June 11, 2013 

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)(15) through (c)(8) 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). 
Page 2 of 109 

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

combination, listed in paragraphs (c)(1) through (c)(8) of this section that are located at a single 

refinery plant site. 

(1) All miscellaneous process vents from petroleum refining process units meeting the criteria in 

paragraph (a) of this section; 

(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, associated with petroleum refining process units meeting the 

criteria in paragraph (a) of this section and which are in organic hazardous air pollutants (HAP) 

service 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 
Page 3 of 109 

(5) Emission points routed to a fuel gas system, as defined in §63.641 of this subpart. No 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 
Page 4 of 109 

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

§63.655(h)(6)(ii). 

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

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

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

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

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

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

which this subpart applies. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

source to which this subpart applies. 

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

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

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

§63.655(h)(6)(iii). 

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

through (g)(7) of this section. 

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

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

subpart; 

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

subpart that is located within a petroleum refining process unit that is subject to this subpart; 
Page 5 of 109 

(3) Units processing natural gas liquids; 

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

(5) Shale oil extraction units; 

(6) Ethylene processes; and 

(7) Process units and emission points subject to subparts F, G, H, and I of this part. 

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

are required to achieve compliance on or before the dates specified in paragraphs (h)(1) through 

(h)(6) of this section. 

(1) Except as provided in paragraphs (h)(1)(i) and (iiv) 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) [Reserved]

(ii) Heat exchange systems aAt new sources that commence construction or reconstruction after 

July 14, 1994August 18, 1995, but on or before September 4, 2007, heat exchange systems 

shall be in compliancey with the existing source requirements for heat exchange systems 

specified in §63.654 no later than October 29, 2012. 

(iii) [Reserved]

(iiv) Heat exchange systems aAt new sources that commence construction or reconstruction after 

September 4, 2007, heat exchange systems shall be in compliance with the new source 

requirements in §63.654 upon initial startup or October 28, 2009, whichever is later. 

(2) Except as provided in paragraphs (h)(3) through (h)(6) of this section, existing sources shall 

be in compliance with this subpart no later than August 18, 1998, except as provided in 

§63.6(c)(5) of subpart A of this part, or unless an extension has been granted by the 

Administrator as provided in §63.6(i) of subpart A of this part. 

(3) Marine tank vessels at existing sources shall be in compliance with this subpart 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). 

(4) Existing Group 1 floating roof storage vessels 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. 
Page 6 of 109 

(5) 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)(5)(i) through (h)(5)(iii) of this section. 

(i) Phase I (see table 2 of this subpart), beginning on August 18, 1998; 

(ii) Phase II (see table 2 of this subpart), beginning no later than August 18, 1999; and 

(iii) Phase III (see table 2 of this subpart), beginning no later than February 18, 2001. 

(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 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: 
Page 7 of 109 

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

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

sooner than November 16, 1995); 

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

addition, or change; 

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

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

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

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

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

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

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

requirements are summarized in table 5 of this subpart. 

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

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

exchange system that meets the criteria in paragraphs (c)(1) through (8) 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 (3) 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 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 
Page 8 of 109 

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

August 18, 1998, whichever is later. 

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

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

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

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

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

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

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

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

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

loading operation, or heat exchange system meeting the criteria in paragraphs (c)(1) through (8) 

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. 
Page 9 of 109 

(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 requirements of this subpart for existing sources for the Group 1 emission 

point as expeditiously as practicable, but in no event later than 3 years after the emission point 

becomes Group 1. 

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

along with a justification for the schedule. 

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

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

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

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

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

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

Status report is due. 

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

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

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

(n) Overlap of subpart CC with other regulations for storage vessels. 

(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 §60.112b of 40 CFR part 

60, subpart Kb is required to comply only with 40 CFR part 60, subpart Kb except as provided in 

paragraph (n)(8) of this section. 

(4) 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. 

(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. 
Page 10 of 109 

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

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

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

paragraph (n)(9) of this section. 

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

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

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

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

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

this section. 

(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. 

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

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

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

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

provide a request for the extension to the Administrator. 

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

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

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

provide the date the storage vessel was emptied. 

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

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

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

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

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

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

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

(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. 
Page 11 of 109 

(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. 

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

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

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

calendar days each. 

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

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

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

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

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

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

possible. 

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

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

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

§60.113a(a)(1)(i)(E) of subpart Ka. 

(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)(C) 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 
Page 12 of 109 

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. 

(ii) Comply with paragraphs (o)(2)(ii)(A) and (o)(2)(ii)(B) of this section. 

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

G. 

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

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

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

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

(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. 

§ 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. 
Page 13 of 109 

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. 

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. 

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. 

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. 
Page 14 of 109 

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

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

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

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

considered control devices. 

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

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

draft. 

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

before exposure to the atmosphere. 

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

during the initiation of the depressuring cycle of the decoking operation 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 drum deheading, draining, or decoking (coke cutting), are not considered to be 

delayed coker vents. 

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 associated with a petroleum refining process unit; an individual 

storage vessel or equipment leak associated with a bulk gasoline terminal or pipeline breakout 

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

classified under Standard Industrial Classification code 2911; or a marine tank vessel loading 

operation located at a petroleum refinery. 

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

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

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

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

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

tanks are not equipment leaks. 
Page 15 of 109 

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. 

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

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

plants or blocked operations. 

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

position would allow gas to flow, in a line. 

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

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

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

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

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

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

methane, light hydrocarbons, hydrogen and other miscellaneous species. 

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

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

engines. 

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

other piping and valves necessary to fill gasoline cargo tanks. 

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

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

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

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

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

and any other person. 

Group 1 marine tank vessel means a vessel at an existing source loaded at any land- or 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 16 of 109 

Group 1 storage vessel means 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 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 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. 

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

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

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

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

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

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

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

loading rack. 

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

Group 1 marine tank vessel. 

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

definition of a Group 1 miscellaneous process vent. 

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

storage vessel. 

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

Group 1 wastewater stream. 

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 collectionseries of devices used to transfer heat from 

process fluids to water without intentional direct contact of the process fluid with the water (i.e., 

non-contact heat exchanger) and to transport and/or cool the water in a closed-loop recirculation 

system (cooling tower system) or a once-through system (e.g., river or pond water). For 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 exchanger(s). For once-through systems, the heat exchange system 

consists of allone or more heat exchangers that are in organic HAP service, as defined in this 
Page 17 of 109 

subpart, servicing an individual petroleum refinery process unit and all water lines to and from 

the heat exchanger(s). Sample coolers or pump seal coolers are not considered heat 

exchangers for the purpose of this definition and are not part of the heat exchange system. 

Intentional direct contact with process fluids results in the formation of a wastewater. 

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

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

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

cooling system, whichever occurs first. 

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

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

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

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

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

gas. 

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

liquid service. 

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

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

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

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

total organic HAP’s as determined according to the provisions of §63.180(d) of subpart H of this 

part and table 1 of this subpart. The provisions of §63.180(d) of subpart H 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. 

