September 2015

R edline of 40 CFR part 63, subpart C C , 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 Hazardo us Air Pollutants From Petroleum Refineries § 63.640 Applicability and designation of affected source. (a) This subpart applies to petroleum refining pr ocess units and to relate d emissions points that are specified in paragraphs (c)(1) through ( 8 9 ) of this section that are located at a plant site and that meet the criteria in paragra phs (a)(1) and (2) of this section: (1) Are located at a plant site th at is a major source as defined in section 112(a) of the Clean Air Act; and (2) Emit or have equipment containing or contac ting 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 secti on, is as a petroleum refining proce ss unit, as defined in §63.641, then the flexible operation unit sha ll be subject to the prov isions 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 great est annual ope rating 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 producti on on a mass basis. (2) The determination of applicability of this su bpart to petroleum refini ng process units that are designed and operated as flexible operation units shall be reported as specified in §63.655(h)(6)(i). (c) For the purposes of this subpart, the affected source shall comprise all emissions points, in combination, listed in paragraphs (c)(1) through (c)( 8 9 ) of this section that are located at a single refinery plant site.Page 2 of 175

(1) All miscellaneous process vents from petroleu m 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 operati ons associated with petroleum refining process units meeting the criteria in paragraph (a) of this section; (4) All equipment leaks from petroleum refining pr ocess units meeting the criteria in paragraph (a) of this section; (5) All gasoline loading racks classified under Standard Indus trial Classification code 2911 meeting the criteria in para graph (a) of this section; (6) All marine vessel loading operations located at a pe troleum refinery meeting the criteria in paragraph (a) of this section and the app licability criteria of subpart Y, §63.560; (7) All storage vessels and equipment leaks associ ated with a bulk gasoline terminal or pipeline breakout station classified under Standard Industrial Classificati on code 2911 located within a contiguous area and under common control with a refi nery meeting the criteria in paragraph (a) of this section; and (8) All heat exchange systems, as defined in this subpart. (9) All releases associated with the decoking operations of a delayed co king unit, as defined in this subpart. (d) The affected source subject to this subpart does not incl ude 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 de vice, sampling connection system, open-ended valve or line, valve, or instru mentation system that is intended to operate in organic hazardous air pollutant service, as defi ned in §63.641 of this subpart, fo r less than 300 hours during the calendar year; (4) Catalytic cracking unit and catalytic reformer catalyst regeneration ve nts, and sulfur plant vents; and (5) Emission points routed to a fuel gas system, as defined in §63.641 of this subpart , provided that on and after [insert date 3 years and 60 days after date of pub lication in the Federal Register], any flares receiving gas from that fuel gas system are subject to §63.670 . NoPage 3 of 175

other testing, monitoring, recordkeeping, or reporting is required for refinery fuel gas systems or emission points routed to refinery fuel gas systems. (e) The owner or operator of a storage vessel constructed on or before August 18, 1994, shall follow the procedures specified in paragraphs (e )(1) and (e)(2) of this section to determine whether a storage vessel is part of a source to which this subpart applie s. 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 de termine 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 petrol eum refining process unit subject to this subpart, then the storage vessel is part of the affected sour ce to which this subpart applies. (ii) If the process unit is not s ubject to this subpart, then the st orage vessel is not part of the affected source to which this subpart applies. (2) If a storage vessel is not dedi cated to a single process unit, then the applicability of this subpart shall be determined according to the provis ions in paragraphs (e)(2)(i) through (e)(2)(iii) of this section. (i) If a storage vessel is shared among proce ss 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 partof 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 ve ssel 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 fr om the storage vessel at the same plant site. (ii) If a storage vessel is shared among process un its so that there is no single predominant use, and at least one of those process units is a petroleum refining pro cess 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 petroleu m 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 ut ilization of that storage vessel during the year preceding August 18, 1995. This determination shall be reported as specified in §63.655(h)(6)(ii).Page 4 of 175

(f) The owner or operator of a distillation unit constructed on or before August 18, 1994, shall follow the procedures specified in paragraphs (f )(1) through (f)(4) of this section to determine whether a miscellaneous process vent from a distillation unit is part of a source to which this subpart applies. The owner or operator of a distillation unit constr ucted after August 18, 1994, shall follow the procedures specified in para graphs (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 di stillation 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 un its 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 un it subject to this subpa rt, the distillation unit shall be assigned to the petroleum refining process unit that is subj ect to this subpart. If more than one petroleum refining process unit is subject to this subpart, the owner or oper ator 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 a nd the vent stream contains gr eater 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 di stillation unit varies from year to year, then the applicability of this subpart shall be determined based on the ut ilization of that distilla tion 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 subpa rt 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 h azardous air pollutants listed in table 1 of this subpart that is located within a petroleum refining process unit th at is subject to this subpart; (3) Units processing natural gas liquids; (4) Units that are used specifically for recycling discarded oil;Page 5 of 175

(5) Shale oil extraction units; (6) Ethylene processes; and (7) Process units and emission po ints 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 Sources subject to this subpart are required to achieve compliance on or before the dates specified in table 11 of this subpart, except as provided in paragraphs (h)(1) through ( h)(6 3 ) of this section. (1) Except as provided in paragr aphs (h)(1)(i) and (ii) of th is section, new sources that commence construction or recons truction after July 14, 1994, shall be in compliance with this subpart upon initial startup or August 18, 1995, whiche ver is later. (i) At new sources that commence construction or reconstruction after July 14, 1994, but on or before September 4, 2007, heat exchange systems sh all be in compliance w ith the existing source requirements for heat exchange systems specified in §63.654 no later than October 29, 2012. (ii) At new sources that comm ence construction or reconstructi on after September 4, 2007, heat exchange systems shall be in compliance w ith the new source requirements in §63.654 upon initial startup or October 28, 2009, whichever is later. (2) Except as provided in paragrap hs (h)(3) through (h)(6) of this section, existing sources shall be in compliance with this subpart no la ter than August 18, 1998, except as provided in §63.6(c)(5) of subpart A of this part, or unl ess an extension has been granted by the Administrator as provided in §63.6( i) of subpart A of this part. (3 (1 ) Marine tank vessels at existing sources shall be in compliance with this subpart , except for §§63.657 through 63.660, no later than August 18, 1999 , unless the vessels are included in an emissions average to generate emission credits. Ma rine tank vessels used to generate credits in an emissions average shall be in compliance with this s ubpart no later than August 18, 1998 unless an extension has been granted by the Administrator as provided in §63.6(i). ( 4 2 ) Existing Group 1 floating roof storage vessels meeting the applicability criteria in item 1 of the definition of Group 1 storage vessel shall be in compliance with §63.646 of this subpart at the first degassing and cleaning activity after August 18, 1998, or A ugust 18, 2005, whichever is first. ( 5 3 ) An owner or operator may elect to comply with the provisions of §63.648 (c) through (i) as an alternative to th e provisions of §63.648 (a) and (b). In such cases, the owner or op erator shall comply no later than the dates specified in paragraphs (h)( 5 3 )(i) through (h)( 5 3 )(iii) of this section. (i) Phase I (see table 2 of this subpart), beginning on August 18, 1998; (ii) Phase II (see table 2 of this subpart ), beginning no later than August 18, 1999; andPage 6 of 175

(iii) Phase III (see table 2 of this subpart), beginning no later than February 18, 2001. (6) Heat exchange systems at an existing source shall be in compliance with the existing source standards in §63.654 no late r than October 29, 2012. (i) If an additional petroleum refi ning process unit is added to a plan t site that is a major source as defined in section 112(a) of the Clean Ai r Act, the addition shall be subject to the requirements for a new source if itmeets the criteria specified in paragraphs (i)(1) through (i)(3) of this section: (1) It is an addition that meet s 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 subj ect 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 co mmenced 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 an d the addition or change is dete rmined to be subject to the new source requirements according to paragraphs (i) or (j) of this section it must comply with the requirements specified in paragraphs (k)(1) and (k)(2) of this section: (1) The reconstructed source, addition, or change shall be in compliance with the new source requirements in item (1), (2), or (3) of table 11 of this subpart, as applicable, upon initial startup of the reconstructed source or by August 18, 1995, whichever is later; and (2) The owner or operator of the reconstructed so urce, addition, or change shall comply with the reporting and recordkeeping requirements that ar e applicable to new sources. The applicable reports include, but are not limited to: (i) The application for approval of construction or reconstruction shall be submitted as soon as practical before the construction or reconstruction is planned to commence (but it need not be sooner than November 16, 1995); (ii) The Notification of Compliance Status report as required by §63.655(f) for a new source, addition, or change;Page 7 of 175

(iii) Periodic Reports and other repor ts 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 subp art H are summarized in ta ble 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) th rough (h)(3), and (k) of subpart R. These requirements are summa rized 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 refi ning process unit is added to a pl ant site or if a miscellaneous process vent, storage vessel, gasoline loadi ng rack, marine tank ve ssel loading operation, or heat exchange system , or decoking operation that meets the criteria inparagraphs (c)(1) through ( 8 9 ) of this section is added to an existing petroleum refinery or if another deliberate operational process change creating an additional Group 1 em issions point(s) (as defined in §63.641) is made to an existing petroleum refining pr ocess unit, and if the addition or process change is not subject to the new source requirements as determined accord ing to paragraphs (i) or (j) of this section, the requirements in paragraphs (l)(1) through ( 3 4 ) of this section sha ll apply. Examples of process changes include, but are not limited to, changes in produc tion capacity, or feed or raw material where the change requi res construction or physical alte ration of the existing equipment or catalyst type, or whenever there is replacemen t, 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 emi ssion point(s) within the added or changed petroleum refining process unit are subject to the requireme nts for an existing source. (2) The added emission point(s) and any emi ssion point(s) within the added or changed petroleum refining process unit shall be in compliance with the applicable requirements in item (4) of table 11 of this subpart by the dates specified in paragraphs (l)(2)(i) or (l)(2)(ii) of this section , as applicable

. (i) If a petroleum refining process unit is added to a plant site or an emission point(s) is added to any existing petroleum refining process unit, the added emission point(s) shall be in compliance upon initial startup of any added petroleum re fining process unit or emission point(s) or by August 18, 1998 the applicable compliance date in it em (4) of table 11 of this subpart , whichever is later. (ii) If a deliberate operational process change to an existing petroleum refining process unit causes a Group 2 emission point to become a Gr oup 1 emission point (as defined in §63.641), the owner or operator shall be in compliance upon initial startup or by A ugust 18, 1998, whichever isPage 8 of 175

later, unless the owner or opera tor 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 opera tor 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 str eam, gasoline loading rack, marine tank vessel loading operation, or heat exchange system , or decoking operation meeting the criteria in paragraphs (c)(1) through ( 8 9 ) of this section that is added to a plant site and is subject to the requirements for existing sources shall comp ly with the reporting and recordkeeping requirements that are applicable to existing s ources 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 shal l be subject to the reporting requirements for existing sources including, but not limited to, the reports listed in paragraphs (l)(3)(i) th rough (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 a dded or changed; (ii) Periodic Reports and other repor ts as required by §63.655(g) and (h); (iii) Reports and notifications requir ed by sections of subpart A of th is 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 summari zed 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) th rough (h)(3), and (k) of subpart R. These requirements are summa rized 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 de vices, 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 fo r existing sources in §63.648. A notification of compliance status report shall not be required for such added equipment. (m) If a change that does not meet the criteria in paragraph (l) of this section is made to a petroleum refining process unit subject to this subpart, and the change causes a Group 2 emission point to become a Group 1 emission point (as de fined in §63.641), then the owner or operator shall comply with the applicable requirements of this s ubpart for existing sources , as specified in item (4) of table 11 of this subpart, for the Group 1 emission point as expeditiously as practicable, but in no event la ter than 3 years after the emission point becomes Group 1.Page 9 of 175

(1) The owner or operator shall submit to the Administrator for approval a compliance schedule, along with a justification for the schedule. (2) The compliance schedule shall be submitted within 180 days after the change is made, unless the compliance schedule has been previously su bmitted 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 sour ce. 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 sc hedule and justification. Approval is automatic if not received from the Administrator within 120 calendar days of receipt. (n) Overlap of subpart CC with othe r regulations for storage vessels. As applicable, paragraphs (n)(1), (n)(3), (n)(4), (n)(6), and (n)(7) of th is section apply for Gro up 2 storage vessels and paragraphs (n)(2) and (n)(5) of this s ection apply for Group 1 storage vessels. (1) After the compliance dates specified in paragraph (h) of this section, a Group 1 or Group 2 storage vessel that is part of an existing source and is also subject to the provisions of 40 CFR part 60, subpart Kb , is required to comply only with the requirements of 40 CFR part 60, subpart Kb, except as provided in para graph (n)(8) of this section. (2) After the compliance dates specified in paragr aph (h) of this secti on a Group 1 storage vessel that is part of a new source and is subject to 40 CFR part 60, subpa rt Kb is required to comply only with this subpart. (3) After the compliance dates specified in paragr aph (h) of this secti on, a Group 2 storage vessel that is part of a new source and is subject to the control requirements in §60.112b provisions of 40 CFR part 60 61 , subpart Kb Y is required to comply only with the requirements of 40 CFR part 60 61 , subpart Kb Y, except as provided in paragraph (n)( 8 10 ) of this section. (4 (2) After the compliance dates specified in paragraph (h) of this section, a Group 1 storage vessel that is also subj ect to 40 CFR part 60, subpart Kb is required to comply only with either 40 CFR part 60, subpart Kb, except as provided in paragraph (n)(8) of this section; or this subpart. After the complian ce dates specified in paragraph (h) of this section, a Group 1 storage vessel that is al so subject to 40 CFR part 61, subpart Y is required to comply only with either 40 CFR part 61, subpart Y, except as provided in paragraph (n)(10) of this section; or this subpart. (3 ) After the compliance dates specified in paragr aph (h) of this secti on, a Group 2 storage vessel that is part of a new source and is subject to 40 CFR 60.110b, but is not required to apply controls by 40 CFR 60.110b or 60.112b , is required to comply only with this subpart.Page 10 of 175

(4) After the compliance dates specified in par agraph (h) of this section, a Group 2 storage vessel that is part of a new source and is subject to 40 CFR 61.270, but is not required to apply controls by 40 CFR 61.271, is required to comply only with this subpart. (5) After the compliance dates specified in paragraph (h) of this section , a Group 1 storage vessel that is also subject to the pr ovisions of 40 CFR part 60, subparts K or Ka is required to only comply with the provis ions of this subpart. (6) After compliance dates specif ied in paragraph (h) of this section, a Group 2 storage vessel that is subject to the control requirements of 40 CFR part 60, subpa rts 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 paragr aph (h) of this secti on, 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 requir ed to comply only with this subpart. (8) Storage vessels described by paragraph s (n)(1 ) and (n)(3 ) of this section are to comply with 40 CFR part 60, subpart Kb except as provided for in paragraphs (n)(8)(i) through (n)(8)(vi) of this section. Storage vessels described by par agraph (n)(2) electing to comply with part 60, subpart Kb of this chapter shall comply with subpart Kb except as provided in paragraphs (n)(8)(i) through (n)(8)(vi ii ) 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 in spect the vessel to determine compliance with §60.113b(a) of subpart Kb because the roof appe ars to be structurally unsound and poses an imminent danger to inspecting personnel, th e owner or operator shall comply with the requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of subpart G (only up to the compliance date specified in paragraph (h) of this sectio n for compliance with §63.660, as applicable) or either §6 3.1063(c)(2)(iv)(A) or §63.1063(c) (2)(iv)(B) of subpart WW

. (iii) If a failure is detected during the inspections required by §60.113b(a)(2) or during the seal gap measurements required by §60.113b(b)(1), and th e 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 exte nsion to the Administrator. (iv) If an extension is utilized in accordance withparagraph (n)(8)(iii) of this section, the owner or operator shall, in the next pe riodic 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 st orage vessel was emptied.Page 11 of 175

(v) Owners and operators of storage vessels comp lying with subpart Kb of part 60 may submit the inspection reports required by §§60.115b(a)(3), (a)(4), a nd (b)(4) of subpart Kb as part of the periodic reports required by this subpart, rath er 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 in spections specified in §60.115b(b)(2) are not required if none of the measured gaps or calculated gap areas ex ceed the limitations specified in §60.113b(b)(4). Documentation of the inspect ions shall be recorded as specified in§60.115b(b)(3). (vii) To be in compliance with §60.112b(a)(1)( iv) or §60.112b(a)(2)(ii) of this chapter, guidepoles in floating roof storage vessels mu st be equipped with covers and/or controls (e.g., pole float system, pole sl eeve system, internal sleeve system or flexible enclosure system) as appropriate to comply with the “no visible ga p” requirement. (viii) If a flare is used as a control device fo r a storage vessel, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the owner or operator must meet the requirements of §63.670 instead of the requirements referenced from part 60, subpart Kb of this chapter for that flare. (9) Storage vessels described by paragraph (n)(6) of this section th at are to comply with 40 CFR part 60, subpart Ka, are to comply with only subp art Ka except as provided for in paragraphs (n)(9)(i) through (n )(9)(iv) of this section. (i) If the owner or operator dete rmines that it is unsafe to perform the seal gap measurements required in §60.113a(a)(1) of subpart Ka because th e floating roof appears to be structurally unsound and poses an imminent danger to inspec ting personnel, the owner or operator shall comply with the requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of subpart G (only up to the compliance date specified in paragraph (h) of this section for compliance with §63.660, as applicable) or either §63.1063(c)(2)(iv)(A) or § 63.1063(c)(2)(iv)(B) of subpart WW

. (ii) If a failure is detected during the seal gap measurements required by §60.113a(a)(1) of subpart Ka, and the vessel cannot be repaired within 45 days a nd the vessel cannot be emptied within 45 days, the owner or operator may utili ze 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 pe riodic report, identify the vessel, describe the nature and date of the repair made or provide the date the storag e vessel was emptied. The ow ner or operator shall also provide documentation of the decision to utilize an extensi on including a description of the failure, documentation that alternate storage capac ity is unavailable, a nd a schedule of actions that will ensure that the contro l equipment will be repaired or the vessel emptied as soon as possible. (iv) Owners and operators of st orage vessels complying with s ubpart Ka of part 60 may submit the inspection reports required by §60.113a(a)(1)(i )(E) of subpart Ka as part of the periodicPage 12 of 175

reports required by this subpart, rather th an within the 60-day period specified in §60.113a(a)(1)(i)(E) of subpart Ka. (10) Storage vessels described by paragraph (n)(1) of this section are to comply with 40 CFR part 61, subpart Y except as provided in paragraphs (n)(10)(i) through (n)(10)(vi) of this section. Storage vessels described by pa ragraph (n)(2) electing to comply with 40 CFR part 61, subpart Y shall comply with subpart Y except as provided for in paragraphs (n)(10)(i) through (n)(10)(viii) of this section. (i) Storage vessels that are to comply with §61.271(b) of this chapter are exempt from the secondary seal requirements of §61.271(b)(2 )(ii) of this chapter during the gap measurements for the primary seal re quired by §61.272(b) of this chapter. (ii) If the owner or operator determines th at it is unsafe to perform the seal gap measurements required in §61.272(b) of this chap ter or to inspect the vessel to determine compliance with §61.272(a) of th is chapter because the roof appears to be structurally unsound and poses an imminent danger to in specting personnel, the owner or operator shall comply with the requirements in either §63.120(b)(7)(i) or §63.120( b)(7)(ii) of subpart G (only up to the compliance date specified in paragraph (h) of this section for compliance with §63.660, as applicable) or either §63.1063( c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of subpart WW. (iii) If a failure is detected during the insp ections required by §61.272(a)(2) of this chapter or during the seal gap measurements require d by §61.272(b)(1) of this chapter, and the vessel cannot be repaired within 45 days and the vessel cannot be emptied within 45 days, the owner or operator may utilize up to two exte nsions of up to 30 additional calendar days each. The owner or operator is not required to provide a request for the extension to the Administrator. (iv) If an extension is utilized in accordance with paragraph (n)(10)(iii) of this section, the owner or operator shall, in the next period ic report, identify the vessel, provide the information listed in §61.272(a)(2 ) or §61.272(b)(4)(iii) of this chapter, and describe the nature and date of the repair made or provide the date the storage vessel was emptied. (v) Owners and operators of storage vessels complying with 40 CFR part 61, subpart Y may submit the inspection reports required by §61.275(a), (b)(1), and (d) of this chapter as part of the periodic reports required by this subpart, rather than within the 60-day period specified in §61.275(a), (b)(1), and (d) of this chapter. (vi) The reports of rim seal inspections sp ecified in §61.275(d) of this chapter are not required if none of the measured gaps or calculated gap areas exceed the limitations specified in §61.272(b)(4) of this chapter. Do cumentation of the inspections shall be recorded as specified in §61.276(a) of this chapter. (vii) To be in compliance with §61.271(a)(6) or §61.271(b)(3) of this chapter, guidepoles in floating roof storage vessels mu st be equipped with covers and/or controls (e.g., pole floatPage 13 of 175

systems, pole sleeve system, internal sleeve system or flexible enclosure system) as appropriate to comply with th e “no visible gap” requirement. (viii) If a flare is used as a control device fo r a storage vessel, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the owner or operator must meet the requirements of §63.670 instead of the requirements referenced from part 61, subpart Y of this chapter for that flare. (o) Overlap of this subpart CC with other regulations for wastewater. (1) After the compliance dates specified in para graph (h) of this sec tion a Group 1 wastewater stream managed in a piece of equipment that is also subject to the prov isions of 40 CFR part 60, subpart QQQ is required to comply only with this subpart. (2) After the compliance dates specified in para graph (h) of this sec tion a Group 1 or Group 2 wastewater stream that is conve yed, stored, or treated in a wast ewater stream management unit that also receives streams subject to th e provisions of §§63.133 through 63.147 of subpart G wastewater provisions of th is 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 paragra phs (o)(2)(i)(A) through ( o)(2)(i)(C D ) of this section. (A) The provisions in §§63.133 through 63.140 of subpart G for all equipment used in the storage and conveyance of the Group 1 or Group 2 wastewater stream. (B) The provisions in both 40 CFR part 61, subpart FF and in §§63.138 and 63.139 of subpart G for the treatment and control of the Group 1 or Group 2 wastewater stream. (C) The provisions in §§63.143 through 63.148 of s ubpart G for monitoring and inspections of equipment and for recordkeeping and reporting requirements. The owner or operator is not required to comply with the monitoring, record keeping, and reporting requirements associated with the treatment and control requirement s in 40 CFR part 61, subpart FF, §§61.355 through 61.357. (D) If a flare is used as a control device, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the requirements of §63.670. Prior to [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall m eet the applicable requirements of 40 CFR part 61, subpart FF and subpart G of this part, or the requirements of §63.670. (ii) Comply with pa ragraphs (o)(2)(ii)(A) and (o)(2)(ii)(B through (C ) of this section. (A) Comply with the provisions of §§63.133 through 63.148 and §§63.151 and 63.152 of subpart G.Page 14 of 175

(B) For any Group 2 wastewater stream or organi c stream whose benzene emissions are subject to control through the use of one or more trea tment processes or waste management units under the provisions of 40 CFR part 61, subpart FF on or after December 31, 1992, comply with the requirements of §63.133 through §63.147 of subpart G for Group 1 wastewater streams. (C) If a flare is used as a control device, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the requirements of §63.670. Prior to [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall m eet the applicable requirements of 40 CFR part 61, subpart FF and subpart G of this part, or the requirements of §63.670. (p) Overlap of subpart CC with othe r regulations for equipment leaks. (1) After the compliance dates specified in paragra ph (h) of this section, equipment leaks that are also subject to the provisions of 40 CFR pa rts 60 and 61 standards promulgated before September 4, 2007, are required to comply only with the provisions specif ied 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 St ate regulations, the permitting authority for the affected source may allow consolidation of the monitoring, recordkeeping, and reporting requirements under this subpart with the mon itoring, 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 pl an provided the implementation plan allows for approval of alternative monitoring, reporting, or recordkeeping requirements and provided that the permit contains an equivalent degr ee 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 r ack that is part of a source subject to subpart CC and also is subject to the provisions of 40 CFR part 60, subpart XX is required to comply only with this subpart. (s) Overlap of subpart CC with other regulation for flares. On [insert date 3 years and 60 days after date of publication in the Federal Register], flares that are subject to the provisions of 40 CFR 60.18 or 40 CFR 63.11 and s ubject to this subpart are required to comply only with the provisions specified in th is subpart. Prior to [i nsert date 3 years and 60 days after date of publication in the Federa l Register], flares th at are subject to the provisions of 40 CFR 60.18 or 40 CFR 63.11 and elect to comply with the requirements in §§63.670 and 63.671 are required to comply only wi th the provisions specified in this subpart.Page 15 of 175

§ 63.641 Definitions. All terms used in this subpart sh all have the meaning given them in the Clean Air Act, subpart A of this part, and in this section. If the same term is defined in subpart A and in this section, it shall have the meaning given in this section for purposes of this subpart. Affected source means the collection of emission points to which this subpart applies as determined by the criteria in §63.640. Aliphatic means open-chained structure consisting of paraffin, olefin and acetylene hydrocarbons and derivatives. Annual average true vapor pressure means the equilibrium partial pressure exerted by the stored liquid at the temperature equal to the annual average of the liquid storage temperature for liquids stored above or below the ambient temperatur e or at the local annual average temperature reported by the National Weather Service for liqu ids stored at the ambient temperature, as determined: (1) In accordance with methods specified in §63.111 of subpart G of this part; (2) From standard reference texts; or (3) By any other method approved by the Administrator.

Assist airmeans all air that intentionally is intro duced prior to or at a flare tip through nozzles or other hardware conveyance for th e purposes including, but not limited to, protecting the design of the flare tip, promoting turbulence for mixing or inducing air into the flame. Assist airincludes premix assist air and perimeter assist air. Assist airdoes not include the surrounding ambient air.

Assist steam means all steam that intentionally is introduced prior to or at a flare tip through nozzles or other hardware conveyan ce for the purposes incl uding, but not limited to, protecting the design of the flare tip, promoting turbulence for mixing or inducing air into the flame. Assist steam includes, but is not necessarily limited to, center steam, lower steam and upper steam.

Boiler means any enclosed combustion device that extr acts useful energy inthe form of steam and is not an incinerator. By compound means by individual stream compon ents, 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 th at the position of the valve cannot be changed without breaking the seal.Page 16 of 175

Center steam means the portion of assist steam intro duced into the stack of a flare to reduce burnback. Closed blowdown system means a system used for depressuri ng process vessels that is not open to the atmosphere and is configu red of piping, ductwork, connections, accumulators/knockout drums, and, if necessa ry, flow inducing devices that transport gas or vapor from process vessel to a contro l device or back into the process. Closed vent system means a system that is not open to the atmosphere and is configured of piping, ductwork, connections, and, if necessary, flow inducing de vices 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 su ch as a flare, incinerator, process heater, or boiler used for the combustion of organic hazardous ai r pollutant vapors. Combustion zone means the area of the flare fl ame where the combustion zone gas combines for combustion. Combustion zone gas means all gases and vapors found ju st after a flare tip. This gas includes all flare vent gas, total steam, and premix air.

Connector means flanged, screwed, or other joined fittings used to connect two pipe lines or a pipe line and a piece of equipment. A common c onnector is a flange. Joined fittings welded completely around the circumference of the in terface are not consider ed connectors for the purpose of this regulation. For the purpose of reporting and re cordkeeping, 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 re corded at the frequenc y specified in §63.655(i).

Continuous recorder means a data recording device recording an instantaneous data value or an average data value at least once every hour.

Control device means any equipment used for recove ring, removing, or oxidizing organic hazardous air pollutants. Such equipment include s, but is not limited to, absorbers, carbon adsorbers, condensers, incinerators, flares, boi lers, and process heaters. For miscellaneous process vents (as defined in this section), recovery devices (as de fined in this section) are not considered control devices. Cooling tower means a heat removal device used to remove the heat absorbed in circulating cooling water systems by transferring the heat to the atmosphere using natural or mechanical draft.Page 17 of 175

Cooling tower return line means the main water trunk lines at the inlet to the cooling tower before exposure to the atmosphere. Decoking operations means the sequence of steps conducted at the end of the delayed coking unit’s cooling cycle to open the coke drum to the atmosphere in order to remove coke from the coke drum. Decoking operations begin at the end of the cooling cycle when steam released from the coke drum is no longer di scharged via the unit’s blowdown system but instead is vented directly to the atmosphere. Decoking operations include atmospheric depressuring (venting), deheading, dr aining, and decoking (coke cutting). Delayed coker vent means a miscellaneous process vent that contains uncondensed vapors from the delayed coking unit’s bl owdown system. Venting from the delayed coker vent is typically intermittent in nature, and usually occurs only primarily during the initiation of the depressuring cooling cycle of the decoking operation a delayed coking unit coke drum when vapor from the coke drums cannot be sent to the fractionator colu mn 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 direct atmospheric venting, deheading, draining, or decoking (coke cutting), ar e not considered to be delayed coker vents

. Delayed coking unit means a refinery process unit in which high molecular weight petroleum derivatives are therma lly cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit includes, but is not limited to, all of the coke drums associated with a single fraction ator; the fractionator, including the bottoms receiver and the overhead condenser; the coke drum cutting water and quench system, including the jet pump and coker quench wa ter tank; and the coke drum blowdown recovery compressor system.

Distillate receiver means overhead receivers, overhead accumulators, reflux drums, and condenser(s) including ejector-condenser(s) associated with a distillation unit.

Distillation unit means a device or vessel in which one or more feed streams are separated into two or more exit streams, each exit stream havi ng component concentrations different from those in the feed stream(s). The sepa ration is achieved by the redistri bution of the components between the liquid and the vapor phases by vaporization a nd condensation as they approach equilibrium within the distillation unit. Distillation unit incl udes the distillate receiver, reboiler, and any associated vacuum pump or steam jet. Emission point means an individual miscellaneous pro cess vent, storage vessel, wastewater stream, or equipment leak , decoking operation or heat exchange system associated with a petroleum refining process unit; anindividual storage vessel or equi pment leak associated with a bulk gasoline terminal or pipeline breakout station classified unde r Standard Industrial Classification code 2911; a gaso line loading rack classifiedunder Standard Industrial Classification code 2911; or a marine tank ve ssel loading operation lo cated at a petroleum refinery.Page 18 of 175

Equipment leak means emissions of organic hazardous air pollutants from a pump, compressor, pressure relief device, samp ling connection system, open-ende d valve or line, valve, or instrumentation system “in organic hazardous air pollutant service” as defined in this section. Vents from wastewater collec tion and conveyance systems (including, but not limited to wastewater drains, sewer vents, and sump drains), tank mixers, and sample valves on storage tanks are not equipment leaks.

Flame zone means the portion of a combustion chamber of a boiler or process heater occupied by the flame envelope created by the primary fuel.

Flare means a combustion device lacking an encl osed combustion chamber that uses an uncontrolled volume of ambient air to burn gases. For the purposes of this rule, the definition of flare includes, but is not necessarily li mited to, air-assisted flares, steamassisted flares and non-assisted flares. Flare purge gas means gas introduced between a flare header’s water seal and the flare tip to prevent oxygen infiltration (b ackflow) into the flare tip. Fo r a flare with no water seal, the function of flare purge gas is performed by flare sweep gas and, therefore, by definition, such a flare has no flare purge gas

. Flare supplemental gas means all gas introduced to th e flare in order to improve the combustible characteristics of combustion zone gas. Flare sweep gas means, for a flare with a flare gas recovery system, the gas intentionally introduced into the flare header system to maintain a constant flow of gas through the flare header in order to prevent oxygen buildup in the flare header; flare sweep gas in these flares is introduced prior to and recovered by the flare gas recovery system. For a flare without a flare gas recovery system, flare sweep gas means the gas intentionally introduced into the flare header system to maintain a cons tant flow of gas through the flare header and out the flare tip in order to prevent oxygen buildup in the flare header and to prevent oxygen infiltration (backflo w) into the flare tip. Flare vent gas means all gas found just prior to the flare tip. This gas includes all flare waste gas ( i.e. , gas from facility operations that is directed to a flare for the purpose of disposing of the gas), that portion of flare sweep gas that is not recovered, flare purge gas and flare supplemental gas, but does not include pilot gas, total steam or assist air.

Flexible enclosure device means a seal made of an elasto meric fabric (or other material) which completely encloses a slotted guidepole or ladder and eliminates the vapor emission pathway from inside the storage vessel throug h the guidepole slots or ladder slots to the outside air. Flexible operation unit means a process unit that manufactures different products periodically by alternating raw materials or ope rating conditions. These units are also referred to as campaign plants or blocked operations.Page 19 of 175

Flow indicator means a device that indicates whether gas is flowing, or whether the valve position would allow gas to flow, in a line. Force majeure event means a release of HAP, either direc tly to the atmosphere from a relief valve or discharged via a flare, that is demonstrated to the sa tisfaction of the Administrator to result from an event beyond the refinery own er or operator’s control, such as natural disasters; acts of war or terrorism; loss of a utility external to the refinery (e.g., external power curtailment), excluding power curtai lment due to an interruptible service agreement; and fire or explosion originating at a near or adjoining facility outside of the refinery that impacts the refinery’s ability to operate. Fuel gas system means the offsite and onsite piping and control system that gathers gaseous streams generated by refinery operations, may blend them with sources of ga s, if available, and transports the blended gaseous fuel at suitable pr essures for use as fuel in heaters, furnaces, boilers, incinerators, gas turbines , and other combustion devices loca ted 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, hydrogenand other miscellaneous species.

