance with the requirements in item (4)(iii) of this table. Table 12— Individual Component Properties

Component Molecular Formula MW i (pounds per

poundmole) CMN i (mole per

mole) NHV i (British thermal units per standard cubic foot) LFL i (volume %) Acetylene C 2 H 2 26.04 2 1,404 2.5 Benzene C 6 H 6 78.11 6 3,591 1.3 1,2-Butadiene C 4 H 6 54.09 4 2,794 2.0 1,3-Butadiene C 4 H 6 54.09 4 2,690 2.0 iso-Butane C 4 H 10 58.12 4 2,957 1.8 n-Butane C 4 H 10 58.12 4 2,968 1.8 cis-Butene C 4 H 8 56.11 4 2,830 1.6 iso-Butene C 4 H 8 56.11 4 2,928 1.8 trans-Butene C 4 H 8 56.11 4 2,826 1.7 Carbon Dioxide CO 2 44.01 1 0 ∞ Carbon Monoxide CO 28.01 1 316 12.5 Cyclopropane C 3 H 6 42.08 3 2,185 2.4 Ethane C 2 H 6 30.07 2 1,595 3.0 Ethylene C 2 H 4 28.05 2 1,477 2.7 Hydrogen H 2 2.02 0 274 4.0 Methane CH 4 16.04 1 896 5.0 Methyl-Acetylene C 3 H 4 40.06 3 2,088 1.7 Nitrogen N 2 28.01 0 0 ∞ Oxygen O 2 32.00 0 0 ∞ Pentane+ (C5+) C 5 H 12 72.15 5 3,655 1.4 Propadiene C 3 H 4 40.06 3 2,066 2.16***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Component Molecular Formula MW i (pounds per

poundmole) CMN i (mole per

mole) NHV i (British thermal units per standard cubic foot) LFL i (volume %) Propane C 3 H 8 44.10 3 2,281 2.1 Propylene C 3 H 6 42.08 3 2,150 2.4 Water H 2 O 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 PERFORMA NCE 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 th e following affected facilities in petroleum refineries: fluid catalytic cracking units (FCCU), fluid coking units (FCU), delayed coking units, fuel gas combustion devices (including process heat ers), 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 paragra ph (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 purpos es 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 ventin g). However, the connections desc ribed 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 existi ng 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 applicab ility date specified in paragraph (b) of this section. § 60.101a Definitions. Terms used in this subpart are defined in the Cl ean 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 conj unction with or that se rve a refinery process unit. Ancillary equipment includes, but is no t 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 fl are'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 fract ionator, including the bottoms receiver and the overhead condenser; the coke drum cutting water and quench system, incl uding 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 ex clusively 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 suppor t, burner, igniter, flare controls, including air injection or steam injection systems, flame arrest ors 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 a dditional 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 rege nerator 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 crackin g 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 r ecovery 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 ai r 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 combuste d 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 com busted 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 fu el 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 contro l 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, lubri cants, 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 sa nds-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 flar es 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 emissi ons 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 su lfur product, but it does not include secondary sulfur storage vessels or loadin g facilities downstream of the su lfur 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 affect ed 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 start up, 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 dr y 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 opera ting 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 ex iting the FCCU or FCU must not fall below the level established during the most recent performance test. (ii) The hourly average oxygen (O2) concentra tion of the exhaust gases exiting the FCCU or FCU must not fall below the level establishe d 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 th e 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 lim its 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 i ndividually or comply with the applicable emission limit in paragraphs (f)(1)(i) or (f)(1)(ii) of this secti on as a flow rate weighted average for a group of release points from the sulfur recovery plant prov ided that flow is moni tored 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. 

##   

#   6

. 25 53

. 11 038

. 0 2 1 

###    

   2 2 LS 

### %O %O k E (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 sy stem 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 c ontrol 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 appl icable emission limit in paragraphs (f)(2)(i) or (f)(2)(ii) of this section as a flow rate weight ed average for a group of release points from the sulfur recovery plant provided that flow is monito red 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 plan ts, this SO2 emission limit is 2,500 ppm v (dry basis) at zero percent excess air. 

