September 2015 

Redline of 40 CFR part 63, subpart CC, showing final 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 (89) 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. 
Page 2 of 175 

(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 [insert date 3 years and 60 days after date of publication in the Federal 

Register], any flares receiving gas from that fuel gas system are subject to §63.670. No
Page 3 of 175 

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 

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

§63.655(h)(6)(ii). 
Page 4 of 175 

(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; 

(3) Units processing natural gas liquids; 

(4) Units that are used specifically for recycling discarded oil; 
Page 5 of 175 

(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) Except as provided in paragraphs (k), (l), or (m) of this section, sourcesSources 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(1) Marine tank vessels at existing sources shall be in compliance with this subpart, except for 

§§63.657 through 63.660, 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. 

(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 
Page 6 of 175 

(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); 

(ii) The Notification of Compliance Status report as required by §63.655(f) for a new source, 

addition, or change; 
Page 7 of 175 

(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. 

(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 
Page 8 of 175 

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 

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. 
Page 9 of 175 

(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.

(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 subject to 40 CFR part 60, subpart Kb is required to comply 

only with 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 §60.112bprovisions of 

40 CFR part 6061, subpart KbY is required to comply only with the requirements of 40 CFR 

part 6061, subpart KbY, except as provided in paragraph (n)(810) of this section. 

(4(2) After the compliance dates specified in paragraph (h) of this section, a Group 1 

storage vessel that is also subject to 40 CFR part 60, subpart Kb is required to comply only 

with either 40 CFR part 60, subpart Kb, except as provided in paragraph (n)(8) of this 

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

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

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

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

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

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

controls by 40 CFR 60.110b or 60.112b, is required to comply only with this subpart. 
Page 10 of 175 

(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 forin 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)(viii) 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. 

(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. 
Page 11 of 175 

(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)(1)(iv) or §60.112b(a)(2)(ii) of this chapter, 

guidepoles in floating roof storage vessels must be equipped with covers and/or controls 

(e.g., pole float system, pole sleeve system, internal sleeve system or flexible enclosure 

system) as appropriate to comply with the “no visible gap” requirement. 

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

years and 60 days after date of publication 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 

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 
Page 12 of 175 

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)(10)(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. 

(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(a)(6) or §61.271(b)(3) of this chapter, guidepoles in 

floating roof storage vessels must be equipped with covers and/or controls (e.g., pole float 
Page 13 of 175 

systems, pole sleeve system, internal sleeve system or flexible enclosure system) as 

appropriate to comply with the “no visible gap” requirement. 

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

years and 60 days after date of publication 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 [insert date 3 years and 60 days after 

date of publication in the Federal Register], the flare shall meet the requirements of 

§63.670. Prior to [insert date 3 years and 60 days after date of publication 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. 
Page 14 of 175 

(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 [insert date 3 years and 60 days after 

date of publication in the Federal Register], the flare shall meet the requirements of 

§63.670. Prior to [insert date 3 years and 60 days after date of publication 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.

(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 

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. 

(s) Overlap of subpart CC with other regulation for flares. On [insert date 3 years and 60 

days after date of publication in the Federal Register], flares that are subject to the 

provisions of 40 CFR 60.18 or 40 CFR 63.11 and subject to this subpart are required to 

comply only with the provisions specified in this subpart. Prior to [insert date 3 years and 

60 days after date of publication in the Federal Register], flares that are subject to the 

provisions of 40 CFR 60.18 or 40 CFR 63.11 and elect to comply with the requirements in 

§§63.670 and 63.671 are required to comply only with the provisions specified in this 

subpart. 
Page 15 of 175 

§ 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. 

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. 
Page 16 of 175 

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. 

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. 
Page 17 of 175 

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 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 miscellaneous process vent that contains uncondensed vapors 

from the delayed coking unit’s blowdown system. Venting from the delayed coker vent is 

typically intermittent in nature, and usually occurs onlyprimarily 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 closed 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 

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. 
Page 18 of 175 

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 gas intentionally 

introduced into the flare header system 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 gas intentionally introduced 

into the flare header system 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), that portion of flare sweep gas that is not recovered, flare purge gas 

and flare supplemental gas, but does not include pilot gas, total steam or assist air. 

Flexible enclosure device means a seal made of an elastomeric fabric (or other material) 

which completely encloses a slotted guidepole or ladder and eliminates the vapor emission 

pathway from inside the storage vessel through the guidepole slots or ladder slots to the 

outside 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 175 

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

position would allow gas to flow, in a line. 

Force majeure event means a release of HAP, either directly to the atmosphere from a relief 

valve or discharged via a flare, that is demonstrated to the satisfaction of the Administrator 

to result from an event beyond the refinery owner or operator’s control, such as natural 

disasters; acts of war or terrorism; loss of a utility external to the refinery (e.g., external 

power curtailment), excluding power curtailment due to an interruptible service 

agreement; and fire or explosion originating at a near or adjoining facility outside of the 

refinery that impacts the refinery’s ability to operate. 

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. 
Page 20 of 175 

Group 1 storage vessel means a: 

(1) Prior to [insert date 60 days after date of publication in the Federal Register]: 

(i) A storage vessel at an existing source that has a design capacity greater than or equal to 177 

cubic meters and stored-liquid maximum true vapor pressure greater than or equal to 10.4 

kilopascals and stored-liquid annual average true vapor pressure greater than or equal to 8.3 

kilopascals and annual average HAP liquid concentration greater than 4 percent by weight total 

organic HAP; 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 [insert date 60 days after date of publication 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 
Page 21 of 175 

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

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

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

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

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

loading rack. 

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

Group 1 marine tank vessel. 

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

definition of a Group 1 miscellaneous process vent. 

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

storage vessel. 

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

Group 1 wastewater stream. 

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 

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 
Page 22 of 175 

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. 

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: 
Page 23 of 175 

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

years and 60 days after date of publication in the Federal Register], any flares receiving gas 

from the fuel gas system are subject to §63.670; 

(2) Relief valvePressure relief device discharges; 

(3) Leaks from equipment regulated under §63.648; 

(4) Episodic or nonroutine releases such as those associated with startup, shutdown, malfunction, 

maintenance, depressuring, and catalyst transfer operations;[Reserved];

(5) In situ sampling systems (onstream analyzers);) until [insert date 3 years and 60 days after 

date of publication 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; 

(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. 
Page 24 of 175 

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 

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, 

whether injected or induced, prior to the flare tip. Premix assist air also includes any air 

intentionally entrained in center steam.
Page 25 of 175 

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

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

addition of other fuels. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

stopping production are not considered process unit shutdowns. 

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

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

absorbers, carbon adsorbers, and condensers. 

Reference control technology for gasoline loading racks means a vapor collection and processing 

system used to reduce emissions due to the loading of gasoline cargo tanks to 10 milligrams of 

total organic compounds per liter of gasoline loaded or less. 

Reference control technology for marine vessels means a vapor collection system and a control 

device that reduces captured HAP emissions by 97 percent. 

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, including an external floating roof converted to an internal 

floating roof, meeting the specifications of §§63.1063(a)(1)(i) and (b); 
Page 26 of 175 

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

or 

(iii) [Reserved] 

(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; 

(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. 

Regulated material means any stream associated with emission sources listed in §63.640(c) 

required to meet control requirements under this subpart as well as any stream for which 
Page 27 of 175 

this subpart or a cross-referencing subpart specifies that the requirements for flare control 

devices in §63.670 must be met. 

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 

(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. 

Thermal expansion relief valve means a pressure relief valve designed to protect equipment 

from excess pressure due to thermal expansion of blocked liquid-filled equipment or piping 

due to ambient heating or heat from a heat tracing system. Pressure relief valves designed 

to protect equipment from excess pressure due to blockage against a pump or compressor 

or due to fire contingency are not thermal expansion relief valves. 
Page 28 of 175 

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

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

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

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

specified in this subpart. 

(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 
Page 29 of 175 

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 02.0 EPV EPV 05.0 ESES EGLR )( EMVREGLR 

where: 

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

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

miscellaneous process vents, as defined in §63.641. 

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

in §63.641. 
Page 30 of 175 

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. 

(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. 
Page 31 of 175 

(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 §63.63.646, 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 §63.655§§63.648 and/or 63.649, 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, 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. 

§ 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 or, if 
Page 32 of 175 

applicable, paragraph (c) of this section. The owner or operator of a miscellaneous process 

vent that meets the conditions in paragraph (c) of this section is only required to comply 

with the requirements of paragraph (c) of this section and §63.655(g)(13) and (i)(12) of this 

subpart for that vent. 

(1) Reduce emissions of organic HAP’s using a flare that meets. On and after [insert date 3 

years and 60 days after date of publication in the Federal Register], the flare shall meet the 

requirements of §63.670. Prior to [insert date 3 years and 60 days after date of publication 

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. 

(c) An owner or operator may designate a process vent as a maintenance vent if the vent is 

only used as a result of startup, shutdown, maintenance, or inspection of equipment where 

equipment is emptied, depressurized, degassed or placed into service. The owner or 

operator does not need to designate a maintenance vent as a Group 1 or Group 2 

miscellaneous process vent. The owner of operator must comply with the applicable 

requirements in paragraph (c)(1) through (c)(3) for each maintenance vent. 

(1) Prior to venting to the atmosphere, process liquids are removed from the equipment as 

much as practical and the equipment is depressured to a control device, fuel gas system, or 

back to the process until one of the following conditions, as applicable, is met. 

(i) The vapor in the equipment served by the maintenance vent has a lower explosive limit 

(LEL) of less than 10 percent. 

(ii) If there is no ability to measure the LEL of the vapor in the equipment based on the 

design of the equipment, the pressure in the equipment served by the maintenance vent is 

reduced to 5 psig or less. Upon opening the maintenance vent, active purging of the 

equipment cannot be used until the LEL of the vapors in the maintenance vent (or inside 

the equipment if the maintenance is a hatch or similar type of opening) equipment is less 

than 10 percent. 

(iii) The equipment served by the maintenance vent contains less than 72 pounds of VOC. 
Page 33 of 175 

(iv) If the maintenance vent is associated with equipment containing pyrophoric catalyst 

(e.g., hydrotreaters and hydrocrackers) at refineries that do not have a pure hydrogen 

supply, the LEL of the vapor in the equipment must be less than 20 percent, except for one 

event per year not to exceed 35 percent. 

(2) Except for maintenance vents complying with the alternative in (c)(1)(iii), the owner or 

operator must determine the LEL or, if applicable, equipment pressure using process 

instrumentation or portable measurement devices and follow procedures for calibration 

and maintenance according to manufacturer’s specifications. 

(3) For maintenance vents complying with the alternative in (c)(1)(iii), the owner or 

operator shall determine mass of VOC in the equipment served by the maintenance vent 

based on the equipment size and contents after considering any contents drained or purged 

from the equipment. Equipment size may be determined from equipment design 

specifications. Equipment contents may be determined using process knowledge. 

§ 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, except for CPMS installed for pilot flame monitoring, 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 [insert date 3 years and 60 days after date of publication in 

the Federal Register], a device (including but not limited to a thermocouple, an ultraviolet beam 

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

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

[insert date 3 years and 60 days after date of publication in the Federal Register], the 

requirements of §63.670 shall be met. 
Page 34 of 175 

(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 the requirements in §63.643(a) of this sectioneither directly to the 

atmosphere or to a control device that does not comply with the requirements in §63.643(a)

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 to the atmosphere or to a control 

device that does not comply with the requirements in §63.643(a) 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, calibrate, and maintain, and operate a flow indicator that determines whether a vent 

stream flow is present at least once every hour. A manual block valve equipped with a valve 

position indicator may be used in lieu of a flow indicator, as long as the valve position 

indicator is monitored continuously. 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 

(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. 
Page 35 of 175 

(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 

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. 
Page 36 of 175 

(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. 

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

2 jj QMCKE



 



  1

where: 
Page 37 of 175 

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: 

TOC  TOC2 MQCKE s

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. 

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. 
Page 38 of 175 

(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 

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. 
Page 39 of 175 

(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 A shall be used.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).

(c) The following paragraphs do not apply to storage vessels at existing sources subject to this 

subpart: §63.119 (b)(5), (b)(6), (c)(2), and (d)(2). 

(d) References shall apply as specified in paragraphs (d)(1) through (d)(10) of this section. 

(1) All references to §63.100(k) of subpart F of this part (or the schedule provisions and the 

compliance date) shall be replaced with §63.640(h), 

(2) All references to April 22, 1994 shall be replaced with August 18, 1995. 

(3) All references to December 31, 1992 shall be replaced with July 15, 1994. 

(4) All references to the compliance dates specified in §63.100 of subpart F shall be replaced 

with §63.640 (h) through (m). 

(5) All references to §63.150 in §63.119 of subpart G of this part shall be replaced with §63.652. 

(6) All references to §63.113(a)(2) of subpart G shall be replaced with §63.643(a)(2) of this 

subpart. 
Page 40 of 175 

(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. 

(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 
Page 41 of 175 

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 [insert date 3 years and 60 days after 

date of publication in the Federal Register], the flare shall meet the requirements of 

§63.670. Prior to [insert date 3 years and 60 days after date of publication in the Federal 

Register], the flare shall meet the applicable requirements of part 61, subpart FF of this 

chapter, or the requirements of §63.670. 

(d) Each owner or operator required under subpart FF of 40 CFR part 61 to perform periodic 

measurement of benzene concentration in wastewater, or to monitor process or control device 

operating parameters shall operate in a manner consistent with the minimum or maximum (as 

appropriate) permitted concentration or operating parameter values. Operation of the process, 

treatment unit, or control device resulting in a measured concentration or operating parameter 

value outside the permitted limits shall constitute a violation of the emission standards. Failure to 

perform required leak monitoring for closed vent systems and control devices or failure to repair 

leaks within the time period specified in subpart FF of 40 CFR part 61 shall constitute a violation 

of the standard. 

§ 63.648 Equipment leak standards. 

(a) Each owner or operator of an existing source subject to the provisions of this subpart shall 

comply with the provisions of 40 CFR part 60 subpart VV 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. 

(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. 
Page 42 of 175 

(3) If a flare is used as a control device, on and after [insert date 3 years and 60 days after 

date of publication in the Federal Register], the flare shall meet the requirements of 

§63.670. Prior to [insert date 3 years and 60 days after date of publication 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 

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. 

(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. 
Page 43 of 175 

(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. 

(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) [Reserved] 

(12) If a flare is used as a control device, on and after [insert date 3 years and 60 days after 

date of publication in the Federal Register], the flare shall meet the requirements of 

§63.670. Prior to [insert date 3 years and 60 days after date of publication 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. 
Page 44 of 175 

(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. 

(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 

pressure relief devices, such as relief valves or rupture disks, 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 paragraphs (j)(4) and (j)(5) of this section, the owner or 
Page 45 of 175 

operator must also comply with the requirements specified in paragraph (j)(3) of this 

section for all pressure relief devices. 

(1) Operating requirements. Except during a pressure release, operate each pressure relief 

device 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 pressure relief devices in organic HAP gas or vapor 

service, the owner or operator must comply with the applicable requirements in 

paragraphs (j)(2)(i) through (iii) of this section following a pressure release. 

(i) If the pressure relief device 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 pressure relief device returns to organic HAP gas or vapor service 

following a pressure release to verify that the pressure relief device is operating with an 

instrument reading of less than 500 ppm. 

(ii) If the pressure relief device includes a rupture disk, either comply with the 

requirements in (j)(2)(i) of this section (not replacing the rupture disk) or 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 conduct instrument 

monitoring, as specified in §60.485(b) or §63.180(c), as applicable, no later than 5 calendar 

days after the pressure relief device returns to organic HAP gas or vapor service following 

a pressure release to verify that the pressure relief device is operating with an instrument 

reading of less than 500 ppm. 

(iii) If the pressure relief device consists only of 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 may not initiate startup of the equipment served 

by the rupture disk until the rupture disc is replaced., The owner or operator must conduct 

instrument monitoring, as specified in §60.485(b) or §63.180(c), as applicable, no later than 

5 calendar days after the pressure relief device returns to organic HAP gas or vapor service 

following a pressure release to verify that the pressure relief device is operating with an 

instrument reading of less than 500 ppm. 