Gasoline means any petroleum distillate or petrol eum 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 th at 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 te rminal 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, th at emits greater than 9.1 megagrams of any individual HAP or 22.7 megagrams of any co mbination 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 emi ssions 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 a ny control device and prior to discharge to the atmosphere.Page 20 of 175

Group 1 storage vessel means a : (1) Prior to [insert date 60 days after date of publication in the Federal Register]: (i) A storage vessel at an existing source that has a design capacitygreater than or equal to 177 cubic meters and stored-liquid maximum true vapor pressure greater th an or equal to 10.4 kilopascals and stored-liquid a nnual average true vapor pressure greater than or equal to 8.3 kilopascals and annual average HAP liquid concentr ation greater than 4 percent by weight total organic HAP; a (ii) A storage vessel at a new source that has a desi gn storage capacity grea ter 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 concentr ation greater than 2 percent by weight total organic HAP; or a (iii) A storage vessel at a new source that has a design storage capac ity 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 k ilopascals and annual average HAP li quid concentration greater than 2 percent by weight total organic HAP. (2) On and after [insert date 60 days after da te of publication in the Federal Register]: (i) A storage vessel at an existing source that has a design capacity greater than or equal to 151 cubic meters (40,000 gallons) and stored- liquid maximum true vapor pressure greater than or equal to 5.2 kilopascals (0.75 pounds per square inch) and annual average HAP liquid concentration greater than 4 p ercent by weight total organic HAP; (ii) A storage vessel at an existing source that has a design storage capacity greater than or equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressu re greater than or equal to 13.1 kilopascals (1.9 pounds per square inch) and annual average HAP liquid concentration greater than 4 percent by weight total organic HAP; (iii) A storage vessel at a new source that ha s a design storage capacity greater than or equal to 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or equal to 3.4 kilopascals (0.5 pounds per square inch) and annual average HAP liquid concentration greater than 2 p ercent by weight total organic HAP; or (iv) A storage vessel at a new source that has a design stor age capacity greater than or equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressu re greater than or equal to 13.1 kilopascals (1.9 pounds per square inch) and annual average HAP liquid concentration greater than 2 percent by weight total organic HAP. Group 1 wastewater stream means a wastewater stream at a petroleum refinery with a total annual benzene loading of 10 mega grams per year or greater as calculated acco rding to thePage 21 of 175

procedures in 40 CFR 61.342 of subpart FF of pa rt 61 that has a flow rate of 0.02 liters per minute or greater, a benzene concentration of 10 parts per million by weight or greater, and is not exempt from control requirements under the provisions of 40 CFR part 61, subpart FF. Group 2 gasoline loading rack means a gasoline loading rack classified under Standard Industrial Classification code 2911 that does no t 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 no t meet the definition of a Group 1 storage vessel. Group 2 wastewater stream means a wastewater stream that does not meet the definition of Group 1 wastewater stream. Hazardous air pollutant or HAP means one of the chemicals listed in section 112(b) of the Clean Air Act. Heat exchange system means a device or collection of device s used to transfer heat from process fluids to water without intentional direct co ntact of the process fluid with the water ( i.e. , noncontact heat exchanger) and to transport and/or cool the wate r 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 cooli ng tower, all petroleum refinery process unit heat exchangers that are in organic HAP service, as defined in this subpart, serviced by that cooling tower, and all water lines to and from these petroleum refinery process unit heat exchangers. For once-through systems, the heat exchange system consists of all heat exchangers that are in organic HAP service, as defined in this subpart, servicing an individual petroleum refinery process unit and all water line s to and from these heat exchangers. Sample coolers or pump seal coolers are not considered heat exchangers for the purpose of this definition and are not part of the heat exchange system . Intentional direct contact with process fluids results in the formation of a wastewater. Heat exchanger exit line means the cooling water line from the exit of one or more heat exchangers (where cooling water leaves the heat exchangers) to either th e 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 en ergy recovery section is a separate sectionPage 22 of 175

following the combustion section and the two are joined by ducts or connections carrying flue gas. In heavy liquid service means that the piece of equipment is not in gas/vapor service or in light liquid service. In light liquid service means that the piece of equipment contains a liquid that meets the conditions specified in §60.593(d) of part 60, subpart GGG. In organic hazardous air pollutant service or in organic HAP service means that a piece of equipment either contains or contacts a fluid (liquid or gas) that is at least 5 percen t by weight of total organic HAP as determined according to th e provisions of §63.180(d) of this part and table 1 of this subpart. The provisions of §63.180(d) al so specify how to determine that a piece of equipment is not in organic HAP service.

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

Lower steam means the portion of assist steam piped to an exteri or annular ring near the lower part of a flare tip, which then flows th rough tubes to the flare tip, and ultimately exits the tubes at the flare tip. Maximum true vapor pressure means the equilibrium partial pre ssure exerted by the stored liquid at the temperature equal to the highest calendar- month average of the liq uid 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 continuo usly or periodically discharged during normal operation of

from a petroleum refining process unit mee ting the criteria specified in §63.640(a). Miscellaneous process vents include gas streams that are discharged direc tly 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, fl ash/knockout drums, reactor vessels, scrubber overheads, stripper overheads, vacuum ( pumps, steam ) ejectors , hot wells, high point bleeds , wash tower overheads, water wash accumula tors, blowdown condensers/accumulators, and delayed coker vents. Miscellaneous process vents do not include:Page 23 of 175

(1) Gaseous streams routed to a fuel gas system , provided that on and after [insert date 3 years and 60 days after date of publication in th e Federal Register], any flares receiving gas from the fuel gas system are subject to §63.670 ; (2) Relief valve Pressure relief device discharges; (3) Leaks from equipment regulated under §63.648; (4) Episodic or nonroutine releases such as those associated with startup, shutdown, malfunction, maintenance, depressuring, and catalyst transfer operations; [Reserved]; (5) In situ sampling systems (onstream analyzers ); ) until [insert date 3 years and 60 days after date of publication in the Federal Register]. After this date, these sampling systems will be included in the definition of miscellaneous process vents; (6) Catalytic cracking unit ca talyst regeneration vents; (7) Catalytic reformer regeneration vents; (8) Sulfur plant vents; (9) Vents from control devices such as scrubbe rs, boilers, incinerato rs, and electrostatic precipitators applied to catalytic cracking unit catalyst regeneration vent s, catalytic reformer regeneration vents, and sulfur plant vents; (10) Vents from any stripping operations applied to comply with the wast ewater provisions of this subpart, subpart G of this pa rt, or 40 CFR part 61, subpart FF; (11) Coking unit vents Emissions associated with coke drum depressuring at or below a coke drum outlet pressure of 15 pounds per square inch gauge, deheading, draining, or delayed coking unit decoking (coke cutting) or pressu re testing after decoking operations ; (12) Vents from storage vessels; (13) Emissions from wastewater collection and conveyance systems including, but not limited to, wastewater drains, sewer ve nts, and sump drains; and (14) Hydrogen production plant vents through which carbon dioxide is removed from process streams or through which steam condensate produced or treated within the hydrogen plant is degassed or deaerated. Net heating value means the energy released as heat when a compound undergoes complete combustion with oxygen to form gaseous carbon dioxide and gaseous water (also referred to as lower heating value). Operating permit means a permit required by 40 CFR parts 70 or 71.Page 24 of 175

Organic hazardous air pollutant or organic HAP in this subpart, means any of the organic chemicals listed in tabl e 1 of this subpart.

Petroleum-based solvents means mixtures of aliphatic hydroca rbons or mixtures of one and two ring aromatic hydrocarbons.

Perimeter assist airmeans the portion of assist air intr oduced at the perimeter of the flare tip or above the flare tip. Perimeter assist air includes air intentionally entrained in lower and upper steam. Perimeter assist air includes all assist air except premix assist air. Periodically discharged means discharges that are intermittent and associated with routine operations . Discharges associated with , maintenance activities , startups, shutdowns, malfunctions, or process upsets are not considered periodically discharged miscellaneous process vents and are therefore not regulated by the petroleum re finery miscellaneous process vent provisions

. Petroleum refining process unit means a process unit used in an establishment primarily engaged in petroleum refining as define d in the Standard Industrial Cl assification 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 distilla te, and fuel oils), or lubricants; (2) Separating petroleum; or (3) Separating, cracking, reacting, or refo rming intermediate petroleum streams. (4) Examples of such units include, but are not limited to, petroleum-based solvent units, alkylation units, catalytic hydrotreating, catal ytic hydrorefining, catalytic hydrocracking, catalytic reforming, catalytic cracking, cr ude distillation, lube oil processing, hydrogen production, isomerization, polymerization, therma l processes, and ble nding, sweetening, and treating processes. Petroleum refining pro cess units also include sulfur plants. Pilot gas means gas introduced into a flare tip that provides a flam e to ignite the flare vent gas. Plant site means all contiguous or adjoining propertythat is under common control including properties that are se parated only by a road or other publ ic right-of-way. Common control includes properties that are owned, leased, or operated by the same entity, parent entity, subsidiary, or any combination thereof.

Premix assist airmeans the portion of assist air that is introduced to the flare vent gas, whether injected or induced , prior to the flare tip. Premix assist airalso includes any air intentionally entrained in center steam.Page 25 of 175

Primary fuel means the fuel that provides the principal heat input (i.e., more than 50 percent) to the device. To be considered primary, the fuel must be able to sustain operation without the addition of other fuels.

Process heater means an enclosed combustion device that primarily transfers heat liberated by burning fuel directly to proce ss 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 manufactur e an intended product. A process unit includes any associated storage vessels. For the purpose of this subpart, process un it includes, but is not limited to, chemical manufacturing process un its and petroleum refining process units.

Process unit shutdown means a work practice or operationa l procedure that stops production from a process unit or part of a process unit du ring which it is technical ly 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 pro cess unit for less than 24 hours is not considered a proce ss unit shutdown. An unscheduled work practice or operational procedure that would stop production from a pro cess 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 th an delay of repair of leaking components until the next scheduled process un it shutdown is not considered a process unit shutdown. The use of spare equipment and techni cally feasible bypassing of equipment without stopping production are not consid ered 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 technologyfor 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 fo r miscellaneous process vents means a combustion device used to reduce organic HAP emissions by 98 percent, or to an outlet concen tration of 20 parts per million by volume. Reference control technology for storage vessels means either: (1 ) For Group 1 storage vessels complying with §63.660: (i) An internal floating roof, including an exte rnal floating roof converted to an internal floating roof, meeting the specifica tions of §§63.1063(a)(1)(i) and (b);Page 26 of 175

(ii) An external floating roof meeting the specifications of §63.1063(a)(1 )(ii), (a)(2), and (b); or (iii) [Reserved] (iv) A closed-vent system to a control devi ce that reduces organic HAP emissions by 95 percent, or to an outlet concentration of 20 parts per million by volume (ppmv). (v) For purposes of emissions averaging, these four technologies are considered equivalent. (2) For all other storage vessels: (i ) An internal floating roof meeting the specif ications of §63.119(b) of subpart G except for §63.119 (b)(5) and (b)(6); ( 2 ii ) An external floating roof m eeting the specifications of §63.119(c) of subpart G except for §63.119(c)(2); ( 3 iii ) An external floating roof convert ed to an internal floating roof meeting the spec ifications of §63.119(d) of subpart G excep t for §63.119(d)(2); or ( 4 iv ) A closed-vent system to a control devi ce that reduces organic HAP emissions by 95

- percent, or to an outlet concentration of 20 parts per million by volume. ( 5 v ) For purposes of emissions averaging, these f our technologies are co nsidered equivalent. Reference control technology for wastewater means the use of: (1) Controls specified in §§61.343 thr ough 61.347 of subpart FF of part 61; (2) A treatment process that achieves the emission reductions specified in ta ble 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 s ubpart 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 de scribed 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, et c.) that is produced in the refining of crude oil and/or petrochemical processe s and that is separated for use as a fuel in boilers and process heater s throughout the refinery. Regulated material means any stream associated with emission sources listed in §63.640(c) required to meet control requi rements under this subpart as well as any stream for whichPage 27 of 175

this subpart or a cross-referencing subpart sp ecifies that the require ments for flare control devices in §63.670 must be met. Relief valve means a valve used only to release an unplanned, nonroutine discharge. A relief valve discharge can result from an operator er ror, a malfunction such as a power failure or equipment failure, or other unexpected cause th at 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 pl ant operations whose primary purpose is to conduct research and developmen t into new processes and products, where the operations are under the close superv ision of technically trained pe rsonnel, and is not engaged in the manufacture of products for commerci al 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 reacto r) 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 opera tion 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 ex cess of 204.9 kilopascals and without emissions to the atmosphere; (3) Vessels with capacities smaller than 40 cubic meters; (4) Bottoms receiver tanks; or (5) Wastewater storage tanks. Wastewater st orage 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 per cent of the temperature being m onitored expressed in degrees Celsius or ±0.5 °C, whichever is greater. Thermal expansion relief valve means a pressure relief valve designed to protect equipment from excess pressure due to thermal expansion of blocked liquid-filled equipment or piping due to ambient heating or heat from a heat tracing system. Pressure relief valves designed to protect equipment from ex cess pressure due to blockage against a pump or compressor or due to fire contingency are not thermal expansion relief valves.Page 28 of 175

Total annual benzene means the total amount of benzene in waste streams at a facility on an annual basis as determined in §61.342 of 40 CFR part 61, subpart FF. Total organic compounds or TOC, as used in this subpart, means those compounds excluding methane and ethane measured according to th e procedures of Method 18 of 40 CFR part 60, appendix A. Method 25A may be used alone or in combination with Method 18 to measure TOC as provided in §63.645 of this subpart.

Total steam means the total of all steam that is s upplied to a flare and includes, but is not limited to, lower steam, center steam and upper steam. Upper steam means the portion of assist steam in troduced via nozzles located on the exterior perimeter of the upper end of the flare tip.

Wastewater means water or wastewater that, during production or processing, comes into direct contact with or results from th e 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 organi c products or reactants; water used to cool or quench organic vapor streams through direct c ontact; and condensed steam from jet ejector systems pulling vacuum on ve ssels 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, th e permit shall be obtained from the State authority. If the State operati ng permit program has not been approved, the source shall apply to the EPA Regional Office pursuant to part 71. (b) [Reserved] The emission standards set forth in th is subpart shall apply at all times. (c) Table 6 of this subpart specif ies 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 complia nce determinations shall be required only as specified in this subpart. (1) Performance tests and comp liance determinations shall be conducted according to the schedule and procedures sp ecified in this subpart. (2) The owner or operator shall notify the Administrator of the intention to conduct a performance test at least 30 days befo re the performance test is scheduled. (3) Performance tests shall be c onducted according to the provis ions of §63.7(e) except that performance tests shall be conducted at maxi mum representative operating capacity for thePage 29 of 175

process. During the performance test, an owner or operator shall operate the control device at either maximum or minimum representative ope rating conditions for monitored control device parameters, whichever results in lower emission reduction. An owner or operator shall not conduct a performance test during startup, sh utdown, periods when the control device is bypassed or periods when the process, monito ring equipment or control device is not operating properly. The owner/operator may no t conduct performance tests during periods of malfunction. The owner or operator must record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that the test was co nducted at maximum representative operating capacity. Upon request, the owner or operato r shall make available to the Administrator such records as may be necessary to det ermine the conditions of performance tests. (4) Data shall be reduced in accordance withthe 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 th is subpart shall keep co pies 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 ma intained as specified in §63.655(i). All applicable records shall be maintained in such a manner that they can be readily accessed within 24 hours. Records may be maintained in hard copy or co mputer-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 ac ceptable to both the Admi nistrator 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 requi rements of this subpart shall control emissions of organic HAP’s to the level represented by the following equation:



#      

       

2 1C 2 1 2 1C 2 1 2 1 A 

### EWW EWW EMV EMVREGLR EGLR ESES EPV EPV E )( 05.0 02.0

where:

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

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

Σ EPV 2 = Sum of the emissions, megagrams per year, from all Group 2 proce ss vents, as defined in §63.641.Page 30 of 175

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

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

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

Σ EGLR2 = Sum of the emissions, megagrams per year , from all Group 2 gasoline loading racks, as defined in §63.641. (R) Σ EMV 1 = Sum of the residual em issions megagrams per year, from all Group 1 marine tank vessels, as defined in §63.641. R = 0.03 for existing sources, 0.02 for new sources.

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

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

Σ EWW 2 = Sum of emissions from all Group 2 wa stewater streams, as defined in §63.641. The emissions level represented by this equati on 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 em ission 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 th is section by following the procedur es 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 sp ecified emission points and the procedures specified in paragraph (k )(1 ) of this section for all other emissi on points within the source

. (j) The owner or operator of a new source sh all demonstrate compliance with the emission standard in paragraph (h) of this section only by following the proced ures in paragraph (k) of this section. The owner or operator of a new source may not use the emissions averaging compliance approach.Page 31 of 175

(k) The owner or operator of an existing source may comply, and the owner or operator of a new source shall comply, with the miscellaneous process vent applicable provisions in §§63.643 through 63.645, the storage vessel provisions in §63. 63. 646 , the wastewater provisions in § or 63.660, 63.647, the gasoline loading rack provisions in § 63.650, and the marine tank vessel loading operation provisions in § 63.651 of this subpart. , as specified in §63.640(h). (1) The owner or operator usi ng this compliance approach shall also comply with the requirements of §63.655 §§63.648 and/or 63.649, 63.654, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable. (2) The owner or operator using th is compliance approach is not re quired to calculate the annual emission rate specified in para graph (g) of this section. (l) The owner or operator of an existing source may elect to control some of the emission points within the source to different levels than specified under §§63.643 through 63. 645, 63.646 or 63.660, 63. 647, §§ 63.650 , and 63.651 , as applicable according to §63.640(h), by using an emissions averaging compliance approach as long as the overall emissions for the source do not exceed the emission level specified in paragraph (g) of this sec tion. The owner or operator using emissions averaging shall meet the requi rements in paragraphs (l)(1) and ( l)( 2) of this section. (1) Calculate emission debits and credits for t hose emission points involv ed in the emissions average according to the proce dures specified in §63.652; and (2) Comply with the requirements of §§63. 648 and/or 63.649, 63.654, 63. 652, 63.653, and 63.655 , 63.657, 63.658, 63.670 and 63.671 , as applicable. (m) A State may restrict the owner or operator of an existing source to us ing 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 th e source from using an emissions averaging compliance approach. (n) At all times, the owner or operator must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control prac tices for minimizing emissions. The general duty to minimize emis sions does not require the owner operator to make any further efforts to reduce emissions if levels required by the applicable standard have been achieved. Determination of wheth er a source is operating in compliance with operation and maintenance requirements will be based on information available to the Administrator which may include, but is no t limited to, monitori ng results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. § 63.643 Miscellaneous process vent provisions. (a) The owner or operator of a Group 1 miscella neous process vent as defined in §63.641 shall comply with the requirements of either pa ragraphs (a)(1) or (a )(2) of this section or, ifPage 32 of 175

applicable, paragraph (c) of this section. Th e owner or operator of a miscellaneous process vent that meets the conditions in paragraph (c) of this section is only required to comply with the requirements of paragraph (c) of this section and §63.655(g)(13) and (i)(12) of this subpart for that vent

. (1) Reduce emissions of organic HAP’s using a flare that meets . On and after [insert date 3 years and 60 days after date of publication in th e Federal Register], th e flare shall meet the requirements of §63.670. Prior to [i nsert date 3 years and 60 days after date of publication in the Federal Register ], the flare shall meet the requirements of §63.11(b) of subpart A of this part or the requirements of §63.670

. (2) Reduce emissions of organic HAP’s, using a control device, by 98 weight-percent or to a concentration of 20 parts per million by volume, on a dry basis, corrected to 3 percent oxygen, whichever is less stringent. Compliance can be de termined 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 pe rcentage 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 th at the required percent reduction or concentration is ach ieved. Testing and monitoring is required only as specified in §§63.644(a) and 63.645 of this subpart. (c) An owner or operator may designate a process vent as a maintenance vent if the vent is only used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied, depressurized, degasse d or placed into service. The owner or operator does not need to designate a ma intenance vent as a Group 1 or Group 2 miscellaneous process vent. The owner of op erator must comply with the applicable requirements in paragraph (c)(1) through (c)(3) for each maintenance vent. (1) Prior to venting to the atmosphere, pro cess liquids are removed from the equipment as much as practical and the equipment is depressu red to a control device, fuel gas system, or back to the process until one of the followi ng conditions, as applicable, is met. (i) The vapor in the equipment served by the maintenance vent has a lower explosive limit (LEL) of less than 10 percent. (ii) If there is no ability to measure the LEL of the vapor in the equipment based on the design of the equipment, the pressure in the equipment served by the maintenance vent is reduced to 5 psig or less. Upon opening th e maintenance vent, active purging of the equipment cannot be used until the LEL of the vapors in the maintenance vent (or inside the equipment if the maintenance is a hatch or similar type of open ing) equipment is less than 10 percent. (iii) The equipment served by the maintenanc e vent contains less th an 72 pounds of VOC.Page 33 of 175

(iv) If the maintenance vent is associated with equipment co ntaining pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers) at re fineries that do not have a pure hydrogen supply, the LEL of the vapor in the equipment mu st be less than 20 p ercent, except for one event per year not to exceed 35 percent. (2) Except for maintenance vents complying with the alternative in (c)(1)(iii), the owner or operator must determine the LEL or, if appl icable, equipment pressure using process instrumentation or portable measurement devi ces and follow procedures for calibration and maintenance according to ma nufacturer’s specifications. (3) For maintenance vents complying with the alternative in (c)(1) (iii), the owner or operator shall determine mass of VOC in the equipment served by the maintenance vent based on the equipment size and contents afte r considering any contents drained or purged from the equipment. Equipment size may be determined from equipment design specifications. Equipment contents may be determined using process knowledge. § 63.644 Monitoring provisions fo r miscellaneous process vents. (a) Except as provided in paragr aph (b) of this section, each owner or operator of a Group 1 miscellaneous process vent that uses a combus tion device to comply with the requirements in §63.643(a) shall install the monitoring equipment spec ified in paragraph (a)(1 ), (a)(2), (a)(3), or (a)(4) of this section, dependi ng on the type of combustion device used. All monitoring equipment shall be installed, calibrated, mainta ined, and operated according to manufacturer’s specifications or other written pr ocedures that provide adequate assurance that the equipment will monitor accurately and, except for CPMS installed for pilot flame monitoring, must meet the applicable minimum accuracy, ca libration and quality control requirements specified in table 13 of this subpart

. (1) Where an incinerator is used, a temperature monitoring device equipped with a continuous recorder is required. (i) Where an incinerator other than a catalytic incinerator is used, a temperature monitoring device shall be installed in the firebox or in the ductwork imme diately downstream of the firebox in a position before any substa ntial heat exchange occurs. (ii) Where a catalytic incinerator is used, temper ature monitoring devices shall be installed in the gas stream immediately before and after the catalyst bed. (2) Where a flare is used prior to [insert date 3 years and 60 days after date of publication in the Federal Register] , a device (including but no t limited to a thermocouple, an ultraviolet beam sensor, or an infrared sensor) cap able of continuously detecting th e presence of a pilot flame is required , or the requirements of §63.670 shall be me t. Where a flare is used on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the requirements of §63.670 shall be met

.Page 34 of 175

(3) Any boiler or process heater with a design h eat input capacity greater than or equal to 44 megawatt or any boiler or process heater in which all vent stream s 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 re quired to use a temperature monitoring device in the firebox equipped with a continuous recorder. (b) An owner or operator of a Group 1 miscella neous process vent may request approval to monitor parameters other than those listed in para graph (a) of this section. The request shall be submitted according to the procedures specified in §63.655(h). Approval shall be requested if the owner or operator: (1) Uses a control device other than an incine rator, boiler, process heater, or flare; or (2) Uses one of the control devices listed in para graph (a) of this secti on, 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 miscellane ous process vent using a vent system that contains bypass lines that could divert a vent stream away from the control device used to comply with paragraph the requirements in §63.643 (a) of this section either directly to the atmosphere or to a control device that do es not comply with the requirements in §63.643(a) shall comply with either paragraph (c)(1) or ( c)( 2) of this section. Use of the bypass at any time to divert a Group 1 miscellaneous process ve nt stream to the atmosphere or to a control device that does not comply with the require ments in §63.643(a) is an emissions standards violation. Equipment such as low leg drains , high point bleeds, anal yzer vents, open-ended valves or lines, pressure relief valves needed for safety reasons, and equipment subject to §63.648 are not subject to this paragraph. (1) Install, calibrate , and maintain , and operate a flow indicator that determines whether a vent stream flow is present at least once every hour. A manual block valve equipped with a valve position indicator may be used in lieu of a flow indicator, as long as the valve position indicator is monitored continuously. Records shall be generated as specified in §63.655(h) and (i). The flow indicator shall be installed at th e entrance to any bypass line that could divert the vent stream away from the cont rol device to the atmosphere; or (2) Secure the bypass line valve in the closed non-diverting position with a car-seal or a lockand-key type configuration. A vi sual inspection of the seal orclosure mechanism shall be performed at least once every month to ensu re that the valve is maintained in the closed nondiverting position and that the vent stream is not di verted through th e bypass line. (d) The owner or operator shall establish a range that ensures compliance with the emissions standard for each parameter monitored under paragra phs (a) and (b) of this section. In order to establish the range, the information require d in §63.655(f)(3) shall be submitted in the Notification of Compliance Status report.Page 35 of 175

(e) Each owner or operator of a control device subject to the monito ring 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 contro l 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 viol ation of the applicable emissi on 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 consider ed 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) shal l be replaced with para graphs (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 ve nt 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 la st product recovery device (as defined in §63.641 of this subpart) (if any recovery devices are present) but pr ior to the inlet of a ny control device (as defined in §63.641 of this subpart) that is presen t, prior to any diluti on of the process vent stream, and prior to release to the atmosphere. (1) Methods 1 or 1A of 40 CFR part 60, a A ppendix A -1 , as appropriate, shall be used for selection of the sampling site . For vents smaller than 0.10 mete r in diameter, sample at the center of the vent

. (2) No traverse site selection method is needed for vents smaller than 0.10 meter in diameter. (f) Except as provided in paragr aph (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 sha ll determine the TOC mass flow rate by the following procedures: (1) The sampling site shall be selected as sp ecified in paragraph (e) of this section.Page 36 of 175

(2) The gas volumetric flow rate shall be determined using Methods 2, 2A, 2C, 2D, or 2D 2F of 40 CFR part 60, a A ppendix A -1 or Method 2G of 40 CFR part 60, Appendix A-2 , as appropriate. (3) Method 18 or Method 25A of 40 CFR part 60, appendix A shall be used to measure concentration; alternatively, any other method or data that has been validated according to the protocol in Method 301 of appendix A of this part may be used. If Method 25A is used, and the TOC mass flow rate calculated fr om 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 hydrocar bons that may be deducted to calculate the TOC (minus non-VOC hydrocarbons) concentrat ion 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 samp ling is used, then the samples shall be taken at approximately equal intervals in time, su ch as 15-minute intervals during the run. (ii) The TOC concentration (C TOC ) is the sum of the concentrati ons of the indi vidual components and shall be computed for each run using th e following equation if Method 18 is used:

X C C x

i n

j ji

TOC 

#  

         

 1 1

where:

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

C

ji = Concentration of sample component j of the sample i, dry basis, parts per million by volume. n = Number of components in the sample. x = Number of samples in the sample run. (4) The emission rate of TOC (minus methane and ethane) (E TOC ) shall be calculated using the following equation if Method 18 is used:

s n

j jj 2 QMCKE      

 

## 

 1

where:Page 37 of 175

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

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

C

j = Concentration on a dry basis of organic compound j in parts per million as measured by Method 18 of 40 CFR part 60, appendix A, as indi cated in paragraph (f)(3) of this section. C j includes all organic compounds meas ured minus methane and ethane.

M

j = Molecular weight of organic compound j, gram per gram-mole. Q s = Vent stream flow rate, dry standard cubic meters per minute, at a temperature of 20 °C. (5) If Method 25A is used, the emission rate of TOC (E TOC ) shall be calculated using the following equation:

s TOC2 TOC MQCKE 

where:

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

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

C TOC = Concentration of TOC on a dry basis in parts per million volume as measured by Method 25A of 40 CFR part 60, appendix A, as indicat ed in paragraph (f)(3 ) of this section. M = Molecular weight of organic co mpound used to express units of C TOC , gram per gram-mole. Q s = Vent stream flow rate, dry standard cubic meters per minute, at a temperature of 20 °C. (g) Engineering assessment may be used to determine the TOC emission rate for the representative operating condition expected to yield the highest daily emission rate. (1) Engineering assessment includes, but is not limited to, the following: (i) Previous test results provide d the tests are representative of current operating practices at the process unit. (ii) Bench-scale or pilot-scale test data representative of the process under representative operating conditions. (iii) TOC emission rate specified or implied within a permit limit applicable to the process vent.Page 38 of 175

(iv) Design analysis based on accepted chemical engineering principles, measurable process parameters, or physical or chemical laws or properties. Examples of analytical methods include, but are not limited to: (A) Use of material balances based on pro cess stoichiometry to estimate maximum TOC concentrations; (B) Estimation of maximum flow rate based on physical equipment design such as pump or blower capacities; and (C) Estimation of TOC concentratio ns based on saturation conditions. (v) All data, assumptions, and procedures used in the engineering assessment shall be documented. (h) The owner or operator of a Group 2 process ve nt 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 pr ocess 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 recoveryequipment. For purposes of this paragraph, process changes do not include: pr ocess upsets; unintentional, te mporary process changes; and changes that are within the range on wh ich 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 ch ange. 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 sha ll comply with the appropriate provisions in §63.643 by the dates specified in §63.640. (i) A compliance determination for visible emissi ons shall be conducted within 150 days of the compliance date using Method 22 of 40 CFR pa rt 60, appendix A, to determine visible emissions. § 63.646 Storage vessel provisions. Upon a demonstration of compliance with th e standards in §63.660 by the compliance dates specified in §63.640(h), the standards in this section shall no longer apply. (a) Each owner or operator of a Group 1 storage ve ssel subject to this subp art shall comply with the requirements of §§63.119 through 63.121 except as provided in paragra phs (b) through (l) of this section.Page 39 of 175

(b) As used in this section, a ll terms not defined in §63.641 shall have the meaning given them in 40 CFR part 63, subparts A or G. The Group 1 st orage vessel definition presented in §63.641 shall apply in lieu of the Group 1 storage vessel definitions pres ented in tables 5 and 6 of §63.119 of subpart G of this part. (1) An owner or operator may use good engineeri ng 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 Admi nistrator do not agree on whether the annual average weight percent organic HAP in the stored liquid is a bove or below 4 percent for a storage vessel at an existing s ource or above or below 2 percen t for a storage vessel at a new source, Method 18 of 40 CFR part 60, appendix A shall be used. an appropriate method (based on the type of liquid stored) as publishe d by EPA or a consensus-based standards organization shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM Internatio nal (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B 2959, (800) 262–1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293–8020, http: //www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street , NW., 4th Floor, Washington, DC 20001, (202) 824–7000, http://www.aga.org), the American Societ y of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016–5990, ( 800) 843–2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005–4070, (202) 682–8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356–0060, http://www.naesb.org). (c) The following paragraphs do not apply to storag e 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 sc hedule provisions and the compliance date) shall be replaced with §63.640(h), (2) All references to April 22, 1994 sh all 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 spec ified 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 repla ced with §63.643(a )(2) of this subpart.Page 40 of 175

(7) All references to §63.126(b)(1) of subpart G shall be replaced with §63.422(b) of subpart R of this part. (8) All references to §63.128(a) of subpart G shall be replaced with §63.425, paragraphs (a) through (c) and (e) through (h) of subpart R of this part. (9) All references to §63.139(d )(1) in §63.120(d)(1)(ii) of subpart G are not applicable. For sources subject to this subpart , such references shall mean that 40 CFR 61.355 is applicable. (10) All references to §63.139( c) in §63.120(d)(1)(ii) of subpart G are not applicable. For sources subject to this subpart , such references shall mean that §63.647 of this subpart is applicable. (e) When complying with the inspection requir ements of §63.120 of subpart G of this part, owners and operators of storag e vessels at existing sources su bject to this subpart are not required to comply with the provisions for ga skets, 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 cove r 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 whenthe 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 th is 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) a nd (d)(3)(i) shall be replaced with the Notification of Compliance Status report. (j) References to the Notification of Co mpliance Status report in §63.152(b) mean the Notification of Compliance St atus 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)(1 0)(ii), and 63.120(b)(10)(iii) for all or some storagePage 41 of 175

vessels at petroleum refineries subject to this subpart. The State or local permitting authority may also grant permission to refill storage vessels sooner than 30 days after submitting the notifications in §63.120(a)(6) or §63. 120(b)(10)(iii) for all storage ve ssels at a refinery or for individual storage vessel s on a case-by-case basis. § 63.647 Wastewater provisions. (a) Except as provided in paragraph s (b ) and (c ) of this section, each owner or operator of a Group 1 wastewater stream shall comply w ith the requirements of §§61.340 through 61.355 of 40 CFR part 61, subpart FF this chapter for each process wastewater stream that meets the definition in §63.641. (b) As used in this section, a ll terms not defined in §63.641 shall have the meaning given them in the Clean Air Act or in 40 CFR part 61, subpart FF, §61.341. (c ) If a flare is used as a control device, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the requirements of §63.670. Prior to [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the applicable requirements of part 61, subpart FF of this chapter, or the requirements of §63.670. (d ) Each owner or operator requi red under subpart FF of 40 CFR pa rt 61 to perform periodic measurement of benzene concentration in wastewat er, or to monitor pro cess 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 devi ce resulting in a measured conc entration or operating parameter value outside the permitted limits shall constitute a violation of the emission standards. Failure to perform required leak monitoring fo r closed vent systems and contro l devices or failure to repair leaks within the time period speci fied in subpart FF of 40 CFR part61 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 paragr aph (b) of this section except as provided in paragraphs (a )(1), (a)(2), and (c) th rough (i) of this s ection. 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 para graphs (c) through (i) of this section. (1) For purposes of compliance w ith this section, th e provisions of 40 CFR part 60, subpart VV apply only to equipment in organic HAP serv ice, as defined in §63.641 of this subpart. (2) Calculation of percentage leaking equipm ent components for subpart VV of 40 CFR part 60 may be done on a process unit basis or a source wide basis. Once the owner or operator has decided, all subsequent calculati ons shall be on the same basis unless a permit change is made.Page 42 of 175

