June 15, 2014 

Redline of 40 CFR part 63, subpart CC, showing proposed amendments 

Insertions are shown in bold blue text 

Deletions are shown in red strikeout text 

Title 40: Protection of Environment 

PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 

FOR SOURCE CATEGORIES 

Subpart CC—National Emission Standards for Hazardous Air Pollutants From Petroleum 

Refineries 

§ 63.640 Applicability and designation of affected source. 

(a) This subpart applies to petroleum refining process units and to related emissions points that 

are specified in paragraphs (c)(1) through (98) of this section that are located at a plant site and 

that meet the criteria in paragraphs (a)(1) and (2) of this section: 

(1) Are located at a plant site that is a major source as defined in section 112(a) of the Clean Air 

Act; and 

(2) Emit or have equipment containing or contacting one or more of the hazardous air pollutants 

listed in table 1 of this subpart. 

(b)(1) If the predominant use of the flexible operation unit, as described in paragraphs (b)(1)(i) 

and (ii) of this section, is as a petroleum refining process unit, as defined in §63.641, then the 

flexible operation unit shall be subject to the provisions of this subpart. 

(i) Except as provided in paragraph (b)(1)(ii) of this section, the predominant use of the flexible 

operation unit shall be the use representing the greatest annual operating time. 

(ii) If the flexible operation unit is used as a petroleum refining process unit and for another 

purpose equally based on operating time, then the predominant use of the flexible operation unit 

shall be the use that produces the greatest annual production on a mass basis. 

(2) The determination of applicability of this subpart to petroleum refining process units that are 

designed and operated as flexible operation units shall be reported as specified in 

§63.655(h)(6)(i). 

(c) For the purposes of this subpart, the affected source shall comprise all emissions points, in 

combination, listed in paragraphs (c)(1) through (c)(89) of this section that are located at a single 

refinery plant site. 
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(1) All miscellaneous process vents from petroleum refining process units meeting the criteria in 

paragraph (a) of this section; 

(2) All storage vessels associated with petroleum refining process units meeting the criteria in 

paragraph (a) of this section; 

(3) All wastewater streams and treatment operations associated with petroleum refining process 

units meeting the criteria in paragraph (a) of this section; 

(4) All equipment leaks from petroleum refining process units meeting the criteria in paragraph 

(a) of this section; 

(5) All gasoline loading racks classified under Standard Industrial Classification code 2911 

meeting the criteria in paragraph (a) of this section; 

(6) All marine vessel loading operations located at a petroleum refinery meeting the criteria in 

paragraph (a) of this section and the applicability criteria of subpart Y, §63.560; 

(7) All storage vessels and equipment leaks associated with a bulk gasoline terminal or pipeline 

breakout station classified under Standard Industrial Classification code 2911 located within a 

contiguous area and under common control with a refinery meeting the criteria in paragraph (a) 

of this section; and 

(8) All heat exchange systems, as defined in this subpart. 

(9) All releases associated with the decoking operations of a delayed coking unit, as defined 

in this subpart. 

(d) The affected source subject to this subpart does not include the emission points listed in 

paragraphs (d)(1) through (d)(5) of this section. 

(1) Stormwater from segregated stormwater sewers; 

(2) Spills; 

(3) Any pump, compressor, pressure relief device, sampling connection system, open-ended 

valve or line, valve, or instrumentation system that is intended to operate in organic hazardous 

air pollutant service, as defined in §63.641 of this subpart, for less than 300 hours during the 

calendar year; 

(4) Catalytic cracking unit and catalytic reformer catalyst regeneration vents, and sulfur plant 

vents; and 

(5) Emission points routed to a fuel gas system, as defined in §63.641 of this subpart, provided 

that on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares 
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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) The owner or operator of a storage vessel constructed on or before August 18, 1994, shall 

follow the procedures specified in paragraphs (e)(1) and (e)(2) of this section to determine 

whether a storage vessel is part of a source to which this subpart applies. The owner or operator 

of a storage vessel constructed after August 18, 1994, shall follow the procedures specified in 

paragraphs (e)(1), (e)(2)(i), and (e)(2)(ii) of this section to determine whether a storage vessel is 

part of a source to which this subpart applies. 

(1) Where a storage vessel is used exclusively by a process unit, the storage vessel shall be 

considered part of that process unit. 

(i) If the process unit is a petroleum refining process unit subject to this subpart, then the storage 

vessel is part of the affected source to which this subpart applies. 

(ii) If the process unit is not subject to this subpart, then the storage vessel is not part of the 

affected source to which this subpart applies. 

(2) If a storage vessel is not dedicated to a single process unit, then the applicability of this 

subpart shall be determined according to the provisions in paragraphs (e)(2)(i) through (e)(2)(iii) 

of this section. 

(i) If a storage vessel is shared among process units and one of the process units has the 

predominant use, as determined by paragraphs (e)(2)(i)(A) and (e)(2)(i)(B) of this section, then 

the storage vessel is part of that process unit. 

(A) If the greatest input on a volume basis into the storage vessel is from a process unit that is 

located on the same plant site, then that process unit has the predominant use. 

(B) If the greatest input on a volume basis into the storage vessel is provided from a process unit 

that is not located on the same plant site, then the predominant use shall be the process unit that 

receives the greatest amount of material on a volume basis from the storage vessel at the same 

plant site. 

(ii) If a storage vessel is shared among process units so that there is no single predominant use, 

and at least one of those process units is a petroleum refining process unit subject to this subpart, 

the storage vessel shall be considered to be part of the petroleum refining process unit that is 

subject to this subpart. If more than one petroleum refining process unit is subject to this subpart, 

the owner or operator may assign the storage vessel to any of the petroleum refining process 

units subject to this subpart. 

(iii) If the predominant use of a storage vessel varies from year to year, then the applicability of 

this subpart shall be determined based on the utilization of that storage vessel during the year 
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preceding August 18, 1995. This determination shall be reported as specified in 

§63.655(h)(6)(ii). 

(f) The owner or operator of a distillation unit constructed on or before August 18, 1994, shall 

follow the procedures specified in paragraphs (f)(1) through (f)(4) of this section to determine 

whether a miscellaneous process vent from a distillation unit is part of a source to which this 

subpart applies. The owner or operator of a distillation unit constructed after August 18, 1994, 

shall follow the procedures specified in paragraphs (f)(1) through (f)(5) of this section to 

determine whether a miscellaneous process vent from a distillation unit is part of a source to 

which this subpart applies. 

(1) If the greatest input to the distillation unit is from a process unit located on the same plant 

site, then the distillation unit shall be assigned to that process unit. 

(2) If the greatest input to the distillation unit is provided from a process unit that is not located 

on the same plant site, then the distillation unit shall be assigned to the process unit located at the 

same plant site that receives the greatest amount of material from the distillation unit. 

(3) If a distillation unit is shared among process units so that there is no single predominant use, 

as described in paragraphs (f)(1) and (f)(2) of this section, and at least one of those process units 

is a petroleum refining process unit subject to this subpart, the distillation unit shall be assigned 

to the petroleum refining process unit that is subject to this subpart. If more than one petroleum 

refining process unit is subject to this subpart, the owner or operator may assign the distillation 

unit to any of the petroleum refining process units subject to this rule. 

(4) If the process unit to which the distillation unit is assigned is a petroleum refining process 

unit subject to this subpart and the vent stream contains greater than 20 parts per million by 

volume total organic hazardous air pollutants, then the vent from the distillation unit is 

considered a miscellaneous process vent (as defined in §63.641 of this subpart) and is part of the 

source to which this subpart applies. 

(5) If the predominant use of a distillation unit varies from year to year, then the applicability of 

this subpart shall be determined based on the utilization of that distillation unit during the year 

preceding August 18, 1995. This determination shall be reported as specified in 

§63.655(h)(6)(iii). 

(g) The provisions of this subpart do not apply to the processes specified in paragraphs (g)(1) 

through (g)(7) of this section. 

(1) Research and development facilities, regardless of whether the facilities are located at the 

same plant site as a petroleum refining process unit that is subject to the provisions of this 

subpart; 

(2) Equipment that does not contain any of the hazardous air pollutants listed in table 1 of this 

subpart that is located within a petroleum refining process unit that is subject to this subpart; 
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(3) Units processing natural gas liquids; 

(4) Units that are used specifically for recycling discarded oil; 

(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) SExcept as provided in paragraphs (k), (l), or (m) of this section, sources subject to this 

subpart are required to achieve compliance on or before the dates specified in table 11 of this 

subpart, except as provided in paragraphs (h)(1) through (h)(63) of this section. 

(1) 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) Marine tank vessels at existing sources shall be in compliance with this subpart, except for 

§§63.657 through 63.661, no later than August 18, 1999, unless the vessels are included in an 

emissions average to generate emission credits. Marine tank vessels used to generate credits in 

an emissions average shall be in compliance with this subpart no later than August 18, 1998 

unless an extension has been granted by the Administrator as provided in §63.6(i). 

(42) Existing Group 1 floating roof storage vessels meeting the applicability criteria in item 1 

of the definition of Group 1 storage vessel shall be in compliance with §63.646 of this subpart

at the first degassing and cleaning activity after August 18, 1998, or August 18, 2005, whichever 

is first.

(53) 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)(53)(i) through (h)(53)(iii) of this 

section. 
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(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. 

(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. 

(i) If an additional petroleum refining process unit is added to a plant site that is a major source 

as defined in section 112(a) of the Clean Air Act, the addition shall be subject to the 

requirements for a new source if it meets the criteria specified in paragraphs (i)(1) through (i)(3) 

of this section: 

(1) It is an addition that meets the definition of construction in §63.2 of subpart A of this part; 

(2) Such construction commenced after July 14, 1994; and 

(3) The addition has the potential to emit 10 tons per year or more of any hazardous air pollutant 

or 25 tons per year or more of any combination of hazardous air pollutants. 

(j) If any change is made to a petroleum refining process unit subject to this subpart, the change 

shall be subject to the requirements for a new source if it meets the criteria specified in 

paragraphs (j)(1) and (j)(2) of this section: 

(1) It is a change that meets the definition of reconstruction in §63.2 of subpart A of this part; 

and 

(2) Such reconstruction commenced after July 14, 1994. 

(k) If an additional petroleum refining process unit is added to a plant site or a change is made to 

a petroleum refining process unit and the addition or change is determined to be subject to the 

new source requirements according to paragraphs (i) or (j) of this section it must comply with the 

requirements specified in paragraphs (k)(1) and (k)(2) of this section: 

(1) The reconstructed source, addition, or change shall be in compliance with the new source 

requirements in item (1), (2), or (3) of table 11 of this subpart, as applicable, upon initial 

startup of the reconstructed source or by August 18, 1995, whichever is later; and 

(2) The owner or operator of the reconstructed source, addition, or change shall comply with the 

reporting and recordkeeping requirements that are applicable to new sources. The applicable 

reports include, but are not limited to: 

(i) The application for approval of construction or reconstruction shall be submitted as soon as 

practical before the construction or reconstruction is planned to commence (but it need not be 

sooner than November 16, 1995); 
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(ii) The Notification of Compliance Status report as required by §63.655(f) for a new source, 

addition, or change; 

(iii) Periodic Reports and other reports as required by §63.655(g) and (h); 

(iv) Reports and notifications required by §60.487 of subpart VV of part 60 or §63.182 of 

subpart H of this part. The requirements for subpart H are summarized in table 3 of this subpart; 

(v) Reports required by 40 CFR 61.357 of subpart FF; 

(vi) Reports and notifications required by §63.428(b), (c), (g)(1), (h)(1) through (h)(3), and (k) of 

subpart R. These requirements are summarized in table 4 of this subpart; and 

(vii) Reports and notifications required by §§63.565 and 63.567 of subpart Y of this part. These 

requirements are summarized in table 5 of this subpart. 

(l) If an additional petroleum refining process unit is added to a plant site or if a miscellaneous 

process vent, storage vessel, gasoline loading rack, marine tank vessel loading operation, or heat 

exchange system, or decoking operation that meets the criteria in paragraphs (c)(1) through 

(89) of this section is added to an existing petroleum refinery or if another deliberate operational 

process change creating an additional Group 1 emissions point(s) (as defined in §63.641) is made 

to an existing petroleum refining process unit, and if the addition or process change is not subject 

to the new source requirements as determined according to paragraphs (i) or (j) of this section, 

the requirements in paragraphs (l)(1) through (34) of this section shall apply. Examples of 

process changes include, but are not limited to, changes in production capacity, or feed or raw 

material where the change requires construction or physical alteration of the existing equipment 

or catalyst type, or whenever there is replacement, removal, or addition of recovery equipment. 

For purposes of this paragraph and paragraph (m) of this section, process changes do not include: 

Process upsets, unintentional temporary process changes, and changes that are within the 

equipment configuration and operating conditions documented in the Notification of Compliance 

Status report required by §63.655(f). 

(1) The added emission point(s) and any emission point(s) within the added or changed 

petroleum refining process unit are subject to the requirements for an existing source. 

(2) The added emission point(s) and any emission point(s) within the added or changed 

petroleum refining process unit shall be in compliance with the applicable requirements in 

item (4) of table 11 of this subpart by the dates specified in paragraphs (l)(2)(i) or (l)(2)(ii) of 

this section, as applicable. 

(i) If a petroleum refining process unit is added to a plant site or an emission point(s) is added to 

any existing petroleum refining process unit, the added emission point(s) shall be in compliance 

upon initial startup of any added petroleum refining process unit or emission point(s) or by 

August 18, 1998the applicable compliance date in item (4) of table 11 of this subpart, 

whichever is later. 
Page 8 of 162 

(ii) If a deliberate operational process change to an existing petroleum refining process unit 

causes a Group 2 emission point to become a Group 1 emission point (as defined in §63.641), the 

owner or operator shall be in compliance upon initial startup or by August 18, 1998, whichever is 

later, unless the owner or operator demonstrates to the Administrator that achieving compliance 

will take longer than making the change. If this demonstration is made to the Administrator’s 

satisfaction, the owner or operator shall follow the procedures in paragraphs (m)(1) through 

(m)(3) of this section to establish a compliance date. 

(3) The owner or operator of a petroleum refining process unit or of a storage vessel, 

miscellaneous process vent, wastewater stream, gasoline loading rack, marine tank vessel 

loading operation, or heat exchange system, or decoking operation meeting the criteria in 

paragraphs (c)(1) through (89) of this section that is added to a plant site and is subject to the 

requirements for existing sources shall comply with the reporting and recordkeeping 

requirements that are applicable to existing sources including, but not limited to, the reports 

listed in paragraphs (l)(3)(i) through (vii) of this section. A process change to an existing 

petroleum refining process unit shall be subject to the reporting requirements for existing sources 

including, but not limited to, the reports listed in paragraphs (l)(3)(i) through (l)(3)(vii) of this 

section. The applicable reports include, but are not limited to: 

(i) The Notification of Compliance Status report as required by §63.655(f) for the emission 

points that were added or changed; 

(ii) Periodic Reports and other reports as required by §63.655(g) and (h); 

(iii) Reports and notifications required by sections of subpart A of this part that are applicable to 

this subpart, as identified in table 6 of this subpart. 

(iv) Reports and notifications required by §63.182, or 40 CFR 60.487. The requirements of 

subpart H of this part are summarized in table 3 of this subpart; 

(v) Reports required by §61.357 of subpart FF; 

(vi) Reports and notifications required by §63.428(b), (c), (g)(1), (h)(1) through (h)(3), and (k) of 

subpart R. These requirements are summarized in table 4 of this subpart; and 

(vii) Reports and notifications required by §§63.565 and 63.567 of subpart Y. These 

requirements are summarized in table 5 of this subpart. 

(4) If pumps, compressors, pressure relief devices, sampling connection systems, open-ended 

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 
Page 9 of 162 

shall comply with the applicable requirements of this subpart for existing sources, as specified 

in item (4) of table 11 of this subpart, for the Group 1 emission point as expeditiously as 

practicable, but in no event later than 3 years after the emission point becomes Group 1. 

(1) The owner or operator shall submit to the Administrator for approval a compliance schedule, 

along with a justification for the schedule. 

(2) The compliance schedule shall be submitted within 180 days after the change is made, unless 

the compliance schedule has been previously submitted to the permitting authority. If it is not 

possible to determine until after the change is implemented whether the emission point has 

become Group 1, the compliance schedule shall be submitted within 180 days of the date when 

the affect of the change is known to the source. The compliance schedule may be submitted in 

the next Periodic Report if the change is made after the date the Notification of Compliance 

Status report is due. 

(3) The Administrator shall approve or deny the compliance schedule or request changes within 

120 calendar days of receipt of the compliance schedule and justification. Approval is automatic 

if not received from the Administrator within 120 calendar days of receipt. 

(n) Overlap of subpart CC with other regulations for storage vessels. As applicable, paragraphs 

(n)(1), (n)(3), (n)(4), (n)(6), and (n)(7) of this section apply for Group 2 storage vessels and 

paragraphs (n)(2) and (n)(5) of this section apply for Group 1 storage vessels.

(1) After the compliance dates specified in paragraph (h) of this section, a Group 1 or Group 2 

storage vessel that is part of an existing source and is also 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 part of a new source and is also subject to 40 CFR part 60, subpart Kb is required to 

comply only with either 40 CFR part 60, subpart Kb, except as provided in paragraph 

(n)(8) of this section; or this subpart. After the compliance dates specified in paragraph (h) 

of this section, a Group 1 storage vessel that is also subject to 40 CFR part 61, subpart Y is 

required to comply only with either 40 CFR part 61, subpart Y, except as provided in 

paragraph (n)(10) of this section; or this subpart.

(3) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel 

that is part of a new source and is subject to 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. 
Page 10 of 162 

(4) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel 

that is part of a new source and is subject to 40 CFR 60.110b, but is not required to apply 

controls by 40 CFR 60.110b or 60.112b, is required to comply only with this subpart.

(4) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage 

vessel that is part of a new source and is subject to 40 CFR 61.270, but is not required to 

apply controls by 40 CFR 61.271, is required to comply only with this subpart. 

(5) After the compliance dates specified in paragraph (h) of this section, a Group 1 storage vessel 

that is also subject to the provisions of 40 CFR part 60, subparts K or Ka is required to only 

comply with the provisions of this subpart. 

(6) After compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel 

that is subject to the control requirements of 40 CFR part 60, subparts K or Ka is required to 

comply only with the provisions of 40 CFR part 60, subparts K or Ka except as provided for in 

paragraph (n)(9) of this section. 

(7) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel 

that is subject to 40 CFR part 60, subparts K or Ka, but not to the control requirements of 40 

CFR part 60, subparts K or Ka, is required to comply only with this subpart. 

(8) Storage vessels described by paragraphs (n)(1) and (n)(3) of this section are to comply with 

40 CFR part 60, subpart Kb except as provided for in paragraphs (n)(8)(i) through (n)(8)(vi) of 

this section. Storage vessels described by paragraph (n)(2) electing to comply with part 60, 

subpart Kb of this chapter shall comply with subpart Kb except as provided in paragraphs 

(n)(8)(i) through (n)(8)(vii) of this section.

(i) Storage vessels that are to comply with §60.112b(a)(2) of subpart Kb are exempt from the 

secondary seal requirements of §60.112b(a)(2)(i)(B) during the gap measurements for the 

primary seal required by §60.113b(b) of subpart Kb. 

(ii) If the owner or operator determines that it is unsafe to perform the seal gap measurements 

required in §60.113b(b) of subpart Kb or to inspect the vessel to determine compliance with 

§60.113b(a) of subpart Kb because the roof appears to be structurally unsound and poses an 

imminent danger to inspecting personnel, the owner or operator shall comply with the 

requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of subpart G (only up to the 

compliance date specified in paragraph (h) of this section for compliance with §63.660, as 

applicable) or either §63.1063(c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of subpart WW. 

(iii) If a failure is detected during the inspections required by §60.113b(a)(2) or during the seal 

gap measurements required by §60.113b(b)(1), and the vessel cannot be repaired within 45 days 

and the vessel cannot be emptied within 45 days, the owner or operator may utilize up to two 

extensions of up to 30 additional calendar days each. The owner or operator is not required to 

provide a request for the extension to the Administrator. 
Page 11 of 162 

(iv) If an extension is utilized in accordance with paragraph (n)(8)(iii) of this section, the owner 

or operator shall, in the next periodic report, identify the vessel, provide the information listed in 

§60.113b(a)(2) or §60.113b(b)(4)(iii), and describe the nature and date of the repair made or 

provide the date the storage vessel was emptied. 

(v) Owners and operators of storage vessels complying with subpart Kb of part 60 may submit 

the inspection reports required by §§60.115b(a)(3), (a)(4), and (b)(4) of subpart Kb as part of the 

periodic reports required by this subpart, rather than within the 30-day period specified in 

§§60.115b(a)(3), (a)(4), and (b)(4) of subpart Kb. 

(vi) The reports of rim seal inspections specified in §60.115b(b)(2) are not required if none of the 

measured gaps or calculated gap areas exceed the limitations specified in §60.113b(b)(4). 

Documentation of the inspections shall be recorded as specified in §60.115b(b)(3). 

(vii) To be in compliance with §60.112b(a)(2)(ii) of this chapter, floating roof storage vessels 

must be equipped with guidepole controls as described in Appendix I: Acceptable Controls 

for Slotted Guidepoles Under the Storage Tank Emissions Reduction Partnership Program 

(available at http://www.epa.gov/ttn/atw/petrefine/petrefpg.html). 

(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 subpart G (only 

up to the compliance date specified in paragraph (h) of this section for compliance with 

§63.660, as applicable) or either §63.1063(c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of subpart 

WW. 

(ii) If a failure is detected during the seal gap measurements required by §60.113a(a)(1) of 

subpart Ka, and the vessel cannot be repaired within 45 days and the vessel cannot be emptied 

within 45 days, the owner or operator may utilize up to 2 extensions of up to 30 additional 

calendar days each. 

(iii) If an extension is utilized in accordance with paragraph (n)(9)(ii) of this section, the owner 

or operator shall, in the next periodic report, identify the vessel, describe the nature and date of 

the repair made or provide the date the storage vessel was emptied. The owner or operator shall 

also provide documentation of the decision to utilize an extension including a description of the 
Page 12 of 162 

failure, documentation that alternate storage capacity is unavailable, and a schedule of actions 

that will ensure that the control equipment will be repaired or the vessel emptied as soon as 

possible. 

(iv) Owners and operators of storage vessels complying with subpart Ka of part 60 may submit 

the inspection reports required by §60.113a(a)(1)(i)(E) of subpart Ka as part of the periodic 

reports required by this subpart, rather than within the 60-day period specified in 

§60.113a(a)(1)(i)(E) of subpart Ka. 

(10) Storage vessels described by paragraph (n)(1) of this section are to comply with 40 

CFR part 61, subpart Y except as provided in paragraphs (n)(10)(i) through (n)(8)(vi) of 

this section. Storage vessels described by paragraph (n)(2) electing to comply with 40 CFR 

part 61, subpart Y shall comply with subpart Y except as provided for in paragraphs 

(n)(10)(i) through (n)(10)(viii) of this section. 

(i) Storage vessels that are to comply with §61.271(b) of this chapter are exempt from the 

secondary seal requirements of §61.271(b)(2)(ii) of this chapter during the gap 

measurements for the primary seal required by §61.272(b) of this chapter. 

(ii) If the owner or operator determines that it is unsafe to perform the seal gap 

measurements required in §61.272(b) of this chapter or to inspect the vessel to determine 

compliance with §61.272(a) of this chapter because the roof appears to be structurally 

unsound and poses an imminent danger to inspecting personnel, the owner or operator 

shall comply with the requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of subpart 

G (only up to the compliance date specified in paragraph (h) of this section for compliance 

with §63.660, as applicable) or either §63.1063(c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of 

subpart WW. 

(iii) If a failure is detected during the inspections required by §61.272(a)(2) of this chapter 

or during the seal gap measurements required by §61.272(b)(1) of this chapter, and the 

vessel cannot be repaired within 45 days and the vessel cannot be emptied within 45 days, 

the owner or operator may utilize up to two extensions of up to 30 additional calendar days 

each. The owner or operator is not required to provide a request for the extension to the 

Administrator. 

(iv) If an extension is utilized in accordance with paragraph (n)(10)(iii) of this section, the 

owner or operator shall, in the next periodic report, identify the vessel, provide the 

information listed in §61.272(a)(2) or §61.272(b)(4)(iii) of this chapter, and describe the 

nature and date of the repair made or provide the date the storage vessel was emptied. 

(v) Owners and operators of storage vessels complying with 40 CFR part 61, subpart Y 

may submit the inspection reports required by §61.275(a), (b)(1), and (d) of this chapter as 

part of the periodic reports required by this subpart, rather than within the 60-day period 

specified in §61.275(a), (b)(1), and (d) of this chapter. 
Page 13 of 162 

(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 

(available at http://www.epa.gov/ttn/atw/petrefine/petrefpg.html). 

(viii) If a flare is used as a control device for a storage vessel, on and after [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the owner or operator must meet the 

requirements of §63.670 instead of the requirements referenced from part 61, subpart Y of 

this chapter for that flare. 

(o) Overlap of this subpart CC with other regulations for wastewater. 

(1) After the compliance dates specified in paragraph (h) of this section a Group 1 wastewater 

stream managed in a piece of equipment that is also subject to the provisions of 40 CFR part 60, 

subpart QQQ is required to comply only with this subpart. 

(2) After the compliance dates specified in paragraph (h) of this section a Group 1 or Group 2 

wastewater stream that is conveyed, stored, or treated in a wastewater stream management unit 

that also receives streams subject to the provisions of §§63.133 through 63.147 of subpart G 

wastewater provisions of this part shall comply as specified in paragraph (o)(2)(i) or (o)(2)(ii) of 

this section. Compliance with the provisions of paragraph (o)(2) of this section shall constitute 

compliance with the requirements of this subpart for that wastewater stream. 

(i) Comply with paragraphs (o)(2)(i)(A) through (o)(2)(i)(CD) 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. 

(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 
Page 14 of 162 

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) and (o)(2)(ii)(Bthrough (C) of this section. 

(A) Comply with the provisions of §§63.133 through 63.148 and §§63.151 and 63.152 of subpart 

G. 

(B) For any Group 2 wastewater stream or organic stream whose benzene emissions are subject 

to control through the use of one or more treatment processes or waste management units under 

the provisions of 40 CFR part 61, subpart FF on or after December 31, 1992, comply with the 

requirements of §63.133 through §63.147 of subpart G for Group 1 wastewater streams. 

(C) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the applicable 

requirements of 40 CFR part 61, subpart FF and subpart G of this part, or the 

requirements of §63.670. 

(p) Overlap of subpart CC with other regulations for equipment leaks. 

(1) After the compliance dates specified in paragraph (h) of this section, equipment leaks that are 

also subject to the provisions of 40 CFR parts 60 and 61 standards promulgated before 

September 4, 2007, are required to comply only with the provisions specified in this subpart. 

(2) Equipment leaks that are also subject to the provisions of 40 CFR part 60, subpart GGGa, are 

required to comply only with the provisions specified in 40 CFR part 60, subpart GGGa.

Owners and operators of equipment leaks that are subject to the provisions of 40 CFR part 

60, subpart GGGa and subject to this subpart may elect to monitor equipment leaks 

following the provisions in §63.661, provided that the equipment is in compliance with all 

other provisions of 40 CFR part 60, subpart GGGa.

(q) For overlap of subpart CC with local or State regulations, the permitting authority for the 

affected source may allow consolidation of the monitoring, recordkeeping, and reporting 

requirements under this subpart with the monitoring, recordkeeping, and reporting requirements 

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 
Page 15 of 162 

source subject to subpart CC and also is subject to the provisions of 40 CFR part 60, subpart XX 

is required to comply only with this subpart. 

§ 63.641 Definitions. 

All terms used in this subpart shall have the meaning given them in the Clean Air Act, subpart A 

of this part, and in this section. If the same term is defined in subpart A and in this section, it 

shall have the meaning given in this section for purposes of this subpart. 

Affected source means the collection of emission points to which this subpart applies as 

determined by the criteria in §63.640. 

Aliphatic means open-chained structure consisting of paraffin, olefin and acetylene hydrocarbons 

and derivatives. 

Annual average true vapor pressure means the equilibrium partial pressure exerted by the stored 

liquid at the temperature equal to the annual average of the liquid storage temperature for liquids 

stored above or below the ambient temperature or at the local annual average temperature 

reported by the National Weather Service for liquids stored at the ambient temperature, as 

determined: 

(1) In accordance with methods specified in §63.111 of subpart G of this part; 

(2) From standard reference texts; or 

(3) By any other method approved by the Administrator. 

Assist air means all air that intentionally is introduced prior to or at a flare tip through 

nozzles or other hardware conveyance for the purposes including, but not limited to, 

protecting the design of the flare tip, promoting turbulence for mixing or inducing air into 

the flame. Assist air includes premix assist air and perimeter assist air. Assist air does not 

include the surrounding ambient air. 

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. 
Page 16 of 162 

Car-seal means a seal that is placed on a device that is used to change the position of a valve 

(e.g., from opened to closed) in such a way that the position of the valve cannot be changed 

without breaking the seal. 

Center steam means the portion of assist steam introduced into the stack of a flare to reduce 

burnback. 

Closed blowdown system means a system used for depressuring process vessels that is not 

open to the atmosphere and is configured of piping, ductwork, connections, 

accumulators/knockout drums, and, if necessary, flow inducing devices that transport gas 

or vapor from process vessel to a control device or back into the process. 

Closed vent system means a system that is not open to the atmosphere and is configured of 

piping, ductwork, connections, and, if necessary, flow inducing devices that transport gas or 

vapor from an emission point to a control device or back into the process. If gas or vapor from 

regulated equipment is routed to a process (e.g., to a petroleum refinery fuel gas system), the 

process shall not be considered a closed vent system and is not subject to closed vent system 

standards. 

Combustion device means an individual unit of equipment such as a flare, incinerator, process 

heater, or boiler used for the combustion of organic hazardous air pollutant vapors. 

Combustion zone means the area of the flare flame where the combustion zone gas 

combines for combustion. 

Combustion zone gas means all gases and vapors found just after a flare tip. This gas 

includes all flare vent gas, total steam, and premix air. 

Connector means flanged, screwed, or other joined fittings used to connect two pipe lines or a 

pipe line and a piece of equipment. A common connector is a flange. Joined fittings welded 

completely around the circumference of the interface are not considered connectors for the 

purpose of this regulation. For the purpose of reporting and recordkeeping, connector means 

joined fittings that are accessible. 

Continuous record means documentation, either in hard copy or computer readable form, of data 

values measured at least once every hour and recorded at the frequency specified in §63.655(i). 

Continuous recorder means a data recording device recording an instantaneous data value or an 

average data value at least once every hour. 

Control device means any equipment used for recovering, removing, or oxidizing organic 

hazardous air pollutants. Such equipment includes, but is not limited to, absorbers, carbon 

adsorbers, condensers, incinerators, flares, boilers, and process heaters. For miscellaneous 

process vents (as defined in this section), recovery devices (as defined in this section) are not 

considered control devices. 
Page 17 of 162 

Cooling tower means a heat removal device used to remove the heat absorbed in circulating 

cooling water systems by transferring the heat to the atmosphere using natural or mechanical 

draft. 

Cooling tower return line means the main water trunk lines at the inlet to the cooling tower 

before exposure to the atmosphere. 

Decoking operations means the sequence of steps conducted at the end of the delayed coking 

unit’s cooling cycle to open the coke drum to the atmosphere in order to remove coke from 

the coke drum. Decoking operations begin at the end of the cooling cycle when steam 

released from the coke drum is no longer discharged via the delayed coker vent to the 

unit’s blowdown system but instead is vented directly to the atmosphere. Decoking 

operations include atmospheric depressuring (venting), deheading, draining, and decoking 

(coke cutting). 

Delayed coker vent means a vent that is typically intermittent in nature, and usually occurs only 

during the initiation of the depressuringcooling cycle of the decoking operationa 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 a closedthe delayed coking 

unit’s blowdown system or directly to the atmosphere in an open blowdown system. The 

emissions from the decoking phases of delayed coker operations, which include coke drumdirect 

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 those 

in the feed stream(s). The separation is achieved by the redistribution of the components between 

the liquid and the vapor phases by vaporization and condensation as they approach equilibrium 

within the distillation unit. Distillation unit includes the distillate receiver, reboiler, and any 

associated vacuum pump or steam jet. 

Emission point means an individual miscellaneous process vent, storage vessel, wastewater 

stream, or equipment leak, decoking operation or heat exchange system associated with a 

petroleum refining process unit; an individual storage vessel or equipment leak associated with a 

bulk gasoline terminal or pipeline breakout station classified under Standard Industrial 
Page 18 of 162 

Classification code 2911; a gasoline loading rack classified under Standard Industrial 

Classification code 2911; or a marine tank vessel loading operation located at a petroleum 

refinery. 

Equipment leak means emissions of organic hazardous air pollutants from a pump, compressor, 

pressure relief device, sampling connection system, open-ended valve or line, valve, or 

instrumentation system “in organic hazardous air pollutant service” as defined in this section. 

Vents from wastewater collection and conveyance systems (including, but not limited to 

wastewater drains, sewer vents, and sump drains), tank mixers, and sample valves on storage 

tanks are not equipment leaks. 

Flame zone means the portion of a combustion chamber of a boiler or process heater occupied by 

the flame envelope created by the primary fuel. 

Flare means a combustion device lacking an enclosed combustion chamber that uses an 

uncontrolled volume of ambient air to burn gases. For the purposes of this rule, the 

definition of flare includes, but is not necessarily limited to, air-assisted flares, steamassisted flares and non-assisted flares. 

Flare purge gas means gas introduced between a flare header’s water seal and the flare tip 

to prevent oxygen infiltration (backflow) into the flare tip. For a flare with no water seal, 

the function of flare purge gas is performed by flare sweep gas and, therefore, by definition, 

such a flare has no flare purge gas. 

Flare supplemental gas means all gas introduced to the flare in order to improve the 

combustible characteristics of combustion zone gas. 

Flare sweep gas means, for a flare with a flare gas recovery system, the minimum amount 

of gas necessary to maintain a constant flow of gas through the flare header in order to 

prevent oxygen buildup in the flare header; flare sweep gas in these flares is introduced 

prior to and recovered by the flare gas recovery system. For a flare without a flare gas 

recovery system, flare sweep gas means the minimum amount of gas necessary to maintain 

a constant flow of gas through the flare header and out the flare tip in order to prevent 

oxygen buildup in the flare header and to prevent oxygen infiltration (backflow) into the 

flare tip. 

Flare vent gas means all gas found just prior to the flare tip. This gas includes all flare 

waste gas (i.e., gas from facility operations that is directed to a flare for the purpose of 

disposing of the gas), flare sweep gas, flare purge gas and flare supplemental gas, but does 

not include pilot gas, total steam or assist air. 

Flexible operation unit means a process unit that manufactures different products periodically by 

alternating raw materials or operating conditions. These units are also referred to as campaign 

plants or blocked operations. 
Page 19 of 162 

Flow indicator means a device that indicates whether gas is flowing, or whether the valve 

position would allow gas to flow, in a line. 

Fuel gas system means the offsite and onsite piping and control system that gathers gaseous 

streams generated by refinery operations, may blend them with sources of gas, if available, and 

transports the blended gaseous fuel at suitable pressures for use as fuel in heaters, furnaces, 

boilers, incinerators, gas turbines, and other combustion devices located within or outside of the 

refinery. The fuel is piped directly to each individual combustion device, and the system 

typically operates at pressures over atmospheric. The gaseous streams can contain a mixture of 

methane, light hydrocarbons, hydrogen and other miscellaneous species. 

Gasoline means any petroleum distillate or petroleum distillate/alcohol blend having a Reid 

vapor pressure of 27.6 kilopascals or greater that is used as a fuel for internal combustion 

engines. 

Gasoline loading rack means the loading arms, pumps, meters, shutoff valves, relief valves, and 

other piping and valves necessary to fill gasoline cargo tanks. 

Group 1 gasoline loading rack means any gasoline loading rack classified under Standard 

Industrial Classification code 2911 that is located within a bulk gasoline terminal that has a 

gasoline throughput greater than 75,700 liters per day. Gasoline throughput shall be the 

maximum calculated design throughput for the terminal as may be limited by compliance with 

enforceable conditions under Federal, State, or local law and discovered by the Administrator 

and any other person. 