(3) Pressure release management. Except as specified in paragraphs (j)(4) and (j)(5) of this 

section, the owner or operator shall comply with the requirements specified in paragraphs 

(j)(3)(i) through (v) of this section for all pressure relief devices in organic HAP service no 

later than [insert date 3 years and 60 days after date of publication in the Federal 

Register]. 

(i) The owner or operator must equip each affected pressure relief device 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 
Page 46 of 175 

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) The owner or operator must apply at least three redundant prevention measures to 

each affected pressure relief device and document these measures. Examples of prevention 

measures include: 

(A) Flow, temperature, level and pressure indicators with deadman switches, monitors, or 

automatic actuators. 

(B) Documented routine inspection and maintenance programs and/or operator training 

(maintenance programs and operator training may count as only one redundant 

prevention measure). 

(C) Inherently safer designs or safety instrumentation systems. 

(D) Deluge systems. 

(E) Staged relief system where initial pressure relief valve (with lower set release pressure) 

discharges to a flare or other closed vent system and control device. 

(iii) If any affected pressure relief device releases to atmosphere as a result of a pressure 

release event, the owner or operator must perform root cause analysis and corrective 

action analysis according to the requirement in paragraph (j)(6) of this section and 

implement corrective actions according to the requirements in paragraph (j)(7) of this 

section. The owner or operator must also 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 pressure relief device 

monitoring alone or in combination with process parameter monitoring data and process 

knowledge. 

(iv) The owner or operator shall determine the total number of release events occurred 

during the calendar year for each affected pressure relief device separately. The owner or 

operator shall also determine the total number of release events for each pressure relief 

device for which the root cause analysis concluded that the root cause was a force majeure 

event, as defined in this subpart. 

(v) Except for pressure relief devices described in paragraphs (j)(4) and (5) of this section, 

the following release events are a violation of the pressure release management work 

practice standards. 

(A) Any release event for which the root cause of the event was determined to be operator 

error or poor maintenance. 
Page 47 of 175 

(B) A second release event not including force majeure events from a single pressure relief 

device in a 3 calendar year period for the same root cause for the same equipment. 

(C) A third release event not including force majeure events from a single pressure relief 

device in a 3 calendar year period for any reason. 

(4) Pressure relief devices routed to a control device. If all releases and potential leaks from a 

pressure relief device are routed through a closed vent system to a control device, back into 

the process or to the fuel gas system, 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 

“pressure relief device.” If a pressure relief device complying with this paragraph is routed 

to the fuel gas system, then on and after [insert date 3 years and 60 days after date of 

publication in the Federal Register], any flares receiving gas from that fuel gas system must 

be in compliance with §63.670. 

(5) Pressure relief devices exempted from pressure release management requirements. The 

following types of pressure relief devices are not subject to the pressure release 

management requirements in paragraph (j)(3). 

(i) Pressure relief devices in heavy liquid service, as defined in §63.641. 

(ii) Pressure relief devices that only release material that is liquid at standard conditions (1 

atmosphere and 68 degrees Fahrenheit) and that are hard-piped to a controlled drain 

system (i.e., a drain system meeting the requirements for Group 1 wastewater streams in 

§63.647(a)) or piped back to the process or pipeline. 

(iii) Thermal expansion relief valves. 

(iv) Pressure relief devices designed with a set relief pressure of less than 2.5 psig. 

(v) Pressure relief devices that do not have the potential to emit 72 lbs/day or more of VOC 

based on the valve diameter, the set release pressure, and the equipment contents. 

(vi) Pressure relief devices on mobile equipment. 

(6) Root cause analysis and corrective action analysis. A root cause analysis and corrective 

action analysis must be completed as soon as possible, but no later than 45 days after a 

release event. Special circumstances affecting the number of root cause analyses and/or 

corrective action analyses are provided in paragraphs (j)(6)(i) through (iv) of this section. 

(i) You may conduct a single root cause analysis and corrective action analysis for a single 

emergency event that causes two or more pressure relief devices installed on the same 

equipment to release. 
Page 48 of 175 

(ii) You may conduct a single root cause analysis and corrective action analysis for a single 

emergency event that causes two or more pressure relief devices to release, regardless of 

the equipment served, if the root cause is reasonably expected to be a force majeure event, 

as defined in this subpart. 

(iii) Except as provided in paragraphs (j)(6)(i) and (ii), if more than one pressure relief 

device has a release during the same time period, an initial root cause analysis shall be 

conducted separately for each pressure relief device that had a release. If the initial root 

cause analysis indicates that the release events have the same root cause(s), the initially 

separate root cause analyses may be recorded as a single root cause analysis and a single 

corrective action analysis may be conducted. 

(7) Corrective action implementation. Each owner or operator required to conduct a root 

cause analysis and corrective action analysis as specified in paragraphs (j)(3)(iii) and (j)(6) 

shall implement the corrective action(s) identified in the corrective action analysis in 

accordance with the applicable requirements in paragraphs (j)(7)(i) through (iii) of this 

section. 

(i) All corrective action(s) must be implemented within 45 days of the event for which the 

root cause and corrective action analyses were required or as soon thereafter as 

practicable. If an owner or operator concludes that no corrective action should be 

implemented, the owner or operator shall record and explain the basis for that conclusion 

no later than 45 days following the event. 

(ii) For corrective actions that cannot be fully implemented within 45 days following the 

event for which the root cause and corrective action analyses were required, the owner or 

operator shall develop an implementation schedule to complete the corrective action(s) as 

soon as practicable. 

(iii) No later than 45 days following the event for which a root cause and corrective action 

analyses were required, the owner or operator shall record the corrective action(s) 

completed to date, and, for action(s) not already completed, a schedule for implementation, 

including proposed commencement and completion dates. 

§ 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. 
Page 49 of 175 

(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. 

(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. 
Page 50 of 175 

(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. 

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)(43)(iii) for existing process 

units, and after the date of start-up for new process units. If credits are not taken, then Cc = 0. 
Page 51 of 175 

(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. 

(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. 
Page 52 of 175 

§ 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 [insert date 3 years and 60 days after 

date of publication in the Federal Register], the flare shall meet the requirements of 

§63.670. Prior to [insert date 3 years and 60 days after date of publication 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. 

(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 [insert date 3 years and 60 days after 

date of publication in the Federal Register], the flare shall meet the requirements of 

§63.670. Prior to [insert date 3 years and 60 days after date of publication 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 
Page 53 of 175 

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. 

(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 
Page 54 of 175 

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 

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. 
Page 55 of 175 

(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. 

(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: 
Page 56 of 175 

       

   

  



  



     

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

03.0

02.0 05.0

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. 

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. 
Page 57 of 175 

(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 MCQh jj

1

9 10494.2

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. 

(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. 
Page 58 of 175 

(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: 

  T

SPMG EGLRiu

7 1020.1  

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). 
Page 59 of 175 

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

GP

P

j

nj

 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 







nj

GG j

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: 

  

G

GM

M

j

nj

 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. 
Page 60 of 175 

(iv) The following equation shall be used for each gasoline loading rack i to calculate the 

monthly weighted rack bulk liquid loading temperature: 

  

G

GT

T

j

nj

 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

8 101  

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. 

(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 PFQ iii

1
Page 61 of 175 

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. 

(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: 
Page 62 of 175 

    

    

  

    

   

 

 

 

 

 

 

 

 

 

  

   

   

   

    

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 EMV2D EMV2

EGLRD EGLR1 D EGLR2 EGLR2

D ES1ES1 ES2D ES2

DCredits EPV1 EPV1 EPV2D EPV2

1 1

1 1

1 1

1 1

1 1

03.0

05.0

02.0

where: 

Credits and all terms of the equation are in units of megagrams per month, the baseline date is 

November 15, 1990, and 

D = Discount factor = 0.9 for all credit-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. 

(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. 
Page 63 of 175 

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. 

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. 
Page 64 of 175 

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 eficiency% EPV1iACTUAL EPV1iu

(iii) The following procedures shall be used to calculate actual emissions from Group 2 process 

vents, EPV2iACTUAL: 

(A) For a Group 2 process vent controlled by a control device, a recovery device applied as a 

pollution prevention project, or a pollution prevention measure, if the control achieves a 

percentage of reduction less than or equal to a 98 percent reduction, 





 



 

%100

1 Percent reduction EPV2 EPV2 iACTUAL iu
Page 65 of 175 

(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 eficiency% EPV2iACTUAL EPV2iu

(iv) Emissions from Group 2 process vents at baseline, EPV2iBASE, shall be calculated as follows: 

(A) If the process vent was uncontrolled on November 15, 1990, EPV2iBASE = EPV2iu, and shall 

be calculated according to the procedures and equation for EPViu in paragraphs (g)(2)(i) and 

(g)(2)(ii) of this section. 

(B) If the process vent was controlled on November 15, 1990, 





 



 

%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 

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. 
Page 66 of 175 

(3) Emissions from storage vessels shall be determined as specified in §63.150(h)(3) of subpart 

G, except as follows: 

(i(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: 





 



 

%100

1 Nominal efficiency% EGLR1iACTUAL EGLR1iu

(iv) The following procedures shall be used to calculate actual emissions from Group 2 gasoline 

loading racks, EGLR2iACTUAL: 
Page 67 of 175 

(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 EGLR2 EGLR2 iBASE iu

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: 

(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: 
Page 68 of 175 





 



 

%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 EMV2iACTUAL EMV2iu

(iv) Emissions from Group 2 marine tank vessels at baseline, EMV2iBASE, shall be calculated as 

follows: 

(A) If the marine terminal was uncontrolled on November 15, 1990, EMV2iBASE equals EMV2iu, 

and shall be calculated according to the procedures and equations for EMViu in paragraph 

(g)(5)(i) of this section. 

(B) If the marine tank vessel was controlled on November 15, 1990, 





 



 

%100

1 Percent reduction EMV2iBASE EMV2iu

where EMV2iu is calculated according to the procedures and equations for EMViu in paragraph 

(g)(5)(i) of this section. Percentage of reduction shall be calculated according to the procedures 

in paragraphs (g)(5)(ii)(B)(1) and (g)(5)(ii)(B)(2) of this section. 

(6) Emissions from wastewater shall be determined as follows: 

(i) For purposes of paragraphs (h)(4)(ii) through (h)(4)(vi) of this section, the following terms 

will have the meaning given them in paragraphs (h)(6)(i)(A) through (h)(6)(i)(C) of this section. 
Page 69 of 175 

(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

ii imm

s

m

EWWic ii HAPFeFrHQ immm HAPFrHQ

1

8

1

8 100.6 1 100.605.0

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. 

(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: 
Page 70 of 175 

(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

ii imim

s

m

EWW1iACTUAL ii HAPFeHQ imm PRim PRHAPHQ

1

8

1

8 100.6 1 100.605.0

Where: 

EWWiACTUAL = Monthly wastewater stream emission rate if wastewater stream i is treated to a 

level more stringent than the reference control technology, megagrams per month. 

PRim = The efficiency of the treatment process, or series of treatment processes, that treat 

wastewater stream i in reducing the emission potential of organic HAP m in wastewater, 

dimensionless, as calculated by: 

inim

inim outim

im HAP

HAP HAP PR



   

Where: 
Page 71 of 175 

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

ii mim

s

m

iACTUAL ii m im m AHAPHQ Nominal efficiency% EWW1 AHAPFeHQ 1

8

1

8 100.6

100

100.6 11

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 

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 
Page 72 of 175 

control device has an approved nominal efficiency greater than 95 percent, the following 

equation shall be used: 

         







   

 



  

s

m

ii imim

s

m

iACTUAL ii imm im PRHAPHQ Nominal efficiency% EWW1 HAPFeHQ PR 1

8

1

8 100.6

100

100.6 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 ii HAPFeHQ imm

1

8 100.62

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

ii imim

i

s

m

iBASE ii imm im PRHAPHQ R EWW2 HAPFeHQ PR 1

8

1

8 100.6

%100

100.6 1 1

where Ri is calculated according to paragraph (h)(6)(vii) of this section and all other terms are as 

defined and determined according to paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of this section. 

(vi) For Group 2 wastewater streams that are correctly suppressed, EWW2iACTUAL shall be 

calculated according to the equation for EWW2iBASE in paragraph (h)(6)(v) of this section. 

EWW2iACTUAL shall be calculated with all control methods in place accounted for. 

(vii) The reduction efficiency, Ri, of the vapor control device shall be demonstrated according to 

the following procedures: 
Page 73 of 175 

(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

iaip

m

p

a ap MWCV

m

E

1 1

6 10

0416.0

































   

n

p

ibip

m

p

b bp MWCV

m

E

1 1

6 10

0416.0

Where: 

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

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

Vap = Average volumetric flow rate of vent stream exiting the control device during run p at 

standards conditions, cubic meters per hour. 

Vbp = Average volumetric flow rate of vent stream entering the control device during run p at 

standards conditions, cubic meters per hour. 

p = Run. 

m = Number of runs. 
Page 74 of 175 

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

ab

E

EE 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. 

(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; 
Page 75 of 175 

(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. 

(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. 
Page 76 of 175 

(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. 

(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

Bpp

B

E

P

PE

E

Percent reduction

Where: 

Percent reduction = Efficiency of pollution prevention measure (percentage of organic HAP 

reduction). 
Page 77 of 175 

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 BiBi m HAPFeHQ Bim

1 1

8 6 100.

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. 

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. 
Page 78 of 175 

(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 ppippi m HAPFeHQ ppim

1 1

8 6 100.

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 

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. 
Page 79 of 175 

(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 

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, 
Page 80 of 175 

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. 

(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; 
Page 81 of 175 

(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. 

(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. 
Page 82 of 175 

(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. 

(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. 
Page 83 of 175 

(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. 

§ 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 
Page 84 of 175 

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 

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 
Page 85 of 175 

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 

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: 
Page 86 of 175 

(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 

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. 
Page 87 of 175 

(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 

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, 
Page 88 of 175 

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 

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. 
Page 89 of 175 

(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). 

(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 
Page 90 of 175 

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). 

(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 
Page 91 of 175 

(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. 

(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 
Page 92 of 175 

(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 pressure relief devices in organic HAP service subject to the requirement in 

§63.648(j)(3)(i) and (ii), this report shall include the information specified in paragraphs 

(f)(1)(vii)(A) and (B) of this section: 

(A) A description of the monitoring system to be implemented, including the relief devices 

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. 

(B) A description of the prevention measures to be implemented for each affected pressure 

relief device. 

(viii) For each delayed coking unit, identification of whether the unit is an existing affected 

source or a new affected source and whether monitoring will be conducted as specified in 

§63.657(b) or §63.657(c). 

(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 [insert date 60 days after date of 

publication in the Federal Register], performance tests shall be submitted according to 

paragraph (h)(9) of this section.
Page 93 of 175 

(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. 

(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. 
Page 94 of 175 

(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 (14) 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 paragraphs (g)(1) 

through (67) of this section or paragraphs (g)(9) through (14) 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 (914) of this section. 

(1) For storage vessels, Periodic Reports shall include the information specified for Periodic 

Reports in paragraphs (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. 

(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)(CA)(3) 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 
Page 95 of 175 

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)(CA)(3) 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. 

(B2) 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. 

(3(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 (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. 

(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). 
Page 96 of 175 

(3) External floating roofs. (i) An owner or operator who elects to comply with §63.646 by 

using an external floating roof shall meet the periodic reporting requirements specified in 

paragraphs (g)(3)(i)(A) through (g)(3)(iiiC) 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. 

(B2) 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. 

(4ii) An owner or operator who elects to comply with §63.6460 by using an external floating 

roof converted to an internal floating roof shall comply withmeet the periodic reporting 

requirements of paragraphspecified in paragraphs (g)(23)(ii)(A) and (B) of this section. 
Page 97 of 175 

(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) [Reserved] 

(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)(iiiv) 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(iii) If a flare is used prior to [insert date 3 years and 60 days after date 

of publication in the Federal Register] and prior to electing to comply with the 

requirements in §63.670, the Periodic Report shall describe each occurrence when the flare 

does not meet the general control device requirements specified in §63.11(b) of subpart A of this 

part and shall include: Identification of the flare that does not meet the general requirements 

specified in §63.11(b) of subpart A of this part, and reasons the flare did not meet the general 

requirements specified in §63.11(b) of subpart A of this part. 