##   

#   256 3

. 115 38

. 0 2 1 

###    

   2 2 SS 

### %O %O k E (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 sy stem 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 ppm v SO2 (dry basis) at zero percent excess air

. (iii) For a sulfur recovery plant with a reduction c ontrol 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 p eriods 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 thes e periods. Examples of these measures include not adding fresh sulfur or shutting off vent fans. (g) Each owner or operator of an affected fu el 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 s ection, 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 crackin g unit or fluid coking unit affected facility, the owner or operator shall comply with the fuel ga s 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 successi ve 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 cale ndar 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 lim its 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 ex cess 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 co mply 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, correct ed to 0-percent excess air) dete rmined daily on a 30-day rolling average basis; or (B) 0.040 pounds per million British thermal un its (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, correct ed to 0-percent excess air) dete rmined 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 owne r 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 calcu lated using Equation 3 of this section:

oil oil gas gas oil oil gas gas NOx HHV Q HHV Q HHV Q HHV Q ER  

 35

. 0 06

. 0 (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 fu el oil fired to the pr ocess heater, MMBtu/scf. (iv) For each co-fired forced draft process heat er, comply with the limit in either paragraph (g)(2)(iv)(A) or (B) of this section. The owne r 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 calcu lated using Equation 4 of this section:

oil oil gas gas oil oil gas gas NOx 

### HHV Q HHV Q HHV Q HHV Q ER  

 40

. 0 11

. 0 (Eq. 4)

Where: ERNOx = Daily allowable average emission rate of NOX, lb/MMBtu (higher heating value basis); Qgas = Daily average volumetric fl ow 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 fu el oil fired to the pr ocess 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 criter ia 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 affect ed 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 criteri a in paragraphs (i)(1)(i) through (iv) of this section may apply for a site-s pecific 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 approp riate 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 th e 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 para graph (i)(2)(i) demonstrate that ultra-low NOX burners, flue gas recirculation, control of ex cess 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 em issions 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 Stan dards, 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 copi es in lieu of hard copies may also be submitted to refinerynsps@epa.gov. (4) The approval process for a request for a faci lity-specific NOX emissions limit is described in paragraphs (i)(4)(i) through (iii) of this section. (i) Approval by the Administrator of a facili ty-specific NOX emissions limit request will be based on the completeness, accuracy and reasonablen ess 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 de signs 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 Administra tor, 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 deve lop 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 disc harges 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 alterna tive(s) or a statement, w ith 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, includi ng 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 diag ram 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 (i f any); maximum supplemental gas flow rate; maximum pilot gas flow rate; and, if the flar e 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, pre ssure 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 compre ssor 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 c onditions for each alternate baseline; and (iii) Procedures to minimize discharges to th e 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 discharg es to the flare during the planned startup and shutdown of the refinery process units and ancilla ry 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 fu el 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 fl are 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 construc ted 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 mana gement 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 th e 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-submitt ed 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 Protecti on Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Divi sion, 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 act ion 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 specifi ed 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 sulf ur 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 paragr aphs (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 mu st 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) th rough (3) of this section for more than one affected facility in the same 24-hour period, in itial root cause analyses shall be conducted for each affected facility. If the initi al root cause analyses indicate th at the discharges have the same root cause(s), the initial root cause analyses can be recorded as a single ro ot 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 fu lly 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 aff ected 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 decr ee, 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 w ith both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternat ive to complying with the requirements of paragraphs (a) through (e) of this section. An aff ected 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 th e requirements of paragraphs (a) through (e) of this section. The owner or operator of an affect ed 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) E ach owner or operator subject to the provisions of this section may apply to th e 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 po llutant achieved by the cont rols 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 determ ination 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 alternativ e 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 demons trated 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 op portunity for public hearing if the Administrator judges that the request may be approved. (ii) After notice and opportunity for public h earing, 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 op erational 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 equi valence 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 demons trate 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 concentra tion 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 conti nuous 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 th e 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 subj ect 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 te st 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 sd s 