Group 1 marine tank vessel means a vessel at an existing source loaded at any land- or sea-based 

terminal or structure that loads liquid commodities with vapor pressures greater than or equal to 

10.3 kilopascals in bulk onto marine tank vessels, that emits greater than 9.1 megagrams of any 

individual HAP or 22.7 megagrams of any combination of HAP annually after August 18, 1999, 

or a vessel at a new source loaded at any land- or sea-based terminal or structure that loads liquid 

commodities with vapor pressures greater than or equal to 10.3 kilopascals onto marine tank 

vessels. 

Group 1 miscellaneous process vent means a miscellaneous process vent for which the total 

organic HAP concentration is greater than or equal to 20 parts per million by volume, and the 

total volatile organic compound emissions are greater than or equal to 33 kilograms per day for 

existing sources and 6.8 kilograms per day for new sources at the outlet of the final recovery 

device (if any) and prior to any control device and prior to discharge to the atmosphere. 

Group 1 storage vessel means a: 

(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 
Page 20 of 162 

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; a

(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 a

(iii) A storage vessel at a new source that has a design storage capacity greater than or equal to 

76 cubic meters and less than 151 cubic meters and stored-liquid maximum true vapor pressure 

greater than or equal to 77 kilopascals and annual average HAP liquid concentration greater than 

2 percent by weight total organic HAP. 

(2) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER]: 

(i) A storage vessel at an existing source that has a design capacity greater than or equal to 

151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater 

than or equal to 5.2 kilopascals (0.75 pounds per square inch) and annual average HAP 

liquid concentration greater than 4 percent by weight total organic HAP; 

(ii) A storage vessel at an existing source that has a design storage capacity greater than or 

equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) 

and stored-liquid maximum true vapor pressure greater than or equal to 13.1 kilopascals 

(1.9 pounds per square inch) and annual average HAP liquid concentration greater than 4 

percent by weight total organic HAP; 

(iii) A storage vessel at a new source that has a design storage capacity greater than or 

equal to 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure 

greater than or equal to 3.4 kilopascals (0.5 pounds per square inch) and annual average 

HAP liquid concentration greater than 2 percent by weight total organic HAP; or 

(iv) A storage vessel at a new source that has a design storage capacity greater than or 

equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) 

and 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 2 

percent by weight total organic HAP. 

Group 1 wastewater stream means a wastewater stream at a petroleum refinery with a total 

annual benzene loading of 10 megagrams per year or greater as calculated according to the 

procedures in 40 CFR 61.342 of subpart FF of part 61 that has a flow rate of 0.02 liters per 

minute or greater, a benzene concentration of 10 parts per million by weight or greater, and is not 

exempt from control requirements under the provisions of 40 CFR part 61, subpart FF. 
Page 21 of 162 

Group 2 gasoline loading rack means a gasoline loading rack classified under Standard 

Industrial Classification code 2911 that does not meet the definition of a Group 1 gasoline 

loading rack. 

Group 2 marine tank vessel means a marine tank vessel that does not meet the definition of a 

Group 1 marine tank vessel. 

Group 2 miscellaneous process vent means a miscellaneous process vent that does not meet the 

definition of a Group 1 miscellaneous process vent. 

Group 2 storage vessel means a storage vessel that does not meet the definition of a Group 1 

storage vessel. 

Group 2 wastewater stream means a wastewater stream that does not meet the definition of 

Group 1 wastewater stream. 

Halogenated vent stream or halogenated stream means a stream determined to have a mass 

rate of halogen atoms of 0.45 kilograms per hour or greater, determined by the procedures 

presented in §63.115(d)(2)(v). The following procedures may be used as alternatives to the 

procedures in §63.115(d)(2)(v)(A): 

(1) Process knowledge that halogen or hydrogen halides are present in a vent stream and 

that the vent stream is halogenated, or 

(2) Concentration of compounds containing halogen and hydrogen halides measured by 

Method 26 or 26A of part 60, Appendix A–8 of this chapter, or 

(3) Concentration of compounds containing hydrogen halides measured by Method 320 of 

Appendix A of this part. 

Halogens and hydrogen halides means hydrogen chloride (HCl), chlorine (Cl2), hydrogen 

bromide (HBr), bromine (Br2), and hydrogen fluoride (HF). 

Hazardous air pollutant or HAP means one of the chemicals listed in section 112(b) of the Clean 

Air Act. 

Heat exchange system means a device or collection of devices used to transfer heat from process 

fluids to water without intentional direct contact of the process fluid with the water (i.e., noncontact 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 closedloop recirculation systems, the heat exchange system consists of a cooling tower, all petroleum 

refinery process unit heat exchangers that are in organic HAP service, as defined in this subpart, 

serviced by that cooling tower, and all water lines to and from these petroleum refinery process 

unit heat exchangers. For once-through systems, the heat exchange system consists of all heat 

exchangers that are in organic HAP service, as defined in this subpart, servicing an individual 

petroleum refinery process unit and all water lines to and from these heat exchangers. Sample 
Page 22 of 162 

coolers or pump seal coolers are not considered heat exchangers for the purpose of this definition 

and are not part of the heat exchange system. Intentional direct contact with process fluids results 

in the formation of a wastewater. 

Heat exchanger exit line means the cooling water line from the exit of one or more heat 

exchangers (where cooling water leaves the heat exchangers) to either the entrance of the cooling 

tower return line or prior to exposure to the atmosphere, in, as an example, a once-through 

cooling system, whichever occurs first. 

Incinerator means an enclosed combustion device that is used for destroying organic 

compounds. Auxiliary fuel may be used to heat waste gas to combustion temperatures. Any 

energy recovery section present is not physically formed into one manufactured or assembled 

unit with the combustion section; rather, the energy recovery section is a separate section 

following the combustion section and the two are joined by ducts or connections carrying flue 

gas. 

In heavy liquid service means that the piece of equipment is not in gas/vapor service or in light 

liquid service. 

In light liquid service means that the piece of equipment contains a liquid that meets the 

conditions specified in §60.593(d) of part 60, subpart GGG. 

In organic hazardous air pollutant service or in organic HAP service means that a piece of 

equipment either contains or contacts a fluid (liquid or gas) that is at least 5 percent by weight of 

total organic HAP as determined according to the provisions of §63.180(d) of this part and table 

1 of this subpart. The provisions of §63.180(d) also specify how to determine that a piece of 

equipment is not in organic HAP service. 

Leakless valve means a valve that has no external actuating mechanism. 

Lower steam means the portion of assist steam piped to an exterior annular ring near the 

lower part of a flare tip, which then flows through tubes to the flare tip, and ultimately 

exits the tubes at the flare tip. 

Maximum true vapor pressure means the equilibrium partial pressure exerted by the stored liquid 

at the temperature equal to the highest calendar-month average of the liquid storage temperature 

for liquids stored above or below the ambient temperature or at the local maximum monthly 

average temperature as reported by the National Weather Service for liquids stored at the 

ambient temperature, as determined: 

(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. 
Page 23 of 162 

Miscellaneous process vent means a gas stream containing greater than 20 parts per million by 

volume organic HAP that is continuously or periodically discharged during normal operation 

offrom a petroleum refining process unit meeting the criteria specified in §63.640(a). 

Miscellaneous process vents include gas streams that are discharged directly to the atmosphere, 

gas streams that are routed to a control device prior to discharge to the atmosphere, or gas 

streams that are diverted through a product recovery device prior to control or discharge to the 

atmosphere. Miscellaneous process vents include vent streams from: caustic wash accumulators, 

distillation tower condensers/accumulators, flash/knockout drums, reactor vessels, scrubber 

overheads, stripper overheads, vacuum (pumps, steam) ejectors, hot wells, high point bleeds, 

wash tower overheads, water wash accumulators, blowdown condensers/accumulators, and 

delayed coker vents. Miscellaneous process vents do not include: 

(1) Gaseous streams routed to a fuel gas system, provided that on and after [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas from the fuel 

gas system are in compliance with §63.670; 

(2) Relief valve discharges regulated under §63.648; 

(3) Leaks from equipment regulated under §63.648; 

(4) [Reserved]Episodic or nonroutine releases such as those associated with startup, shutdown, 

malfunction, maintenance, depressuring, and catalyst transfer operations; 

(5) In situ sampling systems (onstream analyzers) until [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER]. After this date, these sampling systems will be included in the definition of 

miscellaneous process vents; 

(6) Catalytic cracking unit catalyst regeneration vents; 

(7) Catalytic reformer regeneration vents; 

(8) Sulfur plant vents; 

(9) Vents from control devices such as scrubbers, boilers, incinerators, and electrostatic 

precipitators applied to catalytic cracking unit catalyst regeneration vents, catalytic reformer 

regeneration vents, and sulfur plant vents; 

(10) Vents from any stripping operations applied to comply with the wastewater provisions of 

this subpart, subpart G of this part, or 40 CFR part 61, subpart FF; 

(11) Coking unit ventsEmissions associated with coke drum depressuring at or below a coke 

drum outlet pressure of 15 pounds per square inch gauge, deheading, draining, or delayed 

coking unit decoking (coke cutting) or pressure testing after decokingoperations; 
Page 24 of 162 

(12) Vents from storage vessels; 

(13) Emissions from wastewater collection and conveyance systems including, but not limited to, 

wastewater drains, sewer vents, and sump drains; and 

(14) Hydrogen production plant vents through which carbon dioxide is removed from process 

streams or through which steam condensate produced or treated within the hydrogen plant is 

degassed or deaerated. 

Net heating value means the energy released as heat when a compound undergoes complete 

combustion with oxygen to form gaseous carbon dioxide and gaseous water (also referred 

to as lower heating value). 

Operating permit means a permit required by 40 CFR parts 70 or 71. 

Organic hazardous air pollutant or organic HAP in this subpart, means any of the organic 

chemicals listed in table 1 of this subpart. 

Petroleum-based solvents means mixtures of aliphatic hydrocarbons or mixtures of one and two 

ring aromatic hydrocarbons. 

Perimeter assist air means the portion of assist air introduced at the perimeter of the flare 

tip or above the flare tip. Perimeter assist air includes air intentionally entrained in lower 

and upper steam. Perimeter assist air includes all assist air except premix assist air. 

Periodically discharged means discharges that are intermittent and associated with routine 

operations. Discharges associated with, maintenance activities, startups, shutdowns, 

malfunctions, or process upsets are not considered periodically discharged miscellaneous 

process vents and are therefore not regulated by the petroleum refinery miscellaneous process 

vent provisions. 

Petroleum refining process unit means a process unit used in an establishment primarily engaged 

in petroleum refining as defined in the Standard Industrial Classification code for petroleum 

refining (2911), and used primarily for the following: 

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

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

(2) Separating petroleum; or 

(3) Separating, cracking, reacting, or reforming intermediate petroleum streams. 

(4) Examples of such units include, but are not limited to, petroleum-based solvent units, 

alkylation units, catalytic hydrotreating, catalytic hydrorefining, catalytic hydrocracking, 

catalytic reforming, catalytic cracking, crude distillation, lube oil processing, hydrogen 
Page 25 of 162 

production, isomerization, polymerization, thermal processes, and blending, sweetening, and 

treating processes. Petroleum refining process units also include sulfur plants. 

Pilot gas means gas introduced into a flare tip that provides a flame to ignite the flare vent 

gas. 

Plant site means all contiguous or adjoining property that is under common control including 

properties that are separated only by a road or other public right-of-way. Common control 

includes properties that are owned, leased, or operated by the same entity, parent entity, 

subsidiary, or any combination thereof. 

Premix assist air means the portion of assist air that is introduced to the flare vent gas prior 

to the flare tip. Premix assist air also includes any air intentionally entrained in center 

steam.

Primary fuel means the fuel that provides the principal heat input (i.e., more than 50 percent) to 

the device. To be considered primary, the fuel must be able to sustain operation without the 

addition of other fuels. 

Process heater means an enclosed combustion device that primarily transfers heat liberated by 

burning fuel directly to process streams or to heat transfer liquids other than water. 

Process unit means the equipment assembled and connected by pipes or ducts to process raw 

and/or intermediate materials and to manufacture an intended product. A process unit includes 

any associated storage vessels. For the purpose of this subpart, process unit includes, but is not 

limited to, chemical manufacturing process units and petroleum refining process units. 

Process unit shutdown means a work practice or operational procedure that stops production 

from a process unit or part of a process unit during which it is technically feasible to clear 

process material from a process unit or part of a process unit consistent with safety constraints 

and during which repairs can be accomplished. An unscheduled work practice or operational 

procedure that stops production from a process unit or part of a process unit for less than 24 

hours is not considered a process unit shutdown. An unscheduled work practice or operational 

procedure that would stop production from a process unit or part of a process unit for a shorter 

period of time than would be required to clear the process unit or part of the process unit of 

materials and start up the unit, or would result in greater emissions than delay of repair of leaking 

components until the next scheduled process unit shutdown is not considered a process unit 

shutdown. The use of spare equipment and technically feasible bypassing of equipment without 

stopping production are not considered process unit shutdowns. 

Recovery device means an individual unit of equipment capable of and used for the purpose of 

recovering chemicals for use, reuse, or sale. Recovery devices include, but are not limited to, 

absorbers, carbon adsorbers, and condensers. 
Page 26 of 162 

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. 

Reference control technology for miscellaneous process vents means a combustion device used 

to reduce organic HAP emissions by 98 percent, or to an outlet concentration of 20 parts per 

million by volume. 

Reference control technology for storage vessels means either: 

(1) For Group 1 storage vessels complying with §63.660: 

(i) An internal floating roof meeting the specifications of §§63.1063(a)(1)(i) and (b); 

(ii) An external floating roof meeting the specifications of §63.1063(a)(1)(ii), (a)(2), and (b); 

(iii) An external floating roof converted to an internal floating roof meeting the 

specifications of §63.1063(a)(1)(i) and (b); or 

(iv) A closed-vent system to a control device that reduces organic HAP emissions by 95 

percent, or to an outlet concentration of 20 parts per million by volume (ppmv). 

(v) For purposes of emissions averaging, these four technologies are considered equivalent. 

(2) For all other storage vessels: 

(i) An internal floating roof meeting the specifications of §63.119(b) of subpart G except for 

§63.119 (b)(5) and (b)(6); 

(2ii) An external floating roof meeting the specifications of §63.119(c) of subpart G except for 

§63.119(c)(2); 

(3iii) 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 

(4iv) 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. 

(5v) 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; 
Page 27 of 162 

(2) A treatment process that achieves the emission reductions specified in table 7 of this subpart 

for each individual HAP present in the wastewater stream or is a steam stripper that meets the 

specifications in §63.138(g) of subpart G of this part; and 

(3) A control device to reduce by 95 percent (or to an outlet concentration of 20 parts per million 

by volume for combustion devices) the organic HAP emissions in the vapor streams vented from 

treatment processes (including the steam stripper described in paragraph (2) of this definition) 

managing wastewater. 

Refinery fuel gas means a gaseous mixture of methane, light hydrocarbons, hydrogen, and other 

miscellaneous species (nitrogen, carbon dioxide, hydrogen sulfide, etc.) that is produced in the 

refining of crude oil and/or petrochemical processes and that is separated for use as a fuel in 

boilers and process heaters throughout the refinery. 

Relief valve means a valve used only to release an unplanned, nonroutine discharge. A relief 

valve discharge can result from an operator error, a malfunction such as a power failure or 

equipment failure, or other unexpected cause that requires immediate venting of gas from 

process equipment in order to avoid safety hazards or equipment damage. 

Research and development facility means laboratory and pilot plant operations whose primary 

purpose is to conduct research and development into new processes and products, where the 

operations are under the close supervision of technically trained personnel, and is not engaged in 

the manufacture of products for commercial sale, except in a de minimis manner. 

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; 

(4) Bottoms receiver tanks; or 
Page 28 of 162 

(5) Wastewater storage tanks. Wastewater storage tanks are covered under the wastewater 

provisions. 

Temperature monitoring device means a unit of equipment used to monitor temperature and 

having an accuracy of ±1 percent of the temperature being monitored expressed in degrees 

Celsius or ±0.5 °C, whichever is greater. 

Total annual benzene means the total amount of benzene in waste streams at a facility on an 

annual basis as determined in §61.342 of 40 CFR part 61, subpart FF. 

Total organic compounds or TOC, as used in this subpart, means those compounds excluding 

methane and ethane measured according to the procedures of Method 18 of 40 CFR part 60, 

appendix A. Method 25A may be used alone or in combination with Method 18 to measure TOC 

as provided in §63.645 of this subpart. 

Total steam means the total of all steam that is supplied to a flare and includes, but is not 

limited to, lower steam, center steam and upper steam. 

Upper steam means the portion of assist steam introduced via nozzles located on the 

exterior perimeter of the upper end of the flare tip. 

Wastewater means water or wastewater that, during production or processing, comes into direct 

contact with or results from the production or use of any raw material, intermediate product, 

finished product, byproduct, or waste product and is discharged into any individual drain system. 

Examples are feed tank drawdown; water formed during a chemical reaction or used as a 

reactant; water used to wash impurities from organic products or reactants; water used to cool or 

quench organic vapor streams through direct contact; and condensed steam from jet ejector 

systems pulling vacuum on vessels containing organics. 

§ 63.642 General standards. 

(a) Each owner or operator of a source subject to this subpart is required to apply for a part 70 or 

part 71 operating permit from the appropriate permitting authority. If the EPA has approved a 

State operating permit program under part 70, the permit shall be obtained from the State 

authority. If the State operating permit program has not been approved, the source shall apply to 

the EPA Regional Office pursuant to part 71. 

(b) The emission standards set forth in this subpart shall apply at all times.[Reserved]

(c) Table 6 of this subpart specifies the provisions of subpart A of this part that apply and those 

that do not apply to owners and operators of sources subject to this subpart. 

(d) Initial performance tests and initial compliance determinations shall be required only as 

specified in this subpart. 
Page 29 of 162 

(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 according to the provisions of §63.7(e) except that 

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) 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.All applicable records shall be maintained as specified in §63.655(i). 

 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, floppy disk, magnetic tape, or microfiche. 

(f) All reports required under this subpart shall be sent to the Administrator at the addresses 

listed in §63.13 of subpart A of this part. If acceptable to both the Administrator and the owner 

or operator of a source, reports may be submitted on electronic media. 

(g) The owner or operator of an existing source subject to the requirements of this subpart shall 

control emissions of organic HAP’s to the level represented by the following equation: 

  

      

 

       

2 1C 2

A 1 2 1 2 1C 2 1

EMV EWW EWW

E 0.02 EPV EPV 0.05 ES ES EGLR EGLR (R) EMV 

where: 

EA = Emission rate, megagrams per year, allowed for the source. 
Page 30 of 162 

0.02Σ EPV1 = Sum of the residual emissions, megagrams per year, from all Group 1 

miscellaneous process vents, as defined in §63.641. 

Σ EPV2 = Sum of the emissions, megagrams per year, from all Group 2 process vents, as defined 

in §63.641. 

0.05Σ ES1 = Sum of the residual emissions, megagrams per year, from all Group 1 storage 

vessels, as defined in §63.641. 

Σ ES2 = Sum of the emissions, megagrams per year, from all Group 2 storage vessels, as defined 

in §63.641. 

Σ EGLR1C = Sum of the residual emissions, megagrams per year, from all Group 1 gasoline 

loading racks, as defined in §63.641. 

Σ EGLR2 = Sum of the emissions, megagrams per year, from all Group 2 gasoline loading racks, 

as defined in §63.641. 

(R)Σ EMV1 = Sum of the residual emissions megagrams per year, from all Group 1 marine tank 

vessels, as defined in §63.641. 

R = 0.03 for existing sources, 0.02 for new sources. 

Σ EMV2 = Sum of the emissions, megagrams per year from all Group 2 marine tank vessels, as 

defined in §63.641. 

Σ EWW1C = Sum of the residual emissions from all Group 1 wastewater streams, as defined in 

§63.641. This term is calculated for each Group 1 stream according to the equation for EWWic in 

§63.652(h)(6). 

Σ EWW2 = Sum of emissions from all Group 2 wastewater streams, as defined in §63.641. 

The emissions level represented by this equation is dependent on the collection of emission 

points in the source. The level is not fixed and can change as the emissions from each emission 

point change or as the number of emission points in the source changes. 

(h) The owner or operator of a new source subject to the requirements of this subpart shall 

control emissions of organic HAP’s to the level represented by the equation in paragraph (g) of 

this section. 

(i) The owner or operator of an existing source shall demonstrate compliance with the emission 

standard in paragraph (g) of this section by following the procedures specified in paragraph (k) 

of this section for all emission points, or by following the emissions averaging compliance 

approach specified in paragraph (l) of this section for specified emission points and the 

procedures specified in paragraph (k)(1) of this section for all other emission points within the 

source. 
Page 31 of 162 

(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. 

(k) The owner or operator of an existing source may comply, and the owner or operator of a new 

source shall comply, with the miscellaneous process ventapplicable provisions in §§63.643 

through 63.645, the storage vessel provisions in §63.646, the wastewater provisions in § or 

63.660, 63.647, the gasoline loading rack provisions in §63.650, and the marine tank vessel 

loading operation provisions in §63.651 of this subpart., 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 (l)(2) of this section. 

(1) Calculate emission debits and credits for those emission points involved in the emissions 

average according to the procedures specified in §63.652; and 

(2) Comply with the requirements of §§63.648 and/or 63.649 or 63.661, 63.654, 63.652, 63.653, 

and 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable. 

(m) A State may restrict the owner or operator of an existing source to using only the procedures 

in paragraph (k) of this section to comply with the emission standard in paragraph (g) of this 

section. Such a restriction would preclude the source from using an emissions averaging 

compliance approach. 

(n) At all times, the owner or operator must operate and maintain any affected source, 

including associated air pollution control equipment and monitoring equipment, in a 

manner consistent with safety and good air pollution control practices for minimizing 

emissions. The general duty to minimize emissions does not require the owner operator to 

make any further efforts to reduce emissions if levels required by the applicable standard 

have been achieved. Determination of whether a source is operating in compliance with 

operation and maintenance requirements will be based on information available to the 

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

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

inspection of the source. 
Page 32 of 162 

§ 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 that meets. On and after [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements 

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

THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall 

meet the requirements of §63.11(b) of subpart A of this partor the requirements of §63.670. 

(2) Reduce emissions of organic HAP’s, using a control device, by 98 weight-percent or to a 

concentration of 20 parts per million by volume, on a dry basis, corrected to 3 percent oxygen, 

whichever is less stringent. Compliance can be determined by measuring either organic HAP’s or 

TOC’s using the procedures in §63.645. 

(b) If a boiler or process heater is used to comply with the percentage of reduction requirement 

or concentration limit specified in paragraph (a)(2) of this section, then the vent stream shall be 

introduced into the flame zone of such a device, or in a location such that the required percent 

reduction or concentration is achieved. Testing and monitoring is required only as specified in 

§§63.644(a) and 63.645 of this subpart. 

§ 63.644 Monitoring provisions for miscellaneous process vents. 

(a) Except as provided in paragraph (b) of this section, each owner or operator of a Group 1 

miscellaneous process vent that uses a combustion device to comply with the requirements in 

§63.643(a) shall install the monitoring equipment specified in paragraph (a)(1), (a)(2), (a)(3), or 

(a)(4) of this section, depending on the type of combustion device used. All monitoring 

equipment shall be installed, calibrated, maintained, and operated according to manufacturer’s 

specifications or other written procedures that provide adequate assurance that the equipment 

will monitor accurately and must meet the applicable minimum accuracy, calibration and 

quality control requirements specified in table 13 of this subpart. 

(1) Where an incinerator is used, a temperature monitoring device equipped with a continuous 

recorder is required. 

(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 
Page 33 of 162 

REGISTER], a device (including but not limited to a thermocouple, an ultraviolet beam sensor, 

or an infrared sensor) capable of continuously detecting the presence of a pilot flame is required, 

or the requirements of §63.670 shall be met. Where a flare is used on and after [THE 

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

AMENDMENTS IN THE FEDERAL REGISTER], the requirements of §63.670 shall be 

met. 

(3) Any boiler or process heater with a design heat input capacity greater than or equal to 44 

megawatt or any boiler or process heater in which all vent streams are introduced into the flame 

zone is exempt from monitoring. 

(4) Any boiler or process heater less than 44 megawatts design heat capacity where the vent 

stream is not introduced into the flame zone is required to use a temperature monitoring device in 

the firebox equipped with a continuous recorder. 

(b) An owner or operator of a Group 1 miscellaneous process vent may request approval to 

monitor parameters other than those listed in paragraph (a) of this section. The request shall be 

submitted according to the procedures specified in §63.655(h). Approval shall be requested if the 

owner or operator: 

(1) Uses a control device other than an incinerator, boiler, process heater, or flare; or 

(2) Uses one of the control devices listed in paragraph (a) of this section, but seeks to monitor a 

parameter other than those specified in paragraph (a) of this section. 

(c) The owner or operator of a Group 1 miscellaneous process vent using a vent system that 

contains bypass lines that could divert a vent stream away from the control device used to 

comply with paragraph (a) of this section shall comply with either paragraph (c)(1) or (c)(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, analyzer vents, open-ended valves or lines, pressure relief valves needed for safety 

reasons, and equipment subject to §63.648 are not subject to this paragraph. 

(1) Install, operate, calibrate, and maintain, and operate a continuous parameter monitoring 

system for flow, as specified in paragraphs (c)(1)(i) through (iii) of this section indicator that 

determines whether a vent stream flow is present at least once every hour. 

(i) Install a continuous parameter monitoring system for Records shall be generated as 

specified in §63.655(h) and (i). The flow indicator shall be installed at the entrance to any bypass 

line that could divert the vent stream away from the control device to the atmosphere; or. The 

continuous parameter monitoring system must record the volume of the gas stream that 

bypassed the control device and must meet the applicable minimum accuracy, calibration 

and quality control requirements specified in table 13 of this subpart. 
Page 34 of 162 

(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 closednon-diverting position with a car-seal or a lockand-key type configuration. A visual inspection of the seal or closure mechanism shall be 

performed at least once every month to ensure that the valve is maintained in the closednondiverting position and that the vent stream is not diverted through the bypass line. 

(d) The owner or operator shall establish a range that ensures compliance with the emissions 

standard for each parameter monitored under paragraphs (a) and (b) of this section. In order to 

establish the range, the information required in §63.655(f)(3) shall be submitted in the 

Notification of Compliance Status report. 

(e) Each owner or operator of a control device subject to the monitoring provisions of this 

section shall operate the control device in a manner consistent with the minimum and/or 

maximum operating parameter value or procedure required to be monitored under paragraphs (a) 

and (b) of this section. Operation of the control device in a manner that constitutes a period of 

excess emissions, as defined in §63.655(g)(6), or failure to perform procedures required by this 

section shall constitute a violation of the applicable emission standard of this subpart. 

§ 63.645 Test methods and procedures for miscellaneous process vents. 

(a) To demonstrate compliance with §63.643, an owner or operator shall follow §63.116 except 

for §63.116 (a)(1), (d) and (e) of subpart G of this part except as provided in paragraphs (b) 

through (d) and paragraph (i) of this section. 

(b) All references to §63.113(a)(1) or (a)(2) in §63.116 of subpart G of this part shall be replaced 

with §63.643(a)(1) or (a)(2), respectively. 

(c) In §63.116(c)(4)(ii)(C) of subpart G of this part, organic HAP’s in the list of HAP’s in table 1 

of this subpart shall be considered instead of the organic HAP’s in table 2 of subpart F of this 

part. 

(d) All references to §63.116(b)(1) or (b)(2) shall be replaced with paragraphs (d)(1) and (d)(2) 

of this section, respectively. 

(1) Any boiler or process heater with a design heat input capacity of 44 megawatts or greater. 

(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 
Page 35 of 162 

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, aAppendix A-1, as appropriate, shall be used for 

selection of the sampling site. For vents smaller than 0.10 meter in diameter, sample at the 

center of the vent. 

(2) No traverse site selection method is needed for vents smaller than 0.10 meter in diameter. 

(f) Except as provided in paragraph (g) of this section, an owner or operator seeking to 

demonstrate that a process vent TOC mass flow rate is less than 33 kilograms per day for an 

existing source or less than 6.8 kilograms per day for a new source in accordance with the Group 

2 process vent definition of this subpart shall determine the TOC mass flow rate by the following 

procedures: 

(1) The sampling site shall be selected as specified in paragraph (e) of this section. 

(2) The gas volumetric flow rate shall be determined using Methods 2, 2A, 2C, 2D, or 2D2F of 

40 CFR part 60, aAppendix A-1 or Method 2G of 40 CFR part 60, Appendix A-2, as 

appropriate. 

(3) Method 18 or Method 25A of 40 CFR part 60, appendix A shall be used to measure 

concentration; alternatively, any other method or data that has been validated according to the 

protocol in Method 301 of appendix A of this part may be used. If Method 25A is used, and the 

TOC mass flow rate calculated from the Method 25A measurement is greater than or equal to 33 

kilograms per day for an existing source or 6.8 kilograms per day for a new source, Method 18 

may be used to determine any non-VOC hydrocarbons that may be deducted to calculate the 

TOC (minus non-VOC hydrocarbons) concentration and mass flow rate. The following 

procedures shall be used to calculate parts per million by volume concentration: 

(i) The minimum sampling time for each run shall be 1 hour in which either an integrated sample 

or four grab samples shall be taken. If grab sampling is used, then the samples shall be taken at 

approximately equal intervals in time, such as 15-minute intervals during the run. 

(ii) The TOC concentration (CTOC) is the sum of the concentrations of the individual components 

and shall be computed for each run using the following equation if Method 18 is used: 

X

C

C

x

i

n

j

ji

TOC

    















 1 1

where: 

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

volume. 
Page 36 of 162 

Cji = Concentration of sample component j of the sample i, dry basis, parts per million by 

volume. 

n = Number of components in the sample. 

x = Number of samples in the sample run. 

(4) The emission rate of TOC (minus methane and ethane) (ETOC) shall be calculated using the 

following equation if Method 18 is used: 

s

n

j

E K2 CjM jQ



 



  1

where: 

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

K2 = Constant, 5.986 × 10−5

 (parts per million)−1 (gram-mole per standard cubic meter) 

(kilogram per gram) (minute per day), where the standard temperature (standard cubic meter) is 

at 20 °C. 

Cj = Concentration on a dry basis of organic compound j in parts per million as measured by 

Method 18 of 40 CFR part 60, appendix A, as indicated in paragraph (f)(3) of this section. Cj

includes all organic compounds measured minus methane and ethane. 

Mj = Molecular weight of organic compound j, gram per gram-mole. 

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

(5) If Method 25A is used, the emission rate of TOC (ETOC) shall be calculated using the 

following equation: 

ETOC  K2CTOCMQs

where: 

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

K2 =Constant, 5.986×10–5 (parts per million)−1 (gram-mole per standard cubic meter) (kilogram 

per gram)(minute per day), where the standard temperature (standard cubic meter) is at 20 °C. 

CTOC = Concentration of TOC on a dry basis in parts per million volume as measured by Method 

25A of 40 CFR part 60, appendix A, as indicated in paragraph (f)(3) of this section. 

M = Molecular weight of organic compound used to express units of CTOC, gram per gram-mole. 
Page 37 of 162 

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

(g) Engineering assessment may be used to determine the TOC emission rate for the 

representative operating condition expected to yield the highest daily emission rate. 

(1) Engineering assessment includes, but is not limited to, the following: 

(i) Previous test results provided the tests are representative of current operating practices at the 

process unit. 

(ii) Bench-scale or pilot-scale test data representative of the process under representative 

operating conditions. 

(iii) TOC emission rate specified or implied within a permit limit applicable to the process vent. 

(iv) Design analysis based on accepted chemical engineering principles, measurable process 

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

but are not limited to: 

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

concentrations; 

(B) Estimation of maximum flow rate based on physical equipment design such as pump or 

blower capacities; and 

(C) Estimation of TOC concentrations based on saturation conditions. 

(v) All data, assumptions, and procedures used in the engineering assessment shall be 

documented. 

(h) The owner or operator of a Group 2 process vent shall recalculate the TOC emission rate for 

each process vent, as necessary, whenever process changes are made to determine whether the 

vent is in Group 1 or Group 2. Examples of process changes include, but are not limited to, 

changes in production capacity, production rate, or catalyst type, or whenever there is 

replacement, removal, or addition of recovery equipment. For purposes of this paragraph, 

process changes do not include: process upsets; unintentional, temporary process changes; and 

changes that are within the range on which the original calculation was based. 

(1) The TOC emission rate shall be recalculated based on measurements of vent stream flow rate 

and TOC as specified in paragraphs (e) and (f) of this section, as applicable, or on best 

engineering assessment of the effects of the change. Engineering assessments shall meet the 

specifications in paragraph (g) of this section. 

(2) Where the recalculated TOC emission rate is greater than 33 kilograms per day for an 

existing source or greater than 6.8 kilograms per day for a new source, the owner or operator 
Page 38 of 162 

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, Method 18 of 40 CFR part 60, appendix Aan appropriate method (based on the type 

of liquid stored) as published by EPA or a consensus-based standards organization shall be 

used. Consensus-based standards organizations include, but are not limited to, the 

following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West 

Conshohocken, Pennsylvania 19428–B2959, (800) 262–1373, http://www.astm.org), the 

American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, 

DC 20036, (202) 293–8020, http://www.ansi.org), the American Gas Association (AGA, 400 

North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824–7000, 

http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park 

Avenue, New York, NY 10016–5990, (800) 843–2763, http://www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005–4070, (202) 682–

8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 

Travis Street, Suite 1675, Houston, TX 77002, (713) 356–0060, http://www.naesb.org).

(c) The following paragraphs do not apply to storage vessels at existing sources subject to this 

subpart: §63.119 (b)(5), (b)(6), (c)(2), and (d)(2). 

(d) References shall apply as specified in paragraphs (d)(1) through (d)(10) of this section. 
Page 39 of 162 

(1) All references to §63.100(k) of subpart F of this part (or the schedule provisions and the 

compliance date) shall be replaced with §63.640(h), 

(2) All references to April 22, 1994 shall be replaced with August 18, 1995. 

(3) All references to December 31, 1992 shall be replaced with July 15, 1994. 

(4) All references to the compliance dates specified in §63.100 of subpart F shall be replaced 

with §63.640 (h) through (m). 

(5) All references to §63.150 in §63.119 of subpart G of this part shall be replaced with §63.652. 

(6) All references to §63.113(a)(2) of subpart G shall be replaced with §63.643(a)(2) of this 

subpart. 

(7) All references to §63.126(b)(1) of subpart G shall be replaced with §63.422(b) of subpart R 

of this part. 

(8) All references to §63.128(a) of subpart G shall be replaced with §63.425, paragraphs (a) 

through (c) and (e) through (h) of subpart R of this part. 

(9) All references to §63.139(d)(1) in §63.120(d)(1)(ii) of subpart G are not applicable. For 

sources subject to this subpart, such references shall mean that 40 CFR 61.355 is applicable. 

(10) All references to §63.139(c) in §63.120(d)(1)(ii) of subpart G are not applicable. For 

sources subject to this subpart, such references shall mean that §63.647 of this subpart is 

applicable. 

(e) When complying with the inspection requirements of §63.120 of subpart G of this part, 

owners and operators of storage vessels at existing sources subject to this subpart are not 

required to comply with the provisions for gaskets, slotted membranes, and sleeve seals. 

(f) The following paragraphs (f)(1), (f)(2), and (f)(3) of this section apply to Group 1 storage 

vessels at existing sources: 

(1) If a cover or lid is installed on an opening on a floating roof, the cover or lid shall remain 

closed except when the cover or lid must be open for access. 

(2) Rim space vents are to be set to open only when the floating roof is not floating or when the 

pressure beneath the rim seal exceeds the manufacturer’s recommended setting. 

(3) Automatic bleeder vents are to be closed at all times when the roof is floating except when 

the roof is being floated off or is being landed on the roof leg supports. 

(g) Failure to perform inspections and monitoring required by this section shall constitute a 

violation of the applicable standard of this subpart. 
Page 40 of 162 

(h) References in §§63.119 through 63.121 to §63.122(g)(1), §63.151, and references to initial 

notification requirements do not apply. 

(i) References to the Implementation Plan in §63.120, paragraphs (d)(2) and (d)(3)(i) shall be 

replaced with the Notification of Compliance Status report. 