(iv) If a flare is used on or after the date for which compliance with the requirements in 

§63.670 is elected, which can be no later than [insert date 3 years and 60 days after date of 
Page 98 of 175 

publication 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 periods in closed vent systems when a Group 1 miscellaneous process vent stream 

was detected in the bypass line or diverted from the control device and either directly to the 

atmosphere or to a control device that does not comply with the requirements in 

§63.643(a), report the date, time, duration, estimate of the volume of gas, the concentration 

of organic HAP in the gas and the resulting mass emissions of organic HAP that bypassed 

the control device. For periods when the flow indicator is not operating, report the date, 

time, and duration.Periods of startup and shutdown that meet the definition of §63.641, and 

malfunction that meet the definition in §63.2 and periods of performance testing and monitoring 

system calibration shall not be considered periods of excess emissions. Malfunctions may 

include process unit, control device, or monitoring system malfunctions.

(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 
Page 99 of 175 

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 

(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: 
Page 100 of 175 

(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 pressure relief devices subject to the requirements §63.648(j), Periodic Reports 

must include the information specified in paragraphs (g)(10)(i) through (iii) of this section. 

(i) For pressure relief devices in organic HAP gas or vapor service, pursuant to 

§63.648(j)(1), report any instrument reading of 500 ppm or greater. 

(ii) For pressure relief devices in organic HAP gas or vapor service subject to §63.648(j)(2), 

report confirmation that any monitoring required to be done during the reporting period 

to show compliance was conducted. 

(iii) For pressure relief devices in organic HAP service subject to §63.648(j)(3), report each 

pressure release to the atmosphere, including duration of the pressure release and estimate 

of the mass quantity of each organic HAP released, and the results of any root cause 

analysis and corrective action analysis completed during the reporting period, including 

the corrective actions implemented during the reporting period and, if applicable, the 
Page 101 of 175 

implementation schedule for planned corrective actions to be implemented subsequent to 

the reporting period. 

(11) For flares subject to §63.670, Periodic Reports must include the information specified 

in paragraphs (g)(11)(i) through (iv) of this section. 

(i) Records as specified in paragraph (i)(9)(i) of this section for each 15-minute block 

during which there was at least one minute when regulated material is routed to a flare and 

no pilot flame is present. 

(ii) Visible emission records as specified in paragraph (i)(9)(ii)(C) 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 net 

heating value operating parameter(s) determined following the methods in §63.670(k) 

through (n) as applicable. 

(iv) For flaring events meeting the criteria in §63.670(o)(3): 

(A) The start and stop time and date of the flaring event. 

(B) The length of time for which emissions were visible from the flare during the event. 

(C) The periods of time that the flare tip velocity exceeds the maximum flare tip velocity 

determine using the methods in §63.670(d)(2) and the maximum 15-minute block average 

flare tip velocity recorded during the event. 

(D) Results of the root cause and corrective actions analysis completed during the reporting 

period, including the corrective actions implemented to during the reporting period and, if 

applicable, the implementation schedule for planned corrective actions to be implemented 

subsequent to the reporting period. 

(12) For delayed coking units, the Periodic Report must include the information specified 

in paragraphs (g)(12)(i) through (iv) of this section. 

(i) For existing source delayed coking units, any 60-cycle average exceeding the applicable 

limit in §63.657(a)(1). 

(ii) For new source delayed coking units, any direct venting event exceeding the applicable 

limit in §63.657(a)(1). 

(iii) The total number of double quenching events performed during the reporting period. 

(iv) For each double quenching draining event when the drain water temperature exceeded 

210oF, report the drum, date, time, the coke drum vessel pressure or temperature, as 
Page 102 of 175 

applicable, when pre-vent draining was initiated, and the maximum drain water 

temperature during the pre-vent draining period. 

(13) For maintenance vents subject to the requirements in §63.643(c), Periodic Reports 

must include the information specified in paragraphs (g)(13)(i) through (iv) of this section 

for any release exceeding the applicable limits in §63.643(c)(1). For the purposes of this 

reporting requirement, owners or operators complying with §63.643(c)(1)(iv) must report 

each venting event for which the lower explosive limit is 20 percent or greater. 

(i) Identification of the maintenance vent and the equipment served by the maintenance 

vent. 

(ii) The date and time the maintenance vent was opened to the atmosphere. 

(iii) The lower explosive limit, vessel pressure, or mass of VOC in the equipment, as 

applicable, at the start of atmospheric venting. If the 5 psig vessel pressure option in 

§63.643(c)(1)(ii) was used and active purging was initiated while the lower explosive limit 

was 10 percent or greater, also include the lower explosive limit of the vapors at the time 

active purging was initiated. 

(iv) An estimate of the mass of organic HAP released during the entire atmospheric venting 

event. 

 (14) 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) 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[Reserved]

(2) For storage vessels, notifications of inspections as specified in paragraphs (h)(2)(i) and 

(h)(2)(ii) of this section;.

(i) In order to afford the Administrator the opportunity to have an observer present, the owner or 

operator shall notify the Administrator of the refilling of each Group 1 storage vessel that has 

been emptied and degassed. 

(A) Except as provided in paragraphs (h)(2)(i) (B) and (C) of this section, the owner or operator 

shall notify the Administrator in writing at least 30 calendar days prior to filling or refilling of 

each storage vessel with organic HAP’s to afford the Administrator the opportunity to inspect the 

storage vessel prior to refilling. 
Page 103 of 175 

(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. 

(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 
Page 104 of 175 

as part of the Notification of Compliance Status report required in paragraphs (e) and (f) of this 

section. 

(iii) The frequency and content of monitoring, recording, and reporting if: monitoring and 

recording are not continuous; or if periods of excess emissions, as defined in paragraph (g)(6) of 

this section, will not be identified in Periodic Reports required under paragraphs (e) and (g) of 

this section. The rationale for the proposed monitoring, recording, and reporting system shall be 

included. 

(5) An owner or operator may request approval to use alternatives to the continuous operating 

parameter monitoring and recordkeeping provisions listed in paragraph (i) of this section. 

(i) Requests shall be submitted with the Application for Approval of Construction or 

Reconstruction for new sources and no later than 18 months prior to the compliance date for 

existing sources. The information may be submitted in an operating permit application, in an 

amendment to an operating permit application, or in a separate submittal. Requests shall contain 

the information specified in paragraphs (h)(5)(iii) through (h)(5)(iv) of this section, as applicable. 

(ii) The provisions in §63.8(f)(5)(i) of subpart A of this part shall govern the review and approval 

of requests. 

(iii) An owner or operator may request approval to use an automated data compression recording 

system that does not record monitored operating parameter values at a set frequency (for 

example, once every hour) but records all values that meet set criteria for variation from 

previously recorded values. 

(A) The requested system shall be designed to: 

(1) Measure the operating parameter value at least once every hour. 

(2) Record at least 24 values each day during periods of operation. 

(3) Record the date and time when monitors are turned off or on. 

(4) Recognize unchanging data that may indicate the monitor is not functioning properly, alert 

the operator, and record the incident. 

(5) Compute daily average values of the monitored operating parameter based on recorded data. 

(B) The request shall containYou must maintain a record of the 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 

demonstrations that they 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. 
Page 105 of 175 

(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 quarterly reporting period covered by the periodic report, each owner or 

operator shall submit the following information to the EPA’s Compliance and Emissions 

Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA’s Central 

Data Exchange (CDX) (https://cdx.epa.gov/). 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 period during the 

quarterly 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 annual average concentration difference (Δc) values for benzene for the 

quarterly reporting period. 

(iii) Notation for each biweekly value that indicates whether background correction was 

used, all measurements in the sampling period were below detection, or whether an outlier 

was removed from the sampling period data set. 

(9) On and after [insert date 60 days after date of publication 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 according to the procedures in paragraphs 

(h)(9)(i) and (ii) of this section. 
Page 106 of 175 

(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 following 

the procedure specified in 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 Electronic Reporting 

Tool (ERT) as listed on the EPA’s ERT Web site 

(http://www.epa.gov/ttn/chief/ert/index.html) at the time of the test, the owner or operator 

must submit the results of the performance test to the EPA via the CEDRI. (CEDRI can be 

accessed through the EPA’s CDX.) Performance test data must be submitted in a file 

format generated through the use of the EPA’s ERT or an alternate electronic file format 

consistent with the extensible markup language (XML) schema listed on the EPA’s ERT 

Web site. 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 or an alternate 

electronic file consistent with the XML schema listed on the EPA’s ERT Web site, 

including information claimed to be CBI, on a compact disc, flash drive or other commonly 

used electronic storage media to the EPA. The electronic storage media must be clearly 

marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group 

Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. 

The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the 

EPA’s 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 Web site at the time of the test, 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 following the procedure specified in either paragraph (h)(9)(ii)(A) or 

(h)(9)(ii)(B) of this section. 

(A) For performance evaluations of continuous monitoring systems measuring relative 

accuracy test audit (RATA) pollutants that are supported by the EPA’s ERT as listed on 

the EPA’s ERT Web site at the time of the evaluation, the owner or operator must submit 

the results of the performance evaluation to the EPA via the CEDRI. (CEDRI can be 

accessed through the EPA’s CDX.) Performance evaluation data must be submitted in a 

file format generated through the use of the EPA’s ERT or an alternate file format 

consistent with the XML schema listed on the EPA’s ERT Web site. 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 or an alternate electronic file consistent with the XML schema listed on the 

EPA’s ERT Web site, including information claimed to be CBI, on a compact disc, flash 

drive or other commonly used electronic storage media to the EPA. The electronic storage 

media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, 

Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., 
Page 107 of 175 

Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be 

submitted to the EPA via the EPA’s CDX as described earlier in this paragraph. 

(B) For any performance evaluations of continuous monitoring systems measuring RATA 

pollutants that are not supported by the EPA’s ERT as listed on the EPA’s ERT Web site 

at the time of the evaluation, 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 (12) 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)(iviv) 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 or §63.998, as applicable. 

(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 108 of 175 

(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 either directly to the atmosphere or to a control device 

that does not comply with the requirements in §63.643(a), the owner or operator shall keep 
Page 109 of 175 

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 periods when flow was detected in the 

bypass line, including the date and time and the duration of the flow in the bypass line. For 

each flow event, the owner or operator shall maintain records sufficient to determine 

whether or not the detected flow included flow of a Group 1 miscellaneous process vent 

stream requiring control. For periods when the Group 1 miscellaneous process vent stream 

requiring control is diverted from the control device and released either directly to the 

atmosphere or to a control device that does not comply with the requirements in 

§63.643(a), 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 using process knowledge and engineering estimates. 

(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 mass emissions of 

organic HAP from the Group 1 miscellaneous process vent stream requiring control that 

bypassed the control device or records sufficient to demonstrate that there was no flow of a 

Group 1 miscellaneous process vent stream requiring control during the period. 

(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. 
Page 110 of 175 

(C) El Paso air stripping apparatus water flow milliliter/minute (ml/min) and air flow, ml/min, 

and air temperature, °Celsius. 

(D) FID reading (ppmv). 

(E) Length of sampling period. 

(F) Sample volume. 

(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 specified in paragraphs (i)(7)(i) through (iii) of 

this section. 

(i) The average pressure or temperature, as applicable, 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, 

(ii) If complying with the 60-cycle rolling average, each 60-cycle rolling average pressure or 

temperature, as applicable, considering all coke drum venting events in the existing 

affected source. 

(iii) For double-quench cooling cycles: 

(A) The date, time and duration of each pre-vent draining event.(B) The pressure or 

temperature of the coke drum vessel, as applicable, for the 15 minute period prior to the 

pre-vent draining.(C) The drain water temperature at 1-minute intervals from the start of 

pre-vent draining to the complete closure of the drain valve. (8) For fenceline monitoring 

systems subject to §63.658, each owner or operator shall keep the records specified in 

paragraphs (i)(8)(i) through (x) of this section on an ongoing basis. 
Page 111 of 175 

(i) Coordinates of all passive monitors, including replicate samplers and field blanks, and if 

applicable, 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) Sampling period average temperature and barometric pressure measurements. 

(iv) For each outlier determined in accordance with Section 9.2 of Method 325A of 

Appendix A of this part, the sampler location of and the concentration of the outlier and 

the evidence used to conclude that the result is an outlier. 

(v) For samples that will be adjusted for a background, the location of and the 

concentration measured simultaneously by the background sampler, and the perimeter 

samplers to which it applies. 

(vi) Individual sample results, the calculated Δc for benzene for each sampling period and 

the two samples used to determine it, whether background correction was used, and the 

annual average Δc calculated after each sampling period. 

(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. 

(x) If a near-field source correction is used as provided in §63.658(i), records of hourly 

meteorological data, including temperature, barometric pressure, wind speed and wind 

direction, calculated daily unit vector wind direction and daily sigma theta, and other 

records specified in the site-specific monitoring plan. 

(9) For each flare subject to §63.670, each owner or operator shall keep the records 

specified in paragraphs (i)(9)(i) through (xii) 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 each 15-

minute block during which there was at least one minute that no pilot flame is present 

when regulated material is routed to a flare for a minimum of 5 years. 

(ii) Retain records of daily visible emissions observations or video surveillance images 

required in §63.670(h) as specified in the paragraphs (i)(9)(ii)(A) through (C), as 

applicable, for a minimum of 3 years. 
Page 112 of 175 

(A) If visible emissions observations are performed using Method 22 at 40 CFR part 60, 

Appendix A-7, 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. 

(B) If video surveillance camera is used, the record must include all video surveillance 

images recorded, with time and date stamps. 

(C) For each 2 hour period for which visible emissions are observed for more than 5 

minutes in 2 consecutive hours, the record must include the date and time of the 2 hour 

period and an estimate of the cumulative number of minutes in the 2 hour period for which 

emissions were visible. 

(iii) The 15-minute block average cumulative flows for flare vent gas and, if applicable, 

total steam, perimeter assist air, and premix assist air specified to be monitored under 

§63.670(i), along with the date and time interval for the 15-minute block. If multiple 

monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter 

assist air, and premix assist air, retain records of the 15-minute block average flows for 

each monitoring location for a minimum of 2 years, and retain the 15-minute block average 

cumulative flows that are used in subsequent calculations for a minimum of 5 years. If 

pressure and temperature monitoring is used, retain records of the 15-minute block 

average temperature, pressure and molecular weight of the flare vent gas or assist gas 

stream for each measurement location used to determine the 15-minute block average 

cumulative flows for a minimum of 2 years, and retain the 15-minute block average 

cumulative flows that are used in subsequent calculations for a minimum of 5 years. 

(iv) The flare vent gas compositions specified to be monitored under §63.670(j). Retain 

records of individual component concentrations from each compositional analyses for a 

minimum of 2 years. If NHVvg 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 (n), as applicable. 

(vi) [Reserved] 

(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). 
Page 113 of 175 

(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) Records when the flow of vent gas exceeds the smokeless capacity of the flare, including 

start and stop time and dates of the flaring event. 

(xi) Records of the root cause analysis and corrective action analysis conducted as required 

in §63.670(o)(3), including an identification of the affected facility, the date and duration of 

the event, a statement noting whether the event resulted from the same root cause(s) 

identified in a previous analysis and either a description of the recommended corrective 

action(s) or an explanation of why corrective action is not necessary under §63.670(o)(5)(i). 

(xii) For any corrective action analysis for which implementation of corrective actions are 

required in §63.670(o)(5), a description of the corrective action(s) completed within the first 

45 days following the discharge and, for action(s) not already completed, a schedule for 

implementation, including proposed commencement and completion dates. 

(10) [Reserved] 

(11) For each pressure relief device subject to the pressure release management work 

practice standards in §63.648(j)(3), the owner or operator shall keep the records specified 

in paragraphs (i)(11)(i) through (iii) of this section. 