## KR

Q c 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: 

##   

#    
oxy oxy 3 2 2 r 3 a 2 2 r 1 c %O Q K %O %CO %CO Q K Q K %CO %CO Q K R   

    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 rege nerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min); Qoxy = Volumetric flow rate of O2 enriched ai r 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 st ream 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 emissi on control or energy recovery sy stem 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 oxy xy a

r 

### %O %CO %CO Q %O Q Q

   

  

 100 100

79 (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 rege nerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min); Qoxy = Volumetric flow rate of O2 enriched ai r 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 fl uid 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 st ream 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 di oxide (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 meas adj %O C C 9

. 20 9

. 20 (Eq. 8)

Where: Cadj = pollutant concentration adjusted to 0-perc ent 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 mit Opacity Li burn coke lb 1,000 / lb 1 (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 measur ed 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) a nd 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)(ii i ) 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 du ration 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 averag ing 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 conditio n 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, diff erent 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 ra nges 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 averag ing 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 percen t 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, th e 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. Owne rs 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 ma ximum 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 complia nce 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 indivi dual 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 lim it. Each owner or operator subject to the provisions of this subpart shall monitor each F CCU 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 paragrap hs (b)(1)(i) through (v) of this section. (i) For units controlled using an electrostatic pr ecipitator, 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 info rmation in paragraphs (b)(1)(v)(A) through (E) of this section. (A) A description of each affected facility and th e parameter(s) to be monitored to determine whether the affected facility will continuously comply with the emissi on 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 th e control device is bei ng 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 ac curacy 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 simila r 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 cer tified 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 ou tput 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 equipp ed 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 op erator 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, includi ng 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 l eak 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 co ndition 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 ti me will ensure alleviation of this condition as expeditiously as practicable; and (vii) How the baghouse system will be opera ted 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 owne r 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 ad justments, 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 an d 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 ow ner or operator subject to the NOX emissions limit in §60.102a(b)(2) for an FCCU or FCU sha ll install, operate, calibrate, and maintain an instrument for continuously monitoring and reco rding 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 reco rding the concentration by volume (dry basis, corrected to 0 percent excess air) of SO2 emis sions 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 sh all install, operate, calibrate, and maintain an instrument for continuously monitoring and record ing the concentration by volume (dry basis) of CO emissions into the atmosphere from each FCCU and FCU subject to the CO emissions limit in §60.102a(b)(4). (1) The owner or operator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to part 60. The span value for this instrument is 1,000 ppm v 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 ow ner or operator demonstrates that all hourly average CO emissions are and will remain less than 50 ppmv (dry basis) corrected to 0 percent excess air. The Administrator may revoke this exemption from monitoring upon a determination that CO emissions on an hourly average basis have exceeded 50 ppmv (dry basis) corrected to 0 percent excess air, in which case a CO CEMS shall be installed within 180 days. (i) The demonstration shall consist of continuously monitoring CO emissions for 30 days using an instrument that meets the requirements of Performance Specification 4 or 4A of appendix B to part 60. The span value shall be 100 ppm v CO instead of 1,000 ppm v , and the relative accuracy limit shall be 10 percent of the average CO emissions or 5 ppm v 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 th ose 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 re quired 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-combusti on 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 em issions 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 applic able 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 aver age 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, operat e, calibrate, and maintain an instrument for continuously monitoring and record ing 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 concentra tion 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 r ecording 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 locat e 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 m onitor, 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 connecti ons 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

       

   



oxy air oxy 2,oxy air 2 Q Q Q %O Q %O 9

. 20 (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 plan t 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 locat e 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 connecti ons 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 meas adj %O Q Q 9