(j) References to the Notification of Compliance Status report in §63.152(b) mean the 

Notification of Compliance Status required by §63.655(f). 

(k) References to the Periodic Reports in §63.152(c) mean the Periodic Report required by 

§63.655(g). 

(l) The State or local permitting authority can waive the notification requirements of 

§§63.120(a)(5), 63.120(a)(6), 63.120(b)(10)(ii), and 63.120(b)(10)(iii) for all or some storage 

vessels at petroleum refineries subject to this subpart. The State or local permitting authority may 

also grant permission to refill storage vessels sooner than 30 days after submitting the 

notifications in §63.120(a)(6) or §63.120(b)(10)(iii) for all storage vessels at a refinery or for 

individual storage vessels on a case-by-case basis. 

§ 63.647 Wastewater provisions. 

(a) Except as provided in paragraphs (b) and (c) of this section, each owner or operator of a 

Group 1 wastewater stream shall comply with the requirements of §§61.340 through 61.355 of 

40 CFR part 61, subpart FFthis chapter for each process wastewater stream that meets the 

definition in §63.641. 

(b) As used in this section, all terms not defined in §63.641 shall have the meaning given them in 

the Clean Air Act or in 40 CFR part 61, subpart FF, §61.341. 

(c) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the applicable 

requirements of part 61, subpart FF of this chapter, or the requirements of §63.670. 

(d) Each owner or operator required under subpart FF of 40 CFR part 61 to perform periodic 

measurement of benzene concentration in wastewater, or to monitor process or control device 

operating parameters shall operate in a manner consistent with the minimum or maximum (as 

appropriate) permitted concentration or operating parameter values. Operation of the process, 

treatment unit, or control device resulting in a measured concentration or operating parameter 

value outside the permitted limits shall constitute a violation of the emission standards. Failure to 

perform required leak monitoring for closed vent systems and control devices or failure to repair 

leaks within the time period specified in subpart FF of 40 CFR part 61 shall constitute a violation 

of the standard. 
Page 41 of 162 

§ 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 40 CFR part 60, subpart VV of this chapter and paragraph (b) of 

this section except as provided in paragraphs (a)(1), (a)(2), and (c) through (i) of this section. 

Each owner or operator of a new source subject to the provisions of this subpart shall comply 

with subpart H of this part except as provided in paragraphs (c) through (i) of this section. As an 

alternative to the monitoring requirements of part 60, subpart VV of this chapter or 

subpart H of this part, as applicable, the owner or operator may elect to monitor 

equipment leaks following the provisions in §63.661.

(1) For purposes of compliance with this section, the provisions of 40 CFR part 60, subpart VV 

apply only to equipment in organic HAP service, as defined in §63.641 of this subpart. 

(2) Calculation of percentage leaking equipment components for subpart VV of 40 CFR part 60 

may be done on a process unit basis or a sourcewide basis. Once the owner or operator has 

decided, all subsequent calculations shall be on the same basis unless a permit change is made. 

(3) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of complying with the 

requirements of §60.482-6(a)(2) of this chapter, the term “seal” or “sealed” means 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. 

(4) 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. 

(1) Monitoring data must meet the test methods and procedures specified in §60.485(b) of 40 

CFR part 60, subpart VV or §63.180(b)(1) through (b)(5) of subpart H of this part except for 

minor departures. 

(2) Departures from the criteria specified in §60.485(b) of 40 CFR part 60 subpart VV or 

§63.180(b)(1) through (b)(5) of subpart H of this part or from the monitoring frequency specified 

in subpart VV or in paragraph (c) of this section (such as every 6 weeks instead of monthly or 

quarterly) are minor and do not significantly affect the quality of the data. An example of a 
Page 42 of 162 

minor departure is monitoring at a slightly different frequency (such as every 6 weeks instead of 

monthly or quarterly). Failure to use a calibrated instrument is not considered a minor departure. 

(c) In lieu of complying with the existing source provisions of paragraph (a) in this section, an 

owner or operator may elect to comply with the requirements of §§63.161 through 63.169, 

63.171, 63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 of subpart H of this part except as 

provided in paragraphs (c)(1) through (c)(1012) and (e) through (i) of this section. 

(1) The instrument readings that define a leak for light liquid pumps subject to §63.163 of 

subpart H of this part and gas/vapor and light liquid valves subject to §63.168 of subpart H of 

this part are specified in table 2 of this subpart. 

(2) In phase III of the valve standard, the owner or operator may monitor valves for leaks as 

specified in paragraphs (c)(2)(i) or (c)(2)(ii) of this section. 

(i) If the owner or operator does not elect to monitor connectors, then the owner or operator shall 

monitor valves according to the frequency specified in table 8 of this subpart. 

(ii) If an owner or operator elects to monitor connectors according to the provisions of §63.649, 

paragraphs (b), (c), or (d), then the owner or operator shall monitor valves at the frequencies 

specified in table 9 of this subpart. If an owner or operator elects to comply with §63.649, the 

owner or operator cannot also elect to comply with §63.661.

(3) The owner or operator shall decide no later than the first required monitoring period after the 

phase I compliance date specified in §63.640(h) whether to calculate the percentage leaking 

valves on a process unit basis or on a sourcewide basis. Once the owner or operator has decided, 

all subsequent calculations shall be on the same basis unless a permit change is made. 

(4) The owner or operator shall decide no later than the first monitoring period after the phase III 

compliance date specified in §63.640(h) whether to monitor connectors according to the 

provisions in §63.649, paragraphs (b), (c), or (d). 

(5) Connectors in gas/vapor service or light liquid service are subject to the requirements for 

connectors in heavy liquid service in §63.169 of subpart H of this part (except for the agitator 

provisions). The leak definition for valves, connectors, and instrumentation systems subject to 

§63.169 is 1,000 parts per million. 

(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. 
Page 43 of 162 

(8) An owner or operator may make the election described in paragraphs (c)(3) and (c)(4) of this 

section at any time except that any election to change after the initial election shall be treated as a 

permit modification according to the terms of part 70 of this chapter. 

(9) When complying with the requirements of §63.168(e)(3)(i), non-repairable valves shall be 

included in the calculation of percent leaking valves the first time the valve is identified as 

leaking and non-repairable. Otherwise, a number of non-repairable valves up to a maximum of 1 

percent per year of the total number of valves in organic HAP service up to a maximum of 3 

percent may be excluded from calculation of percent leaking valves for subsequent monitoring 

periods. When the number of non-repairable valves exceeds 3 percent of the total number of 

valves in organic HAP service, the number of non-repairable valves exceeding 3 percent of the 

total number shall be included in the calculation of percent leaking valves. 

(10) If in phase III of the valve standard any valve is designated as being leakless, the owner or 

operator has the option of following the provisions of 40 CFR 60.482–7(f). If an owner or 

operator chooses to comply with the provisions of 40 CFR 60.482–7(f), the valve is exempt from 

the valve monitoring provisions of §63.168 of subpart H of this part. 

(11) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of complying with the 

requirements of §63.167(a)(2), the term “seal” or “sealed” means that instrument 

monitoring of the open-ended valve or line conducted according to the method specified in 

§63.180(b) and, as applicable, §63.180(c) of this chapter indicates no readings of 500 parts 

per million or greater. 

(12) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the applicable 

requirements of §§63.172 and 63.180, or the requirements of §63.670. 

(d) Upon startup of new sources, the owner or operator shall comply with §63.163(a)(1)(ii) of 

subpart H of this part for light liquid pumps and §63.168(a)(1)(ii) of subpart H of this part for 

gas/vapor and light liquid valves. 

(e) For reciprocating pumps in heavy liquid service and agitators in heavy liquid service, owners 

and operators are not required to comply with the requirements in §63.169 of subpart H of this 

part. 

(f) Reciprocating pumps in light liquid service are exempt from §§63.163 and 60.482 if recasting 

the distance piece or reciprocating pump replacement is required. 

(g) Compressors in hydrogen service are exempt from the requirements of paragraphs (a) and (c) 

of this section if an owner or operator demonstrates that a compressor is in hydrogen service. 
Page 44 of 162 

(1) Each compressor is presumed not to be in hydrogen service unless an owner or operator 

demonstrates that the piece of equipment is in hydrogen service. 

(2) For a piece of equipment to be considered in hydrogen service, it must be determined that the 

percentage hydrogen content can be reasonably expected always to exceed 50 percent by 

volume. 

(i) For purposes of determining the percentage hydrogen content in the process fluid that is 

contained in or contacts a compressor, the owner or operator shall use either: 

(A) Procedures that conform to those specified in §60.593(b)(2) of 40 part 60, subpart GGG. 

(B) Engineering judgment to demonstrate that the percentage content exceeds 50 percent by 

volume, provided the engineering judgment demonstrates that the content clearly exceeds 50 

percent by volume. 

(1) When an owner or operator and the Administrator do not agree on whether a piece of 

equipment is in hydrogen service, the procedures in paragraph (g)(2)(i)(A) of this section shall 

be used to resolve the disagreement. 

(2) If an owner or operator determines that a piece of equipment is in hydrogen service, the 

determination can be revised only by following the procedures in paragraph (g)(2)(i)(A) of this 

section. 

(h) Each owner or operator of a source subject to the provisions of this subpart must maintain all 

records for a minimum of 5 years. 

(i) Reciprocating compressors are exempt from seal requirements if recasting the distance piece 

or compressor replacement is required. 

(j) Except as specified in paragraph (j)(4) of this section, the owner or operator must 

comply with the requirements specified in paragraphs (j)(1) and (2) of this section for relief 

valves in organic HAP gas or vapor service instead of the pressure relief device 

requirements of §60.482-4 or §63.165, as applicable. Except as specified in paragraph (j)(4) 

of this section, the owner or operator must also comply with the requirements specified in 

paragraph (j)(3) of this section for all relief valves in organic HAP service. 

(1) Operating requirements. Except during a pressure release, operate each relief valve in 

organic HAP gas or vapor service with an instrument reading of less than 500 ppm above 

background as detected by Method 21 of 40 CFR part 60, Appendix A-7. 

(2) Pressure release requirements. For relief valves in organic HAP gas or vapor service, the 

owner or operator must comply with either paragraph (j)(2)(i) or (ii) of this section 

following a pressure release. 
Page 45 of 162 

(i) If the relief valve does not consist of or include a rupture disk, conduct instrument 

monitoring, as specified in §60.485(b) or §63.180(c), as applicable, no later than 5 calendar 

days after the relief valve returns to organic HAP gas or vapor service following a pressure 

release to verify that the relief valve is operating with an instrument reading of less than 

500 ppm. 

(ii) If the relief valve consists of or includes a rupture disk, install a replacement disk as 

soon as practicable after a pressure release, but no later than 5 calendar days after the 

pressure release. The owner or operator must also conduct instrument monitoring, as 

specified in §60.485(b) or §63.180(c), as applicable, no later than 5 calendar days after the 

relief valve returns to organic HAP gas or vapor service following a pressure release to 

verify that the relief valve is operating with an instrument reading of less than 500 ppm. 

(3) Pressure release management. Except as specified in paragraph (j)(4) of this section, 

emissions of organic HAP may not be discharged to the atmosphere from relief valves in 

organic HAP service, and on or before [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the owner or operator shall comply with the requirements specified in 

paragraphs (j)(3)(i) and (ii) of this section for all relief valves in organic HAP service. 

(i) The owner or operator must equip each relief valve in organic HAP service with a 

device(s) or use a monitoring system that is capable of: 1) identifying the pressure release; 

2) recording the time and duration of each pressure release; and 3) notifying operators 

immediately that a pressure release is occurring. The device or monitoring system may be 

either specific to the pressure relief device itself or may be associated with the process 

system or piping, sufficient to indicate a pressure release to the atmosphere. Examples of 

these types of devices and systems include, but are not limited to, a rupture disk indicator, 

magnetic sensor, motion detector on the pressure relief valve stem, flow monitor, or 

pressure monitor. 

(ii) If any relief valve in organic HAP service vents or releases to atmosphere as a result of 

a pressure release event, the owner or operator must calculate the quantity of organic HAP 

released during each pressure release event and report this quantity as required in 

§63.655(g)(10)(iii). Calculations may be based on data from the relief valve monitoring 

alone or in combination with process parameter monitoring data and process knowledge. 

(4) Relief valves routed to a control device. If all releases and potential leaks from a relief 

valve in organic HAP service are routed through a closed vent system to a control device, 

the owner or operator is not required to comply with paragraphs (j)(1), (2) or (3) (if 

applicable) of this section. Both the closed vent system and control device (if applicable) 

must meet the requirements of §63.644. When complying with this paragraph, all 

references to “Group 1 miscellaneous process vent” in 63.644 mean “relief valve.” 
Page 46 of 162 

§ 63.649 Alternative means of emission limitation: Connectors in gas/vapor service and 

light liquid service. 

(a) If an owner or operator elects to monitor valves according to the provisions of 

§63.648(c)(2)(ii), the owner or operator shall implement one of the connector monitoring 

programs specified in paragraphs (b), (c), or (d) of this section. 

(b) Random 200 connector alternative. The owner or operator shall implement a random 

sampling program for accessible connectors of 2.0 inches nominal diameter or greater. The 

program does not apply to inaccessible or unsafe-to-monitor connectors, as defined in §63.174 of 

subpart H. The sampling program shall be implemented source-wide. 

(1) Within the first 12 months after the phase III compliance date specified in §63.640(h), a 

sample of 200 connectors shall be randomly selected and monitored using Method 21 of 40 CFR 

part 60, appendix A. 

(2) The instrument reading that defines a leak is 1,000 parts per million. 

(3) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 

calendar days after the leak is detected except as provided in paragraph (e) of this section. A first 

attempt at repair shall be made no later than 5 calendar days after the leak is detected. 

(4) If a leak is detected, the connector shall be monitored for leaks within the first 3 months after 

its repair. 

(5) After conducting the initial survey required in paragraph (b)(1) of this section, the owner or 

operator shall conduct subsequent monitoring of connectors at the frequencies specified in 

paragraphs (b)(5)(i) through (b)(5)(iv) of this section. 

(i) If the percentage leaking connectors is 2.0 percent or greater, the owner or operator shall 

survey a random sample of 200 connectors once every 6 months. 

(ii) If the percentage leaking connectors is 1.0 percent or greater but less than 2.0 percent, the 

owner or operator shall survey a random sample of 200 connectors once per year. 

(iii) If the percentage leaking connectors is 0.5 percent or greater but less than 1.0 percent, the 

owner or operator shall survey a random sample of 200 connectors once every 2 years. 

(iv) If the percentage leaking connectors is less than 0.5 percent, the owner or operator shall 

survey a random sample of 200 connectors once every 4 years. 

(6) Physical tagging of the connectors to indicate that they are subject to the monitoring 

provisions is not required. Connectors may be identified by the area or length of pipe and need 

not be individually identified. 
Page 47 of 162 

(c) Connector inspection alternative. The owner or operator shall implement a program to 

monitor all accessible connectors in gas/vapor service that are 2.0 inches (nominal diameter) or 

greater and inspect all accessible connectors in light liquid service that are 2 inches (nominal 

diameter) or greater as described in paragraphs (c)(1) through (c)(7) of this section. The program 

does not apply to inaccessible or unsafe-to-monitor connectors. 

(1) Within 12 months after the phase III compliance date specified in §63.640(h), all connectors 

in gas/vapor service shall be monitored using Method 21 of 40 CFR part 60 appendix A. The 

instrument reading that defines a leak is 1,000 parts per million. 

(2) All connectors in light liquid service shall be inspected for leaks. A leak is detected if liquids 

are observed to be dripping at a rate greater than three drops per minute. 

(3) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 

calendar days after the leak is detected except as provided in paragraph (e) of this section. A first 

attempt at repair shall be made no later than 5 calendar days after the leak is detected. 

(4) If a leak is detected, connectors in gas/vapor service shall be monitored for leaks within the 

first 3 months after repair. Connectors in light liquid service shall be inspected for indications of 

leaks within the first 3 months after repair. A leak is detected if liquids are observed to be 

dripping at a rate greater than three drops per minute. 

(5) After conducting the initial survey required in paragraphs (c)(1) and (c)(2) of this section, the 

owner or operator shall conduct subsequent monitoring at the frequencies specified in paragraphs 

(c)(5)(i) through (c)(5)(iii) of this section. 

(i) If the percentage leaking connectors is 2.0 percent or greater, the owner or operator shall 

monitor or inspect, as applicable, the connectors once per year. 

(ii) If the percentage leaking connectors is 1.0 percent or greater but less than 2.0 percent, the 

owner or operator shall monitor or inspect, as applicable, the connectors once every 2 years. 

(iii) If the percentage leaking connectors is less than 1.0 percent, the owner or operator shall 

monitor or inspect, as applicable, the connectors once every 4 years. 

(6) The percentage leaking connectors shall be calculated for connectors in gas/vapor service and 

for connectors in light liquid service. The data for the two groups of connectors shall not be 

pooled for the purpose of determining the percentage leaking connectors. 

(i) The percentage leaking connectors shall be calculated as follows: 

% CL = [(CL−CAN)/Ct+Cc)]×100 

where: 

% CL = Percentage leaking connectors. 
Page 48 of 162 

CL = Number of connectors including nonrepairables, measured at 1,000 parts per million or 

greater, by Method 21 of 40 CFR part 60, appendix A. 

CAN = Number of allowable nonrepairable connectors, as determined by monitoring, not to 

exceed 3 percent of the total connector population, Ct. 

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

Cc = Optional credit for removed connectors=0.67×net number (i.e., the total number of 

connectors removed minus the total added) of connectors in organic HAP service removed from 

the process unit after the applicability date set forth in §63.640(h)(4)(iii) for existing process 

units, and after the date of start-up for new process units. If credits are not taken, then Cc = 0. 

(ii) Nonrepairable connectors shall be included in the calculation of percentage leaking 

connectors the first time the connector is identified as leaking and nonrepairable. Otherwise, a 

number of nonrepairable connectors up to a maximum of 1 percent per year of the total number 

of connectors in organic HAP service up to a maximum of 3 percent may be excluded from 

calculation of percentage leaking connectors for subsequent monitoring periods. 

(iii) If the number of nonrepairable connectors exceeds 3 percent of the total number of 

connectors in organic HAP service, the number of nonrepairable connectors exceeding 3 percent 

of the total number shall be included in the calculation of the percentage leaking connectors. 

(7) Physical tagging of the connectors to indicate that they are subject to the monitoring 

provisions is not required. Connectors may be identified by the area or length of pipe and need 

not be individually identified. 

(d) Subpart H program. The owner or operator shall implement a program to comply with the 

provisions in §63.174 of this part. 

(e) Delay of repair of connectors for which leaks have been detected is allowed if repair is not 

technically feasible by normal repair techniques without a process unit shutdown. Repair of this 

equipment shall occur by the end of the next process unit shutdown. 

(1) Delay of repair is allowed for equipment that is isolated from the process and that does not 

remain in organic HAP service. 

(2) Delay of repair for connectors is also allowed if: 

(i) The owner or operator determines that emissions of purged material resulting from immediate 

repair would be greater than the fugitive emissions likely to result from delay of repair, and 

(ii) When repair procedures are accomplished, the purged material would be collected and 

destroyed or recovered in a control device. 
Page 49 of 162 

(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 (cd) of this section, each owner or operator of a 

Group 1 gasoline loading rack classified under Standard Industrial Classification code 2911 

located within a contiguous area and under common control with a petroleum refinery shall 

comply with subpart R, §§63.421, 63.422(a) through (c) and (e), 63.425(a) through (c) and (i), 

63.425(e) through (h), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3), and (k). 

(b) As used in this section, all terms not defined in §63.641 shall have the meaning given them in 

subpart A or in 40 CFR part 63, subpart R. The §63.641 definition of “affected source” applies 

under this section. 

(c) Gasoline loading racks regulated under this subpart are subject to the compliance dates 

specified in §63.640(h). 

(d) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare shall meet the requirements of §63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the applicable 

requirements of subpart R of this part, or the requirements of §63.670. 

§ 63.651 Marine tank vessel loading operation provisions. 

(a) Except as provided in paragraphs (b) through (de) 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. 

(c) The notification reports under §63.567(b) are not required. 
Page 50 of 162 

(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)(31). 

(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, and 

§§63.650, and 63.651. Existing marine tank vessel loading operations located at the Valdez 

Marine Terminal source may not comply with the standard by using emissions averaging. 

(b) The owner or operator shall develop and submit for approval an Implementation Plan 

containing all of the information required in §63.653(d) for all points to be included in an 

emissions average. The Implementation Plan shall identify all emission points to be included in 

the emissions average. This must include any Group 1 emission points to which the reference 

control technology (defined in §63.641) is not applied and all other emission points being 

controlled as part of the average. 

(c) The following emission points can be used to generate emissions averaging credits if control 

was applied after November 15, 1990 and if sufficient information is available to determine the 

appropriate value of credits for the emission point: 

(1) Group 2 emission points; 

(2) Group 1 storage vessels, Group 1 wastewater streams, Group 1 gasoline loading racks, Group 

1 marine tank vessels, and Group 1 miscellaneous process vents that are controlled by a 

technology that the Administrator or permitting authority agrees has a higher nominal efficiency 

than the reference control technology. Information on the nominal efficiencies for such 

technologies must be submitted and approved as provided in paragraph (i) of this section; and 

(3) Emission points from which emissions are reduced by pollution prevention measures. 

Percentages of reduction for pollution prevention measures shall be determined as specified in 

paragraph (j) of this section. 

(i) For a Group 1 emission point, the pollution prevention measure must reduce emissions more 

than the reference control technology would have had the reference control technology been 

applied to the emission point instead of the pollution prevention measure except as provided in 

paragraph (c)(3)(ii) of this section. 
Page 51 of 162 

(ii) If a pollution prevention measure is used in conjunction with other controls for a Group 1 

emission point, the pollution prevention measure alone does not have to reduce emissions more 

than the reference control technology, but the combination of the pollution prevention measure 

and other controls must reduce emissions more than the reference control technology would have 

had it been applied instead. 

(d) The following emission points cannot be used to generate emissions averaging credits: 

(1) Emission points already controlled on or before November 15, 1990 unless the level of 

control is increased after November 15, 1990, in which case credit will be allowed only for the 

increase in control after November 15, 1990; 

(2) Group 1 emission points that are controlled by a reference control technology unless the 

reference control technology has been approved for use in a different manner and a higher 

nominal efficiency has been assigned according to the procedures in paragraph (i) of this section. 

For example, it is not allowable to claim that an internal floating roof meeting only the 

specifications stated in the reference control technology definition in §63.641 (i.e., that meets the 

specifications of §63.119(b) of subpart G but does not have controlled fittings per §63.119 (b)(5) 

and (b)(6) of subpart G) applied to a storage vessel is achieving greater than 95 percent control; 

(3) Emission points on shutdown process units. Process units that are shut down cannot be used 

to generate credits or debits; 

(4) Wastewater that is not process wastewater or wastewater streams treated in biological 

treatment units. These two types of wastewater cannot be used to generate credits or debits. 

Group 1 wastewater streams cannot be left undercontrolled or uncontrolled to generate debits. 

For the purposes of this section, the terms “wastewater” and “wastewater stream” are used to 

mean process wastewater; and 

(5) Emission points controlled to comply with a State or Federal rule other than this subpart, 

unless the level of control has been increased after November 15, 1990 above what is required by 

the other State or Federal rule. Only the control above what is required by the other State or 

Federal rule will be credited. However, if an emission point has been used to generate emissions 

averaging credit in an approved emissions average, and the point is subsequently made subject to 

a State or Federal rule other than this subpart, the point can continue to generate emissions 

averaging credit for the purpose of complying with the previously approved average. 

(e) For all points included in an emissions average, the owner or operator shall: 

(1) Calculate and record monthly debits for all Group 1 emission points that are controlled to a 

level less stringent than the reference control technology for those emission points. Equations in 

paragraph (g) of this section shall be used to calculate debits. 

(2) Calculate and record monthly credits for all Group 1 or Group 2 emission points that are 

overcontrolled to compensate for the debits. Equations in paragraph (h) of this section shall be 

used to calculate credits. Emission points and controls that meet the criteria of paragraph (c) of 
Page 52 of 162 

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 debit-generating 

emission points must be made under representative operating conditions. 

(ii) After the compliance date, actual operating data will be used for all debit and credit 

calculations. 

(4) Demonstrate that debits calculated for a quarterly (3-month) period according to paragraph 

(g) of this section are not more than 1.30 times the credits for the same period calculated 

according to paragraph (h) of this section. Compliance for the quarter shall be determined based 

on the ratio of credits and debits from that quarter, with 30 percent more debits than credits 

allowed on a quarterly basis. 

(5) Record and report quarterly and annual credits and debits in the Periodic Reports as specified 

in §63.655(g)(8). Every fourth Periodic Report shall include a certification of compliance with 

the emissions averaging provisions as required by §63.655(g)(8)(iii). 

(f) Debits and credits shall be calculated in accordance with the methods and procedures 

specified in paragraphs (g) and (h) of this section, respectively, and shall not include emissions 

from the following: 

(1) More than 20 individual emission points. Where pollution prevention measures (as specified 

in paragraph (j)(1) of this section) are used to control emission points to be included in an 

emissions average, no more than 25 emission points may be included in the average. For 

example, if two emission points to be included in an emissions average are controlled by 

pollution prevention measures, the average may include up to 22 emission points. 

(2) [Reserved]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.

(3) For emission points for which continuous monitors are used, periods of excess emissions as 

defined in §63.655(g)(6)(i). For these periods, the calculation of monthly credits and debits shall 

be adjusted as specified in paragraphs (f)(3)(i) through (f)(3)(iii) of this section. 

(i) No credits would be assigned to the credit-generating emission point. 

(ii) Maximum debits would be assigned to the debit-generating emission point. 
Page 53 of 162 

(iii) The owner or operator may use the procedures in paragraph (l) of this section to demonstrate 

to the Administrator that full or partial credits or debits should be assigned. 

(g) Debits are generated by the difference between the actual emissions from a Group 1 emission 

point that is uncontrolled or is controlled to a level less stringent than the reference control 

technology, and the emissions allowed for Group 1 emission point. Debits shall be calculated as 

follows: 

(1) The overall equation for calculating sourcewide debits is: 

       

   

  



  



      

n

i

iACTUAL iu

n

i

iACTUAL iC

n

i

iACTUAL iu

n

i

iACTUAL iu

EMV EMV

Debits EPV EPV ES ES EGLR EGLR

1

1 1 1

0.03

0.02 0.05

where: 

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

EPViACTUAL = Emissions from each Group 1 miscellaneous process vent i that is uncontrolled or 

is controlled to a level less stringent than the reference control technology. This is calculated 

according to paragraph (g)(2) of this section. 

(0.02) EPViu = Emissions from each Group 1 miscellaneous process vent i if the reference 

control technology had been applied to the uncontrolled emissions, calculated according to 

paragraph (g)(2) of this section. 

ESiACTUAL = Emissions from each Group 1 storage vessel i that is uncontrolled or is controlled to 

a level less stringent than the reference control technology. This is calculated according to 

paragraph (g)(3) of this section. 

(0.05) ESiu = Emissions from each Group 1 storage vessel i if the reference control technology 

had been applied to the uncontrolled emissions, calculated according to paragraph (g)(3) of this 

section. 

EGLRiACTUAL = Emissions from each Group 1 gasoline loading rack i that is uncontrolled or is 

controlled to a level less stringent than the reference control technology. This is calculated 

according to paragraph (g)(4) of this section. 

EGLRic = Emissions from each Group 1 gasoline loading rack i if the reference control 

technology had been applied to the uncontrolled emissions. This is calculated according to 

paragraph (g)(4) of this section. 
Page 54 of 162 

EMVACTUAL = Emissions from each Group 1 marine tank vessel i that is uncontrolled or is 

controlled to a level less stringent than the reference control technology. This is calculated 

according to paragraph (g)(5) of this section. 

(0.03) EMViu = Emissions from each Group 1 marine tank vessel i if the reference control 

technology had been applied to the uncontrolled emissions calculated according to paragraph 

(g)(5) of this section. 

n = The number of Group 1 emission points being included in the emissions average. The value 

of n is not necessarily the same for each kind of emission point. 

(2) Emissions from miscellaneous process vents shall be calculated as follows: 

(i) For purposes of determining miscellaneous process vent stream flow rate, organic HAP 

concentrations, and temperature, the sampling site shall be after the final product recovery 

device, if any recovery devices are present; before any control device (for miscellaneous process 

vents, recovery devices shall not be considered control devices); and before discharge to the 

atmosphere. Method 1 or 1A of part 60, appendix A shall be used for selection of the sampling 

site. 

(ii) The following equation shall be used for each miscellaneous process vent i to calculate 

EPViu: 

  













   

 n

j

EPViu Qh CjM j

1

9 2.494 10

where: 

EPViu = Uncontrolled process vent emission rate from miscellaneous process vent i, megagrams 

per month. 

Q = Vent stream flow rate, dry standard cubic meters per minute, measured using Methods 2, 

2A, 2C, or 2D of part 60 appendix A, as appropriate. 

h = Monthly hours of operation during which positive flow is present in the vent, hours per 

month. 

Cj = Concentration, parts per million by volume, dry basis, of organic HAP j as measured by 

Method 18 of part 60 appendix A. 

Mj = Molecular weight of organic HAP j, gram per gram-mole. 

n = Number of organic HAP’s in the miscellaneous process vent stream. 
Page 55 of 162 

(A) The values of Q, Cj, and Mj shall be determined during a performance test conducted under 

representative operating conditions. The values of Q, Cj, and Mj shall be established in the 

Notification of Compliance Status report and must be updated as provided in paragraph 

(g)(2)(ii)(B) of this section. 

(B) If there is a change in capacity utilization other than a change in monthly operating hours, or 

if any other change is made to the process or product recovery equipment or operation such that 

the previously measured values of Q, Cj, and Mj are no longer representative, a new performance 

test shall be conducted to determine new representative values of Q, Cj, and Mj. These new 

values shall be used to calculate debits and credits from the time of the change forward, and the 

new values shall be reported in the next Periodic Report. 

(iii) The following procedures and equations shall be used to calculate EPViACTUAL: 

(A) If the vent is not controlled by a control device or pollution prevention measure, EPViACTUAL

= EPViu, where EPViu is calculated according to the procedures in paragraphs (g)(2)(i) and 

(g)(2)(ii) of this section. 

(B) If the vent is controlled using a control device or a pollution prevention measure achieving 

less than 98-percent reduction, 





 



    100%

1 Percent reduction EPViACTUAL EPViu

(1) The percent reduction shall be measured according to the procedures in §63.116 of subpart G 

if a combustion control device is used. For a flare meeting the criteria in §63.116(a) of subpart G

or §63.670 of this subpart, as applicable, or a boiler or process heater meeting the criteria in 

§63.645(d) of this subpart or §63.116(b) of subpart G, the percentage of reduction shall be 98 

percent. If a noncombustion control device is used, percentage of reduction shall be 

demonstrated by a performance test at the inlet and outlet of the device, or, if testing is not 

feasible, by a control design evaluation and documented engineering calculations. 

(2) For determining debits from miscellaneous process vents, product recovery devices shall not 

be considered control devices and cannot be assigned a percentage of reduction in calculating 

EPViACTUAL. The sampling site for measurement of uncontrolled emissions is after the final 

product recovery device. 

(3) Procedures for calculating the percentage of reduction of pollution prevention measures are 

specified in paragraph (j) of this section. 

(3) Emissions from storage vessels shall be calculated as specified in §63.150(g)(3) of subpart G. 

(4) Emissions from gasoline loading racks shall be calculated as follows: 

(i) The following equation shall be used for each gasoline loading rack i to calculate EGLRiu: 
Page 56 of 162 

  T

SPMG EGLRiu

7 1.20 10  

where: 

EGLRiu = Uncontrolled transfer HAP emission rate from gasoline loading rack i, megagrams per 

month 

S = Saturation factor, dimensionless (see table 33 of subpart G). 

P = Weighted average rack partial pressure of organic HAP’s transferred at the rack during the 

month, kilopascals. 

M = Weighted average molecular weight of organic HAP’s transferred at the gasoline loading 

rack during the month, gram per gram-mole. 

G = Monthly volume of gasoline transferred from gasoline loading rack, liters per month. 

T = Weighted rack bulk liquid loading temperature during the month, degrees kelvin (degrees 

Celsius °C + 273). 

(ii) The following equation shall be used for each gasoline loading rack i to calculate the 

weighted average rack partial pressure: 

  

G

P G

P

j

j n

 j



 1

where: 

Pj = Maximum true vapor pressure of individual organic HAP transferred at the rack, kilopascals. 

G = Monthly volume of organic HAP transferred, liters per month, and 







j n

G Gj

1

Gj = Monthly volume of individual organic HAP transferred at the gasoline loading rack, liters 

per month. 

n = Number of organic HAP’s transferred at the gasoline loading rack. 

(iii) The following equation shall be used for each gasoline loading rack i to calculate the 

weighted average rack molecular weight: 
Page 57 of 162 

  

G

M G

M

j

j n

 j



 1

where: 

Mj = Molecular weight of individual organic HAP transferred at the rack, gram per gram-mole. 

G, Gj, and n are as defined in paragraph (g)(4)(ii) of this section. 

(iv) The following equation shall be used for each gasoline loading rack i to calculate the 

monthly weighted rack bulk liquid loading temperature: 

  

G

T G

T

j

j n

 j



 1

Tj = Average annual bulk temperature of individual organic HAP loaded at the gasoline loading 

rack, kelvin (degrees Celsius °C+273). 

G, Gj, and n are as defined in paragraph (g)(4)(ii) of this section. 

(v) The following equation shall be used to calculate EGLRic: 

EGLRic G

8 1 10  

G is as defined in paragraph (g)(4)(ii) of this section. 

(vi) The following procedures and equations shall be used to calculate EGLRiACTUAL: 

(A) If the gasoline loading rack is not controlled, EGLRiACTUAL = EGLRiu, where EGLRiu is 

calculated using the equations specified in paragraphs (g)(4)(i) through (g)(4)(iv) of this section. 

(B) If the gasoline loading rack is controlled using a control device or a pollution prevention 

measure not achieving the requirement of less than 10 milligrams of TOC per liter of gasoline 

loaded, 





 



    100%

1 Percent reduction EGLRiACTUAL EGLRiu

(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. 
Page 58 of 162 

(2) Procedures for calculating the percentage of reduction for pollution prevention measures are 

specified in paragraph (j) of this section. 

(5) Emissions from marine tank vessel loading shall be calculated as follows: 

(i) The following equation shall be used for each marine tank vessel i to calculate EMViu: 

    



m

i

EMViu Qi Fi Pi

1

where: 

EMViu = Uncontrolled marine tank vessel HAP emission rate from marine tank vessel i, 

megagrams per month. 

Qi = Quantity of commodity loaded (per vessel type), liters. 

Fi = Emission factor, megagrams per liter. 

Pi = Percent HAP. 

m = Number of combinations of commodities and vessel types loaded. 

Emission factors shall be based on test data or emission estimation procedures specified in 

§63.565(l) of subpart Y. 

(ii) The following procedures and equations shall be used to calculate EMViACTUAL: 

(A) If the marine tank vessel is not controlled, EMViACTUAL = EMViu, where EMViu is calculated 

using the equations specified in paragraph (g)(5)(i) of this section. 

(B) If the marine tank vessel is controlled using a control device or a pollution prevention 

measure achieving less than 97-percent reduction, 





 



    100%

1 Percent reduction EMViACTUAL EMViu

(1) The percent reduction for a control device shall be measured according to the procedures and 

test methods specified in §63.565(d) of subpart Y. If testing is not feasible, the percentage of 

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. 
Page 59 of 162 

(h) Credits are generated by the difference between emissions that are allowed for each Group 1 

and Group 2 emission point and the actual emissions from a Group 1 or Group 2 emission point 

that has been controlled after November 15, 1990 to a level more stringent than what is required 

by this subpart or any other State or Federal rule or statute. Credits shall be calculated as follows: 

(1) The overall equation for calculating sourcewide credits is: 

    

    

  

    

   

 

 

 

 

 

 

 

 

 

  

   

   

   

    

m

i

iBASE iACTUAL

n

i

ic iACTUAL

m

i

iBASE iACTUAL

n

i

iu iACTUAL

m

i

iBASE iACTUAL

n

i

ic iACTUAL

m

i

iBASE iACTUAL

n

i

iu iACTUAL

m

i

iBASE iACTUAL

n

i

iu iACTUAL

D EWW1 EWW1 D EWW2 EWW2

D EMV1 EMV1 D EMV2 EMV2

D EGLR EGLR1 D EGLR2 EGLR2

D ES1 ES1 D ES2 ES2

Credits D EPV1 EPV1 D EPV2 EPV2

1 1

1 1

1 1

1 1

1 1

0.03

0.05

0.02

where: 

Credits and all terms of the equation are in units of megagrams per month, the baseline date is 

November 15, 1990, and 

D = Discount factor = 0.9 for all credit-generating emission points except those controlled by a 

pollution prevention measure, which will not be discounted. 