(i) Records of the prevention measures implemented as required in §63.648(j)(3)(ii), if 

applicable. 

(ii) Records of the number of releases during each calendar year and the number of those 

releases for which the root cause was determined to be a force majeure event. Keep these 

records for the current calendar year and the past five calendar years. 

(iii) For each release to the atmosphere, the owner or operator shall keep the records 

specified in paragraphs (i)(11)(iii)(A) through (D) of this section. 

(A) The start and end time and date of each pressure release to the atmosphere. 

(B) Records of any data, assumptions, and calculations used to estimate of the mass 

quantity of each organic HAP released during the event. 

(C) Records of the root cause analysis and corrective action analysis conducted as required 

in §63.648(j)(3)(iii), including an identification of the affected facility, the date and duration 

of the event, a statement noting whether the event resulted from the same root cause(s) 

identified in a previous analysis and either a description of the recommended corrective 

action(s) or an explanation of why corrective action is not necessary under §63.648(j)(7)(i). 
Page 114 of 175 

(D) For any corrective action analysis for which implementation of corrective actions are 

required in §63.648(j)(7), a description of the corrective action(s) completed within the first 

45 days following the discharge and, for action(s) not already completed, a schedule for 

implementation, including proposed commencement and completion dates. 

(12) For each maintenance vent opening subject to the requirements in §63.643(c), the 

owner or operator shall keep the applicable records specified in (i)(12)(i) through (v) of this 

section. 

(i) The owner or operator shall maintain standard site procedures used to deinventory 

equipment for safety purposes (e.g., hot work or vessel entry procedures) to document the 

procedures used to meet the requirements in §63.643(c). The current copy of the 

procedures shall be retained and available on-site at all times. Previous versions of the 

standard site procedures, is applicable, shall be retained for five years. 

(ii) If complying with the requirements of §63.643(c)(1)(i) and the lower explosive limit at 

the time of the vessel opening exceeds 10 percent, identification of the maintenance vent, 

the process units or equipment associated with the maintenance vent, the date of 

maintenance vent opening, and the lower explosive limit at the time of the vessel opening. 

(iii) If complying with the requirements of §63.643(c)(1)(ii) and either the vessel pressure at 

the time of the vessel opening exceeds 5 psig or the lower explosive limit at the time of the 

active purging was initiated exceeds 10 percent, identification of the maintenance vent, the 

process units or equipment associated with the maintenance vent, the date of maintenance 

vent opening, the pressure of the vessel or equipment at the time of discharge to the 

atmosphere and, if applicable, the lower explosive limit of the vapors in the equipment 

when active purging was initiated. 

(iv) If complying with the requirements of §63.643(c)(1)(iii), identification of the 

maintenance vent, the process units or equipment associated with the maintenance vent, 

the date of maintenance vent opening, and records used to estimate the total quantity of 

VOC in the equipment at the time the maintenance vent was opened to the atmosphere for 

each applicable maintenance vent opening. 

(v) If complying with the requirements of §63.643(c)(1)(iv), identification of the 

maintenance vent, the process units or equipment associated with the maintenance vent, 

records documenting the lack of a pure hydrogen supply, the date of maintenance vent 

opening, and the lower explosive limit of the vapors in the equipment at the time of 

discharge to the atmosphere for each applicable maintenance vent opening. 

§ 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 
Page 115 of 175 

Office to find out if implementation and enforcement of this subpart is delegated to a State, local, 

or Tribal agency. 

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

Tribal agency under subpart E of this part, the authorities contained in paragraph (c) of this 

section are retained by the Administrator of U.S. EPA and cannot be transferred to the State, 

local, or Tribal agency. 

(c) The authorities that cannot be delegated to State, local, or Tribal agencies are as specified in 

paragraphs (c)(1) through (4) of this section. 

(1) Approval of alternatives to the requirements in §§63.640, 63.642(g) through (l), 63.643, 

63.646 through 63.652, 63.654, 63.657 through 63.660, 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. 

(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. 

§§ 63.657 Delayed coking unit decoking operation standards. 

(a) Except as provided in paragraphs (e) and (f) of this section, 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 or temperature measured at the top of the coke drum or in the 

overhead line of the coke drum as near as practical to the coke drum meets the applicable 

limits specified in paragraphs (a)(1) or (a)(2) of this section prior to venting to the 

atmosphere, draining or deheading the coke drum at the end of the cooling cycle. 

(1) For delayed coking units at an existing affected source, meet either: 

(i) An average vessel pressure of 2 psig determined on a rolling 60-event average; or 

(ii) An average vessel temperature of 220 degrees Fahrenheit determined on a rolling 60-

event average. 

(2) For delayed coking units at a new affected source, meet either: 
Page 116 of 175 

(i) A vessel pressure of 2.0 psig for each decoking event; or 

(ii) A vessel temperature of 218 degrees Fahrenheit for each decoking event. 

(b) Each owner or operator of a delayed coking unit complying with the pressure limits in 

paragraphs (a)(1)(i) or (a)(2)(i) of this section shall install, operate, calibrate, and maintain 

a monitoring system, as specified in paragraphs (b)(1) through (5) of this section, to 

determine the coke drum vessel pressure. 

(1) The pressure monitoring system must be in a representative location (at the top of the 

coke drum or in the overhead line as near as practical to the coke drum) that minimizes or 

eliminates pulsating pressure, vibration, and, to the extent practical, internal and external 

corrosion. 

(2) The pressure monitoring system must be capable of measuring a pressure of 2.0 psig 

within ±0.5 psig. 

(3) The pressure monitoring system must be verified annually or at the frequency 

recommended by the instrument manufacturer. The pressure monitoring system must be 

verified 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. 

(4) All components of the pressure monitoring system must be visually inspected for 

integrity, oxidation and galvanic corrosion every 3 months, unless the system has a 

redundant pressure sensor. 

(5) The output of the pressure monitoring system must be reviewed daily to ensure that the 

pressure readings fluctuate as expected between operating and cooling/decoking cycles to 

verify the pressure taps are not plugged. Plugged pressure taps must be unplugged or 

otherwise repaired prior to the next operating cycle. 

(c) Each owner or operator of a delayed coking unit complying with the temperature limits 

in paragraphs (a)(1)(ii) or (a)(2)(ii) of this section shall install, operate, calibrate, and 

maintain a continuous parameter monitoring system to measure the coke drum vessel 

temperature (at the top of the coke drum or in the overhead line as near as practical to the 

coke drum) according to the requirements specified in table 13 of this subpart. 

(d) The owner or operator of a delayed coking unit shall determine the coke drum vessel 

pressure or temperature, as applicable, on a 5-minute rolling average basis while the coke 

drum is vented to the closed blowdown system and shall use the last complete 5-minute 

rolling average pressure or temperature just prior to initiating steps to isolate the coke 

drum prior to venting, draining or deheading to demonstrate compliance with the 

requirements in paragraph (a) of this section. Pressure or temperature 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 
Page 117 of 175 

determining the average coke drum vessel pressure or temperature for the purpose of 

compliance with the requirements in paragraph (a) of this section. 

(e) The owner or operator of a delayed coking unit using the “water overflow” method of 

coke cooling must hardpipe the overflow water or otherwise prevent exposure of the 

overflow water to the atmosphere when transferring the overflow water to the overflow 

water storage tank whenever the coke drum vessel temperature exceeds 220 degrees 

Fahrenheit. The overflow water storage tank may be an open or fixed-roof tank provided 

that a submerged fill pipe (pipe outlet below the existing liquid level in the tank) is used to 

transfer overflow water to the tank. The owner or operator of a delayed coking unit using 

the “water overflow” method of coke cooling shall determine the coke drum vessel 

temperature as specified in paragraphs (c) and (d) of this section regardless of the 

compliance method used to demonstrate compliance with the requirements in paragraph 

(a) of this section. 

(f) The owner or operator of a delayed coking unit may partially drain a coke drum prior 

to achieving the applicable limits in paragraph (a) of this section in order to double-quench 

a coke drum that did not cool adequately using the normal cooling process steps provided 

that the owner or operator meets the conditions in paragraphs (f)(1) and (2) of this section. 

(1) The owner or operator shall install, operate, calibrate, and maintain a continuous 

parameter monitoring system to measure the drain water temperature at the bottom of the 

coke drum or in the drain line as near as practical to the coke drum according to the 

requirements specified in table 13 of this subpart. 

(2) The owner or operator must maintain the drain water temperature below 210 degrees 

Fahrenheit during the partial drain associated with the double-quench event.§ 

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 

and paragraphs (b) through (k) of this section. 

(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. 

(1) As it pertains to this subpart, known sources of VOCs, as used in Section 8.2.1.3 in 

Method 325A of Appendix A of this part for siting passive monitors means a wastewater 

treatment unit, process unit, or any emission source requiring control according to the 

requirements of this subpart, including marine vessel loading operations. For marine 

loading operations that are located offshore, one passive monitor should be sited on the 

shoreline adjacent to the dock. 
Page 118 of 175 

(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 plan, 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 period and at least two field blanks per sampling period, 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 collect and record meteorological data according to the 

applicable requirements in paragraphs (d)(1) through (3) of this section. 

(1) If a near-field source correction is used as provided in paragraph (i)(2) of this section or 

if an alternative test method is used that provides time-resolved measurements, the owner 

or operator shall: 

(i) Use an on-site meteorological station in accordance with Section 8.3 of Method 325A of 

Appendix A of this part. 

(ii) Collect and record hourly meteorological data, including temperature, barometric 

pressure, wind speed and wind direction and calculate daily unit vector wind direction and 

daily sigma theta. 

(2) For cases other than those specified in paragraph (d)(1) of this section, the owner or 

operator shall collect and record sampling period average temperature and barometric 

pressure using either an on-site meteorological station in accordance with Section 8.3 of 

Method 325A of Appendix A of this part or, alternatively, using data from a United States 

Weather Service (USWS) meteorological station provided the USWS meteorological station 

is within 40 kilometers (25 miles) of the refinery. 

(3) If an on-site meteorological station is used, the owner or operator shall follow the 

calibration and standardization procedures for meteorological measurements in EPA454/B-08-002 (incorporated by reference—see §63.14). 

(e) The owner of operator shall use a sampling period and sampling frequency as specified 

in paragraphs (e)(1) through (3) of this section. 
Page 119 of 175 

(1) Sampling period. A 14-day sampling period shall be used, unless a shorter sampling 

period is determined to be necessary under paragraph (g) or (i) of this section. A sampling 

period is defined as the period during which sampling tube is deployed at a specific 

sampling location with the diffusive sampling end cap in-place and does not include the 

time required to analyze the sample. For the purpose of this subpart, a 14-day sampling 

period may be no shorter than 13 calendar days and no longer than 15 calendar days, but 

the routine sampling period shall be 14 calendar days. 

(2) Base sampling frequency. Except as provided in paragraph (e)(3) of this section, the 

frequency of sample collection shall be once each contiguous 14-day sampling period, such 

that the beginning of the next 14-day sampling period begins immediately upon the 

completion of the previous 14-day sampling period. 

(3) Alternative sampling frequency for burden reduction. When an individual monitor 

consistently achieves results at or below 0.9 μg/m3

, the owner or operator may elect to use 

the applicable minimum sampling frequency specified in paragraph (e)(3)(i) through (v) of 

this section for that monitoring site. When calculating Δc for the monitoring period when 

using this alternative for burden reduction, zero shall be substituted for the sample result 

for the monitoring site for any period where a sample is not taken. 

(i) If every sample at a monitoring site is at or below 0.9 μg/m3

 for 2 years (52 consecutive 

samples), every other sampling period can be skipped for that monitoring site, i.e., 

sampling will occur approximately once per month. 

(ii) If every sample at a monitoring site that is monitored at the frequency specified in 

paragraph (e)(3)(i) of this section is at or below 0.9 μg/m3

 for 2 years (i.e., 26 consecutive 

“monthly” samples), five 14-day sampling periods can be skipped for that monitoring site 

following each period of sampling, i.e., sampling will occur approximately once per 

quarter. 

(iii) If every sample at a monitoring site that is monitored at the frequency specified in 

paragraph (e)(3)(ii) of this section is at or below 0.9 μg/m3

 for 2 years (i.e., 8 consecutive 

quarterly samples), twelve 14-day sampling periods can be skipped for that monitoring site 

following each period of sampling, i.e., sampling will occur twice a year. 

(iv) If every sample at a monitoring site that is monitored at the frequency specified in 

paragraph (e)(3)(iii) of this section is at or below 0.9 μg/m3

 for an 2 years (i.e., 4 consecutive 

semi-annual samples), only one sample per year is required for that monitoring site. For 

yearly sampling, samples shall occur at least 10 months but no more than 14 months apart. 

(v) If at any time a sample for a monitoring site that is monitored at the frequency specified 

in paragraphs (e)(3)(i) through (iv) of this section returns a result that is above 0.9 μg/m3, 

the sampling site must return to the original sampling requirements of contiguous 14-day 

sampling periods with no skip periods for one quarter (six 14-day sampling periods). If 

every sample collected during this quarter is at or below 0.9 μg/m3

, the owner or operator 

may revert back to the reduced monitoring schedule applicable for that monitoring site 
Page 120 of 175 

prior to the sample reading exceeding 0.9 μg/m3

. If any sample collected during this 

quarter is above 0.9 μg/m3, that monitoring site must return to the original sampling 

requirements of contiguous 14-day sampling periods with no skip periods for a minimum 

of two years. The burden reduction requirements can be used again for that monitoring 

site once the requirements of paragraph (e)(3)(i) of this section are met again, i.e., after 52 

contiguous 14-day samples with no results above 0.9 μg/m3. 

(f) Within 45 days of completion of each sampling period, the owner or operator shall 

determine whether the results are above or below the action level as follows: 

(1) The owner or operator shall determine the facility impact on the benzene concentration 

(Δc) for each 14-day sampling period according to either paragraphs (f)(1)(i) or (ii) of this 

section, as applicable. 

(i) Except when near-field source correction is used as provided in paragraph (i) of this 

section, the owner or operator shall determine the highest and lowest sample results for 

benzene concentratons from the sample pool and calculate Δc as the difference in these 

concentrations. The owner or operator shall adhere to the following procedures when one 

or more samples for the sampling period 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) When near-field source correction is used as provided in paragraph (i) of this section, 

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 calculate the annual average Δc based on the average of the 

26 most recent 14-day sampling periods. The owner or operator shall update this annual 

average value after receiving the results of each subsequent 14-day sampling period. 

(3) The action level for benzene is 9 micrograms per cubic meter (μg/m3) on an annual 

average basis. If the annual average Δc value for benzene is less than or equal to 9 μg/m3, 

the concentration is below the action level. If the annual average Δc value for benzene is 

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 annual 

average Δc and no longer than 50 days after completion of the sampling period, the owner 

or operator shall initiate a root cause analysis to determine the cause of such exceedance 

and to determine appropriate corrective action, such as those described in paragraphs 

(g)(1) through (4) of this section. The root cause analysis and initial corrective action 
Page 121 of 175 

analysis shall be completed and initial corrective actions taken 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 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 periods for Methods 325A and 325B of Appendix A of this part, or using 

active sampling techniques). 

(h) If, upon completion of the corrective action analysis and corrective actions such as those 

described in paragraph (g) of this section, the Δc value for the next 14-day sampling period 

for which the sampling start time begins after the completion of the corrective actions is 

greater than 9 μg/m3 or if all corrective action measures identified require more than 45 

days to implement, 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 receiving the analytical 

results indicating that the Δc value for the 14-day sampling period following the completion 

of the initial corrective action is greater than 9 μg/m3 or, if no initial corrective actions were 

identified, no later than 60 days following the completion of the corrective action analysis 

required in paragraph (g) of this section. 

(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. The procedures in Section 12 of Method 

325A are not required, but may be used, if applicable, when determining near-field source 

contributions. 

(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. 
Page 122 of 175 

(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 the near-field source or sources that 

are expected to contribute to the 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 or a monitoring station other than a passive diffusive tube 

monitoring station is proposed, provide a detailed description of the measurement 

methods, measurement frequency, and recording frequency for determining the uniform 

background or near-field source concentration contribution. 