. 20 9

. 20 (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 adj,n n

ave Q Q C 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 averag ing 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 aver aging 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 s ection 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 arithme tic 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) thr ough (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 operati ons for fuel gas combustion devices and flares. (a) Fuel gas combustion devices subject to SO 2 or H2S limit and flares subject to H2S concentration requirements. The owner or operat or 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 ppm v SO2. (ii) The owner or operator shall conduct performance evaluations for the SO2 monitor according to the requirements of §60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60. Samples taken by Method 6 of appendix A-4 to part 60 shall be taken at a flow rate of approximately 2 liters/min for at least 30 minutes. The relative accuracy limit shall be 20 percent or 4 ppm v , 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, opera te, 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 th at 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 op erator 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 combus tion 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 (t his should be shown in the piping diagrams); (iii) An explanation of the conditions that ensure low amounts of sulfur in the fuel gas stream (i.e., control equipment or product specifications) at all times; (iv) The supporting test results from sampling the requested fuel gas stream/system demonstrating that the sulfur content is less than 5 ppm v 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 seve n 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 c ontent 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 concen tration-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 th is 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 modi fication-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) thro ugh (5) of this section or, alternatively, the owner or operator of such a process heater sha ll 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 emissi ons 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 h eater 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, calibra te and maintain an instrument for continuously monitoring and recording the flow rate of the fu el 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 in clude 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 pa ragraph (d)(2) of this section, the owner or operator of a gas-fired process heater shall in stall, 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 MHC X MEV X F 000 , 000 , 1 (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 perfor mance 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 an d maintain fuel gas flow monitors according to the manufacturer's recommendations. For volumetric flow meters, temperature and pressure monitors must be installed in co njunction 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 (inc orporated by reference-see §60.17); (x) AGA Report No. 3, Pa rt 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 20 06) (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 sha ll 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. T he 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 th e 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 Me thod 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.



### SDev Ratio AR Avg 

###    262

. 2 (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 sulfu r-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 wh ich 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 sec tion 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 requ irements 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.

FG d SO FG 

### HHV F C TS
2 

###    (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 requirement s. 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 fr om 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 speci fications 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 sensitiv ity 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 fl ow 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 connecti ons 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 a lternative 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 mainta in, 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 monito r 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 subjec t to the emissions limitations in §60.102a(g) and flares subject to the concentration requireme nt 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 av erages). 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 durin g 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 em issions 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 pro cess 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 repr esentative 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 inte grated 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 emis sion 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 responsib le 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 c ontact your U.S. EPA Regional Office to find out if this subpart is delegated to a State, lo cal, or tribal agency within your State. (b) In delegating implementation and enforcement au thority 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 Part60 Subpart_J_Re gtext _20140128