EPV1iACTUAL = Emissions for each Group 1 miscellaneous process vent i that is controlled to a 

level more stringent than the reference control technology, calculated according to paragraph 

(h)(2) of this section. 

(0.02) EPV1iu = Emissions from each Group 1 miscellaneous process vent i if the reference 

control technology had been applied to the uncontrolled emissions. EPV1iu is calculated 

according to paragraph (h)(2) of this section. 

EPV2iBASE = Emissions from each Group 2 miscellaneous process vent; at the baseline date, as 

calculated in paragraph (h)(2) of this section. 

EPV2iACTUAL = Emissions from each Group 2 miscellaneous process vent that is controlled, 

calculated according to paragraph (h)(2) of this section. 

ES1iACTUAL = Emissions from each Group 1 storage vessel i that is controlled to a level more 

stringent than the reference control technology, calculated according to paragraph (h)(3) of this 

section. 
Page 60 of 162 

(0.05) ES1iu = Emissions from each Group 1 storage vessel i if the reference control technology 

had been applied to the uncontrolled emissions. ES1iu is calculated according to paragraph (h)(3) 

of this section. 

ES2iACTUAL = Emissions from each Group 2 storage vessel i that is controlled, calculated 

according to paragraph (h)(3) of this section. 

ES2iBASE = Emissions from each Group 2 storage vessel i at the baseline date, as calculated in 

paragraph (h)(3) of this section. 

EGLR1iACTUAL = Emissions from each Group 1 gasoline loading rack i that is controlled to a 

level more stringent than the reference control technology, calculated according to paragraph 

(h)(4) of this section. 

EGLRic = Emissions from each Group 1 gasoline loading rack i if the reference control 

technology had been applied to the uncontrolled emissions. EGLRiu is calculated according to 

paragraph (h)(4) of this section. 

EGRL2iACTUAL = Emissions from each Group 2 gasoline loading rack i that is controlled, 

calculated according to paragraph (h)(4) of this section. 

EGLR2iBASE = Emissions from each Group 2 gasoline loading rack i at the baseline date, as 

calculated in paragraph (h)(4) of this section. 

EMV1iACTUAL = Emissions from each Group 1 marine tank vessel i that is controlled to a level 

more stringent than the reference control technology, calculated according to paragraph (h)(4) of 

this section. 

(0.03)EMV1iu = Emissions from each Group 1 marine tank vessel i if the reference control 

technology had been applied to the uncontrolled emissions. EMV1iu is calculated according to 

paragraph (h)(5) of this section. 

EMV2iACTUAL = Emissions from each Group 2 marine tank vessel i that is controlled, calculated 

according to paragraph (h)(5) of this section. 

EMV2iBASE = Emissions from each Group 2 marine tank vessel i at the baseline date, as 

calculated in paragraph (h)(5) of this section. 

EWW1iACTUAL = Emissions from each Group 1 wastewater stream i that is controlled to a level 

more stringent than the reference control technology, calculated according to paragraph (h)(6) of 

this section. 

EWW1ic = Emissions from each Group 1 wastewater stream i if the reference control technology 

had been applied to the uncontrolled emissions, calculated according to paragraph (h)(6) of this 

section. 
Page 61 of 162 

EWW2iACTUAL = Emissions from each Group 2 wastewater stream i that is controlled, calculated 

according to paragraph (h)(6) of this section. 

EWW2iBASE = Emissions from each Group 2 wastewater stream i at the baseline date, calculated 

according to paragraph (h)(6) of this section. 

n = Number of Group 1 emission points included in the emissions average. The value of n is not 

necessarily the same for each kind of emission point. 

m = Number of Group 2 emission points included in the emissions average. The value of m is 

not necessarily the same for each kind of emission point. 

(i) For an emission point controlled using a reference control technology, the percentage of 

reduction for calculating credits shall be no greater than the nominal efficiency associated with 

the reference control technology, unless a higher nominal efficiency is assigned as specified in 

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

(ii) For an emission point controlled to a level more stringent than the reference control 

technology, the nominal efficiency for calculating credits shall be assigned as described in 

paragraph (i) of this section. A reference control technology may be approved for use in a 

different manner and assigned a higher nominal efficiency according to the procedures in 

paragraph (i) of this section. 

(iii) For an emission point controlled using a pollution prevention measure, the nominal 

efficiency for calculating credits shall be determined as described in paragraph (j) of this section. 

(2) Emissions from process vents shall be determined as follows: 

(i) Uncontrolled emissions from miscellaneous process vents, EPV1iu, shall be calculated 

according to the procedures and equation for EPViu in paragraphs (g)(2)(i) and (g)(2)(ii) of this 

section. 

(ii) Actual emissions from miscellaneous process vents controlled using a technology with an 

approved nominal efficiency greater than 98 percent or a pollution prevention measure achieving 

greater than 98 percent emission reduction, EPV1iACTUAL, shall be calculated according to the 

following equation: 





 



    100%

1 Nominal efficiency% EPV1iACTUAL EPV1iu

(iii) The following procedures shall be used to calculate actual emissions from Group 2 process 

vents, EPV2iACTUAL: 
Page 62 of 162 

(A) For a Group 2 process vent controlled by a control device, a recovery device applied as a 

pollution prevention project, or a pollution prevention measure, if the control achieves a 

percentage of reduction less than or equal to a 98 percent reduction, 





 



    100%

1 Percent reduction EPV2iACTUAL EPV2iu

(1) EPV2iu shall be calculated according to the equations and procedures for EPViu in paragraphs 

(g)(2)(i) and (g)(2)(ii) of this section except as provided in paragraph (h)(2)(iii)(A)(3) of this 

section. 

(2) The percentage of reduction shall be calculated according to the procedures in paragraphs 

(g)(2)(iii)(B)(1) through (g)(2)(iii)(B)(3) of this section except as provided in paragraph 

(h)(2)(iii)(A)(4) of this section. 

(3) If a recovery device was added as part of a pollution prevention project, EPV2iu shall be 

calculated prior to that recovery device. The equation for EPViu in paragraph (g)(2)(ii) of this 

section shall be used to calculate EPV2iu; however, the sampling site for measurement of vent 

stream flow rate and organic HAP concentration shall be at the inlet of the recovery device. 

(4) If a recovery device was added as part of a pollution prevention project, the percentage of 

reduction shall be demonstrated by conducting a performance test at the inlet and outlet of that 

recovery device. 

(B) For a Group 2 process vent controlled using a technology with an approved nominal 

efficiency greater than a 98 percent or a pollution prevention measure achieving greater than 98 

percent reduction, 





 



    100%

1 Nominal efficiency% EPV2 EPV2 iACTUAL iu

(iv) Emissions from Group 2 process vents at baseline, EPV2iBASE, shall be calculated as follows: 

(A) If the process vent was uncontrolled on November 15, 1990, EPV2iBASE = EPV2iu, and shall 

be calculated according to the procedures and equation for EPViu in paragraphs (g)(2)(i) and 

(g)(2)(ii) of this section. 

(B) If the process vent was controlled on November 15, 1990, 





 



    100%

1 Percent reduction EPV2 EPV2 BASE iu

where EPV2iu is calculated according to the procedures and equation for EPViu in paragraphs 

(g)(2)(i) and (g)(2)(ii) of this section. The percentage of reduction shall be calculated according 
Page 63 of 162 

to the procedures specified in paragraphs (g)(2)(iii)(B)(1) through (g)(2)(iii)(B)(3) of this 

section. 

(C) If a recovery device was added to a process vent as part of a pollution prevention project 

initiated after November 15, 1990, EPV2iBASE = EPV2iu, where EPV2iu is calculated according to 

paragraph (h)(2)(iii)(A)(3) of this section. 

(3) Emissions from storage vessels shall be determined as specified in §63.150(h)(3) of subpart 

G, except as follows: 

(i) For storage vessels complying with §63.646: 

(A) All references to §63.119(b) in §63.150(h)(3) of subpart G shall be replaced with: §63.119

(b) or §63.119(b) except for §63.119(b)(5) and (b)(6). 

(iiB) 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). 

(iiiC) All references to §63.119(d) in §63.150(h)(3) of subpart G shall be replaced with: 

§63.119(d) or §63.119(d) except for §63.119(d)(2). 

(ii) For storage vessels complying with §63.660: 

(A) Sections 63.1063(a)(1)(i), (a)(2), and (b) or §§63.1063(a)(1)(i) and (b) shall apply instead 

of §63.119(b) in §63.150(h)(3) of subpart G. 

(B) Sections 63.1063(a)(1)(ii), (a)(2), and (b) shall apply instead of §63.119(c) in 

§63.150(h)(3) of subpart G. 

(C) Sections 63.1063(a)(1)(i), (a)(2), and (b) or §§63.1063(a)(1)(i) and (b) shall apply instead 

of §63.119(d) in §63.150(h)(3) of subpart G. 

(4) Emissions from gasoline loading racks shall be determined as follows: 

(i) Uncontrolled emissions from Group 1 gasoline loading racks, EGLR1iu, shall be calculated 

according to the procedures and equations for EGLRiu as described in paragraphs (g)(4)(i) 

through (g)(4)(iv) of this section. 

(ii) Emissions from Group 1 gasoline loading racks if the reference control technology had been 

applied, EGLRic, shall be calculated according to the procedures and equations in paragraph 

(g)(4)(v) of this section. 

(iii) Actual emissions from Group 1 gasoline loading racks controlled to less than 10 milligrams 

of TOC per liter of gasoline loaded; EGLRiACTUAL, shall be calculated according to the following 

equation: 
Page 64 of 162 





 



    100%

1 Nominal efficiency% EGLR1 EGLR1 iACTUAL iu

(iv) The following procedures shall be used to calculate actual emissions from Group 2 gasoline 

loading racks, EGLR2iACTUAL: 

(A) For a Group 2 gasoline loading rack controlled by a control device or a pollution prevention 

measure achieving emissions reduction but where emissions are greater than the 10 milligrams of 

TOC per liter of gasoline loaded requirement, 





 



    100%

1 Percent reduction EGLR2iACTUAL EGLR2iu

(1) EGLR2iu shall be calculated according to the equations and procedures for EGLRiu in 

paragraphs (g)(4)(i) through (g)(4)(iv) of this section. 

(2) The percentage of reduction shall be calculated according to the procedures in paragraphs 

(g)(4)(vi)(B)(1) and (g)(4)(vi)(B)(2) of this section. 

(B) For a Group 2 gasoline loading rack controlled by using a technology with an approved 

nominal efficiency greater than 98 percent or a pollution prevention measure achieving greater 

than a 98-percent reduction, 





 



    100%

1 Nominal efficiency EGLR2iACTUAL EGLR2iu

(v) Emissions from Group 2 gasoline loading racks at baseline, EGLR2iBASE, shall be calculated 

as follows: 

(A) If the gasoline loading rack was uncontrolled on November 15, 1990, EGLR2iBASE = 

EGLR2iu, and shall be calculated according to the procedures and equations for EGLRiu in 

paragraphs (g)(4)(i) through (g)(4)(iv) of this section. 

(B) If the gasoline loading rack was controlled on November 15, 1990, 





 



    100%

1 Percent reduction EGLR2iBASE EGLR2iu

where EGLR2iu is calculated according to the procedures and equations for EGLRiu in 

paragraphs (g)(4)(i) through (g)(4)(iv) of this section. Percentage of reduction shall be calculated 

according to the procedures in paragraphs (g)(4)(vi)(B)(1) and (g)(4)(vi)(B)(2) of this section. 

(5) Emissions from marine tank vessels shall be determined as follows: 
Page 65 of 162 

(i) Uncontrolled emissions from Group 1 marine tank vessels, EMV1iu, shall be calculated 

according to the procedures and equations for EMViu as described in paragraph (g)(5)(i) of this 

section. 

(ii) Actual emissions from Group 1 marine tank vessels controlled using a technology or 

pollution prevention measure with an approved nominal efficiency greater than 97 percent, 

EMViACTUAL, shall be calculated according to the following equation: 





 



    100%

1 Nominal efficiency EMV1 EMV1 iACTUAL iu

(iii) The following procedures shall be used to calculate actual emissions from Group 2 marine 

tank vessels, EMV2iACTUAL: 

(A) For a Group 2 marine tank vessel controlled by a control device or a pollution prevention 

measure achieving a percentage of reduction less than or equal to 97 percent reduction, 





 



    100%

1 Percent reduction EMV2iACTUAL EMV2iu

(1) EMV2iu shall be calculated according to the equations and procedures for EMViu in 

paragraph (g)(5)(i) of this section. 

(2) The percentage of reduction shall be calculated according to the procedures in paragraphs 

(g)(5)(ii)(B)(1) and (g)(5)(ii)(B)(2) of this section. 

(B) For a Group 2 marine tank vessel controlled using a technology or a pollution prevention 

measure with an approved nominal efficiency greater than 97 percent, 





 



    100%

1 Nominal efficiency EMV2 EMV2 iACTUAL iu

(iv) Emissions from Group 2 marine tank vessels at baseline, EMV2iBASE, shall be calculated as 

follows: 

(A) If the marine terminal was uncontrolled on November 15, 1990, EMV2iBASE equals EMV2iu, 

and shall be calculated according to the procedures and equations for EMViu in paragraph 

(g)(5)(i) of this section. 

(B) If the marine tank vessel was controlled on November 15, 1990, 





 



    100%

1 Percent reduction EMV2 EMV2 iBASE iu
Page 66 of 162 

where EMV2iu is calculated according to the procedures and equations for EMViu in paragraph 

(g)(5)(i) of this section. Percentage of reduction shall be calculated according to the procedures 

in paragraphs (g)(5)(ii)(B)(1) and (g)(5)(ii)(B)(2) of this section. 

(6) Emissions from wastewater shall be determined as follows: 

(i) For purposes of paragraphs (h)(4)(ii) through (h)(4)(vi) of this section, the following terms 

will have the meaning given them in paragraphs (h)(6)(i)(A) through (h)(6)(i)(C) of this section. 

(A) Correctly suppressed means that a wastewater stream is being managed according to the 

requirements of §§61.343 through 61.347 or §61.342(c)(l)(iii) of 40 CFR part 61, subpart FF, as 

applicable, and the emissions from the waste management units subject to those requirements are 

routed to a control device that reduces HAP emissions by 95 percent or greater. 

(B) Treatment process has the meaning given in §61.341 of 40 CFR part 61, subpart FF except 

that it does not include biological treatment units. 

(C) Vapor control device means the control device that receives emissions vented from a 

treatment process or treatment processes. 

(ii) The following equation shall be used for each wastewater stream i to calculate EWWic: 

       







     

s

m

i i m im

s

m

EWWic QiHi Frm Fem HAPim Q H Fr HAP

1

8

1

8 6.0 10 1 0.05 6.0 10

where: 

EWWic = Monthly wastewater stream emission rate if wastewater stream i were controlled by the 

reference control technology, megagrams per month. 

Qi = Average flow rate for wastewater stream i, liters per minute. 

Hi = Number of hours during the month that wastewater stream i was generated, hours per 

month. 

Frm =Fraction removed of organic HAP m in wastewater, from table 7 of this subpart, 

dimensionless. 

Fem =Fraction emitted of organic HAP m in wastewater from table 7 of this subpart, 

dimensionless. 

s = Total number of organic HAP’s in wastewater stream i. 

HAPim = Average concentration of organic HAP m in wastewater stream i, parts per million by 

weight. 
Page 67 of 162 

(A) HAPim shall be determined for the point of generation or at a location downstream of the 

point of generation. Wastewater samples shall be collected using the sampling procedures 

specified in Method 25D of 40 CFR part 60, appendix A. Where feasible, samples shall be taken 

from an enclosed pipe prior to the wastewater being exposed to the atmosphere. When sampling 

from an enclosed pipe is not feasible, a minimum of three representative samples shall be 

collected in a manner to minimize exposure of the sample to the atmosphere and loss of organic 

HAP’s prior to sampling. The samples collected may be analyzed by either of the following 

procedures: 

(1) A test method or results from a test method that measures organic HAP concentrations in the 

wastewater, and that has been validated pursuant to section 5.1 or 5.3 of Method 301 of appendix 

A of this part may be used; or 

(2) Method 305 of appendix A of this part may be used to determine Cim, the average volatile 

organic HAP concentration of organic HAP m in wastewater stream i, and then HAPim may be 

calculated using the following equation: HAPim = Cim/Fmm, where Fmm for organic HAP m is 

obtained from table 7 of this subpart. 

(B) Values for Qi, HAPim, and Cim shall be determined during a performance test conducted 

under representative conditions. The average value obtained from three test runs shall be used. 

The values of Qi, HAPim, and Cim shall be established in the Notification of Compliance Status 

report and must be updated as provided in paragraph (h)(6)(i)(C) of this section. 

(C) If there is a change to the process or operation such that the previously measured values of 

Qi, HAPim, and Cim are no longer representative, a new performance test shall be conducted to 

determine new representative values of Qi, HAPim, and Cim. These new values shall be used to 

calculate debits and credits from the time of the change forward, and the new values shall be 

reported in the next Periodic Report. 

(iii) The following equations shall be used to calculate EWW1iACTUAL for each Group 1 

wastewater stream i that is correctly suppressed and is treated to a level more stringent than the 

reference control technology. 

(A) If the Group 1 wastewater stream i is controlled using a treatment process or series of 

treatment processes with an approved nominal reduction efficiency for an individually speciated 

HAP that is greater than that specified in table 7 of this subpart, and the vapor control device 

achieves a percentage of reduction equal to 95 percent, the following equation shall be used: 

          







     

s

m

i i im im

s

m

EWW1iACTUAL QiHi Fem HAPim PRim Q H HAP PR

1

8

1

8 6.0 10 1 0.05 6.0 10

Where: 

EWWiACTUAL = Monthly wastewater stream emission rate if wastewater stream i is treated to a 

level more stringent than the reference control technology, megagrams per month. 
Page 68 of 162 

PRim = The efficiency of the treatment process, or series of treatment processes, that treat 

wastewater stream i in reducing the emission potential of organic HAP m in wastewater, 

dimensionless, as calculated by: 

im in

im in im out

im HAP

HAP HAP PR



   

Where: 

HAPim-in = Average concentration of organic HAP m, parts per million by weight, as defined and 

determined according to paragraph (h)(6)(ii)(A) of this section, in the wastewater entering the 

first treatment process in the series. 

HAPim-out = Average concentration of organic HAP m, parts per million by weight, as defined 

and determined according to paragraph (h)(6)(ii)(A) of this section, in the wastewater exiting the 

last treatment process in the series. 

All other terms are as defined and determined in paragraph (h)(6)(ii) of this section. 

(B) If the Group 1 wastewater stream i is not controlled using a treatment process or series of 

treatment processes with an approved nominal reduction efficiency for an individually speciated 

HAP that is greater than that specified in table 7 of this subpart, but the vapor control device has 

an approved nominal efficiency greater than 95 percent, the following equation shall be used: 

         







   

 



     

s

m

i i im m

s

m

iACTUAL i i m im m Q H HAP A Nominal efficiency% EWW1 Q H Fe HAP A 1

8

1

8 6.0 10

100

6.0 10 1 1

Where: 

Nominal efficiency = Approved reduction efficiency of the vapor control device, dimensionless, 

as determined according to the procedures in §63.652(i). 

Am = The efficiency of the treatment process, or series of treatment processes, that treat 

wastewater stream i in reducing the emission potential of organic HAP m in wastewater, 

dimensionless. 

All other terms are as defined and determined in paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of this 

section. 

(1) If a steam stripper meeting the specifications in the definition of reference control technology 

for wastewater is used, Am shall be equal to the value of Frm given in table 7 of this subpart. 

(2) If an alternative control device is used, the percentage of reduction must be determined using 

the equation and methods specified in paragraph (h)(6)(iii)(A) of this section for determining 
Page 69 of 162 

PRim. If the value of PRim is greater than or equal to the value of Frm given in table 7 of this 

subpart, then Am equals Frm unless a higher nominal efficiency has been approved. If a higher 

nominal efficiency has been approved for the treatment process, the owner or operator shall 

determine EWW1iACTUAL according to paragraph (h)(6)(iii)(B) of this section rather than 

paragraph (h)(6)(iii)(A) of this section. If PRim is less than the value of FRm given in table 7 of 

this subpart, emissions averaging shall not be used for this emission point. 

(C) If the Group 1 wastewater stream i is controlled using a treatment process or series of 

treatment processes with an approved nominal reduction efficiency for an individually speciated 

hazardous air pollutant that is greater than that specified in table 7 of this subpart, and the vapor 

control device has an approved nominal efficiency greater than 95 percent, the following 

equation shall be used: 

         







   

 



     

s

m

i i im im

s

m

iACTUAL i i m im im Q H HAP PR Nominal efficiency% EWW1 Q H Fe HAP PR 1

8

1

8 6.0 10

100

6.0 10 1 1

where all terms are as defined and determined in paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of this 

section. 

(iv) The following equation shall be used to calculate EWW2iBASE for each Group 2 wastewater 

stream i that on November 15, 1990 was not correctly suppressed or was correctly suppressed 

but not treated: 

  

  

s

m

EWW iBASE QiHi Fem HAPim

1

8 2 6.0 10

Where: 

EWW2iBASE = Monthly wastewater stream emission rate if wastewater stream i is not correctly 

suppressed, megagrams per month. 

Qi, Hi, s, Fem, and HAPim are as defined and determined according to paragraphs (h)(6)(ii) and 

(h)(6)(iii)(A) of this section. 

(v) The following equation shall be used to calculate EWW2iBASE for each Group 2 wastewater 

stream i on November 15, 1990 was correctly suppressed. EWW2iBASE shall be calculated as if 

the control methods being used on November 15, 1990 are in place and any control methods 

applied after November 15, 1990 are ignored. However, values for the parameters in the equation 

shall be representative of present production levels and stream properties. 

         







   

 



     

s

m

i i im im

i

s

m

iBASE i i m im im Q H HAP PR R EWW2 Q H Fe HAP PR 1

8

1

8 6.0 10

100%

6.0 10 1 1
Page 70 of 162 

where Ri is calculated according to paragraph (h)(6)(vii) of this section and all other terms are as 

defined and determined according to paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of this section. 

(vi) For Group 2 wastewater streams that are correctly suppressed, EWW2iACTUAL shall be 

calculated according to the equation for EWW2iBASE in paragraph (h)(6)(v) of this section. 

EWW2iACTUAL shall be calculated with all control methods in place accounted for. 

(vii) The reduction efficiency, Ri, of the vapor control device shall be demonstrated according to 

the following procedures: 

(A) Sampling sites shall be selected using Method 1 or 1A of 40 CFR part 60, appendix A, as 

appropriate. 

(B) The mass flow rate of organic compounds entering and exiting the control device shall be 

determined as follows: 

(1) The time period for the test shall not be less than 3 hours during which at least three runs are 

conducted. 

(2) A run shall consist of a 1-hour period during the test. For each run: 

(i) The volume exhausted shall be determined using Methods 2, 2A, 2C, or 2D of 40 CFR part 60 

appendix A, as appropriate; 

(ii) The organic concentration in the vent stream entering and exiting the control device shall be 

determined using Method 18 of 40 CFR part 60, appendix A. Alternatively, any other test 

method validated according to the procedures in Method 301 of appendix A of this part may be 

used. 

(3) The mass flow rate of organic compounds entering and exiting the control device during each 

run shall be calculated as follows: 

































     

n

p

aip i

m

p

a Vap C MW

m

E

1 1

6 10

0.0416

































     

n

p

bip i

m

p

b Vbp C MW

m

E

1 1

6 10

0.0416

Where: 

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

Eb = Mass flow rate of organic compounds entering the control device, kilograms per hour. 
Page 71 of 162 

Vap = Average volumetric flow rate of vent stream exiting the control device during run p at 

standards conditions, cubic meters per hour. 

Vbp = Average volumetric flow rate of vent stream entering the control device during run p at 

standards conditions, cubic meters per hour. 

p = Run. 

m = Number of runs. 

Caip = Concentration of organic compound i measured in the vent stream exiting the control 

device during run p as determined by Method 18 of 40 CFR part 60 appendix A, parts per 

million by volume on a dry basis. 

Cbip = Concentration of organic compound i measured in the vent stream entering the control 

device during run p as determined by Method 18 of 40 CFR part 60, appendix A, parts per 

million by volume on a dry basis. 

MWi = Molecular weight of organic compound i in the vent stream, kilograms per kilogrammole. 

n = Number of organic compounds in the vent stream. 

0.0416 = Conversion factor for molar volume, kilograms-mole per cubic meter at 293 kelvin and 

760 millimeters mercury absolute. 

(C) The organic reduction efficiency for the control device shall be calculated as follows: 

100  

b

b a

E

E E R

Where: 

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

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

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

(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. 
Page 72 of 162 

(1) In those cases where the owner or operator is seeking permission to take credit for use of a 

control technology that is different in use or design from the reference control technology, and 

the different control technology will be used in more than three applications at a single plant site, 

the owner or operator shall submit the information specified in paragraphs (i)(1)(i) through 

(i)(1)(iv) of this section to the Administrator in writing: 

(i) Emission stream characteristics of each emission point to which the control technology is or 

will be applied including the kind of emission point, flow, organic HAP concentration, and all 

other stream characteristics necessary to design the control technology or determine its 

performance; 

(ii) Description of the control technology including design specifications; 

(iii) Documentation demonstrating to the Administrator’s satisfaction the control efficiency of 

the control technology. This may include performance test data collected using an appropriate 

EPA method or any other method validated according to Method 301 of appendix A of this part. 

If it is infeasible to obtain test data, documentation may include a design evaluation and 

calculations. The engineering basis of the calculation procedures and all inputs and assumptions 

made in the calculations shall be documented; and 

(iv) A description of the parameter or parameters to be monitored to ensure that the control 

technology will be operated in conformance with its design and an explanation of the criteria 

used for selection of that parameter (or parameters). 

(2) The Administrator shall determine within 120 calendar days whether an application presents 

sufficient information to determine nominal efficiency. The Administrator reserves the right to 

request specific data in addition to the items listed in paragraph (i)(1) of this section. 

(3) The Administrator shall determine within 120 calendar days of the submittal of sufficient 

data whether a control technology shall have a nominal efficiency and the level of that nominal 

efficiency. If, in the Administrator’s judgment, the control technology achieves a level of 

emission reduction greater than the reference control technology for a particular kind of emission 

point, the Administrator will publish a Federal Register notice establishing a nominal efficiency 

for the control technology. 

(4) The Administrator may grant conditional permission to take emission credits for use of the 

control technology on requirements that may be necessary to ensure operation and maintenance 

to achieve the specified nominal efficiency. 

(5) In those cases where the owner or operator is seeking permission to take credit for use of a 

control technology that is different in use or design from the reference control technology and 

the different control technology will be used in no more than three applications at a single plant 

site, the information listed in paragraphs (i)(1)(i) through (i)(1)(iv) of this section can be 

submitted to the permitting authority for the source for approval instead of the Administrator. 
Page 73 of 162 

(i) In these instances, use and conditions for use of the control technology can be approved by 

the permitting authority. The permitting authority shall follow the procedures specified in 

paragraphs (i)(2) through (i)(4) of this section except that, in these instances, a 

Federal Register notice is not required to establish the nominal efficiency for the different 

technology. 

(ii) If, in reviewing the submittal, the permitting authority believes the control technology has 

broad applicability for use by other sources, the permitting authority shall submit the information 

provided in the application to the Director of the EPA Office of Air Quality Planning and 

Standards. The Administrator shall review the technology for broad applicability and may 

publish a Federal Register notice; however, this review shall not affect the permitting authority’s 

approval of the nominal efficiency of the control technology for the specific application. 

(6) If, in reviewing an application for a control technology for an emission point, the 

Administrator or permitting authority determines the control technology is not different in use or 

design from the reference control technology, the Administrator or permitting authority shall 

deny the application. 

(j) The following procedures shall be used for calculating the efficiency (percentage of 

reduction) of pollution prevention measures: 

(1) A pollution prevention measure is any practice that meets the criteria of paragraphs (j)(1)(i) 

and (j)(1)(ii) of this section. 

(i) A pollution prevention measure is any practice that results in a lesser quantity of organic HAP 

emissions per unit of product released to the atmosphere prior to out-of-process recycling, 

treatment, or control of emissions while the same product is produced. 

(ii) Pollution prevention measures may include: Substitution of feedstocks that reduce HAP 

emissions, alterations to the production process to reduce the volume of materials released to the 

environment, equipment modifications; housekeeping measures, and in-process recycling that 

returns waste materials directly to production as raw materials. Production cutbacks do not 

qualify as pollution prevention. 

(2) The emission reduction efficiency of pollution prevention measures implemented after 

November 15, 1990 can be used in calculating the actual emissions from an emission point in the 

debit and credit equations in paragraphs (g) and (h) of this section. 

(i) For pollution prevention measures, the percentage of reduction used in the equations in 

paragraphs (g)(2) and (g)(3) of this section and paragraphs (h)(2) through (h)(4) of this section is 

the difference in percentage between the monthly organic HAP emissions for each emission 

point after the pollution prevention measure for the most recent month versus monthly emissions 

from the same emission point before the pollution prevention measure, adjusted by the volume of 

product produced during the two monthly periods. 
Page 74 of 162 

(ii) The following equation shall be used to calculate the percentage of reduction of a pollution 

prevention measure for each emission point. 

 

100%





B

pp

pp B

B

E

P

E P

E

Percent reduction

Where: 

Percent reduction = Efficiency of pollution prevention measure (percentage of organic HAP 

reduction). 

EB = Monthly emissions before the pollution prevention measure, megagrams per month, 

determined as specified in paragraphs (j)(2)(ii)(A), (j)(2)(ii)(B), and (j)(2)(ii)(C) of this section. 

Epp = Monthly emissions after the pollution prevention measure, megagrams per month, as 

determined for the most recent month, determined as specified in paragraphs (j)(2)(ii)(D) or 

(j)(2)(ii)(E) of this section. 

PB = Monthly production before the pollution prevention measure, megagrams per month, during 

the same period over which EB is calculated. 

Ppp = Monthly production after the pollution prevention measure, megagrams per month, as 

determined for the most recent month. 

(A) The monthly emissions before the pollution prevention measure, EB, shall be determined in a 

manner consistent with the equations and procedures in paragraphs (g)(2), (g)(3), (g)(4), and 

(g)(5) of this section for miscellaneous process vents, storage vessels, gasoline loading racks, and 

marine tank vessels. 

(B) For wastewater, EB shall be calculated as follows: 

     







 



  

n

i

s

m

EB QBiHBi Fem HAPBim

1 1

8 6 .0 10

where: 

n = Number of wastewater streams. 

QBi = Average flow rate for wastewater stream i before the pollution prevention measure, liters 

per minute. 

HBi = Number of hours per month that wastewater stream i was discharged before the pollution 

prevention measure, hours per month. 
Page 75 of 162 

s = Total number of organic HAP’s in wastewater stream i. 

Fem = Fraction emitted of organic HAP m in wastewater from table 7 of this subpart, 

dimensionless. 

HAPBim = Average concentration of organic HAP m in wastewater stream i, defined and 

determined according to paragraph (h)(6)(ii)(A)(2) of this section, before the pollution 

prevention measure, parts per million by weight, as measured before the implementation of the 

pollution measure. 

(C) If the pollution prevention measure was implemented prior to July 14, 1994, records may be 

used to determine EB. 

(D) The monthly emissions after the pollution prevention measure, Epp, may be determined 

during a performance test or by a design evaluation and documented engineering calculations. 

Once an emissions-to-production ratio has been established, the ratio can be used to estimate 

monthly emissions from monthly production records. 

(E) For wastewater, Epp shall be calculated using the following equation: 

     







 



  

n

i

s

m

Epp QppiH ppi Fem HAPppim

1 1

8 6 .0 10

where n, Q, H, s, Fem, and HAP are defined and determined as described in paragraph 

(j)(2)(ii)(B) of this section except that Qppi, Hppi, and HAPppim shall be determined after the 

pollution prevention measure has been implemented. 

(iii) All equations, calculations, test procedures, test results, and other information used to 

determine the percentage of reduction achieved by a pollution prevention measure for each 

emission point shall be fully documented. 

(iv) The same pollution prevention measure may reduce emissions from multiple emission 

points. In such cases, the percentage of reduction in emissions for each emission point must be 

calculated. 

(v) For the purposes of the equations in paragraphs (h)(2) through (h)(6) of this section used to 

calculate credits for emission points controlled more stringently than the reference control 

technology, the nominal efficiency of a pollution prevention measure is equivalent to the 

percentage of reduction of the pollution prevention measure. When a pollution prevention 

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 
Page 76 of 162 

emission points were controlled according to the provisions in §§63.643 through 63.645, 63.646 

or 63.660, 63.647, and §§63.650, and 63.651, as applicable. 

(1) This demonstration of hazard or risk equivalency shall be made to the satisfaction of the State 

or local permitting authority. 

(i) The State or local permitting authority may require owners and operators to use specific 

methodologies and procedures for making a hazard or risk determination. 

(ii) The demonstration and approval of hazard or risk equivalency may be made according to any 

guidance that the EPA makes available for use. 

(2) Owners and operators shall provide documentation demonstrating the hazard or risk 

equivalency of their proposed emissions average in their Implementation Plan. 

(3) An emissions averaging plan that does not demonstrate an equivalent or lower hazard or risk 

to the satisfaction of the State or local permitting authority shall not be approved. The State or 

local permitting authority may require such adjustments to the emissions averaging plan as are 

necessary in order to ensure that the average will not result in greater hazard or risk to human 

health or the environment than would result if the emission points were controlled according to 

§§63.643 through 63.645, 63.646 or 63.660, 63.647, and §§63.650, and 63.651, as applicable. 

(4) A hazard or risk equivalency demonstration shall: 

(i) Be a quantitative, bona fide chemical hazard or risk assessment; 

(ii) Account for differences in chemical hazard or risk to human health or the environment; and 

(iii) Meet any requirements set by the State or local permitting authority for such demonstrations. 

(l) For periods of excess emissions, an owner or operator may request that the provisions of 

paragraphs (l)(1) through (l)(4) of this section be followed instead of the procedures in 

paragraphs (f)(3)(i) and (f)(3)(ii) of this section. 

(1) The owner or operator shall notify the Administrator of excess emissions in the Periodic 

Reports as required in §63.655(g)(6). 

(2) The owner or operator shall demonstrate that other types of monitoring data or engineering 

calculations are appropriate to establish that the control device for the emission point was 

operating in such a fashion to warrant assigning full or partial credits and debits. This 

demonstration shall be made to the Administrator’s satisfaction, and the Administrator may 

establish procedures for demonstrating compliance that are acceptable. 

(3) The owner or operator shall provide documentation of the period of excess emissions and the 

other type of monitoring data or engineering calculations to be used to demonstrate that the 
Page 77 of 162 

control device for the emission point was operating in such a fashion to warrant assigning full or 

partial credits and debits. 

(4) The Administrator may assign full or partial credit and debits upon review of the information 

provided. 

§ 63.653 Monitoring, recordkeeping, and implementation plan for emissions averaging. 

(a) For each emission point included in an emissions average, the owner or operator shall 

perform testing, monitoring, recordkeeping, and reporting equivalent to that required for Group 1 

emission points complying with §§63.643 through 63.645, 63.646 or 63.660, 63.647, and 

§§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 (a)(7) of this section. 

(1) The source shall implement the following testing, monitoring, recordkeeping, and reporting 

procedures for each miscellaneous process vent equipped with a flare, incinerator, boiler, or 

process heater: 

(i) Conduct initial performance tests to determine the percentage of reduction as specified in 

§63.645 of this subpart and §63.116 of subpart G; and 

(ii) Monitor the operating parameters specified in §63.644, as appropriate for the specific control 

device. 