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 of 

a petroleum refining process unit meeting the criteria specified in §63.640(a). Miscellaneous 
Page 18 of 109 

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 (steam) ejectors, wash tower overheads, water wash accumulators, 

blowdown condensers/accumulators, and delayed coker vents. Miscellaneous process vents do 

not include: 

(1) Gaseous streams routed to a fuel gas system; 

(2) Relief valve 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; 

(5) In situ sampling systems (onstream analyzers); 

(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 vents associated with coke drum depressuring at or below a coke drum outlet 

pressure of 15 pounds per square inch gauge, deheading, draining, or decoking (coke cutting) or 

pressure testing after decoking; 

(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. 
Page 19 of 109 

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

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

chemicals listed in table 1 of this subpart. 

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

ring aromatic hydrocarbons. 

Periodically discharged means discharges that are intermittent and associated with routine 

operations. Discharges associated with maintenance activities 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. 

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. 

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. 
Page 20 of 109 

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

§63.119 (b)(5) and (b)(6); 

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

§63.119(c)(2); 

(3) 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 

(4) 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. 

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

Reference control technology for wastewater means the use of: 
Page 21 of 109 

(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. 

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

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

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

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

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

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

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

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

Shutdown means the cessation of a petroleum refining process unit or a unit operation (including, 

but not limited to, a distillation unit or reactor) within a petroleum refining process unit for 

purposes including, but not limited to, periodic maintenance, replacement of equipment, or 

repair. 

Startup means the setting into operation of a petroleum refining process unit for purposes of 

production. Startup does not include operation solely for purposes of testing equipment. Startup 

does not include changes in product for flexible operation units. 

Storage vessel means a tank or other vessel that is used to store organic liquids. Storage vessel 

does not include: 

(1) Vessels permanently attached to motor vehicles such as trucks, railcars, barges, or ships; 

(2) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to 

the atmosphere; 

(3) Vessels with capacities smaller than 40 cubic meters; 

(4) Bottoms receiver tanks; or 
Page 22 of 109 

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

provisions. 

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

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

Celsius or ±0.5 °C, whichever is greater. 

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

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

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

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

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

as provided in §63.645 of this subpart. 

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] 

(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. 
Page 23 of 109 

(3) Performance tests shall be conducted according to the provisions of §63.7(e) except that 

performance tests shall be conducted at maximum representative operating capacity for the 

process. During the performance test, an owner or operator shall operate the control device at 

either maximum or minimum representative operating conditions for monitored control device 

parameters, whichever results in lower emission reduction. 

(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 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: 

EA = 0.02Σ EPV1 + Σ EPV2 + 0.05Σ ES1 + Σ ES2 + Σ EGLR1C + Σ EGLR2 + (R) Σ EMV1 + Σ

EMV2 + Σ EWW1C + Σ EWW2

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. 

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. 
Page 24 of 109 

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) 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. 

(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 vent provisions in §§63.643 through 63.645, 

the storage vessel provisions in §63.646, the wastewater provisions in §63.647, the gasoline 

loading rack provisions in §63.650, and the marine tank vessel loading operation provisions in 

§63.651 of this subpart. 

(1) The owner or operator using this compliance approach shall also comply with the 

requirements of §63.655 as applicable. 
Page 25 of 109 

(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 63.647, §§63.650 and 

63.651 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 §§63.652, 63.653, and 63.655, 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. 

§ 63.643 Miscellaneous process vent provisions. 

(a) The owner or operator of a Group 1 miscellaneous process vent as defined in §63.641 shall 

comply with the requirements of either paragraphs (a)(1) or (a)(2) of this section. 

(1) Reduce emissions of organic HAP’s using a flare that meets the requirements of §63.11(b) of 

subpart A of this part. 

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

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

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

TOC’s using the procedures in §63.645. 

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

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

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

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

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

§ 63.644 Monitoring provisions for miscellaneous process vents. 

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

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

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

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

equipment shall be installed, calibrated, maintained, and operated according to manufacturer’s 
Page 26 of 109 

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

will monitor accurately. 

(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, 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. 

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

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

zone is exempt from monitoring. 

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

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

the firebox equipped with a continuous recorder. 

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

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

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

owner or operator: 

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

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

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

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

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

comply with paragraph (a) of this section shall comply with either paragraph (c)(1) or (c)(2) of 

this section. 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, maintain, and operate a flow indicator that determines whether a vent 

stream flow is present at least once every hour. 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 
Page 27 of 109 

(2) Secure the bypass line valve in the closed position with a car-seal or a lock-and-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 closed position and the vent 

stream is not diverted through the bypass line. 

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

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

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

Notification of Compliance Status report. 

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

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

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

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

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

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

§ 63.645 Test methods and procedures for miscellaneous process vents. 

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

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

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

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

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

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

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

part. 

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

of this section, respectively. 

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

(2) Any boiler or process heater in which all vent streams are introduced into the flame zone. 

(e) For purposes of determining the TOC emission rate, as specified under paragraph (f) of this 

section, the sampling site shall be after the last product recovery device (as defined in §63.641 of 

this subpart) (if any recovery devices are present) but prior to the inlet of any control device (as 

defined in §63.641 of this subpart) that is present, prior to any dilution of the process vent 

stream, and prior to release to the atmosphere. 

(1) Methods 1 or 1A of 40 CFR part 60, appendix A, as appropriate, shall be used for selection of 

the sampling site. 
Page 28 of 109 

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

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

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

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

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

procedures: 

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

(2) The gas volumetric flow rate shall be determined using Methods 2, 2A, 2C, or 2D of 40 CFR 

part 60, appendix A, 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: 

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. 
Page 29 of 109 

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

following equation if Method 18 is used: 

where: 

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

K2 = Constant, 5.986 × 10−5 (parts per million)−1 (gram-mole per standard cubic meter) 

(kilogram per gram) (minute per day), where the standard temperature (standard cubic meter) is 

at 20 °C. 

Cj = Concentration on a dry basis of organic compound j in parts per million as measured by 

Method 18 of 40 CFR part 60, appendix A, as indicated in paragraph (f)(3) of this section. Cj

includes all organic compounds measured minus methane and ethane. 

Mj = Molecular weight of organic compound j, gram per gram-mole. 

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

(5) If Method 25A is used, the emission rate of TOC (ETOC) shall be calculated using the 

following equation: 

ETOC = K2CTOCMQs

where: 

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

K2 =Constant, 5.986×10–5 (parts per million)−1

 (gram-mole per standard cubic meter) (kilogram 

per gram)(minute per day), where the standard temperature (standard cubic meter) is at 20 °C. 

CTOC = Concentration of TOC on a dry basis in parts per million volume as measured by Method 

25A of 40 CFR part 60, appendix A, as indicated in paragraph (f)(3) of this section. 

M = Molecular weight of organic compound used to express units of CTOC, gram per gram-mole. 

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: 
Page 30 of 109 

(i) Previous test results provided the tests are representative of current operating practices at the 

process unit. 

(ii) Bench-scale or pilot-scale test data representative of the process under representative 

operating conditions. 

(iii) TOC emission rate specified or implied within a permit limit applicable to the process vent. 

(iv) Design analysis based on accepted chemical engineering principles, measurable process 

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

but are not limited to: 

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

concentrations; 

(B) Estimation of maximum flow rate based on physical equipment design such as pump or 

blower capacities; and 

(C) Estimation of TOC concentrations based on saturation conditions. 

(v) All data, assumptions, and procedures used in the engineering assessment shall be 

documented. 