Title 40: Protection of Environment

PART 60—STANDARDS OF PERFORMANC E 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 applicab le 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 pe troleum 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 whic h 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, lubri cants, 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 th e 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 faciliti es 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 regenerato r. 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 (H 2 S), carbonyl sulfide (COS) and carbon disulfide (CS 2 ). (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 feedst ock quality for additional processing; and the catalyst or contact material is continuously rege nerated 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 porti on 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 sec tion 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 (H 2 S) 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 (SO 2 ) 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 (H 2 S), each calculated as ppm SO 2 by volume (dry basis) at zero percent excess air. (b) Each owner or operator that is subject to th e 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 SO 2 emissions to the atmosphere by 90 percent or maintain SO 2 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 SO 2 emission, maintain sulfur oxides emissions calculated as SO 2 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 r ecording 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 record ing the concentration by volume (dry basis) of CO emissions into the atmosphere, except as provid ed 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 m onitoring 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 SO 2 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 SO 2 and 25 percent oxygen (O 2 ). (ii) The SO 2 monitoring level equivalent to the H 2 S standard under §60.104(a)(1) shall be 20 ppm (dry basis, zero percent excess air). (iii) The performance evaluations for this SO 2 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 li mit 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 SO 2 emissions into the atmosphere from each of the combustion devices. (4) Instead of the SO 2 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 H 2 S in fuel gases before being burned in any fuel gas combustion device. (i) The span value for this instrument is 425 mg/dscm H 2 S. (ii) Fuel gas combustion devices having a comm on source of fuel gas may be monitored at only one location, if monitoring at this location accurately represents the concentration of H 2 S in the fuel gas being burned. (iii) The performance evaluations for this H 2 S 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 SO 2 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 SO 2 and 25 percent O 2 . (ii) The performance evaluations for this SO 2 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 O 2 emissions into the atmosphere. The reduced sulfur emissions shall be calculated as SO 2 (dry basis, zero percent excess air). (i) The span values for this monitor are 450 ppm reduced sulfur and 25 percent O 2 . (ii) The performance evaluations for this reduced sulfur (and O 2 ) 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 O 2 analyzer). Methods 15 or 15A and Method 3 shall be used for conducting the relative accuracy evaluations. If Method 3 yields O 2 concentrations below 0.25 percent during the performance specification test, the O 2 concentration may be assumed to be zero and the reduced sulfur CEMS need not include an O 2 monitor. (7) In place of the reduced sulfur monitor under paragraph (a)(6) of this section, an instrument using an air or O 2 dilution and oxidation system to convert the reduced sulfur to SO 2 for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of the resultant SO 2 . The monitor shall include an oxyge n monitor for correcting the data for excess oxygen. (i) The span values for this monitor are 375 ppm SO 2 and 25 percent O 2 . (ii) For reporting purposes, the SO 2 exceedance level for this monitor is 250 ppm (dry basis, zero percent excess air). (iii) The performance evaluations for this SO 2 (and O 2 ) 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 SO 2 in the gases at both the inlet and outlet of the SO 2 control device from any fluid catalytic cracking unit catalyst regenerator for which the owner or operat or 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 SO 2 emission concentration entering the control device, and the span value of the outlet monitor shall be set at 50 percen t of the maximum estimated hourly potential SO 2 emission concentration entering the control device. (ii) The performance evaluations for these SO 2 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 SO 2 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 monito r shall be set at 50 percent of the maximum hourly potential SO 2 emission concentration of the control device. (ii) The performance evaluations for this SO 2 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 monitori ng and recording concentrations of oxygen (O 2 ) 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 H 2 S 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 en sure 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 H 2 S; and (v) A description of how the 2 weeks (or seve n samples for infrequently operated fuel gas streams/systems) of monitoring results compares to the typical range of H 2 S 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 H 2 S 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 H 2 S 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 paragra ph (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 H 2 S 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 so on 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 H 2 S 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:

N OTE : All averages, except for opacity, shall be determined as the arithmetic average of the applicable 1-hour averages, e.g., the rolling 3-ho ur 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 SO 2 as measured by the SO 2 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 H 2 S as measured by the H 2 S 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 SO 2 as measured by the SO 2 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 SO 2 ) 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 SO 2 as measured by the SO 2 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 sd s 

### KR

Q c E 

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

c s = Concentration of PM, g/dscm (gr/dscf). Q sd = Volumetric flow rate of effluent gas, dscm/hr (dscf/hr).

R c = 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 (R c ) shall be computed for each run using the following equation:

R c = K 1 Q r (%CO 2 + %CO) + K 2 Q a − K 3 Q r (%CO/2 + %CO 2 + %O 2 ) + K 3 Q oxy (%O oxy )

Where:

R c = Coke burn-off rate, kilograms per hour (kg/hr) (lb/hr).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Q r

= Volumetric flow rate of exhaust gas from fluid catalytic cracking unit regenerator before entering the emission control system, dscm/min (dscf/min). Q a = Volumetric flow rate of air to fluid cataly tic cracking unit regenerator, as determined from the fluid catalytic cracking unit control room instrumentation, dscm/min (dscf/min). Q oxy = Volumetric flow rate of O 2 enriched air to fluid catalytic cracking unit regenerator, as determined from the fluid catalytic cracking unit control room instrumentation, dscm/min (dscf/min).

%CO 2 = 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).