(3) If a flare is used as a co ntrol device, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the requirements of §63.670. Prior to [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the applicable requirements of part 60, subpart VV of this chapter, or the requirements of §63.670. (b) The use of monitoring data generated be fore August 18, 1995 to qualify for less frequent monitoring of valves and pumps as provided un der 40 CFR part 60 subpart VV or subpart H of this part and paragraph (c) of this section (i.e., quarterly or semia nnually) is governed by the requirements of paragraphs (b)(1 ) and (b)(2) of this section. (1) Monitoring data must meet the test met hods and procedures specified in §60.485(b) of 40 CFR part 60, subpart VV or §63.180(b)(1) through (b )(5) of subpart H of this part except for minor departures. (2) Departures from the criteria specified in §60.485(b) of 40 CFR part 60 subpart VV or §63.180(b)(1) through (b)(5) of subpart H of this part or from the monitoring frequency specified in subpart VV or in paragraph (c) of this section (such as every 6 weeks instead of monthly or quarterly) are minor and do not significantly aff ect the quality of the data. An example of a minor departure is monitoring at a slightly differe nt frequency (such as ev ery 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 provisi ons 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 12 ) and (e) through (i) of this section. (1) The instrument readings that define a l eak for light liquid pump s subject to §63.163 of subpart H of this part and gas/ vapor and light liquid valves s ubject to §63.168 of subpart H of this part are specified in table 2 of this subpart. (2) In phase III of the valve standard, the owne r or operator may monitor valves for leaks as specified in paragraphs (c)(2)(i) or (c)(2)(ii) of this section. (i) If the owner or operator does not elect to monitor connectors, th en 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 acco rding 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 th an the first required monitoring period after the phase I compliance date specifi ed in §63.640(h) whether to calc ulate the percentage leaking valves on a process unit basis or on a sourcewide basis. Once the owner or operator has decided, all subsequent calculations shall be on the same basis unless a permit change is made.Page 43 of 175

(4) The owner or operator shall decide no later th an the first monitoring pe riod after the phase III compliance date specified in §63.640(h) whethe r to monitor connector s according to the provisions in §63.649, paragraphs (b), (c), or (d). (5) Connectors in gas/vapor service or light li quid service are subject to the requirements for connectors in heavy liquid service in §63.169 of subpart H of this part (e xcept for the agitator provisions). The leak definition for valves, conn ectors, 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 pe rcent 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 liqui d pumps leaking or one light liquid pump leaking, whic hever is greater, shall monito r light liquid pumps quarterly. (8) An owner or operator may make the election de scribed 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 te rms of part 70 of this chapter. (9) When complying with the requirements of §63.168(e)(3)(i), non-repairab le valves shall be included in the calculation of percent leaking valves the first time the valve is identified as leaking and non-repairable. Otherw ise, 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 perc ent leaking valves for subsequent monitoring periods. When the number of non-repairable valv es exceeds 3 percent of the total number of valves in organic HAP service, the number of non-repairable valves ex ceeding 3 percent of the total number shall be included in the calculation of percen t leaking valves. (10) If in phase III of the valve standard any va lve is designated as bei ng leakless, the owner or operator has the option of following the provi sions of 40 CFR 60.482–7(f). If an owner or operator chooses to comply with the provisions of 40 CFR 60.482–7(f), the valv e is exempt from the valve monitoring provisions of §63.168 of subpart H of this part. (11) [Reserved] (12) If a flare is used as a control device, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the requirements of §63.670. Prior to [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the applicable requirem ents of §§63.172 and 63.180, or the requirements of §63.670. (d) Upon startup of new sources, the owner or operator shall comply with §63.163(a)(1)(ii) of subpart H of this part for light liquid pumps and §63.168(a)(1)(ii) of subpart H of this part for gas/vapor and light liquid valves.Page 44 of 175

(e) For reciprocating pumps in h eavy liquid service and agitators in heavy li quid 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 se rvice 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 fr om the requirements of paragraphs (a) and (c) of this section if an owner or operator demonstrates that a co mpressor is in hydrogen service. (1) Each compressor is presumed not to be inhydrogen 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 reasonabl y 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 operato r shall use either: (A) Procedures that conform to those speci fied in §60.593(b)(2) of 40 part 60, subpart GGG. (B) Engineering judgment to demonstrate that the percentage conten t 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 Admi nistrator 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 determ ines that a piece of equipmen t is in hydrogen service, the determination can be revised only by following the procedures in paragra ph (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 s eal requirements if recasting the distance piece or compressor replacement is required. (j) Except as specified in paragraph (j)(4) of this section, the ow ner or operator must comply with the requirements specified in paragraphs (j)(1) and (2) of this section for pressure relief devices, such as relief valves or rupture disks, in or ganic HAP gas or vapor service instead of the pressure relief device requirements of §60.482-4 or §63.165, as applicable. Except as specified in paragraphs (j) (4) and (j)(5) of this section, the owner orPage 45 of 175

operator must also comply with the requirements specified in paragraph (j)(3) of this section for all pressure relief devices. (1) Operating requirements . Except during a pressure release, operate each pressure relief device in organic HAP gas or vapor service wi th an instrument reading of less than 500 ppm above background as detected by Method 21 of 40 CFR part 60, Appendix A-7. (2) Pressure release requirements . For pressure relief devices in organic HAP gas or vapor service, the owner or operator must comp ly with the applicable requirements in paragraphs (j)(2)(i) through (iii) of th is section following a pressure release. (i) If the pressure relief device does not co nsist of or include a rupture disk, conduct instrument monitoring, as specified in §60.485(b) or §63.180(c), as applicable, no later than 5 calendar days after the pressure relief device returns to organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operating with an instrument reading of less than 500 ppm. (ii) If the pressure relief device includes a rupture disk , either comply with the requirements in (j)(2)(i) of this section (n ot replacing the rupture disk) or install a replacement disk as soon as practicable af ter a pressure release, but no later than 5 calendar days after the pressu re release. The owner or opera tor must conduct instrument monitoring, as specified in §60.485(b) or §63.180(c) , as applicable, no later than 5 calendar days after the pressure relief device returns to organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operatin g with an instrument reading of less than 500 ppm. (iii) If the pressure relief device consists only of a rupture disk, insta ll a replacement disk as soon as practicable after a pressure release, but no later than 5 calendar days after the pressure release. The owner or operator may no t initiate startup of the equipment served by the rupture disk until the rupture disc is replaced., The owner or operator must conduct instrument monitoring, as specified in §60.485(b) or §63.180(c), as applicable, no later than 5 calendar days after the pressure relief device returns to organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operating with an instrument reading of less than 500 ppm. (3) Pressure release management . Except as specified in paragr aphs (j)(4) and (j)(5) of this section, the owner or operator shall comply with the requirements specified in paragraphs (j)(3)(i) through (v) of this se ction for all pressure relief devi ces in organic HAP service no later than [insert date 3 years and 60 days after date of publication in the Federal Register]. (i) The owner or operator must equip each a ffected pressure relief device with a device(s) or use a monitoring system that is capabl e of: 1) identifying the pressure release; 2) recording the time and duration of each p ressure release; and 3) notifying operators immediately that a pressure release is occurr ing. The device or monitoring system may be either specific to the pressure relief device itself or may be associated with the processPage 46 of 175

system or piping, sufficient to indicate a p ressure release to the atmosphere. Examples of these types of devices and systems include, but are not limited to, a rupture disk indicator, magnetic sensor, motion detector on the p ressure relief valve stem, flow monitor, or pressure monitor. (ii) The owner or operator must apply at least three redundant prev ention measures to each affected pressure relief device and docume nt these measures. Examples of prevention measures include: (A) Flow, temperature, level and pressure indica tors with deadman switches, monitors, or automatic actuators. (B) Documented routine inspection and main tenance programs and/or operator training (maintenance programs and operator traini ng may count as only one redundant prevention measure). (C) Inherently safer designs or safety instrumentation systems. (D) Deluge systems. (E) Staged relief system where initial pressure relief valve (with lower set release pressure) discharges to a flare or other clos ed vent system and control device. (iii) If any affected pressure relief device rele ases to atmosphere as a result of a pressure release event, the owner or operator must perform root cause analysis and corrective action analysis according to the requiremen t in paragraph (j)(6) of this section and implement corrective actions according to th e requirements in paragraph (j)(7) of this section. The owner or operator must also ca lculate the quantity of organic HAP released during each pressure release event and report this quantity as required in §63.655(g)(10)(iii). Calculations may be based on data from the pressure relief device monitoring alone or in combination with pr ocess parameter monitoring data and process knowledge. (iv) The owner or operator shall determine the total number of re lease events occurred during the calendar year for each affected pr essure relief device sepa rately. The owner or operator shall also determine th e total number of release events for each pressure relief device for which the root cause analysis concluded that the root cause was a force majeure event, as defined in this subpart. (v) Except for pressure relief devices described in paragraphs (j)(4) and (5) of this section, the following release events are a violation of the pressure release management work practice standards. (A) Any release event for which the root cause of the event was determined to be operator error or poor maintenance.Page 47 of 175

(B) A second release event not including force ma jeure events from a single pressure relief device in a 3 calendar year period for the same root cause for the same equipment. (C) A third release event not including force ma jeure events from a single pressure relief device in a 3 calendar year period for any reason. (4) Pressure relief devices routed to a control device . If all releases and potential leaks from a pressure relief device are routed through a closed vent system to a control device, back into the process or to the fuel gas system, the own er or operator is not required to comply with paragraphs (j)(1), (2) or (3) (if applicable) of this section. Both the closed vent system and control device (if applicable) must meet the requirements of §63.644. When complying with this paragraph, all references to “Group 1 miscellaneous process vent” in §63.644 mean “pressure relief device.” If a pressure relief devi ce complying with this paragraph is routed to the fuel gas system, then on and after [i nsert date 3 years and 60 days after date of publication in the Federal Register ], any flares receiving gas from that fuel gas system must be in compliance with §63.670. (5) Pressure relief devices exempted from pressure release management requirements . The following types of pressure relief devices are not subject to the pressure release management requirements in paragraph (j)(3). (i) Pressure relief devices in heavy liquid service, as defined in §63.641. (ii) Pressure relief devices that only release mat erial that is liquid at standard conditions (1 atmosphere and 68 degrees Fahrenheit) and that are hard-piped to a controlled drain system (i.e., a drain system meeting the re quirements for Group 1 wastewater streams in §63.647(a)) or piped back to the process or pipeline. (iii) Thermal expansion relief valves. (iv) Pressure relief devices designed with a set relief pressure of less than 2.5 psig. (v) Pressure relief devices that do not have th e potential to emit 72 lbs/day or more of VOC based on the valve diameter, the set release pressure, and the equipment contents. (vi) Pressure relief devices on mobile equipment. (6) Root cause analysis and corrective action analysis. A root cause analysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a release event. Special circumstances affectin g the number of root cause analyses and/or corrective action analyses are provided in paragr aphs (j)(6)(i) through (iv) of this section. (i) You may conduct a single root cause analysis and corrective action analysis for a single emergency event that causes two or more pr essure relief devices installed on the same equipment to release.Page 48 of 175

(ii) You may conduct a single root cause analysis and corrective action analysis for a single emergency event that causes two or more pressure relief devices to release, regardless of the equipment served, if the root cause is reaso nably expected to be a force majeure event, as defined in this subpart. (iii) Except as provided in paragraphs (j)(6)(i) and (ii), if more than one pressure relief device has a release during the same time period , an initial root cause analysis shall be conducted separately for each pressure relief de vice that had a release. If the initial root cause analysis indicates that the release events have the same root cause(s), the initially separate root cause analyses may be recorded as a single root cause analysis and a single corrective action analysis may be conducted. (7) Corrective action implementation . Each owner or operator required to conduct a root cause analysis and corrective action analysis as specified in paragra phs (j)(3)(iii) and (j)(6) shall implement the corrective ac tion(s) identified in the co rrective action analysis in accordance with the applicable requirements in paragraphs (j)(7 )(i) through (iii) of this section. (i) All corrective action(s) must be implemen ted within 45 days of the event for which the root cause and corrective action analyses were required or as soon thereafter as practicable. If an owner or operator conc ludes that no corrective action should be implemented, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the event. (ii) For corrective actions that cannot be fu lly implemented within 45 days following the event for which the root cause and corrective action analyses were required, the owner or operator shall develop an implementation sche dule to complete the corrective action(s) as soon as practicable. (iii) No later than 45 days following the even t for which a root cause and corrective action analyses were required, the owner or operato r shall record the corrective action(s) completed to date, and, for action(s) not alrea dy completed, a schedule for implementation, including proposed commencement and completion dates. § 63.649 Alternative means of emission limi tation: 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 im plement 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 sh all be implemented source-wide.Page 49 of 175

(1) Within the first 12 months after the phase III compliance date specified in §63.640(h), a sample of 200 connectors shall be randomly sele cted 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 repair ed as soon as practicable, but no later than 15 calendar days after the leak is de tected except as provided in paragr aph (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 c onnector shall be monitored for leak s within the first 3 months after its repair. (5) After conducting the init ial 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 th is section. (i) If the percentage leaking connectors is 2.0 percent or great er, 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 pe rcent or greater but less than 2.0 percent, the owner or operator shall survey a random sample of 200 connectors once per year. (iii) If the percentage leaking connectors is 0.5 percent or greater but less than 1.0 percent, the owner or operator shall survey a random sample of 200 connectors once every 2 years. (iv) If the percentage leaking connectors is less than 0.5 percent, the owner or operator shall survey a random sample of 200 connectors once every 4 years. (6) Physical tagging of the connectors to indi cate that they are subject to the monitoring provisions is not required . Connectors may be identified by the area or length of pipe and need not be individually identified. (c) Connector inspec tion alternative . The owner or operator sha ll implement a program to monitor all accessible conn ectors in gas/vapor service that ar e 2.0 inches (nominal diameter) or greater and inspect all accessible connectors in light liquid servi ce 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 complia nce date specified in §63.640(h), all connectors in gas/vapor service shall be monitored usi ng Method 21 of 40 CFR part 60 appendix A. The instrument reading that define s a leak is 1,000 parts per million. (2) All connectors in light liquid service shall be inspected for leaks. A leak is detected if liquids are observed to be dripping at a rate greater than three drops per minute.Page 50 of 175

(3) When a leak is detected, it shall be repair ed as soon as practicable, but no later than 15 calendar days after the leak is de tected except as provided in paragr aph (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 li quid service shall be insp ected for indications of leaks within the first 3 months after repair. A le ak is detected if liqui ds are observed to be dripping at a rate greater th an three drops per minute. (5) After conducting the init ial survey required in paragraphs (c )(1) and (c)(2) of this section, the owner or operator shall conduct subsequent monito ring at the frequencies sp ecified in paragraphs (c)(5)(i) through (c)(5)(iii) of this section. (i) If the percentage leaking connectors is 2.0 percent or great er, the owner or operator shall monitor or inspect, as applicab le, the connectors once per year. (ii) If the percentage leaking connectors is 1.0 pe rcent or greater but less than 2.0 percent, the owner or operator shall monito r 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 ca lculated for connectors in gas/vapor service and for connectors in light liquid service. The datafor the two groups of connectors shall not be pooled for the purpose of determining the percentage l eaking connectors. (i) The percentage leaking connector s shall be calculated as follows:

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

where:

% C L = Percentage leaking connectors.

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

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

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

C c = Optional credit for removed connectors= 0.67×net number (i.e., the total number of connectors removed minus the total added) of c onnectors in organic HAP service removed from the process unit after th e applicability date set forth in §63.640(h)( 4 3 )(iii) for existing process units, and after the date of start-up for new pr ocess units. If credits are not taken, then C c = 0.Page 51 of 175

(ii) Nonrepairable connectors sh all be included in the calcul ation of percentage leaking connectors the first time the connector is identifi ed as leaking and nonrepairable. Otherwise, a number of nonrepairable connect ors up to a maximum of 1 percen t 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 subs equent monitoring periods. (iii) If the number of nonr epairable connectors exceeds 3 pe rcent of the total number of connectors in organic HAP service, the number of nonrepairable connector s exceeding 3 percent of the total number shall be included in the ca lculation of the percenta ge leaking connectors. (7) Physical tagging of the connectors to indi cate that they are subject to the monitoring provisions is not required . Connectors may be identified by the area or length of pipe and need not be individually identified. (d) Subpart H program . The owner or operator shall implem ent 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 re pair techniques without a proce ss 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 conn ectors is also allowed if: (i) The owner or operator determines that emissi ons of purged material resulting from immediate repair would be greater than the fugitive emi ssions 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 desi gnated as an unsafe-to-repair c onnector 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 determ ines that repair personnel woul d be exposed to an immediate danger as a consequence of complying with para graphs (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 record s to document that the connector monitoring or inspections have been conducted as required and to document repair of leaking connectors as applicable.Page 52 of 175

§ 63.650 Gasoline loadin g rack provisions. (a) Except as provided in paragraphs (b) through ( c d ) of this section, each owner or operator of a Group 1 gasoline loading rack classified under Standard Industrial Classification code 2911 located within a contiguous area and under common control with a petroleum refinery shall comply with subpart R, §§63.421, 63.422(a) throu gh (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, a ll terms not defined in §63.641 shall have the meaning given them in subpart A or in 40 CFR part 63, subpart R. Th e §63.641 definition of “affected source” applies under this section. (c) Gasoline loading racks regulated under this subpart are subject to the compliance dates specified in §63.640(h). (d) If a flare is used as a co ntrol device, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the requirements of §63.670. Prior to [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the applicable requirements of s ubpart R of this part, or the requirements of §63.670. § 63.651 Marine tank vessel loading operation provisions. (a) Except as provided in paragraphs (b) through ( d e ) of this section, each owner or operator of a marine tank vessel loading operation located at a petroleum refinery shall comply with the requirements of §§63.560 through 63.568. (b) As used in this section, a ll terms not defined in §63.641 shall have the meaning given them in subpart A or in 40 CFR part 63, subpart Y. Th e §63.641 definition of “affected source” applies under this section. (c) The notification reports unde r §63.567(b) are not required. (d) The compliance time of 4 years after prom ulgation of 40 CFR part63, subpart Y does not apply. The compliance time is specified in §63.640(h)( 3 1 ). (e) If a flare is used as a control device, on and after [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the requirements of §63.670. Prior to [insert date 3 years and 60 days after date of publication in the Federal Register], the flare shall meet the applicable requirements of s ubpart Y of this part, or the requirements of §63.670. § 63.652 Emissions averaging provisions. (a) This section applies to owners or operators of existing sources who seek to comply with the emission standard in §63.642(g) by using emissions averaging according to §63.642(l) ratherPage 53 of 175

than following the provisions of §§63.643 through 63. 645, 63.646 or 63.660, 63. 647, and §§ 63.650 , and 63.651. Existing marine tank vessel load ing 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 sha ll identify all emission points to be included in the emissions average. This must include a ny 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 ge nerate emissions averag ing credits if control was applied after November 15, 1990 and if suffici ent information is avai lable to determine the appropriate value of cred its for the emission point: (1) Group 2 emission points; (2) Group 1 storage vessels, Gr oup 1 wastewater streams, Group 1 gasoline loading racks, Group 1 marine tank vessels, and Gr oup 1 miscellaneous process vent s that are controlled by a technology that the Administrator or permitting aut hority 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 pr ovided in paragraph (i) of this section; and (3) Emission points from which emissions ar e reduced by pollution prevention measures. Percentages of reduction for polluti on prevention measures shall be determined as specified in paragraph (j) of this section. (i) For a Group 1 emission point, the pollution prevention measure must reduce emissions more than the reference control tec hnology would have had the refe rence control technology been applied to the emission point instead of the po llution prevention measure except as provided in paragraph (c)(3)(ii) of this section. (ii) If a pollution prevention measure is used in conjunction with othe r controls for a Group 1 emission point, the pollution prev ention measure alone does not ha ve to reduce emissions more than the reference control tec hnology, 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 ha s been approved for use in a different manner and a higherPage 54 of 175

nominal efficiency has been assign ed 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 refe rence control technology definiti on 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 pe rcent control; (3) Emission points on shutdown process units. Pro cess units that are shut down cannot be used to generate credits or debits; (4) Wastewater that is not process wastewater or wastewater stream s treated in biological treatment units. These two types of wastewater ca nnot be used to generate credits or debits. Group 1 wastewater streams cannot be left underc ontrolled or uncontrolled to generate debits. For the purposes of this section, the terms “was tewater” and “wastewater stream” are used to mean process wastewater; and (5) Emission points controlled to comply with a State or Federal rule ot her 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 contro l above what is required by the other State or Federal rule will be credited. However, if an em ission point has been used to generate emissions averaging credit in an approved emissions average, and the point is subseque ntly made subject to a State or Federal rule other th an this subpart, the point can c ontinue to generate emissions averaging credit for the purpose of complying with the previously approved average. (e) For all points included in an emissi ons average, the owner or operator shall: (1) Calculate and record monthl y debits for all Group 1 emission points that are controlled to a level less stringent than the re ference control technology for thos e emission points. Equations in paragraph (g) of this section shal l be used to calculate debits. (2) Calculate and record monthly credits for all Group 1 or Group 2 em ission points that are overcontrolled to compensate for the debits. Equati ons in paragraph (h) of this section shall be used to calculate credits. Emission points and cont rols that meet the crite ria of paragraph (c) of this section may be included in the credit calculation, whereas t hose described in paragraph (d) of this section shall not be included. (3) Demonstrate that annual cred its calculated according to para graph (h) of this section are greater than or equal to deb its calculated for the same annua l compliance period according to paragraph (g) of this section. (i) The initial demonstration in the Implementa tion Plan that credit-g enerating emission points will be capable of generating sufficient credits to offset the debits from the debit-generating emission points must be made under representative operating conditions. (ii) After the compliance date, actual operating data will be used for all debit and credit calculations.Page 55 of 175

(4) Demonstrate that debits calculated for a qua rterly (3-month) period according to paragraph (g) of this section are not mo re 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 per cent more debits than credits allowed on a quarterly basis. (5) Record and report quarterly and annual credits a nd debits in the Periodic Reports as specified in §63.655(g)(8). Every fourth Peri odic Report shall include a cert ification of compliance with the emissions averaging provision s 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 sect ion, 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 include d in an emissions average are controlled by pollution prevention measures, the averag e may include up to 22 emission points. (2) [Reserved] Periods of startup, shutdown, and malfunction as described in the source’s startup, shutdown, and malfunction plan required by §63.6(e)(3) of subpart A of this part. (3) For emission points for which continuous monito rs are used, periods of excess emissions as defined in §63.655(g)(6)(i). For thes e periods, the calculati on of monthly credit s 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-genera ting 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 partia l credits or debits should be assigned. (g) Debits are generated by the difference betwee n the actual emissions from a Group 1 emission point that is uncontrolled or is controlled to a level less stringe nt than the reference control technology, and the emissions allowed for Group 1 em ission point. Debits shall be calculated as follows: (1) The overall equation for calculating sourcewide debits is:Page 56 of 175



##             

#    

   



###   

 

 

n

i iu iACTUAL n

i iC iACTUAL n

i iu iACTUAL n

i iu iACTUAL



### EMV EMV EGLR EGLR ES ES EPV EPV Debits

1 1 1 1 

### 03.0 05.0 02.0

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

EPV iACTUAL = Emissions from each Group 1 miscellaneous process vent i that is uncontrolled or is controlled to a level less stringent than the reference control technology. This is calculated according to paragraph (g)(2) of this section. (0.02) EPV iu = Emissions from each Group 1 miscellaneous process vent i if the reference control technology had been applied to the unc ontrolled emissions, calculated according to paragraph (g)(2) of this section.

ES iACTUAL = Emissions from each Group 1 storage vessel i that is uncontrolled or is controlled to a level less stringent than the reference control technology. This is calculated according to paragraph (g)(3) of this section. (0.05) ES iu = Emissions from each Group 1 storage ve ssel i if the refere nce control technology had been applied to the uncontrolled emissions, cal culated according to pa ragraph (g)(3) of this section.

EGLR iACTUAL = Emissions from each Group 1 gasoline loading rack i that is uncontrolled or is controlled to a level le ss stringent than the reference c ontrol technology. This is calculated according to paragraph (g)(4) of this section.

EGLR ic = Emissions from each Group 1 gasoline lo ading rack i if th e reference control technology had been applied to the uncontrolled emissions. This is calculated according to paragraph (g)(4) of this section.

EMV ACTUAL = Emissions from each Group 1 marine tank vessel i that is uncontrolled or is controlled to a level le ss stringent than the reference c ontrol technology. This is calculated according to paragraph (g)(5) of this section. (0.03) EMV iu = Emissions from each Group 1 marine tank vessel i if the reference control technology had been applied to the uncontrolled emissions calculated according to paragraph (g)(5) of this section. n = The number of Group 1 emission points being included in the emissions average. The value of n is not necessarily the same for each kind of emission point.Page 57 of 175

(2) Emissions from miscellaneous process vents shall be calculated as follows: (i) For purposes of determining miscellaneous process vent stream fl ow rate, organic HAP concentrations, and temperature, the sampling si te shall be after the final product recovery device, if any recovery devices are present; befo re any control device (for miscellaneous process vents, recovery devices shall no t 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 proce ss vent i to calculate EPV iu : 

#            

## 

  n

j jj iu MCQh EPV

1 9 10494.2

where:

EPV iu = Uncontrolled process vent em ission rate from miscellaneous process vent i, megagrams per month. Q = Vent stream flow rate, dry standard cubi c 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 positiv e flow is present in the vent, hours per month.

C

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

M

j = Molecular weight of organic HAP j, gram per gram-mole. n = Number of organic HAP’s in the miscellaneous process vent stream. (A) The values of Q, C j , and M j shall be determined during a performance test conducted under representative operating condi tions. The values of Q, C j , and M j shall be established in the Notification of Compliance Stat us report and must be update d as provided in paragraph (g)(2)(ii)(B) of this section. (B) If there is a change in cap acity utilization other than a cha nge in monthly operating hours, or if any other change is made to the process or product recovery equipment or operation such that the previously measured values of Q, C j , and M j are no longer representa tive, a new performance test shall be conducted to determine new representative values of Q, C j , and M j . These new values shall be used to calculate debits and cred its from the time of the change forward, and the new values shall be reported in the next Periodic Report.Page 58 of 175

(iii) The following procedures and equa tions shall be used to calculate EPV iACTUAL : (A) If the vent is not controlled by a contro l device or pollution prevention measure, EPV iACTUAL = EPV iu , where EPV iu is calculated according to the pro cedures in paragraphs (g)(2)(i) and (g)(2)(ii) of this section. (B) If the vent is controlled using a control device or a pollu tion prevention measure achieving less than 98-per cent reduction, 

###        %100 1 duction Percent re EPV EPV iu iACTUAL

( 1 ) The percent reduction shall be measured according to the pr ocedures in §63.116 of subpart G if a combustion control device is used. For a flar e meeting the criteria in§63.116(a) of subpart G or §63.670 of this subpart, as applicable , or a boiler or process heat er meeting the criteria in §63.645(d) of this subpart or §63.116(b) of subpart G, the percentage of reduction shall be 98 percent. If a noncombustion control device is used, percentage of reduction shall be demonstrated by a performance test at the inlet and outlet of the device, or, if testing is not feasible, by a control design evaluation and documented engineering calculations. ( 2 ) For determining debits from miscellaneous pr ocess vents, product reco very devices shall not be considered control devices a nd cannot be assigned a percentage of reduction in calculating EPV iACTUAL . The sampling site for measurement of unc ontrolled emissions is after the final product recovery device. ( 3 ) Procedures for calculating the percentage of reduction of pollution prevention measures are specified in paragraph (j) of this section. (3) Emissions from storage vessels shall be calcu lated as specified in §63. 150(g)(3) of subpart G. (4) Emissions from gasoline loading r acks shall be calculated as follows: (i) The following equation shall be used for each gasoline loading rack i to calculate EGLR iu : 

#   T SPMG EGLR iu 7 1020.1  

where:

EGLR iu = Uncontrolled transfer HAP emission rate fr om gasoline loading rack i, megagrams per month S = Saturation factor, dimensionle ss (see table 33 of subpart G).Page 59 of 175

P = Weighted average rack partial pressure of organic HAP’s transferred at the rack during the month, kilopascals. M = Weighted average molecular weight of organic HAP’s transferred at the gasoline loading rack during the month, gram per gram-mole. G = Monthly volume of gasoline transferred from gasoline lo ading rack, liters per month. T = Weighted rack bulk liquid loading temperature during the month, degr ees kelvin (degrees Celsius °C + 273). (ii) The following equation shall be used for each gasoline loading rack i to calculate the weighted average rack partial pressure: 

#   

G GP P j nj j 

# 



 1

where:

P

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

## 



 nj j GG

1 G

j = Monthly volume of individual organic HAP transferred at th e gasoline loading rack, liters per month. n = Number of organic HAP’s transf erred at the gasoline loading rack. (iii) The following equation shall be used for each gasoline loading rack i to calculate the weighted average rack molecular weight: 

#   

G GM M j nj j 

# 



 1

where:

M

j = Molecular weight of indivi dual organic HAP transferred at the rack, gram per gram-mole. G, G j , and n are as defined in paragr aph (g)(4)(ii) of this section.Page 60 of 175

(iv) The following equation shall be used for each gasoline loading rack i to calculate the monthly weighted rack bulk liquid loading temperature: 

#   

G GT T j nj j 

# 





###  1

T

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

G EGLR ic 8 101   G is as defined in paragraph (g)(4)(ii) of this section. (vi) The following procedures and equati ons shall be used to calculate EGLR iACTUAL : (A) If the gasoline loading r ack is not controlled, EGLR iACTUAL = EGLR iu , where EGLR iu is calculated using the equations specifi ed in paragraphs (g)(4)(i) thr ough (g)(4)(iv) of this section. (B) If the gasoline load ing rack is controlled using a control device or a pollution prevention measure not achieving the requirement of less than 10 milligrams of TOC per liter of gasoline loaded,        %100 1 duction Percent re EGLR EGLR iu iACTUAL ( 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 eval uation 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 lo ading shall be calculated as follows: (i) The following equation shall be used fo r each marine tank vessel i to calculate EMV iu : 

##     

## 

  m

i iii iu PFQ EMV

1Page 61 of 175

where:

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

F i = Emission factor, megagrams per liter.

P i = Percent HAP. m = Number of combinations of commodities and vessel types loaded. Emission factors shall be based on test data or emission estimation procedures specified in §63.565(l) of subpart Y. (ii) The following procedures and equa tions shall be used to calculate EMV iACTUAL : (A) If the marine tank vesse l is not controlled, EMV iACTUAL = EMV iu , where EMV iu is calculated using the equations specif ied 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 than97-percent reduction,        %100 1 duction Percent re EMV EMV iu iACTUAL ( 1 ) The percent reduction for a control device shall be measured according to the procedures and test methods specified in §63.565(d) of subpart Y. If testing is not feasible, the percentage of reduction shall be determined through a design eval uation 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 betwee n emissions that are allowed for each Group 1 and Group 2 emission point and the actual emi ssions from a Group 1 or Group 2 emission point that has been controlled after N ovember 15, 1990 to a level more stringent than what is required by this subpart or any other State or Federal rule or statute. Cred its shall be calculated as follows: (1) The overall equation for calcu lating sourcewide credits is:Page 62 of 175



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

#         



        



 

 

 

 

 

 

 

 

 

 

m

i iACTUAL iBASE n

i iACTUAL ic m

i iACTUAL iBASE n

i iACTUAL iu m

i iACTUAL iBASE n

i iACTUAL ic m

i iACTUAL iBASE n

i iACTUAL iu m

i iACTUAL iBASE n

i iACTUAL iu

EWW2 EWW2 D EWW1 EWW1 D EMV2 EMV2D EMV1 EMV1 D EGLR2 EGLR2 D EGLR1 EGLRD ES2 ES2D ES1ES1 D EPV2 EPV2D EPV1 EPV1 DCredits

1 1 1 1 1 1 1 1 1

1

03.0

05.0

02.0

where: Credits and all terms of the equa tion are in units of megagrams pe r month, the baseline date is November 15, 1990, and D = Discount factor = 0.9 for all credit-generating emission points excep t those controlled by a pollution prevention measure, which will not be discounted.

EPV1 iACTUAL = Emissions for each Group 1 miscellaneous process vent i that is controlled to a level more stringent than the reference control technology, calculated according to paragraph (h)(2) of this section. (0.02) EPV1 iu = Emissions from each Group 1 miscellaneous process vent i if the reference control technology had been applied to the uncontrolled emissions. EPV1 iu is calculated according to paragraph (h)(2) of this section.

EPV2 iBASE = Emissions from each Group 2 miscellaneous process vent; at the baseline date, as calculated in paragraph (h )(2) of this section.

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

ES1 iACTUAL = Emissions from each Group 1 storage vesse l i that is controlle d to a level more stringent than the reference cont rol technology, calculated according to paragraph (h)(3) of this section. (0.05) ES1 iu = Emissions from each Group 1 storage ve ssel i if the refere nce control technology had been applied to the uncontrolled emissions. ES1 iu is calculated according to paragraph (h)(3) of this section.

ES2 iACTUAL = Emissions from each Group 2 storage ve ssel i that is controlled, calculated according to paragraph (h)(3) of this section.Page 63 of 175

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

EGLR1 iACTUAL = Emissions from each Group 1 gasoline lo ading rack i that is controlled to a level more stringent than the reference control technology, calculated according to paragraph (h)(4) of this section.

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

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

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

EMV1 iACTUAL = Emissions from each Group 1 marine tank vessel i that is controlled to a level more stringent than the reference control tec hnology, calculated according to paragraph (h)(4) of this section. (0.03)EMV1 iu = Emissions from each Group 1 marine tank vessel i if the reference control technology had been applied to the uncontrolled emissions. EMV1 iu is calculated according to paragraph (h)(5) of this section.

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

EMV2 iBASE = Emissions from each Group 2 marine ta nk vessel i at the baseline date, as calculated in paragraph (h )(5) of this section.

EWW1 iACTUAL = Emissions from each Group 1 wastewater stream i that is controlled to a level more stringent than the reference control tec hnology, calculated according to paragraph (h)(6) of this section.

EWW1 ic = Emissions from each Group 1 wastewater stre am i if the reference control technology had been applied to the uncontrolled emissions, cal culated according to pa ragraph (h)(6) of this section.