(h) The owner or operator of a Group 2 process vent shall recalculate the TOC emission rate for 

each process vent, as necessary, whenever process changes are made to determine whether the 

vent is in Group 1 or Group 2. Examples of process changes include, but are not limited to, 

changes in production capacity, production rate, or catalyst type, or whenever there is 

replacement, removal, or addition of recovery equipment. For purposes of this paragraph, 

process changes do not include: process upsets; unintentional, temporary process changes; and 

changes that are within the range on which the original calculation was based. 

(1) The TOC emission rate shall be recalculated based on measurements of vent stream flow rate 

and TOC as specified in paragraphs (e) and (f) of this section, as applicable, or on best 

engineering assessment of the effects of the change. Engineering assessments shall meet the 

specifications in paragraph (g) of this section. 

(2) Where the recalculated TOC emission rate is greater than 33 kilograms per day for an 

existing source or greater than 6.8 kilograms per day for a new source, the owner or operator 

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. 
Page 31 of 109 

§ 63.646 Storage vessel provisions. 

(a) Each owner or operator of a Group 1 storage vessel subject to this subpart shall comply with 

the requirements of §§63.119 through 63.121 except as provided in paragraphs (b) through (l) of 

this section. 

(b) As used in this section, all terms not defined in §63.641 shall have the meaning given them in 

40 CFR part 63, subparts A or G. The Group 1 storage vessel definition presented in §63.641 

shall apply in lieu of the Group 1 storage vessel definitions presented in tables 5 and 6 of 

§63.119 of subpart G of this part. 

(1) An owner or operator may use good engineering judgment or test results to determine the 

stored liquid weight percent total organic HAP for purposes of group determination. Data, 

assumptions, and procedures used in the determination shall be documented. 

(2) When an owner or operator and the Administrator do not agree on whether the annual 

average weight percent organic HAP in the stored liquid is above or below 4 percent for a 

storage vessel at an existing source or above or below 2 percent for a storage vessel at a new 

source, Method 18 of 40 CFR part 60, appendix A shall be used. 

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

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

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

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

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

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

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

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

with §63.640 (h) through (m). 

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

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

subpart. 

(7) All references to §63.126(b)(1) of subpart G shall be replaced with §63.422(b) of subpart R 

of this part. 

(8) All references to §63.128(a) of subpart G shall be replaced with §63.425, paragraphs (a) 

through (c) and (e) through (h) of subpart R of this part. 
Page 32 of 109 

(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 

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. 
Page 33 of 109 

§ 63.647 Wastewater provisions. 

(a) Except as provided in paragraph (b) 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 FF 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) 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. 

(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 
Page 34 of 109 

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)(10) 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. 

(4) The owner or operator shall decide no later than the first monitoring period after the phase III 

compliance date specified in §63.640(h) whether to monitor connectors according to the 

provisions in §63.649, paragraphs (b), (c), or (d). 

(5) Connectors in gas/vapor service or light liquid service are subject to the requirements for 

connectors in heavy liquid service in §63.169 of subpart H of this part (except for the agitator 

provisions). The leak definition for valves, connectors, and instrumentation systems subject to 

§63.169 is 1,000 parts per million. 

(6) In phase III of the pump standard, except as provided in paragraph (c)(7) of this section, 

owners or operators that achieve less than 10 percent of light liquid pumps leaking or three light 

liquid pumps leaking, whichever is greater, shall monitor light liquid pumps monthly. 

(7) Owners or operators that achieve less than 3 percent of light liquid pumps leaking or one 

light liquid pump leaking, whichever is greater, shall monitor light liquid pumps quarterly. 
Page 35 of 109 

(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. 

(d) Upon startup of new sources, the owner or operator shall comply with §63.163(a)(1)(ii) of 

subpart H of this part for light liquid pumps and §63.168(a)(1)(ii) of subpart H of this part for 

gas/vapor and light liquid valves. 

(e) For reciprocating pumps in heavy liquid service and agitators in heavy liquid service, owners 

and operators are not required to comply with the requirements in §63.169 of subpart H of this 

part. 

(f) Reciprocating pumps in light liquid service are exempt from §§63.163 and 60.482 if recasting 

the distance piece or reciprocating pump replacement is required. 

(g) Compressors in hydrogen service are exempt from the requirements of paragraphs (a) and (c) 

of this section if an owner or operator demonstrates that a compressor is in hydrogen service. 

(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. 
Page 36 of 109 

(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. 

§ 63.649 Alternative means of emission limitation: Connectors in gas/vapor service and 

light liquid service. 

(a) If an owner or operator elects to monitor valves according to the provisions of 

§63.648(c)(2)(ii), the owner or operator shall implement one of the connector monitoring 

programs specified in paragraphs (b), (c), or (d) of this section. 

(b) Random 200 connector alternative. The owner or operator shall implement a random 

sampling program for accessible connectors of 2.0 inches nominal diameter or greater. The 

program does not apply to inaccessible or unsafe-to-monitor connectors, as defined in §63.174 of 

subpart H. The sampling program shall be implemented source-wide. 

(1) Within the first 12 months after the phase III compliance date specified in §63.640(h), a 

sample of 200 connectors shall be randomly selected and monitored using Method 21 of 40 CFR 

part 60, appendix A. 

(2) The instrument reading that defines a leak is 1,000 parts per million. 

(3) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 

calendar days after the leak is detected except as provided in paragraph (e) of this section. A first 

attempt at repair shall be made no later than 5 calendar days after the leak is detected. 

(4) If a leak is detected, the connector shall be monitored for leaks within the first 3 months after 

its repair. 

(5) After conducting the initial survey required in paragraph (b)(1) of this section, the owner or 

operator shall conduct subsequent monitoring of connectors at the frequencies specified in 

paragraphs (b)(5)(i) through (b)(5)(iv) of this section. 
Page 37 of 109 

(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. 

(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. 
Page 38 of 109 

(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)(4)(iii) for existing process 

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

(ii) Nonrepairable connectors shall be included in the calculation of percentage leaking 

connectors the first time the connector is identified as leaking and nonrepairable. Otherwise, a 

number of nonrepairable connectors up to a maximum of 1 percent per year of the total number 

of connectors in organic HAP service up to a maximum of 3 percent may be excluded from 

calculation of percentage leaking connectors for subsequent monitoring periods. 

(iii) If the number of nonrepairable connectors exceeds 3 percent of the total number of 

connectors in organic HAP service, the number of nonrepairable connectors exceeding 3 percent 

of the total number shall be included in the calculation of the percentage leaking connectors. 

(7) Physical tagging of the connectors to indicate that they are subject to the monitoring 

provisions is not required. Connectors may be identified by the area or length of pipe and need 

not be individually identified. 
Page 39 of 109 

(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. 

§ 63.650 Gasoline loading rack provisions. 

(a) Except as provided in paragraphs (b) through (c) 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). 
Page 40 of 109 

§ 63.651 Marine tank vessel loading operation provisions. 

(a) Except as provided in paragraphs (b) through (d) 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)(3). 

§ 63.652 Emissions averaging provisions. 

(a) This section applies to owners or operators of existing sources who seek to comply with the 

emission standard in §63.642(g) by using emissions averaging according to §63.642(l) rather 

than following the provisions of §§63.643 through 63.647, 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. 
Page 41 of 109 

(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 

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: 
Page 42 of 109 

(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. 