%O 2 = O 2 concentration in fluid catalytic cracking unit regenerator exhaust, percent by volume (dry basis).

%O oxy = O 2 concentration in O 2 enriched air stream inlet to the fluid catalytic cracking unit

regenerator, percent by volume (dry basis).

K 1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hrdscf-%)].

K 2 = Material balance and conversion factor, 2. 088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hrdscf)].

K 3 = 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 (Q r ). (ii) The emission correction factor, integrated sampling and analysis procedure of Method 3B shall be used to determine CO 2 , CO, and O 2 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 bu rned 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 (E s ) of PM shall be computed for each run using the following equation: 

##  

c s 

### R H A F E  

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

E s = 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 em issions, 43 g/GJ (0.10 lb/million Btu). H = Heat input rate from solid or liquid fossil fuel, GJ/hr (million Btu/hr).

R c = 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 (R c ). (d) The owner or operator shall determine compliance with the CO standard in §60.103(a) by using the integrated sampling technique of Me thod 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 H 2 S standard in §60.104(a)(1) as follows: Method 11, 15, 15A, or 16 shall be used to determine the H 2 S 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 H 2 S 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 th is 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 SO 2 and the H 2 S and reduced sulfur standards in §60.104(a)(2) as follows: (1) Method 6 shall be used to determine the SO 2 concentration. The concentration in mg/dscm obtained by Method 6 or 6C is multiplie d 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 m 2 (53.8 ft 2 ) or at a point no closer to the walls than 1.00 m (39.4 in.) if the cross-sectional area is 5.00 m 2 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 mois ture 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 de termine the reduced sulfur and H 2 S 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 li nes, the sampling rate shall be at least 3.0 lpm (0.10 cfm). The SO 2 equivalent for each run shall be calculated after being corrected for moisture and oxygen as the arithmetic average of the SO 2 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 SO 2 , reduced sulfur and H 2 S, or moisture samples. The SO 2 , reduced sulfur, and H 2 S 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 arithm etic mean of the results of all the tests shall be compared with the applicable standard. (h) For the purpose of determining comp liance 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:

Rso 2 = 100(Cso 2 (i)

− Cso 2 (o))/Cso 2 (i)

where:

Rso 2 = 7-day average sulfur dioxide emission reduction, percent

Cso 2 (i) = sulfur dioxide emission concentration determined in §60.106(h)(2) at the inlet to the add-on control device, ppmv

Cso 2 (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, O 2 -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:

C adj = C meas [20.9 c /(20.9

− %O 2 )]

where:

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

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

20.9 c = 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

%O 2 = 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 SO X 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 (Cso x ). (9) Sulfur oxides emission rate calculated as sulf ur dioxide shall be determined for each test run by the following equation:

Where:

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

C SOx = sulfur oxides emission concentration calculated as sulfur dioxide, g/dscm (gr/dscf) Q sd = 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:

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

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

R c = 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 w ith §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 se parately by using any one of the following applicable analytical test methods: ASTM D1 29-64, 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 react or 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 calcu lated for each 8-hour period using the following equation:

where:

S f

= fresh feed sulfur content expressed in percent by weight of fresh feed. n = number of separate fresh feed streams charge d directly to the riser or reactor of the fluid catalytic cracking unit. Q f

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

S i = fresh feed sulfur content expressed in percent by weight of fresh feed for the “ith” sampling location. Q i = 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 obtai ned 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 co ntrol 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, O 2 - 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 SO X 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 av erages 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 faci lity 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 facilit y 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 f acility 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 perfor mance 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 meteorolog ical conditions, or othe r 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 paragrap h (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 mari ne 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 Septem ber 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.