(2) The source shall implement the following procedures for each miscellaneous process vent, 

equipped with a carbon adsorber, absorber, or condenser but not equipped with a control device: 

(i) Determine the flow rate and organic HAP concentration using the methods specified in 

§63.115 (a)(1) and (a)(2), §63.115 (b)(1) and (b)(2), and §63.115(c)(3) of subpart G; and 

(ii) Monitor the operating parameters specified in §63.114 of subpart G, as appropriate for the 

specific recovery device. 

(3) The source shall implement the following procedures for each storage vessel controlled with 

an internal floating roof, external roof, or a closed vent system with a control device, as 

appropriate to the control technique: 

(i) Perform the monitoring or inspection procedures in §63.646 of this subpart and either 

§63.120 of subpart G or §63.1063 of subpart WW, as applicable; and 

(ii) For closed vent systems with control devices, conduct an initial design evaluation as 

specified in §63.646 of this subpart and either §63.120(d) of subpart G or §63.985(b) of 

subpart SS, as applicable. 
Page 78 of 162 

(4) For each gasoline loading rack that is controlled, perform the testing and monitoring 

procedures specified in §§63.425 and 63.427 of subpart R of this part except §63.425(d) or 

§63.427(c). 

(5) For each marine tank vessel that is controlled, perform the compliance, monitoring, and 

performance testing, procedures specified in §§63.563, 63.564, and 63.565 of subpart Y of this 

part. 

(6) The source shall implement the following procedures for wastewater emission points, as 

appropriate to the control techniques: 

(i) For wastewater treatment processes, conduct tests as specified in §61.355 of subpart FF of 

part 60; 

(ii) Conduct inspections and monitoring as specified in §§61.343 through 61.349 and §61.354 of 

40 CFR part 61, subpart FF. 

(7) If an emission point in an emissions average is controlled using a pollution prevention 

measure or a device or technique for which no monitoring parameters or inspection procedures 

are specified in §§63.643 through 63.645, 63.646 or 63.660, 63.647 and §§, 63.650, and 63.651, 

as applicable, the owner or operator shall establish a site-specific monitoring parameter and 

shall submit the information specified in §63.655(h)(4) in the Implementation Plan. 

(b) Records of all information required to calculate emission debits and credits and records 

required by §63.655 shall be retained for 5 years. 

(c) Notifications of Compliance Status report, Periodic Reports, and other reports shall be 

submitted as required by §63.655. 

(d) Each owner or operator of an existing source who elects to comply with §63.655(g) and (h) 

by using emissions averaging for any emission points shall submit an Implementation Plan. 

(1) The Implementation Plan shall be submitted to the Administrator and approved prior to 

implementing emissions averaging. This information may be submitted in an operating permit 

application, in an amendment to an operating permit application, in a separate submittal, in a 

Notification of Compliance Status Report, in a Periodic Report or in any combination of these 

documents. If an owner or operator submits the information specified in paragraph (d)(2) of this 

section at different times, and/or in different submittals, later submittals may refer to earlier 

submittals instead of duplicating the previously submitted information. 

(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. 
Page 79 of 162 

(ii) The projected annual emission debits and credits for each emission point and the sum for the 

emission points involved in the average calculated according to §63.652. The annual projected 

credits must be greater than the projected debits, as required under §63.652(e)(3). 

(iii) The specific control technology or pollution prevention measure that will be used for each 

emission point included in the average and date of application or expected date of application. 

(iv) The specific identification of each emission point affected by a pollution prevention 

measure. To be considered a pollution prevention measure, the criteria in §63.652(j)(1) must be 

met. If the same pollution prevention measure reduces or eliminates emissions from multiple 

emission points in the average, the owner or operator must identify each of these emission 

points. 

(v) A statement that the compliance demonstration, monitoring, inspection, recordkeeping, and 

reporting provisions in paragraphs (a), (b), and (c) of this section that are applicable to each 

emission point in the emissions average will be implemented beginning on the date of 

compliance. 

(vi) Documentation of the information listed in paragraphs (d)(2)(vi)(A) through (d)(2)(vi)(D) of 

this section for each emission point included in the average. 

(A) The values of the parameters used to determine whether each emission point in the emissions 

average is Group 1 or Group 2. 

(B) The estimated values of all parameters needed for input to the emission debit and credit 

calculations in §63.652 (g) and (h). These parameter values or, as appropriate, limited ranges for 

the parameter values, shall be specified in the source’s Implementation Plan as enforceable 

operating conditions. Changes to these parameters must be reported in the next Periodic Report. 

(C) The estimated percentage of reduction if a control technology achieving a lower percentage 

of reduction than the efficiency of the reference control technology, as defined in §63.641, is or 

will be applied to the emission point. 

(D) The anticipated nominal efficiency if a control technology achieving a greater percentage 

emission reduction than the efficiency of the reference control technology is or will be applied to 

the emission point. The procedures in §63.652(i) shall be followed to apply for a nominal 

efficiency. 

(vii) The information specified in §63.655(h)(4) for: 

(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. 
Page 80 of 162 

(viii) Documentation of the information listed in paragraphs (d)(2)(viii)(A) through 

(d)(2)(viii)(G) of this section for each process wastewater stream included in the average. 

(A) The information used to determine whether the wastewater stream is a Group 1 or Group 2 

wastewater stream. 

(B) The estimated values of all parameters needed for input to the wastewater emission credit 

and debit calculations in §63.652(h)(6). 

(C) The estimated percentage of reduction if the wastewater stream is or will be controlled using 

a treatment process or series of treatment processes that achieves an emission reduction less than 

or equal to the emission reduction specified in table 7 of this subpart. 

(D) The estimated percentage of reduction if a control technology achieving less than or equal to 

95 percent emission reduction is or will be applied to the vapor stream(s) vented and collected 

from the treatment processes. 

(E) The estimated percentage of reduction if a pollution prevention measure is or will be applied. 

(F) The anticipated nominal efficiency if the owner or operator plans to apply for a nominal 

efficiency under §63.652(i). A nominal efficiency shall be applied for if: 

(1) A control technology is or will be applied to the wastewater stream and achieves an emission 

reduction greater than the emission reduction specified in table 7 of this subpart; or 

(2) A control technology achieving greater than 95 percent emission reduction is or will be 

applied to the vapor stream(s) vented and collected from the treatment processes. 

(G) For each pollution prevention measure, treatment process, or control device used to reduce 

air emissions of organic HAP from wastewater and for which no monitoring parameters or 

inspection procedures are specified in §63.647, the information specified in §63.655(h)(4) shall 

be included in the Implementation Plan. 

(ix) Documentation required in §63.652(k) demonstrating the hazard or risk equivalency of the 

proposed emissions average. 

(3) The Administrator shall determine within 120 calendar days whether the Implementation 

Plan submitted presents sufficient information. The Administrator shall either 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. 
Page 81 of 162 

§ 63.654 Heat exchange systems. 

(a) Except as specified in paragraph (b) of this section, the owner or operator of a heat exchange 

system that meets the criteria in §63.640(c)(8) must comply with the requirements of paragraphs 

(c) through (g) of this section. 

(b) A heat exchange system is exempt from the requirements in paragraphs (c) through (g) of this 

section if all heat exchangers within the heat exchange system either: 

(1) Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater 

than the maximum pressure on the process side; or 

(2) Employ an intervening cooling fluid containing less than 5 percent by weight of total organic 

HAP, as determined according to the provisions of §63.180(d) of this part and table 1 of this 

subpart, between the process and the cooling water. This intervening fluid must serve to isolate 

the cooling water from the process fluid and must not be sent through a cooling tower or 

discharged. For purposes of this section, discharge does not include emptying for maintenance 

purposes. 

(c) The owner or operator must perform monitoring to identify leaks of total strippable volatile 

organic compounds (VOC) from each heat exchange system subject to the requirements of this 

subpart according to the procedures in paragraphs (c)(1) through (6) of this section. 

(1) Monitoring locations for closed-loop recirculation heat exchange systems. For each closed 

loop recirculating heat exchange system, collect and analyze a sample from the location(s) 

described in either paragraph (c)(1)(i) or (c)(1)(ii) of this section. 

(i) Each cooling tower return line or any representative riser within the cooling tower prior to 

exposure to air for each heat exchange system. 

(ii) Selected heat exchanger exit line(s) so that each heat exchanger or group of heat exchangers 

within a heat exchange system is covered by the selected monitoring location(s). 

(2) Monitoring locations for once-through heat exchange systems. For each once-through heat 

exchange system, collect and analyze a sample from the location(s) described in paragraph 

(c)(2)(i) of this section. The owner or operator may also elect to collect and analyze an additional 

sample from the location(s) described in paragraph (c)(2)(ii) of this section. 

(i) Selected heat exchanger exit line(s) so that each heat exchanger or group of heat exchangers 

within a heat exchange system is covered by the selected monitoring location(s). The selected 

monitoring location may be at a point where discharges from multiple heat exchange 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 
Page 82 of 162 

same primary water source), the owner or operator may monitor at one representative location 

and use the monitoring results for that sampling location for all heat exchange systems that use 

that same water feed. 

(3) Monitoring method. Determine the total strippable hydrocarbon concentration (in parts per 

million by volume (ppmv) as methane) at each monitoring location using the “Air Stripping 

Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions 

from Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, 

Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental 

Quality, January 31, 2003 (incorporated by reference—see § 63.14) using a flame ionization 

detector (FID) analyzer for on-site determination as described in Section 6.1 of the Modified El 

Paso Method. 

(4) Monitoring frequency and leak action level for existing sources. For a heat exchange system 

at an existing source, the owner or operator must comply with the monitoring frequency and leak 

action level as defined in paragraph (c)(4)(i) of this section or comply with the monitoring 

frequency and leak action level as defined in paragraph (c)(4)(ii) of this section. The owner or 

operator of an affected heat exchange system may choose to comply with paragraph (c)(4)(i) of 

this section for some heat exchange systems at the petroleum refinery and comply with 

paragraph (c)(4)(ii) of this section for other heat exchange systems. However, for each affected 

heat exchange system, the owner or operator of an affected heat exchange system must elect one 

monitoring alternative that will apply at all times. If the owner or operator intends to change the 

monitoring alternative that applies to a heat exchange system, the owner or operator must notify 

the Administrator 30 days in advance of such a change. All “leaks” identified prior to changing 

monitoring alternatives must be repaired. The monitoring frequencies specified in paragraphs 

(c)(4)(i) and (ii) of this section also apply to the inlet water feed line for a once-through heat 

exchange system, if monitoring of the inlet water feed is elected as provided in paragraph 

(c)(2)(ii) of this section. 

(i) Monitor monthly using a leak action level defined as a total strippable hydrocarbon 

concentration (as methane) in the stripping gas of 6.2 ppmv. 

(ii) Monitor quarterly using a leak action level defined as a total strippable hydrocarbon 

concentration (as methane) in the stripping gas of 3.1 ppmv unless repair is delayed as provided 

in paragraph (f) of this section. If a repair is delayed as provided in paragraph (f) of this section, 

monitor monthly. 

(5) Monitoring frequency and leak action level for new sources. For a heat exchange system at a 

new source, the owner or operator must monitor monthly using a leak action level defined as a 

total strippable hydrocarbon concentration (as methane) in the stripping gas of 3.1 ppmv. 

(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 
Page 83 of 162 

measurement value of the sample taken from a location specified in paragraph (c)(2)(i) of this 

section and the measurement value of the corresponding sample taken from the location 

specified in paragraph (c)(2)(ii) of this section equals or exceeds the leak action level. 

(ii) For all other heat exchange systems, a leak is detected if a measurement value of the sample 

taken from a location specified in either paragraph (c)(1)(i), (c)(1)(ii), or (c)(2)(i) of this section 

equals or exceeds the leak action level. 

(d) If a leak is detected, the owner or operator must repair the leak to reduce the measured 

concentration to below the applicable action level as soon as practicable, but no later than 45 

days after identifying the leak, except as specified in paragraphs (e) and (f) of this section. Repair 

includes re-monitoring at the monitoring location where the leak was identified according to the 

method specified in paragraph (c)(3) of this section to verify that the measured concentration is 

below the applicable action level. Actions that can be taken to achieve repair include but are not 

limited to: 

(1) Physical modifications to the leaking heat exchanger, such as welding the leak or replacing a 

tube; 

(2) Blocking the leaking tube within the heat exchanger; 

(3) Changing the pressure so that water flows into the process fluid; 

(4) Replacing the heat exchanger or heat exchanger bundle; or 

(5) Isolating, bypassing, or otherwise removing the leaking heat exchanger from service until it is 

otherwise repaired. 

(e) If the owner or operator detects a leak when monitoring a cooling tower return line under 

paragraph (c)(1)(i) of this section, the owner or operator may conduct additional monitoring of 

each heat exchanger or group of heat exchangers associated with the heat exchange system for 

which the leak was detected as provided under paragraph (c)(1)(ii) of this section. If no leaks are 

detected when monitoring according to the requirements of paragraph (c)(1)(ii) of this section, 

the heat exchange system is considered to meet the repair requirements through re-monitoring of 

the heat exchange system as provided in paragraph (d) of this section. 

(f) The owner or operator may delay the repair of a leaking heat exchanger when one of the 

conditions in paragraph (f)(1) or (f)(2) of this section is met and the leak is less than the delay of 

repair action level specified in paragraph (f)(3) of this section. The owner or operator must 

determine if a delay of repair is necessary as soon as practicable, but no later than 45 days after 

first identifying the leak. 

(1) If the repair is technically infeasible without a shutdown and the total strippable hydrocarbon 

concentration is initially and remains less than the delay of repair action level for all monthly 

monitoring periods during the delay of repair, the owner or operator may delay repair until the 

next scheduled shutdown of the heat exchange system. If, during subsequent monthly 
Page 84 of 162 

monitoring, the delay of repair action level is exceeded, the owner or operator must repair the 

leak within 30 days of the monitoring event in which the leak was equal to or exceeded the delay 

of repair action level. 

(2) If the necessary equipment, parts, or personnel are not available and the total strippable 

hydrocarbon concentration is initially and remains less than the delay of repair action level for all 

monthly monitoring periods during the delay of repair, the owner or operator may delay the 

repair for a maximum of 120 calendar days. The owner or operator must demonstrate that the 

necessary equipment, parts, or personnel were not available. If, during subsequent monthly 

monitoring, the delay of repair action level is exceeded, the owner or operator must repair the 

leak within 30 days of the monitoring event in which the leak was equal to or exceeded the delay 

of repair action level. 

(3) The delay of repair action level is a total strippable hydrocarbon concentration (as methane) 

in the stripping gas of 62 ppmv. The delay of repair action level is assessed as described in 

paragraph (f)(3)(i) or (f)(3)(ii) of this section, as applicable. 

(i) For once-through heat exchange systems for which the inlet water feed is monitored as 

described in paragraph (c)(2)(ii) of this section, the delay of repair action level is exceeded if the 

difference in the measurement value of the sample taken from a location specified in paragraph 

(c)(2)(i) of this section and the measurement value of the corresponding sample taken from the 

location specified in paragraph (c)(2)(ii) of this section equals or exceeds the delay of repair 

action level. 

(ii) For all other heat exchange systems, the delay of repair action level is exceeded if a 

measurement value of the sample taken from a location specified in either paragraphs (c)(1)(i), 

(c)(1)(ii), or (c)(2)(i) of this section equals or exceeds the delay of repair action level. 

(g) To delay the repair under paragraph (f) of this section, the owner or operator must record the 

information in paragraphs (g)(1) through (4) of this section. 

(1) The reason(s) for delaying repair. 

(2) A schedule for completing the repair as soon as practical. 

(3) The date and concentration of the leak as first identified and the results of all subsequent 

monthly monitoring events during the delay of repair. 

(4) An estimate of the potential strippable hydrocarbon emissions from the leaking heat 

exchange system or heat exchanger for each required delay of repair monitoring interval 

following the procedures in paragraphs (g)(4)(i) through (iv) of this section. 

(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 
Page 85 of 162 

Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: 

Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 

31, 2003 (incorporated by reference—see § 63.14) and the molecular weight of 16 grams per 

mole (g/mol) for methane. 

(ii) Determine the mass flow rate of the cooling water at the monitoring location where the leak 

was detected. If the monitoring location is an individual cooling tower riser, determine the total 

cooling water mass flow rate to the cooling tower. Cooling water mass flow rates may be 

determined using direct measurement, pump curves, heat balance calculations, or other 

engineering methods. Volumetric flow measurements may be used and converted to mass flow 

rates using the density of water at the specific monitoring location temperature or using the 

default density of water at 25 degrees Celsius, which is 997 kilograms per cubic meter or 8.32 

pounds per gallon. 

(iii) For delay of repair monitoring intervals prior to repair of the leak, calculate the potential 

strippable hydrocarbon emissions for the leaking heat exchange system or heat exchanger for the 

monitoring interval by multiplying the leak concentration in the cooling water, ppmw, 

determined in (g)(4)(i) of this section, by the mass flow rate of the cooling water determined in 

(g)(4)(ii) of this section and by the duration of the delay of repair monitoring interval. The 

duration of the delay of repair monitoring interval is the time period starting at midnight on the 

day of the previous monitoring event or at midnight on the day the repair would have had to be 

completed if the repair had not been delayed, whichever is later, and ending at midnight of the 

day the of the current monitoring event. 

(iv) For delay of repair monitoring intervals ending with a repaired leak, calculate the potential 

strippable hydrocarbon emissions for the leaking heat exchange system or heat exchanger for the 

final delay of repair monitoring interval by multiplying the duration of the final delay of repair 

monitoring interval by the leak concentration and cooling water flow rates determined for the last 

monitoring event prior to the re-monitoring event used to verify the leak was repaired. The 

duration of the final delay of repair monitoring interval is the time period starting at midnight of 

the day of the last monitoring event prior to re-monitoring to verify the leak was repaired and 

ending at the time of the re-monitoring event that verified that the leak was repaired. 

§ 63.655 Reporting and recordkeeping requirements. 

(a) Each owner or operator subject to the wastewater provisions in §63.647 shall comply with the 

recordkeeping and reporting provisions in §§61.356 and 61.357 of 40 CFR part 61, subpart FF 

unless they are complying with the wastewater provisions specified in paragraph (o)(2)(ii) of 

§63.640. There are no additional reporting and recordkeeping requirements for wastewater under 

this subpart unless a wastewater stream is included in an emissions average. Recordkeeping and 

reporting for emissions averages are specified in §63.653 and in paragraphs (f)(5) and (g)(8) of 

this section. 

(b) Each owner or operator subject to the gasoline loading rack provisions in §63.650 shall 

comply with the recordkeeping and reporting provisions in §63.428 (b) and (c), (g)(1), (h)(1) 

through (h)(3), and (k) of subpart R. These requirements are summarized in table 4 of this 
Page 86 of 162 

subpart. There are no additional reporting and recordkeeping requirements for gasoline loading 

racks under this subpart unless a loading rack is included in an emissions average. 

Recordkeeping and reporting for emissions averages are specified in §63.653 and in paragraphs 

(f)(5) and (g)(8) of this section. 

(c) Each owner or operator subject to the marine tank vessel loading operation standards in 

§63.651 shall comply with the recordkeeping and reporting provisions in §§63.567(a) and 

63.567(c) through (k) of subpart Y. These requirements are summarized in table 5 of this 

subpart. There are no additional reporting and recordkeeping requirements for marine tank vessel 

loading operations under this subpart unless marine tank vessel loading operations are included 

in an emissions average. Recordkeeping and reporting for emissions averages are specified in 

§63.653 and in paragraphs (f)(5) and (g)(8) of this section. 

(d) Each owner or operator subject to the equipment leaks standards in §63.648 shall comply 

with the recordkeeping and reporting provisions in paragraphs (d)(1) through (d)(6) of this 

section. 

(1) Sections 60.486 and 60.487 of subpart VV of part 60 except as specified in paragraph 

(d)(1)(i) of this section; or §§63.181 and 63.182 of subpart H of this part except for §§63.182(b), 

(c)(2), and (c)(4). 

(i) The signature of the owner or operator (or designate) whose decision it was that a repair could 

not be effected without a process shutdown is not required to be recorded. Instead, the name of 

the person whose decision it was that a repair could not be effected without a process shutdown 

shall be recorded and retained for 2 years. 

(ii) [Reserved] 

(2) The Notification of Compliance Status report required by §63.182(c) of subpart H and the 

initial semiannual report required by §60.487(b) of 40 CFR part 60, subpart VV shall be 

submitted within 150 days of the compliance date specified in §63.640(h); the requirements of 

subpart H of this part are summarized in table 3 of this subpart. 

(3) An owner or operator who determines that a compressor qualifies for the hydrogen service 

exemption in §63.648 shall also keep a record of the demonstration required by §63.648. 

(4) An owner or operator must keep a list of identification numbers for valves that are designated 

as leakless per §63.648(c)(10). 

(5) An owner or operator must identify, either by list or location (area or refining process unit), 

equipment in organic HAP service less than 300 hours per year within refining process units 

subject to this subpart. 

(6) An owner or operator must keep a list of reciprocating pumps and compressors determined to 

be exempt from seal requirements as per §§63.648 (f) and (i). 
Page 87 of 162 

(e) Each owner or operator of a source subject to this subpart shall submit the reports listed in 

paragraphs (e)(1) through (e)(3) of this section except as provided in paragraph (h)(5) of this 

section, and shall keep records as described in paragraph (i) of this section. 

(1) A Notification of Compliance Status report as described in paragraph (f) of this section; 

(2) Periodic Reports as described in paragraph (g) of this section; and 

(3) Other reports as described in paragraph (h) of this section. 

(f) Each owner or operator of a source subject to this subpart shall submit a Notification of 

Compliance Status report within 150 days after the compliance dates specified in §63.640(h) 

with the exception of Notification of Compliance Status reports submitted to comply with 

§63.640(l)(3) and for storage vessels subject to the compliance schedule specified in 

§63.640(h)(42). 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)(42) shall be submitted 

according to paragraph (f)(6) of this section. This information may be submitted in an operating 

permit application, in an amendment to an operating permit application, in a separate submittal, 

or in any combination of the three. If the required information has been submitted before the date 

150 days after the compliance date specified in §63.640(h), a separate Notification of 

Compliance Status report is not required within 150 days after the compliance dates specified in 

§63.640(h). If an owner or operator submits the information specified in paragraphs (f)(1) 

through (f)(5) of this section at different times, and/or in different submittals, later submittals 

may refer to earlier submittals instead of duplicating and resubmitting the previously submitted 

information. Each owner or operator of a gasoline loading rack classified under Standard 

Industrial Classification Code 2911 located within a contiguous area and under common control 

with a petroleum refinery subject to the standards of this subpart shall submit the Notification of 

Compliance Status report required by subpart R of this part within 150 days after the compliance 

dates specified in §63.640(h) of this subpart. 

(1) The Notification of Compliance Status report shall include the information specified in 

paragraphs (f)(1)(i) through (f)(1)(vii) of this section. 

(i) For storage vessels, this report shall include the information specified in paragraphs 

(f)(1)(i)(A) through (f)(1)(i)(D) of this section. 

(A) Identification of each storage vessel subject to this subpart, and for each Group 1 storage 

vessel subject to this subpart, the information specified in paragraphs (f)(1)(i)(A)(1) through 

(f)(1)(i)(A)(3) of this section. This information is to be revised each time a Notification of 

Compliance Status report is submitted for a storage vessel subject to the compliance schedule 

specified in §63.640(h)(42) 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). 
Page 88 of 162 

(2) For storage vessels subject to the compliance schedule specified in §63.640(h)(42) 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)(42) that are 

complying with §63.646 and the Group 1 storage vessels described in §63.640(l), the actual 

compliance date. 

(B) If a closed vent system and a control device other than a flare is used to comply with §63.646 

or §63.660, the owner or operator shall submit: 

(1) A description of the parameter or parameters to be monitored to ensure that the control device 

is being properly operated and maintained, an explanation of the criteria used for selection of that 

parameter (or parameters), and the frequency with which monitoring will be performed; and 

either 

(2) The design evaluation documentation specified in §63.120(d)(1)(i) of subpart G or 

§63.985(b)(1)(i) of subpart SS (as applicable), if the owner or operator elects to prepare a 

design evaluation; or 

(3) If the owner or operator elects to submit the results of a performance test, identification of the 

storage vessel and control device for which the performance test will be submitted, and 

identification of the emission point(s) that share the control device with the storage vessel and 

for which the performance test will be conducted. 

(C) If a closed vent system and control device other than a flare is used, the owner or operator 

shall submit: 

(1) The operating range for each monitoring parameter. The specified operating range shall 

represent the conditions for which the control device is being properly operated and maintained. 

(2) If a performance test is conducted instead of a design evaluation, results of the performance 

test demonstrating that the control device achieves greater than or equal to the required control 

efficiency. A performance test conducted prior to the compliance date of this subpart can be used 

to comply with this requirement, provided that the test was conducted using EPA methods and 

that the test conditions are representative of current operating practices. 

(D) If a closed vent system and a flare is used, the owner or operator shall submit: 

(1) Flare design (e.g., steam-assisted, air-assisted, or nonassisted); 

(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 of this partor §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. 
Page 89 of 162 

(ii) For miscellaneous process vents, identification of each miscellaneous process vent subject to 

this subpart, whether the process vent is Group 1 or Group 2, and the method of compliance for 

each Group 1 miscellaneous process vent that is not included in an emissions average (e.g., use 

of a flare or other control device meeting the requirements of §63.643(a)). 

(iii) For miscellaneous process vents controlled by control devices required to be tested under 

§63.645 of this subpart and §63.116(c) of subpart G of this part, performance test results 

including the information in paragraphs (f)(1)(iii)(A) and (B) of this section. Results of a 

performance test conducted prior to the compliance date of this subpart can be used provided that 

the test was conducted using the methods specified in §63.645 and that the test conditions are 

representative of current operating conditions. 

(A) The percentage of reduction of organic HAP’s or TOC, or the outlet concentration of organic 

HAP’s or TOC (parts per million by volume on a dry basis corrected to 3 percent oxygen), 

determined as specified in §63.116(c) of subpart G of this part; and 

(B) The value of the monitored parameters specified in table 10 of this subpart, or a site-specific 

parameter approved by the permitting authority, averaged over the full period of the performance 

test, 

(iv) For miscellaneous process vents controlled by flares, performanceinitial compliance test 

results including the information in paragraphs (f)(1)(iv)(A) and (B) of this section; 

(A) All visible emission readings, heat content determinations, flow rate measurements, and exit 

velocity determinations made during the compliance determination required by §63.645 of this 

subpart and §63.116(a) of subpart G of this part or §63.670(h) of this subpart, as applicable, 

and 

(B) A statement of whether a flame was present at the pilot light over the full period of the 

compliance determination. 

(v) For equipment leaks complying with §63.648(c) (i.e., complying with the requirements of 

subpart H of this part), the Notification of Compliance Report Status report information required 

by §63.182(c) of subpart H and whether the percentage of leaking valves will be reported on a 

process unit basis or a sourcewide basis. 

(vi) For each heat exchange system, identification of the heat exchange systems that are subject 

to the requirements of this subpart. For heat exchange systems at existing sources, the owner or 

operator shall indicate whether monitoring will be conducted as specified in §63.654(c)(4)(i) or 

§63.654(c)(4)(ii). 

(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. 
Page 90 of 162 

(2) If initial performance tests are required by §§63.643 through 63.653 of this subpart, the 

Notification of Compliance Status report shall include one complete test report for each test 

method used for a particular source. On and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], performance tests shall be submitted according to paragraph (h)(9) of this 

section.

(i) For additional tests performed using the same method, the results specified in paragraph (f)(1) 

of this section shall be submitted, but a complete test report is not required. 

(ii) A complete test report shall include a sampling site description, description of sampling and 

analysis procedures and any modifications to standard procedures, quality assurance procedures, 

record of operating conditions during the test, record of preparation of standards, record of 

calibrations, raw data sheets for field sampling, raw data sheets for field and laboratory analyses, 

documentation of calculations, and any other information required by the test method. 

(iii) Performance tests are required only if specified by §§63.643 through 63.653 of this subpart. 

Initial performance tests are required for some kinds of emission points and controls. Periodic 

testing of the same emission point is not required. 

(3) For each monitored parameter for which a range is required to be established under 

§63.120(d) of subpart G of this partor §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. 

(4) Results of any continuous monitoring system performance evaluations shall be included in 

the Notification of Compliance Status report. 
Page 91 of 162 

(5) For emission points included in an emissions average, the Notification of Compliance Status 

report shall include the values of the parameters needed for input to the emission credit and debit 

equations in §63.652(g) and (h), calculated or measured according to the procedures in 

§63.652(g) and (h), and the resulting credits and debits for the first quarter of the year. The first 

quarter begins on the compliance date specified in §63.640. 

(6) Notification of Compliance Status reports required by §63.640(l)(3) and for storage vessels 

subject to the compliance dates specified in §63.640(h)(42) shall be submitted no later than 60 

days after the end of the 6-month period during which the change or addition was made that 

resulted in the Group 1 emission point or the existing Group 1 storage vessel was brought into 

compliance, and may be combined with the periodic report. Six-month periods shall be the same 

6-month periods specified in paragraph (g) of this section. The Notification of Compliance Status 

report shall include the information specified in paragraphs (f)(1) through (f)(5) of this section. 

This information may be submitted in an operating permit application, in an amendment to an 

operating permit application, in a separate submittal, as part of the periodic report, or in any 

combination of these four. If the required information has been submitted before the date 60 days 

after the end of the 6-month period in which the addition of the Group 1 emission point took 

place, a separate Notification of Compliance Status report is not required within 60 days after the 

end of the 6-month period. If an owner or operator submits the information specified in 

paragraphs (f)(1) through (f)(5) of this section at different times, and/or in different submittals, 

later submittals may refer to earlier submittals instead of duplicating and resubmitting the 

previously submitted information. 

(g) The owner or operator of a source subject to this subpart shall submit Periodic Reports no 

later than 60 days after the end of each 6-month period when any of the compliance 

exceptionsinformation specified in paragraphs (g)(1) through (67) of this section or paragraphs

(g)(9) through (12) of this section occuris collected. The first 6-month period shall begin on the 

date the Notification of Compliance Status report is required to be submitted. A Periodic Report 

is not required if none of the compliance exceptionsevents identified in paragraph (g)(1) through 

(67) of this section or paragraphs (g)(9) through (12) of this section occurred during the 6-

month period unless emissions averaging is utilized. Quarterly reports must be submitted for 

emission points included in emission averages, as provided in paragraph (g)(8) of this section. 

An owner or operator may submit reports required by other regulations in place of or as part of 

the Periodic Report required by this paragraph if the reports contain the information required by 

paragraphs (g)(1) through (912) 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 except that information. Information

related to gaskets, slotted membranes, and sleeve seals is not required for storage vessels that are 

part of an existing source complying with §63.646. 

(2) Internal floating roofs. (i) An owner or operator who elects to comply with §63.646 by using 

a fixed roof and an internal floating roof or by using an external floating roof converted to an 

internal floating roof shall submit the results of each inspection conducted in accordance with 

§63.120(a) of subpart G of this part in which a failure is detected in the control equipment. 
Page 92 of 162 

(iA) For vessels for which annual inspections are required under §63.120(a)(2)(i) or (a)(3)(ii) of 

subpart G of this part, the specifications and requirements listed in paragraphs (g)(2)(i)(A)(1) 

through (g)(2)(i)(C3) of this section apply. 

(A1) A failure is defined as any time in which the internal floating roof is not resting on the 

surface of the liquid inside the storage vessel and is not resting on the leg supports; or there is 

liquid on the floating roof; or the seal is detached from the internal floating roof; or there are 

holes, tears, or other openings in the seal or seal fabric; or there are visible gaps between the seal 

and the wall of the storage vessel. 

(B2) 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. 

(C3) If an extension is utilized in accordance with §63.120(a)(4) of subpart G of this part, 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 of this part; and describe the date the 

storage vessel was emptied and the nature of and date the repair was made. 

(iiB) For vessels for which inspections are required under §63.120(a)(2)(ii), (a)(3)(i), or 

(a)(3)(iii) of subpart G of this part (i.e., internal inspections), the specifications and requirements 

listed in paragraphs (g)(2)(ii)(Ai)(B)(1) and (g)(2)(ii)(B) of this section apply. 

(A1) A failure is defined as any time in which the internal floating roof has defects; or the 

primary seal has holes, tears, or other openings in the seal or the seal fabric; or the secondary seal 

(if one has been installed) has holes, tears, or other openings in the seal or the seal fabric; or, for 

a storage vessel that is part of a new source, the gaskets no longer close off the liquid surface 

from the atmosphere; or, for a storage vessel that is part of a new source, the slotted membrane 

has more than a 10 percent open area. 

(2B) Each Periodic Report shall include the date of the inspection, identification of each storage 

vessel in which a failure was detected, and a description of the failure. The Periodic Report shall 

also describe the nature of and date the repair was made. 

(ii) An owner or operator who elects to comply with §63.660 by using a fixed roof and an 

internal floating roof shall submit the results of each inspection conducted in accordance 

with §63.1063(c)(1), (d)(1), and (d)(2) of subpart WW in which a failure is detected in the 

control equipment. For vessels for which inspections are required under §63.1063(c) and 

(d), the specifications and requirements listed in paragraphs (g)(2)(ii)(A) through 

(g)(2)(ii)(C) of this section apply. 

(A) A failure is defined in §63.1063(d)(1) of subpart WW. 

(B) Each Periodic Report shall include a copy of the inspection record required by 

§63.1065(b) of subpart WW when a failure occurs. 
Page 93 of 162 

(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) through (g)(3)(iii)(A) and (B) of this section. 

(iA) 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 of this 

part in which the seal and seal gap requirements of §63.120(b)(3), (b)(4), (b)(5), or (b)(6) of 

subpart G of this part are not met. This documentation shall include the information specified in 

paragraphs (g)(3)(i)(A)(1) through (g)(3)(i)(D4) of this section. 

(A1) The date of the seal gap measurement. 

(B2) The raw data obtained in the seal gap measurement and the calculations described in 

§63.120(b)(3) and (b)(4) of subpart G of this part. 

(C3) A description of any seal condition specified in §63.120(b)(5) or (b)(6) of subpart G of this 

part that is not met. 

(D4) A description of the nature of and date the repair was made, or the date the storage vessel 

was emptied. 

(iiB) If an extension is utilized in accordance with §63.120(b)(7)(ii) or (b)(8) of subpart G of this 

part, the owner or operator shall, in the next Periodic Report, identify the vessel; include the 

documentation specified in §63.120(b)(7)(ii) or (b)(8) of subpart G of this part, as applicable; 

and describe the date the vessel was emptied and the nature of and date the repair was made. 

(iiiC) 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 of 

this part.. This documentation shall meet the specifications and requirements in paragraphs 

(g)(3)(iii)(Ai)(C)(1) and (g)(3)(iii)(B2) of this section. 

(A1) A failure is defined as any time in which the external floating roof has defects; or the 

primary seal has holes or other openings in the seal or the seal fabric; or the secondary seal has 

holes, tears, or other openings in the seal or the seal fabric; or, for a storage vessel that is part of 

a new source, the gaskets no longer close off the liquid surface from the atmosphere; or, for a 

storage vessel that is part of a new source, the slotted membrane has more than 10 percent open 

area. 

(B(2B) 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. 
Page 94 of 162 

(ii) An owner or operator who elects to comply with §63.660 by using an external floating 

roof shall meet the periodic reporting requirements specified in paragraphs (g)(3)(ii)(A) 

and (B) of this section. 

(A) For vessels for which inspections are required under §63.1063(c)(2), (d)(1), and (d)(3) of 

subpart WW, the owner or operator shall submit, as part of the Periodic Report, a copy of 

the inspection record required by §63.1065(b) of subpart WW when a failure occurs. A 

failure is defined in §63.1063(d)(1). 

(B) An owner or operator who elects to use an extension in accordance with §63.1063(e)(2) 

or §63.1063(c)(2)(iv)(B) of subpart WW shall, in the next Periodic Report, submit the 

documentation required by those paragraphs. 

(4) An owner or operator who elects to comply with §63.646 or §63.660 by using an external 

floating roof converted to an internal floating roof shall comply with the periodic reporting 

requirements of paragraph (g)(2)(i) of this section. 

(5) An owner or operator who elects to comply with §63.646 or §63.660 by installing a closed 

vent system and control device shall submit, as part of the next Periodic Report, the information 

specified in paragraphs (g)(5)(i) through (g)(5)(iii) of this section, as applicable. 