(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) 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. 
Page 43 of 109 

(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: 

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. 
Page 44 of 109 

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. 

(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: 

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. 
Page 45 of 109 

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. 

(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 EPViuis 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, 

(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 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. 
Page 46 of 109 

(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: 

where: 

EGLRiu = Uncontrolled transfer HAP emission rate from gasoline loading rack i, megagrams per 

month 

S = Saturation factor, dimensionless (see table 33 of subpart G). 

P = Weighted average rack partial pressure of organic HAP’s transferred at the rack during the 

month, kilopascals. 

M = Weighted average molecular weight of organic HAP’s transferred at the gasoline loading 

rack during the month, gram per gram-mole. 

G = Monthly volume of gasoline transferred from gasoline loading rack, liters per month. 

T = Weighted rack bulk liquid loading temperature during the month, degrees kelvin (degrees 

Celsius °C + 273). 

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

weighted average rack partial pressure: 

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 
Page 47 of 109 

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: 

where: 

Mj = Molecular weight of individual organic HAP transferred at the rack, gram per gram-mole. 

G, Gj, and n are as defined in paragraph (g)(4)(ii) of this section. 

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

monthly weighted rack bulk liquid loading temperature: 

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: 

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, 
Page 48 of 109 

(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: 

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, 
Page 49 of 109 

(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: 

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. 
Page 50 of 109 

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. 

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. 
Page 51 of 109 

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. 

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 
Page 52 of 109 

greater than 98 percent emission reduction, EPV1iACTUAL, shall be calculated according to the 

following equation: 

(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, 

(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, 

(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. 
Page 53 of 109 

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

where EPV2iu is calculated according to the procedures and equation for EPViu in paragraphs 

(g)(2)(i) and (g)(2)(ii) of this section. The percentage of reduction shall be calculated according 

to the procedures specified in paragraphs (g)(2)(iii)(B)(1) through (g)(2)(iii)(B)(3) of this 

section. 

(C) If a recovery device was added to a process vent as part of a pollution prevention project 

initiated after November 15, 1990, EPV2iBASE = EPV2iu, where EPV2iu is calculated according to 

paragraph (h)(2)(iii)(A)(3) of this section. 

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

G, except as follows: 

(i) 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). 

(ii) 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). 

(iii) 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). 

(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: 

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

loading racks, EGLR2iACTUAL: 
Page 54 of 109 

(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, 

(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, 

(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, 

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 55 of 109 

(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, 

(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, 

(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, 

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 56 of 109 

(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: 

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 57 of 109 

(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: 

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: 

Where: 
Page 58 of 109 

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: 

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 59 of 109 

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

equation shall be used: 

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: 

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. 

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

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

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

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

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

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

the following procedures: 

(A) Sampling sites shall be selected using Method 1 or 1A of 40 CFR part 60, appendix A, as 

appropriate. 
Page 60 of 109 

(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: 

Where: 

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

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

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

standards conditions, cubic meters per hour. 

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

standards conditions, cubic meters per hour. 

p = Run. 

m = Number of runs. 

Caip = Concentration of organic compound i measured in the vent stream exiting the control 

device during run p as determined by Method 18 of 40 CFR part 60 appendix A, parts per 

million by volume on a dry basis. 
Page 61 of 109 

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: 

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; 

(ii) Description of the control technology including design specifications; 
Page 62 of 109 

(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 63 of 109 

(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. 

Where: 

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

reduction). 
Page 64 of 109 

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: 

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 65 of 109 

(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: 

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 63.647, and 

§§63.650 and 63.651. 

(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 66 of 109 

(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 63.647, and §§63.650 and 63.651. 

(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 63.647, and §§63.650 and 63.651. The 

specific requirements for miscellaneous process vents, storage vessels, wastewater, gasoline 
Page 67 of 109 

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 §63.120 of 

subpart G; and 

(ii) For closed vent systems with control devices, conduct an initial design evaluation as 

specified in §63.646 of this subpart and §63.120(d) of subpart G. 

(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 68 of 109 

(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 63.647 and §§63.650 and 63.651, 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 69 of 109 

(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 70 of 109 

(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 it meets any one of the criteria in paragraphs (b)(1) through (2) of this section.

(1) Aall heat exchangers that are in organic HAP service within the heat exchange system that 

either: 

(1i) Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater 

than the maximum pressure on the process side; or 

(2ii) 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 subpart H of this 
Page 71 of 109 

part andlisted in Ttable 1 ofto this subpart, between the process and the cooling water. This 

intervening fluid must serve to isolate the cooling water from the process fluid and must not be 

sent through a cooling tower or discharged. For purposes of this section, discharge does not 

include emptying for maintenance purposes. 

(2) The heat exchange system cools process fluids that contain less than 5 percent by weight of 

total HAP listed in Table 1 to this subpart (i.e., the heat exchange system does not contain any 

heat exchangers that are in organic HAP service as defined in this subpart).

(c) The owner or operator must perform monthly 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) throughand (62) of this section. 

(1) Monitoring locations for closed-loop recirculation heat exchange systems. For each closed 

loop recirculating heat exchange system, Ccollect and analyze a sample from the location(s) 

described in either paragraph (c)(1)(i) or (c)(1)(ii) of this section. 

(i) eEach cooling tower return line or any representative riser within the cooling tower prior 

to exposure to air for each heat exchange system in organic HAP service or.

(ii) Selectedfrom each heat exchanger exit line(s) so thatfor each heat exchanger or group of 

heat exchangers in organic HAP service within athat 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. to dDetermine the total strippable hydrocarbonVOC concentration (in 

parts per million by volume (ppmv) as methane) at each monitoring locationfrom the air 

stripping testing system using the “Air Stripping Method (Modified El Paso Method) for 

Determination of Volatile Organic Compound Emissions from Water Sources” Revision Number 
Page 72 of 109 

One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower 

Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003 

(incorporated by reference—see §63.14) using a flame ionization detector (FID) analyzer for 

on-site determination as described in Section 6.1 of the Modified El Paso Method. 

(4) Monitoring frequency and leak action level for existing sources. For a heat exchange 

system at an existing source, the owner or operator must comply with the monitoring 

frequency and leak action level as defined in paragraph (c)(4)(i) of this section or comply 

with the monitoring frequency and leak action level as defined in paragraph (c)(4)(ii) of 

this section. The owner or operator of an affected heat exchange system may choose to 

comply with paragraph (c)(4)(i) of this section for some heat exchange systems at the 

petroleum refinery and comply with paragraph (c)(4)(ii) of this section for other heat 

exchange systems. However, for each affected heat exchange system, the owner or operator 

of an affected heat exchange system must elect one monitoring alternative that will apply at 

all times. If the owner or operator intends to change the monitoring alternative that applies 

to a heat exchange system, the owner or operator must notify the Administrator 30 days in 

advance of such a change. All “leaks” identified prior to changing monitoring alternatives 

must be repaired. The monitoring frequencies specified in paragraphs (c)(4)(i) and (ii) of 

this section also apply to the inlet water feed line for a once-through heat exchange system, 

if monitoring of the inlet water feed is elected as provided in paragraph (c)(2)(ii) of this 

section.The owner or operator of a once-through heat exchange system may elect to also monitor 

monthly (in addition to monitoring each heat exchanger exit line) the fresh water feed line prior 

to any heat exchanger to determine the total strippable VOC concentration (as methane) prior to 

the heat exchange system using the Modified El Paso Method.