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

EWW2 iBASE = Emissions from each Group 2 wastewater stream i at the baseline date, calculated according to paragraph (h)(6) of this section.Page 64 of 175

n = Number of Group 1 emission poi nts included in the emissions av erage. The value of n is not necessarily the same for each kind of emission point. m = Number of Group 2 emission points included inthe 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 re ference control technol ogy, the percentage of reduction for calculating credits shall be no greater than the nominal efficiency associated with the reference control technology, unl ess a higher nominal efficiency is assigned as specified in paragraph (h)(1)(ii) of this section. (ii) For an emission point controlled to a le vel 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 c ontrol 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 usi ng a pollution prevention measure, the nominal efficiency for calculating credits shall be determined as described in paragra ph (j) of this section. (2) Emissions from process vents sh all be determined as follows: (i) Uncontrolled emissions from mi scellaneous process vents, EPV1 iu , shall be calculated according to the procedures and equation for EPV iu in paragraphs (g)(2)(i) and (g)(2)(ii) of this section. (ii) Actual emissions from mi scellaneous process vents contro lled using a technology with an approved nominal efficiency greater than 98 pe rcent or a pollution prev ention measure achieving greater than 98 percent emission reduction, EPV1 iACTUAL , shall be calculated according to the following equation: 

###        %100 1 iciency% Nominal ef EPV1 EPV1 iu iACTUAL

(iii) The following procedures shall be used to calculate actual emissions from Group 2 process vents, EPV2 iACTUAL : (A) For a Group 2 process vent controlled by a c ontrol device, a recovery device applied as a pollution prevention project, or a pollution prev ention measure, if the control achieves a percentage of reduction less than or equal to a 98 pe rcent reduction,        %100 1 duction Percent re EPV2 EPV2 iu iACTUALPage 65 of 175

( 1 ) EPV2 iu shall be calculated according to th e equations and procedures for EPV iu in paragraphs (g)(2)(i) and (g)(2)(ii) of this section excep t as provided in para graph (h)(2)(iii)(A)( 3 ) of this section. ( 2 ) The percentage of reduction sh all 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 pa rt of a pollution prevention project, EPV2 iu shall be calculated prior to that recovery device. The equation for EPV iu in paragraph (g)(2)(ii) of this section shall be used to calculate EPV2 iu ; however, the sampling site for measurement of vent stream flow rate and organic HAP concentration shall be at the inlet of the recovery device. ( 4 ) If a recovery device was adde d as part of a pollution prevention project, the percentage of reduction shall be demonstrated by conducting a perf ormance test at the in let and outlet of that recovery device. (B) For a Group 2 process vent controlled us ing a technology with an approved nominal efficiency greater than a 98 percent or a pollu tion prevention measure achieving greater than 98 percent reduction, 

###        %100 1 iciency% Nominal ef EPV2 EPV2 iu iACTUAL

(iv) Emissions from Group 2 pr ocess vents at baseline, EPV2 iBASE , shall be calculated as follows: (A) If the process vent was uncontrolled on November 15, 1990, EPV2 iBASE = EPV2 iu , and shall be calculated according to the procedures and equation for EPV iu in paragraphs (g)(2)(i) and (g)(2)(ii) of this section. (B) If the process vent was controlled on November 15, 1990,        %100 1 duction Percent re EPV2 EPV2 iu BASE

where EPV2 iu is calculated according to the procedures and equation for EPV iu in paragraphs (g)(2)(i) and (g)(2)(ii) of this section. The per centage 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 adde d to a process vent as part of a pollution prevention project initiated after November 15, 1990, EPV2 iBASE = EPV2 iu , where EPV2 iu is calculated according to paragraph (h)(2)(iii)(A)( 3 ) of this section.Page 66 of 175

(3) Emissions from storage vessels shall be dete rmined as specified in §63.150(h)(3) of subpart G, except as follows: (i (i) For storage vessels complying with §63.646: (A ) All references to §63.119(b) in §63.150(h)(3) of subpart G shall be replaced with: §63.119 (b) or §63.119(b) except for §63.119(b)(5) and (b)(6). ( ii B ) All references to §63.119(c) in §63.150(h)(3) of subpart G shall be replaced with: §63.119(c) or §63.119(c) except for §63.119(c)(2). ( iii C ) All references to §63.119(d) in §63.150(h)(3 ) of subpart G shall be replaced with: §63.119(d) or §63.119(d) except for §63.119(d)(2). (ii) For storage vessels complying with §63.660: (A) Sections 63.1063(a)(1)(i), (a)(2 ), and (b) or §§63.1063(a)(1)(i) and (b) shall apply instead of §63.119(b) in §63.150(h)(3) of subpart G. (B) Sections 63.1063(a)(1)(ii), (a)(2), and (b) shall appl y instead of §63.119(c) in §63.150(h)(3) of subpart G. (C) Sections 63.1063(a)(1)(i), (a)(2 ), and (b) or §§63.1063(a)(1)(i) and (b) shall apply instead of §63.119(d) in §63.150(h)(3) of subpart G. (4) Emissions from gasoline loading r acks shall be determined as follows: (i) Uncontrolled emissions from Gro up 1 gasoline loading racks, EGLR1 iu , shall be calculated according to the procedures and equations for EGLR iu as described in paragraphs (g)(4)(i) through (g)(4)(iv) of this section. (ii) Emissions from Group 1 gasoline loading rack s if the reference control technology had been applied, EGLR ic , shall be calculated according to the procedures and equations in paragraph (g)(4)(v) of this section. (iii) Actual emissions from Group 1 gasoline loading racks controlled to less than 10 milligrams of TOC per liter of gasoline loaded; EGLR iACTUAL , shall be calculated according to the following equation:        %100 1 ficiency% Nominal ef EGLR1 EGLR1 iu iACTUAL (iv) The following procedures shall be used to calculate actual emissions from Group 2 gasoline loading racks, EGLR2 iACTUAL :Page 67 of 175

(A) For a Group 2 gasoline loadi ng rack controlled by a control device or a pollution prevention measure achieving emissions reduction but where emissions are greater than the 10 milligrams of TOC per liter of gasoline loaded requirement,         %100 1 duction Percent re EGLR2 EGLR2 iu iACTUAL ( 1 ) EGLR2 iu shall be calculated according to th e equations and procedures for EGLR iu in paragraphs (g)(4)(i) through (g )(4)(iv) of th is section. ( 2 ) The percentage of reduction sh all 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 loadi ng rack controlled by using a technology with an approved nominal efficiency greater than 98 percent or a pollution prevention measure achieving greater than a 98-percent reduction,         %100 1 ficiency Nominal ef EGLR2 EGLR2 iu iACTUAL (v) Emissions from Group 2 gasoline loading racks at baseline, EGLR2 iBASE , shall be calculated as follows: (A) If the gasoline loading rack wa s uncontrolled on November 15, 1990, EGLR2 iBASE = EGLR2 iu , and shall be calculated according to the procedures and equations for EGLR iu in paragraphs (g)(4)(i) through (g )(4)(iv) of th is section. (B) If the gasoline lo ading rack was controlled on November 15, 1990,         %100 1 duction Percent re EGLR2 EGLR2 iu iBASE

where EGLR2 iu is calculated according to the pr ocedures and equations for EGLR iu in paragraphs (g)(4)(i) through (g)(4)(i v) of this section. Percentage of reduction sha ll 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, EMV1 iu , shall be calculated according to the procedures and equations for EMV iu as described in paragraph (g)(5)(i) of this section. (ii) Actual emissions from Gr oup 1 marine tank vessels contro lled using a technology or pollution prevention measure with an approved no minal efficiency greater than 97 percent, EMV iACTUAL , shall be calculated according to the following equation:Page 68 of 175

       %100 1 ficiency Nominal ef EMV1 EMV1 iu iACTUAL (iii) The following procedures shall be used to calculate actual emissions from Group 2 marine tank vessels, EMV2 iACTUAL : (A) For a Group 2 marine tank ve ssel controlled by a control device or a pollution prevention measure achieving a percentage of reduction le ss than or equal to 97 percent reduction,        %100 1 duction Percent re EMV2 EMV2 iu iACTUAL ( 1 ) EMV2 iu shall be calculated according to th e equations and procedures for EMV iu in paragraph (g)(5)(i) of this section. ( 2 ) The percentage of reduction sh all 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 ve ssel controlled using a technology or a pollution prevention measure with an approved nominal efficiency greater than 97 percent,        %100 1 ficiency Nominal ef EMV2 EMV2 iu iACTUAL (iv) Emissions from Group 2 mari ne tank vessels at baseline, EMV2 iBASE , shall be calculated as follows: (A) If the marine terminal was uncontrolled on November 15, 1990, EMV2 iBASE equals EMV2 iu , and shall be calculated according to the procedures and equations for EMV iu in paragraph (g)(5)(i) of this section. (B) If the marine tank vessel wa s controlled on November 15, 1990,        %100 1 duction Percent re EMV2 EMV2 iu iBASE

where EMV2 iu is calculated according to the procedures and equations for EMV iu in paragraph (g)(5)(i) of this section. Percenta ge of reduction shall be calculate d according to the procedures in paragraphs (g)(5)(ii)(B)( 1 ) and (g)(5)(ii)(B)( 2 ) of this section. (6) Emissions from wastewater shall be determined as follows: (i) For purposes of paragraphs (h)(4)(ii) through (h)(4)(vi) of this section, the following terms will have the meaning given them in paragraphs (h)(6)(i)(A) through (h)(6)(i )(C) of this section.Page 69 of 175

(A) Correctly suppressed means that a wastewater stream is being managed according to the requirements of §§61.343 through 61.347 or §61.342(c)(l)( iii) of 40 CFR part 61, subpart FF, as applicable, and the emissions from the waste mana gement 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 bi ological treatment units. (C) Vapor control device means the control device that receives emissions vented from a treatment process or treatment processes. (ii) The following equation shall be used fo r each wastewater stream i to calculate EWW ic : 

#      

#     

##  

 

   

  s

m imm ii s

m immm ii ic HAPFrHQ HAPFeFrHQ EWW

1 8

1 8 100.605.0 1 100.6

where:

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

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

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

Fe m =Fraction emitted of organic HAP m in wa stewater from table 7 of this subpart, dimensionless. s = Total number of organic HAP’s in wastewater stream i.

HAP im = Average concentration of organic HAP m inwastewater stream i, parts per million by weight. (A) HAP im shall be determined for the point of ge neration 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 CF R part 60, appendix A. Where feas ible, 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 mi nimum of three represen tative samples shall be collected in a manner to minimize exposure of the sample to the atmosphere and loss of organic HAP’s prior to sampling. The samples collected may be analyzed by either of the following procedures:Page 70 of 175

( 1 ) A test method or results from a test method th at measures organic HAP concentrations in the wastewater, and that has been validated pursuant to section 5. 1 or 5.3 of Method 301 of appendix A of this part may be used; or ( 2 ) Method 305 of appendix A of this part may be used to determine C im , the average volatile organic HAP concentration of organic HAP m in wastewater stream i, and then HAP im may be calculated using the following equation: HAP im = C im /Fm m , where Fm m for organic HAP m is obtained from table 7 of this subpart. (B) Values for Q i , HAP im , and C im shall be determined during a performance test conducted under representative conditions. The average value obtained from three test runs shall be used. The values of Q i , HAP im , and C im shall be established in the Notification of Compliance Status report and must be updated as provided in paragraph (h)(6)(i)(C) of this section. (C) If there is a change to the process or operation such that the previously measured values of Q i , HAP im , and C im are no longer representative, a new perf ormance test shall be conducted to determine new representative values of Q i , HAP im , and C im . These new values shall be used to calculate debits and credits from the time of th e change forward, and the new values shall be reported in the next Periodic Report. (iii) The following equations sh all be used to calculate EWW1 iACTUAL for each Group 1 wastewater stream i that is corr ectly suppressed and is treated to a level more stringent than the reference control technology. (A) If the Group 1 wastewater stream i is cont rolled using a treatment process or series of treatment processes with an appr oved nominal reduction efficiency for an individually speciated HAP that is greater than that sp ecified in table 7 of this subpart, and the vapor control device achieves a percentage of reduction equal to 95 percent, the following eq uation shall be used: 

#     

##     

#     

##  

 

     s

m imim ii s

m im imm ii iACTUAL PRHAPHQ PR HAPFeHQ EWW1

1 8

1 8 100.605.0 1 100.6

Where:

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

PR im = The efficiency of the treatment process, or series of treatment processes, that treat wastewater stream i in reducing the emissi on potential of organic HAP m in wastewater, dimensionless, as calculated by:

inim outim inim im HAP HAP HAP PR

    

Where:Page 71 of 175

HAP im-in = Average concentration of organic HAP m, parts per million by weight, as defined and determined according to paragraph (h)(6)(ii)(A) of this section, in the wastewater entering the first treatment process in the series.

HAP im-out = Average concentration of organic HAP m, parts per million by weight, as defined and determined according to paragraph (h)(6)(ii)(A) of this section, in the wastewater exiting the last treatment process in the series.

All other terms are as defined and determined in paragraph (h)(6)(ii ) of this section. (B) If the Group 1 wastewater stre am i is not controlled using a treatment process or series of treatment processes with an appr oved nominal reduction efficiency for an individually speciated HAP that is greater than that sp ecified in table 7 of this subpart , but the vapor c ontrol device has an approved nominal efficiency greater than 95 percent, the fo llowing equation shall be used: 

##     

###   

##     

##  

 

           s

m mim ii s

m m im m ii iACTUAL AHAPHQ ficiency% Nominal ef AHAPFeHQ EWW1

1 8

1 8 100.6 100 11 100.6

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

A m = The efficiency of the treatment process, or series of treatment processes, that treat wastewater stream i in reducing the emissi on 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 m eeting the specifications in the defi nition of reference control technology for wastewater is used, A m shall be equal to the value of Fr m given in table 7 of this subpart. ( 2 ) If an alternative control device is used, the percentage of re duction must be determined using the equation and methods specified in paragraph (h)(6)(iii)(A) of this section for determining PR im . If the value of PR im is greater than or equal to the value of Fr m given in table 7 of this subpart, then A m equals Fr m unless a higher nominal efficiency has been approved. If a higher nominal efficiency has been approved for the tr eatment process, the owner or operator shall determine EWW1 iACTUAL according to paragraph (h)(6)(iii)(B ) of this section rather than paragraph (h)(6)(iii)(A) of this section. If PR im is less than the value of FR m

given in table 7 of this subpart, emissions averaging shall not be used for this emission point. (C) If the Group 1 wastewater stream i is cont rolled using a treatment process or series of treatment processes with an appr oved nominal reduction efficiency for an individually speciated hazardous air pollutant that is grea ter than that specified in table 7 of this subpart, and the vaporPage 72 of 175

control device has an approved nominal effici ency greater than 95 percent, the following equation shall be used: 

##     

###   

##     

##  

 

           s

m imim ii s

m im imm ii iACTUAL PRHAPHQ ficiency% Nominal ef PR HAPFeHQ EWW1

1 8

1 8 100.6 100 1 1 100.6

where all terms are as defined and determined in paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of this section. (iv) The following equation shal l be used to calculate EWW2 iBASE for each Group 2 wastewater stream i that on November 15, 1990 was not corr ectly suppressed or was correctly suppressed but not treated: 

#   

   s

m imm ii iBASE HAPFeHQ EWW

1 8 100.62

Where:

EWW2 iBASE = Monthly wastewater streamemission rate if wastewater stream i is not correctly suppressed, megagrams per month. Q i , H i , s, Fe m , and HAP im are as defined and determined according to paragraphs (h)(6)(ii) and (h)(6)(iii)(A) of this section. (v) The following equation shall be used to calculate EWW2 iBASE for each Group 2 wastewater stream i on November 15, 1990 was correctly suppressed. EWW2 iBASE shall be calculated as if the control methods being used on November 15, 1990 are in place and any control methods applied after November 15, 1990 are ignored. However, values for the parameters in the equation shall be representative of present pro duction levels and stream properties. 

#     

##   

#     

##  

 

           s

m imim ii i s

m im imm ii iBASE PRHAPHQ R PR HAPFeHQ EWW2

1 8

1 8 100.6 %100 1 1 100.6

where R i is calculated according to para graph (h)(6)(vii) of this sec tion 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 stream s that are correc tly suppressed, EWW2 iACTUAL shall be calculated according to the equation for EWW2 iBASE in paragraph (h)(6)(v ) of this section. EWW2 iACTUAL shall be calculated with all control methods in place accounted for. (vii) The reduction efficiency, R i , of the vapor control device sha ll be demonstrated according to the following procedures:Page 73 of 175

(A) Sampling sites shall be selected using Method 1 or 1A of 40 CFR part 60, appendix A, as appropriate. (B) The mass flow rate of organic compounds en tering 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 pe riod during the test. For each run: ( i ) The volume exhausted shall be determined us ing 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 exiti ng the control device shall be determined using Method 18 of 40 CFR part 60, appendix A. Alternatively, any other test method validated according to th e procedures in Method 301 of a ppendix A of this part may be used. ( 3 ) The mass flow rate of organic compounds ente ring and exiting the control device during each run shall be calculated as follows:

               

  

## 

  n

p iaip m

p ap a MWCV m E

1 1 6 10 0416.0

               

  

## 

  n

p ibip m

p bp b MWCV m E

1 1 6 10 0416.0

Where:

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

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

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

V bp = Average volumetric flow rate of vent streamentering the control de vice during run p at standards conditions, cubic meters per hour. p = Run.

m = Number of runs.Page 74 of 175

C aip = Concentration of organic compound i measur ed in the vent stream exiting the control device during run p as determined by Method 18 of 40 CFR part 60 appendix A, parts per million by volume on a dry basis.

C bip = Concentration of organic compound i measured in the vent stream entering the control device during run p as determined by Method 18 of 40 CFR part 60, appendix A, parts per million by volume on a dry basis.

MW i = Molecular weight of organic compound i inthe vent stream, kilograms per kilogrammole. n = Number of organic com pounds in the vent stream. 0.0416 = Conversion factor for molar volume, kilogr ams-mole per cubic meter at 293 kelvin and 760 millimeters mercury absolute. (C) The organic reduction efficiency for the co ntrol device shall be calculated as follows:

100    b ab

E EE R

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

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

E a= Mass flow rate of organic compounds exit ing 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 refere nce control technologies and achieve greater percentages of reduction than th e percentages of efficiency as signed to the reference control technologies in §63.641. (1) In those cases where the owne r or operator is seeking permissi on to take credit for use of a control technology that is different in use or de sign 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 subm it 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 emissi on 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 tec hnology or determine its performance;Page 75 of 175

(ii) Description of the control tec hnology including desi gn specifications; (iii) Documentation demonstrating to the Administrator’s satisfaction the control efficiency of the control technology. This may in clude performance test data co llected using an appropriate EPA method or any other method validated accord ing to Method 301 of appendix A of this part. If it is infeasible to obtain test data, do cumentation may include a design evaluation and calculations. The engineering basis of the calcula tion procedures and all inputs and assumptions made in the calculations shall be documented; and (iv) A description of the parame ter or parameters to be monito red to ensure that the control technology will be operated in conf ormance 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 effici ency. 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 sh all have a nominal efficiency and the level of that nominal efficiency. If, in the Administrator’s judgmen t, the control technology achieves a level of emission reduction greater than the reference control technology for a part icular 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 owne r or operator is seeking permissi on to take credit for use of a control technology that is different in use or de sign 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 us e of the control techno logy 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 th e nominal efficiency for the different technology. (ii) If, in reviewing the submittal, the permitti ng 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 shal l not affect the permitting authority’s approval of the nominal efficiency of the c ontrol technology for the specific application.Page 76 of 175

(6) If, in reviewing an application for a control technology for an emission point, the Administrator or permitting authority determines the control technology is not different in use or design from the reference control technology, the Administrator or permitting authority shall deny the application. (j) The following procedures shall be used for calculating the efficiency (percentage of reduction) of pollution prevention measures: (1) A pollution prevention measure is any practice that meets the cr iteria of paragraphs (j)(1)(i) and (j)(1)(ii) of this section. (i) A pollution prevention measure is any practice th at results in a lesser qu antity of organic HAP emissions per unit of product released to the atmosphere prior to out-of-process recycling, treatment, or control of emissions while the same product is produced. (ii) Pollution prevention measures may includ e: Substitution of feedstocks that reduce HAP emissions, alterations to the production process to reduce the volume of materials released to the environment, equipment modifications; housekee ping measures, and in-process recycling that returns waste materials direc tly to production as raw materi als. Production cutbacks do not qualify as pollution prevention. (2) The emission reduction efficiency of pollu tion 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 paragra phs (g) and (h) of this section. (i) For pollution preventi on measures, the percentage of re duction used in the equations in paragraphs (g)(2) and (g)(3) of this section and pa ragraphs (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 preventi on 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 th e two monthly periods. (ii) The following equation shall be used to ca lculate the percentage of reduction of a pollution prevention measure for each emission point. 

#  

%100  

 B pp Bpp B E P PE E duction Percent re

Where: Percent reduction = Efficiency of pollution pr evention measure (percentage of organic HAP reduction).Page 77 of 175

E B = Monthly emissions before the pollution prevention measure, megagrams per month, determined as specified in paragraphs (j)(2)(ii)(A), (j)(2)(ii)(B), and (j)(2)(ii)(C) of this section.

E pp = Monthly emissions after the pollution pr evention measure, megagrams per month, as determined for the most recent month, determined as specified in paragraphs (j)(2)(ii)(D) or (j)(2)(ii)(E) of this section.

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

P pp = Monthly production after the pollution prev ention measure, megagrams per month, as determined for the most recent month. (A) The monthly emissions before the pollution prevention measure, E B , shall be determined in a manner consistent with the equations and procedur es in paragraphs (g)(2 ), (g)(3), (g)(4), and (g)(5) of this section for miscellaneous process ve nts, storage vessels, gasoline loading racks, and marine tank vessels. (B) For wastewater, E B shall be calculated as follows: 

#    

          n

i s

m Bim m BiBi B HAPFeHQ E

1 1 8 100. 6

where:

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

H Bi = Number of hours per month that wastewater stream i was discharged before the pollution prevention measure, hours per month. s = Total number of organic HAP’s in wastewater stream i.

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

HAP Bim = Average concentration of organic HAP m in wastewater stream i, defined and determined according to paragraph (h)(6)(ii)(A)( 2 ) of this section, before the pollution prevention measure, parts per million by weight, as measured before the implementation of the pollution measure. (C) If the pollution prevention measure was impl emented prior to July 14, 1994, records may be used to determine E B .Page 78 of 175

(D) The monthly emissions after th e pollution prevention measure, E pp , may be determined during a performance test or by a design evalua tion and documented engineering calculations. Once an emissions-to-production ratio has been es tablished, the ratio can be used to estimate monthly emissions from m onthly production records. (E) For wastewater, E pp shall be calculated using the following equation: 

#    

          n

i s

m ppim m ppippi pp HAPFeHQ E

1 1 8 100. 6

where n, Q, H, s, Fe m , and HAP are defined and determined as described in paragraph (j)(2)(ii)(B) of this section except that Q ppi , H ppi , and HAP ppim shall be determined after the pollution prevention measure has been implemented. (iii) All equations, calculations, test procedures, test results, and other information used to determine the percentage of reduction achieve d 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 reducti on 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 se ction used to calculate credits for emission points controlled more stringently than the reference control technology, the nominal efficiency of a polluti on prevention measure is equivalent to the percentage of reduction of the pollution prev ention 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 subj ect 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 accord ing to the provisions in §§63.643 through 63. 645, 63.646 or 63.660, 63. 647, and §§ 63.650 , and 63.651 , as applicable

. (1) This demonstration of hazard or risk equivalency shall be made to the satisfaction of the State or local permitting authority. (i) The State or local permitting authority may require owners and operators to use specific methodologies and procedures for making a hazard or risk determination. (ii) The demonstration and approva l of hazard or risk equivalency may be made according to any guidance that the EPA makes available for use.Page 79 of 175

(2) Owners and operators shall provide docum entation demonstrating the hazard or risk equivalency of their proposed emissions average in their Implementation Plan. (3) An emissions averaging plan that does not dem onstrate an equivalent or lower hazard or risk to the satisfaction of the State or local permitti ng authority shall not be approved. The State or local permitting authority may require such adjust ments to the emissions averaging plan as are necessary in order to ensure that the average wi ll not result in greater hazard or risk to human health or the environment than would result if the emission points were controlled according to §§63.643 through 63. 645, 63.646 or 63.660, 63. 647, and §§ 63.650 , and 63.651 , as applicable

. (4) A hazard or risk equivalency demonstration shall: (i) Be a quantitative, bona fide chemical hazard or risk assessment; (ii) Account for differences in chemical hazard or risk to human health or the environment; and (iii) Meet any requirements set by the State or local permitting authority for such demonstrations. (l) For periods of excess emissions, an owner or operator may request th at 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 ex cess emissions in the Periodic Reports as required in §63.655(g)(6). (2) The owner or operator shall de monstrate that other types of m onitoring data or engineering calculations are appropriate to establish that the control device for the emission point was operating in such a fashion to warrant assign ing full or partial credits and debits. This demonstration shall be made to the Administ rator’s satisfaction, and the Administrator may establish procedures for demonstrating compliance that are acceptable. (3) The owner or operator shall provide documentation of the peri od of excess emissions and the other type of monitoring data or engineering cal culations 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 cr edit 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 em issions average, the ow ner or operator shall perform testing, monitoring, record keeping, and reporting equivalent to that required for Group 1 emission points complying with §§63.643 through 63. 645, 63.646 or 63.660, 63. 647, and §§ 63.650 , and 63.651 , as applicable . The specific requirements for miscellaneous process vents,Page 80 of 175

storage vessels, wastewater, gasoline loading rack s, and marine tank vessels are identified in paragraphs (a)(1) through ( a)( 7) of this section. (1) The source shall implement the following te sting, monitoring, recordkeeping, and reporting procedures for each miscellaneous process vent e quipped with a flare, incinerator, boiler, or process heater: (i) Conduct initial performance te sts 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 proc edures 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 proce dures for each storage vessel controlled with an internal floating roof, extern al roof, or a closed vent system with a control device, as appropriate to the control technique: (i) Perform the monitoring or inspection procedures in §63.646 of this subpart and either §63.120 of subpart G or §63.1063 of subpart WW, as applicable ; and (ii) For closed vent systems with control de vices, conduct an initial design evaluation as specified in §63.646 of this subpart and either §63.120(d) of subpart G or §63.985(b) of subpart SS, as applicable

. (4) For each gasoline loading rack that is controlled, perform the testing and monitoring procedures specified in §§63.425 and 63.427 of subpart R of this part except §63.425(d) or §63.427(c). (5) For each marine tank vesse l that is controlled, perform the compliance, monitoring, and performance testing, procedur es specified in §§63.563, 63.564, and 63.565 of subpart Y of this part. (6) The source shall implement the following proc edures for wastewater emission points, as appropriate to the control techniques: (i) For wastewater treatment processes, conduct tests as specified in §61.355 of subpart FF of part 60;Page 81 of 175

(ii) Conduct inspections and monitoring as specified in §§61.343 through 61.349 and §61.354 of 40 CFR part 61, subpart FF. (7) If an emission point in an emissions av erage is controlled usi ng a pollution prevention measure or a device or technique for which no m onitoring parameters or inspection procedures are specified in §§63.643 through 63. 645, 63.646 or 63.660, 63. 647 and §§ , 63.650 , and 63.651 , as applicable , the owner or operator shall establish a site-specific monitoring parameter and shall submit the informati on specified in §63.655(h)(4) inthe Implementation Plan. (b) Records of all information required to calculate emission de bits and credits and records required by §63.655 shall be re tained 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 s ource who elects to comply with §63.655(g) and (h) by using emissions averaging for any emission points shall submit an Implementation Plan. (1) The Implementation Plan shall be submitted to the Administrator and approved prior to implementing emissions averaging. This information may be submitted in an operating permit application, in an amendment to an operating pe rmit application, in a separate submittal, in a Notification of Compliance Status Report, in a Periodic Report or in a ny combination of these documents. If an owner or operator submits the info rmation 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 in formation 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 inthe 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 cr edits for each emission poi nt and the sum for the emission points involved in the average calcu lated according to §63.652. The annual projected credits must be greater than the projec ted debits, as requi red 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 identifica tion of each emission point aff ected by a pollution prevention measure. To be considered a pollution prevention measure, the criteria in §63.652(j)(1) must be met. If the same pollution prevention measure reduces or eliminates emissions from multiple emission points in the average, the owner or operator must identify each of these emission points.Page 82 of 175

(v) A statement that the compliance demonstr ation, 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 determ ine whether each emission point in the emissions average is Group 1 or Group 2. (B) The estimated values of all parameters need ed 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 th e 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 techno logy, as defined in §63.641, is or will be applied to the emission point. (D) The anticipated nominal efficiency if a c ontrol technology achieving a greater percentage emission reduction than the efficiency of the refere nce 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 speci fied in §63.655(h)(4) for: (A) Each miscellaneous process vent controlle d 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 controll ed by a pollution prevention measur e or a control technique other than an internal or external floating roof or a closed vent system with a control device. (viii) Documentation of the information li sted in paragraphs (d)(2)(viii)(A) through (d)(2)(viii)(G) of this section for each process wastewater stream 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 need ed 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 pro cesses that achieves an emission reduction less than or equal to the emission reduction speci fied in table 7 of this subpart.Page 83 of 175

(D) The estimated percentage of reduction if a control technology achieving less than or equal to 95 percent emission reduction is or will be applie d 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 e fficiency 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 emi ssion reduction specified in ta ble 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, treatmen t process, or control device used to reduce air emissions of organic HAP from wastewater and for whic h no monitoring parameters or inspection procedures are specified in §63.647, th e information specified in §63.655(h)(4) shall be included in the Implementation Plan. (ix) Documentation required in §63.652(k) demons trating 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 shal l either approve the Implementation Plan, request changes, or request that the owner or operator submit additional information. Once the Administrator receives su fficient information, the Administrator shall approve, disapprove, or reque st changes to the plan within 120 calendar days. § 63.654 Heat exchange systems. (a) Except as specified in paragra ph (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 re quirements in paragraphs (c) through (g) of this section if all heat exchangers within the heat exchange system either: (1) Operate with the minimum pressure on the coo ling water side at leas t 35 kilopascals greater than the maximum pressure on the process side; or (2) Employ an intervening cooling fluid containing less than 5 percent by we ight of total organic HAP, as determined according to the provisions of §63.180(d) of this part and table 1 of this subpart, between the process and th e 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 orPage 84 of 175

discharged. For purposes of this section, disc harge does not include emptying for maintenance purposes. (c) The owner or operator must perform monitori ng 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 proce dures in paragraphs (c)(1) through (6) of this section. (1) Monitoring locations for closed-loop r ecirculation heat exchange systems . For each closed loop recirculating heat exchange system, collect and analyze a sample from the location(s) described in either paragraph (c)(1) (i) or (c)(1)(ii) of this section. (i) Each cooling tower return line or any representative riser w ithin the cooling tower prior to exposure to air for each heat exchange system. (ii) Selected heat exchanger exit line(s) so that each heat exchanger or gr oup of heat exchangers within a heat exchange system is cove red 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 secti on. 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 gr oup of heat exchangers within a heat exchange system is covered by th e selected monitoring lo cation(s). The selected monitoring location may be at a point where discha rges from multiple heat exchange systems are combined provided that the combined cooling wate r flow rate at the monitoring location does not exceed 40,000 gallons per minute. (ii) The inlet water feed line for a once-thr ough 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 operato r may monitor at one representative location and use the monitoring results for that sampling location for all heat exchange systems that use that same water feed. (3) Monitoring method . Determine the total strippable hydr ocarbon concentrati on (in parts per million by volume (ppmv) as methane) at each monitoring location using the “Air Stripping Method (Modified El Paso Method) for Determin ation of Volatile Organic Compound Emissions from Water Sources” Revision Number One, da ted January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prep ared 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 ac tion level for existing sources . For a heat exchange system at an existing source, the owner or operator mu st comply with the monitoring frequency and leak action level as defined in paragr aph (c)(4)(i) of this section or comply with the monitoringPage 85 of 175

frequency and leak action level as defined in paragraph (c)(4)(ii) of this section. The owner or operator of an affected heat exchange system may choose to comp ly 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 a pply at all times. If the owner or operator intends to change the monitoring alternative that applie s to a heat exchange system, th e 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 freque ncies specified in paragraphs (c)(4)(i) and (ii) of this secti on also apply to the inlet water feed line for a once-through heat exchange system, if monitoring of the inlet wa ter feed is elected as provided in paragraph (c)(2)(ii) of this section. (i) Monitor monthly us ing a leak action level defined as a total strippable hydrocarbon concentration (as methane) inthe stripping gas of 6.2 ppmv. (ii) Monitor quarterly using a leak action le vel defined as a total strippable hydrocarbon concentration (as methane) in th e stripping gas of 3.1 ppmv unless repair is delayed as provided in paragraph (f) of this section. If a repair is delayed as provided in paragraph (f) of this section, monitor monthly. (5) Monitoring frequency and leak action level for new sources . For a heat exchange system at a new source, the owner or operator must monitor monthly using a leak action level defined as a total strippable hydrocarbon concentration (as methane) in the stripping gas of 3.1 ppmv. (6) Leak definition . A leak is defined as described in pa ragraph (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 dete cted if the difference in the measurement value of the sample taken from a lo cation specified in paragraph (c)(2)(i) of this section and the measurement value of the corresponding sample taken from the location specified in paragraph (c)(2)(ii ) of this section equals or exceeds the leak action level. (ii) For all other heat exchange systems, a leak is detected if a measurement value of the sample taken from a location specified in either paragraph (c)(1)(i), (c)(1)(ii), or (c )(2)(i) of this section equals or exceeds the leak action level. (d) If a leak is detected, the owner or operator must repair th e leak to reduce the measured concentration to below the applicable action le vel as soon as practicab le, but no later than 45 days after identifying the leak, exce pt as specified in paragraphs (e ) and (f) of this section. Repair includes re-monitoring at the moni toring 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 re pair include but are not limited to:Page 86 of 175