(2) When an approved site-specific monitoring plan is used, the owner or operator shall 

determine Δc for comparison with the 9 μg/m3 action level using the requirements specified 

in paragraphs (i)(2)(i) through (iii) of this section. 

(i) For each monitoring location, calculate Δci using the following equation. 

Δci i i  UBNFSMFC

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 included in the site-specific monitoring plan, μg/m3. If no additional 

measurements are 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 period are below the method detection 

limit for benzene, adhere to the following procedures: 
Page 123 of 175 

(A) If the benzene concentration at the monitoring location used for the uniform 

background concentration is below the method detection limit, 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 the method detection limit, the owner or 

operator shall use zero for the monitoring location concentration when calculating NFSi for 

that monitoring period. 

(C) If a fenceline monitoring location sample result is below the method detection limit, the 

owner or operator shall use the method detection limit as the sample result. 

(iii) Determine Δc for the monitoring period as the maximum value of Δci from all of the 

fenceline monitoring locations for that monitoring period. 

(3) The site-specific monitoring plan shall be submitted and approved as described in 

paragraphs (i)(3)(i) through (iv) of this section. 

(i) The site-specific monitoring plan must be submitted to the Administrator for approval. 

(ii) The site-specific monitoring plan shall also be submitted to the following address: U.S. 

Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector 

Policies and Programs Division, U.S. EPA Mailroom (E143–01), Attention: Refinery Sector 

Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in 

lieu of hard copies may also be submitted to refineryrtr@epa.gov. 

(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 for a site-specific monitoring 

plan. Factors that the Administrator 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). 
Page 124 of 175 

(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, the adequacy of the description of the 

measurement and recording frequency proposed and the adequacy of the rationale for 

using the alternative monitoring frequency. 

(j) The owner or operator shall comply with the applicable recordkeeping and reporting 

requirements in §63.655(h) and (i). 

(k) As outlined in §63.7(f), the owner or operator may submit a request for an alternative 

test method. At a minimum, the request must follow the requirements outlined in (k)(1) 

through (7) of this section. 

(1) The alternative method may be used in lieu of all or a partial number of passive 

samplers required in Method 325A. 

(2) The alternative method must be validated according to Method 301 in appendix A of 

this part or contain performance based procedures and indicators to ensure self-validation. 

(3) The method detection limit must nominally be at least an order of magnitude below the 

action level, i.e., 0.9 μg/m3 benzene. The alternate test method must describe the procedures 

used to provide field verification of the detection limit. 

(4) The spatial coverage must be equal to or better than the spatial coverage provided in 

Method 325A. 

(i) For path average concentration open-path instruments, the physical path length of the 

measurement shall be no more than a passive sample footprint (the spacing that would be 

provided by the sorbent traps when following Method 325A). For example, if Method 325A 

requires spacing monitors A and B 610 meters (2000 feet) apart, then the physical path 

length limit for the measurement at that portion of the fenceline shall be no more than 610 

meters (2000 feet). 

(ii) For range resolved open-path instrument or approach, the instrument or approach 

must be able to resolve an average concentration over each passive sampler footprint 

within the path length of the instrument. 
Page 125 of 175 

(iii) The extra samplers required in Sections 8.2.1.3 of Method 325A may be omitted when 

they fall within the path length of an open-path instrument. 

(5) At a minimum, non-integrating alternative test methods must provide a minimum of 

one cycle of operation (sampling, analyzing, and data recording) for each successive 15-

minute period. 

(6) For alternative test methods capable of real time measurements (less than a 5 minute 

sampling and analysis cycle), the alternative test method may allow for elimination of data 

points corresponding to outside emission sources for purpose of calculation of the high 

point for the two week average. The alternative test method approach must have wind 

speed, direction and stability class of the same time resolution and within the footprint of 

the instrument. 

(7) For purposes of averaging data points to determine the Δc for the 14-day average high 

sample result, all results measured under the method detection limit must use the method 

detection limit. For purposes of averaging data points for the 14-day average low sample 

result, all results measured under the method detection limit must use zero. 

§ 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 
Page 126 of 175 

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) A floating roof storage vessel complying with the requirements of subpart WW of this 

part may comply with the control option specified in paragraph (b)(1) of this section and, if 

equipped with a ladder having at least one slotted leg, shall comply with one of the control 

options as described in paragraph (b)(2) of this section. 

(1) In addition to the options presented in §§63.1063(a)(2)(viii)(A), 63.1063(a)(2)(viii)(B), 

and 63.1064, a floating roof storage vessel may comply with §63.1063(a)(2)(vii) using a 

flexible enclosure device and either a gasketed or welded cap on the top of the guidepole. 

(2) Each opening through a floating roof for a ladder having at least one slotted leg shall be 

equipped with one of the configurations specified in paragraphs (b)(2)(i) through (iii) of 

this section. 

(i) A pole float in the slotted leg and pole wipers for both legs. The wiper or seal of the pole 

float must be at or above the height of the pole wiper. 

(ii) A ladder sleeve and pole wipers for both legs of the ladder. 

(iii) A flexible enclosure device and either a gasketed or welded cap on the top of the slotted 

leg. 

(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 June 30, 2014. 

(2) All references to “promulgation of the referencing subpart” and “the promulgation date 

of the referencing subpart” in subpart WW of this part mean [insert date 60 days after 

date of publication 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 [insert date 60 days 

after date of publication 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 June 30, 2014. 
Page 127 of 175 

(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 uncontrolled fixed roof storage vessel that commenced construction on or before 

June 30, 2014, and that meets the definition of Group 1 storage vessel in item 2 in §63.641 

but not the definition of Group 1 storage vessel in item 1 in §63.641, the requirements of 

§63.982 and/or §63.1062 do not apply until the next time the storage vessel is completely 

emptied and degassed, or [insert date 10 years and 60 days after date of publication in the 

Federal Register], whichever occurs first. 

(e) Failure to perform inspections and monitoring required by this section shall constitute a 

violation of the applicable standard of this subpart. 

(f) References in §63.1066(a) to initial startup notification requirements do not apply. 

(g) References to the Notification of Compliance Status in §63.999(b) mean the Notification 

of Compliance Status required by §63.655(f). 

(h) References to the Periodic Reports in §§63.1066(b) and 63.999(c) mean the Periodic 

Report required by §63.655(g). 

 (i) 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 (i)(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 §63.983(a)(3)(i) or §63.983(a)(3)(ii) for each closed vent system that 

contains bypass lines that could divert a vent stream either directly to the atmosphere or to 

a control device that does not comply with the requirements in subpart SS of this part. 

Except as provided in paragraphs (i)(2)(i) and (ii) of this section, use of the bypass at any 

time to divert a Group 1 storage vessel to either directly to the atmosphere or to a control 

device that does not comply with the requirements in subpart SS of this part is an 

emissions standards violation. Equipment such as low leg drains and equipment subject to 

§63.648 are not subject to this paragraph. 

(i) If planned routine maintenance of the control device cannot be performed during 

periods that storage vessel emissions are vented to the control device or when the storage 

vessel is taken out of service for inspections or other planned maintenance reasons, the 

owner or operator may bypass the control device. 
Page 128 of 175 

(ii) Periods for which storage vessel control device may be bypassed for planned routine 

maintenance of the control device shall not exceed 240 hours per calendar year. 

 (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. 

§§ 63.661-63.669 [Reserved] 

§ 63.670 Requirements for flare control devices. 

On or before [insert date 3 years and 60 days after date of publication 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) [Reserved] 

(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. Each 15-minute block 

during which there is at least one minute where no pilot flame is present when regulated 

material is routed to the flare is a deviation of the standard. Deviations in different 15-

minute blocks from the same event are considered separate deviations. The owner or 

operator shall monitor for the presence of a pilot flame as specified in paragraph (g) of this 

section. 

(c) Visible emissions. The owner or operator shall specify the smokeless design capacity of 

each flare and operate with no visible emissions, except for periods not to exceed a total of 5 

minutes during any 2 consecutive hours, when regulated material is routed to the flare and 

the flare vent gas flow rate is less than the smokeless design capacity of the flare. 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, whenever regulated material is routed to the flare for at least 15-minutes and the 

flare vent gas flow rate is less than the smokeless design capacity of the flare. 

(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. The owner or operator shall monitor Vtip using the 

procedures specified in paragraph (i) and (k) of this section. 
Page 129 of 175 

(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. The owner or operator 

shall monitor Vtip using the procedures specified in paragraphs (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

212,1

10

  vg

max

NHV

VLog

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) Combustion zone operating limits. For each flare, the owner or operator shall operate the 

flare to maintain the net heating value of flare combustion zone gas (NHVcz) at or above 

270 British thermal units per standard cubic feet (Btu/scf) determined on a 15-minute 

block period basis when regulated material is routed to the flare for at least 15-minutes. 

The owner or operator shall monitor and calculate NHVcz as specified in paragraph (m) of 

this section. 

(f) Dilution operating limits for flares with perimeter assist air. For each flare actively 

receiving perimeter assist air, the owner or operator shall operate the flare to maintain the 

net heating value dilution parameter (NHVdil) at or above 22 British thermal units per 

square foot (Btu/ft2

) determined on a 15-minute block period basis when regulated material 

is being routed to the flare for at least 15-minutes. The owner or operator shall monitor 

and calculate NHVdil as specified in paragraph (n) of this section. 

(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 using 

either the methods in paragraph (h)(1) of this section or, alternatively, the methods in 

paragraph (h)(2) of this section. The owner or operator must record and report any 
Page 130 of 175 

instances where visible emissions are observed for more than 5 minutes during any 2 

consecutive hours as specified in §63.655(g)(11)(ii). 

(1) At least once per day, conduct visible emissions observations 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 A7. 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 or until 5-minutes of visible emissions are 

observed. 

(2) Use a video surveillance camera to continuously record (at least one frame every 15 

seconds with time and date stamps) images of the flare flame and a reasonable distance 

above the flare flame at an angle suitable for visual emissions observations. The owner or 

operator must provide real-time video surveillance camera output to the control room or 

other continuously manned location where the camera images may be viewed at any time. 

(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 as well as any supplemental natural gas used. Different flow 

monitoring methods may be used to measure different gaseous streams that make up the 

flare vent gas provided that the flow rates of all gas streams that contribute to the flare 

vent gas are determined. 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. Continuously monitoring fan 

speed or power and using fan curves is an acceptable method for continuously monitoring 

assist air flow rates. 

(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 atmosphere). 

(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. 
Page 131 of 175 

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 

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 and, if desired, may directly measure the hydrogen concentration in the flare 

vent gas following the methods provided in paragraphs (j)(4) of this section. The owner or 

operator may elect to use different monitoring methods for different gaseous streams that 

make up the flare vent gas using different methods provided the composition or net heating 

value of all gas streams that contribute to the flare vent gas are determined. 

(1) Except as provided in paragraphs (j)(5) and (6) 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 paragraphs (j)(5) and (6) of this section, the owner or operator 

shall install, operate, and maintain a grab sampling system capable of collecting an 
Page 132 of 175 

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 D6420-99 (Reapproved 2010), ASTM D1945-03 (Reapproved 2010) , 

ASTM D1945-14 or ASTM UOP539-12 (all incorporated by reference—see §63.14). 

(3) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator 

shall install, operate, calibrate, and maintain a calorimeter capable of continuously 

measuring, calculating, and recording NHVvg. at standard conditions. 

(4) If the owner or operator uses a continuous net heating value monitor according to 

paragraph (j)(3) of this section, the owner or operator may, at their discretion, install, 

operate, calibrate, and maintain a monitoring system capable of continuously measuring, 

calculating, and recording the hydrogen concentration in the flare vent gas. 

(5) Direct compositional or net heating value monitoring is not required for purchased 

(“pipeline quality”) natural gas streams. The net heating value of purchased natural gas 

streams may be determined using annual or more frequent grab sampling at any one 

representative location. Alternatively, the net heating value of any purchased natural gas 

stream can be assumed to be 920 Btu/scf. 

(6) Direct compositional or net heating value monitoring is not required for gas streams 

that have been demonstrated to have consistent composition (or a fixed minimum net 

heating value) according to the methods in paragraphs (j)(6)(i) through (v). 

(i) The owner or operator shall submit to the Administrator a written application for an 

exemption from monitoring. The application must contain the following information: 

(A) A description of the flare gas stream/system to be considered, including submission of a 

portion of the appropriate piping diagrams indicating the boundaries of the flare gas 

stream/system and the affected flare(s) to be considered; 

(B) A statement that there are no crossover or entry points to be introduced into the flare 

gas stream/system (this should be shown in the piping diagrams) prior to the point where 

the flow rate of the gas streams is measured; 

(C) An explanation of the conditions that ensure that the flare gas net heating value is 

consistent and, if flare gas net heating value is expected to vary (e.g., due to product loading 

of different material), the conditions expected to produce the flare gas with the lowest net 

heating value; 

(D) The supporting test results from sampling the requested flare gas stream/system for the 

net heating value. Sampling data must include, at minimum, 2 weeks of daily measurement 

values (14 grab samples) for frequently operated flare gas streams/systems; for 

infrequently operated flare gas streams/systems, seven grab samples must be collected 

unless other additional information would support reduced sampling. If the flare gas 
Page 133 of 175 

stream composition can vary, samples must be taken during those conditions expected to 

result in lowest net heating value identified in paragraph (j)(6)(i)(C). The owner or 

operator shall determine net heating value for the gas stream using either gas composition 

analysis or net heating value monitor (with optional hydrogen concentration analyzer) 

according to the method provided in paragraph (l) of this section; and 

(E) A description of how the 2 weeks (or seven samples for infrequently operated flare gas 

streams/systems) of monitoring results compares to the typical range of net heating values 

expected for the flare gas stream/system going to the affected flare ( e.g., “the samples are 

representative of typical operating conditions of the flare gas stream going to the loading 

rack flare” or “the samples are representative of conditions expected to yield the lowest net 

heating value of the flare gas stream going to the loading rack flare”). 

(F) The net heating value to be used for all flows of the flare vent gas from the flare gas 

stream/system covered in the application. A single net heating value must be assigned to the 

flare vent gas either by selecting the lowest net heating value measured in the sampling 

program or by determining the 95th percent confidence interval on the mean value of all 

samples collected using the t-distribution statistic (which is 1.943 for 7 grab samples or 

1.771 for 14 grab samples). 

(ii) The effective date of the exemption is the date of submission of the information 

required in paragraph (j)(6)(i) of this section. 

(iii) No further action is required unless refinery operating conditions change in such a way 

that affects the exempt fuel gas stream/system (e.g., the stream composition changes). If 

such a change occurs, the owner or operator shall follow the procedures in paragraph 

(j)(6)(iii)(A), (j)(6)(iii)(B), or (j)(6)(iii)(C) of this section. 

(A) If the operation change results in a flare vent gas net heating value that is still within 

the range of net heating values included in the original application, the owner or operator 

shall determine the net heating value on a grab sample and record the results as proof that 

the net heating value assigned to the vent gas stream in the original application is still 

appropriate. 

(B) If the operation change results in a flare vent gas net heating value that is lower than 

the net heating value assigned to the vent gas stream in the original application, the owner 

or operator may submit new information following the procedures of paragraph (j)(6)(i) of 

this section within 60 days (or within 30 days after the seventh grab sample is tested for 

infrequently operated process units). 

(C) If the operation change results in a flare vent gas net heating value has greater 

variability in the flare gas stream/system such the owner or operator chooses not to submit 

new information to support an exemption, the owner or operator must begin monitoring 

the composition or net heat content of the flare vent gas stream using the methods in this 

section (i.e., grab samples every 8 hours until such time a continuous monitor, if elected, is 

installed). 
Page 134 of 175 

(k) Calculation methods for cumulative flow rates and 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 flare vent gas does 

not exit through them. 

(2) The owner or operator shall determine the cumulative volumetric flow of flare 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. If desired, the cumulative flow rate for a 15-minute block 

period only needs to include flow during those periods when regulated material is sent to 

the flare, but owners or operators may elect to calculate the cumulative flow rates across 

the entire 15-minute block period for any 15-minute block period where there is regulated 

material flow to the flare. 