(i2) For a heat exchange system at an existing source,Monitor monthly using a leak action level 

defined asis a total strippable hydrocarbonVOC concentration (as methane) in the stripping gas 

of 6.2 ppmv or greater. 

(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 

asis a total strippable hydrocarbonVOC concentration (as methane) in the stripping gas of 3.1 

ppmv or greater.

(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 
Page 73 of 109 

location specified in paragraph (c)(2)(ii) of this section equals or exceeds the leak action 

level. 

(ii) For all other heat exchange systems, a leak is detected if a measurement value of the 

sample taken from a location specified in either paragraph (c)(1)(i), (c)(1)(ii), or (c)(2)(i) of 

this section equals or exceeds the leak action level.

(d) If a leak is detected, the owner or operator must repair the leak to reduce the measured 

concentration to below the applicable action level as soon as practicable, but no later than 45 

days after identifying the leak, except as specified in paragraphs (e) and (f) of this section. 

Repair includes re-monitoring at the monitoring location where the leak was identified 

according to the method specified in paragraph (c)(3) of this section to verify that the 

measured concentration is below the applicable action level. Actions that can be taken to 

achieve repair include but are not limited to: 

(1) Physical modifications to the leaking heat exchanger, such as welding the leak or replacing a 

tube; 

(2) Blocking the leaking tube within the heat exchanger; 

(3) Changing the pressure so that water flows into the process fluid; 

(4) Replacing the heat exchanger or heat exchanger bundle; or 

(5) Isolating, bypassing, or otherwise removing the leaking heat exchanger from service until it is 

otherwise repaired. 

(e) If the owner or operator detects a leak when monitoring a cooling tower return line under 

paragraph (c)(1)(i) of this section, the owner or operator may conduct additional monitoring to 

identify leaks of total strippable VOC emissions using Modified El Paso Method from each heat 

exchanger or group of heat exchangers in organic HAP service 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 sectionthe additional monitoring shows that the total strippable VOC 

concentration in the stripped air at the heat exchanger exit line for each heat exchanger in organic 

HAP service is less than 6.2 ppmv for existing sources or less than 3.1 ppmv for new sources, the 

heat exchange system is considered to meet the repair requirements through re-monitoring 

of the heat exchange system as providedexcluded from repair requirements 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 paragraphs (f)(1) orand (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. 
Page 74 of 109 

(1) If the repair is technically infeasible without a shutdown and the total strippable 

hydrocarbonVOC concentration (as methane) is initially and remains less than the delay of 

repair action level62 ppmv 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 

exceededtotal strippable VOC concentration (as methane) is 62 ppmv or greater, 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 level62 ppmv total strippable VOC (as methane), 

except as provided in paragraph (f)(3) of this section. 

(2) If the necessary equipment, parts, or personnel are not available and the total strippable 

hydrocarbonVOC concentration (as methane) is initially and remains less than the delay of 

repair action level62 ppmv 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 exceededtotal 

strippable VOC concentration (as methane) is 62 ppmv or greater, 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 level62 ppmv total strippable VOC (as methane). 

(3) The delay of repair action level is a total strippable hydrocarbon concentration (as 

methane) in the stripping gas of 62 ppmv. The delay of repair action level is assessed as 

described in paragraph (f)(3)(i) or (f)(3)(ii) of this section, as applicable. 

(i) For once-through heat exchange systems for which the inlet water feed is monitored as 

described in paragraph (c)(2)(ii) of this section, the delay of repair action level is exceeded 

if the difference in the measurement value of the sample taken from a location specified in 

paragraph (c)(2)(i) of this section and the measurement value of the corresponding sample 

taken from the location specified in paragraph (c)(2)(ii) of this section equals or exceeds the 

delay of repair action level. 

(ii) For all other heat exchange systems, the delay of repair action level is exceeded if a 

measurement value of the sample taken from a location specified in either paragraphs 

(c)(1)(i), (c)(1)(ii), or (c)(2)(i) of this section equals or exceeds the delay of repair action 

level. 

(g) To delay the repair under paragraph (f) of this section, the owner or operator must record the 

information in paragraphs (g)(1) through (g)(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. 
Page 75 of 109 

(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) throughand (g)(4)(ivi) of this section. 

(i) Determine the leaktotal strippable VOC concentration as specified in paragraph (c) of this 

section and convert the stripping gas leak concentration (in ppmv as methane) to an 

equivalent liquid concentrationin the cooling water, 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 methanebased on the 

total strippable concentration in the stripped air, ppmv, from monitoring. 

(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.Calculate the VOC emissions for the leaking heat exchange 

system or heat exchanger by multiplying the VOC concentration in the cooling water, ppmw, by 

the flow rate of the cooling water from the leaking tower or heat exchanger and by the expected 

duration of the delay.

(iii) For delay of repair monitoring intervals prior to repair of the leak, calculate the 

potential strippable hydrocarbon emissions for the leaking heat exchange system or heat 

exchanger for the monitoring interval by multiplying the leak concentration in the cooling 

water, ppmw, determined in (g)(4)(i) of this section, by the mass flow rate of the cooling 

water determined in (g)(4)(ii) of this section and by the duration of the delay of repair 

monitoring interval. The duration of the delay of repair monitoring interval is the time 

period starting at midnight on the day of the previous monitoring event or at midnight on 

the day the repair would have had to be completed if the repair had not been delayed, 

whichever is later, and ending at midnight of the day the of the current monitoring event. 

(iv) For delay of repair monitoring intervals ending with a repaired leak, calculate the 

potential strippable hydrocarbon emissions for the leaking heat exchange system or heat 

exchanger for the final delay of repair monitoring interval by multiplying the duration of 

the final delay of repair monitoring interval by the leak concentration and cooling water 

flow rates determined for the last monitoring event prior to the re-monitoring event used to 

verify the leak was repaired. The duration of the final delay of repair monitoring interval is 

the time period starting at midnight of the day of the last monitoring event prior to remonitoring to verify the leak was repaired and ending at the time of the re-monitoring 

event that verified that the leak was repaired.
Page 76 of 109 

§ 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. 

(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. 
Page 77 of 109 

(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)(4). 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)(4) shall be submitted 

according to paragraph (f)(6) of this section. This information may be submitted in an operating 

permit application, in an amendment to an operating permit application, in a separate submittal, 

or in any combination of the three. If the required information has been submitted before the date 

150 days after the compliance date specified in §63.640(h), a separate Notification of 

Compliance Status report is not required within 150 days after the compliance dates specified in 

§63.640(h). If an owner or operator submits the information specified in paragraphs (f)(1) 

through (f)(5) of this section at different times, and/or in different submittals, later submittals 

may refer to earlier submittals instead of duplicating and resubmitting the previously submitted 

information. Each owner or operator of a gasoline loading rack classified under Standard 

Industrial Classification Code 2911 located within a contiguous area and under common control 

with a petroleum refinery subject to the standards of this subpart shall submit the Notification of 

Compliance Status report required by subpart R of this part within 150 days after the compliance 

dates specified in §63.640(h) of this subpart. 