T ABLE 1 TO § 63.560—G ENERAL P ROVISIONS A PPLICABILITY TO S UBPART 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 allo ws 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 S ee 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 wa ter 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 proce ss 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, readin g 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 petroleu m 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 begi nning 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-tightmeans 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 lo ading 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 lite rs (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 s ea 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 tr ansporting 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 sour ce 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 termin al'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 mainte nance 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 reco very 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 fo r 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 su bject under paragraph (d)(2) of this section to those vessels that are equipped with vapor colle ction 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 us ing 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 th e total annual average daily loading over all loading berths not equipped with a vapor collect ion 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 Q m :

Where: Q m = 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 wh ich 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 preven t 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 po llution control practices for minimizing emissions. Determination of whethe r acceptable operation and maintenan ce 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 parame ters 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 prot ocol that describes procedures for initial and any subsequent calibration of the CMS; determina tion 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 operat or 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 de veloped, 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 practi cable 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 ro ot 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 operat or 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 th e 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 ma rine 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 eq uipment 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 pa ragraph (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 determinin g vapor tightness of the marine vessel. The owner or operator of a marine tank vesse l, 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 infe asible 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 w ill 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 ot her 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 dur ing 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 th e 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 id entified 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 re quired 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 ini tial 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). Fo llowing the date on which the initial determination of compliance is established, the facility shall ope rate 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 complyin g 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 parame ter 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 init ial 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 sh all 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 requ ired percent recovery efficiency. The owner or operator shall establish as an operating parame ter 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 ini tial 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 outle t 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 usin g 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 re quired percent recovery efficiency. The owner or operator shall establish as an operating parame ter 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 sour ces 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 Ta ble 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 in stalled 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 w ith 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 instal led 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, mainta in, 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 alar m 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 comp lying 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 inst all, calibrate, operate, and maintain a CEMS consistent with the requireme nts 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 op erate 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 inst all, calibrate, operate, and maintain a CEMS consistent with the requireme nts 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 tota l 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 temperat ure 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 da ta 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, op erate, 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 paragr aph (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, op erate, 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 flow rate 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 m easuring 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=P i − P f Where: P=change in pressure, inches of water.

P i =pressure in tank when air/gas source is shut off, inches of water.

P f

=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 P ia L/V
Where: PM=maximum allowable pressure change, inches of water.

P ia =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 instal led 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. Samp ling 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:

M

j =FKV s C VOC Where:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

M

j =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) (m 3 VOC/m 3 air)(1/ppmv). K=density, kilograms per cubic meter (kg/m 3 VOC), standard conditions, 20 °C and 760 mm Hg.

V s =volume of air-vapor mixture at the inlet and outlet of the combustion or recovery device, cubic meters (m 3 ) at standard conditions, 20 °C and 760 mm Hg.
C VOC =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:

E i , E o =mass flow rate of VOC at the inlet (i) and outlet (o) of the recovery or combustion device, kilogram per hour (kg/hr).

M ij , M oj =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***

E i =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.

E o =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 owne r 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 paragra ph 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 calculate d 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 owne r 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 demons trate 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 th e 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 te st plan (if review is requested) or the use of the alternative method within 30 days before the te st 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 operat or'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 re ceived 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 subpar t 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 init ial 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 subj ect to the standard no later than 365 days or 120 days after initial startup, whichever occurs be fore 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 th e intended construction or reconstruction. The notification shall be submitted as soon as practicab le 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 reconstr uction 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 informa tion 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 em issions 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 emi ssions 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 annua l 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 sour ce's potential for noncompliance in the future. If the Administrator will notify the owner or opera tor 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 emissi ons and monitoring sy stem 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, a nd 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, re paired, 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 c ontinuous 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, bo th 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 syst em, 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 contro l 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 sha ll 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 accordan ce 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/chi ef/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 el ectronically 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 subpar t. 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 monito ring 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 reco rdkeeping and reportin g 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 tocomply 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.
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## (2) If you use a wet scrubbe r of the non-venturi jet-ejector design, you're not required to install and operate a continuous paramete r monitoring system for pressure drop.
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## 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.

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## 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.
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## 63.10(d)(5)(ii) Yes Except that actions taken during a startup, shutdown, or malfunction that are not cons istent with the startup, shutdown, and malfunction plan a nd 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 mu st be included in the next periodic report.