(i) The Periodic Report shall include the information specified in paragraphs (g)(5)(i)(A) and 

(g)(5)(i)(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 (e)(2) of subpart G, 

§63.985(a) and (b) of this partsubpart 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 (e)(2) of subpart G, §63.985(a) and (b) of this 

partsubpart 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. 

(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 
Page 95 of 162 

requirements specified in §63.11(b) of subpart A of this part and shall include: Identification of 

the flare that does not meet the general requirements specified in §63.11(b) of subpart A of this 

part, and reasons the flare did not meet the general requirements specified in §63.11(b) of 

subpart A of this part. 

(iv) If a flare is used on and after compliance with the requirements in §63.670 is elected, 

which can be no later than [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the Periodic Report shall include the items specified in paragraph (g)(11) of 

this section. 

(v) An owner or operator who elects to comply with §63.660 by installing an alternate 

control device as described in §63.1064 of subpart WW shall submit, as part of the next 

Periodic Report, a written application as described in §63.1066(b)(3) of subpart WW. 

(6) For miscellaneous process vents for which continuous parameter monitors are required by 

this subpart, periods of excess emissions shall be identified in the Periodic Reports and shall be 

used to determine compliance with the emission standards. 

(i) Period of excess emission means any of the following conditions: 

(A) An operating day when the daily average value of a monitored parameter, except presence of 

a flare pilot flame, is outside the range specified in the Notification of Compliance Status report. 

Monitoring data recorded during periods of monitoring system breakdown, repairs, calibration 

checks and zero (low-level) and high-level adjustments shall not be used in computing daily 

average values of monitored parameters. 

(B) An operating day when all pilot flames of a flare are absent. 

(C) An operating day when monitoring data required to be recorded in paragraphs (i)(3)(i) and 

(ii) of this section are available for less than 75 percent of the operating hours. 

(D) For data compression systems approved under paragraph (h)(5)(iii) of this section, an 

operating day when the monitor operated for less than 75 percent of the operating hours or a day 

when less than 18 monitoring values were recorded. 

(ii) For miscellaneous process vents, excess emissions shall be reported for the operating 

parameters specified in table 10 of this subpart unless other site-specific parameter(s) have been 

approved by the operating permit authority. 

(iii) For closed vent systems, include the records of periods when vent stream flow was 

detected in the bypass line or diverted from the control device, a flow indicator was not 

operating or a bypass of the system was indicated, as specified in paragraph (i)(4) of this 

section.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 
Page 96 of 162 

calibration shall not be considered periods of excess emissions. Malfunctions may include 

process unit, control device, or monitoring system malfunctions.

(7) If a performance test for determination of compliance for a new emission point subject to this 

subpart or for an emission point that has changed from Group 2 to Group 1 is conducted during 

the period covered by a Periodic Report, the results of the performance test shall be included in 

the Periodic Report. 

(i) Results of the performance test shall include the identification of the source tested, the date 

of the test, the percentage of emissions reduction or outlet pollutant concentration reduction 

(whichever is needed to determine compliance) for each run and for the average of all runs, 

and the values of the monitored operating parameters. 

(ii) The complete test report shall be maintained onsite. 

(8) The owner or operator of a source shall submit quarterly reports for all emission points 

included in an emissions average. 

(i) The quarterly reports shall be submitted no later than 60 calendar days after the end of each 

quarter. The first report shall be submitted with the Notification of Compliance Status report no 

later than 150 days after the compliance date specified in §63.640. 

(ii) The quarterly reports shall include: 

(A) The information specified in this paragraph and in paragraphs (g)(2) through (g)(7) of this 

section for all storage vessels and miscellaneous process vents included in an emissions average; 

(B) The information required to be reported by §63.428 (h)(1), (h)(2), and (h)(3) for each 

gasoline loading rack included in an emissions average, unless this information has already been 

submitted in a separate report; 

(C) The information required to be reported by §63.567(e)(4) and (j)(3) of subpart Y for each 

marine tank vessel loading operation included in an emissions average, unless the information 

has already been submitted in a separate report; 

(D) Any information pertaining to each wastewater stream included in an emissions average that 

the source is required to report under the Implementation Plan for the source; 

(E) The credits and debits calculated each month during the quarter; 

(F) A demonstration that debits calculated for the quarter are not more than 1.30 times the credits 

calculated for the quarter, as required under §§63.652(e)(4); 

(G) The values of any inputs to the credit and debit equations in §63.652 (g) and (h) that change 

from month to month during the quarter or that have changed since the previous quarter; and 
Page 97 of 162 

(H) Any other information the source is required to report under the Implementation Plan for the 

source. 

(iii) Every fourth quarterly report shall include the following: 

(A) A demonstration that annual credits are greater than or equal to annual debits as required by 

§63.652(e)(3); and 

(B) A certification of compliance with all the emissions averaging provisions in §63.652 of this 

subpart. 

(9) For heat exchange systems, Periodic Reports must include the following information: 

(i) The number of heat exchange systems at the plant site subject to the monitoring requirements 

in §63.654. 

(ii) The number of heat exchange systems at the plant site found to be leaking. 

(iii) For each monitoring location where the total strippable hydrocarbon concentration was 

determined to be equal to or greater than the applicable leak definitions specified in 

§ 63.654(c)(6), identification of the monitoring location (e.g., unique monitoring location or heat 

exchange system ID number), the measured total strippable hydrocarbon concentration, the date 

the leak was first identified, and, if applicable, the date the source of the leak was identified; 

(iv) For leaks that were repaired during the reporting period (including delayed repairs), 

identification of the monitoring location associated with the repaired leak, the total strippable 

hydrocarbon concentration measured during re-monitoring to verify repair, and the re-monitoring 

date (i.e., the effective date of repair); and 

(v) For each delayed repair, identification of the monitoring location associated with the leak for 

which repair is delayed, the date when the delay of repair began, the date the repair is expected to 

be completed (if the leak is not repaired during the reporting period), the total strippable 

hydrocarbon concentration and date of each monitoring event conducted on the delayed repair 

during the reporting period, and an estimate of the potential strippable hydrocarbon emissions 

over the reporting period associated with the delayed repair. 

(10) For relief valves, Periodic Reports must include the information specified in 

paragraphs (g)(10)(i) through (iii) of this section. 

(i) For relief valves in organic HAP gas or vapor service, pursuant to §63.648(j), report any 

instrument reading of 500 ppm or greater, more than 5 days after the relief valve returns 

to service after a pressure release. 

(ii) For relief valves in organic HAP gas or vapor service subject to §63.648(j)(2), report 

confirmation that all monitoring to show compliance was conducted within the reporting 

period. 
Page 98 of 162 

(iii) For relief valves in organic HAP service, report each pressure release to the 

atmosphere, including duration of the pressure release and estimate of quantity of 

substances released. 

(11) For flares subject to §63.670, Periodic Reports must include the information specified 

in paragraphs (g)(11)(i) through (iii) of this section. 

(i) Records as specified in paragraph (i)(9)(i) of this section for each period when regulated 

material is routed to a flare and a pilot flame is not present. 

(ii) Visible emission records as specified in paragraph (i)(9)(ii) of this section for each 

period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes. 

(iii) The 15-minute block periods for which the applicable operating limits specified in 

§63.670(d) through (f) are not met. Indicate the date and time for the period, the 15-minute 

block average operating parameters determined following the methods in §63.670(k) 

through (o) as applicable, and an indication of whether the three criteria in §63.670(e)(vi) 

were all met for that 15-minute 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]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

(2) For storage vessels, notifications of inspections as specified in paragraphs (h)(2)(i) and 

(h)(2)(ii) of this section;.

(i) In order to afford the Administrator the opportunity to have an observer present, the owner or 

operator shall notify the Administrator of the refilling of each Group 1 storage vessel that has 

been emptied and degassed. 
Page 99 of 162 

(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. 

(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 of this partor 

§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’s, the 

owner or operator shall notify the Administrator at least 7 calendar days prior to refilling of the 

storage vessel. Notification may be made by telephone and immediately followed by written 

documentation demonstrating why the inspection was unplanned. This notification, including the 

written documentation, may also be made in writing and sent so that it is received by the 

Administrator at least 7 calendar days prior to the refilling. 

(C) The State or local permitting authority can waive the notification requirements of paragraphs 

(h)(2)(i)(A) and/or (h)(2)(i)(B) of this section for all or some storage vessels at petroleum 

refineries subject to this subpart. The State or local permitting authority may also grant 

permission to refill storage vessels sooner than 30 days after submitting the notification required 

by paragraph (h)(2)(i)(A) of this section, or sooner than 7 days after submitting the notification 

required by paragraph (h)(2)(i)(B) of this section for all storage vessels, or for individual storage 

vessels on a case-by-case basis. 

(ii) In order to afford the Administrator the opportunity to have an observer present, the owner or 

operator of a storage vessel equipped with an external floating roof shall notify the Administrator 

of any seal gap measurements. The notification shall be made in writing at least 30 calendar days 

in advance of any gap measurements required by §63.120 (b)(1) or (b)(2) of subpart G or 

§63.1062(d)(3) of this partsubpart WW. The State or local permitting authority can waive this 

notification requirement for all or some storage vessels subject to the rule or can allow less than 

30 calendar days’ notice. 

(3) For owners or operators of sources required to request approval for a nominal control 

efficiency for use in calculating credits for an emissions average, the information specified in 

§63.652(h). 

(4) The owner or operator who requests approval to monitor a different parameter than those 

listed in §63.644 for miscellaneous process vents or who is required by §63.653(a)(8) to establish 

a site-specific monitoring parameter for a point in an emissions average shall submit the 

information specified in paragraphs (h)(4)(i) through (h)(4)(iii) of this section. For new or 

reconstructed sources, the information shall be submitted with the application for approval of 

construction or reconstruction required by §63.5(d) of subpart A and for existing sources, and the 

information shall be submitted no later than 18 months prior to the compliance date. The 

information may be submitted in an operating permit application, in an amendment to an 

operating permit application, or in a separate submittal. 
Page 100 of 162 

(i) A description of the parameter(s) to be monitored to determine whether excess emissions 

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

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

parameter can be used to determine excess emissions and the schedule for this demonstration. 

The owner or operator must certify that they will establish a range for the monitored parameter 

as part of the Notification of Compliance Status report required in paragraphs (e) and (f) of this 

section. 

(iii) The frequency and content of monitoring, recording, and reporting if: monitoring and 

recording are not continuous; or if periods of excess emissions, as defined in paragraph (g)(6) of 

this section, will not be identified in Periodic Reports required under paragraphs (e) and (g) of 

this section. The rationale for the proposed monitoring, recording, and reporting system shall be 

included. 

(5) An owner or operator may request approval to use alternatives to the continuous operating 

parameter monitoring and recordkeeping provisions listed in paragraph (i) of this section. 

(i) Requests shall be submitted with the Application for Approval of Construction or 

Reconstruction for new sources and no later than 18 months prior to the compliance date for 

existing sources. The information may be submitted in an operating permit application, in an 

amendment to an operating permit application, or in a separate submittal. Requests shall contain 

the information specified in paragraphs (h)(5)(iii) through (h)(5)(iv) of this section, as applicable. 

(ii) The provisions in §63.8(f)(5)(i) of subpart A of this part shall govern the review and approval 

of requests. 

(iii) An owner or operator may request approval to use an automated data compression recording 

system that does not record monitored operating parameter values at a set frequency (for 

example, once every hour) but records all values that meet set criteria for variation from 

previously recorded values. 

(A) The requested system shall be designed to: 

(1) Measure the operating parameter value at least once every hour. 

(2) Record at least 24 values each day during periods of operation. 

(3) Record the date and time when monitors are turned off or on. 

(4) Recognize unchanging data that may indicate the monitor is not functioning properly, alert 

the operator, and record the incident. 

(5) Compute daily average values of the monitored operating parameter based on recorded data. 
Page 101 of 162 

(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. 

(iv) An owner or operator may request approval to use other alternative monitoring systems 

according to the procedures specified in §63.8(f) of subpart A of this part. 

(6) The owner or operator shall submit the information specified in paragraphs (h)(6)(i) through 

(h)(6)(iii) of this section, as applicable. For existing sources, this information shall be submitted 

in the initial Notification of Compliance Status report. For a new source, the information shall be 

submitted with the application for approval of construction or reconstruction required by 

§63.5(d) of subpart A of this part. The information may be submitted in an operating permit 

application, in an amendment to an operating permit application, or in a separate submittal. 

(i) The determination of applicability of this subpart to petroleum refining process units that are 

designed and operated as flexible operation units. 

(ii) The determination of applicability of this subpart to any storage vessel for which use varies 

from year to year. 

(iii) The determination of applicability of this subpart to any distillation unit for which use varies 

from year to year. 

(7) The owner or operator of a heat exchange system at an existing source must notify the 

Administrator at least 30 calendar days prior to changing from one of the monitoring options 

specified in §63.654(c)(4) to the other. 

(8) For fenceline monitoring systems subject to §63.658, within 45 calendar days after the 

end of each semiannual reporting period, each owner or operator shall submit the 

following information to the EPA’s Compliance and Emissions Data Reporting Interface 

(CEDRI) that is accessed through the EPA’s Central Data Exchange (CDX) 

(www.epa.gov/cdx). The owner or operator need not transmit this data prior to obtaining 

12 months of data. 

(i) Individual sample results for each monitor for each sampling episode during the 

semiannual reporting period. For the first reporting period and for any period in which a 

passive monitor is added or moved, the owner or operator shall report the coordinates of 

all of the passive monitor locations. The owner or operator shall determine the coordinates 

using an instrument with an accuracy of at least 3 meters. Coordinates shall be in decimal 

degrees with at least five decimal places. 

(ii) The biweekly 12-month rolling average concentration difference (Δc) values for benzene 

for the semiannual reporting period. 
Page 102 of 162 

(iii) Notation for each biweekly value that indicates whether background correction was 

used, all measurements in the sampling period were below detection, or whether an outlier 

was removed from the sampling period data set. 

(9) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], if required to submit the results of a 

performance test or CEMS performance evaluation, the owner or operator shall submit the 

results using EPA’s Electronic Reporting Tool (ERT) according to the procedures in 

paragraphs (h)(9)(i) and (ii) of this section. 

(i) Within 60 days after the date of completing each performance test as required by this 

subpart, the owner or operator shall submit the results of the performance tests according 

to the method specified by either paragraph (h)(9)(i)(A) or (h)(9)(i)(B) of this section. 

(A) For data collected using test methods supported by the EPA’s ERT as listed on the 

EPA’s ERT website (http://www.epa.gov/ttn/chief/ert/index.html), the owner or operator 

must submit the results of the performance test to the CEDRI accessed through the EPA’s 

CDX (http://cdx.epa.gov/epa_home.asp), unless the Administrator approves another 

approach. Performance test data must be submitted in a file format generated through the 

use of the EPA’s ERT. If an owner or operator claims that some of the performance test 

information being submitted is confidential business information (CBI), the owner or 

operator must submit a complete file generated through the use of the EPA’s ERT, 

including information claimed to be CBI, on a compact disc or other commonly used 

electronic storage media (including, but not limited to, flash drives) by registered letter to 

the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. 

EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be 

submitted to the EPA via CDX as described earlier in this paragraph. 

(B) For data collected using test methods that are not supported by the EPA’s ERT as 

listed on the EPA’s ERT website, the owner or operator must submit the results of the 

performance test to the Administrator at the appropriate address listed in §63.13. 

(ii) Within 60 days after the date of completing each CEMS performance evaluation as 

required by this subpart, the owner or operator must submit the results of the performance 

evaluation according to the method specified by either paragraph (h)(9)(ii)(A) or 

(h)(9)(ii)(B) of this section. 

(A) For data collection of relative accuracy test audit (RATA) pollutants that are supported 

by the EPA’s ERT as listed on the ERT website, the owner or operator must submit the 

results of the performance evaluation to the CEDRI that is accessed through the EPA’s 

CDX, unless the Administrator approves another approach. Performance evaluation data 

must be submitted in a file format generated through the use of the EPA’s ERT. If an 

owner or operator claims that some of the performance evaluation information being 

submitted is CBI, the owner or operator must submit a complete file generated through the 

use of the EPA’s ERT, including information claimed to be CBI, on a compact disc or other 
Page 103 of 162 

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 any performance evaluation data with RATA pollutants that are not supported by 

the EPA’s ERT as listed on the EPA’s ERT website, the owner or operator must submit the 

results of the performance evaluation to the Administrator at the appropriate address 

listed in §63.13. 

(i) Recordkeeping. Each owner or operator of a source subject to this subpart shall keep 

copies of all applicable reports and records required by this subpart for at least 5 years 

except as otherwise specified in paragraphs (i)(1) through (11) of this section. All applicable 

records shall be maintained in such a manner that they can be readily accessed within 24 hours. 

Records may be maintained in hard copy or computer-readable form including, but not limited 

to, on paper, microfilm, computer, flash drive, floppy disk, magnetic tape, or microfiche. 

(1) Each owner or operator subject to the storage vessel provisions in §63.646 shall keep the 

records specified in §63.123 of subpart G of this part except as specified in paragraphs (i)(1)(i) 

through (i)(1)(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. 
Page 104 of 162 

(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. 

(3) Each owner or operator required to continuously monitor operating parameters under §63.644 

for miscellaneous process vents or under §§63.652 and 63.653 for emission points in an 

emissions average shall keep the records specified in paragraphs (i)(3)(i) through (i)(3)(v) of this 

section unless an alternative recordkeeping system has been requested and approved under 

paragraph (h) of this section. 

(i) The monitoring system shall measure data values at least once every hour. 

(ii) The owner or operator shall record either: 

(A) Each measured data value; or 

(B) Block average values for 1 hour or shorter periods calculated from all measured data values 

during each period. If values are measured more frequently than once per minute, a single value 

for each minute may be used to calculate the hourly (or shorter period) block average instead of 

all measured values. 

(iii) Daily average values of each continuously monitored parameter shall be calculated for each 

operating day and retained for 5 years except as specified in paragraph (i)(3)(iv) of this section. 

(A) The daily average shall be calculated as the average of all values for a monitored parameter 

recorded during the operating day. The average shall cover a 24-hour period if operation is 

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

(B) The operating day shall be the period defined in the Notification of Compliance Status 

report. It may be from midnight to midnight or another daily period. 

(iv) If all recorded values for a monitored parameter during an operating day are within the range 

established in the Notification of Compliance Status report, the owner or operator may record 

that all values were within the range and retain this record for 5 years rather than calculating and 

recording a daily average for that day. For these days, the records required in paragraph (i)(3)(ii) 

of this section shall also be retained for 5 years. 

(v) Monitoring data recorded during periods of monitoring system breakdowns, repairs, 

calibration checks, and zero (low-level) and high-level adjustments shall not be included in any 

average computed under this subpart. Records shall be kept of the times and durations of all such 

periods and any other periods during process or control device operation when monitors are not 

operating. 

(4) For each closed vent system that contains bypass lines that could divert a vent stream 

away from the control device and to the atmosphere, or cause air intrusion into the control 
Page 105 of 162 

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. 

(i) The owner or operator shall maintain records of any alarms triggered because flow was 

detected in the bypass line, including the date and time the alarm was triggered and the 

duration of the flow in the bypass line. The owner or operator shall also maintain records 

of all periods when the vent stream is diverted from the control device or air intrudes into 

the control device. The owner or operator shall include an estimate of the volume of gas, 

the concentration of organic HAP in the gas and the resulting emissions of organic HAP 

that bypassed the control device. 

(ii) Where a seal mechanism is used to comply with §63.644(c)(2), hourly records of flow 

are not required. In such cases, the owner or operator shall record the date that the 

monthly visual inspection of the seals or closure mechanisms is completed. The owner or 

operator shall also record the occurrence of all periods when the seal or closure mechanism 

is broken, the bypass line valve position has changed or the key for a lock-and-key type 

lock has been checked out. The owner or operator shall include an estimate of the volume 

of gas, the concentration of organic HAP in the gas and the resulting emissions of organic 

HAP that bypassed the control device. 

(5) The owner or operator of a heat exchange system subject to this subpart shall comply with 

the recordkeeping requirements in paragraphs (i)(45)(i) through (v) of this section and retain 

these records for 5 years. 

(i) Identification of all petroleum refinery process unit heat exchangers at the facility and the 

average annual HAP concentration of process fluid or intervening cooling fluid estimated when 

developing the Notification of Compliance Status report. 

(ii) Identification of all heat exchange systems subject to the monitoring requirements in §63.654 

and identification of all heat exchange systems that are exempt from the monitoring requirements 

according to the provisions in §63.654(b). For each heat exchange system that is subject to the 

monitoring requirements in §63.654, this must include identification of all heat exchangers 

within each heat exchange system, and, for closed-loop recirculation systems, the cooling tower 

included in each heat exchange system. 

(iii) Results of the following monitoring data for each required monitoring event: 

(A) Date/time of event. 

(B) Barometric pressure. 

(C) El Paso air stripping apparatus water flow milliliter/minute (ml/min) and air flow, ml/min, 

and air temperature, °Celsius. 

(D) FID reading (ppmv). 
Page 106 of 162 

(E) Length of sampling period. 

(F) Sample volume. 

(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. 

(56) All other information required to be reported under paragraphs (a) through (h) of this 

section shall be retained for 5 years. 

(7) Each owner or operator subject to the delayed coking unit decoking operations 

provisions in §63.657 must maintain records of the average pressure for the 5-minute 

period prior to venting to the atmosphere, draining, or deheading the coke drum for each 

cooling cycle for each coke drum. 

(8) For fenceline monitoring systems subject to §63.658, each owner or operator shall keep 

the records specified in paragraphs (i)(8)(i) through (ix) of this section on an ongoing basis. 

(i) Coordinates of all passive monitors, including replicate samplers and field blanks, and 

the meteorological station. The owner or operator shall determine the coordinates using an 

instrument with an accuracy of at least 3 meters. The coordinates shall be in decimal 

degrees with at least five decimal places. 

(ii) The start and stop times and dates for each sample, as well as the tube identifying 

information. 

(iii) Daily unit vector wind direction, calculated daily sigma theta, daily average 

temperature and daily average barometric pressure measurements. 

(iv) For each outlier determined in accordance with Section 9.2 of Method 325A of 

Appendix A of this part, the sampler location of and the concentration of the outlier and 

the evidence used to conclude that the result is an outlier. 
Page 107 of 162 

(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. 

(vi) Individual sample results, the calculated Δc for benzene for each sampling episode and 

the two samples used to determine it, whether background correction was used, and the 12-

month rolling average Δc calculated after each sampling episode. 

(vii) Method detection limit for each sample, including co-located samples and blanks. 

(viii) Documentation of corrective action taken each time the action level was exceeded. 

(ix) Other records as required by Methods 325A and 325B of Appendix A of this part. 

(9) For each flare subject to §63.670, each owner or operator shall keep the records 

specified in paragraphs (i)(9)(i) through (vii) of this section up-to-date and readily 

accessible, as applicable. 

(i) Retain records of the output of the monitoring device used to detect the presence of a 

pilot flame as required in §63.670(b) for a minimum of 2 years. Retain records of periods 

during which the pilot flame is not present when regulated material is routed to a flare for 

a minimum of 5 years. 

(ii) Daily visible emissions observations, as required in §63.670(c), as well as any 

observations required in §63.670(h). The record must identify whether the visible emissions 

observation was performed, the results of each observation, total duration of observed 

visible emissions, and whether it was a 5-minute or 2-hour observation. If the owner or 

operator performs visible emissions observations more than one time during a day, the 

record must also identify the date and time of day each visible emissions observation was 

performed. 

(iii) The 15-minute block average cumulative flows for flare vent gas and, if applicable, 

total steam, perimeter assist air, and premix assist air specified to be monitored under 

§63.670(i), along with the date and time interval for the 15-minute block. If multiple 

monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter 

assist air, and premix assist air, retain records of the 15-minute block average flows for 

each monitoring location for a minimum of 2 years, and retain the 15-minute block average 

cumulative flows that are used in subsequent calculations for a minimum of 5 years. If 

pressure and temperature monitoring is used, retain records of the 15-minute block 

average temperature, pressure and molecular weight of the flare vent gas or assist gas 

stream for each measurement location used to determine the 15-minute block average 

cumulative flows for a minimum of 2 years, and retain the 15-minute block average 

cumulative flows that are used in subsequent calculations for a minimum of 5 years. 

(iv) The flare vent gas compositions specified to be monitored under §63.670(j). Retain 

records of individual component concentrations from each compositional analyses for a 
Page 108 of 162 

minimum of 2 years. If NHVvg or total hydrocarbon analyzer is used, retain records of the 

15-minute block average values for a minimum of 5 years. 

(v) Each 15-minute block average operating parameter calculated following the methods 

specified in §63.670(k) through (m), as applicable. 

(vi) The 15-minute block average olefins, hydrogen, and olefins plus hydrogen 

concentration in the combustion zone used to determine if the criteria in §63.670(e)(4) are 

met. If process knowledge and engineering calculations are used, retain records of the 

information used in the assessment and records of all compositional analyses required in 

§63.670(o)(ii). Identify all 15-minute block averages for which all three criteria in 

§63.670(e)(4) are met or are assumed to be met. 

 (vii) All periods during which operating values are outside of the applicable operating 

limits specified in §63.670(d) through (f) when regulated material is being routed to the 

flare. 

(viii) All periods during which the owner or operator does not perform flare monitoring 

according to the procedures in §63.670(g) through (j). 

(ix) Records of periods when there is flow of vent gas to the flare, but when there is no flow 

of regulated material to the flare, including the start and stop time and dates of periods of 

no regulated material flow. 

(x) All periods during which a halogenated vent stream, as defined in §63.641, is discharged 

to the flare. Records shall include the start time and date of the event, the end time and 

date of the event, and an estimate of the cumulative flow of the halogenated vent stream 

over the duration of the event. 

(10) If the owner or operator elects to comply with §63.661, the owner or operator shall 

keep the records described in paragraphs (i)(10)(i) through (v) of this section. 

(i) The equipment and process units for which the owner or operator chooses to use the 

optical gas imaging instrument. 

(ii) All records required by part 60, Appendix K of this chapter, as applicable. 

(iii) A video record to document the leak survey results. The video record must include a 

time and date stamp for each monitoring event. 

(iv) Identification of the equipment screened and the time and date of the screening. 

(v) Documentation of repairs attempted and repairs delayed. If repair of a leak is 

confirmed using the optical gas imaging instrument, then instead of the maximum 

instrument reading measured by Method 21 of part 60, Appendix A–7 of this chapter, the 
Page 109 of 162 

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. 

(ii) For each failure to meet an applicable standard, record and retain a list of the affected 

sources or equipment, an estimate of the volume of each regulated pollutant emitted over 

any emission limit and a description of the method used to estimate the emissions. 

(iii) Record actions taken to minimize emissions in accordance with §63.642(n), and any 

corrective actions taken to return the affected unit to its normal or usual manner of 

operation. 

§ 63.656 Implementation and enforcement. 

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

such as the applicable State, local, or Tribal agency. If the U.S. EPA Administrator has delegated 

authority to a State, local, or Tribal agency, then that agency, in addition to the U.S. EPA, has the 

authority to implement and enforce this subpart. Contact the applicable U.S. EPA Regional 

Office to find out if implementation and enforcement of this subpart is delegated to a State, local, 

or Tribal agency. 

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

Tribal agency under subpart E of this part, the authorities contained in paragraph (c) of this 

section are retained by the Administrator of U.S. EPA and cannot be transferred to the State, 

local, or Tribal agency. 

(c) The authorities that cannot be delegated to Sstate, local, or Tribal agencies are as specified in 

paragraphs (c)(1) through (45) 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 63.654670. Where these standards 

reference another subpart, the cited provisions will be delegated according to the delegation 

provisions of the referenced subpart. Where these standards reference another subpart and 

modify the requirements, the requirements shall be modified as described in this subpart. 

Delegation of the modified requirements will also occur according to the delegation provisions 

of the referenced subpart. 

(2) Approval of major alternatives to test methods under §63.7(e)(2)(ii) and (f), as defined in 

§63.90, and as required in this subpart. 
Page 110 of 162 

(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). 

§ 63.657 Delayed coking unit decoking operation standards. 

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

closed blowdown system until the coke drum vessel pressure is 2 pounds per square inch 

gauge (psig) or less prior to venting to the atmosphere, draining or deheading the coke 

drum at the end of the cooling cycle. 

(b) Each owner or operator of a delayed coking unit shall install, operate, calibrate, and 

maintain a continuous parameter monitoring system to determine the coke drum vessel 

pressure. The pressure monitoring system must be capable of measuring a pressure of 2 

psig within ±0.5 psig. 

(c) The owner or operator of a delayed coking unit shall determine the coke drum vessel 

pressure on a 5-minute rolling average basis while the coke drum is vented to the closed 

blowdown system to demonstrate compliance the requirement in paragraph (a) of this 

section. Pressure readings after initiating steps to isolate the coke drum from the closed 

blowdown system just prior to atmospheric venting, draining, or deheading the coke drum 

shall not be used in determining the average coke drum vessel pressure for the purpose of 

compliance with the requirement in paragraph (a) of this section. 

§ 63.658 Fenceline monitoring provisions. 

(a) The owner or operator shall conduct sampling along the facility property boundary and 

analyze the samples in accordance with Methods 325A and 325B of Appendix A of this 

part. 

(b) The target analyte is benzene. 

(c) The owner or operator shall determine passive monitor locations in accordance with 

Section 8.2 of Method 325A of Appendix A of this part. General guidance for siting passive 

monitors can be found in EPA-454/R-98-004, Quality Assurance Handbook for Air 

Pollution Measurement Systems, Volume II: Part 1: Ambient Air Quality Monitoring 

Program Quality System Development, August 1998 (incorporated by reference—see 

§63.14). Alternatively, the owner or operator may elect to place monitors at 2 kilometers 

intervals as measured along the property boundary, provided additional monitors are 

located, if necessary, as required in Section 8.2.2.5 in Method 325A of Appendix A of this 

part. 
Page 111 of 162 

(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 the site-specific monitoring plant, the background 

sampler(s) should be operated co-currently with the routine samplers. 

(3) The owner or operator shall collect at least one co-located duplicate sample for every 10 

field samples per sampling episode and at least two field blanks per sampling episode, as 

described in Section 9.3 in Method 325A of Appendix A of this part. The co-located 

duplicates may be collected at any one of the perimeter sampling locations. 

(4) The owner or operator shall follow the procedure in Section 9.6 of Method 325B of 

Appendix A of this part to determine the detection limit of benzene for each sampler used 

to collect samples, background samples (if the owner or operator elects to do so), co-located 

samples and blanks. 

(d) The owner or operator shall use a dedicated meteorological station in accordance with 

Section 8.3 of Method 325A of Appendix A of this part. 

(1) The owner or operator shall collect and record hourly average meteorological data, 

including wind speed, wind direction and temperature. 

(2) The owner or operator shall follow the calibration and standardization procedures for 

meteorological measurements in EPA-454/B-08-002, Quality Assurance Handbook for Air 

Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 

(Final), March 2008 (incorporated by reference—see §63.14). 

(e) The length of the sampling episode must be fourteen days, unless a shorter sampling 

episode is determined to be necessary under paragraph (g) or (i) of this section. A sampling 

episode is defined as the period during which the owner or operator collects the sample and 

does not include the time required to analyze the sample. 

(f) Within 30 days of completion of each sampling episode, the owner or operator shall 

determine whether the results are above or below the action level as follows: 

(1) For each sampling episode, the owner or operator shall determine the highest and 

lowest sample results for benzene from the sample pool and calculate the difference in 

concentration (Δc). 
Page 112 of 162 

(i) The owner or operator shall adhere to the following procedures when one or more 

samples for the sampling episode are below the method detection limit for benzene: 

(A) If the lowest detected value of benzene is below detection, the owner or operator shall 

use zero as the lowest sample result when calculating Δc. 

(B) If all sample results are below the method detection limit, the owner or operator shall 

use the method detection limit as the highest sample result. 

(ii) If the owner or operator identifies an offsite upwind source or an onsite source excluded 

under §63.640(g) that contributes to the benzene concentration at any passive monitor and 

collects background samples according to an approved site-specific monitoring plan, the 

owner or operator shall determine Δc using the calculation protocols outlined in the 

approved site-specific monitoring plan and in paragraph (i) of this section. 

(2) The owner or operator shall average the Δc values collected over the twelve months 

prior to and including the most recent sampling episode. The owner or operator shall 

update this value after receiving the results of each sampling episode. 

(3) The action level for benzene is 9 micrograms per cubic meter (μg/m3). If the 12-month 

rolling average Δc value for benzene is less than 9 μg/m3, the concentration is below the 

action level. If the 12-month rolling average Δc value for benzene is equal to or greater 

than 9 μg/m3, the concentration is above the action level, and the owner or operator shall 

conduct a root cause analysis and corrective action in accordance with paragraph (g) of 

this section. 

(g) Within 5 days of determining that the action level has been exceeded for any 12-month 

rolling average and no longer than 35 days after completion of the sampling episode, the 

owner or operator shall initiate a root cause analysis to determine the cause of such 

exceedance and to determine appropriate corrective action, as described in paragraphs 

(g)(1) through (4) of this section. The root cause analysis and corrective action analysis 

shall be completed no later than 45 days after determining there is an exceedance. Root 

cause analysis and corrective action may include, but is not limited to: 

(1) Leak inspection using Method 21 of part 60, Appendix A-7 of this chapter and repairing 

any leaks found. 

(2) Leak inspection using optical gas imaging as specified in §63.661 and repairing any 

leaks found. 

(3) Visual inspection to determine the cause of the high benzene emissions and 

implementing repairs to reduce the level of emissions. 

(4) Employing progressively more frequent sampling, analysis and meteorology (e.g., using 

shorter sampling episodes for Methods 325A and 325B of Appendix A of this part, or using 
Page 113 of 162 

active sampling techniques), or employing additional monitors to determine contributing 

offsite sources. 

(h) If, upon completion of the corrective actions described in paragraph (g) of this section, 

the action level is exceeded for the next sampling episode following the completion of the 

corrective action, the owner or operator shall develop a corrective action plan that 

describes the corrective action(s) completed to date, additional measures that the owner or 

operator proposes to employ to reduce fenceline concentrations below the action level, and 

a schedule for completion of these measures. The owner or operator shall submit the 

corrective action plan to the Administrator within 60 days after determining the action 

level was exceeded during the sampling episode following the completion of the initial 

corrective action. The Administrator shall approve or disapprove the plan in 90 days. The 

plan shall be considered approved if the Administrator either approves the plan in writing, 

or fails to disapprove the plan in writing. The 90-day period shall begin when the 

Administrator receives the plan. 

(i) An owner or operator may request approval from the Administrator for a site-specific 

monitoring plan to account for offsite upwind sources or onsite sources excluded under 

§63.640(g) according to the requirements in paragraphs (i)(1) through (4) of this section. 

(1) The owner or operator shall prepare and submit a site-specific monitoring plan and 

receive approval of the site-specific monitoring plan prior to using the near-field source 

alternative calculation for determining Δc provided in paragraph (i)(2) of this section. The 

site-specific monitoring plan shall include, at a minimum, the elements specified in 

paragraphs (i)(1)(i) through (v) of this section. 

(i) Identification of the near-field source or sources. For onsite sources, documentation that 

the onsite source is excluded under §63.640(g) and identification of the specific provision in 

§63.640(g) that applies to the source. 

(ii) Location of the additional monitoring stations that shall be used to determine the 

uniform background concentration and the near-field source concentration contribution. 

(iii) Identification of the fenceline monitoring locations impacted by the near-field source. 

If more than one near-field source is present, identify for each monitoring location, the 

near field source or sources that are expected to contribute to fenceline concentration at 

that monitoring location. 

(iv) A description of (including sample calculations illustrating) the planned data reduction 

and calculations to determine the near-field source concentration contribution for each 

monitoring location. 

(v) If more frequent monitoring is proposed or if a monitoring station other than a passive 

diffusive tub monitoring station is proposed, provide a detailed description of the 

measurement methods, measurement frequency, and recording frequency proposed for 

determining the uniform background or near-field source concentration contribution. 
Page 114 of 162 

(2) When an approved site-specific monitoring plan is used, the owner or operator shall 

determine Δc for comparison with the 9 μg/m3 action level using the requirements specified 

in paragraphs (2)(i) through (iii) of this section. 