(1) The Notification of Compliance Status report shall include the information specified in 

paragraphs (f)(1)(i) through (f)(1)(vi) of this section. 
Page 78 of 109 

(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)(4) 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)(4) 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)(4) 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 

the owner or operator shall submit: 

(1) A description of the parameter or parameters to be monitored to ensure that the control device 

is being properly operated and maintained, an explanation of the criteria used for selection of that 

parameter (or parameters), and the frequency with which monitoring will be performed; and 

either 

(2) The design evaluation documentation specified in §63.120(d)(1)(i) of subpart G, 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 
Page 79 of 109 

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 part; and 

(3) All periods during the compliance determination when the pilot flame is absent. 

(ii) For miscellaneous process vents, identification of each miscellaneous process vent subject to 

this subpart, whether the process vent is Group 1 or Group 2, and the method of compliance for 

each Group 1 miscellaneous process vent that is not included in an emissions average (e.g., use 

of a flare or other control device meeting the requirements of §63.643(a)). 

(iii) For miscellaneous process vents controlled by control devices required to be tested under 

§63.645 of this subpart and §63.116(c) of subpart G of this part, performance test results 

including the information in paragraphs (f)(1)(iii)(A) and (B) of this section. Results of a 

performance test conducted prior to the compliance date of this subpart can be used provided that 

the test was conducted using the methods specified in §63.645 and that the test conditions are 

representative of current operating conditions. 

(A) The percentage of reduction of organic HAP’s or TOC, or the outlet concentration of organic 

HAP’s or TOC (parts per million by volume on a dry basis corrected to 3 percent oxygen), 

determined as specified in §63.116(c) of subpart G of this part; and 

(B) The value of the monitored parameters specified in table 10 of this subpart, or a 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, performance 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, 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 
Page 80 of 109 

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).

(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. 

(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 part 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. 
Page 81 of 109 

(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. 

(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)(4) 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 exceptions 

specified in paragraphs (g)(1) through (6) of this section or paragraph (g)(9) of this section occur. 

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 exceptions 

identified in paragraph (g)(1) through (6) of this section or paragraph (g)(9) 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 (9) of this section. 

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

Reports in paragraph (g)(2) through (g)(5) of this section except that information related to 

gaskets, slotted membranes, and sleeve seals is not required for storage vessels that are part of an 

existing source. 
Page 82 of 109 

(2) 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. 

(i) 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) 

through (g)(2)(i)(C) of this section apply. 

(A) A failure is defined as any time in which the internal floating roof is not resting on the 

surface of the liquid inside the storage vessel and is not resting on the leg supports; or there is 

liquid on the floating roof; or the seal is detached from the internal floating roof; or there are 

holes, tears, or other openings in the seal or seal fabric; or there are visible gaps between the seal 

and the wall of the storage vessel. 

(B) Except as provided in paragraph (g)(2)(i)(C) of this section, each Periodic Report shall 

include the date of the inspection, identification of each storage vessel in which a failure was 

detected, and a description of the failure. The Periodic Report shall also describe the nature of 

and date the repair was made or the date the storage vessel was emptied. 

(C) 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. 

(ii) 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)(A) and (g)(2)(ii)(B) of this section apply. 

(A) 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. 

(B) 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) An owner or operator who elects to comply with §63.646 by using an external floating roof 

shall meet the periodic reporting requirements specified in paragraphs (g)(3)(i) through (g)(3)(iii) 

of this section. 

(i) 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 
Page 83 of 109 

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) through (g)(3)(i)(D) of this section. 

(A) The date of the seal gap measurement. 

(B) 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. 

(C) 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. 

(D) A description of the nature of and date the repair was made, or the date the storage vessel 

was emptied. 

(ii) 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. 

(iii) 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)(A) and (g)(3)(iii)(B) of this section. 

(A) A failure is defined as any time in which the external floating roof has defects; or the 

primary seal has holes or other openings in the seal or the seal fabric; or the secondary seal has 

holes, tears, or other openings in the seal or the seal fabric; or, for a storage vessel that is part of 

a new source, the gaskets no longer close off the liquid surface from the atmosphere; or, for a 

storage vessel that is part of a new source, the slotted membrane has more than 10 percent open 

area. 

(B) 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. 

(4) An owner or operator who elects to comply with §63.646 by using an external floating roof 

converted to an internal floating roof shall comply with the periodic reporting requirements of 

paragraph (g)(2) of this section. 

(5) An owner or operator who elects to comply with §63.646 by installing a closed vent system 

and control device shall submit, as part of the next Periodic Report, the information specified in 

paragraphs (g)(5)(i) through (g)(5)(iii) of this section. 

(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 
Page 84 of 109 

the control device not to meet the requirements of §63.119(e)(1) or (e)(2) of subpart G of this 

part, 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 §63.119 (e)(1) or (e)(2) of subpart G of this part, 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, 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. 

(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. 
Page 85 of 109 

(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) 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 

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 percentage of emissions reduction or outlet 

pollutant concentration reduction (whichever is needed to determine compliance) 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; 
Page 86 of 109 

(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: 

(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 §63.654in HAP service. 

(ii) The number of heat exchange systems at the plant sitein HAP service found to be leaking. 

(iii) For each monitoring location where the total strippable hydrocarbon concentration 

wasA summary of the monitoring data that indicate a leak, including the number of leaks

determined to be equal to or greater than the applicable leak definitions specified in 

§63.654(c)(62), identification of the monitoring location (e.g., unique monitoring location or 

heat exchange system ID number), the measured total strippable hydrocarbon 

concentration,;

(iv) If applicable, the date thea 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) ForIf applicable, a summary of each delayed repair, including identification of the 

monitoring location associated with the leak for which repair is delayed, the original date 

when the delay of repair began,and reason for the delay and the date of 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
Page 87 of 109 

(vi) If applicable, an estimate of the potential strippable hydrocarbonVOC emissions for each 

delayed repair over the reporting period associated with the delayed repair. 

(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 

(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. 

(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 part 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 of this 
Page 88 of 109 

part. 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 

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 
Page 89 of 109 

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

previously recorded values. 

(A) The requested system shall be designed to: 

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

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

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

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

the operator, and record the incident. 

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

(B) The request shall contain a description of the monitoring system and data compression 

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

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

meets all criteria of paragraph (h)(5)(iii)(A) of this section. 

(iv) An owner or operator may request approval to use other alternative monitoring systems 

according to the procedures specified in §63.8(f) of subpart A of this part. 

(6) The owner or operator shall submit the information specified in paragraphs (h)(6)(i) through 

(h)(6)(iii) of this section, as applicable. For existing sources, this information shall be submitted 

in the initial Notification of Compliance Status report. For a new source, the information shall be 

submitted with the application for approval of construction or reconstruction required by 

§63.5(d) of subpart A of this part. The information may be submitted in an operating permit 

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

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

designed and operated as flexible operation units. 

(ii) The determination of applicability of this subpart to any storage vessel for which use varies 

from year to year. 

(iii) The determination of applicability of this subpart to any distillation unit for which use varies 

from year to year.