(1) Physical modifications to the leaking heat exchanger, such as welding the leak or replacing a tube; (2) Blocking the leaking tube within the heat exchanger; (3) Changing the pressure so that water flows into the process fluid; (4) Replacing the heat exchange r 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 de tects a leak when monitoring a cooling tower return line under paragraph (c)(1)(i) of this section, the owner or operator may conduct additional monitoring of each heat exchanger or group of heat exchangers associated with the heat exchange system for which the leak was detected as provided under para graph (c)(1)(ii) of this section. If no leaks are detected when monitoring according to the requirem ents of paragraph (c)(1 )(ii) of this section, the heat exchange system is considered to meet the repair requirements through re-monitoring of the heat exchange system as provided in paragraph (d) of this section. (f) The owner or operator may delay the repair of a leaking heat exchanger when one of the conditions in paragraph (f)(1) or (f)( 2) of this section is met and the leak is less than the delay of repair action level specified in paragraph (f)(3) of this section. The owner or operator must determine if a delay of repair is necessary as soon as practicable , but no later than 45 days after first identifying the leak. (1) If the repair is technically infeasible without a shutdown and the tota l strippable hydrocarbon concentration is initially and remains less than the delay of repair action level for all monthly monitoring periods during the delay of repair, th e owner or operator may delay repair until the next scheduled shutdown of the heat excha nge system. If, during subsequent monthly monitoring, the delay of repair action level is ex ceeded, the owner or operator must repair the leak within 30 days of the mon itoring event in which the leak wa s equal to or ex ceeded the delay of repair action level. (2) If the necessary equipment, parts, or pers onnel are not available and the total strippable hydrocarbon concentration is initially and remains le ss than the delay of repa ir action level for all monthly monitoring periods during the delay of repair, the owner or operator may delay the repair for a maximum of 120 calendar days. The ow ner 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 ex ceeded, the owner or operator must repair the leak within 30 days of the mon itoring event in which the leak wa s equal to or ex ceeded the delay of repair action level. (3) The delay of repair action level is a total strippable hydro carbon concentration (as methane) in the stripping gas of 62 ppmv. The delay of repa ir action level is asse ssed as described in paragraph (f)(3)(i) or (f)(3)(ii) of this section, as applicable.Page 87 of 175

(i) For once-through heat exchange systems for which the inlet water feed is monitored as described in paragraph (c)(2)(ii) of this section, the delay of repair action level is exceeded if the difference in the measurement value of the sample taken from a location specified in paragraph (c)(2)(i) of this section and the measurement value of the corresponding sample taken from the location specified in paragraph (c )(2)(ii) of this section equals or exceeds the delay of repair action level. (ii) For all other heat exchange systems, the delay of repair action level is exceeded if a measurement value of the sample taken from a lo cation 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 op erator must record the information in paragraphs (g)(1 ) through (4) of this section. (1) The reason(s) for delaying repair. (2) A schedule for completing th e repair as soon as practical. (3) The date and concentration of the leak as fi rst identified and the re sults of all subsequent monthly monitoring events dur ing the delay of repair. (4) An estimate of the potential strippable hydrocarbon emissions from the leaking heat exchange system or heat exchanger for each re quired delay of repair monitoring interval following the procedures in paragraphs (g)(4)(i) through (iv) of this section. (i) Determine the leak concentrati on as specified in paragraph (c) of this section and convert the stripping gas leak concentration (in ppmv as methane) to an e quivalent liquid concentration, in parts per million by weight (ppmw), using equa tion 7-1 from “Air St ripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003 (incorporated by reference—see § 63.14) and the molecular weight of 16 grams per mole (g/mol) for methane. (ii) Determine the mass flow rate of the cooli ng water at the monitoring location where the leak was detected. If the monitoring location is an individual cooling tower riser, determine the total cooling water mass flow rate to the cooling tower. Cooling water mass flow rates may be determined using direct measurement, pump curves, heat balance calculations, or other engineering methods. Volumetric flow measurements may be used and converted to mass flow rates using the density of water at the specifi c monitoring location temperature or using the default density of water at 25 degrees Celsius, which is 997 k ilograms per cubic meter or 8.32 pounds per gallon. (iii) For delay of repair monitori ng intervals prior to repair of the leak, calculate the potential strippable hydrocarbon emissions fo r the leaking heat exchange syst em or heat exchanger for the monitoring interval by multiplying the leak co ncentration in the cooling water, ppmw,Page 88 of 175

determined in (g)(4)(i) of this se ction, by the mass flow rate of the cooling water determined in (g)(4)(ii) of this sect ion 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 midni ght on the day the repair would have had to be completed if the repair had not been delayed, wh ichever is later, and ending at midnight of the day the of the current monitoring event. (iv) For delay of repair monito ring intervals ending with a repair ed leak, calculate the potential strippable hydrocarbon emissions fo r the leaking heat exchange syst em 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 co ncentration 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 repa ir monitoring interval is the tim e period starting at midnight of the day of the last monitoring ev ent prior to re-monitoring to veri fy the leak was repaired and ending at the time of the re-m onitoring event that verified that the leak was repaired. § 63.655 Reporting and recordkeeping requirements. (a) Each owner or operator subject to the wastew ater provisions in §63.647 shall comply with the recordkeeping and reporting pr ovisions in §§61.356 and 61.357 of 40 CFR part 61, subpart FF unless they are complying with the wastewater pr ovisions specified in paragraph (o)(2)(ii) of §63.640. There are no additional reporting and recor dkeeping requirements for wastewater under this subpart unless a wastewater stream is incl uded in an emissions average. Recordkeeping and reporting for emissions averages are specified in §63.653 and in pa ragraphs (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 pr ovisions in §63.428 (b) an d (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 re cordkeeping requirements for gasoline loading racks under this subpart unless a loading rack is included in an emissions average. Recordkeeping and reporting for emissions averages are specified in §63.653 and in paragraphs (f)(5) and (g)(8) of this section. (c) Each owner or operator subject to the ma rine 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 requir ements are summarized in table 5 of this subpart. There are no additional reporting and re cordkeeping requirements for marine tank vessel loading operations under this subpa rt unless marine tank vessel lo ading operations are included in an emissions average. Recordkeeping and reporting for emissions averages are specified in §63.653 and in paragraphs (f)(5) an d (g)(8) of this section. (d) Each owner or operator subject to the e quipment leaks standards in §63.648 shall comply with the recordkeeping and re porting provisions in paragraphs (d)(1) through (d )(6) of this section.Page 89 of 175

(1) Sections 60.486 and 60.487 of subpart VV of pa rt 60 except as specified in paragraph (d)(1)(i) of this section; or §§63.181 and 63.182 of subpart H of th is part except for §§63.182(b), (c)(2), and (c)(4). (i) The signature of the owner or operator (or desi gnate) whose decision it wa s 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 co uld not be effected w ithout a process shutdown shall be recorded and retained for 2 years. (ii) [Reserved] (2) The Notification of Compliance Status re port 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 summari zed in table 3 of this subpart. (3) An owner or operator who determines that a compressor qualifies for the hydrogen service exemption in §63.648 shall also keep a reco rd of the demonstration required by §63.648. (4) An owner or operator must k eep 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 r eciprocating pumps and compressors determined to be exempt from seal requirem ents as per §§63.64 8 (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 reco rds as described in paragr aph (i) of this section. (1) A Notification of Compliance St atus report as described in pa ragraph (f) of this section; (2) Periodic Reports as described in paragraph (g) of this section; and (3) Other reports as described in paragraph (h) of this section. (f) Each owner or operator of a source subject to this subpart shall submit a Notification of Compliance Status report within 150 days afte r the compliance dates specified in §63.640(h) with the exception of Notification of Complia nce Status reports submitted to comply with §63.640(l)(3) and for storage vess els subject to the complia nce schedule specified in §63.640(h)( 4 2 ). Notification of Compliance Status reports required by §63.640(l)(3) and for storage vessels subject to the comp liance dates specified in §63.640(h)( 4 2 ) shall be submitted according to paragraph (f)(6) of this section. Th is information may be submitted in an operatingPage 90 of 175

permit application, in an amendment to an opera ting 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 th e 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 dup licating and resubmitting the previously submitted information. Each owner or operator of a gaso line loading rack clas sified under Standard Industrial Classification Code 2911 located within a contiguous area and under common control with a petroleum refinery subject to the standard s of this subpart shall submit the Notification of Compliance Status report required by subpart R of this part with in 150 days after the compliance dates specified in §63.640(h) of this subpart. (1) The Notification of Compliance Status repor t shall include the information specified in paragraphs (f)(1)(i ) through (f)(1)(vi i ) of this section. (i) For storage vessels, this report shall incl ude the information specified in paragraphs (f)(1)(i)(A) thr ough (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 inform ation 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 stor age vessel subject to the compliance schedule specified in §63.640(h)( 4 2 ) or to comply with §63.640(l)(3). ( 1 ) For each Group 1 storage vessel complying w ith §63.646 that is not incl uded in an emissions average, the method of compliance (i.e., internal floating roof, exte rnal floating roof, or closed vent system and control device). ( 2 ) For storage vessels subject to the co mpliance schedule specified in §63.640(h)( 4 2 ) that are not complying with §63.646, the anticipated compliance date. ( 3 ) For storage vessels subject to the co mpliance schedule specified in §63.640(h)( 4 2 ) that are complying with §63.646 and the Group 1 storage vessels described in §63.640(l), the actual compliance date. (B) If a closed vent system and a control device other than a flare is used to comply with §63.646 or §63.660, the owner or opera tor 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 explan ation of the criteria used for selection of that parameter (or parameters), and the frequency with which monitoring will be performed; and eitherPage 91 of 175

( 2 ) The design evaluation documentation speci fied in §63.120(d)(1)(i) of subpart G or §63.985(b)(1)(i) of subpart SS (as applicable) , if the owner or operator elects to prepare a design evaluation; or ( 3 ) If the owner or operator elects to submit the re sults of a performance te st, 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 ot her 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 whic h the control device is being pr operly operated and maintained. ( 2 ) If a performance test is conducted instead of a design evaluation, results of the performance test demonstrating that the cont rol device achieves greater than or equal to the re quired control efficiency. A performance test conducted prior to the compliance date of th is subpart can be used to comply with this requirement, provided that the test was conducted using EPA methods and that the test conditions are represen tative 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 co mpliance determination required by §63.120(e) of subpart G of this part or §63.987(b) of subpart SS or §63.670(h), as applicable ; and ( 3 ) All periods during the compliance determination when the pilot flame is absent. (ii) For miscellaneous process vents, identificatio n of each miscellaneous process vent subject to this subpart, whether the process vent is Gr oup 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 da te of this subpart can be used provided that the test was conducted using the methods specifi ed in §63.645 and that th e test conditions are representative of curre nt operating conditions. (A) The percentage of reduction of organic HAP’s or TOC, or the outlet c oncentration 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; andPage 92 of 175

(B) The value of the monitored parameters specified in table 10 of this subpart, or a site-specific parameter approved by the permitting authority, averaged over the full period of the performance test, (iv) For miscellaneous proce ss vents controlled by flares, performance initial compliance test results including the information in paragra phs (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 comp liance determination re quired by §63.645 of this subpart and §63.116(a) of subpart G of this part or §63.670(h) of this subpart, as applicable , and (B) A statement of whether a flame was present at the pilot light over the full period of the compliance determination. (v) For equipment leaks complying with §63.648(c) (i.e., complying with the requirements of subpart H of this part), the No tification of Compliance Report St atus report information required by §63.182(c) of subpart H and whether the percenta ge 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 ex change systems at existi ng sources, the owner or operator shall indicate whether monitoring will be conducted as specified in §63.654(c)(4)(i) or §63.654(c)(4)(ii). (vii) For pressure relief devices in organic HAP service subj ect to the requirement in §63.648(j)(3)(i) and (ii), this repor t shall include the informatio n specified in paragraphs (f)(1)(vii)(A) and (B) of this section: (A) A description of the monitoring system to be implemented, incl uding the relief devices and process parameters to be monitored, and a description of the alarms or other methods by which operators will be notified of a pressure release. (B) A description of the preventi on measures to be implemente d for each affected pressure relief device. (viii) For each delayed coking unit, identificati on of whether the unit is an existing affected source or a new affected source and whether mo nitoring will be conducted as specified in §63.657(b) or §63.657(c). (2) If initial performance tests are requir ed by §§63.643 through 63.653 of this subpart, the Notification of Compliance Status report shall include one comple te test report for each test method used for a particular source. On and after [insert date 60 days after date of publication in the Federal Register], performa nce tests shall be s ubmitted according to paragraph (h)(9) of this section.Page 93 of 175

(i) For additional tests pe rformed using the same method, the re sults specified in paragraph (f)(1) of this section shall be submitted, but a complete test report is not required. (ii) A complete test report sh all include a sampling site descri ption, description of sampling and analysis procedures and any modi fications to standard procedures , quality assurance procedures, record of operating conditions during the test, record of prepar ation of standard s, record of calibrations, raw data sheets for field sampling, raw data sheets fo r field and laboratory analyses, documentation of calculations, and any othe r 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 emissi on 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 or §63.985(b) of subpart SS for storage vessels or §63.644 for miscellaneous process vents, the Notification of Compliance St atus 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 ra nge and a description of why the range ensures compliance with the emission standard. (A) If a performance test is requ ired 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 assessment s and manufacturers’ recommendations. (iii) A definition of the source’s operating day fo r purposes of determining daily average values of monitored parameters. The defi nition 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 Notificati on 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 deb its for the first quarter of the year. The first quarter begins on the compliance date specified in §63.640.Page 94 of 175

(6) Notification of Compliance St atus reports required by §63.640( l)(3) and for storage vessels subject to the compliance da tes specified in §63.640(h)( 4 2 ) shall be submitted no later than 60 days after the end of the 6-m onth 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 period ic report. Six-month periods shall be the same 6-month periods specified in paragraph (g) of th is section. The Notificatio n 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 operati ng 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 submitta ls 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 information specified in paragraphs (g)(1) through ( 6 7 ) of this section or paragraph s (g)(9) through (14) of this section occur is collected . The first 6-month period shall begin on the date the Notification of Compliance Status report is required to be submitted. A Periodic Report is not required if none of the compliance exceptions events identified in paragraph s (g)(1) through ( 6 7 ) of this section or paragraph s (g)(9 ) through (14 ) of this section occurred during the 6-month period unless emissions averaging is ut ilized. 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 th e information required by paragraphs (g)(1) through ( 9 14 ) of this section. (1) For storage vessels, Periodic Reports shall include the information specified for Periodic Reports in paragraph s (g)(2) through (g)(5) of this section except that information . Information related to gaskets, slotted membra nes, and sleeve seals is not requi red for storage vessels that are part of an existing source complying with §63.646

. (2 ) Internal floating roofs . (i ) An owner or operator who elects to comply with §63.646 by using a fixed roof and an internal floa ting roof or by using an external floating roof converted to an internal floating roof shall submit the results of each inspection conducte d in accordance with §63.120(a) of subpart G of this part in which a failure is detected in the control equipment. ( i A ) For vessels for which annual inspections are required under §63.120(a)(2)(i) or (a)(3)(ii) of subpart G of this part , the specifications and requirements listed in paragraphs (g)(2)(i)(A )( 1 ) through (g)(2)(i)( C A)(3 ) of this section apply. ( A 1 ) A failure is defined as any time in which th e 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 isPage 95 of 175

liquid on the floating roof; or the seal is detached from the internal floa ting 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 2 ) Except as provided in paragraph (g)(2)(i)( C A)(3 ) of this section, eac h Periodic Report shall include the date of the inspect ion, identification of each storag e vessel in which a failure was detected, and a description of the failure. The Pe riodic Report shall also describe the nature of and date the repair was made or th e date the storage vessel was emptied. ( C 3 ) 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 Peri odic 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 natu re of and date the repair was made. ( ii B ) For vessels for which inspections are re quired 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 i)(B)( 1 ) and ( g)( 2 )(ii)(B ) of this section apply. ( A 1 ) A failure is defined as any time in which th e internal floating roof has defects; or the primary seal has holes, tears, or ot her openings in the seal or the se al 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 lo nger 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 2 ) Each Periodic Report shall in clude the date of the inspection, identification of each storage vessel in which a failure was dete cted, and a description of the fa ilure. The Periodic Report shall also describe the nature of and date the repair was made. (3 (ii) An owner or operator who elects to comp ly with §63.660 by using a fixed roof and an internal floating roof shall submit the resul ts of each inspection conducted in accordance with §63.1063(c)(1), (d)(1), and (d)(2) of subpart WW in which a failure is detected in the control equipment. For vessels for whic h inspections are required under §63.1063(c) and (d), the specifications and requirements listed in paragraphs (g)(2)(ii)(A) through (C) of this section apply. (A) A failure is defined in §63.1063(d)(1) of subpart WW. (B) Each Periodic Report shall include a co py of the inspection record required by §63.1065(b) of subpart WW when a failure occurs. (C) An owner or operator who elects to use an extension in accordance with §63.1063(e)(2) of subpart WW shall, in the next Periodic Re port, submit the docume ntation required by §63.1063(e)(2).Page 96 of 175

(3) External floating roofs . (i ) An owner or operator who elects to comply with §63.646 by using an external floating roof shall meet the periodic repor ting requirements specified in paragraphs (g)(3)(i )(A ) through ( g)(3)(iii C ) of this section. ( i A ) The owner or operator shall submit, as part of the Periodic Report, documentation of the results of each seal gap measurement ma de in accordance with §63.120(b) of subpart G of this part in which the seal and seal gap requirements of §63.120(b)(3), (b)(4), (b)(5), or (b)(6) of subpart G of this part are not met. This documentation shall include the information specified in paragraphs (g)(3)(i)(A )( 1 ) through ( g)(3)(i)(D 4 ) of this section. ( A 1 ) The date of the seal gap measurement. ( B 2 ) The raw data obtained in the seal gap meas urement and the calculations described in §63.120(b)(3) and (b)(4) of subpart G of this part

. ( C 3 ) A description of any seal condition spec ified in §63.120(b)(5) or (b)(6) of subpart G of this part that is not met. ( D 4 ) A description of the nature of and date the repair was made, or the date the storage vessel was emptied. ( ii B ) If an extension is utili zed 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 Pe riodic 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 C ) The owner or operator shall su bmit, as part of the Periodic Report, documentation of any failures that are identified dur ing visual inspections require d by §63.120(b)(10) of subpart G of this part.

. This documentation shall meet the specifi cations and requirements in paragraphs (g)(3)( iii)(A i)(C)( 1 ) and ( g)(3)(iii)(B 2 ) of this section. ( A 1 ) A failure is defined as any time in which th e external floating roof has defects; or the primary seal has holes or other openings in the seal or the seal fabric; or the secondary seal has holes, tears, or other openings in the seal or the seal fabric; or, fo r 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, th e slotted membrane has more than 10 percent open area. ( B 2 ) Each Periodic Report shall in clude the date of the inspection, identification of each storage vessel in which a failure was dete cted, and a description of the fa ilure. The Periodic Report shall also describe the nature of and date the repair was made. ( 4 ii ) An owner or operator who elects to comply with §63.6 4 6 0 by using an external floating roof converted to an internal floating roof shall comply with meet the periodic reporting requirements of paragraph specified in paragraphs (g)( 2 3)(ii)(A) and (B ) of this section.Page 97 of 175

(A) For vessels for which inspections are re quired under §63.1063(c)(2), (d )(1), and (d)(3) of subpart WW, the owner or operator shall submit, as part of the Periodic Report, a copy of the inspection record required by §63.1065(b) of subpart WW when a failure occurs. A failure is defined in §63.1063(d)(1). (B) An owner or operator who elects to use an extension in accordance with §63.1063(e)(2) or §63.1063(c)(2)(iv)(B) of subpart WW shall, in the next Periodic Report, submit the documentation required by those paragraphs. (4) [Reserved] (5) An owner or operator who elects to comply with §63.646 or §63.660 by installing a closed vent system and control device shall submit, as part of the ne xt Periodic Report, the information specified in paragraphs (g)(5)(i) through (g)(5)( iii v ) of this section , as applicable

. (i) The Periodic Report shall include the inform ation specified in para graphs (g)(5)(i)(A) and ( g)(5)(i)( B) of this section for those planned routin e maintenance operations that would require the control device not to meet the requirements of either §63.119(e)(1) or (e)(2 ) of subpart G , §63.985(a) and (b) of this part subpart SS, or §63.670 , as applicable. (A) A description of the planned routine maintenan ce that is anticipated to be performed for the control device during the next 6 months. This desc ription shall include th e type of maintenance necessary, planned frequency of maintenan ce, and lengths of maintenance periods. (B) A description of the planned routine maintena nce 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 mont hs that the control device did not meet the requirements of either §63.119 (e)(1) or ( e)( 2) of subpart G , §63.985(a) and (b) of this part subpart SS, or §63.670 , as applicable, due to pl anned routine maintenance. (ii) If a control device other than a flare is used, the Periodic Re port shall describe each occurrence when the monitored parameters were out side of the parameter ranges documented in the Notification of Compliance Status report. The description shall include : Identification of the control device for which the measured parameters were outside of the established ranges, and causes for the measured parameters to be outside of the established ranges. (iii) If a flare is used (iii) If a flare is used prior to [ins ert date 3 years and 60 days after date of publication in the Federal Register] and prior to electing to comply with the requirements in §63.670 , the Periodic Report shall describe each occurrence when the flare does not meet the general control device requireme nts specified in §63.11(b) of subpart A of this part and shall include: Identific ation of the flare that does no t meet the general requirements specified in §63.11(b) of subpart A of this part, and reasons the flare did not meet the general requirements specified in §63.11(b) of subpart A of this part. (iv) If a flare is used on or after the date for which compliance with the requirements in §63.670 is elected, which can be no later than [ins ert date 3 years and 60 days after date ofPage 98 of 175

publication in the Federal Register], the Periodic Report shall include the items specified in paragraph (g)(11) of this section. (v) An owner or operator who elects to comp ly with §63.660 by installing an alternate control device as described in §63.1064 of subpart WW shall submit, as part of the next Periodic Report, a written application as described in §63.1066(b)(3) of subpart WW. (6) For miscellaneous process vents for which continuous parameter monitors are required by this subpart, periods of excess emissions shall be identified in the Periodi c 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 m onitoring 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 pilo t flames of a flare are absent. (C) An operating day when monitoring data requiredto be recorded in pa ragraphs (i)(3)(i) and (ii) of this section are available for le ss 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 monitori ng values were recorded. (ii) For miscellaneous process vents, excess emissions shall be reported for the operating parameters specified in table 10 of this subpart unless other site-specific parameter(s) have been approved by the operating permit authority. (iii) For periods in closed vent systems when a Group 1 miscellaneous process vent stream was detected in the bypass line or diverted from the control device and either directly to the atmosphere or to a control device that do es not comply with the requirements in §63.643(a), report the date, time, duration, estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting mass emissions of organic HAP that bypassed the control device. For periods when the flow indicator is not operating, report the date, time, and duration. Periods of startup and shutdown th at 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 co mpliance for a new emission point subject to this subpart or for an emission point that has ch anged from Group 2 to Group 1 is conducted duringPage 99 of 175

the period covered by a Periodic Report, the results of the performance test shall be included in the Periodic Report. (i) Results of the performance test shall include the identification of the source tested, the date of the test, the percentage of emissions reduction or outlet pollutant concentration reduction (whichever is needed to determine compliance) for each run and for the average of all runs, and the values of the monitored operating parameters. (ii) The complete test report shall be maintained onsite. (8) The owner or operator of a source shall submit quarterly reports for all emission points included in an emissions average. (i) The quarterly reports shall be submitted no later than 60 calendar days after the end of each quarter. The first report shall be submitted with the Notification of Compliance Status report no later than 150 days after the co mpliance date specified in §63.640. (ii) The quarterly re ports shall include: (A) The information specified in this paragraph a nd in paragraphs (g)(2) through (g)(7) of this section for all storage vessels and miscellaneous pr ocess vents included in an emissions average; (B) The information required to be reporte d by §63.428 (h)(1), (h)(2), and (h)(3) for each gasoline loading rack included in an emissions average, unless this information has already been submitted in a separate report; (C) The information required to be reported by §63.567(e)(4) and (j)(3) of subpart Y for each marine tank vessel loading operation included in an emissions average, unless the information has already been submitted in a separate report; (D) Any information pertaining to each wastewater stream included in an emissions average that the source is required to report under the Implementation Plan for the source; (E) The credits and debits calculated each month during the quarter; (F) A demonstration that debits calculated for the quarter are not more than 1.30 times the credits calculated for the quarter, as required under §§63.652(e)(4); (G) The values of any inputs to the credit and debit equations in §63.652 (g) and (h) that change from month to month during the quarter or that have changed since the previous quarter; and (H) Any other information the source is required to report under the Implementation Plan for the source. (iii) Every fourth quarterly repo rt shall include the following:Page 100 of 175

(A) A demonstration that annual cr edits 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 averagi ng provisions in §63.652 of this subpart. (9) For heat exchange systems, Periodic Repor ts must include the following information: (i) The number of heat exchange systems at the plant site subject to the monitoring requirements in §63.654. (ii) The number of heat exchange systems at the plant site found to be leaking. (iii) For each monitoring locat ion where the total strippable hydrocarbon concentration was determined to be equal to or greater than the applicable leak definitions specified in § 63.654(c)(6), identification of th e monitoring location (e.g., unique monitoring location or heat exchange system ID number), the measured to tal strippable hydrocarbon concentration, the date the leak was first identified, and, if applicable, the da te the source of the leak was identified; (iv) For leaks that were repaired during th e reporting period (including delayed repairs), identification of the monitoring location associated with the repaired leak, the total strippable hydrocarbon concentration measured during re-monitoring to verify repair, and the re-monitoring date ( i.e. , the effective date of repair); and (v) For each delayed repair, iden tification of the monitoring locati on associated with the leak for which repair is delayed, the date when the delay of repair began, the date the repair is expected to be completed (if the leak is not repaired during the reporting period) , the total strippable hydrocarbon concentration and date of each mon itoring event conducted on the delayed repair during the reporting period, and an estimate of the potential strippabl e hydrocarbon emissions over the reporting period associ ated with the delayed repair. (10) For pressure relief devices subject to the requirements §63.648(j) , Periodic Reports must include the information specified in paragr aphs (g)(10)(i) through (iii) of this section. (i) For pressure relief devices in organic HAP gas or vapor service, pursuant to §63.648(j)(1), report any instrument reading of 500 ppm or greater. (ii) For pressure relief devices in organic HAP gas or vapor s ervice subject to §63.648(j)(2), report confirmation that any monitoring requi red to be done during the reporting period to show compliance was conducted. (iii) For pressure relief devices in organic HAP service subject to §63.648(j)(3), report each pressure release to the atmosph ere, including duration of the p ressure release and estimate of the mass quantity of each organic HAP rel eased, and the results of any root cause analysis and corrective action analysis comp leted during the reporting period, including the corrective actions implemented during the reporting period and, if applicable, thePage 101 of 175

implementation schedule for planned corrective actions to be implem ented subsequent to the reporting period. (11) For flares subject to §63.670, Periodic Repo rts must include the information specified in paragraphs (g)(11)(i) through (iv) of this section. (i) Records as specified in paragraph (i)(9)( i) of this section for each 15-minute block during which there was at least one minute when reg ulated material is routed to a flare and no pilot flame is present. (ii) Visible emission records as specified in paragraph (i)(9)(ii)(C) of this section for each period of 2 consecutive hours during which visi ble emissions exceeded a total of 5 minutes. (iii) The 15-minute block periods for which th e applicable operating limits specified in §63.670(d) through (f) are not met. Indicate th e date and time for the period, the net heating value operating parameter(s) determined following the methods in §63.670(k) through (n) as applicable. (iv) For flaring events meet ing the criteria in §63.670(o)(3): (A) The start and stop time a nd date of the flaring event. (B) The length of time for which emissions were visible from the flare during the event. (C) The periods of time that the flare tip ve locity exceeds the maximu m flare tip velocity determine using the methods in §63.670(d)(2) and the maxi mum 15-minute block average flare tip velocity reco rded during the event. (D) Results of the root cause and corrective ac tions analysis completed during the reporting period, including the corrective ac tions implemented to during the reporting period and, if applicable, the implementation schedule for planned corrective actions to be implemented subsequent to the reporting period. (12) For delayed coking units, the Periodic Re port must include the information specified in paragraphs (g)(12)(i) through (iv) of this section. (i) For existing source delayed coking units, any 60-cycle average exceeding the applicable limit in §63.657(a)(1). (ii) For new source delayed coking units, any direct venting event exceeding the applicable limit in §63.657(a)(1). (iii) The total number of double quenching ev ents performed during the reporting period. (iv) For each double quenching draining even t when the drain wat er temperature exceeded 210oF, report the drum, date, time, the coke drum vessel pressure or temperature, asPage 102 of 175

applicable, when pre-vent draining was initiated, and the maximum drain water temperature during the pre-vent draining period. (13) For maintenance vents subject to th e requirements in §63.643(c), Periodic Reports must include the information specified in paragr aphs (g)(13)(i) through (iv) of this section for any release exceeding the applicable limi ts in §63.643(c)(1). For the purposes of this reporting requirement, owners or operators complying with §63.643(c)(1)(iv) must report each venting event for which the lower ex plosive limit is 20 percent or greater. (i) Identification of the maintenance vent and the equipment served by the maintenance vent. (ii) The date and time the maintenan ce vent was opened to the atmosphere. (iii) The lower explosive limit, vessel pressure, or mass of VOC in the equipment, as applicable, at the start of atmospheric ventin g. If the 5 psig vessel pressure option in §63.643(c)(1)(ii) was used and active purging wa s initiated while the lower explosive limit was 10 percent or greater, also include the lower explosive lim it of the vapors at the time active purging was initiated. (iv) An estimate of the mass of organic HAP released during the entire atmospheric venting event. (14) Any changes in the information provide d in a previous Notification of Compliance Status report. (h) Other reports shall be submitted as specified in subpart A of this part and as follows: (1) Reports of startup, shutdown, and malfunction required by §63.10(d)(5). Records and reports of startup, shutdown, and malfunctio n are not required if they pe rtain solely to Group 2 emission points, as defined in §63.641, that are not included in an emissions average. For purposes of this paragraph, startup and shutdown shall have the meaning defined in §63.641, and malfunction shall have the meaning defined in §63.2; and [Reserved] (2) For storage vessels, notifications of inspectio ns as specified in paragraphs (h)(2)(i) and (h)(2)(ii) of this section ; . (i) In order to afford the Administrator the opport unity to have an observe r present, the owner or operator shall notify the Administ rator of the refilling of each Gr oup 1 storage vessel that has been emptied and degassed. (A) Except as provided in paragrap hs (h)(2)(i) (B) and (C) of this section, the owner or operator shall notify the Administrator in writing at least 30 calendar days prior to filling or refilling of each storage vessel with organic HAP’s to afford the Administrator the opportunity to inspect the storage vessel prior to refilling.Page 103 of 175

(B) Except as provided in paragr aph (h)(2)(i)(C) of this sectio n, 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 or §63.1063(d)(1) of subpart WW is not planned and the owner or operator could not have known about the inspection 30 calendar days in adva nce of refilling the vessel with organic HAP ’s , the owner or operator shall notify the Administrator at least 7 cale ndar 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 wr iting 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 waiv e the notification requirements of paragraphs (h)(2)(i)(A) and/or (h)(2)(i )(B) of this section for all or so me storage vessels at petroleum refineries subject to this subpart. The Stat e 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 soon er than 7 days after submitting the notification required by paragraph (h)(2)(i)(B) of this section for all storage ve ssels, or for individual storage vessels on a case-by-case basis. (ii) In order to afford the Administrator the opport unity to have an observe r present, the owner or operator of a storage vessel equipp ed with an external floating roof shall notify the Administrator of any seal gap measurements. The notification sha ll be made in writing at least 30 calendar days in advance of any gap measurements required by §63.120 (b)(1) or (b)(2) of subpart G or §63.1062(d)(3) of this part subpart WW . The State or local permitting authority can waive this notification requirement for all or some storage ve ssels subject to the rule or can allow less than 30 calendar days’ notice. (3) For owners or operators of sources requi red 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 re quests approval to monitor a di fferent 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 re quired by §63.5(d) of subpart A a nd 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 m onitored to determine whether excess emissions occur and an explanation of the criter ia 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 wi ll establish a range for the monitored parameterPage 104 of 175

as part of the Notificat ion of Compliance Status report required in paragraphs (e) and (f) of this section. (iii) The frequency and content of monitori ng, 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 identif ied in Periodic Reports required under paragraphs (e) and (g) of this section. The rationale for the proposed m onitoring, 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 A pplication for Approval of Construction or Reconstruction for new sources and no later than18 months prior to th e 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 paragr aphs (h)(5)(iii) through (h)(5)(iv) of this se ction, as applicable. (ii) The provisions in §63.8(f)(5)( i) of subpart A of this part sh all govern the review and approval of requests. (iii) An owner or operator mayrequest approval to use an automated data compression recording system that does not record monitored operatin g parameter values at a set frequency (for example, once every hour) but records all values that meet set criteria for variation from previously recorded values. (A) The requested system shall be designed to: ( 1 ) Measure the operating parameter value at least once every hour. ( 2 ) Record at least 24 values each day during periods of operation. ( 3 ) Record the date and time when monitors are turned off or on. ( 4 ) Recognize unchanging data that may indicate th e monitor is not functioning properly, alert the operator, and record the incident. ( 5 ) Compute daily average values of the monito red operating parameter based on recorded data. (B) The request shall contain You must maintain a record of the description of the monitoring system and data compression recording system in cluding the criteria used to determine which monitored values are recorded and retained, th e method for calculating daily averages, and a demonstration s that the y system meets all criteri a of paragraph (h)(5)(iii)( A) of this section. (iv) An owner or operator may request approva l to use other alternat ive monitoring systems according to the procedures specified in§63.8(f) of subpart A of this part.Page 105 of 175

(6) The owner or operator shall submit the information specified in paragraphs (h)(6)(i) through (h)(6)(iii) of this section, as applicable. For ex isting sources, this information shall be submitted in the initial Notification of Co mpliance 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 inform ation may be submitted in an operating permit application, in an amendment to an operating pe rmit application, or in a separate submittal. (i) The determination of applicability of this s ubpart to petroleum refini ng process units that are designed and operated as flexible operation units. (ii) The determination of applicab ility of this subpart to any st orage vessel for which use varies from year to year. (iii) The determination of applicability of this su bpart 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 cale ndar days prior to changing from one of the monitoring options specified in §63.654(c)(4) to the other. (8) For fenceline monitoring systems subjec t to §63.658, within 45 calendar days after the end of each quarterly reporting period covered by the periodic report, each owner or operator shall submit the following informat ion to the EPA’s Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA’s Central Data Exchange (CDX) (https://cdx.epa.gov/). The owner or operator need not transmit this data prior to obtaining 12 months of data. (i) Individual sample results for each moni tor for each sampling period during the quarterly reporting period. For the first reporti ng period and for any period in which a passive monitor is added or moved, the owner or operator shall report the coordinates of all of the passive monitor locations. The owne r or operator shall dete rmine the coordinates using an instrument with an accuracy of at least 3 meters. Coordinate s shall be in decimal degrees with at least five decimal places. (ii) The biweekly annual average concentration difference ( Δ c) values for benzene for the quarterly reporting period. (iii) Notation for each biweekly value that indicates whether background correction was used, all measurements in the sampling period were below detection, or whether an outlier was removed from the sampling period data set. (9) On and after [insert date 60 days after date of publication in the Federal Register], if required to submit the results of a performanc e test or CEMS performance evaluation, the owner or operator shall submit the results ac cording to the procedures in paragraphs (h)(9)(i) and (ii) of this section.Page 106 of 175