(i) For each monitoring location, calculate Δci using the following equation. 

Δci  MFCi  NFS i UB

where: 

Δci = The fenceline concentration, corrected for background, at measurement location i, 

micrograms per cubic meter (μg/m3). 

MFCi = The measured fenceline concentration at measurement location i, μg/m3. 

NFSi = The near-field source contributing concentration at measurement location i 

determined using the additional measurements and calculation procedures included in the 

site-specific monitoring plan, μg/m3. For monitoring locations that are not included in the 

site-specific monitoring plan as impacted by a near-field source, use NFSi = 0 μg/m3. 

UB = The uniform background concentration determined using the additional 

measurements specified included in the site-specific monitoring plan, μg/m3. If no 

additional measurement location is specified in the site-specific monitoring plan for 

determining the uniform background concentration, use UB = 0 μg/m3. 

(ii) When one or more samples for the sampling episode are below the method detection 

limit for benzene, adhere to the following procedures: 

(A) If the benzene concentration at the monitoring location used for the uniform 

background concentration is below detection, the owner or operator shall use zero for UB 

for that monitoring period. 

(B) If the benzene concentration at the monitoring location(s) used to determine the nearfield source contributing concentration is below detection, the owner or operator shall use 

zero for the monitoring location concentration when calculating NFSi for that monitoring 

period. 

(C) If a fenceline monitoring location sample result is below the method detection limit, the 

owner or operator shall use the method detection limit as the sample result. 

(iii) Determine Δc for the monitoring period as the maximum value of Δci from all of the 

fenceline monitoring locations for that monitoring period. 

(3) The site-specific monitoring plan shall be submitted and approved as described in 

paragraphs (i)(3)(i) through (iv) of this section. 
Page 115 of 162 

(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. 

(iii) 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 

disapprove the plan in writing. The 90-day period shall begin when the Administrator 

receives the plan. 

(iv) If the Administrator finds any deficiencies in the site-specific monitoring plan and 

disapproves the plan in writing, the owner or operator may revise and resubmit the sitespecific monitoring plan following the requirements in paragraphs (i)(3)(i) and (ii) of this 

section. The 90-day period starts over with the resubmission of the revised monitoring 

plan. 

(4) The approval by the Administrator of a site-specific monitoring plan will be based on 

the completeness, accuracy and reasonableness of the request process for a site-specific 

monitoring plan. Factors that the EPA will consider in reviewing the request for a sitespecific monitoring plan include, but are not limited to, those described in paragraphs 

(i)(4)(i) through (v) of this section. 

(i) The identification of the near-field source or sources. For onsite sources, the 

documentation provided that the onsite source is excluded under §63.640(g). 

(ii) The monitoring location selected to determine the uniform background concentration 

or an indication that no uniform background concentration monitor will be used. 

(iii) The location(s) selected for additional monitoring to determine the near-field source 

concentration contribution. 

(iv) The identification of the fenceline monitoring locations impacted by the near-field 

source or sources. 

(v) The appropriateness of the planned data reduction and calculations to determine the 

near-field source concentration contribution for each monitoring location. 

(vi) If more frequent monitoring is proposed or if a monitoring station other than a passive 

diffusive tub monitoring station is proposed, the adequacy of the description of the 

measurement methods, measurement frequency, and recording frequency proposed and 

the adequacy of the rationale for using the alternative monitoring frequency or method. 
Page 116 of 162 

(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. 

(a) As used in this section, all terms not defined in §63.641 shall have the meaning given 

them in subpart A, subpart WW, or subpart SS of this part. The definitions of “Group 1 

storage vessel” (item 2) and “storage vessel” in §63.641 shall apply in lieu of the definition 

of “storage vessel” in §63.1061. 

(1) An owner or operator may use good engineering judgment or test results to determine 

the stored liquid weight percent total organic HAP for purposes of group determination. 

Data, assumptions, and procedures used in the determination shall be documented. 

(2) When an owner or operator and the Administrator do not agree on whether the annual 

average weight percent organic HAP in the stored liquid is above or below 4 percent for a 

storage vessel at an existing source or above or below 2 percent for a storage vessel at a new 

source, an appropriate method (based on the type of liquid stored) as published by EPA or 

a consensus-based standards organization shall be used. Consensus-based standards 

organizations include, but are not limited to, the following: ASTM International (100 Barr 

Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B2959, (800) 

262–1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L 

Street, NW., 6th floor, Washington, DC 20036, (202) 293–8020, http://www.ansi.org), the 

American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, 

DC 20001, (202) 824–7000, http://www.aga.org), the American Society of Mechanical 

Engineers (ASME, Three Park Avenue, New York, NY 10016–5990, (800) 843–2763, 

http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., 

Washington, DC 20005–4070, (202) 682–8000, http://www.api.org), and the North 

American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 

77002, (713) 356–0060, http://www.naesb.org). 

(b) In addition to the options presented in §§63.1063(a)(2)(vii)(A), 63.1063(a)(2)(vii)(B), and 

63.1064, an external floating roof storage vessel may comply with §63.1063(a)(2)(vii) using 

a flexible enclosure system as described in item 6 of Appendix I: Acceptable Controls for 

Slotted Guidepoles Under the Storage Tank Emissions Reduction Partnership Program 

(available at http://www.epa.gov/ttn/atw/petrefine/petrefpg.html). 
Page 117 of 162 

(c) For the purposes of this subpart, references shall apply as specified in paragraphs (c)(1) 

through (6) of this section. 

(1) All references to “the proposal date for a referencing subpart” and “the proposal date 

of the referencing subpart” in subpart WW of this part mean [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. 

(2) All references to “promulgation of the referencing subpart” and “the promulgation date 

of the referencing subpart” in subpart WW of this part mean [THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER]. 

(3) All references to “promulgation date of standards for an affected source or affected 

facility under a referencing subpart” in subpart SS of this part mean [THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER]. 

(4) All references to “the proposal date of the relevant standard established pursuant to 

CAA section 112(f)” in subpart SS of this part mean [INSERT DATE OF PUBLICATION 

IN THE FEDERAL REGISTER]. 

(5) All references to “the proposal date of a relevant standard established pursuant to CAA 

section 112(d)” in subpart SS of this part mean July 14, 1994. 

(6) All references to the “required control efficiency” in subpart SS of this part mean 

reduction of organic HAP emissions by 95 percent or to an outlet concentration of 20 

ppmv. 

(d) For an existing storage vessel fixed roof that meets the definition of Group 1 storage 

vessel (item 2) in §63.641 but not the definition of Group 1 storage vessel (item 1) in 

§63.641, the requirements of §63.1062 do not apply until the next time the storage vessel is 

completely emptied and degassed, or [THE DATE 10 YEARS AFTER PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], whichever occurs 

first. 

(e) Failure to perform inspections and monitoring required by this section shall constitute a 

violation of the applicable standard of this subpart. 

(f) References in §63.1066(a) to initial startup notification requirements do not apply. 

(g) References to the Notification of Compliance Status in §63.999(b) mean the Notification 

of Compliance Status required by §63.655(f). 

(h) References to the Periodic Reports in §§63.1066(b) and 63.999(c) mean the Periodic 

Report required by §63.655(g). 
Page 118 of 162 

(i) Owners or operators electing to comply with the requirements in subpart SS of this part 

for a Group 1 storage vessel must comply with the requirements in paragraphs (c)(1) 

through (3) of this section. 

(1) 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. 

(2) If a closed vent system contains a bypass line, the owner or operator shall comply with 

the provisions of either §63.985(a)(3)(i) or §63.985(a)(3)(ii) for each closed vent system that 

contains bypass lines that could divert a vent stream to the atmosphere. Use of the bypass 

at any time to divert a Group 1 storage vessel to the atmosphere is an emissions standards 

violation. Equipment such as low leg drains and equipment subject to §63.648 are not 

subject to this paragraph. 

(3) If storage vessel emissions are routed to a fuel gas system or process, the fuel gas system 

or process shall be operating at all times when regulated emissions are routed to it. The 

exception in §63.984(a)(1) does not apply. 

§ 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. 

(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. 
Page 119 of 162 

(2) The owner or operator shall repair leaking equipment as required in the applicable 

section of part 60, subpart VV of this chapter or subpart H of this part. 

(3) Monitoring to confirm repair of leaking equipment must be conducted using the 

procedures referenced in paragraph (a)(2) of this section. 

(c) Recordkeeping. The owner or operator shall comply with the applicable requirements in 

§63.655(i). 

§§ 63.662-63.669 [Reserved] 

§ 63.670 Requirements for flare control devices. 

On or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the owner or operator 

of a flare used as a control device for an emission point subject to this subpart shall meet 

the applicable requirements for flares as specified in paragraphs (a) through (q) of this 

section and the applicable requirements in §63.671. The owner or operator may elect to 

comply with the requirements of paragraph (r) of this section in lieu of the requirements in 

paragraphs (d) through (f) 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 (g) of this 

section. 

(c) Visible emissions. Each flare must be designed for and operated with no visible 

emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive 

hours. The owner or operator shall monitor for visible emissions from the flare as specified 

in paragraph (h) 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-place. If a total hydrocarbon analyzer is used for compositional analysis as allowed 

under section (j)(4) of this section, then the owner or operator must comply with paragraph 

(d)(1) of this section. 

(1) Except as provided in paragraph (d)(2) of this section, the actual flare tip velocity (Vtip) 

must be less than 60 feet per second when regulated material is being routed to the flare. 

The owner or operator shall monitor Vtip using the procedures specified in paragraph (i) 

and (k) of this section. 
Page 120 of 162 

(2) Vtip must be less than 400 feet per second and also less than the maximum allowed flare 

tip velocity (Vmax) as calculated according to the following equation at all times regulated 

material is being routed to the flare. The owner or operator shall monitor Vtip using the 

procedures specified in paragraph (i) and (k) of this section and monitor gas composition 

and determine NHVvg using the procedures specified in paragraphs (j) and (l) of this 

section. 

  850

1,212

10

  vg

max

NHV

Log V

where: 

Vmax = Maximum allowed flare tip velocity, ft/sec. 

NHVvg = Net heating value of flare vent gas, as determined by paragraph (l)(4) of this 

section, Btu/scf. 

1,212 = Constant. 

850 = Constant. 

(e) Target combustion zone gas properties. For each flare, the owner or operator shall 

comply with the applicable requirements in either paragraph (e)(1), (2), or (3) of this 

section. The owner or operator may elect to comply with any of these applicable 

requirements at any time (e.g., may elect to comply with the requirements in paragraph 

(e)(1) during certain flow conditions and comply with the requirements in paragraph (e)(2) 

or (e)(3) under different flow conditions) provided that the owner or operator has the 

appropriate monitoring equipment to determine compliance with the specified 

requirement. 

(1) The net heating value of flare combustion zone gas (NHVcz) must be greater than or 

equal to the target values in paragraphs (e)(1)(i) or (ii), as applicable, when regulated 

material is being routed to the flare. The owner or operator shall monitor and calculate 

NHVcz as specified in paragraph (m) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

NHVcz value is 380 British thermal units per standard cubic feet (Btu/scf). 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target NHVcz value is 270 Btu/scf. 

(2) The lower flammability limit of the combustion zone gas (LFLcz) must be less than or 

equal to the target values in paragraphs (e)(2)(i) or (ii), as applicable, when regulated 

material is being routed to the flare. The owner or operator shall monitor and calculate 

LFLcz as specified in paragraph (m) of this section. 
Page 121 of 162 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

LFLcz value is 0.11 volume fraction. 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target LFLcz value is 0.15 volume fraction. 

(3) The total volumetric fraction of hydrogen and combustible organic components present 

in the combustion zone gas (Ccz), as propane, must be greater than or equal to the target 

values in paragraphs (e)(3)(i) or (ii), as applicable, when regulated material is being routed 

to the flare. The owner or operator shall monitor and calculate Ccz as specified in 

paragraph (m) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

Ccz value is 0.23 volume fraction as propane. 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target Ccz value is 0.18 volume fraction as propane. 

(4) More stringent combustion zone gas target properties apply only during those flare flow 

periods when all three conditions in paragraphs (e)(4)(i) through (iii) simultaneously exist. 

The owner or operator shall monitor and calculate hydrogen and cumulative olefin 

combustion zone concentrations as specified in paragraph (o) of this section: 

(i) The concentration of hydrogen in the combustion zone is greater than 1.2 percent by 

volume. 

(ii) The cumulative concentration of olefins in the combustion zone is greater than 2.5 

percent by volume. 

(iii) The cumulative concentration of olefins in the combustion zone plus the concentration 

of hydrogen in the combustion zone is greater than 7.4 percent by volume. 

(f) Target dilution parameters for flares with perimeter assist air. For each flare actively 

receiving perimeter assist air, the owner or operator shall comply with the applicable 

requirements in either paragraph (f)(1), (2), or (3) of this section in addition to complying 

with the target combustion zone gas properties as specified in paragraph (e) of this section. 

The owner or operator may elect to comply with any of these applicable requirements at 

any time (e.g., may elect to comply with the requirements in paragraph (f)(1) during 

certain flow conditions and comply with the requirements in paragraph (f)(2) or (f)(3) 

under different flow conditions) provided that the owner or operator has the appropriate 

monitoring equipment to determine compliance with the specified requirement. 

(1) The net heating value dilution parameter (NHVdil) must be greater than or equal to the 

target values in paragraphs (f)(1)(i) or (ii), as applicable, when regulated material is being 

routed to the flare. The owner or operator shall monitor and calculate NHVdil as specified 

in paragraph (n) of this section. 
Page 122 of 162 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

NHVdil value is 31 British thermal units per square foot (Btu/ft2). 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target NHVdil value is 22 Btu/ft2. 

(2) The lower flammability limit dilution parameter (LFLdil) must be less than or equal to 

the target values in paragraphs (f)(2)(i) or (ii), as applicable, when regulated material is 

being routed to the flare. The owner or operator shall monitor and calculate LFLdil as 

specified in paragraph (n) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

LFLdil value is 1.6 volume fraction per foot (volume fraction/ft). 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target LFLdil value is 2.2 volume fraction/ft. 

(3) The combustibles concentration dilution parameter (Cdil) must be greater than or equal 

to the target values in paragraphs (f)(3)(i) or (ii), as applicable, when regulated material is 

being routed to the flare. The owner or operator shall monitor and calculate Cdil as 

specified in paragraph (n) of this section. 

(i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target 

Cdil value is 0.015 volume fraction-ft. 

(ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this 

section, the target Ccz value is 0.012 volume fraction-ft. 

(g) Pilot flame monitoring. The owner or operator shall continuously monitor the presence 

of the pilot flame(s) using a device (including, but not limited to, a thermocouple, 

ultraviolet beam sensor, or infrared sensor) capable of detecting that the pilot flame(s) is 

present. 

(h) Visible emissions monitoring. The owner or operator shall monitor visible emissions 

while regulated materials are vented to the flare. An initial visible emissions demonstration 

must be conducted using an observation period of 2 hours using Method 22 at 40 CFR part 

60, Appendix A-7. Subsequent visible emissions observations must be conducted at a 

minimum of once per day using an observation period of 5 minutes using Method 22 at 40 

CFR part 60, Appendix A-7. If at any time the owner or operator sees visible emissions, 

even if the minimum required daily visible emission monitoring has already been 

performed, the owner or operator shall immediately begin an observation period of 5 

minutes using Method 22 at 40 CFR part 60, Appendix A-7. If visible emissions are 

observed for more than one continuous minute during any 5-minute observation period, 

the observation period using Method 22 at 40 CFR part 60, Appendix A-7 must be 

extended to 2 hours. 
Page 123 of 162 

(i) Flare vent gas, steam assist and air assist flow rate monitoring. The owner or operator 

shall install, operate, calibrate, and maintain a monitoring system capable of continuously 

measuring, calculating, and recording the volumetric flow rate in the flare header or 

headers that feed the flare. If assist air or assist steam is used, the owner or operator shall 

install, operate, calibrate, and maintain a monitoring system capable of continuously 

measuring, calculating, and recording the volumetric flow rate of assist air and/or assist 

steam used with the flare. If pre-mix assist air and perimeter assist are both used, the 

owner or operator shall install, operate, calibrate, and maintain a monitoring system 

capable of separately measuring, calculating, and recording the volumetric flow rate of 

premix assist air and perimeter assist air used with the flare. 

(1) The flow rate monitoring systems must be able to correct for the temperature and 

pressure of the system and output parameters in standard conditions (i.e., a temperature of 

20 °C [68 °F] and a pressure of 1 atm). The flare vent gas flow rate monitoring system(s) 

must also be able to output flow in actual conditions for use in the flare tip velocity 

calculation. 

(2) Mass flow monitors may be used for determining volumetric flow rate of flare vent gas 

provided the molecular weight of the flare vent gas is determined using compositional 

analysis as specified in paragraph (j) of this section so that the mass flow rate can be 

converted to volumetric flow at standard conditions using the following equation. 

MWt

Q Q mass

vol

 385.3 

where: 

Qvol = Volumetric flow rate, standard cubic feet per second. 

Qmass = Mass flow rate, pounds per second. 

385.3 = Conversion factor, standard cubic feet per pound-mole. 

MWt = Molecular weight of the gas at the flow monitoring location, pounds per poundmole. 

(3) Mass flow monitors may be used for determining volumetric flow rate of assist air or 

assist steam. Use equation in paragraph (i)(2) of this section to convert mass flow rates to 

volumetric flow rates. Use a molecular weight of 18 pounds per pound-mole for assist 

steam and use a molecular weight of 29 pounds per pound-mole for assist air. 

(4) Continuous pressure/temperature monitoring system(s) and appropriate engineering 

calculations may be used in lieu of a continuous volumetric flow monitoring systems 

provided the molecular weight of the gas is known. For assist steam, use a molecular weight 

of 18 pounds per pound-mole. For assist air, use a molecular weight of 29 pounds per 
Page 124 of 162 

pound-mole. For flare vent gas, molecular weight must be determined using compositional 

analysis as specified in paragraph (j) of this section. 

(j) Flare vent gas composition monitoring. The owner or operator shall determine the 

concentration of individual components in the flare vent gas using either the methods 

provided in paragraphs (j)(1) or (j)(2) of this section, to assess compliance with the 

operating limits in paragraph (e) of this section and, if applicable, paragraphs (d) and (f) of 

this section. Alternatively, the owner or operator may elect to directly monitor the net 

heating value of the flare vent gas following the methods provided in paragraphs (j)(3) of 

this section or the combustibles concentration following the methods provided in 

paragraphs (j)(4) of this section.. The owner or operator electing to directly monitor the net 

heating value of the flare vent gas must comply with the net heating value operating limits 

in paragraph (e) and, if applicable, paragraph (f) of this section. The owner or operator 

electing to directly monitor the combustibles concentration in the flare vent gas must 

comply with the combustibles concentration operating limits in paragraph (e) and, if 

applicable, paragraph (f) of this section, and must comply with the maximum velocity 

requirements in paragraph (d)(1) of this section. 

(1) Except as provided in paragraph (j)(5) of this section, the owner or operator shall 

install, operate, calibrate, and maintain a monitoring system capable of continuously 

measuring (i.e., at least once every 15-minutes), calculating, and recording the individual 

component concentrations present in the flare vent gas. 

(2) Except as provided in paragraph (j)(5) of this section, the owner or operator shall 

install, operate, and maintain a grab sampling system capable of collecting an evacuated 

canister sample for subsequent compositional analysis at least once every eight hours while 

there is flow of regulated material to the flare. Subsequent compositional analysis of the 

samples must be performed according to Method 18 of 40 CFR part 60, Appendix A-6, 

ASTM D1945-03 (Reapproved 2010) (incorporated by reference—see §63.14), or ASTM 

UOP539-12 (incorporated by reference—see §63.14). 

(3) The owner or operator shall install, operate, calibrate, and maintain a monitoring 

system capable of continuously measuring, calculating, and recording NHVvg. at standard 

conditions. 

(4) The owner or operator shall install, operate, calibrate, and maintain a monitoring 

system capable of continuously measuring, calculating, and recording total hydrocarbon 

content (as propane) as a surrogate for combustibles concentration. 

(5) Direct compositional monitoring is not required for pipeline quality natural gas 

streams. In lieu of monitoring the composition of a pipeline quality natural gas stream, the 

following composition can be used for any pipeline quality natural gas stream. 

(i) 93.2 volume percent (vol %) methane. 

(ii) 3.2 vol % ethane. 
Page 125 of 162 

(iii) 0.6 vol % propane. 

(iv) 0.3 vol % butane. 

(v) 2.0 vol % hydrogen. 

(vi) 0.7 vol % nitrogen.

(k) Calculation methods for determining compliance with Vtip operating limits. The owner or 

operator shall determine Vtip on a 15-minute block average basis according to the following 

requirements. 

(1) The owner or operator shall use design and engineering principles to determine the 

unobstructed cross sectional area of the flare tip. The unobstructed cross sectional area of 

the flare tip is the total tip area that vent gas can pass through. This area does not include 

any stability tabs, stability rings, and upper steam or air tubes because vent gas does not 

exit through them. 

(2) The owner or operator shall determine the cumulative volumetric flow of vent gas for 

each 15-minute block average period using the data from the continuous flow monitoring 

system required in paragraph (i) of this section according to the following requirements, as 

applicable. 

(i) Use set 15-minute time periods starting at 12 midnight to 12:15 AM, 12:15 AM to 12:30 

AM and so on concluding at 11:45 PM to midnight when calculating 15-minute block 

average flow volumes. 

(ii) If continuous pressure/temperature monitoring system(s) and engineering calculations 

are used as allowed under paragraph (i)(4) of this section, the owner of operator shall, at a 

minimum, determine the 15-minute block average temperature and pressure from the 

monitoring system and use those values to perform the engineering calculations to 

determine the cumulative flow over the 15-minute block average period. Alternatively, the 

owner or operator may divide the 15-minute block average period into equal duration 

subperiods (e.g., three 5-minute periods) and determine the average temperature and 

pressure for each subperiod, perform engineering calculations to determine the flow for 

each subperiod, then add the volumetric flows for the subperiods to determine the 

cumulative volumetric flow of vent gas for the 15-minute block average period. 

(3) The 15-minute block average Vtip shall be calculated using the following equation. 

 900  Area

Q V cum

tip

where: 
Page 126 of 162 

Vtip = Flare tip velocity, feet per second. 

Qcum = Cumulative volumetric flow over 15-minute block average period, actual cubic feet. 

Area = Unobstructed area of the flare tip, square feet. 

900 = Conversion factor, seconds per 15-minute block average. 

(4) If the owner or operator chooses to comply with paragraph (d)(2) of this section, the 

owner or operator shall also determine the net heating value of the flare vent gas following 

the requirements in paragraph (j) and (l) of this section and calculate Vmax using the 

equation in paragraph (d)(2) of this section in order to compare Vtip to Vmax on a 15-minute 

block average basis. 

(l) Calculation methods for determining flare vent gas parameters. The owner or operator 

shall determine the net heating value, lower flammability limit, and/or combustibles 

concentration of the flare vent gas (NHVvg, LFLvg, and/or Cvg, respectively) based on the 

composition monitoring data on a 15-minute block average basis according to the following 

requirements. 

(1) Use set 15-minute time periods starting at 12 midnight to 12:15 AM, 12:15 AM to 12:30 

AM and so on concluding at 11:45 PM to midnight when calculating 15-minute block 

averages. 

(2) When a continuous monitoring system is used to determine flare vent gas composition, 

net heating value, or total hydrocarbon content: 

(i) Use the results from the first sample collected during an event, (for periodic flare vent 

gas flow events) for the first and second 15-minute block associated with that event. 

(ii) For all other 15-minute block periods, use the results that are available from the most 

recent sample prior to the 15-minute block period for that 15-minute block period. For the 

purpose of this requirement, use the time that the results become available rather than the 

time the sample was collected. For example, if a sample is collected at 12:25 AM and the 

analysis is completed at 12:38 AM, the results are available at 12:38 AM and these results 

would be used to determine compliance during the 15-minute block period from 12:45 AM 

to 1:00 AM. 

(3) When grab samples are used to determine flare vent gas composition: 

(i) Use the analytical results from the first grab sample collected for an event for all 15-

minute periods from the start of the event through the 15-minute block prior to the 15-

minute block in which a subsequent grab sample is collected. 

(ii) Use the results from subsequent grab sampling events for all 15 minute periods starting 

with the 15-minute block in which the sample was collected and ending with the 15-minute 
Page 127 of 162 

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. 

(4) The owner or operator shall determine NHVvg from compositional analysis data by 

using the following equation. If the owner or operator uses a monitoring system(s) capable 

of continuously measuring, calculating, and recording NHVvg, as provided in paragraph 

(j)(3) of this section, the owner or operator shall use the NHVvg as determined by the 

continuous NHVvg monitor. 





n

i

vg iNHVi NHV x

1

where: 

NHVvg = Net heating value of flare vent gas, Btu/scf. 

i = Individual component in flare vent gas. 

n = Number of components in flare vent gas. 

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

NHVi = Net heating value of component i according to table 12 of this subpart, Btu/scf. If 

the component is not specified in table 12 of this subpart, the heats of combustion may be 

determined using any published values where the net enthalpy per mole of offgas is based 

on combustion at 25 °C and 1 atmosphere (or constant pressure) with offgas water in the 

gaseous state, but the standard temperature for determining the volume corresponding to 

one mole of vent gas is 20 °C. 

(5) The owner or operator shall calculate LFLvg using the following equation: 

 













  n

i i

vg

LFL

χ

LFL

i

1

1

where: 

LFLvg = Lower flammability limit of flare vent gas, volume fraction. 

n = Number of components in the vent gas. 

i = Individual component in the vent gas. 
Page 128 of 162 

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

LFLi = Lower flammability limit of component i according to table 12 of this subpart, vol 

%. If the component is not specified in table 12 of this subpart, the owner or operator shall 

use the LFL value as published in Appendix A of Flammability Characteristics of 

Combustible Gases and Vapors, U.S. Bureau of Mines, Bulletin 627, 1965 (incorporated by 

reference—see §63.14). All inerts, including nitrogen, shall be assumed to have an infinite 

lower flammability limit (e.g., LFLN2 = ∞, so that χN2/ LFLN2 = 0). 

(6) The owner or operator shall calculate Cvg using the following equation. If the owner or 

operator uses a total hydrocarbon analyzer, the owner or operator may substitute the 

“∑χi” term in the following equation with the total volumetric hydrocarbon concentration 

present in the flare vent gas (vol % as propane), and the owner or operator may choose to 

ignore the concentration of hydrogen in the flare vent gas. 

100%

1 3 



 



  



 



 





h

n

i

i i

vg

χ

CMN χ

C

where: 

Cvg = Total volumetric fraction of hydrogen and combustible organic components present 

in the flare vent gas, volume fraction. For the purposes of Cvg, carbon dioxide is not 

considered to be a combustible organic component, but carbon monoxide may be included 

in Cvg. 

n = Number of individual combustible organic components in flare vent gas. 

i = Individual combustible organic component in flare vent gas. 

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

CMNi = Carbon mole number of combustible organic component i in flare vent gas, mole 

carbon atoms per mole of compound. E.g., CMN for ethane (C2H6) is 2; CMN for propane 

(C3H8) is 3. 

χh = Concentration of hydrogen in flare vent gas, vol %. 

100% = Constant, used to convert volume percent to volume fraction. 

(m) Calculation methods for determining combustion zone parameters. The owner or 

operator shall determine the net heating value, lower flammability limit and combustibles 

concentration of the combustion zone gas (NHVcz, LFLcz, and Ccz, respectively) based on 

the vent gas and assist gas flow rates on a 15-minute block average basis according to the 
Page 129 of 162 

following requirements. For periods when there is no assist steam flow or premix assist air 

flow, the combustion zone parameters are equal to the vent gas parameters. 

(1) The owner or operator shall calculate NHVcz using the following equation: 

  vg s a,premix

vg vg

cz Q Q Q

Q NHV

NHV

 

 

where: 

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

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

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

(2) The owner or operator shall calculate LFLcz using the following equation: 

 

vg

vg vg s a,premix

cz Q

LFL Q Q Q LFL   

where: 

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

LFLvg = Lower flammability limit of flare vent gas determined for the 15-minute block 

period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

(3) The owner or operator shall calculate Ccz using the following equation: 
Page 130 of 162 

  vg s a,premix

vg vg

cz Q Q Q

Q C

C

 

 

where: 

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

Cvg = Combustibles concentration of flare vent gas determined for the 15-minute block 

period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

(n) Calculation methods for determining dilution parameters. The owner or operator shall 

determine the net heating value, lower flammability limit and combustibles concentration 

dilution parameters (NHVdil, LFLdil, and Cdil, respectively) based on the vent gas and 

perimeter assist air flow rates on a 15-minute block average basis according to the 

following requirements only during periods when perimeter assist air is used. For 15-

minute block periods when there is no cumulative volumetric flow of perimeter assist air, 

the dilution parameters do not need to be calculated. 

(1) The owner or operator shall calculate NHVdil using the following equation: 

  vg s a,premix a,perimeter

vg vg

dil Q Q Q Q

Q Diam NHV

NHV

  

  

where: 

NHVdil = Net heating value of combustion zone gas, Btu/ft2

NHVvg = Net heating value of flare vent gas determined for the 15-minute block period, 

Btu/scf. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, 

ft. Use the area as determined in paragraph (k)(1) of this section and determine the 

diameter as Diam  2 Area π

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 
Page 131 of 162 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

Qa,perimiter = Cumulative volumetric flow of perimeter assist air during the 15-minute block 

period, scf. 

(2) The owner or operator shall calculate LFLdil using the following equation: 

 

Q Diam

LFL Q Q Q Q LFL

vg

vg vg s a,premix a,perimeter

dil



    

where: 

LFLdil = Lower flammability limit of combustion zone gas, ft-1. 

LFLvg = Lower flammability limit of flare vent gas determined for the 15-minute block 

period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, 

ft. Use the area as determined in paragraph (k)(1) of this section and determine the 

diameter as Diam  2 Area π

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

Qa,perimiter = Cumulative volumetric flow of perimeter assist air during the 15-minute block 

period, scf. 

(3) The owner or operator shall calculate Cdil using the following equation: 

  vg s a,premix a,perimeter

vg vg

dil Q Q Q Q

Q Diam C

C

  

  

where: 

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

Cvg = Combustibles concentration of flare vent gas determined for the 15-minute block 

period, volume fraction. 
Page 132 of 162 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, 

ft. Use the area as determined in paragraph (k)(1) of this section and determine the 

diameter as Diam  2 Area π

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

Qa,perimiter = Cumulative volumetric flow of perimeter assist air during the 15-minute block 

period, scf. 

(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 isobutene, and all isomers of butadiene. 

(2) If individual component concentrations are determined following the methods specified 

in paragraphs (j)(1) or (j)(2) of this section, the measured vent gas concentrations shall be 

used to determine the hydrogen, olefins, and hydrogen plus olefins concentration in the 

combustion zone using the following general equation. The methods specified in 

paragraphs (l)(1) through (3) of this section, as applicable, shall be used to assign the vent 

gas concentration results to a specific 15-minute block period. 

  vg s a,premix

vg vg

cz Q Q Q

Q A

A

 

 

where: 

Acz = Concentration of target compound(s) “A” (representing either the olefins 

concentration, the hydrogen concentration, or the sum of the olefins and hydrogen 

concentration) in the combustion zone gas, volume fraction. 

Avg = Concentration of target compound(s) “A” (representing either the olefins 

concentration, the hydrogen concentration, or the sum of the olefins and hydrogen 

concentration) in the flare vent gas determined for the 15-minute block period, volume 

fraction. 
Page 133 of 162 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

(3) If NHVvg or total hydrocarbon monitoring systems are used as provided in paragraphs 

(j)(3) or (j)(4) of this section, the owner or operator may elect to determine the hydrogen 

and olefins concentrations using any of the following methods. 

(i) The owner or operator may elect to assume the hydrogen concentration, the olefins 

concentration, and the olefins plus hydrogen concentration in the combustion zone gas 

exceed all three criteria in (e)(4) at all times without making specific measurements of 

olefins or hydrogen concentrations. 

(ii) The owner or operator may elect to use process knowledge and engineering calculations 

to determine the highest flare vent gas concentrations of olefins and hydrogen that can 

reasonably be expected to be discharged to the flare and the highest concentration of 

olefins plus hydrogen that can reasonably be expected to be discharged to the flare while 

the flare vent gas concentrations exceed the target combustion zone concentrations in 

paragraphs (e)(4)(i) and (ii) of this section at the same time. The owner or operator shall 

take daily flare vent gas samples for fourteen days or for 7 flaring events, whichever results 

in the greatest number of grab samples to verify that the calculated values are 

representative of the highest concentrations that reasonably be expected to be discharged 

to the flare. 

(A) If the highest flare vent gas concentrations of olefins, hydrogen, and olefins plus 

hydrogen that can reasonably be expected to be discharged to the flare do not exceed all 

three combustion zone concentration criteria in paragraph (e)(4) of this section, for 

example, if the flare does not service any process units that contain olefins, then the 

engineering assessment is sufficient to document that all three criteria in paragraph (e)(4) 

of this section are not met and that the more stringent operating limits do not apply at any 

time. 

(B) If the highest flare vent gas concentrations of olefins, hydrogen, and olefins plus 

hydrogen that can reasonably be expected to be discharged to the flare exceed all three 

combustion zone concentration criteria in paragraph (e)(4), then the owner or operator will 

use the concentrations determined from the engineering analysis as the vent gas 

concentrations that exist in the vent gas at all times and use the equation in paragraph 

(o)(2) of this section to determine the combustion zone concentrations of olefins, 

(C) If the operation of process units connected to the flares change or new connections are 

made to the flare and these changes can reasonably be expected to alter the highest vent gas 

concentrations of olefins, hydrogen, and/or olefins plus hydrogen received by the flare, a 
Page 134 of 162 

new engineering assessment and sampling period for verification will be conducted 

following the requirements of paragraph (o)(3)(ii) of this section. 

(p) Flare monitoring records. The owner or operator shall keep the records specified in 

§63.655(i)(9). 

(q) Reporting. The owner or operator shall comply with the reporting requirements 

specified in §63.655(g)(11). 

(r) Alternative means of emissions limitation. An owner or operator may request approval 

from the Administrator for site-specific operating limits that shall apply specifically to a 

selected flare. Site-specific operating limits include alternative threshold values for the 

parameters specified in paragraphs (d) through (f) of this section as well as threshold 

values for operating parameters other than those specified in paragraphs (d) through (f) of 

this section. The owner or operator must demonstrate that the flare achieves 96.5 percent 

combustion efficiency (or 98 percent destruction efficiency) using the site-specific operating 

limits based on a performance test as described in paragraph (r)(1) of this section. The 

request shall include information as described in paragraph (r)(2) of this section. The 

request shall be submitted and followed as described in paragraph (r)(3) of this section. 

(1) The owner or operator shall prepare and submit a site-specific test plan and receive 

approval of the site-specific test plan prior to conducting any flare performance test 

intended for use in developing site-specific operating limits. The site-specific test plan shall 

include, at a minimum, the elements specified in paragraphs (r)(1)(i) through (ix) of this 

section. Upon approval of the site-specific test plan, the owner or operator shall conduct a 

performance test for the flare following the procedures described in the site-specific test 

plan. 

(i) The design and dimensions of the flare, flare type (air-assisted only, steam-assisted only, 

air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being 

flared, including quantity of gas flared, frequency of flaring events (if periodic), expected 

net heating value of flare vent gas, minimum total steam assist rate. 

(ii) The operating conditions (vent gas compositions, vent gas flow rates and assist flow 

rates, if applicable) likely to be encountered by the flare during normal operations and the 

operating conditions for the test period. 

(iii) A description of (including sample calculations illustrating) the planned data reduction 

and calculations to determine the flare combustion or destruction efficiency. 

(iv) Site-specific operating parameters to be monitored continuously during the flare 

performance test. These parameters may include but are not limited to vent gas flow rate, 

steam and/or air assist flow rates, and flare vent gas composition. If new operating 

parameters are proposed for use other than those specified in paragraphs (d) through (f) of 

this section, an explanation of the relevance of the proposed operating parameter(s) as an 
Page 135 of 162 

indicator of flare combustion performance and why the alternative operating parameter(s) 

can adequately ensure that the flare achieves the required combustion efficiency. 

(v) A detailed description of the measurement methods, monitored pollutant(s), 

measurement locations, measurement frequency, and recording frequency proposed for 

both emission measurements and flare operating parameters. 