(7) The owner or operator of a heat exchange system at an existing source must notify the 

Administrator at least 30 calendar days prior to changing from one of the monitoring 

options specified in §63.654(c)(4) to the other.
Page 90 of 109 

(i) Recordkeeping. (1) Each owner or operator subject to the storage vessel provisions in §63.646 

shall keep the records specified in §63.123 of subpart G of this part except as specified in 

paragraphs (i)(1)(i) through (i)(1)(iv) of this section. 

(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. 

(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. 
Page 91 of 109 

(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) The owner or operator of a heat exchange system subject to this subpartthe monitoring 

requirements in §63.654 shall comply with the recordkeeping requirements in paragraphs 

(i)(4)(i) through (vi) 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)that are in organic HAP 

service. For each heat exchange system that is subject to the monitoring requirements in 

§63.654this subpart, this must include identification of all heat exchangers within each heat 

exchange system, identification of the individual heat exchangers in organic HAP service 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 requiredmonthly monitoring event: 

(A) Date/time of event. 

(B) Barometric pressure. 

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

and air temperature, °Celsius. 

(D) FID reading (ppmv). 

(E) Length of sampling periodHeat exchange exit line flow or cooling tower return line flow at 

the El Paso monitoring location, gal/min. 
Page 92 of 109 

(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—seein §63.14(n). 

(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. 

(vi) 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. 

(5) All other information required to be reported under paragraphs (a) through (h) of this section 

shall be retained for 5 years. 

§ 63.656 Implementation and enforcement. 

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

such as the applicable State, local, or Tribal agency. If the U.S. EPA Administrator has delegated 

authority to a State, local, or Tribal agency, then that agency, in addition to the U.S. EPA, has the 

authority to implement and enforce this subpart. Contact the applicable U.S. EPA Regional 

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

or Tribal agency. 

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

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

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

local, or Tribal agency. 

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

paragraphs (c)(1) through (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, and 63.654. Where these standards reference another subpart, the cited 

provisions will be delegated according to the delegation provisions of the referenced subpart. 

Where these standards reference another subpart and modify the requirements, the requirements 

shall be modified as described in this subpart. Delegation of the modified requirements will also 

occur according to the delegation provisions of the referenced subpart. 

(2) Approval of major alternatives to test methods under §63.7(e)(2)(ii) and (f), as defined in 

§63.90, and as required in this subpart. 
Page 93 of 109 

(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. 

§§ 63.657-63.679 [Reserved] 

Appendix to Subpart CC of Part 63—Tables 

Table 1—Hazardous Air Pollutants 

Chemical name CAS No.a

Benzene 71432

Biphenyl 92524

Butadiene (1,3) 106990

Carbon disulfide 75150

Carbonyl sulfide 463581

Cresol (mixed isomersb) 1319773

Cresol (m-) 108394

Cresol (o-) 95487

Cresol (p-) 106445

Cumene 98828

Dibromoethane (1,2) (ethylene dibromide) 106934

Dichloroethane (1,2) 107062

Diethanolamine 111422

Ethylbenzene 100414

Ethylene glycol 107211

Hexane 110543

Methanol 67561

Methyl isobutyl ketone (hexone) 108101

Methyl tert butyl ether 1634044

Naphthalene 91203

Phenol 108952

Toluene 108883

Trimethylpentane (2,2,4) 540841

Xylene (mixed isomersb) 1330207

xylene (m-) 108383

xylene (o-) 95476

xylene (p-) 106423

a

CAS number = Chemical Abstract Service registry number assigned to specific compounds, 

isomers, or mixtures of compounds. 
Page 94 of 109 

b

Isomer means all structural arrangements for the same number of atoms of each element and 

does not mean salts, esters, or derivatives. 

Table 2—Leak Definitions for Pumps and Valves 

Standarda

 Phase Leak definition (parts per million) 

§63.163 (pumps) I 10,000

 II 5,000

 III 2,000

§63.168 (valves) I 10,000

 II 1,000

 III 1,000

a

Subpart H of this part. 
Page 95 of 109 

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). 

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. 
Page 96 of 109 

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. 
Page 97 of 109 

Table 5—Marine Vessel Loading Operations Recordkeeping and Reporting Requirementsa

Reference 

(section of 

subpart Y) Description Comment 

63.562(e)(2) Operation and maintenance 

plan for control equipment and 

monitoring equipment 

63.565(a) Performance test/site test plan The information required under this 

paragraph is to be submitted with the 

Notification of Compliance Status report 

required under 40 CFR part 63, subpart 

CC. 

63.565(b) Performance test data 

requirements 

63.567(a) General Provisions (subpart A) 

applicability 

63.567(c) Request for extension of 

compliance 

63.567(d) Flare recordkeeping 

requirements 

63.567(e) Summary report and excess 

emissions and monitoring 

system performance report 

requirements 

The information required under this 

paragraph is to be submitted with the 

Periodic Report required under 40 CFR 

part 63, subpart CC. 

63.567(f) Vapor collection system 

engineering report 

63.567(g) Vent system valve bypass 

recordkeeping requirements 

63.567(h) Marine vessel vapor-tightness 

documentation 

63.567(i) Documentation file 

maintenance 

63.567(j) Emission estimation reporting 

and recordkeeping procedures 

a

This table does not include all the requirements delineated under the referenced sections. See 

referenced sections for specific requirements. 
Page 98 of 109 

Table 6—General Provisions Applicability to Subpart CCa

Reference 

Applies to 

subpart CC Comment 

63.1(a)(1) Yes 

63.1(a)(2) Yes 

63.1(a)(3) Yes 

63.1(a)(4) Yes 

63.1(a)(5) No Reserved. 

63.1(a)(6) Yes Except the correct mail drop (MD) number is C404–04. 

63.1(a)(7)–

63.1(a)(9) 

No Reserved. 

63.1(a)(10) Yes 

63.1(a)(11) Yes 

63.1(a)(12) Yes 

63.1(b)(1) Yes 

63.1(b)(2) No Reserved. 

63.1(b)(3) No 

63.1(c)(1) Yes 

63.1(c)(2) No Area sources are not subject to subpart CC. 

63.1(c)(3)–

63.1(c)(4) 

No Reserved. 

63.1(c)(5) Yes Except that sources are not required to submit notifications 

overridden by this table. 

63.1(d) No Reserved. 

63.1(e) No No CAA section 112(j) standard applies to the affected 

sources under subpart CC. 

63.2 Yes §63.641 of subpart CC specifies that if the same term is 

defined in subparts A and CC, it shall have the meaning given 

in subpart CC. 

63.3 Yes 

63.4(a)(1)–

63.4(a)(2) 

Yes 

63.4(a)(3)–

63.4(a)(5) 

No Reserved. 

63.4(b) Yes 

63.4(c) Yes 

63.5(a) Yes 

63.5(b)(1) Yes 

63.5(b)(2) No Reserved. 

63.5(b)(3) Yes 

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 
Page 99 of 109 

Reference 

Applies to 

subpart CC Comment 

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. 

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 

63.6(a) Yes 

63.6(b)(1)–

63.6(b)(5) 

No Subpart CC specifies compliance dates and notifications for 

sources subject to subpart CC. 

63.6(b)(6) No Reserved. 

63.6(b)(7) Yes 

63.6(c)(1)–

63.6(c)(2) 

No §63.640 of subpart CC specifies the compliance date. 