(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 or operator shall, at a 

minimum, determine the 15-minute block average temperature and pressure from the 

monitoring system and use those values to perform the engineering calculations to 

determine the cumulative flow over the 15-minute block average period. Alternatively, the 

owner or operator may divide the 15-minute block average period into equal duration 

subperiods (e.g., three 5-minute periods) and determine the average temperature and 

pressure for each subperiod, perform engineering calculations to determine the flow for 

each subperiod, then add the volumetric flows for the subperiods to determine the 

cumulative volumetric flow of vent gas for the 15-minute block average period. 

(3) The 15-minute block average Vtip shall be calculated using the following equation. 

900  Area

Q V cum

tip

where: 

Vtip = Flare tip velocity, feet per second. 

Qcum = Cumulative volumetric flow over 15-minute block average period, standard cubic 

feet. 
Page 135 of 175 

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 net heating value. The owner or 

operator shall determine the net heating value of the flare vent gas (NHVvg) based on the 

composition monitoring data on a 15-minute block average basis according to the following 

requirements. 

(1) If compositional analysis data are collected as provided in paragraph (j)(1) or (2) of this 

section, the owner or operator shall determine NHVvg of a specific sample by using the 

following equation. 





n

i

NHV vg NHVx ii

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. 

(2) If direct net heating value monitoring data are collected as provided in paragraph (j)(3) 

of this section but a hydrogen concentration monitor is not used, the owner or operator 

shall use the direct output of the monitoring system(s) (in Btu/scf) to determine the NHVvg

for the sample. 
Page 136 of 175 

(3) If direct net heating value monitoring data are collected as provided in paragraph (j)(3) 

of this section and hydrogen concentration monitoring data are collected as provided in 

paragraph (j)(4) of this section, the owner or operator shall use the following equation to 

determine NHVvg for each sample measured via the net heating value monitoring system. 

2 938 vg measured H NHV  NHV  x

where: 

NHVvg = Net heating value of flare vent gas, Btu/scf. 

NHVmeasured = Net heating value of flare vent gas stream as measured by the continuous 

net heating value monitoring system, Btu/scf. 

xH2 = Concentration of hydrogen in flare vent gas at the time the sample was input into the 

net heating value monitoring system, volume fraction. 

938 = Net correction for the measured heating value of hydrogen (1,212 – 274), Btu/scf. 

(4) 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. 

(5) When a continuous monitoring system is used as provided in paragraphs (j)(1) or (j)(3) 

and, if applicable, (j)(4) of this section, the owner or operator may elect to determine the 

15-minute block average NHVvg using the either the calculation methods in paragraph 

(l)(5)(i) of this section or the calculation methods in paragraph (l)(5)(ii) of this section. The 

owner or operator may choose to comply using the calculation methods in paragraph 

(l)(5)(i) of this section for some flares at the petroleum refinery and comply using the 

calculation methods (l)(5)(ii) of this section for other flares. However, for each flare, the 

owner or operator must elect one calculation method that will apply at all times, and use 

that method for all continuously monitored flare vent streams associated with that flare. If 

the owner or operator intends to change the calculation method that applies to a flare, the 

owner or operator must notify the Administrator 30 days in advance of such a change. 

(i) Feed-forward calculation method. When calculating NHVvg for a specific 15-minute 

block: 

(A) Use the results from the first sample collected during an event, (for periodic flare vent 

gas flow events) for the first 15-minute block associated with that event. 

(B) If the results from the first sample collected during an event (for periodic flare vent gas 

flow events) are not available until after the second 15-minute block starts, use the results 

from the first sample collected during an event for the second 15-minute block associated 

with that event. 
Page 137 of 175 

(C) For all other cases, 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 all flare vent gas steams. 

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. 

(ii) Direct calculation method. When calculating NHVvg for a specific 15-minute block: 

(A) If the results from the first sample collected during an event (for periodic flare vent gas 

flow events) are not available until after the second 15-minute block starts, use the results 

from the first sample collected during an event for the first 15-minute block associated with 

that event. 

(B) For all other cases, use the arithmetic average of all NHVvg measurement data results 

that become available during a 15-minute block to calculate the 15-minute block average 

for that 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 12:30 AM to 12:45 AM. 

(6) When grab samples are used to determine flare vent gas composition: 

(i) Use the analytical results from the first grab sample collected for an event for all 15-

minute periods from the start of the event through the 15-minute block prior to the 15-

minute block in which a subsequent grab sample is collected. 

(ii) Use the results from subsequent grab sampling events for all 15 minute periods starting 

with the 15-minute block in which the sample was collected and ending with the 15-minute 

block prior to the 15-minute block in which the next grab sample is collected. For the 

purpose of this requirement, use the time the sample was collected rather than the time the 

analytical results become available. 

(7) If the owner or operator monitors separate gas streams that combine to comprise the 

total flare vent gas flow, the 15-minute block average net heating value shall be determined 

separately for each measurement location according to the methods in paragraphs (l)(1) 

through (l)(6) of this section and a flow-weighted average of the gas stream net heating 

values shall be used to determine the 15-minute block average net heating value of the 

cumulative flare vent gas. 

(m) Calculation methods for determining combustion zone net heating value. The owner or 

operator shall determine the net heating value of the combustion zone gas (NHVcz) as 

specified in paragraphs (m)(1) or (m)(2), as applicable. 
Page 138 of 175 

(1) Except as specified in paragraph (m)(2), determine the 15-minute block average NHVcz

based on the 15-minute block average vent gas and assist gas flow rates using the following 

equation. For periods when there is no assist steam flow or premix assist air flow, NHVcz = 

NHVvg. 

  svg a,premix

vg vg

cz QQQ

NHVQ 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) Owners or operators of flares that use the feed-forward calculation methodology in 

paragraph (l)(5)(i) of this section and that monitor gas composition or net heating value in 

a location representative of the cumulative vent gas stream and that directly monitor 

supplemental natural gas flow additions to the flare must determine the 15-minute block 

average NHVcz using the following equation. 

   

  svg a,premix

vg NG NG vg NG NG NG

cz QQQ

QQQ QQNHV NHV

NHV



     2 1 2 1

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. 

QNG2 = Cumulative volumetric flow of supplemental natural gas to the flare during the 15-

minute block period, scf. 

QNG1 = Cumulative volumetric flow of supplemental natural gas to the flare during the 

previous 15-minute block period, scf. For the first 15-minute block period of an event, use 

the volumetric flow value for the current 15-minute block period, i.e., QNG1 =QNG2. 
Page 139 of 175 

NHVNG = Net heating value of supplemental natural gas to the flare for the 15-minute 

block period determined according to the requirements in paragraph (j)(5) of this section, 

Btu/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 the net heating value dilution parameter. The owner 

or operator shall determine the net heating value dilution parameter (NHVdil) as specified 

in paragraphs (n)(1) or (n)(2), as applicable. 

(1) Except as specified in paragraph (n)(2), determine the 15-minute block average NHVdil

based on the 15-minute block average vent gas and perimeter assist air flow rates using the 

following equation 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 15-

minute block average NHVdil parameter does not need to be calculated. 

  svg a,premix ra,perimete

vg vg

dil QQQQ

DiamQ NHV

NHV



 

where: 

NHVdil = Net heating value dilution parameter, Btu/ft2

. 

NHVvg = Net heating value of flare vent gas determined for the 15-minute block period, 

Btu/scf. 

Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, 

ft. Use the area as determined in paragraph (k)(1) of this section and determine the 

diameter as Diam 2 Area π . 

Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block 

period, scf. 

Qa,perimeter = Cumulative volumetric flow of perimeter assist air during the 15-minute block 

period, scf. 

(2) Owners or operators of flares that use the feed-forward calculation methodology in 

paragraph (l)(5)(i) of this section and that monitor gas composition or net heating value in 
Page 140 of 175 

a location representative of the cumulative vent gas stream and that directly monitor 

supplemental natural gas flow additions to the flare must determine the 15-minute block 

average NHVdil using the following equation 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 15-minute block average NHVdil parameter does not need to be 

calculated. 

    

  svg a,premix ra,perimete

vg NG NG vg NG NG NG

dil QQQQ

QQQ QQNHV NHV Diam

NHV



      2 1 2 1

where: 

NHVdil = Net heating value dilution parameter, 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. 

QNG2 = Cumulative volumetric flow of supplemental natural gas to the flare during the 15-

minute block period, scf. 

QNG1 = Cumulative volumetric flow of supplemental natural gas to the flare during the 

previous 15-minute block period, scf. For the first 15-minute block period of an event, use 

the volumetric flow value for the current 15-minute block period, i.e., QNG1 =QNG2. 

NHVNG = Net heating value of supplemental natural gas to the flare for the 15-minute 

block period determined according to the requirements in paragraph (j)(5) of this section, 

Btu/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,perimeter = Cumulative volumetric flow of perimeter assist air during the 15-minute block 

period, scf. 

(o) Emergency Flaring Provisions. The owner or operator of a flare that can receive 

regulated material under any circumstance during an emergency release event shall 

comply with the provisions in paragraphs (o)(1) through (o)(8) of this section. 
Page 141 of 175 

(1) Develop a flare management plan to minimize flaring during periods of startup, 

shutdown, or emergency releases. The flare management plan must include the 

information described in paragraphs (o)(1)(i) through (vii) of this section. 

(i) A listing of all refinery process units, ancillary equipment, and fuel gas systems 

connected to the flare for each affected flare. 

(ii) An assessment of whether discharges to affected flares from these process units, 

ancillary equipment and fuel gas systems can be minimized or prevented during periods of 

startup, shutdown, or emergency releases. The flare minimization assessment must (at a 

minimum) consider the items in paragraphs (o)(1)(ii)(A) through (C) of this section. The 

assessment must provide clear rationale in terms of costs (capital and annual operating), 

natural gas offset credits (if applicable), technical feasibility, secondary environmental 

impacts and safety considerations for the selected minimization alternative(s) or a 

statement, with justifications, that flow reduction could not be achieved. Based upon the 

assessment, each owner or operator of an affected flare shall identify the minimization 

alternatives that it has implemented by the due date of the flare management plan and 

shall include a schedule for the prompt implementation of any selected measures that 

cannot reasonably be completed as of that date. 

(A) Modification in startup and shutdown procedures to reduce the quantity of process gas 

discharge to the flare. 

(B) Implementation of prevention measures listed for pressure relief devices in 

§63.648(j)(5) for each pressure relief valve that can discharge to the flare. 

(C) Installation of a flare gas recovery system or, for facilities that are fuel gas rich, a flare 

gas recovery system and a co-generation unit or combined heat and power unit. 

(iii) A description of each affected flare containing the information in paragraphs 

(o)(1)(iii)(A) through (G) of this section. 

(A) A general description of the flare, including whether it is a ground flare or elevated 

(including height), the type of assist system ( e.g., air, steam, pressure, non-assisted), 

whether the flare is used on a routine basis or if it is only used during periods of startup, 

shutdown or emergency release, and whether the flare is equipped with a flare gas recovery 

system. 

(B) The smokeless capacity of the flare based on design conditions. Note: a single value 

must be provided for the smokeless capacity of the flare. 

(C) The maximum vent gas flow rate (hydraulic load capacity). 

(D) The maximum supplemental gas flow rate. 
Page 142 of 175 

(E) For flares that receive assist steam, the minimum total steam rate and the maximum 

total steam rate. 

(F) For flares that receive assist air, an indication of whether the fan/blower is single speed, 

multi-fixed speed (e.g., high, medium, and low speeds), or variable speeds. For fans/blowers 

with fixed speeds, provide the estimated assist air flow rate at each fixed speed. For 

variable speeds, provide the design fan curve (e.g., air flow rate as a function of power 

input). 

(G) Simple process flow diagram showing the locations of the flare following components of 

the flare: flare tip (date installed, manufacturer, nominal and effective tip diameter, tip 

drawing); knockout or surge drum(s) or pot(s) (including dimensions and design 

capacities); flare header(s) and subheader(s); assist system; and ignition system. 

(iv) Description and simple process flow diagram showing all gas lines (including flare 

waste gas, purge or sweep gas (as applicable), supplemental gas) that are associated with 

the flare. For purge, sweep, supplemental gas, identify the type of gas used. Designate 

which lines are exempt from composition or net heating value monitoring and why ( e.g.,

natural gas, gas streams that have been demonstrated to have consistent composition, pilot 

gas). Designate which lines are monitored and identify on the process flow diagram the 

location and type of each monitor. Designate the pressure relief devices that are vented to 

the flare. 

(v) For each flow rate, gas composition, net heating value or hydrogen concentration 

monitor identified in paragraph (o)(1)(iv) of this section, provide a detailed description of 

the manufacturer's specifications, including, but not limited to, make, model, type, range, 

precision, accuracy, calibration, maintenance and quality assurance procedures. 

(vi) For each pressure relief valve vented to the flare identified in (o)(1)(iv), provide a 

detailed description of each pressure release valve, including type of relief device (rupture 

disc, valve type) diameter of the relief valve, set pressure of the relief valve and listing of 

the prevention measures implemented. This information may be maintained in an 

electronic database on-site and does not need to be submitted as part of the flare 

management plan unless requested to do so by the Administrator. 

(vii) Procedures to minimize or eliminate discharges to the flare during the planned startup 

and shutdown of the refinery process units and ancillary equipment that are connected to 

the affected flare, together with a schedule for the prompt implementation of any 

procedures that cannot reasonably be implemented as of the date of the submission of the 

flare management plan. 

(2) Each owner or operator required to develop and implement a written flare 

management plan as described in paragraph (o)(1) of this section must submit the plan to 

the Administrator as described in paragraphs (o)(2)(i) through (iii) of this section. 
Page 143 of 175 

(i) The owner or operator must develop and implement the flare management plan no later 

than [insert date 3 years and 60 days after date of publication in the Federal Register], or 

at startup for a new flare that commenced construction on or after [insert date 60 days 

after date of publication in the Federal Register]. 

(ii) The owner or operator must comply with the plan as submitted by the date specified in 

paragraph (o)(2)(i) of this section. The plan should be updated periodically to account for 

changes in the operation of the flare, such as new connections to the flare or the installation 

of a flare gas recovery system, but the plan need be re-submitted to the Administrator only 

if the owner or operator alters the design smokeless capacity of the flare. The owner or 

operator must comply with the updated plan as submitted. 

(iii) All versions of the plan submitted to the Administrator shall also be submitted to the 

following address: U.S. Environmental Protection Agency, Office of Air Quality Planning 

and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143-01), 

Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 

27711. Electronic copies in lieu of hard copies may also be submitted to 

refinerynsps@epa.gov . 

(3) The owner or operator of a flare subject to this subpart shall conduct a root cause 

analysis and a corrective action analysis for each flow event that contains regulated 

material and that meets either the criteria in paragraphs (o)(3)(i) or (ii) of this section. 

(i) The vent gas flow rate exceeds the smokeless capacity of the flare and visible emissions 

are present from the flare for more than 5 minutes during any 2 consecutive hours during 

the release event. 

(ii) The vent gas flow rate exceeds the smokeless capacity of the flare and the 15-minute 

block average flare tip velocity exceeds the maximum flare tip velocity determined using 

the methods in paragraph (d)(2) of this section. 

(4) A root cause analysis and corrective action analysis must be completed as soon as 

possible, but no later than 45 days after a flare flow event meeting the criteria in 

paragraphs (o)(3)(i) or (ii) of this section. Special circumstances affecting the number of 

root cause analyses and/or corrective action analyses are provided in paragraphs (o)(4)(i) 

through (v) of this section. 

(i) You may conduct a single root cause analysis and corrective action analysis for a single 

continuous flare flow event that meets both of the criteria in paragraphs (o)(3)(i) and (ii) of 

this section. 

(ii) You may conduct a single root cause analysis and corrective action analysis for a single 

continuous flare flow event regardless of the number of 15-minute block periods in which 

the flare tip velocity was exceeded or the number of 2 hour periods that contain more the 5 

minutes of visible emissions. 
Page 144 of 175 

(iii) You may conduct a single root cause analysis and corrective action analysis for a single 

event that causes two or more flares that are operated in series (i.e., cascaded flare systems) 

to have a flow event meeting the criteria in paragraphs (o)(3)(i) or (ii) of this section. 