(i) Within 60 days after the date of completi ng each performance test as required by this subpart, the owner or operator shall submit th e results of the performance tests following the procedure specified in either paragraph (h )(9)(i)(A) or (h)(9)(i)(B ) of this section. (A) For data collected using test methods supported by the EPA’s Electronic Reporting Tool (ERT) as listed on the EPA’s ERT Web site (http://www.epa.gov/ttn/chief/ert/index.html) at th e time of the test, the owner or operator must submit the results of the performance te st to the EPA via the CEDRI. (CEDRI can be accessed through the EPA’s CDX.) Performance te st data must be submitted in a file format generated through the use of the EPA’s ERT or an alternate el ectronic file format consistent with the extensible markup langu age (XML) schema listed on the EPA’s ERT Web site. If an owner or operator claims that some of the performance test information being submitted is confidenti al business information (CBI), the owner or operator must submit a complete file generated through the use of the EPA’s ERT or an alternate electronic file consistent with the XML schema listed on the EPA’s ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage media to the EPA. Th e electronic storage media must be clearly marked as CBI and mailed to U.S. EPA/OA QPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA’s CDX as described earlier in this paragraph. (B) For data collected using test methods th at are not supported by the EPA’s ERT as listed on the EPA’s ERT Web site at the time of the test, the owner or operator must submit the results of the performance test to the Administrator at the appropriate address listed in §63.13. (ii) Within 60 days after the date of comple ting each CEMS performance evaluation as required by this subpart, the owner or operator must submit the results of the performance evaluation following the procedure specified in either paragraph (h)(9)(ii)(A) or (h)(9)(ii)(B) of this section. (A) For performance evaluations of continuo us monitoring systems measuring relative accuracy test audit (RATA) pollutants that are supported by the EPA’s ERT as listed on the EPA’s ERT Web site at the time of the e valuation, the owner or operator must submit the results of the performance evaluation to the EPA via the CEDRI. (CEDRI can be accessed through the EPA’s CDX.) Performance e valuation data must be submitted in a file format generated through the use of the EPA’s ERT or an alternate file format consistent with the XML schema listed on the EPA’s ERT Web site. If an owner or operator claims that some of the performanc e evaluation information being submitted is CBI, the owner or operator mu st submit a complete file ge nerated through the use of the EPA’s ERT or an alternate electronic file co nsistent with the XML schema listed on the EPA’s ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage media to the EPA. The electronic storage media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Poli cy Group, MD C404-02, 4930 Old Page Rd.,Page 107 of 175

Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA’s CDX as described earlier in this paragraph. (B) For any performance evaluations of cont inuous monitoring systems measuring RATA pollutants that are not supported by the EPA’ s ERT as listed on the EPA’s ERT Web site at the time of the evaluation, the owner or operator must submit the results of the performance evaluation to the Administrato r at the appropriate address listed in §63.13. (i) Recordkeeping

. Each owner or operator of a source s ubject to this subpart shall keep copies of all applicable reports and records re quired by this subpart for at least 5 years except as otherwise specified in paragraphs (i)(1) through (12) of this section. All applicable records shall be maintained in such a manner th at they can be readily accessed within 24 hours. Records may be maintained in hard copy or computer-readable form including, but not limited to, on paper, microfilm, computer, flash drive, floppy disk, m agnetic tape, or microfiche. (1) Each owner or operator subject to the st orage vessel provisions in §63.646 shall keep the records specified in §63.123 of subpa rt G of this part except as sp ecified in paragraphs (i)(1)(i) through ( i)(1)(iv iv) of this section. Each owner or operator subject to the storage vessel provisions in §63.660 shall keep records as sp ecified in paragraphs (i)(1)(v) and (vi ) of this section. (i) Records related to gaskets, slotted membrane s, 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 subpartG 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 thanor equal to 4 percent for exis ting sources or 2 percent for new sources, a record of any data, assumptions, and pro cedures used to make this determination shall be retained. (v) Each owner or operator of a Group 1 st orage vessel subject to the provisions in §63.660 shall keep records as specified in §63.1065 or §63.998, as applicable. (vi) Each owner or operator of a Group 2 stor age vessel shall keep the records specified in §63.1065(a) of subpart WW. If a storage vessel is determined to be Group 2 because the weight percent total organic HAP of the stored liquid is less than or equal to 4 percent for existing sources or 2 percent for new source s, a record of any data, assumptions, and procedures used to make this determination shall be retained.Page 108 of 175

(2) Each owner or operator required to report th e 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 paragra ph (f)(2)(ii) of this section for each emission point tested. (3) Each owner or operator required to con tinuously monitor operating parameters under §63.644 for miscellaneous process vents or unde r §§63.652 and 63.653 for emission points in an emissions average shall keep the re cords 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 pe r minute, a single value for each minute may be used to calculate the hour ly (or shorter period) block average instead of all measured values. (iii) Daily average values of each continuously m onitored parameter shall be calculated for each operating day and retained for 5 years except as speci fied 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 operati on per day if operation is not continuous. (B) The operating day shall be the period define d in the Notification of Compliance Status report. It may be from midnight to midnight or another daily period. (iv) If all recorded values fo r a monitored parameter during an operating day are within the range established in the Notification of Compliance St atus 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 da ys, 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-le vel 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 dur ing process or control device operation when monitors are not operating. (4 ) For each closed vent system that contains bypass lines that could divert a vent stream away from the control device and either directl y to the atmosphere or to a control device that does not comply with the requirements in §63.643(a), the owner or operator shall keepPage 109 of 175

a record of the information specifi ed in either paragraph (i)(4)(i) or (ii) of this section, as applicable. (i) The owner or operator shall maintain records of periods when flow was detected in the bypass line, including the date and time and th e duration of the flow in the bypass line. For each flow event, the owner or operator shal l maintain records sufficient to determine whether or not the detected flow included fl ow of a Group 1 miscellaneous process vent stream requiring control. For periods when th e Group 1 miscellaneous process vent stream requiring control is diverted from the cont rol device and released either directly to the atmosphere or to a control device that do es not comply with the requirements in §63.643(a), the owner or operator shall include an estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting emissions of organic HAP that bypassed the control device using process knowledge and engineering estimates. (ii) Where a seal mechanism is used to comp ly with §63.644(c)(2), hourly records of flow are not required. In such cases, the owner or operator shall record the date that the monthly visual inspection of the seals or clos ure mechanisms is completed. The owner or operator shall also record the occurrence of all periods when the seal or closure mechanism is broken, the bypass line valve position has changed or the key for a lock-and-key type lock has been checked out. Th e owner or operator shall incl ude an estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting mass emissions of organic HAP from the Group 1 miscellaneous process vent stream requiring control that bypassed the control device or records sufficient to demonstrate that there was no flow of a Group 1 miscellaneous process vent strea m requiring control during the period. (5 ) The owner or operator of a heat exchange syst em subject to this subpart shall comply with the recordkeeping requirem ents in paragraphs (i)( 4 5 )(i) through (v) of this section and retain these records for 5 years. (i) Identification of all petroleu m refinery process unit heat exch angers at the facility and the average annual HAP concentration of process flui d or intervening cooling fluid estimated when developing the Notification of Compliance Status report. (ii) Identification of all heat exchange systems subject to the monitoring requirements in §63.654 and identification of all heat exchange systems that are exempt from the monitoring requirements according to the provisions in §63.654(b). For each heat exchange system that is subject to the monitoring requirements in §63.654, this must incl ude identification of all heat exchangers within each heat exchange syst em, and, for closed-loop recirculation systems, the cooling tower included in each heat exchange system. (iii) Results of the following monitoring da ta for each required monitoring event: (A) Date/time of event. (B) Barometric pressure.Page 110 of 175

(C) El Paso air stripping apparatus water flow milliliter/minute (ml/min) and air flow, ml/min, and air temperature, °Celsius. (D) FID reading (ppmv). (E) Length of sampling period. (F) Sample volume. (G) Calibration information identified in Sect ion 5.4.2 of the “Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources” Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003 (incorporated by reference—see §63.14). (iv) The date when a leak was identified, the date the source of the leak was identified, and the date when the heat exchanger was re paired or taken out of service. (v) If a repair is delayed, the re ason for the delay, the schedule fo r completing the repair, the heat exchange exit line flow or cool ing tower return line average flow rate at the monitoring location (in gallons/minute), and the estimate of poten tial strippable hydrocarbon emissions for each required monitoring interval during the delay of repair. ( 5 6 ) All other information required to be repor ted under paragraphs (a ) through (h) of this section shall be retained for 5 years. (7) Each owner or operator subject to th e delayed coking unit decoking operations provisions in §63.657 must maintain records specified in paragraphs (i)(7)(i) through (iii) of this section. (i) The average pressure or temperature, as applicable, for the 5-minute period prior to venting to the atmosphere, draining, or dehead ing the coke drum for each cooling cycle for each coke drum, (ii) If complying with the 60-cycle rolling average, each 60-cycle rolling average pressure or temperature, as applicable, considering all co ke drum venting events in the existing affected source. (iii) For double-quench cooling cycles: (A) The date, time and duration of each pre- vent draining event.(B) The pressure or temperature of the coke drum vessel, as appl icable, for the 15 minute period prior to the pre-vent draining.(C) The drai n water temperature at 1-minute intervals from the start of pre-vent draining to the complete closure of the drain valve. (8) For fenceline monitoring systems subject to §63.658, each owner or opera tor shall keep the re cords specified in paragraphs (i)(8)(i) through (x) of this section on an ongoing basis.Page 111 of 175

(i) Coordinates of all passive monitors, includi ng replicate samplers and field blanks, and if applicable, the meteorological station. Th e owner or operator shall determine the coordinates using an instrument with an accu racy of at least 3 meters. The coordinates shall be in decimal degrees with at least five decimal places. (ii) The start and stop times and dates for ea ch sample, as well as the tube identifying information. (iii) Sampling period average temperatu re and barometric pressure measurements. (iv) For each outlier determ ined in accordance with Section 9.2 of Method 325A of Appendix A of this part, the sampler location of and the concentration of the outlier and the evidence used to conclude that the result is an outlier. (v) For samples that will be adjusted for a background, the location of and the concentration measured simultaneously by the background sampler, and the perimeter samplers to which it applies. (vi) Individual sample results, the calculated Δ c for benzene for each sampling period and the two samples used to determine it, whet her background correction was used, and the annual average Δ c calculated after each sampling period. (vii) Method detection limit for each sample, including co -located samples and blanks. (viii) Documentation of correct ive action taken each time th e action level was exceeded. (ix) Other records as required by Methods 325A and 325B of Appendix A of this part. (x) If a near-field source correction is used as provided in §63.658(i), records of hourly meteorological data, including temperature, barometric pressure, wind speed and wind direction, calculated daily unit vector wind direction and daily sigma theta, and other records specified in the site -specific monitoring plan. (9) For each flare subject to §63.670, each owner or operator sh all keep the records specified in paragraphs (i)( 9)(i) through (xii) of this section up-to-date and readily accessible, as applicable. (i) Retain records of the output of the monito ring device used to detect the presence of a pilot flame as required in §63.670(b) for a mini mum of 2 years. Retain records of each 15- minute block during which there was at least on e minute that no pilot flame is present when regulated material is routed to a flare for a minimum of 5 years. (ii) Retain records of daily visible emissi ons observations or video surveillance images required in §63.670(h) as specifi ed in the paragraphs (i)( 9)(ii)(A) thro ugh (C), as applicable, for a minimum of 3 years.Page 112 of 175

(A) If visible emissions obs ervations are performed using Method 22 at 40 CFR part 60, Appendix A-7, the record must identify whet her the visible emissions observation was performed, the results of each observation, total duration of observed visible emissions, and whether it was a 5-minute or 2-hour observatio n. If the owner or operator performs visible emissions observations more than one time duri ng a day, the record must also identify the date and time of day each visible emissions observation was performed. (B) If video surveillance cam era is used, the record must include all video surveillance images recorded, with time and date stamps. (C) For each 2 hour period for which visi ble emissions are observed for more than 5 minutes in 2 consecutive hours, the record must include the date and time of the 2 hour period and an estimate of the cumulative numb er of minutes in the 2 hour period for which emissions were visible. (iii) The 15-minute block average cumulative flows for flare ve nt gas and, if applicable, total steam, perimeter assist air, and premix assist air specified to be monitored under §63.670(i), along with the date and time interv al for the 15-minute block. If multiple monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter assist air, and premix assist air, retain records of the 15-minute block average flows for each monitoring location for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If pressure and temperature monitoring is us ed, retain records of the 15-minute block average temperature, pressure and molecular weig ht of the flare vent gas or assist gas stream for each measurement location used to determine the 15-mi nute block average cumulative flows for a minimum of 2 year s, and retain the 15-minute block average cumulative flows that are used in subseque nt calculations for a minimum of 5 years. (iv) The flare vent gas compositions speci fied to be monitored under §63.670(j). Retain records of individual component concentrations from each compositional analyses for a minimum of 2 years. If NHV vg analyzer is used, retain records of the 15-minute block average values for a minimum of 5 years. (v) Each 15-minute block average operating pa rameter calculated following the methods specified in §63.670(k) through (n), as applicable. (vi) [Reserved] (vii) All periods during which operating value s are outside of the applicable operating limits specified in §63.670(d) through (f) when reg ulated material is being routed to the flare. (viii) All periods during which the owner or operator does not perform flare monitoring according to the procedures in §63.670(g) through (j).Page 113 of 175

(ix) Records of periods when there is flow of vent gas to the flare, but when there is no flow of regulated material to the flare, including th e start and stop time a nd dates of periods of no regulated material flow. (x) Records when the flow of ve nt gas exceeds the smokeless capa city of the flare, including start and stop time and da tes of the flaring event. (xi) Records of the root cause analysis and corrective action analysis conducted as required in §63.670(o)(3), including an iden tification of the affected fa cility, the date and duration of the event, a statement noting whether the ev ent resulted from the same root cause(s) identified in a previous analysis and eith er a description of the recommended corrective action(s) or an explanation of why corrective action is not necessary under §63.670(o)(5)(i). (xii) For any corrective action analysis for which implementation of corrective actions are required in §63.670(o)(5), a description of the co rrective action(s) comple ted within the first 45 days following the discharge and, for acti on(s) not already completed, a schedule for implementation, including proposed commencement and completion dates. (10) [Reserved] (11) For each pressure relief device subject to the pressure release management work practice standards in §63.648(j)(3), the owner or operator shall keep the records specified in paragraphs (i)(11)(i) thro ugh (iii) of this section. (i) Records of the prevention measures implemented as re quired in §63.648(j)(3)(ii), if applicable. (ii) Records of the number of releases during each calendar year and the number of those releases for which the root cause was determin ed to be a force majeure event. Keep these records for the current cale ndar year and the past five calendar years. (iii) For each release to the atmosphere, th e owner or operator sh all keep the records specified in paragraphs (i)(11)(iii)(A) through (D) of this section. (A) The start and end time and date of each pressure release to the atmosphere. (B) Records of any data, assumptions, and ca lculations used to estimate of the mass quantity of each organic HAP released during the event. (C) Records of the root cause analysis and co rrective action analysis conducted as required in §63.648(j)(3)(iii), including an identification of the affected facility, the date and duration of the event, a statement noting whether the event resulted from the same root cause(s) identified in a previous analysis and eith er a description of the recommended corrective action(s) or an explanation of why corrective action is not necessary under §63.648(j)(7)(i).Page 114 of 175

(D) For any corrective action analysis for which implementation of corrective actions are required in §63.648(j)(7), a description of the co rrective action(s) comple ted within the first 45 days following the discharge and, for acti on(s) not already completed, a schedule for implementation, including proposed commencement and completion dates. (12) For each maintenance vent opening subject to the requirements in §63.643(c), the owner or operator shall keep the applicable records specified in (i)(12)(i) through (v) of this section. (i) The owner or operator shall maintain stan dard site procedures used to deinventory equipment for safety purposes (e.g., hot work or vessel entry procedures) to document the procedures used to meet the requireme nts in §63.643(c). The current copy of the procedures shall be retained and available on-s ite at all times. Previous versions of the standard site procedures, is applicable, shall be retained for five years. (ii) If complying with the requirements of §63. 643(c)(1)(i) and the lowe r explosive limit at the time of the vessel opening exceeds 10 percent, id entification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and the lower explos ive limit at the time of the vessel opening. (iii) If complying with the requirements of §6 3.643(c)(1)(ii) and either the vessel pressure at the time of the vessel opening ex ceeds 5 psig or the lower explos ive limit at the time of the active purging was initiated exceeds 10 percent, identification of the maintenance vent, the process units or equipment associated with th e maintenance vent, the date of maintenance vent opening, the pressure of the vessel or e quipment at the time of discharge to the atmosphere and, if applicable, the lower explosive limit of the vapors in the equipment when active purging was initiated. (iv) If complying with the requirements of §63.643(c)(1)(iii), iden tification of the maintenance vent, the process units or equipm ent associated with the maintenance vent, the date of maintenance vent opening, and reco rds used to estimate the total quantity of VOC in the equipment at the time the maintena nce vent was opened to the atmosphere for each applicable maintenance vent opening. (v) If complying with the requirements of §63.643(c)(1)(iv), iden tification of the maintenance vent, the process units or equipm ent associated with the maintenance vent, records documenting the lack of a pure hydr ogen supply, the date of maintenance vent opening, and the lower explosive limit of the vapors in the equipment at the time of discharge to the atmosphere for each applicable maintenance vent opening. § 63.656 Implementation and enforcement. (a) This subpart can be implemented and enforc ed by the U.S. EPA, or a delegated authority such as the applicable State, lo cal, or Tribal agency. If the U.S. EPA Administrator has delegated authority to a State, local, or Tr ibal agency, then that agency, in addition to the U.S. EPA, has the authority to implement and enforce this subpa rt. Contact the applicab le U.S. EPA RegionalPage 115 of 175

Office to find out if implementation and enforcement of this subpart is delegated to a State, local, or Tribal agency. (b) In delegating implementation and enforcement au thority 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 Admini strator 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 Trib al agencies are as specified in paragraphs (c)(1) through (4) of this section. (1) Approval of alternativ es to the requirements in §§63.640, 63.642(g) through (l), 63.643, 63.646 through 63.652, 63.654, 63.657 through 63.660, and 63. 654 670 . Where these standards reference another subpart, the c ited provisions will be delegate d according to the delegation provisions of the referenced subpart. Where th ese standards reference another subpart and modify the requirements, the requirements shall be modified as described in this subpart. Delegation of the modified requirements will al so occur according to the delegation provisions of the referenced subpart. (2) Approval of major alte rnatives to test methods under §63.7(e)(2)(ii) and (f), as defined in §63.90, and as required in this subpart. (3) Approval of major alterna tives to monitoring under §63.8(f), as defined in §63.90, and as required in this subpart. (4) Approval of major al ternatives to recordkeeping and re porting under §63.10(f), as defined in §63.90, and as required in this subpart. § § 63.657 Delayed coking unit decoking operation standards. (a) Except as provided in paragraphs (e) and (f) of this section, each owner or operator of a delayed coking unit shall depressure each coke drum to a closed blowdown system until the coke drum vessel pressure or te mperature measured at the top of the coke drum or in the overhead line of the coke drum as near as pr actical to the coke drum meets the applicable limits specified in paragraphs (a)(1) or (a)(2 ) of this section prior to venting to the atmosphere, draining or deheading the coke drum at the end of the cooling cycle. (1) For delayed coking units at an ex isting affected source, meet either: (i) An average vessel pressure of 2 psig de termined on a rolling 60-event average; or (ii) An average vessel temperature of 220 degr ees Fahrenheit determined on a rolling 60- event average. (2) For delayed coking units at a new affected source, meet either:Page 116 of 175

(i) A vessel pressure of 2.0 psig for each decoking event; or (ii) A vessel temperature of 218 degrees Fahrenheit for each decoking event. (b) Each owner or operator of a delayed coki ng unit complying with the pressure limits in paragraphs (a)(1)(i) or (a)(2)(i) of this section shall install, op erate, calibrate, and maintain a monitoring system, as specified in paragra phs (b)(1) through (5) of this section, to determine the coke dr um vessel pressure. (1) The pressure monitoring system must be in a representative locati on (at the top of the coke drum or in the overhead line as near as practical to the coke drum) that minimizes or eliminates pulsating pressure, vibration, and, to the extent practical, internal and external corrosion. (2) The pressure monitoring system must be capable of measuring a pressure of 2.0 psig within ±0.5 psig. (3) The pressure monitoring system must be verified annually or at the frequency recommended by the instrument manufacturer. The pressure monitoring system must be verified following any period of more than 24 hours throughout which the pressure exceeded the maximum rated pressure of the sensor, or the data recorder was off scale. (4) All components of the pressure monitori ng system must be visually inspected for integrity, oxidation and galvanic corrosion every 3 months, unless the system has a redundant pressure sensor. (5) The output of the pressure monitoring system must be reviewed daily to ensure that the pressure readings fluctuate as expected between operating and cooling/decoking cycles to verify the pressure taps are not plugged. Pl ugged pressure taps must be unplugged or otherwise repaired prior to the next operating cycle. (c) Each owner or operator of a delayed coki ng unit complying with the temperature limits in paragraphs (a)(1)(ii) or (a)(2 )(ii) of this section shall install, operate, calibrate, and maintain a continuous parameter monitoring system to measure the coke drum vessel temperature (at the top of the coke drum or in the overhead line as near as practical to the coke drum) according to the requirements specified in table 13 of this subpart. (d) The owner or operator of a delayed coki ng unit shall determine the coke drum vessel pressure or temperature, as app licable, on a 5-minute rolling average basis while the coke drum is vented to the closed blowdown syst em and shall use the last complete 5-minute rolling average pressure or temp erature just prior to initiati ng steps to isolate the coke drum prior to venting, drai ning or deheading to demonstrate compliance with the requirements in paragraph (a) of this sect ion. Pressure or temp erature readings after initiating steps to isolate the coke drum from the closed blowdown system just prior to atmospheric venting, draining, or deheadin g the coke drum shall not be used inPage 117 of 175

determining the average coke drum vessel pressure or temperature for the purpose of compliance with the requirements in paragraph (a) of this section. (e) The owner or operator of a delayed coking unit using the “water overflow” method of coke cooling must hardpipe the overflow wa ter or otherwise prevent exposure of the overflow water to the atmosph ere when transferring the ov erflow water to the overflow water storage tank whenever the coke dr um vessel temperature exceeds 220 degrees Fahrenheit. The overflow water storage tank m ay be an open or fixed-roof tank provided that a submerged fill pipe (pipe outlet below the existing liquid level in the tank) is used to transfer overflow water to the tank. The owner or operator of a delayed coking unit using the “water overflow” method of coke coo ling shall determine the coke drum vessel temperature as specified in paragraphs (c) and (d) of this section regardless of the compliance method used to demonstrate comp liance with the requirements in paragraph (a) of this section. (f) The owner or operator of a delayed coking unit may partially drain a coke drum prior to achieving the applicable limi ts in paragraph (a) of this s ection in order to double-quench a coke drum that did not cool adequately us ing the normal cooling process steps provided that the owner or operator meets the conditions in paragraphs (f)(1) and (2) of this section. (1) The owner or operator shall install, operate, calibrate, and maintain a continuous parameter monitoring system to measure the drain water temperature at the bottom of the coke drum or in the drain line as near as practical to the coke drum according to the requirements specified in ta ble 13 of this subpart. (2) The owner or operator must maintain the drain water temperature below 210 degrees Fahrenheit during the partial drain asso ciated with the double-quench event.§ 63.658 Fenceline monitoring provisions. (a) The owner or operator shall conduct sampli ng along the facility property boundary and analyze the samples in accord ance with Methods 325A and 325B of Appendix A of this part and paragraphs (b) through (k) of this section. (b) The target analyte is benzene. (c) The owner or operator shall determine pass ive monitor locations in accordance with Section 8.2 of Method 325A of Appendix A of this part. (1) As it pertains to this subpart, known so urces of VOCs, as used in Section 8.2.1.3 in Method 325A of Appendix A of this part for siting passive monitors means a wastewater treatment unit, process unit, or any emission source requiring control according to the requirements of this subpart, including mari ne vessel loading operations. For marine loading operations that are located offshore, one passive monitor should be sited on the shoreline adjacent to the dock.Page 118 of 175

(2) The owner or operator may collect one or more background samples if the owner or operator believes that an offsite upwind so urce or an onsite source excluded under §63.640(g) may influence the sampler measuremen ts. If the owner or operator elects to collect one or more background samples, the owner of operato r must develop and submit a site-specific monitoring plan for approval acco rding to the requirements in paragraph (i) of this section. Upon approval of the site-speci fic monitoring plan, the background sampler(s) should be operated co-currently with the routine samplers. (3) The owner or operator shall collect at leas t one co-located duplicat e sample for every 10 field samples per sampling period and at leas t two field blanks per sampling period, as described in Section 9.3 in Method 325A of Appendix A of this pa rt. The co-located duplicates may be collected at any one of the perimeter sampling locations. (4) The owner or operator shall follow the procedure in Section 9.6 of Method 325B of Appendix A of this part to determine the det ection limit of benzene for each sampler used to collect samples, background sa mples (if the owner or operator el ects to do so), co-located samples and blanks. (d) The owner or operator shall collect and record meteorological da ta according to the applicable requirements in paragraphs (d)(1) through (3) of this section. (1) If a near-field source correction is used as provided in paragraph (i)( 2) of this section or if an alternative test method is used that provides time-resolved measurements, the owner or operator shall: (i) Use an on-site meteorological station in accordance with Section 8.3 of Method 325A of Appendix A of this part. (ii) Collect and record hourly meteorologica l data, including temp erature, barometric pressure, wind speed and wind direction and calc ulate daily unit vector wind direction and daily sigma theta. (2) For cases other than those specified in pa ragraph (d)(1) of this section, the owner or operator shall collect and record sampling pe riod average temperature and barometric pressure using either an on-site meteorologica l station in accordance with Section 8.3 of Method 325A of Appendix A of this part or, al ternatively, using data from a United States Weather Service (USWS) meteorological statio n provided the USWS meteorological station is within 40 kilometers ( 25 miles) of the refinery. (3) If an on-site meteorologica l station is used, the owner or operator shall follow the calibration and standardization procedures for meteorological measurements in EPA454/B-08-002 (incorporated by reference—see §63.14). (e) The owner of operator shall use a sampling period and sampling frequency as specified in paragraphs (e)(1) through (3) of this section.Page 119 of 175

(1) Sampling period . A 14-day sampling period shall be used, unless a shorter sampling period is determined to be necessary under par agraph (g) or (i) of this section. A sampling period is defined as the period during wh ich sampling tube is deployed at a specific sampling location with the diffusive samplin g end cap in-place and does not include the time required to analyze the sample. For the purpose of this subpart, a 14-day sampling period may be no shorter than 13 calendar days and no longer than 15 calendar days, but the routine sampling period sh all be 14 calendar days. (2) Base sampling frequency . Except as provided in paragra ph (e)(3) of this section, the frequency of sample collection shall be once each contiguous 14-day sampling period, such that the beginning of the next 14-day sampling period begins immediately upon the completion of the previous 14-day sampling period. (3) Alternative sampling frequency for burden reduction . When an individual monitor consistently achieves results at or below 0.9 μg/m 3 , the owner or operator may elect to use the applicable minimum sampling frequency speci fied in paragraph (e)(3)(i) through (v) of this section for that monito ring site. When calculating Δ c for the monitoring period when using this alternative for burden reduction, zero shall be substituted for the sample result for the monitoring site for any p eriod where a sample is not taken. (i) If every sample at a monitori ng site is at or below 0.9 μg/m 3 for 2 years (52 consecutive samples), every other sampling period can be skipped for that mo nitoring site, i.e., sampling will occur approximately once per month. (ii) If every sample at a monitoring site th at is monitored at the frequency specified in paragraph (e)(3)(i) of this s ection is at or below 0.9 μg/m 3 for 2 years (i.e., 26 consecutive “monthly” samples), five 14-day sampling period s can be skipped for that monitoring site following each period of sampling, i.e ., sampling will occur approximately once per quarter. (iii) If every sample at a monitoring site th at is monitored at the frequency specified in paragraph (e)(3)(ii) of this se ction is at or below 0.9 μg/m 3 for 2 years (i.e., 8 consecutive quarterly samples), twelve 14-day sampling periods can be skipped for th at monitoring site following each period of sampling, i.e., sampling will occur twice a year. (iv) If every sample at a monitoring site th at is monitored at the frequency specified in paragraph (e)(3)(iii) of this section is at or below 0.9 μg/m 3 for an 2 years (i.e., 4 consecutive semi-annual samples), only one sa mple per year is required for that monitoring site. For yearly sampling, samples shall occur at least 10 months but no more than 14 months apart. (v) If at any time a sample for a monitoring si te that is monitored at the frequency specified in paragraphs (e)(3)(i) through (iv) of this section returns a result that is above 0.9 μg/m 3 , the sampling site must return to the origin al sampling requirements of contiguous 14-day sampling periods with no skip periods for one quarter (six 14-day sampling periods). If every sample collected during this quarter is at or below 0.9 μg/m 3 , the owner or operator may revert back to the reduced monitoring schedule applicable for that monitoring sitePage 120 of 175

prior to the sample reading exceeding 0.9 μg/m 3 . If any sample collected during this quarter is above 0.9 μg/m 3 , that monitoring site must return to the original sampling requirements of contiguous 14- day sampling periods with no skip periods for a minimum of two years. The burden reduction requiremen ts can be used again for that monitoring site once the requirements of pa ragraph (e)(3)(i) of this sect ion are met again, i.e., after 52 contiguous 14-day samples with no results above 0.9 μg/m 3

. (f) Within 45 days of completion of each sa mpling period, the owner or operator shall determine whether the results are above or below the action level as follows: (1) The owner or operator shall determine the facility impact on the benzene concentration ( Δ c) for each 14-day sampling period according to either paragraphs (f)(1)(i) or (ii) of this section, as applicable. (i) Except when near-field source correction is used as provided in paragraph (i) of this section, the owner or operator shall determine the highest a nd lowest sample results for benzene concentratons from th e sample pool and calculate Δ c as the difference in these concentrations. The owner or operator shall adhere to the following procedures when one or more samples for the sampling period are be low the method detection limit for benzene: (A) If the lowest detected value of benzene is below detection, the owner or operator shall use zero as the lowest sample result when calculating Δ c. (B) If all sample results are below the method detection limit, the ow ner or operator shall use the method detection limit as the highest sample result. (ii) When near-field source correction is used as provided in paragraph (i) of this section, the owner or operator shall determine Δ c using the calculation protocols outlined in the approved site-specific monito ring plan and in paragra ph (i) of this section. (2) The owner or operator shall calculate the annual average Δ c based on the average of the 26 most recent 14-day sampling periods. The ow ner or operator shall update this annual average value after receiving the results of each subsequent 14-day sampling period. (3) The action level for benzene is 9 micrograms per cubic meter (μg/m 3 ) on an annual average basis. If the annual average Δ c value for benzene is less than or equal to 9 μg/m 3 , the concentration is below the action level. If the annual average Δ c value for benzene is greater than 9 μg/m 3 , the concentration is above the acti on level, and the owner or operator shall conduct a root cause analys is and corrective action in accordance with paragraph (g) of this section. (g) Within 5 days of determining that the action level has been exceeded for any annual average Δ c and no longer than 50 days after comple tion of the sampling period, the owner or operator shall initiate a root cause analys is to determine the cause of such exceedance and to determine appropriate corrective action, such as those described in paragraphs (g)(1) through (4) of this section. The root cause analysis and initial corrective actionPage 121 of 175

analysis shall be completed and initial correct ive actions taken no later than 45 days after determining there is an exceedance. Root cause analysis and corrective action may include, but is not limited to: (1) Leak inspection using Method 21 of part 6 0, Appendix A-7 of this chapter and repairing any leaks found. (2) Leak inspection using optical gas im aging and repairing any leaks found. (3) Visual inspection to determine the ca use of the high benzene emissions and implementing repairs to reduce the level of emissions. (4) Employing progressively more frequent sampling, analysis and meteorology (e.g., using shorter sampling periods for Methods 325A and 325B of Appendix A of this part, or using active sampling techniques). (h) If, upon completion of the corrective action analysis and corrective actions such as those described in paragraph (g) of this section, the Δ c value for the next 14-day sampling period for which the sampling start time begins after the completion of the corrective actions is greater than 9 μ g/m 3 or if all corrective action measu res identified require more than 45 days to implement, the own er or operator shall develop a corrective action plan that describes the corrective action(s ) completed to date, additional measures that the owner or operator proposes to employ to reduce fenceline concentrations below the action level, and a schedule for completion of these measures . The owner or operator shall submit the corrective action plan to the Administrator within 60 days after receiving the analytical results indicating that the Δ c value for the 14-day sampling p eriod following the completion of the initial corrective ac tion is greater than 9 μ g/m 3 or, if no initial corrective actions were identified, no later than 60 days following the completion of th e corrective action analysis required in paragraph (g) of this section. (i) An owner or operator may request approval from the Administrato r for a site-specific monitoring plan to account for offsite upw ind sources or onsite sources excluded under §63.640(g) according to the requirements in paragr aphs (i)(1) through (4 ) of this section. (1) The owner or operator shall prepare and submit a site-specific monitoring plan and receive approval of the site-specific monitoring plan prior to using the near-field source alternative calculation for determining Δ c provided in paragraph (i)(2) of this section. The site-specific monitoring plan shall include, at a minimum, the elements specified in paragraphs (i)(1)(i) through (v) of this sect ion. The procedures in Section 12 of Method 325A are not required, but may be used, if applicable, when determining near-field source contributions. (i) Identification of the near-field source or sources. For onsite sources, documentation that the onsite source is excluded under §63.640(g) and id entification of the specific provision in §63.640(g) that applies to the source.Page 122 of 175

(ii) Location of the additional monitoring st ations that shall be used to determine the uniform background concentration and the near -field source concentration contribution. (iii) Identification of the fenceline monitoring locations impacted by the near-field source. If more than one near-field source is present, identify the near-field source or sources that are expected to contribute to the con centration at that monitoring location. (iv) A description of (i ncluding sample calculations illust rating) the planned data reduction and calculations to determin e the near-field source concentration contribution for each monitoring location. (v) If more frequent monitoring or a monitoring station other than a passive diffusive tube monitoring station is proposed, provide a detailed description of the measurement methods, measurement frequency, and recordin g frequency for determining the uniform background or near-field source concentration contribution. (2) When an approved site-specific monitoring plan is used, the owner or operator shall determine Δ c for comparison with the 9 μg/m 3 action level using the requirements specified in paragraphs (i)(2)(i) thro ugh (iii) of this section. (i) For each monitoring location, calculate Δ c i using the following equation. 