63.6(c)(3)–

63.6(c)(4) 

No Reserved. 

63.6(c)(5) Yes 

63.6(d) No Reserved. 

63.6(e)(1) Yes 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)(2) No Reserved. 

63.6(e)(3)(i) Yes 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) 

Yes 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) Yes Except for the heat exchange system standards, which apply 

at all times. 
Page 100 of 109 

Reference 

Applies to 

subpart CC Comment 

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(g) Yes 

63.6(h)(1) and 

63.6(h)(2) 

Yes Except §63.6(h)(2)(ii), which is reserved. 

63.6(h)(3) No Reserved. 

63.6(h)(4) No Notification of visible emission test not required in subpart 

CC. 

63.6(h)(5) No Visible emission requirements and timing is specified in 

§63.645(i) of subpart CC. 

63.6(h)(6) Yes 

63.6(h)(7) No Subpart CC does not require opacity standards. 

63.6(h)(8) Yes 

63.6(h)(9) No Subpart CC does not require opacity standards. 

63.6(i) Yes Except for §63.6(i)(15), which is reserved. 

63.6(j) Yes 

63.7(a)(1) Yes 

63.7(a)(2) Yes Except test results must be submitted in the Notification of 

Compliance Status report due 150 days after compliance date, 

as specified in §63.655(f) of subpart CC. 

63.7(a)(3) Yes 

63.7(a)(4) Yes 

63.7(b) No 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) Yes Except the performance test must be conducted at the 

maximum representative capacity as specified in 

§63.642(d)(3) of subpart CC. 

63.7(e)(2)–

63.7(e)(4) 

Yes 

63.7(f) No Subpart CC specifies applicable methods and provides 

alternatives without additional notification or approval. 

63.7(g) No Performance test reporting specified in §63.655(f). 

63.7(h)(1) Yes 

63.7(h)(2) Yes 

63.7(h)(3) Yes Yes, except site-specific test plans shall not be required, and 

where §63.7(g)(3) specifies submittal by the date the sitespecific test plan is due, the date shall be 90 days prior to the 

Notification of Compliance Status report in §63.655(f). 

63.7(h)(4)(i) Yes 
Page 101 of 109 

Reference 

Applies to 

subpart CC Comment 

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) Yes Except §63.8(a)(3), which is reserved. 

63.8(b) Yes 

63.8(c)(1) Yes 

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 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 

63.8(d) No 

63.8(e) No 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). 

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). 
Page 102 of 109 

Reference 

Applies to 

subpart CC Comment 

63.9(b)(2) No A separate Initial Notification report is not required under 

subpart CC. 

63.9(b)(3) No Reserved. 

63.9(b)(4) Yes Except for subparagraphs §63.9(b)(4)(ii) through (iv), which 

are reserved. 

63.9(b)(5) Yes 

63.9(c) Yes 

63.9(d) Yes 

63.9(e) No Subpart CC requires notification of performance test at least 

30 days (rather than 60 days) prior to the performance test and 

does not require a site-specific test plan. 

63.9(f) No Subpart CC does not require advanced notification of visible 

emissions test. 

63.9(g) No 

63.9(h) No Subpart CC §63.655(f) specifies Notification of Compliance 

Status report requirements. 

63.9(i) Yes 

63.9(j) No 

63.10(a) Yes 

63.10(b)(1) No §63.655(i) of subpart CC specifies record retention 

requirements. 

63.10(b)(2)(i) Yes 

63.10(b)(2)(ii) Yes 

63.10(b)(2)(iii) No 

63.10(b)(2)(iv) Yes 

63.10(b)(2)(v) Yes 

63.10(b)(2)(vi) Yes 

63.10(b)(2)(vii) No 

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)–

63.10(c)(15) 

No 
Page 103 of 109 

Reference 

Applies to 

subpart CC Comment 

63.10(d)(1) Yes 

63.10(d)(2) No §63.655(f) of subpart CC specifies performance test reporting. 

63.10(d)(3) No Results of visible emissions test are included in Compliance 

Status Report as specified in §63.655(f). 

63.10(d)(4) Yes 

63.10(d)(5)(i) Yesb 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. 

63.10(d)(5)(ii) Yes Except that actions taken during a startup, shutdown, or 

malfunction that are not consistent with the startup, shutdown, 

and malfunction plan and that cause the source to exceed any 

applicable emission limitation do not need to be reported 

within 2 and 7 days of commencing and completing the 

action, respectively, but must be included in the next periodic 

report. 

63.10(e) No 

63.10(f) Yes 

63.11–63.16 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. 
Page 104 of 109 

Table 7—Fraction Measured (FM), Fraction Emitted (FE), and Fraction Removed (FR) for 

HAP Compounds in Wastewater Streams 

Chemical name CAS No.a Fm Fe Fr 

Benzene 71432 1.00 0.80 0.99

Biphenyl 92524 0.86 0.45 0.99

Butadiene (1,3) 106990 1.00 0.98 0.99

Carbon disulfide 75150 1.00 0.92 0.99

Cumene 98828 1.00 0.88 0.99

Dichloroethane (1,2-) (Ethylene dichloride) 107062 1.00 0.64 0.99

Ethylbenzene 100414 1.00 0.83 0.99

Hexane 110543 1.00 1.00 0.99

Methanol 67561 0.85 0.17 0.31

Methyl isobutyl ketone (hexone) 108101 0.98 0.53 0.99

Methyl tert butyl ether 1634044 1.00 0.57 0.99

Naphthalene 91203 0.99 0.51 0.99

Trimethylpentane (2,2,4) 540841 1.00 1.00 0.99

xylene (m-) 108383 1.00 0.82 0.99

xylene (o-) 95476 1.00 0.79 0.99

xylene (p-) 106423 1.00 0.82 0.99

a

CAS numbers refer to the Chemical Abstracts Service registry number assigned to specific 

compounds, isomers, or mixtures of compounds. 

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. 
Page 105 of 109 

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 106 of 109 

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

. 
Page 107 of 109 

Control device Parameters to be monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

 5. Report all daily average 

temperature differences across the 

catalyst bed that are outside the 

range established in the NCS or 

operating permit—PRg. 

 6. Report all operating days when 

insufficient monitoring data are 

collectedf

. 

Boiler or process 

heater with a design 

heat capacity less than 

44 megawatts where 

the vent stream is not

introduced into the 

flame zoneh,i

Firebox 

temperatureb

(63.644(a)(4)) 

1. Continuous recordsc. 

 2. Record and report the firebox 

temperature averaged over the 

full period of the performance 

test—NCSd. 

 3. Record the daily average 

firebox temperature for each 

operating daye

. 

 4. Report all daily average 

firebox temperatures that are 

outside the range established in 

the NCS or operating permit and 

all operating days when 

insufficient monitoring data are 

collectedf

—PRg. 

Flare 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. 
Page 108 of 109 

Control device Parameters to be monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

 4. Report the times and durations 

of all periods when all pilot 

flames for a flare are absent or the 

monitor is not operating. 

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 109 of 109 

i

Process vents that are routed to refinery fuel gas systems are not regulated under this subpart. No 

monitoring, recordkeeping, or reporting is required for boilers and process heaters that combust 

refinery fuel gas.