(iv) You may conduct a single root cause analysis and corrective action analysis for a single 

event that causes two or more flares to have a flow event meeting the criteria in paragraphs 

(o)(3)(i) or (ii) of this section, regardless of the configuration of the flares, if the root cause 

is reasonably expected to be a force majeure event, as defined in this subpart. 

(v) Except as provided in paragraphs (o)(4)(iii) and (iv) of this section, if more than one 

flare has a flow event that meets the criteria in paragraphs (o)(3)(i) or (ii) of this section 

during the same time period, an initial root cause analysis shall be conducted separately for 

each flare that has a flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this 

section. If the initial root cause analysis indicates that the flow events have the same root 

cause(s), the initially separate root cause analyses may be recorded as a single root cause 

analysis and a single corrective action analysis may be conducted. 

(5) Each owner or operator of a flare required to conduct a root cause analysis and 

corrective action analysis as specified in paragraphs (o)(3) and (o)(4) shall implement the 

corrective action(s) identified in the corrective action analysis in accordance with the 

applicable requirements in paragraphs (o)(5)(i) through (iii) of this section. 

(i) All corrective action(s) must be implemented within 45 days of the event for which the 

root cause and corrective action analyses were required or as soon thereafter as 

practicable. If an owner or operator concludes that no corrective action should be 

implemented, the owner or operator shall record and explain the basis for that conclusion 

no later than 45 days following the event. 

(ii) For corrective actions that cannot be fully implemented within 45 days following the 

event for which the root cause and corrective action analyses were required, the owner or 

operator shall develop an implementation schedule to complete the corrective action(s) as 

soon as practicable. 

(iii) No later than 45 days following the event for which a root cause and corrective action 

analyses were required, the owner or operator shall record the corrective action(s) 

completed to date, and, for action(s) not already completed, a schedule for implementation, 

including proposed commencement and completion dates. 

(6) The owner or operator shall determine the total number of events for which a root 

cause and corrective action analyses was required during the calendar year for each 

affected flare separately for events meeting the criteria in paragraph (o)(3)(i) of this section 

and those meeting the criteria in paragraph (o)(3)(ii) of this section. For the purpose of this 

requirement, a single root cause analysis conducted for an event that met both of the 

criteria in paragraph (o)(3)(i) and (ii) of this section would be counted as an event under 

each of the separate criteria counts for that flare. Additionally, if a single root cause 

analysis was conducted for an event that caused multiple flares to meet the criteria in 
Page 145 of 175 

paragraph (o)(3)(i) or (ii) of this section, that event would count as an event for each of the 

flares for each criteria in paragraph (o)(3) of this section that was met during that event. 

The owner or operator shall also determine the total number of events for which a root 

cause and correct action analyses was required and the analyses concluded that the root 

cause was a force majeure event, as defined in this subpart. 

(7) The following events would be a violation of this emergency flaring work practice 

standard. 

(i) Any flow event for which a root cause analysis was required and the root cause was 

determined to be operator error or poor maintenance. 

(ii) Two visible emissions exceedance events meeting the criteria in paragraph (o)(3)(i) that 

were not caused by a force majeure event from a single flare in a 3 calendar year period for 

the same root cause for the same equipment. 

(iii) Two flare tip velocity exceedance events meeting the criteria in paragraph (o)(3)(ii) 

that were not caused by a force majeure event from a single flare in a 3 calendar year 

period for the same root cause for the same equipment. 

(iv) Three visible emissions exceedance events meeting the criteria in paragraph (o)(3)(i) 

that were not caused by a force majeure event from a single flare in a 3 calendar year 

period for any reason. 

(v) Three flare tip velocity exceedance events meeting the criteria in paragraph (o)(3)(ii) 

that were not caused by a force majeure event from a single flare in a 3 calendar year 

period for any reason. 

(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 evaluation 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. 
Page 146 of 175 

(1) The owner or operator shall prepare and submit a site-specific test plan and receive 

approval of the site-specific performance evaluation plan prior to conducting any flare 

performance evaluation test runs intended for use in developing site-specific operating 

limits. The site-specific performance evaluation 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 performance evaluation plan, the owner or operator shall conduct 

performance evaluation test runs for the flare following the procedures described in the 

site-specific performance evaluation 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 evaluation. These parameters may include but are not limited to vent gas flow 

rate, steam and/or air assist flow rates, and flare vent gas composition. If new operating 

parameters are proposed for use other than those specified in paragraphs (d) through (f) of 

this section, an explanation of the relevance of the proposed operating parameter(s) as an 

indicator of flare combustion performance and why the alternative operating parameter(s) 

can adequately ensure that the flare achieves the required combustion efficiency. 

(v) A detailed description of the measurement methods, monitored pollutant(s), 

measurement locations, measurement frequency, and recording frequency proposed for 

both emission measurements and flare operating parameters. 

(vi) A description of (including sample calculations illustrating) the planned data reduction 

and calculations to determine the flare operating parameters. 

(vii) The minimum number and length of test runs and range of operating values to be 

evaluated during the performance evaluation. A sufficient number of test runs shall be 

conducted to identify the point at which the combustion/destruction efficiency of the flare 

deteriorates. 

(viii) [Reserved] 

(ix) Test schedule. 
Page 147 of 175 

(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 evaluation test run conducted, including, at a minimum: 

(A) The measured combustion/destruction efficiency. 

(B) The measured or calculated operating parameters for each test run. If operating 

parameters are calculated, the raw data from which the parameters are calculated must be 

included in the test report. 

(C) Measurement location descriptions for both emission measurements and flare 

operating parameters. 

(D) Description of sampling and analysis procedures (including number and length of test 

runs) and any modifications to standard procedures. If there were deviations from the 

approved test plan, a detailed description of the deviations and rationale why the test 

results or calculation procedures used are appropriate. 

(E) Operating conditions (e.g., vent gas composition, assist rates, etc.) that occurred during 

the test. 

(F) Quality assurance procedures. 

(G) Records of calibrations. 

(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 evaluation 

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 
Page 148 of 175 

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 evaluation conducted following the methods in an approved 

site-specific performance evaluation plan for an operating limit(s) that shall apply 

specifically to that flare. 

(ii) The request must be submitted to the Administrator for approval. The owner or 

operator must continue to comply with the applicable standards for flares in this subpart 

until the requirements in 40 CFR 63.6(g)(1) are met and a notice is published in the Federal 

Register allowing use of such an alternative means of emission limitation. 

(iii) The request shall also be submitted to the following address: U.S. Environmental 

Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and 

Programs Division, U.S. EPA Mailroom (E143–01), Attention: Refinery Sector Lead, 109 

T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard 

copies may also be submitted to refineryrtr@epa.gov. 

(iv) If the Administrator finds any deficiencies in the request, the request must be revised 

to address the deficiencies and be re-submitted for approval within 45 days of receipt of the 

notice of deficiencies. The owner or operator must comply with the revised request as 

submitted until it is approved. 

(4) The approval process for a request for a flare-specific operating limit(s) is described in 

paragraphs (r)(4)(i) through (iii) of this section. 

(i) Approval by the Administrator of a flare-specific operating limit(s) request will be based 

on the completeness, accuracy and reasonableness of the request. Factors that the EPA will 

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. 
Page 149 of 175 

(C) The results of the flare performance evaluation test runs 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 evaluation 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) Except for CPMS installed for pilot flame monitoring, all monitoring equipment must 

meet the applicable minimum accuracy, calibration and quality control requirements 

specified in table 13 of this subpart. 

(2) The owner or operator shall ensure the readout (that portion of the CPMS that 

provides a visual display or record) or other indication of the monitored operating 

parameter from any CPMS required for compliance is readily accessible onsite for 

operational control or inspection by the operator of the source. 

(3) All CPMS must complete a minimum of one cycle of operation (sampling, analyzing and 

data recording) for each successive 15-minute period. 

(4) Except for periods of monitoring system malfunctions, repairs associated with 

monitoring system malfunctions and required monitoring system quality assurance or 

quality control activities (including, as applicable, calibration checks and required zero and 

span adjustments), the owner or operator shall operate all CPMS and collect data 

continuously at all times 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 except for CPMS installed for pilot flame monitoring, the owner or 

operator shall comply with the out-of-control procedures described in paragraphs (c) of 

this section. 

(7) The owner or operator shall reduce data from a CPMS as specified in paragraph (d) of 

this section. 
Page 150 of 175 

(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 that covers each flare 

subject to the provisions in §63.670 and each CPMS installed to comply with applicable 

provisions in §63.670. 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 (b)(3)(i) 

through (vii) of this section. 

(i) Manufacturer and model number for all monitoring equipment components installed to 

comply with applicable provisions in §63.670. 

(ii) Performance specifications, as provided by the manufacturer, and any differences 

expected for this installation and operation. 

(iii) The location of the CPMS sampling probe or other interface and a justification of how 

the location meets the requirements of paragraph (a)(1) of this section. 

(iv) Placement of the CPMS readout, or other indication of parameter values, indicating 

how the location meets the requirements of paragraph (a)(2) of this section. 

(v) Span of the CPMS. The span of the CPMS sensor and analyzer must encompass the full 

range of all expected values. 

(vi) How data outside of the span of the CPMS 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. 
Page 151 of 175 

(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 (b)(5)(i) through (vi) of this section and a schedule for 

conducting these procedures. The routine procedures must provide an assessment of CPMS 

performance. 

(i) Initial and subsequent calibration of the CPMS and acceptance criteria. 

(ii) Determination and adjustment of the calibration drift of the CPMS. 

(iii) Daily checks for indications that the system is responding. If the CPMS system includes 

an internal system check, the owner or operator may use the results to verify the system is 

responding, as long as the system provides an alarm to the owner or operator or 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 installed to comply with applicable provisions in 

§63.670 except for CPMS installed for pilot flame monitoring, 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. 
Page 152 of 175 

(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 installed 

to comply with applicable provisions in §63.670 as specified in paragraphs (d)(1) through 

(3) of this section. 

(1) The owner or operator may round the data to the same number of significant digits 

used in that operating limit. 

(2) Periods of non-operation of the process unit (or portion thereof) resulting in cessation of 

the emissions to which the monitoring applies must not be included in the 15-minute block 

averages. 

(3) Periods when the CPMS is out of control must not be included in the 15-minute block 

averages. 

(e) Additional requirements for gas chromatographs. For monitors used to determine 

compositional analysis for net heating value per §63.670(j)(1), the gas chromatograph must 

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

(1) The quality assurance requirements are in table 13 of this subpart. 

(2) The calibration gases must meet one of the following options: 

(i) The owner or operator must use a calibration gas or multiple gases that include all of 

compounds listed in paragraphs (e)(2)(i)(A) through (K) of this section that may be 

reasonably expected to exist in the flare gas stream and optionally include any of the 

compounds listed in paragraphs (e)(2)(i)(L) through (O) of this section. 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. 

(A) Hydrogen. 

(B) Methane. 
Page 153 of 175 

(C) Ethane. 

(D) Ethylene. 

(E) Propane. 

(F) Propylene. 

(G) n-Butane. 

(H) iso-Butane. 

(I) Butene (general). It is not necessary to separately speciate butene isomers, but the net 

heating value of trans-butene must be used for co-eluting butene isomers. 

(J) 1,3-Butadiene. It is not necessary to separately speciate butadiene isomers, but you must 

use the response factor and net heating value of 1,3-butadiene for co-eluting butadiene 

isomers. 

(K) n-Pentane. Use the response factor for n-pentane to quantify all C5+ hydrocarbons. 

(L) Acetylene (optional). 

(M) Carbon monoxide (optional). 

(N) Propadiene (optional). 

(O) Hydrogen sulfide (optional). 

(ii) The owner or operator must use a surrogate calibration gas consisting of hydrogen and 

C1 through C5 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) Use the response factor for n-pentane to quantify unknown components detected in the 

analysis that elute after n-pentane. 

§§ 63.672-63.679 [Reserved] 

Appendix to Subpart CC of Part 63—Tables 
Page 154 of 175 

Table 1—Hazardous Air Pollutants 

Chemical name CAS No.a

Benzene 71432

Biphenyl 92524

Butadiene (1,3) 106990

Carbon disulfide 75150

Carbonyl sulfide 463581

Cresol (mixed isomersb) 1319773

Cresol (m-) 108394

Cresol (o-) 95487

Cresol (p-) 106445

Cumene 98828

Dibromoethane (1,2) (ethylene dibromide) 106934

Dichloroethane (1,2) 107062

Diethanolamine 111422

Ethylbenzene 100414

Ethylene glycol 107211

Hexane 110543

Methanol 67561

Methyl isobutyl ketone (hexone) 108101

Methyl tert butyl ether 1634044

Naphthalene 91203

Phenol 108952

Toluene 108883

Trimethylpentane (2,2,4) 540841

Xylene (mixed isomersb) 1330207

xylene (m-) 108383

xylene (o-) 95476

xylene (p-) 106423

a

CAS number = Chemical Abstract Service registry number assigned to specific compounds, 

isomers, or mixtures of compounds. 

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
Page 155 of 175 

 III 1,000

a

Subpart H of this part. 

Table 3—Equipment Leak Recordkeeping and Reporting Requirements for Sources 

Complying With §63.648 of Subpart CC by Compliance With Subpart H of this Parta

Reference 

(section of 

subpart H of 

this part) Description Comment 

63.181(a) Recordkeeping system 

requirements 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 

63.181(b) Records required for 

process unit equipment 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 

63.181(c) Visual inspection 

documentation 

Except for §§63.181(b)(2)(iii) and 

63.181(b)(9). 

63.181(d) Leak detection record 

requirements 

Except for §63.181(d)(8). 

63.181(e) Compliance requirements 

for pressure tests for batch 

product process equipment 

trains 

This subsection does not apply to subpart 

CC. 

63.181(f) Compressor compliance test 

records. 

63.181(g) Closed-vent systems and 

control device record 

requirements. 

63.181(h) Process unit quality 

improvement program 

records. 

63.181(i) Heavy liquid service 

determination record. 

63.181(j) Equipment identification 

record. 

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). 
Page 156 of 175 

63.182(d) Periodic report Except for §§63.182 (d)(2)(vii), (d)(2)(viii), 

and (d)(3). 

a

This table does not include all the requirements delineated under the referenced sections. See 

referenced sections for specific requirements. 

Table 4—Gasoline Distribution Emission Point Recordkeeping and Reporting 

Requirementsa

Reference 

(section of 

subpart R) Description Comment 

63.428(b) or (k) Records of test results for each 

gasoline cargo tank loaded at the 

facility 

63.428(c) Continuous monitoring data 

recordkeeping requirements 

63.428(g)(1) Semiannual report loading rack 

information 

Required to be submitted with the 

Periodic Report required under 40 

CFR part 63, subpart CC. 

63.428(h)(1) 

through (h)(3) 

Excess emissions report loading 

rack information 

Required to be submitted with the 

Periodic Report required under 40 

CFR part 63, subpart CC. 

a

This table does not include all the requirements delineated under the referenced sections. See 

referenced sections for specific requirements. 

Table 5—Marine Vessel Loading Operations Recordkeeping and Reporting Requirementsa

Reference 

(section of 

subpart Y) Description Comment 

63.562(e)(2) Operation and maintenance 

plan for control equipment and 

monitoring equipment 

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 
Page 157 of 175 

Reference 

(section of 

subpart Y) Description Comment 

63.567(d) Flare recordkeeping 

requirements 

63.567(e) Summary report and excess 

emissions and monitoring 

system performance report 

requirements 

The information required under this 

paragraph is to be submitted with the 

Periodic Report required under 40 CFR 

part 63, subpart CC. 

63.567(f) Vapor collection system 

engineering report 

63.567(g) Vent system valve bypass 

recordkeeping requirements 

63.567(h) Marine vessel vapor-tightness 

documentation 

63.567(i) Documentation file 

maintenance 

63.567(j) Emission estimation reporting 

and recordkeeping procedures 

a

This table does not include all the requirements delineated under the referenced sections. See 

referenced sections for specific requirements. 