### UBNFSMFC Δ c i i i 

### 

where:

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

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

. NFS i = The near-field source contributing con centration at measurement location i determined using the additional measurements and calculation procedures included in the site-specific monitoring plan, μg/m 3 . For monitoring locations that are not included in the site-specific monitoring plan as impa cted by a near-field source, use NFS i = 0 μg/m 3

. UB = The uniform background concentrat ion determined using the additional measurements included in the site -specific monitoring plan, μg/m 3 . If no additional measurements are specified in the site-specific monitoring plan for determining the uniform background concentration, use UB = 0 μg/m 3

. (ii) When one or more samples for the samp ling period are below the method detection limit for benzene, adhere to the following procedures:Page 123 of 175

(A) If the benzene concentration at the mo nitoring location used for the uniform background concentration is below the method detection limit, the ow ner or operator shall use zero for UB for that monitoring period. (B) If the benzene concentration at the monito ring location(s) used to determine the nearfield source contributing concentration is be low the method detection limit, the owner or operator shall use zero for the monitoring lo cation concentration when calculating NFS i for that monitoring period. (C) If a fenceline monitoring location sample result is below the method detection limit, the owner or operator shall use the method detection limit as the sample result. (iii) Determine Δ c for the monitoring period as the maximum value of Δ c i from all of the fenceline monitoring locations for that monitoring period. (3) The site-specific monitoring plan shall be submitted and approved as described in paragraphs (i)(3)(i) throug h (iv) of this section. (i) The site-specific monitoring plan must be submitted to the Admi nistrator for approval. (ii) The site-specific monitoring plan shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Ai r Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mail room (E143–01), Attentio n: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refineryrtr@epa.gov. (iii) The Administrator shall approve or disapprove the plan in 90 days. The plan shall be considered approved if the Admi nistrator either approves the pl an in writing, or fails to disapprove the plan in writing. The 90-day p eriod shall begin when the Administrator receives the plan. (iv) If the Administrator finds any deficienci es in the site-specific monitoring plan and disapproves the plan in writing, the owner or operator may revise and resubmit the sitespecific monitoring plan following the requirement s in paragraphs (i)(3)(i) and (ii) of this section. The 90-day period starts over with the resubmission of the revised monitoring plan. (4) The approval by the Administrator of a site -specific monitoring plan will be based on the completeness, accuracy and reasonableness of the request for a site-specific monitoring plan. Factors that the Administrator will co nsider in reviewing the request for a sitespecific monitoring plan include, but are not limited to, those described in paragraphs (i)(4)(i) through (v) of this section. (i) The identification of the near-field source or sources. For onsite sources, the documentation provided that the onsite source is excluded under §63.640(g).Page 124 of 175

(ii) The monitoring location selected to determine the uniform background concentration or an indication that no uniform back ground concentration monitor will be used. (iii) The location(s) selected for additional monitoring to determin e the near-field source concentration contribution. (iv) The identification of the fenceline moni toring locations impacted by the near-field source or sources. (v) The appropriateness of the planned data reduction and calculations to determine the near-field source concentration contribution for each monitoring location. (vi) If more frequent monitori ng is proposed, the adequacy of the description of the measurement and recording frequency proposed and the adequacy of the rationale for using the alternative monitoring frequency. (j) The owner or operator shall comply with the applicable recordkeeping and reporting requirements in §63.655(h) and (i). (k) As outlined in §63.7(f), the owner or operator may submit a request for an alternative test method. At a minimum, the request must follow the requirements outlined in (k)(1) through (7) of this section. (1) The alternative method may be used in lieu of all or a partial number of passive samplers required in Method 325A. (2) The alternative method must be validat ed according to Method 301 in appendix A of this part or contain performan ce based procedures and indicators to ensure self-validation. (3) The method detection limit must nominally be at least an order of magnitude below the action level, i.e., 0.9 μg/m 3 benzene. The alternate test meth od must describe the procedures used to provide field verifica tion of the detection limit. (4) The spatial coverage must be equal to or better than the spatial coverage provided in Method 325A. (i) For path average concentration open-path in struments, the physical path length of the measurement shall be no more than a passive sa mple footprint (the spacing that would be provided by the sorbent traps when following Method 325A). For example, if Method 325A requires spacing monitors A and B 610 meters (2000 feet) apart, then the physical path length limit for the measurement at that portion of the fenceline shall be no more than 610 meters (2000 feet). (ii) For range resolved open-path instrument or approach, the instrument or approach must be able to resolve an average concen tration over each passive sampler footprint within the path length of the instrument.Page 125 of 175

(iii) The extra samplers required in Sectio ns 8.2.1.3 of Method 325A may be omitted when they fall within the path leng th of an open-path instrument. (5) At a minimum, non-integrating alternativ e test methods must provide a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15- minute period. (6) For alternative test methods capable of real time measurements (less than a 5 minute sampling and analysis cycle), th e alternative test method may allow for elimination of data points corresponding to outside emission sou rces for purpose of calculation of the high point for the two week average. The alternat ive test method approach must have wind speed, direction and stability class of the same time resolution and within the footprint of the instrument. (7) For purposes of averaging data points to determine the Δ c for the 14-day average high sample result, all results meas ured under the method detectio n limit must use the method detection limit. For purposes of averaging da ta points for the 14-day average low sample result, all results measured under the me thod detection limit must use zero. § 63.659 [Reserved] § 63.660 Storage vessel provisions. On and after the applicable compliance date fo r a Group 1 storage vessel located at a new or existing source as specified in §63.640(h), the owner or operator of a Group 1 storage vessel that is part of a new or existing sou rce shall comply with the requirements in subpart WW or subpart SS of this part according to the requirements in paragraphs (a) through (i) of this section. (a) As used in this section, all terms no t defined in §63.641 shall have the meaning given them in subpart A, subpart WW, or subpart SS of this part. The definitions of “Group 1 storage vessel” (item 2) and “storage vessel” in §63.641 shall apply in li eu of the definition of “storage vessel” in §63.1061. (1) An owner or operator may use good engineering judgment or test results to determine the stored liquid weight percent total organic HAP for purposes of group determination. Data, assumptions, and procedures used in the determination shall be documented. (2) When an owner or operator and the Admi nistrator do not agree on whether the annual average weight percent organic HAP in the sto red liquid is above or below 4 percent for a storage vessel at an existing source or above or below 2 percent for a storage vessel at a new source, an appropriate method (based on the ty pe of liquid stored) as published by EPA or a consensus-based standards organization sh all be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B2959, (800) 262–1373, http://www.astm.org), the American Nati onal Standards Institute (ANSI, 1819 LPage 126 of 175

Street, NW., 6th floor, Washington, DC 2003 6, (202) 293–8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Ca pitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824–7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Av enue, New York, NY 10016–5990, (800) 843–2763, http://www.asme.org), the American Petr oleum Institute (API, 1220 L Street, NW., Washington, DC 20005–4070, (202) 682–8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356–0060, http://www.naesb.org). (b) A floating roof storage vessel complying wi th the requirements of subpart WW of this part may comply with the control option specified in paragraph (b)(1) of this section and, if equipped with a ladder having at least one slotted leg, shall co mply with one of the control options as described in paragraph (b)(2) of this section. (1) In addition to the options presente d in §§63.1063(a)(2)(viii)(A), 63.1063(a)(2)(viii)(B), and 63.1064, a floating roof storage vessel ma y comply with §63.1063(a)(2)(vii) using a flexible enclosure device and ei ther a gasketed or welded cap on the top of the guidepole. (2) Each opening through a floating roof for a la dder having at least one slotted leg shall be equipped with one of the configurations specif ied in paragraphs (b)(2)(i) through (iii) of this section. (i) A pole float in the slotted leg and pole wipers for both legs. The wiper or seal of the pole float must be at or above th e height of the pole wiper. (ii) A ladder sleeve and pole wipers for both legs of the ladder. (iii) A flexible enclosure device and either a gaske ted or welded cap on the top of the slotted leg. (c) For the purposes of this s ubpart, references shall apply as sp ecified in paragraphs (c)(1) through (6) of this section. (1) All references to “the proposal date for a referencing subpart” and “the proposal date of the referencing subpart” in subpart WW of this part mean June 30, 2014. (2) All references to “promulgation of the re ferencing subpart” and “the promulgation date of the referencing subpart” in subpart WW of this part mean [insert date 60 days after date of publication in the Federal Register]. (3) All references to “promulgation date of standards for an affected source or affected facility under a referencing subpart” in subpart SS of this part mean [insert date 60 days after date of publication in the Federal Register]. (4) All references to “the proposal date of the relevant standard established pursuant to CAA section 112(f)” in subpart SS of this part mean June 30, 2014.Page 127 of 175

(5) All references to “the proposal date of a relevant standard established pursuant to CAA section 112(d)” in subpart SS of this part mean July 14, 1994. (6) All references to the “required control ef ficiency” in subpart SS of this part mean reduction of organic HAP emissions by 95 p ercent or to an outlet concentration of 20 ppmv. (d) For an uncontrolled fixed roof storage vess el that commenced construction on or before June 30, 2014, and that meets the definition of Group 1 storage vessel in item 2 in §63.641 but not the definition of Gr oup 1 storage vessel in item 1 in §63.641, the requirements of §63.982 and/or §63.1062 do not apply until the next time the storage ve ssel is completely emptied and degassed, or [insert date 10 years and 60 days after date of publication in the Federal Register], whichever occurs first. (e) Failure to perform inspections and monitoring required by this section shall constitute a violation of the applicable standard of this subpart. (f) References in §63.1066(a) to initial start up notification requirements do not apply. (g) References to the Notification of Complia nce Status in §63.999(b) mean the Notification of Compliance Status required by §63.655(f). (h) References to the Periodic Reports in §§63.1066(b) and 63.999(c) mean the Periodic Report required by §63.655(g). (i) Owners or operators electing to comply wi th the requirements in subpart SS of this part for a Group 1 storage vessel must comply wi th the requirements in paragraphs (i)(1) through (3) of this section. (1) If a flare is used as a control device, the flare shall meet th e requirements of §63.670 instead of the flare requirements in §63.987. (2) If a closed vent system contains a bypass line, the owner or operator shall comply with the provisions of either §63.983(a)(3 )(i) or §63.983(a)(3)(ii) for each closed vent system that contains bypass lines that could divert a vent stream either direc tly to the atmosphere or to a control device that does not comply with the requirements in subpart SS of this part. Except as provided in paragraphs (i)(2)(i) and ( ii) of this section, use of the bypass at any time to divert a Group 1 storage vessel to either directly to the atmosphere or to a control device that does not comply with the require ments in subpart SS of this part is an emissions standards violation. Equipment such as low leg drains and equipment subject to §63.648 are not subject to this paragraph. (i) If planned routine maintenance of th e control device cannot be performed during periods that storage vessel emissions are vented to the control device or when the storage vessel is taken out of service for inspections or other planned maintenance reasons, the owner or operator may bypass the control device.Page 128 of 175

(ii) Periods for which storage vessel contro l device may be bypassed for planned routine maintenance of the control device shall not exceed 240 hours per calendar year. (3) If storage vessel emissions are routed to a fuel gas system or process, the fuel gas system or process shall be operating at all ti mes when regulated emissions are routed to it. The exception in §63.984(a)(1) does not apply. §§ 63.661-63.669 [Reserved] § 63.670 Requirements for flare control devices. On or before [insert date 3 years and 60 days after date of publication in the Federal Register], the owner or operator of a flare us ed as a control device for an emission point subject to this subpart shall meet the applic able requirements for flares as specified in paragraphs (a) through (q) of this section and the applicable requirements in §63.671. The owner or operator may elect to comply with the requirements of paragraph (r) of this section in lieu of the requirements in par agraphs (d) through (f) of this section, as applicable. (a) [Reserved] (b) Pilot flame presence . The owner or operator shall operat e each flare with a pilot flame present at all times when regulated material is routed to the flare. Each 15-minute block during which there is at least one minute where no pilot flame is present when regulated material is routed to the flar e is a deviation of the standa rd. Deviations in different 15- minute blocks from the same event are considered separate deviations. The owner or operator shall monitor for the pres ence of a pilot flame as specifi ed in paragraph (g) of this section. (c) Visible emissions . The owner or operator shall specify the smokeless design capacity of each flare and operate with no visible emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours, when reg ulated material is routed to the flare and the flare vent gas flow rate is less than the smokeless design capacity of the flare. The owner or operator shall monitor for visible emissions from the flare as specified in paragraph (h) of this section. (d) Flare tip velocity . For each flare, the owner or operator shall comply with either paragraph (d)(1) or (d)(2) of this section, pr ovided the appropriate monitoring systems are in-place, whenever regulated material is routed to the flare for at least 15-minutes and the flare vent gas flow rate is less than the smokeless design capaci ty of the flare. (1) Except as provided in paragraph (d)(2) of th is section, the actual flare tip velocity (V tip ) must be less than 60 feet per second . The owner or operator shall monitor V tip using the procedures specified in paragra ph (i) and (k) of this section.Page 129 of 175

(2) V tip must be less than 400 feet per second and also less than the ma ximum allowed flare tip velocity (V max ) as calculated according to the foll owing equation. The owner or operator shall monitor V tip using the procedures specified in paragraphs (i) and (k) of this section and monitor gas composit ion and determine NHV vg using the procedures specified in paragraphs (j) and (l) of this section. 

##   850 212,1

10 

### 

 vg max 

### NHV VLog

where:

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

NHV vg = Net heating value of flare vent gas, as determined by paragraph (l)(4) of this section, Btu/scf. 1,212 = Constant.

850 = Constant. (e) Combustion zone operating limits . For each flare, the owner or operator shall operate the flare to maintain the net heating valu e of flare combustion zone gas (NHV cz ) at or above 270 British thermal units per standard cubic feet (Btu/scf) determ ined on a 15-minute block period basis when regulated material is routed to the flare for at least 15-minutes. The owner or operator shall monitor and calculate NHV cz as specified in paragraph (m) of this section. (f) Dilution operating limits for flares with perimeter assist air . For each flare actively receiving perimeter assist air, the owner or op erator shall operate the flare to maintain the net heating value dilution parameter (NHV dil ) at or above 22 Brit ish thermal units per square foot (Btu/ft 2 ) determined on a 15-minute block peri od basis when regulated material is being routed to the flare for at least 15- minutes. The owner or operator shall monitor and calculate NHV dil as specified in paragraph (n) of this section. (g) Pilot flame monitoring . The owner or operator shall co ntinuously monitor the presence of the pilot flame(s) using a device (including, but not limited to, a thermocouple, ultraviolet beam sensor, or infr ared sensor) capable of detecting that the pilot flame(s) is present. (h) Visible emissions monitoring . The owner or operator sha ll monitor visible emissions while regulated materials are vented to the fla re. An initial visible emissions demonstration must be conducted using an observation peri od of 2 hours using Method 22 at 40 CFR part 60, Appendix A-7. Subsequent vi sible emissions observations must be conducted using either the methods in paragra ph (h)(1) of this section or, alternatively, the methods in paragraph (h)(2) of this section. The owner or operator must record and report anyPage 130 of 175

instances where visible emissions are observed for more than 5 minutes during any 2 consecutive hours as specified in §63.655(g)(11)(ii). (1) At least once per day, conduct visible emis sions observations using an observation period of 5 minutes using Method 22 at 40 CF R part 60, Appendix A-7. If at any time the owner or operator sees visible emissions, even if the minimum required daily visible emission monitoring has already been perfor med, the owner or operator shall immediately begin an observation period of 5 minutes using Method 22 at 40 CFR part 60, Appendix A7. If visible emissions are observed for more than one continuous minute during any 5- minute observation period, the observation period using Method 22 at 40 CFR part 60, Appendix A-7 must be extended to 2 hours or until 5-minutes of visible emissions are observed. (2) Use a video surveillance camera to cont inuously record (at least one frame every 15 seconds with time and date stamps) images of the flare flame and a reasonable distance above the flare flame at an an gle suitable for visual emissi ons observations. The owner or operator must provide real-time video surveilla nce camera output to the control room or other continuously manned location where the ca mera images may be viewed at any time. (i) Flare vent gas, steam assist and air assist flow rate monitoring . The owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording the volum etric flow rate in the flare header or headers that feed the flare as well as any s upplemental natural gas used. Different flow monitoring methods may be used to measure different gaseous streams that make up the flare vent gas provided that the flow rates of all gas streams that contribute to the flare vent gas are determined. If assi st air or assist steam is used, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording the volumetri c flow rate of assist air and/or assist steam used with the flare. If pre-mix assist air and perimeter assist are both used, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of separately measuring, calculatin g, and recording the volumetric flow rate of premix assist air and perimeter assist air used with the flare. Continuously monitoring fan speed or power and using fan curves is an ac ceptable method for continuously monitoring assist air flow rates. (1) The flow rate monitoring systems must be able to correct for the temperature and pressure of the system and output parameters in standard conditions (i.e., a temperature of 20 °C (68 °F) and a pressure of 1 atmosphere). (2) Mass flow monitors may be used for determ ining volumetric flow ra te of flare vent gas provided the molecular weight of the flare ve nt gas is determined using compositional analysis as specified in paragraph (j) of this section so that the mass flow rate can be converted to volumetric flow at standard conditions using the following equation.Page 131 of 175



### M W t Q Q mass

vol 

### 385.3 



where: Q vol = Volumetric flow rate, standard cubic feet per second. Q mass = Mass flow rate, pounds per second. 385.3 = Conversion factor, standard cubic feet per pound-mole.MWt = Molecular weight of the gas at the flow monitoring location, pounds per poundmole. (3) Mass flow monitors may be used for determ ining volumetric flow rate of assist air or assist steam. Use equation in paragraph (i)(2) of this section to convert mass flow rates to volumetric flow rates. Use a molecular weig ht of 18 pounds per pound-mole for assist steam and use a molecular weight of 29 pounds per pound-mole for assist air. (4) Continuous pressure/temperature monitori ng system(s) and appropriate engineering calculations may be used in lieu of a cont inuous volumetric flow monitoring systems provided the molecular weight of the gas is know n. For assist steam, use a molecular weight of 18 pounds per pound-mole. For assist air, use a molecular weight of 29 pounds per pound-mole. For flare vent gas, molecular weight must be determined using compositional analysis as specified in paragraph (j) of this section. (j) Flare vent gas composition monitoring . The owner or operator shall determine the concentration of individual components in the flare vent gas using either the methods provided in paragraphs (j)(1) or (j)(2) of th is section, to assess compliance with the operating limits in paragraph (e) of this sectio n and, if applicable, paragraphs (d) and (f) of this section. Alternatively, the owner or op erator may elect to dire ctly monitor the net heating value of the flare vent gas following the methods provided in paragraphs (j)(3) of this section and, if desired, may directly measure the hydrogen con centration in the flare vent gas following the methods provided in par agraphs (j)(4) of this section. The owner or operator may elect to use diff erent monitoring methods for di fferent gaseous streams that make up the flare vent gas using different me thods provided the composition or net heating value of all gas streams th at contribute to the flare vent gas are determined. (1) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring (i.e., at least once every 15-minutes ), calculating, and recording the individual component concentrations pres ent in the flare vent gas. (2) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, and maintain a grab sampling system capable of collecting anPage 132 of 175

evacuated canister sample for subsequent compos itional analysis at least once every eight hours while there is flow of regulated materi al to the flare. Subsequent compositional analysis of the samples must be performe d according to Method 18 of 40 CFR part 60, Appendix A-6, ASTM D6420-99 (Reapproved 2010), ASTM D1945-03 (Reapproved 2010) , ASTM D1945-14 or ASTM UOP539-12 (all incorporated by reference—see §63.14). (3) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, calibrate, and mainta in a calorimeter capable of continuously measuring, calculating, and recording NHV vg. at standard conditions. (4) If the owner or operator uses a continuo us net heating value monitor according to paragraph (j)(3) of this sectio n, the owner or operator may, at their discretion, install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording the hydrogen concentration in the flare vent gas. (5) Direct compositional or net heating value monitoring is not required for purchased (“pipeline quality”) natural gas streams. The net heating value of purchased natural gas streams may be determined using annual or more frequent grab sampling at any one representative location. Alternatively, the net heating value of any purchased natural gas stream can be assumed to be 920 Btu/scf. (6) Direct compositional or net heating value monitoring is not required for gas streams that have been demonstrated to have consistent composition (or a fixed minimum net heating value) according to the methods in paragraphs (j)(6)(i) through (v). (i) The owner or operator shall submit to th e Administrator a written application for an exemption from monitoring. The application must contain the following information: (A) A description of the flare gas stream/system to be considered, including submission of a portion of the appropriate piping diagrams indicating the boundaries of the flare gas stream/system and the affected flare(s) to be considered; (B) A statement that there are no crossover or en try points to be introduced into the flare gas stream/system (this should be shown in the piping diagrams) prior to the point where the flow rate of the gas streams is measured; (C) An explanation of the conditions that en sure that the flare gas net heating value is consistent and, if flare gas net heating value is expected to vary (e.g., due to product loading of different material), the conditions expected to produce the flare gas with the lowest net heating value; (D) The supporting test results from sampling the requested flare gas stream/system for the net heating value. Sampling data must include, at minimum, 2 weeks of daily measurement values (14 grab samples) for frequently operated flare gas streams/systems; for infrequently operated flare gas streams/system s, seven grab samples must be collected unless other additional information would support reduced sampling. If the flare gasPage 133 of 175

stream composition can vary, samples must be taken during those conditions expected to result in lowest net heating value identifi ed in paragraph (j)(6)(i)(C). The owner or operator shall determine net heating value fo r the gas stream using either gas composition analysis or net heating value monitor (wit h optional hydrogen concentration analyzer) according to the method provided in paragraph (l) of this section; and (E) A description of how the 2 weeks (or seven samples for infrequently operated flare gas streams/systems) of monitoring results compares to the typical range of net heating values expected for the flare gas stream/syst em going to the affected flare ( e.g., “the samples are representative of typical operating conditions of the flare gas stream going to the loading rack flare” or “the samples are representative of conditions expected to yield the lowest net heating value of the flare gas stream going to the loading rack flare”). (F) The net heating value to be used for all fl ows of the flare vent gas from the flare gas stream/system covered in the application. A sing le net heating value must be assigned to the flare vent gas either by selecting the lowest net heating value measured in the sampling program or by determining the 95 th percent confidence interval on the mean value of all samples collected using the t-d istribution statistic (which is 1.943 for 7 grab samples or 1.771 for 14 grab samples). (ii) The effective date of the exemption is the date of submission of the information required in paragraph (j)(6 )(i) of this section. (iii) No further action is re quired unless refinery operating co nditions change in such a way that affects the exempt fuel gas stream/system (e.g., the stre am composition changes). If such a change occurs, the owner or operator shall follow the procedures in paragraph (j)(6)(iii)(A), (j) (6)(iii)(B), or (j)(6)(ii i)(C) of this section. (A) If the operation change results in a flare vent gas net heating value that is still within the range of net heating values included in the original application, the owner or operator shall determine the net heating value on a grab sample and record the results as proof that the net heating value assigned to the vent gas stream in the original application is still appropriate. (B) If the operation change results in a flare vent gas net heating value that is lower than the net heating value assigned to the vent gas stream in the original application, the owner or operator may submit new information follow ing the procedures of paragraph (j)(6)(i) of this section within 60 days (or within 30 days after the seventh grab sample is tested for infrequently operated process units). (C) If the operation change results in a fl are vent gas net heating value has greater variability in the flare gas stream/system such the owner or operator chooses not to submit new information to support an exemption, the owner or operator must begin monitoring the composition or net heat content of the flar e vent gas stream using the methods in this section (i.e., grab samples every 8 hours until such time a continuous monitor, if elected, is installed).Page 134 of 175

(k) Calculation methods for cumulative flow rates and determining compliance with V tip operating limits. The owner or operato r shall determine V tip on a 15-minute block average basis according to the following requirements. (1) The owner or operator shall use design a nd engineering principles to determine the unobstructed cross sectional area of the flare tip. The unobstructed cross sectional area of the flare tip is the total tip area that vent gas can pass through. This area does not include any stability tabs, stability rings, and upper st eam or air tubes because flare vent gas does not exit through them. (2) The owner or operator shall determine the cumulative volumet ric flow of flare vent gas for each 15-minute block average period us ing the data from the continuous flow monitoring system required in paragraph (i) of this section according to the following requirements, as applicable. If desired, the cumulative flow rate for a 15-minute block period only needs to include flow during thos e periods when regulated material is sent to the flare, but owners or operators may elect to calculate the cumulative flow rates across the entire 15-minute block period for any 15-mi nute block period wher e there is regulated material flow to the flare. (i) Use set 15-minute time periods starting at 12 midnight to 12:15 AM, 12:15 AM to 12:30 AM and so on concluding at 11:45 PM to midnight when calculating 15-minute block average flow volumes. (ii) If continuous pressure/temperature monito ring system(s) and engineering calculations are used as allowed under paragraph (i)(4) of th is section, the owner or operator shall, at a minimum, determine the 15-minute block ave rage temperature and pressure from the monitoring system and use those values to perform the engineering calculations to determine the cumulative flow over the 15-mi nute block average period. Alternatively, the owner or operator may divide the 15-minute block average period into equal duration subperiods (e.g., three 5-minute periods) a nd determine the average temperature and pressure for each subperiod, perform engineerin g calculations to determine the flow for each subperiod, then add the volumetric fl ows for the subperiods to determine the cumulative volumetric flow of vent gas for the 15-mi nute block average period. (3) The 15-minute block average V tip shall be calculated using the following equation.



### 900   Area Q V cum

tip

where:

V tip = Flare tip velocity, feet per second. Q cum = Cumulative volumetric flow over 15-mi nute block average period, standard cubic feet.Page 135 of 175

Area = Unobstructed area of the flare tip, square feet. 900 = Conversion factor, seconds per 15-minute block average. (4) If the owner or operator chooses to comply with paragraph (d)(2) of this section, the owner or operator shall also determine the net heating value of the flare vent gas following the requirements in paragraph (j) and (l) of this section and calculate V max using the equation in paragraph (d)(2) of th is section in order to compare V tip to V max on a 15-minute block average basis. (l) Calculation methods for determining flare vent gas net heating value . The owner or operator shall determine the net heatin g value of the flare vent gas (NHV vg ) based on the composition monitoring data on a 15-minute bl ock average basis according to the following requirements. (1) If compositional analysis data are collected as provided in paragraph (j)(1) or (2) of this section, the owner or op erator shall determine NHV vg of a specific sample by using the following equation. 

# 

 

###  n

i ii vg 

### NHVx NHV

1

where:

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

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

NHV i = Net heating value of compon ent i according to table 12 of this subpart, Btu/scf. If the component is not specified in table 12 of this subpart, th e heats of combustion may be determined using any published values where the net enthalpy per mole of offgas is based on combustion at 25 °C and 1 atmosphere (or constant pressure) with offgas water in the gaseous state, but the standard temperature for determining the volume corresponding to one mole of vent gas is 20 °C. (2) If direct net heating value monitoring data are collected as provided in paragraph (j)(3) of this section but a hydrogen concentration monitor is not used, the owner or operator shall use the direct output of the monitoring system(s) (in Btu/scf) to determine the NHV vg for the sample.Page 136 of 175

(3) If direct net heating value monitoring data are collected as provided in paragraph (j)(3) of this section and hydrogen concentration monitoring data are collected as provided in paragraph (j)(4) of this sectio n, the owner or operator shall use the following equation to determine NHV vg for each sample measured via the ne t heating value monitoring system.

2 

### 938 H measured vg 

### x NHV NHV  

where:

NHV vg = Net heating value of fl are vent gas, Btu/scf.

NHV measured = Net heating value of flare vent gas stream as measured by the continuous net heating value monito ring system, Btu/scf.

x H2 = Concentration of hydrogen in flare vent gas at the time the sample was input into the net heating value monitoring system, volume fraction. 938 = Net correction for the measured heating value of hydrogen (1,212 – 274), Btu/scf. (4) Use set 15-minute time periods starting at 12 midnight to 12:15 AM, 12:15 AM to 12:30 AM and so on concluding at 11:45 PM to midnight when calculating 15-minute block averages. (5) When a continuous monitoring system is us ed as provided in par agraphs (j)(1) or (j)(3) and, if applicable, (j)(4) of th is section, the owner or operat or may elect to determine the 15-minute block average NHV vg using the either the calculation methods in paragraph (l)(5)(i) of this section or the calculation methods in paragraph (l)(5)(ii) of this section. The owner or operator may choose to comply us ing the calculation methods in paragraph (l)(5)(i) of this section for some flares at the petroleum refinery and comply using the calculation methods (l)(5)(ii) of this section for other flares. However, for each flare, the owner or operator must elect one calculation me thod that will apply at all times, and use that method for all continuously monitored flare vent streams associated with that flare. If the owner or operator intends to change the calc ulation method that a pplies to a flare, the owner or operator must notify the Administ rator 30 days in advance of such a change. (i) Feed-forward calculation method . When calculating NHV vg for a specific 15-minute block: (A) Use the results from the firs t sample collected during an even t, (for periodic flare vent gas flow events) for the first 15-minute block associated with that event. (B) If the results from the first sample collect ed during an event (for p eriodic flare vent gas flow events) are not available until after the se cond 15-minute block starts, use the results from the first sample collected during an ev ent for the second 15-minute block associated with that event.Page 137 of 175

(C) For all other cases, use the results that ar e available from the most recent sample prior to the 15-minute block period fo r that 15-minute block period for all flare vent gas steams. For the purpose of this requirement, use the time that the results become available rather than the time the sample was collected. For exam ple, if a sample is collected at 12:25 AM and the analysis is completed at 12:38 AM, the results are available at 12:38 AM and these results would be used to determine complia nce during the 15-minute block period from 12:45 AM to 1:00 AM. (ii) Direct calculation method . When calculating NHV vg for a specific 15-minute block: (A) If the results from the first sample collect ed during an event (for p eriodic flare vent gas flow events) are not available until after the se cond 15-minute block starts, use the results from the first sample collected during an even t for the first 15-minute block associated with that event. (B) For all other cases, use the arithmetic average of all NHV vg measurement data results that become available during a 15-minute bloc k to calculate the 15-minute block average for that period. For the purpose of this requi rement, use the time that the results become available rather than the time the sample was collected. For example, if a sample is collected at 12:25 AM and the analysis is co mpleted at 12:38 AM, the results are available at 12:38 AM and these results would be used to determine compliance during the 15- minute block period from 12:30 AM to 12:45 AM. (6) When grab samples are used to determine flare vent gas composition: (i) Use the analytical results from the first grab sample collected for an event for all 15- minute periods from the start of the event through the 15-minute block prior to the 15- minute block in which a subsequent grab sample is collected. (ii) Use the results from subse quent grab sampling events for all 15 minute periods starting with the 15-minute block in which the sample was collected and ending with the 15-minute block prior to the 15-minute bl ock in which the next grab sample is collected. For the purpose of this requirement, use the time the sample was collected rather than the time the analytical results become available. (7) If the owner or operator monitors separate gas streams that combine to comprise the total flare vent gas flow, the 15-minute block av erage net heating value shall be determined separately for each measurement location acco rding to the methods in paragraphs (l)(1) through (l)(6) of this section and a flow-wei ghted average of the gas stream net heating values shall be used to determine the 15-minu te block average net heating value of the cumulative flare vent gas. (m) Calculation methods for determining combustion zone net heating value . The owner or operator shall determine the net heating value of the combustion zone gas (NHV cz ) as specified in paragraphs (m)(1 ) or (m)(2), as applicable.Page 138 of 175

(1) Except as specified in paragraph (m)(2), determine the 15-minute block average NHV cz based on the 15-minute block average vent gas a nd assist gas flow rates using the following equation. For periods when there is no assist steam flow or premix assist air flow, NHV cz = NHV vg . 

#   a,premix svg vg vg cz QQQ NHVQ NHV  



where:

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

NHV vg = Net heating value of flare vent gas for the 15-minute bloc k period, Btu/scf. Q vg = Cumulative volumetric flowof flare vent gas during th e 15-minute block period, scf. Q s = Cumulative volumetric flow of total steam during the 15-minute block period, scf. Q a,premix = Cumulative volumetric flow of prem ix assist air during the 15-minute block period, scf. (2) Owners or operators of flares that us e the feed-forward calc ulation methodology in paragraph (l)(5)(i) of this sect ion and that monitor gas composition or net heating value in a location representative of the cumulative vent gas stream and that directly monitor supplemental natural gas flow additions to th e flare must determin e the 15-minute block average NHV cz using the following equation. 

#     

#   a,premix svg NG NG NG vg NG NG vg cz QQQ NHV QQNHV QQQ NHV  

  

 1 2 1 2

where:

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

NHV vg = Net heating value of flare vent gas for the 15-minute bloc k period, Btu/scf. Q vg = Cumulative volumetric flowof flare vent gas during th e 15-minute block period, scf. Q NG2 = Cumulative volumetric flow of suppleme ntal natural gas to the flare during the 15- minute block period, scf. Q NG1 = Cumulative volumetric flow of supple mental natural gas to the flare during the previous 15-minute block period, scf. For the fi rst 15-minute block peri od of an event, use the volumetric flow value for the cu rrent 15-minute block period, i.e., Q NG1 =Q NG2 .Page 139 of 175

NHV NG = Net heating value of supplemental na tural gas to the flare for the 15-minute block period determined according to the requi rements in paragraph (j)(5) of this section, Btu/scf. Q s = Cumulative volumetric flow of total steam during the 15-minute block period, scf. Q a,premix = Cumulative volumetric flow of prem ix assist air during the 15-minute block period, scf. (n) Calculation methods for determining the net heating value dilution parameter . The owner or operator shall determine the net heating value dilution parameter (NHV dil ) as specified in paragraphs (n)(1) or (n)(2), as applicable. (1) Except as specified in paragraph (n)(2), determine the 15-minut e block average NHV dil based on the 15-minute block average vent gas a nd perimeter assist air flow rates using the following equation only during periods when perimeter assist air is used. For 15-minute block periods when there is no cumulative volu metric flow of perimeter assist air, the 15- minute block average NHV dil parameter does not need to be calculated. 