(vi) A description of (including sample calculations illustrating) the planned data reduction 

and calculations to determine the flare operating parameters. 

(vii) The minimum number and length of test runs and range of operating values to be 

evaluated during the performance test. A sufficient number of test runs shall be conducted 

to identify the point at which the combustion/destruction efficiency of the flare 

deteriorates. 

(viii) If the flare can receive vent gases containing olefins and hydrogen above the levels 

specified for the combustion zone gas in paragraph (e)(4) of this section, a sufficient 

number of tests must be conducted while exceeding these limits to assess whether more 

stringent operating limits are required under these conditions. 

(ix) Test schedule. 

(2) The request for flare-specific operating limits shall include sufficient and appropriate 

data, as determined by the Administrator, to allow the Administrator to confirm that the 

selected site-specific operating limit(s) adequately ensures that the flare destruction 

efficiency is 98 percent or greater or that the flare combustion efficiency is 96.5 percent or 

greater at all times. At a minimum, the request shall contain the information described in 

paragraphs (r)(2)(i) through (iv) of this section. 

(i) The design and dimensions of the flare, flare type (air-assisted only, steam-assisted only, 

air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being 

flared, including quantity of gas flared, frequency of flaring events (if periodic), expected 

net heating value of flare vent gas, minimum total steam assist rate. 

(ii) Results of each performance test run conducted, including, at a minimum: 

(A) The measured combustion/destruction efficiency. 

(B) The measured or calculated operating parameters for each test run. If operating 

parameters are calculated, the raw data from which the parameters are calculated must be 

included in the test report. 

(C) Measurement location descriptions for both emission measurements and flare 

operating parameters. 
Page 136 of 162 

(D) Description of sampling and analysis procedures (including number and length of test 

runs) and any modifications to standard procedures. If there were deviations from the 

approved test plan, a detailed description of the deviations and rationale why the test 

results or calculation procedures used are appropriate. 

(E) Operating conditions (e.g., vent gas composition, assist rates, etc.) that occurred during 

the test. 

(F) Quality assurance procedures. 

(G) Records of calibrations. 

(H) Raw data sheets for field sampling. 

(I) Raw data sheets for field and laboratory analyses. 

(J) Documentation of calculations 

(iii) The selected flare-specific operating limit values based on the performance test results, 

including the averaging time for the operating limit(s), and rationale why the selected 

values and averaging times are sufficiently stringent to ensure proper flare performance. If 

new operating parameters or averaging times are proposed for use other than those 

specified in paragraphs (d) through (f) of this section, an explanation of why the alternative 

operating parameter(s) or averaging time(s) adequately ensures the flare achieves the 

required combustion efficiency. 

(iv) The means by which the owner or operator will document on-going, continuous 

compliance with the selected flare-specific operating limit(s), including the specific 

measurement location and frequencies, calculation procedures, and records to be 

maintained. 

(3) The request shall be submitted as described in paragraphs (r)(3)(i) through (iv) of this 

section. 

(i) The owner or operator may request approval from the Administrator at any time upon 

completion of a performance test conducted following the methods in an approved sitespecific 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 
Page 137 of 162 

T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard 

copies may also be submitted to refineryrtr@epa.gov. 

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

to address the deficiencies and be re-submitted for approval within 45 days of receipt of the 

notice of deficiencies. The owner or operator must comply with the revised request as 

submitted until it is approved. 

(4) The approval process for a request for a flare-specific operating limit(s) is described in 

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

(i) Approval by the Administrator of a flare-specific operating limit(s) request will be based 

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

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

described in paragraphs (r)(4)(i)(A) through (C) of this section. 

(A) The description of the flare design and operating characteristics. 

(B) If a new operating parameter(s) other than those specified in paragraphs (d) through 

(f) of this section is proposed, the explanation of how the proposed operating parameter(s) 

serves a good indicator(s) of flare combustion performance. 

(C) The results of the flare performance test and the establishment of operating limits that 

ensures that the flare destruction efficiency is 98 percent or greater or that the flare 

combustion efficiency is 96.5 percent or greater at all times. 

(D) The completeness of the flare performance test report. 

(ii) If the request is approved by the Administrator, a flare-specific operating limit(s) will 

be established at the level(s) demonstrated in the approved request. 

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

to address the deficiencies and be re-submitted for approval. 

§ 63.671 Requirements for flare monitoring systems. 

(a) Operation of CPMS. For each CPMS installed to comply with applicable provisions in 

§63.670, the owner or operator shall install, operate, calibrate, and maintain the CPMS as 

specified in paragraphs (a)(1) through (8) of this section. 

(1) All monitoring equipment must meet the minimum accuracy, calibration and quality 

control requirements specified in table 13 of this subpart. 

(2) The owner or operator shall ensure the readout (that portion of the CPMS that 

provides a visual display or record) or other indication of the monitored operating 
Page 138 of 162 

parameter from any CPMS required for compliance is readily accessible onsite for 

operational control or inspection by the operator of the source. 

(3) All CPMS must complete a minimum of one cycle of operation (sampling, analyzing and 

data recording) for each successive 15-minute period. 

(4) Except for maintenance periods, instrument adjustments or checks to maintain 

precision and accuracy, calibration checks, and zero and span adjustments, the owner or 

operator shall operate all CPMS and collect data continuously when regulated emissions 

are routed to the flare. 

(5) The owner or operator shall operate, maintain, and calibrate each CPMS according to 

the CPMS monitoring plan specified in paragraph (b) of this section. 

(6) For each CPMS, the owner or operator shall comply with the out-of-control procedures 

described in paragraphs (c) of this section. The CPMS monitoring plan must be submitted 

to the Administrator for approval upon request. 

(7) The owner or operator shall reduce data from a CPMS as specified in paragraph (d) of 

this section. 

(8) The CPMS must be capable of measuring the appropriate parameter over the range of 

values expected for that measurement location. The data recording system associated with 

each CPMS must have a resolution that is equal to or better than the required system 

accuracy. 

 (b) CPMS monitoring plan. The owner or operator shall develop and implement a CPMS 

quality control program documented in a CPMS monitoring plan. The owner or operator 

shall have the CPMS monitoring plan readily available on-site at all times and shall submit 

a copy of the CPMS monitoring plan to the Administrator upon request by the 

Administrator. The CPMS monitoring plan must contain the information listed in 

paragraphs (b)(1) through (5) of this section. 

(1) Identification of the specific flare being monitored and the flare type (air-assisted only, 

steam-assisted only, air- and steam-assisted, pressure-assisted, or non-assisted). 

(2) Identification of the parameter to be monitored by the CPMS and the expected 

parameter range, including worst case and normal operation. 

(3) Description of the monitoring equipment, including the information specified in (c)(3)(i) 

through (viii) of this section. 

(i) Manufacturer and model number for all monitoring equipment components. 

(ii) Performance specifications, as provided by the manufacturer, and any differences 

expected for this installation and operation. 
Page 139 of 162 

(iii) The location of the CPMS sampling probe or other interface and a justification of how 

the location meets the requirements of paragraph (a)(1) of this section. 

(iv) Placement of the CPMS readout, or other indication of parameter values, indicating 

how the location meets the requirements of paragraph (a)(2) of this section. 

(v) Span of the analyzer. The span must encompass all expected concentrations and meet 

the requirements of paragraph (b)(10) of this section. 

(vi) How data outside of the analyzer’s span will be handled and the corrective action that 

will be taken to reduce and eliminate such occurrences in the future. 

(vii) Identification of the parameter detected by the parametric signal analyzer and the 

algorithm used to convert these values into the operating parameter monitored to 

demonstrate compliance, if the parameter detected is different from the operating 

parameter monitored. 

(4) Description of the data collection and reduction systems, including the information 

specified in paragraphs (b)(4)(i) through (iii) of this section. 

(i) A copy of the data acquisition system algorithm used to reduce the measured data into 

the reportable form of the standard and to calculate the applicable averages. 

(ii) Identification of whether the algorithm excludes data collected during CPMS 

breakdowns, out-of-control periods, repairs, maintenance periods, instrument adjustments 

or checks to maintain precision and accuracy, calibration checks, and zero (low-level), midlevel (if applicable) and high-level adjustments. 

(iii) If the data acquisition algorithm does not exclude data collected during CPMS 

breakdowns, out-of-control periods, repairs, maintenance periods, instrument adjustments 

or checks to maintain precision and accuracy, calibration checks, and zero (low-level), midlevel (if applicable) and high-level adjustments, a description of the procedure for 

excluding this data when the averages calculated as specified in paragraph (e) of this 

section are determined. 

(5) Routine quality control and assurance procedures, including descriptions of the 

procedures listed in paragraphs (c)(5)(i) through (vi) of this section and a schedule for 

conducting these procedures. The routine procedures must provide an assessment of CPMS 

performance. 

(i) Initial and subsequent calibration of the CPMS and acceptance criteria. 

(ii) Determination and adjustment of the calibration drift of the CPMS. 

(iii) Daily checks for indications that the system is responding. If the CPMS system includes 

an internal system check, the owner or operator may use the results to verify the system is 
Page 140 of 162 

responding, as long as the owner or operator checks the internal system results daily for 

proper operation and the results are recorded. 

(iv) Preventive maintenance of the CPMS, including spare parts inventory. 

(v) Data recording, calculations and reporting. 

(vi) Program of corrective action for a CPMS that is not operating properly. 

(c) Out-of-control periods. For each CPMS, the owner or operator shall comply with the 

out-of-control procedures described in paragraphs (c)(1) and (2) of this section. 

(1) A CPMS is out-of-control if the zero (low-level), mid-level (if applicable) or high-level 

calibration drift exceeds two times the accuracy requirement of table 13 of this subpart. 

(2) When the CPMS is out of control, the owner or operator shall take the necessary 

corrective action and repeat all necessary tests that indicate the system is out of control. 

The owner or operator shall take corrective action and conduct retesting until the 

performance requirements are below the applicable limits. The beginning of the out-ofcontrol period is the hour a performance check (e.g., calibration drift) that indicates an 

exceedance of the performance requirements established in this section is conducted. The 

end of the out-of-control period is the hour following the completion of corrective action 

and successful demonstration that the system is within the allowable limits. The owner or 

operator shall not use data recorded during periods the CPMS is out of control in data 

averages and calculations, used to report emissions or operating levels, as specified in 

paragraph (d)(3) of this section. 

(d) CPMS data reduction. The owner or operator shall reduce data from a CPMS as 

specified in paragraphs (d)(1) through (3) of this section. 

(1) The owner or operator may round the data to the same number of significant digits 

used in that operating limit. 

(2) Periods of non-operation of the process unit (or portion thereof) resulting in cessation of 

the emissions to which the monitoring applies must not be included in the 15-minute block 

averages. 

(3) Periods when the CPMS is out of control must not be included in the 15-minute block 

averages. 

(e) Additional requirements for gas chromatographs. For monitors used to determine 

compositional analysis for net heating value per §63.670(j)(1), the gas chromatograph must 

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

(1) The quality assurance requirements are in table 13 of this subpart. 
Page 141 of 162 

(2) The calibration gases must meet one of the following options: 

(i) The owner or operator must use a calibration gas or multiple gases that include all of 

the compounds that exist in the flare gas stream. All of the calibration gases may be 

combined in one cylinder. If multiple calibration gases are necessary to cover all 

compounds, the owner or operator must calibrate the instrument on all of the gases. 

(ii) The owner or operator must use a surrogate calibration gas consisting of C1 through 

C7 normal hydrocarbons. All of the calibration gases may be combined in one cylinder. If 

multiple calibration gases are necessary to cover all compounds, the owner or operator 

must calibrate the instrument on all of the gases. 

(3) If the owner or operator chooses to use a surrogate calibration gas under paragraph 

(e)(2)(ii) of this section, the owner or operator must comply with the following paragraphs. 

(i) Use the response factor for the nearest normal hydrocarbon (i.e., n-alkane) in the 

calibration mixture to quantify unknown components detected in the analysis. 

(ii) Unknown compounds that elute after n-heptane must either be identified and 

quantified using an identical compound standard, or the owner or operator must extend 

the calibration range to include the additional normal hydrocarbons necessary to perform 

the unknown hydrocarbon quantitation procedure. 

§§ 63.657§§ 63.672-63.679 [Reserved] 

Appendix to Subpart CC of Part 63—Tables 

Table 1—Hazardous Air Pollutants 

Chemical name CAS No.a

Benzene 71432

Biphenyl 92524

Butadiene (1,3) 106990

Carbon disulfide 75150

Carbonyl sulfide 463581

Cresol (mixed isomersb) 1319773

Cresol (m-) 108394

Cresol (o-) 95487

Cresol (p-) 106445

Cumene 98828

Dibromoethane (1,2) (ethylene dibromide) 106934

Dichloroethane (1,2) 107062

Diethanolamine 111422

Ethylbenzene 100414

Ethylene glycol 107211
Page 142 of 162 

Chemical name CAS No.a

Hexane 110543

Methanol 67561

Methyl isobutyl ketone (hexone) 108101

Methyl tert butyl ether 1634044

Naphthalene 91203

Phenol 108952

Toluene 108883

Trimethylpentane (2,2,4) 540841

Xylene (mixed isomersb) 1330207

xylene (m-) 108383

xylene (o-) 95476

xylene (p-) 106423

a

CAS number = Chemical Abstract Service registry number assigned to specific compounds, 

isomers, or mixtures of compounds. 

b

Isomer means all structural arrangements for the same number of atoms of each element and 

does not mean salts, esters, or derivatives. 

Table 2—Leak Definitions for Pumps and Valves 

Standarda Phase Leak definition (parts per million) 

§63.163 (pumps) I 10,000

 II 5,000

 III 2,000

§63.168 (valves) I 10,000

 II 1,000

 III 1,000

a

Subpart H of this part. 

Table 3—Equipment Leak Recordkeeping and Reporting Requirements for Sources 

Complying With §63.648 of Subpart CC by Compliance With Subpart H of this Parta

Reference 

(section of 

subpart H of 

this part) Description Comment 

63.181(a) Recordkeeping system 

requirements 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 

63.181(b) Records required for process 

unit equipment 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 

63.181(c) Visual inspection 

documentation 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 
Page 143 of 162 

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. 

63.181(k) Enclosed-vented process 

unit emission limitation 

record requirements. 

63.182(a) Reports. 

63.182(b) Initial notification report 

requirements. 

Not required. 

63.182(c) Notification of compliance 

status report 

Except in §63.182(c); change “within 90 

days of the compliance dates” to “within 150 

days of the compliance dates”; except in 

§§63.182 (c)(2) and (c)(4). 

63.182(d) Periodic report Except for §§63.182 (d)(2)(vii), (d)(2)(viii), 

and (d)(3). 

a

This table does not include all the requirements delineated under the referenced sections. See 

referenced sections for specific requirements. 

Table 4—Gasoline Distribution Emission Point Recordkeeping and Reporting 

Requirementsa

Reference 

(section of 

subpart R) Description Comment 

63.428(b) or (k) Records of test results for each 

gasoline cargo tank loaded at the 

facility 

63.428(c) Continuous monitoring data 

recordkeeping requirements 
Page 144 of 162 

63.428(g)(1) Semiannual report loading rack 

information 

Required to be submitted with the 

Periodic Report required under 40 CFR 

part 63, subpart CC. 

63.428(h)(1) 

through (h)(3) 

Excess emissions report loading 

rack information 

Required to be submitted with the 

Periodic Report required under 40 CFR 

part 63, subpart CC. 

a

This table does not include all the requirements delineated under the referenced sections. See 

referenced sections for specific requirements. 

Table 5—Marine Vessel Loading Operations Recordkeeping and Reporting Requirementsa

Reference 

(section of 

subpart Y) Description Comment 

63.562(e)(2) Operation and maintenance 

plan for control equipment and 

monitoring equipment 

63.565(a) Performance test/site test plan The information required under this 

paragraph is to be submitted with the 

Notification of Compliance Status report 

required under 40 CFR part 63, subpart 

CC. 

63.565(b) Performance test data 

requirements 

63.567(a) General Provisions (subpart A) 

applicability 

63.567(c) Request for extension of 

compliance 

63.567(d) Flare recordkeeping 

requirements 

63.567(e) Summary report and excess 

emissions and monitoring 

system performance report 

requirements 

The information required under this 

paragraph is to be submitted with the 

Periodic Report required under 40 CFR 

part 63, subpart CC. 

63.567(f) Vapor collection system 

engineering report 

63.567(g) Vent system valve bypass 

recordkeeping requirements 

63.567(h) Marine vessel vapor-tightness 

documentation 

63.567(i) Documentation file 

maintenance 

63.567(j) Emission estimation reporting 

and recordkeeping procedures 
Page 145 of 162 

a

This table does not include all the requirements delineated under the referenced sections. See 

referenced sections for specific requirements. 

Table 6—General Provisions Applicability to Subpart CCa

Reference 

Applies to 

subpart CC Comment 

63.1(a)(1) Yes 

63.1(a)(2) Yes 

63.1(a)(3) Yes 

63.1(a)(4) Yes 

63.1(a)(5) No Reserved. 

63.1(a)(6) Yes Except the correct mail drop (MD) number is C404–04. 

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 
Page 146 of 162 

Reference 

Applies to 

subpart CC Comment 

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. 

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) 

YesNo Except the startup, shutdown, or malfunction plan does not 

apply to Group 2 emission points that are not part of an 

emissions averaging group.bSee §63.642(n) for general duty 

requirement.

63.6(e)(1)(iii) Yes 

63.6(e)(2) No Reserved. 

63.6(e)(3)(i) YesNo 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

63.6(e)(3)(ii) No Reserved. 
Page 147 of 162 

Reference 

Applies to 

subpart CC Comment 

63.6(e)(3)(iii)–

63.6(e)(3)(ix) 

YesNo 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.

63.6(f)(1) YesNo Except for the heat exchange system standards, which apply 

at all times.

63.6(f)(2) and 

(3)

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(f)(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)(1) and 

63.6(h)(2) 

Yes Except §63.6(h)(2)(ii), which is reserved. 

63.6(h)(3) No Reserved. 

63.6(h)(4) No Notification of visible emission test not required in subpart 

CC. 

63.6(h)(5) No Visible emission requirements and timing is specified in 

§63.645(i) of subpart CC. 

63.6(h)(6) Yes 

63.6(h)(7) No Subpart CC does not require opacity standards. 

63.6(h)(8) Yes 

63.6(h)(9) No Subpart CC does not require opacity standards. 

63.6(i) Yes Except for §63.6(i)(15), which is reserved. 

63.6(j) Yes 

63.7(a)(1) Yes 

63.7(a)(2) Yes Except test results must be submitted in the Notification of 

Compliance Status report due 150 days after compliance date, 

as specified in §63.655(f) of subpart CC. 

63.7(a)(3) Yes 

63.7(a)(4) Yes 

63.7(b) NoYes SubpartExcept 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) YesNo Except the performance test must be conducted at the 

maximum representative capacity as specified in 

§63.642(d)(3) of subpart CC.See §63.642(d)(3).

63.7(e)(2)–

63.7(e)(4) 

Yes 
Page 148 of 162 

Reference 

Applies to 

subpart CC Comment 

63.7(f) No Subpart CC specifies applicable methods and provides 

alternatives without additional notification or approval. 

63.7(g) No Performance test reporting specified in §63.655(f). 

63.7(h)(1) Yes 

63.7(h)(2) Yes 

63.7(h)(3) Yes Yes, except site-specific test plans shall not be required, and 

where §63.7(g)(3) specifies submittal by the date the sitespecific test plan is due, the date shall be 90 days prior to the 

Notification of Compliance Status report in §63.655(f). 

63.7(h)(4)(i) Yes 

63.7(h)(4)(ii) No Site-specific test plans are not required in subpart CC. 

63.7(h)(4)(iii) 

and (iv) 

Yes 

63.7(h)(5) Yes 

63.8(a)(1) and 

(2) 

Yes 

63.8(a)(3) No Reserved. 

63.8(a)(4) Yes Except §63.8(a)(3), which is reserved.Except that for a flare 

complying with §63.670, the cross-reference to §63.11 in 

this paragraph does not include §63.11(b).

63.8(b) Yes 

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) NoYes 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.
Page 149 of 162 

Reference 

Applies to 

subpart CC Comment 

63.8(f)(1) Yes 

63.8(f)(2) Yes 

63.8(f)(3) Yes 

63.8(f)(4)(i) No Timeframe for submitting request is specified in 

§63.655(h)(5)(i) of subpart CC. 

63.8(f)(4)(ii) Yes 

63.8(f)(4)(iii) No Timeframe for submitting request is specified in 

§63.655(h)(5)(i) of subpart CC. 

63.8(f)(5) Yes 

63.8(f)(6) No Subpart CC does not require continuous emission monitors. 

63.8(g) No Subpart CC specifies data reduction procedures in 

§§63.655(i)(3) and 63.671(d). 

63.9(a) Yes Except that the owner or operator does not need to send a 

copy of each notification submitted to the Regional Office of 

the EPA as stated in §63.9(a)(4)(ii). 

63.9(b)(1) Yes Except the notification of compliance status report specified 

in §63.655(f) of subpart CC may also serve as the initial 

compliance notification required in §63.9(b)(1)(iii). 

63.9(b)(2) No A separate Initial Notification report is not required under 

subpart CC. 

63.9(b)(3) No Reserved. 

63.9(b)(4) Yes Except for subparagraphs §63.9(b)(4)(ii) through (iv), which 

are reserved. 

63.9(b)(5) Yes 

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) YesNo
Page 150 of 162 

Reference 

Applies to 

subpart CC Comment 

63.10(b)(2)(ii) YesNo 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) YesNo

63.10(b)(2)(v) YesNo

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)(910)–

63.10(c)(1511) 

No See §63.655(i)(11) for malfunctions recordkeeping 

requirements.

63.10(c)(12)–

63.10(c)(15) 

No 

63.10(d)(1) Yes 

63.10(d)(2) No §63.655(f) of subpart CC specifies performance test 

reporting. 

63.10(d)(3) No Results of visible emissions test are included in Compliance 

Status Report as specified in §63.655(f). 

63.10(d)(4) Yes 

63.10(d)(5)(i) YesbNo 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.See §63.655(g)(12) for 

malfunctions reporting requirements. 
Page 151 of 162 

Reference 

Applies to 

subpart CC Comment 

63.10(d)(5)(ii) Yes Except that actions taken during a startup, shutdown, or 

malfunction that are not consistent with the startup, 

shutdown, and malfunction plan and that cause the source to 

exceed any applicable emission limitation do not need to be 

reported within 2 and 7 days of commencing and completing 

the action, respectively, but must be included in the next 

periodic report. 

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). 

63.1112–63.16 Yes 

a

Wherever subpart A specifies “postmark” dates, submittals may be sent by methods other than 

the U.S. Mail (e.g., by fax or courier). Submittals shall be sent by the specified dates, but a 

postmark is not required. 

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. 

Table 7—Fraction Measured (FM), Fraction Emitted (FE), and Fraction Removed (FR) for 

HAP Compounds in Wastewater Streams 

Chemical name CAS No.a Fm Fe Fr 

Benzene 71432 1.00 0.80 0.99

Biphenyl 92524 0.86 0.45 0.99

Butadiene (1,3) 106990 1.00 0.98 0.99

Carbon disulfide 75150 1.00 0.92 0.99

Cumene 98828 1.00 0.88 0.99

Dichloroethane (1,2-) (Ethylene dichloride) 107062 1.00 0.64 0.99

Ethylbenzene 100414 1.00 0.83 0.99

Hexane 110543 1.00 1.00 0.99

Methanol 67561 0.85 0.17 0.31

Methyl isobutyl ketone (hexone) 108101 0.98 0.53 0.99

Methyl tert butyl ether 1634044 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. 
Page 152 of 162 

Table 8—Valve Monitoring Frequency for Phase III 

Performance level 

Leaking valves Valve monitoring frequency a (%) 

≥4 Monthly or QIP.b

<4 Quarterly. 

<3 Semiannual. 

<2 Annual. 

a

Percent leaking valves is calculated as a rolling average of two consecutive monitoring periods. 

b

QIP=Quality improvement program. Specified in §63.175 of subpart H of this part. 

Table 9—Valve Monitoring Frequency for Alternative 

Performance level 

Leaking valves Valve monitoring frequency under §63.649 alternative a (%) 

≥5 Monthly or QIP.b

<5 Quarterly. 

<4 Semiannual. 

<3 Annual. 

a

Percent leaking valves is calculated as a rolling average of two consecutive monitoring periods. 

b

QIP=Quality improvement program. Specified in §63.175 of subpart H of this part. 

Table 10—Miscellaneous Process Vents—Monitoring, Recordkeeping and Reporting 

Requirements for Complying With 98 Weight-Percent Reduction of Total Organic HAP 

Emissions or a Limit of 20 Parts Per Million by Volume 

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

Thermal incinerator Firebox temperatureb

(63.644(a)(1)(i)) 

1. Continuous recordsc. 

 2. Record and report the firebox 

temperature averaged over the full 

period of the performance test—NCSd

.

 3. Record the daily average firebox 

temperature for each operating daye

. 

 4. Report all daily average 

temperatures that are outside the range 

established in the NCS or operating 

permit and all operating days when 

insufficient monitoring data are 

collectedf

—PRg. 
Page 153 of 162 

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

Catalytic incinerator Temperature upstream and 

downstream of the catalyst 

bed (63.644(a)(1)(ii)) 

1. Continuous recordsc

. 

 2. Record and report the upstream and 

downstream temperatures and the 

temperature difference across the 

catalyst bed averaged over the full 

period of the performance test—NCSd

.

 3. Record the daily average upstream 

temperature and temperature 

difference across the catalyst bed for 

each operating daye

. 

 4. Report all daily average upstream 

temperatures that are outside the range 

established in the NCS or operating 

permit—PRg

. 

 5. Report all daily average 

temperature differences across the 

catalyst bed that are outside the range 

established in the NCS or operating 

permit—PRg

. 

 6. Report all operating days when 

insufficient monitoring data are 

collectedf

. 

Boiler or process heater 

with a design heat capacity 

less than 44 megawatts 

where the vent stream is 

not introduced into the 

flame zoneh,i

Firebox temperatureb

(63.644(a)(4)) 

1. Continuous recordsc. 

 2. Record and report the firebox 

temperature averaged over the full 

period of the performance test—NCSd

.

 3. Record the daily average firebox 

temperature for each operating daye

. 

 4. Report all daily average firebox 

temperatures that are outside the range 

established in the NCS or operating 

permit and all operating days when 

insufficient monitoring data are 

collectedf

—PRg. 
Page 154 of 162 

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

Flare (if meeting the 

requirements of 63.643 

and 63.644)

Presence of a flame at the 

pilot light (63.644(a)(2)) 

1. Hourly records of whether the 

monitor was continuously operating 

and whether a pilot flame was 

continuously present during each 

hour. 

 2. Record and report the presence of a 

flame at the pilot light over the full 

period of the compliance 

determination—NCSd

. 

 3. Record the times and durations of 

all periods when all pilot flames for a 

flare are absent or the monitor is not 

operating. 

 4. Report the times and durations of 

all periods when all pilot flames for a 

flare are absent or the monitor is not 

operating. 

Flare (if meeting the 

requirements of 63.670 

and 63.671) 

The parameters specified 

in 63.670 

1. Records as specified in 

63.655(i)(9). 

2. Report information as specified in 

63.655(g)(11)—PRg. 

All control devices PresenceVolume of 

flowthe gas stream

diverted to the atmosphere 

from the control device 

(63.644(c)(1)) or 

1. ContinuousHourly records of 

whether the flow indicator was 

operating and whether flow was 

detected at any time during each 

hour.c.

 2. Record and report the times and 

durations of all periods when the vent 

stream is diverted through a bypass 

line or the monitor is not operating—

PRg

. 

 Monthly inspections of 

sealed valves 

[(63.644(c)(2)]))

1. Records that monthly inspections 

were performed. 

 2. Record and report all monthly 

inspections that show the valves are 

not closed or the seal has been 

changed—PRg

. 

a

Regulatory citations are listed in parentheses. 
Page 155 of 162 

b

Monitor may be installed in the firebox or in the ductwork immediately downstream of the 

firebox before any substantial heat exchange is encountered. 

c

“Continuous records” is defined in §63.641. 

d

NCS = Notification of Compliance Status Report described in §63.655. 

e

The daily average is the average of all recorded parameter values for the operating day. If all 

recorded values during an operating day are within the range established in the NCS or operating 

permit, a statement to this effect can be recorded instead of the daily average. 

f

When a period of excess emission is caused by insufficient monitoring data, as described in 

§63.655(g)(6)(i)(C) or (D), the duration of the period when monitoring data were not collected 

shall be included in the Periodic Report. 

g

PR = Periodic Reports described in §63.655(g). 

h

No monitoring is required for boilers and process heaters with a design heat capacity ≥44 

megawatts or for boilers and process heaters where all vent streams are introduced into the flame 

zone. No recordkeeping or reporting associated with monitoring is required for such boilers and 

process heaters. 

i

Process vents that are routed to refinery fuel gas systems are not regulated under this subpart

provided that on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], any flares receiving gas from that fuel gas system are in compliance with 

§63.670. No monitoring, recordkeeping, or reporting is required for boilers and process heaters 

that combust refinery fuel gas. 

Table 11—Compliance Dates and Requirements 

If the construction/ 

reconstruction 

datea is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as provided 

in... 

(1) After [INSERT 

THE DATE OF 

PUBLICATION 

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) 
Page 156 of 162 

If the construction/ 

reconstruction 

datea is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as provided 

in... 

(ii) 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 

IN THE 

FEDERAL 

REGISTER] 

(i) Requirements for 

new sources in 

§§63.640 through 

63.653 and 63.656b,c

(a) Upon initial 

startup 

(1) §63.640(k), (l) 

and (m) 

(ii) Requirements for 

new sources in 

§§63.640 through 

63.645, §§63.647 

through 63.653, and 

§§63.656, through 

63.658b

(a) On or before 

[THE DATE 3 

YEARS AFTER 

THE DATE OF 

PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iii) Requirements for 

new sources in §63.660c

(a) On or before 

[THE DATE 90 

DAYS AFTER THE 

DATE OF 

PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iv) The new source 

requirements in 

§63.654 for heat 

exchange systems 

(a) Upon initial 

startup or October 

28, 2009, whichever 

is later 

(1) §63.640(k), (l) 

and (m) 

(3) After July 14, 

1994 but on or 

before September 

4, 2007 

(i) Requirements for 

new sources in 

§§63.640 through 

63.653 and 63.656d,e

(a) Upon initial 

startup or August 18, 

1995, whichever is 

later 

(1) §63.640(k), (l) 

and (m) 
Page 157 of 162 

If the construction/ 

reconstruction 

datea is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as provided 

in... 

(ii) Requirements for 

new sources in 

§§63.640 through 

63.645, §§63.647 

through 63.653, and 

§§63.656, through 

63.658d

(a) On or before 

[THE DATE 3 

YEARS AFTER 

THE DATE OF 

PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iii) Requirements for 

new sources in §63.660e

(a) On or before 

[THE DATE 90 

DAYS AFTER THE 

DATE OF 

PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iv) The existing source 

requirements in 

§63.654 for heat 

exchange systems 

(a) On or before 

October 29, 2012 

(1) §63.640(k), (l) 

and (m) 

(4) On or before 

July 14, 1994 

(i) Requirements for 

existing sources in 

§§63.640 through 

63.653 and 63.656f,g

(a) On or before 

August 18, 1998 

(1) §63.640(k), (l) 

and (m) 

(2) §63.6(c)(5) of 

subpart A of this 

part or unless an 

extension has been 

granted by the 

Administrator as 

provided in §63.6(i) 

of subpart A of this 

part 

(ii) Requirements for 

existing sources in 

§§63.640 through 

63.645, §§63.647 

through 63.653, and 

§§63.656 through 

63.658f

(a) On or before 

[THE DATE 3 

YEARS AFTER 

THE DATE OF 

PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 
Page 158 of 162 

If the construction/ 

reconstruction 

datea is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as provided 

in... 

(iii) Requirements for 

existing sources in 

§63.660g

(a) On or before 

[THE DATE 90 

DAYS AFTER THE 

DATE OF 

PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(1) §63.640(k), (l) 

and (m) 

(iii) The existing source 

requirements in 

§63.654 for heat 

exchange systems 

(a) On or before 

October 29, 2012 

(1) §63.640(k), (l) 

and (m) 

a

 For purposes of this table, the construction/reconstruction date means the date of 

construction or reconstruction of an entire affected source or the date of a process unit 

addition or change meeting the criteria in §63.640(i) or (j). If a process unit addition or 

change does not meet the criteria in §63.640(i) or (j), the process unit shall comply with the 

applicable requirements for existing sources. 

b

 Between the compliance dates in items (2)(i)(a) and (2)(ii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (2)(i) or item (2)(ii) of 

this table. The requirements in item (2)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (2)(ii) of this table. 

c

 Between the compliance dates in items (2)(i)(a) and (2)(iii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (2)(i) or item (2)(iii) of 

this table. The requirements in item (2)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (2)(iii) of this table. 

d

 Between the compliance dates in items (3)(i)(a) and (3)(ii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (3)(i) or item (3)(ii) of 

this table. The requirements in item (3)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (3)(ii) of this table. 

e

 Between the compliance dates in items (3)(i)(a) and (3)(iii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (3)(i) or item (3)(iii) of 

this table. The requirements in item (3)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (3)(iii) of this table. 

f

 Between the compliance dates in items (4)(i)(a) and (4)(ii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (4)(i) or item (4)(ii) of 
Page 159 of 162 

this table. The requirements in item (4)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (4)(ii) of this table. 

g

 Between the compliance dates in items (4)(i)(a) and (4)(iii)(a) of this table, the owner or 

operator may elect to comply with either the requirements in item (4)(i) or item (4)(iii) of 

this table. The requirements in item (4)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (4)(iii) of this table. 

Table 12— Individual Component Properties 

Component 

Molecular 

Formula 

MWi

(pounds per 

poundmole) 

CMNi

(mole per 

mole) 

NHVi

(British thermal 

units per standard 

cubic foot) 

LFLi

(volume 

%) 

Acetylene C2H2 26.04 2 1,404 2.5 

Benzene C6H6 78.11 6 3,591 1.3 

1,2-Butadiene C4H6 54.09 4 2,794 2.0 

1,3-Butadiene C4H6 54.09 4 2,690 2.0 

iso-Butane C4H10 58.12 4 2,957 1.8 

n-Butane C4H10 58.12 4 2,968 1.8 

cis-Butene C4H8 56.11 4 2,830 1.6 

iso-Butene C4H8 56.11 4 2,928 1.8 

trans-Butene C4H8 56.11 4 2,826 1.7 

Carbon Dioxide CO2 44.01 1 0 ∞

Carbon 

Monoxide 

CO 28.01 1 316 12.5 

Cyclopropane C3H6 42.08 3 2,185 2.4 

Ethane C2H6 30.07 2 1,595 3.0 

Ethylene C2H4 28.05 2 1,477 2.7 

Hydrogen H2 2.02 0 274 4.0 

Methane CH4 16.04 1 896 5.0 

Methyl-Acetylene C3H4 40.06 3 2,088 1.7 

Nitrogen N2 28.01 0 0 ∞

Oxygen O2 32.00 0 0 ∞

Pentane+ (C5+) C5H12 72.15 5 3,655 1.4 

Propadiene C3H4 40.06 3 2,066 2.16 

Propane C3H8 44.10 3 2,281 2.1 

Propylene C3H6 42.08 3 2,150 2.4 

Water H2O 18.02 0 0 ∞
Page 160 of 162 

Table 13—Calibration and Quality Control Requirements for CPMS 

Parameter Accuracy requirements Calibration requirements 

Temperature ±1 percent over the normal 

range of temperature 

measured or 2.8 degrees 

Celsius (5 degrees 

Fahrenheit), whichever is 

greater, for non-cryogenic 

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 

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 
Page 161 of 162 

Parameter Accuracy requirements Calibration requirements 

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 inleakages, or other point at which a 

change in the pollutant 

concentration or emission rate 

occurs. 

Net Heating 

Value by Gas 

Chromatogra

ph 

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 performed every quarter. 

For both the calibration drift and error 

tests, the calibration gases should be 

injected into the sampling system as 
Page 162 of 162 

Parameter Accuracy requirements Calibration requirements 

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.