Table 6—General Provisions Applicability to Subpart CCa

Reference 

Applies to 

subpart CC Comment 

63.1(a)(1) Yes 

63.1(a)(2) Yes 

63.1(a)(3) Yes 

63.1(a)(4) Yes 

63.1(a)(5) No Reserved. 

63.1(a)(6) Yes Except the correct mail drop (MD) number is C404–04. 

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. 
Page 158 of 175 

Reference 

Applies to 

subpart CC Comment 

63.1(c)(5) Yes Except that sources are not required to submit notifications 

overridden by this table. 

63.1(d) No Reserved. 

63.1(e) No No CAA section 112(j) standard applies to the affected 

sources under subpart CC. 

63.2 Yes §63.641 of subpart CC specifies that if the same term is 

defined in subparts A and CC, it shall have the meaning 

given in subpart CC. 

63.3 Yes 

63.4(a)(1)–

63.4(a)(2) 

Yes 

63.4(a)(3)–

63.4(a)(5) 

No Reserved. 

63.4(b) Yes 

63.4(c) Yes 

63.5(a) Yes 

63.5(b)(1) Yes 

63.5(b)(2) No Reserved. 

63.5(b)(3) Yes 

63.5(b)(4) Yes Except the cross-reference to §63.9(b) is changed to 

§63.9(b)(4) and (5). Subpart CC overrides §63.9 (b)(2). 

63.5(b)(5) No Reserved. 

63.5(b)(6) Yes 

63.5(c) No Reserved. 

63.5(d)(1)(i) Yes Except that the application shall be submitted as soon as 

practicable before startup, but no later than 90 days after the 

promulgation date of subpart CC if the construction or 

reconstruction had commenced and initial startup had not 

occurred before the promulgation of subpart CC. 

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 
Page 159 of 175 

Reference 

Applies to 

subpart CC Comment 

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. 

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 
Page 160 of 175 

Reference 

Applies to 

subpart CC Comment 

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 

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 

site-specific 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.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).
Page 161 of 175 

Reference 

Applies to 

subpart CC Comment 

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.

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. 
Page 162 of 175 

Reference 

Applies to 

subpart CC Comment 

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

63.10(b)(2)(ii) YesNo §63.655(i) of subpart CC specifies the records that must 

be kept.

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 §63.655(i) of subpart CC specifies the records that must 

be kept.
Page 163 of 175 

Reference 

Applies to 

subpart CC Comment 

63.10(c)(12)–

63.10(c)(15) 

No 

63.10(d)(1) Yes 

63.10(d)(2) No Although §63.655(f) of subpart CC specifies performance 

test reporting., EPA may approve other timeframes for 

submittal of performance test data 

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 specifies the reporting 

requirements. 

63.10(e) No 

63.10(f) Yes 

63.10(d)(5)(ii)11 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.Except that flares complying with 

§63.670 are not subject to the requirements of §63.11(b).

63.10(e) No 

63.10(f) Yes 

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
Page 164 of 175 

Chemical name CAS No.a Fm Fe Fr 

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. 

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. 
Page 165 of 175 

Table 10—Miscellaneous Process Vents—Monitoring, Recordkeeping and Reporting 

Requirements for Complying With 98 Weight-Percent Reduction of Total Organic HAP 

Emissions or a Limit of 20 Parts Per Million by Volume 

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

Thermal incinerator Firebox temperatureb

(63.644(a)(1)(i)) 

1. Continuous recordsc. 

2. Record and report the firebox 

temperature averaged over the full 

period of the performance test—

NCSd

. 

3. Record the daily average firebox 

temperature for each operating daye

. 

4. Report all daily average 

temperatures that are outside the 

range established in the NCS or 

operating permit and all operating 

days when insufficient monitoring 

data are collectedf

—PRg. 

Catalytic incinerator Temperature upstream 

and downstream of the 

catalyst bed 

(63.644(a)(1)(ii)) 

1. Continuous recordsc. 

2. Record and report the upstream and 

downstream temperatures and the 

temperature difference across the 

catalyst bed averaged over the full 

period of the performance test—

NCSd

. 

3. Record the daily average upstream 

temperature and temperature 

difference across the catalyst bed for 

each operating daye

. 

4. Report all daily average upstream 

temperatures that are outside the 

range established in the NCS or 

operating permit—PRg

. 

5. Report all daily average 

temperature differences across the 

catalyst bed that are outside the range 

established in the NCS or operating 

permit—PRg

. 
Page 166 of 175 

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

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. 

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). 
Page 167 of 175 

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

2. Report information as specified 

in §63.655(g)(11)—PRg. 

All control devices Presence of flow 

diverted to the 

atmosphere from the 

control device 

(63.644(c)(1)) or 

1. Hourly records of whether the flow 

indicator was operating and whether 

flow was detected at any time during 

each hour. 

2. Record and report the times and 

durations of all periods when the vent 

stream is diverted through a bypass 

line or the monitor is not operating—

PRg

. 

Monthly inspections of 

sealed valves 

[(63.644(c)(2)])

1. Records that monthly inspections 

were performed. 

2. Record and report all monthly 

inspections that show the valves are 

not closed or the seal has been 

changed—PRg

. 

a

Regulatory citations are listed in parentheses. 

b

Monitor may be installed in the firebox or in the ductwork immediately downstream of the 

firebox before any substantial heat exchange is encountered. 

c

“Continuous records” is defined in §63.641. 

d

NCS = Notification of Compliance Status Report described in §63.655. 

e

The daily average is the average of all recorded parameter values for the operating day. If all 

recorded values during an operating day are within the range established in the NCS or operating 

permit, a statement to this effect can be recorded instead of the daily average. 

f

When a period of excess emission is caused by insufficient monitoring data, as described in 

§63.655(g)(6)(i)(C) or (D), the duration of the period when monitoring data were not collected 

shall be included in the Periodic Report. 

g

PR = Periodic Reports described in §63.655(g). 

h

No monitoring is required for boilers and process heaters with a design heat capacity ≥44 

megawatts or for boilers and process heaters where all vent streams are introduced into the flame 

zone. No recordkeeping or reporting associated with monitoring is required for such boilers and 

process heaters. 
Page 168 of 175 

i

Process vents that are routed to refinery fuel gas systems are not regulated under this subpart

provided that on and after [insert date 3 years and 60 days after date of publication 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 June 30, 

2014 

(i) Requirements for 

new sources in 

§§63.640 through 

63.642, §63.647, 

§§63.650 through 

63.653, and §§63.656 

through 63.660 

Upon initial startup 

or [insert date 60 

days after date of 

publication in the 

Federal Register], 

whichever is later 

§63.640(k), (l) and 

(m) 

(ii) The new source 

requirements in 

§63.654 for heat 

exchange systems 

Upon initial startup 

or October 28, 2009, 

whichever is later 

§63.640(k), (l) and 

(m) 

(2) After 

September 4, 2007 

but on or before 

June 30, 2014 

(i) Requirements for 

new sources in 

§§63.640 through 

63.653 and 63.656b,c

Upon initial startup §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 and 63.657b

On or before [insert 

date 3 years and 60 

days after date of 

publication in the 

Federal Register] 

§63.640(k), (l) and 

(m) 

(iii) Requirements for 

existing sources in 

§63.658 

On or before [insert 

date 2 years and 60 

days after date of 

publication in the 

Federal Register] 

§63.640(k), (l) and 

(m) 

(iv) Requirements for 

new sources in 

§63.660c

On or before [insert 

date 150 days after 

date of publication 

in the Federal 

Register] 

§63.640(k), (l) and 

(m) 
Page 169 of 175 

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... 

(v) The new source 

requirements in 

§63.654 for heat 

exchange systems 

Upon initial startup 

or October 28, 2009, 

whichever is later 

§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

Upon initial startup 

or August 18, 1995, 

whichever is later 

§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 and 63.657d

On or before [insert 

date 3 years and 60 

days after date of 

publication in the 

Federal Register] 

§63.640(k), (l) and 

(m) 

(iii) Requirements for 

existing sources in 

§63.658 

On or before [insert 

date 2 years and 60 

days after date of 

publication in the 

Federal Register] 

§63.640(k), (l) and 

(m) 

(iv) Requirements for 

new sources in 

§63.660e

On or before [insert 

date 150 days after 

date of publication 

in the Federal 

Register] 

§63.640(k), (l) and 

(m) 

(v) The existing source 

requirements in 

§63.654 for heat 

exchange systems 

On or before 

October 29, 2012 

§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 
Page 170 of 175 

If the 

construction/ 

reconstruction 

datea is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as provided 

in... 

(ii) Requirements for 

existing sources in 

§§63.640 through 

63.645, §§63.647 

through 63.653, and 

§§63.656 and 63.657f

On or before [insert 

date 3 years and 60 

days after date of 

publication in the 

Federal Register] 

§63.640(k), (l) and 

(m) 

(iii) Requirements for 

existing sources in 

§63.658 

On or before [insert 

date 2 years and 60 

days after date of 

publication in the 

Federal Register] 

§63.640(k), (l) and 

(m) 

(iv) Requirements for 

existing sources in 

§63.660g

On or before [insert 

date 150 days after 

date of publication 

in the Federal 

Register] 

§63.640(k), (l) and 

(m) 

(v) The existing source 

requirements in 

§63.654 for heat 

exchange systems 

On or before 

October 29, 2012 

§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) and (2)(ii) 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) and (2)(iv) of this table, the owner or 

operator may elect to comply with either the requirements in item (2)(i) or item (2)(iv) of 

this table. The requirements in item (2)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (2)(iv) of this table. 

d Between the compliance dates in items (3)(i) and (3)(ii) 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. 
Page 171 of 175 

e

 Between the compliance dates in items (3)(i) and (3)(iv) of this table, the owner or 

operator may elect to comply with either the requirements in item (3)(i) or item (3)(iv) of 

this table. The requirements in item (3)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (3)(iv) of this table. 

f

 Between the compliance dates in items (4)(i) and (4)(ii) of this table, the owner or operator 

may elect to comply with either the requirements in item (4)(i) or item (4)(ii) of this table. 

The requirements in item (4)(i) of this table no longer apply after demonstrated compliance 

with the requirements in item (4)(ii) of this table. 

g Between the compliance dates in items (4)(i) and (4)(iv) of this table, the owner or 

operator may elect to comply with either the requirements in item (4)(i) or item (4)(iv) of 

this table. The requirements in item (4)(i) of this table no longer apply after demonstrated 

compliance with the requirements in item (4)(iv) 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 1,212A 4.0 

Hydrogen 

Sulfide 

H2S 34.08 0 587 4.0 

Methane CH4 16.04 1 896 5.0 

MethylAcetylene C3H4 40.06 3 2,088 1.7 

Nitrogen N2 28.01 0 0 ∞

Oxygen O2 32.00 0 0 ∞
Page 172 of 175 

Component 

Molecular 

Formula 

MWi

(pounds 

per poundmole) 

CMNi

(mole per 

mole) 

NHVi

(British thermal 

units per 

standard cubic 

foot) 

LFLi

(volume 

%) 

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 ∞

A The theoretical net heating value for hydrogen is 274 Btu/scf, but for the purposes of the 

flare requirement in this subpart, a net heating value of 1,212 Btu/scf shall be used. 

Table 13—Calibration and Quality Control Requirements for CPMS 

Parameter Minimum accuracy 

requirements 

Calibration requirements 

Temperature ±1 percent over the normal 

range of temperature 

measured, expressed in 

degrees Celsius (C), or 2.8 

degrees C, whichever is 

greater. 

Conduct calibration checks at least 

annually; conduct calibration 

checks following any period of 

more than 24 hours throughout 

which the temperature exceeded 

the manufacturer’s specified 

maximum rated temperature or 

install a new temperature sensor. 

At least quarterly, inspect all 

components for integrity and all 

electrical connections for 

continuity, oxidation, and galvanic 

corrosion, unless the CPMS has a 

redundant temperature sensor. 

Record the results of each calibration 

check and inspection. 

Locate the temperature sensor in a 

position that provides a 

representative temperature; shield 

the temperature sensor system 

from electromagnetic interference 

and chemical contaminants. 

Flow Rate for 

All Flows 

Other Than 

Flare Vent 

Gas 

±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. 

Conduct a flow sensor calibration 

check at least biennially (every two 

years); conduct a calibration check 

following any period of more than 

24 hours throughout which the 

flow rate exceeded the 
Page 173 of 175 

Parameter Minimum accuracy 

requirements 

Calibration requirements 

±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. 

±5 percent over the normal 

range measured for mass 

flow. 

manufacturer’s specified 

maximum rated flow rate or install 

a new flow sensor. 

At least quarterly, inspect all 

components for leakage, unless the 

CPMS has a redundant flow 

sensor. 

Record the results of each calibration 

check and inspection. 

Locate the flow sensor(s) and other 

necessary equipment (such as 

straightening vanes) in a position 

that provides representative flow; 

reduce swirling flow or abnormal 

velocity distributions due to 

upstream and downstream 

disturbances. 

Flare Vent 

Gas Flow Rate 

±20 percent of flow rate at 

velocities ranging from 

0.03 to 0.3 meters per 

second (0.1 to 1 feet per 

second). 

±5 percent of flow rate at 

velocities greater than 0.3 

meters per second (1 feet 

per second). 

Conduct a flow sensor calibration 

check at least biennially (every two 

years); conduct a calibration check 

following any period of more than 

24 hours throughout which the 

flow rate exceeded the 

manufacturer’s specified 

maximum rated flow rate or install 

a new flow sensor. 

At least quarterly, inspect all 

components for leakage, unless the 

CPMS has a redundant flow 

sensor. 

Record the results of each calibration 

check and inspection. 

Locate the flow sensor(s) and other 

necessary equipment (such as 

straightening vanes) in a position 

that provides representative flow; 

reduce swirling flow or abnormal 

velocity distributions due to 

upstream and downstream 

disturbances. 

Pressure ±5 percent over the normal 

operating range or 0.12 

kilopascals (0.5 inches of 

Review pressure sensor readings at 

least once a week for straightline 

(unchanging) pressure and 

perform corrective action to ensure 
Page 174 of 175 

Parameter Minimum accuracy 

requirements 

Calibration requirements 

water column), whichever 

is greater. 

proper pressure sensor operation if 

blockage is indicated. 

Using an instrument recommended by 

the sensor’s manufacturer, check 

gauge calibration and transducer 

calibration annually; conduct 

calibration checks following any 

period of more than 24 hours 

throughout which the pressure 

exceeded the manufacturer’s 

specified maximum rated pressure 

or install a new pressure sensor. 

At least quarterly, inspect all 

components for integrity, all 

electrical connections for 

continuity, and all mechanical 

connections for leakage, unless the 

CPMS has a redundant pressure 

sensor. 

Record the results of each calibration 

check and inspection. 

Locate the pressure sensor(s) in a 

position that provides a 

representative measurement of the 

pressure and 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 yearround 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 
Page 175 of 175 

Parameter Minimum accuracy 

requirements 

Calibration requirements 

least two equivalent duct diameters 

from the nearest control device, 

point of pollutant generation, air 

in-leakages, or other point at 

which a change in the pollutant 

concentration or emission rate 

occurs. 

Net Heating 

Value by Gas 

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, except that a single 

daily mid-level calibration check 

can be used (rather than triplicate 

analysis), the multi-point 

calibration can be conducted 

quarterly (rather than monthly), 

and the sampling line temperature 

must be maintained at a minimum 

temperature of 60 °C (rather than 

120 °C). 

Hydrogen 

analyzer 

±2 percent over the 

concentration measured or 

0.1 volume percent, 

whichever is greater. 

Specify calibration requirements in 

your site specific CPMS 

monitoring plan. Calibration 

requirements should follow 

manufacturer’s recommendations 

at a minimum. 

Select the sampling location at least 

two equivalent duct diameters 

from the nearest control device, 

point of pollutant generation, air 

in-leakages, or other point at 

which a change in the pollutant 

concentration occurs.