#   ra,perimete a,premix svg vg vg dil QQQQ NHV DiamQ NHV  



where:

NHV dil = Net heating value dilution parameter, Btu/ft 2

. NHV vg = Net heating value of flare vent gas de termined for the 15-mi nute block period, Btu/scf. Q vg = Cumulative volumetric flowof flare vent gas during th e 15-minute block period, scf.

Diam = Effective diameter of the unobstructed a rea of the flare tip for flare vent gas flow, ft. Use the area as determined in paragra ph (k)(1) of this section and determine the diameter as 

### π Area Diam  2

. Q s = Cumulative volumetric flow of total steam during the 15-minute block period, scf. Q a,premix = Cumulative volumetric flow of prem ix assist air during the 15-minute block period, scf. Q a,perimeter = Cumulative volumetric flow of perime ter assist air during the 15-minute block period, scf. (2) Owners or operators of flares that us e the feed-forward calc ulation methodology in paragraph (l)(5)(i) of this sect ion and that monitor gas composition or net heating value inPage 140 of 175

a location representative of the cumulative vent gas stream and th at directly monitor supplemental natural gas flow additions to th e flare must determin e the 15-minute block average NHV dil using the following equation only dur ing periods when perimeter assist air is used. For 15-minute block periods when th ere is no cumulative volumetric flow of perimeter assist air, the 15-minute block average NHV dil parameter does not need to be calculated. 

#     

#     ra,perimete a,premix svg NG NG NG vg NG NG vg dil QQQQ Diam NHV QQNHV QQQ NHV   

  

 1 2 1 2

where:

NHV dil = Net heating value dilution parameter, Btu/ft 2

. NHV vg = Net heating value of flare vent gas de termined for the 15-mi nute block period, Btu/scf. Q vg = Cumulative volumetric flowof flare vent gas during th e 15-minute block period, scf. Q NG2 = Cumulative volumetric flow of suppleme ntal natural gas to the flare during the 15- minute block period, scf. Q NG1 = Cumulative volumetric flow of suppleme ntal natural gas to the flare during the previous 15-minute block period, scf. For the fi rst 15-minute block peri od of an event, use the volumetric flow value for the cu rrent 15-minute block period, i.e., Q NG1 =Q NG2 . NHV NG = Net heating value of supplemental na tural gas to the flare for the 15-minute block period determined according to the requi rements in paragraph (j)(5) of this section, Btu/scf.

Diam = Effective diameter of the unobstructed a rea of the flare tip for flare vent gas flow, ft. Use the area as determined in paragra ph (k)(1) of this section and determine the diameter as 

### π Area Diam  2

. Q s = Cumulative volumetric flow of total steam during the 15-minute block period, scf. Q a,premix = Cumulative volumetric flow of prem ix assist air during the 15-minute block period, scf. Q a,perimeter = Cumulative volumetric flow of perime ter assist air during the 15-minute block period, scf. (o) Emergency Flaring Provisions . The owner or operator of a flare that can receive regulated material under any circumstance during an emergency release event shall comply with the provisions in paragraphs (o)(1) through (o)(8) of this section.Page 141 of 175

(1) Develop a flare management plan to mi nimize flaring during periods of startup, shutdown, or emergency releases. The fl are management plan must include the information described in paragraphs (o)(1)(i) through (vii) of this section. (i) A listing of all refinery process units, ancillary equipment, and fuel gas systems connected to the flare for each affected flare. (ii) An assessment of whether discharges to affected flares from these process units, ancillary equipment and fuel gas systems can be minimized or prevented during periods of startup, shutdown, or emergency releases. Th e flare minimization assessment must (at a minimum) consider the items in paragraphs (o)(1 )(ii)(A) through (C) of this section. The assessment must provide clear ra tionale in terms of costs (c apital and annual operating), natural gas offset credits (if applicable), te chnical feasibility, secondary environmental impacts and safety considerations for the se lected minimization alternative(s) or a statement, with justifications, that flow re duction could not be achieved. Based upon the assessment, each owner or operator of an affe cted flare shall identify the minimization alternatives that it has implemented by the due date of the flare management plan and shall include a schedule for the prompt implem entation of any selected measures that cannot reasonably be completed as of that date. (A) Modification in startup and shutdown pro cedures to reduce the quantity of process gas discharge to the flare. (B) Implementation of preven tion measures listed for pressure relief devices in §63.648(j)(5) for each pressure relief valve that can di scharge to the flare. (C) Installation of a flare gas recovery system or , for facilities that are fuel gas rich, a flare gas recovery system and a co-generation unit or combined heat and power unit. (iii) A description of each affected flare containing the information in paragraphs (o)(1)(iii)(A) through (G) of this section. (A) A general description of the flare, includi ng whether it is a ground flare or elevated (including height), the ty pe of assist system ( e.g., air, steam, pressure, non-assisted), whether the flare is used on a routine basis or if it is only used during periods of startup, shutdown or emergency release, and whether th e flare is equipped with a flare gas recovery system. (B) The smokeless capacity of the flare based on design condi tions. Note: a single value must be provided for the smokeless capacity of the flare. (C) The maximum vent gas flow ra te (hydraulic load capacity). (D) The maximum supplemental gas flow rate.Page 142 of 175

(E) For flares that receive assist steam, the minimum total steam rate and the maximum total steam rate. (F) For flares that receive assist air, an indica tion of whether the fan/blower is single speed, multi-fixed speed (e.g., high, me dium, and low speeds), or variable speeds. For fans/blowers with fixed speeds, provide the estimated assi st air flow rate at each fixed speed. For variable speeds, provide the design fan curve (e.g., air flow rate as a function of power input). (G) Simple process flow diagram showing the lo cations of the flare following components of the flare: flare tip (date inst alled, manufacturer, nominal a nd effective tip diameter, tip drawing); knockout or surge drum(s) or po t(s) (including dime nsions and design capacities); flare header(s) and subheader( s); assist system; and ignition system. (iv) Description and simple process flow di agram showing all gas lines (including flare waste gas, purge or sweep gas (as applicable), supplemental gas) that are associated with the flare. For purge, sweep, supplemental gas, identify the type of gas used. Designate which lines are exempt from composition or net heating value monitoring and why ( e.g., natural gas, gas streams that have been demonstr ated to have consistent composition, pilot gas). Designate which lines are monitored and identify on the process flow diagram the location and type of each monitor. Designate the pressure relief devices that are vented to the flare. (v) For each flow rate, gas composition, net heating value or hydrogen concentration monitor identified in paragraph (o)(1)(iv) of th is section, provide a detailed description of the manufacturer's specifications, including, but not limited to, make, model, type, range, precision, accuracy, calibration, maintenance and quality assurance procedures. (vi) For each pressure relief valve vented to the flare identified in (o)(1)(iv), provide a detailed description of each pressure release va lve, including type of relief device (rupture disc, valve type) diameter of th e relief valve, set pressure of the relief valve and listing of the prevention measures implemented. This information may be maintained in an electronic database on-site and does not n eed to be submitted as part of the flare management plan unless requested to do so by the Administrator. (vii) Procedures to minimize or eliminate disc harges to the flare during the planned startup and shutdown of the refinery process units an d ancillary equipment that are connected to the affected flare, together with a schedul e for the prompt implementation of any procedures that cannot reasonably be implemente d as of the date of the submission of the flare management plan. (2) Each owner or operator required to develop and implement a written flare management plan as described in paragraph (o)(1 ) of this section must submit the plan to the Administrator as described in paragraphs (o)(2)(i) through (iii) of this section.Page 143 of 175

(i) The owner or operator must develop and im plement the flare management plan no later than [insert date 3 years and 60 days after date of publication in the Federal Register], or at startup for a new flare that commenced cons truction on or after [insert date 60 days after date of publication in the Federal Register]. (ii) The owner or operator must comply with th e plan as submitted by the date specified in paragraph (o)(2)(i) of this section. The plan sh ould be updated periodically to account for changes in the operation of the flare, such as new connections to the flare or the installation of a flare gas recovery system, but the plan need be re-submit ted to the Administrator only if the owner or operator alters the design sm okeless capacity of the flare. The owner or operator must comply with the updated plan as submitted. (iii) All versions of the plan submitted to th e Administrator shall also be submitted to the following address: U.S. Environmental Protec tion Agency, Office of Air Quality Planning and Standards, Sector Policies and Program s Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 109 T.W. Al exander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refinerynsps@epa.gov

. (3) The owner or operator of a flare subject to this subpart shall conduct a root cause analysis and a corrective action analysis for each flow event that contains regulated material and that meets either th e criteria in paragraphs (o)(3)(i) or (ii) of this section. (i) The vent gas flow rate exceeds the smokeless capacity of the flare and visible emissions are present from the flare fo r more than 5 minutes during any 2 consecutive hours during the release event. (ii) The vent gas flow rate exceeds the smok eless capacity of the flare and the 15-minute block average flare tip velocity exceeds the maximum flar e tip velocity determined using the methods in paragraph (d)(2) of this section. (4) A root cause analysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a flare flow event meeting the criteria in paragraphs (o)(3)(i) or (ii) of this section. Special circumstances affecting the number of root cause analyses and/or corrective action analyses are provided in paragraphs (o)(4)(i) through (v) of this section. (i) You may conduct a single root cause analysis and corrective action analysis for a single continuous flare flow event that meets both of the criteria in paragraphs (o)(3)(i) and (ii) of this section. (ii) You may conduct a single root cause analysis and corrective action analysis for a single continuous flare flow event regardless of th e number of 15-minute block periods in which the flare tip velocity was exceed ed or the number of 2 hour p eriods that contain more the 5 minutes of visible emissions.Page 144 of 175

(iii) You may conduct a single root cause analysis and corrective action analysis for a single event that causes two or more flares that are op erated in series (i.e., cascaded flare systems) to have a flow event meeting the criteria in pa ragraphs (o)(3)(i) or (ii) of this section. (iv) You may conduct a single root cause analysis and corrective action analysis for a single event that causes two or more flares to have a flow event meeting the criteria in paragraphs (o)(3)(i) or (ii) of this section, regardless of the configuration of the flares, if the root cause is reasonably expected to be a force maje ure event, as define d in this subpart. (v) Except as provided in paragraphs (o)(4)(iii) a nd (iv) of this section, if more than one flare has a flow event that meet s the criteria in paragraphs (o)(3 )(i) or (ii) of this section during the same time period, an initial root cause an alysis shall be conducted separately for each flare that has a flow even t meeting the criteria in paragr aph (o)(3)(i) or (ii) of this section. If the initial root cause analysis indi cates that the flow events have the same root cause(s), the initially separate root cause anal yses may be recorded as a single root cause analysis and a single corrective action analysis may be conducted. (5) Each owner or operator of a flare re quired to conduct a root cause analysis and corrective action analysis as specified in pa ragraphs (o)(3) and (o)(4) shall implement the corrective action(s) identified in the corrective action anal ysis in accordance with the applicable requirements in paragraphs (o )(5)(i) through (iii) of this section. (i) All corrective action(s) must be implemen ted within 45 days of the event for which the root cause and corrective action analyses were required or as soon thereafter as practicable. If an owner or operator conc ludes that no corrective action should be implemented, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the event. (ii) For corrective actions that cannot be fully implemented within 45 days following the event for which the root cause and corrective action analyses were required, the owner or operator shall develop an implementation sche dule to complete the corrective action(s) as soon as practicable. (iii) No later than 45 days following the even t for which a root cause and corrective action analyses were required, the owner or operato r shall record the corrective action(s) completed to date, and, for action(s) not alrea dy completed, a schedule for implementation, including proposed commencement and completion dates. (6) The owner or operator shall determine th e total number of events for which a root cause and corrective action analyses was re quired during the calendar year for each affected flare separately for events meeting th e criteria in paragraph (o )(3)(i) of this section and those meeting the criteria in paragraph (o)(3)(i i) of this section. For the purpose of this requirement, a single root cause analysis co nducted for an event that met both of the criteria in paragraph (o)(3)(i) and (ii) of this section would be counted as an event under each of the separate criteria counts for that flare. Additionally, if a single root cause analysis was conducted for an event that caused multiple flares to meet the criteria inPage 145 of 175

paragraph (o)(3)(i) or (ii) of this section, that event would count as an event for each of the flares for each criteria in paragraph (o)(3) of this section that was met during that event. The owner or operator shall also determine th e total number of events for which a root cause and correct action analyses was required and the analyses concluded that the root cause was a force majeure event, as defined in this subpart. (7) The following events would be a violatio n of this emergency flaring work practice standard. (i) Any flow event for which a root cause analysis was required and the root cause was determined to be operator error or poor maintenance. (ii) Two visible emissions exceedance events meet ing the criteria in paragraph (o)(3)(i) that were not caused by a force majeure event from a single flare in a 3 calendar year period for the same root cause for the same equipment. (iii) Two flare tip velocity exceedance events m eeting the criteria in paragraph (o)(3)(ii) that were not caused by a force majeure event from a single flare in a 3 calendar year period for the same root cause for the same equipment. (iv) Three visible emissions exceedance events meeting the criteria in paragraph (o)(3)(i) that were not caused by a force majeure event from a single flare in a 3 calendar year period for any reason. (v) Three flare tip velocity exceedance events meeting the criteria in paragraph (o)(3)(ii) that were not caused by a force majeure event from a single flare in a 3 calendar year period for any reason. (p) Flare monitoring records . The owner or operator shall k eep the records specified in §63.655(i)(9). (q) Reporting . The owner or operator shall comply with the reporting requirements specified in §63.655(g)(11). (r) Alternative means of emissions limitation . An owner or operator may request approval from the Administrator for site-specific operati ng limits that shall apply specifically to a selected flare. Site-specific operating limit s include alternative threshold values for the parameters specified in paragraphs (d) thro ugh (f) of this section as well as threshold values for operating parameters other than thos e specified in paragraphs (d) through (f) of this section. The owner or operator must de monstrate that the fl are achieves 96.5 percent combustion efficiency (or 98 percent destructio n efficiency) using the site-specific operating limits based on a performance evaluation as de scribed in paragraph (r)(1) of this section. The request shall include information as describe d in paragraph (r)(2) of this section. The request shall be submitted and followed as des cribed in paragraph (r)( 3) of this section.Page 146 of 175

(1) The owner or operator shall prepare and submit a site-specific test plan and receive approval of the site-specific performance eval uation plan prior to conducting any flare performance evaluation test runs intended fo r use in developing site-specific operating limits. The site-specifi c performance evaluation plan sh all include, at a minimum, the elements specified in paragraphs (r)(1)(i) throug h (ix) of this section. Upon approval of the site-specific performance evaluation pl an, the owner or operator shall conduct performance evaluation test runs for the fla re following the procedures described in the site-specific performance evaluation plan. (i) The design and dimensions of the flare, fla re type (air-assisted only, steam-assisted only, air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being flared, including quantity of gas flared, frequenc y of flaring events (if periodic), expected net heating value of flare vent gas , minimum total steam assist rate. (ii) The operating conditions (vent gas compos itions, vent gas flow rates and assist flow rates, if applicable) likely to be encountered by the flare during normal operations and the operating conditions for the test period. (iii) A description of (i ncluding sample calculations illust rating) the planned data reduction and calculations to determine the flare combustion or destruction efficiency. (iv) Site-specific operating parameters to be monitored continuously during the flare performance evaluation. These parameters may in clude but are not limited to vent gas flow rate, steam and/or air assist flow rates, and flare vent gas composition. If new operating parameters are proposed for use other than th ose specified in paragraphs (d) through (f) of this section, an explanation of the relevance of the proposed operating parameter(s) as an indicator of flare combustion performance an d why the alternative operating parameter(s) can adequately ensure that the flare achi eves the required combustion efficiency. (v) A detailed description of the measu rement methods, monitored pollutant(s), measurement locations, measurement freque ncy, and recording frequency proposed for both emission measurements and flare operating parameters. (vi) A description of (i ncluding sample calculations illust rating) the planned data reduction and calculations to determine the flare operating parameters. (vii) The minimum number and length of test runs and range of operating values to be evaluated during the performance evaluation. A sufficient number of test runs shall be conducted to identify the point at which the co mbustion/destruction efficiency of the flare deteriorates. (viii) [Reserved] (ix) Test schedule.Page 147 of 175

(2) The request for flare-specific operating lim its shall include suffi cient and appropriate data, as determined by the Ad ministrator, to allow the Administrator to confirm that the selected site-specific operati ng limit(s) adequately ensures that the flare destruction efficiency is 98 percent or greater or that the flare com bustion efficiency is 96.5 percent or greater at all times. At a minimum, the request shall contain the information described in paragraphs (r)(2)(i) through (iv) of this section. (i) The design and dimensions of the flare, fla re type (air-assisted only, steam-assisted only, air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being flared, including quantity of gas flared, frequenc y of flaring events (if periodic), expected net heating value of flare vent gas , minimum total steam assist rate. (ii) Results of each performa nce evaluation test run conducted, including, at a minimum: (A) The measured combustion/destruction efficiency. (B) The measured or calculated operating pa rameters for each test run. If operating parameters are calculated, the raw data from which the parameters are calculated must be included in the test report. (C) Measurement location descriptions fo r both emission measurements and flare operating parameters. (D) Description of sampling and analysis proce dures (including number and length of test runs) and any modifications to standard procedures. If there were deviations from the approved test plan, a detailed description of the deviations and rationale why the test results or calculation procedures used are appropriate. (E) Operating conditions (e.g., vent gas composition, assist rates, etc.) that occurred during the test. (F) Quality assurance procedures. (G) Records of calibrations. (H) Raw data sheets for field sampling. (I) Raw data sheets for field and laboratory analyses. (J) Documentation of calculations. (iii) The selected flare-specifi c operating limit values based on the performance evaluation test results, including the av eraging time for the operating limit(s), and rationale why the selected values and averaging times are suff iciently stringent to ensure proper flare performance. If new operating parameters or averaging times are proposed for use other than those specified in paragraphs (d) through (f) of this section, an explanation of why thePage 148 of 175

alternative operating parameter(s) or aver aging time(s) adequately ensures the flare achieves the required combustion efficiency. (iv) The means by which the owner or op erator will document on-going, continuous compliance with the selected flare-specific operating limit( s), including the specific measurement location and frequencies, calculation procedures, and records to be maintained. (3) The request shall be submitted as described in paragraphs (r)(3)(i) through (iv) of this section. (i) The owner or operator may request approval from the Administrator at any time upon completion of a performance evaluation co nducted following the methods in an approved site-specific performance evaluation plan for an operating limit (s) that shall apply specifically to that flare. (ii) The request must be submitted to the Administrator for approval. The owner or operator must continue to comply with the app licable standards for flares in this subpart until the requirements in 40 CFR 63.6(g)(1) are met and a notice is published in the Federal Register allowing use of such an alt ernative means of emission limitation. (iii) The request shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Plan ning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E14 3–01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park , NC 27711. Electronic copies in lieu of hard copies may also be submitted to refineryrtr@epa.gov. (iv) If the Administrator finds any deficiencies in the request, the request must be revised to address the deficiencies and be re-submitted for approval within 45 days of receipt of the notice of deficiencies. The owner or operator must comply with the revised request as submitted until it is approved. (4) The approval process for a request for a fla re-specific operating li mit(s) is described in paragraphs (r)(4)(i) through (iii) of this section. (i) Approval by the Administrator of a flare-specific operating limit(s) request will be based on the completeness, accuracy and reasonableness of the request. Factors that the EPA will consider in reviewing the request for appr oval include, but are not limited to, those described in paragraphs (r)(4)(i)(A) through (C) of this section. (A) The description of the flare desi gn and operating characteristics. (B) If a new operating paramete r(s) other than those specifie d in paragraphs (d) through (f) of this section is proposed, the explanatio n of how the proposed operating parameter(s) serves a good indicator(s) of flare combustion performance.Page 149 of 175

(C) The results of the flare p erformance evaluation test r uns and the establishment of operating limits that ensures that the flare dest ruction efficiency is 98 percent or greater or that the flare combustion efficiency is 96.5 percent or greater at all times. (D) The completeness of the flare p erformance evaluation test report. (ii) If the request is approved by the Admini strator, a flare-specific operating limit(s) will be established at the level(s) de monstrated in the approved request. (iii) If the Administrator finds any deficiencies in the request, the request must be revised to address the deficiencies and be re-submitted for approval. § 63.671 Requirements for flare monitoring systems. (a) Operation of CPMS . For each CPMS installed to comply with applicable provisions in §63.670, the owner or operator shall install, opera te, calibrate, and maintain the CPMS as specified in paragraphs (a)(1) through (8) of this section. (1) Except for CPMS installed for pilot flame monitoring, all monitoring equipment must meet the applicable minimum accuracy, ca libration and quality control requirements specified in table 13 of this subpart. (2) The owner or operator shall ensure the readout (that portion of the CPMS that provides a visual display or record) or oth er indication of the monitored operating parameter from any CPMS required for comp liance is readily a ccessible onsite for operational control or inspection by the operator of the source. (3) All CPMS must complete a minimum of on e cycle of operation (sampling, analyzing and data recording) for each successive 15-minute period. (4) Except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments), the own er or operator shall operate all CPMS and collect data continuously at all times when regulated emissions are routed to the flare. (5) The owner or operator shall operate, main tain, and calibrate each CPMS according to the CPMS monitoring plan specified in paragraph (b) of this section. (6) For each CPMS except for CPMS installe d for pilot flame monitoring, the owner or operator shall comply with the out-of-control procedures described in paragraphs (c) of this section. (7) The owner or operator shall reduce data from a CPMS as specified in paragraph (d) of this section.Page 150 of 175

(8) The CPMS must be capable of measuring the appropriate parameter over the range of values expected for that measurement location . The data recording system associated with each CPMS must have a resolution that is equal to or better than the required system accuracy. (b) CPMS monitoring plan . The owner or operator shall develop and implement a CPMS quality control program documented in a CPMS monitoring plan that covers each flare subject to the provisions in §63.670 and each CP MS installed to comp ly with applicable provisions in §63.670. The owner or operator shall have the CPMS monitoring plan readily available on-site at all times and shall submit a copy of the CPMS monitoring plan to the Administrator upon request by the Administ rator. The CPMS monitoring plan must contain the information listed in paragra phs (b)(1) through (5) of this section. (1) Identification of the specific flare being mo nitored and the flare type (air-assisted only, steam-assisted only, air- and steam-assist ed, pressure-assisted, or non-assisted). (2) Identification of the parameter to be monitored by the CPMS and the expected parameter range, including worst case and normal operation. (3) Description of the monitoring equipment, including the information specified in (b)(3)(i) through (vii) of this section. (i) Manufacturer and model number for all monito ring equipment components installed to comply with applicable provisions in §63.670. (ii) Performance specifications, as provide d by the manufacturer, and any differences expected for this installation and operation. (iii) The location of the CPMS sampling probe or other interface and a justification of how the location meets the requirements of paragraph (a)(1) of this section. (iv) Placement of the CPMS readout, or other indication of parameter values, indicating how the location meets the requirements of paragraph (a)(2) of this section. (v) Span of the CPMS. The span of the CPMS sensor and analyzer must encompass the full range of all expected values. (vi) How data outside of the span of the CP MS will be handled and the corrective action that will be taken to reduce and elim inate such occurrences in the future. (vii) Identification of the parameter detected by the parametric signal analyzer and the algorithm used to convert these values in to the operating parameter monitored to demonstrate compliance, if the parameter detected is different from the operating parameter monitored.Page 151 of 175

(4) Description of the data collection and re duction systems, including the information specified in paragraphs (b)(4)(i) through (iii) of this section. (i) A copy of the data acquisition system algor ithm used to reduce the measured data into the reportable form of the standard and to calculate the applicable averages. (ii) Identification of whether the algor ithm excludes data collected during CPMS breakdowns, out-of-control periods, repairs, ma intenance periods, instrument adjustments or checks to maintain precision and accuracy, calibration checks, and zero (low-level), midlevel (if applicable) and high-level adjustments. (iii) If the data acquisition algorithm do es not exclude data collected during CPMS breakdowns, out-of-control periods, repairs, ma intenance periods, instrument adjustments or checks to maintain precision and accuracy, calibration checks, and zero (low-level), midlevel (if applicable) and high-level adjus tments, a description of the procedure for excluding this data when the averages calculat ed as specified in paragraph (e) of this section are determined. (5) Routine quality control and assurance pr ocedures, including descriptions of the procedures listed in paragraphs (b)(5)(i) thro ugh (vi) of this section and a schedule for conducting these procedures. The routine proce dures must provide an assessment of CPMS performance. (i) Initial and subsequent calibration of the CPMS and acceptance criteria. (ii) Determination and adjustment of the calibration drift of the CPMS. (iii) Daily checks for indications that the system is responding. If the CPMS system includes an internal system check, the owner or operator may use the resul ts to verify the system is responding, as long as the system provides an alarm to the owner or operator or the owner or operator checks the internal system result s daily for proper operation and the results are recorded. (iv) Preventive maintenance of the CP MS, including spare parts inventory. (v) Data recording, calculations and reporting. (vi) Program of corrective action for a CPMS that is not operating properly. (c) Out-of-control periods . For each CPMS installed to comp ly with applicable provisions in §63.670 except for CPMS installed for pilot flam e monitoring, the owner or operator shall comply with the out-of-control procedures described in paragraphs (c)(1) and (2) of this section. (1) A CPMS is out-of-control if the zero (low-l evel), mid-level (if appl icable) or high-level calibration drift exceeds two times the accura cy requirement of table 13 of this subpart.Page 152 of 175

(2) When the CPMS is out of control, the owner or operator shall take the necessary corrective action and repeat all necessary tests that indicate the system is out of control. The owner or operator sha ll take corrective action and conduct retesting until the performance requirements are below the applic able limits. The beginning of the out-ofcontrol period is the hour a performance check ( e.g. , calibration drift) that indicates an exceedance of the performance requirements estab lished in this section is conducted. The end of the out-of-control period is the hour following the completion of corrective action and successful demonstration that the system is within the allowable limits. The owner or operator shall not use data recorded during peri ods the CPMS is out of control in data averages and calculations, used to report emis sions or operating levels, as specified in paragraph (d)(3) of this section. (d) CPMS data reduction . The owner or operator shall reduce data from a CPMS installed to comply with applicable provisions in §63.670 as specified in paragraphs (d)(1) through (3) of this section. (1) The owner or operator may round the data to the same number of significant digits used in that operating limit. (2) Periods of non-operation of the process uni t (or portion thereof) resu lting in cessation of the emissions to which the monitoring applie s must not be included in the 15-minute block averages. (3) Periods when the CPMS is out of control must not be included in the 15-minute block averages. (e) Additional requirements for gas chromatographs . For monitors used to determine compositional analysis for net heating value per §63.670(j)(1), the gas chromatograph must also meet the requirements of paragraphs (e)(1) through (3) of this section. (1) The quality assurance requirements are in table 13 of this subpart. (2) The calibration gases must meet one of the following options: (i) The owner or operator must use a calibration gas or multiple gases that include all of compounds listed in paragraphs (e)(2)(i)(A) through (K) of this section that may be reasonably expected to exist in the flare gas stream and op tionally include any of the compounds listed in paragraphs (e)(2)(i)(L) through (O) of this section. All of the calibration gases may be comb ined in one cylinder. If mu ltiple calibration gases are necessary to cover all compounds, the owner or operator must calibrate the instrument on all of the gases. (A) Hydrogen. (B) Methane.Page 153 of 175

(C) Ethane. (D) Ethylene. (E) Propane. (F) Propylene. (G) n-Butane. (H) iso-Butane. (I) Butene (general). It is not necessary to separately speciate butene isomers, but the net heating value of trans-butene must be used for co-eluting butene isomers. (J) 1,3-Butadiene. It is not necessary to separa tely speciate butadiene isomers, but you must use the response factor and net heating value of 1,3-butadiene for co-eluting butadiene isomers. (K) n-Pentane. Use the response factor for n- pentane to quantify all C5+ hydrocarbons. (L) Acetylene (optional). (M) Carbon monoxide (optional). (N) Propadiene (optional). (O) Hydrogen sulfide (optional). (ii) The owner or operator must use a surroga te calibration gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All of the calibration gases may be combined in one cylinder. If multiple calibration gases are n ecessary to cover all compounds, the owner or operator must calibrate the inst rument on all of the gases. (3) If the owner or operator chooses to us e a surrogate calibration gas under paragraph (e)(2)(ii) of this section, the owner or operator must comply with the following paragraphs. (i) Use the response factor for the nearest normal hydrocarbon (i.e., n-alkane) in the calibration mixture to quantify unknown components detected in the analysis. (ii) Use the response factor for n-pentane to quantify unknown components detected in the analysis that elute after n-pentane. §§ 63.672 -63.679 [Reserved] Appendix to Subpart CC of Part 63—TablesPage 154 of 175

Table 1—Hazardous Air Pollutants Chemical name CAS No. a Benzene 71432 Biphenyl 92524 Butadiene (1,3) 106990 Carbon disulfide 75150 Carbonyl sulfide 463581 Cresol (mixed isomers b ) 1319773 Cresol (m-) 108394 Cresol (o-) 95487 Cresol (p-) 106445 Cumene 98828 Dibromoethane (1,2) (e thylene dibromide) 106934 Dichloroethane (1,2) 107062 Diethanolamine 111422 Ethylbenzene 100414 Ethylene glycol 107211 Hexane 110543 Methanol 67561 Methyl isobutyl ketone (hexone) 108101 Methyl tert butyl ether 1634044 Naphthalene 91203 Phenol 108952 Toluene 108883 Trimethylpentane (2,2,4) 540841 Xylene (mixed isomers b ) 1330207 xylene (m-) 108383 xylene (o-) 95476 xylene (p-) 106423

a CAS number = Chemical Abstra ct Service registry number assigned to specific compounds, isomers, or mixtures of compounds.

b Isomer means all structural arrangements for th e same number of atoms of each element and does not mean salts, es ters, or derivatives.

Table 2—Leak Definitions for Pumps and Valves Standard a Phase Leak definition (parts per million) §63.163 (pumps) I 10,000 II 5,000 III 2,000 §63.168 (valves) I 10,000 II 1,000Page 155 of 175

III 1,000

a Subpart H of this part.

Table 3—Equipment Leak Recordkeeping and Reporting Requirements for Sources Complying With §63.648 of Subpart CC by Co mpliance With Subpart H of this Part a

Reference (section of subpart H of

this part) Description Comment 63.181(a) Recordkeeping system requirements Except for §§63.181(b)(2)(iii) and 63.181(b)(9). 63.181(b) Records required for process unit equipment Except for §§63.181(b)(2)(iii) and 63.181(b)(9). 63.181(c) Visual inspection documentation Except for §§63.181(b)(2)(iii) and 63.181(b)(9). 63.181(d) Leak detection record requirements Except for §63.181(d)(8). 63.181(e) Compliance requirements for pressure tests for batch product process equipment trains This subsection does not apply to subpart CC.

63.181(f) Compressor compliance test records. 63.181(g) Closed-vent systems and control device record requirements. 63.181(h) Process unit quality improvement program records. 63.181(i) Heavy liquid service determination record. 63.181(j) Equipment identification record. 63.181(k) Enclosed-vented process unit emission limitation record requirements. 63.182(a) Reports. 63.182(b) Initial no tification report requirements. Not required. 63.182(c) Notification of compliance status report Except in §63.182(c); change “within 90 days of the compliance dates” to “within 150 days of the compliance dates”; except in §§63.182 (c)(2) and (c)(4).Page 156 of 175

63.182(d) Periodic report Except for §§63.182 (d)(2)(vii), (d)(2)(viii), and (d)(3).

a This table does not include all the requirement s delineated under the re ferenced sections. See referenced sections for specific requirements.

Table 4—Gasoline Distribution Emission Point Recordkeeping and Reporting Requirements a Reference (section of subpart R) Description Comment 63.428(b) or (k) Records of test results for each gasoline cargo tank loaded at the facility 63.428(c) Continuous monitoring data recordkeeping requirements 63.428(g)(1) Semiannual report loading rack information Required to be submitted with the Periodic Report required under 40 CFR part 63, subpart CC. 63.428(h)(1) through (h)(3) Excess emissions report loading rack information Required to be submitted with the Periodic Report required under 40 CFR part 63, subpart CC.

a This table does not include all the requirement s delineated under the re ferenced sections. See referenced sections for specific requirements.

Table 5—Marine Vessel Loading Operations Recordkeeping and Reporting Requirements a Reference (section of subpart Y) Description Comment 63.562(e)(2) Operation and maintenance plan for control equipment and monitoring equipment 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 compliancePage 157 of 175

Reference (section of subpart Y) Description Comment 63.567(d) Flare recordkeeping requirements 63.567(e) Summary report and excess emissions and monitoring system performance report requirements The information required under this paragraph is to be submitted with the Periodic Report required under 40 CFR part 63, subpart CC. 63.567(f) Vapor collection system engineering report 63.567(g) Vent system valve bypass recordkeeping requirements 63.567(h) Marine vessel vapor-tightness documentation 63.567(i) Documentation file maintenance 63.567(j) Emission estimation reporting and recordkeeping procedures

a This table does not include all the requirement s delineated under the re ferenced sections. See referenced sections for specific requirements.

Table 6—General Provisions A pplicability to Subpart CC a

Reference Applies to subpart CC Comment 63.1(a)(1) Yes 63.1(a)(2) Yes 63.1(a)(3) Yes 63.1(a)(4) Yes 63.1(a)(5) No Reserved. 63.1(a)(6) Yes Except the correct mail drop (MD) number is C404–04. 63.1(a)(7)– 63.1(a)(9) No Reserved. 63.1(a)(10) Yes 63.1(a)(11) Yes 63.1(a)(12) Yes 63.1(b)(1) Yes 63.1(b)(2) No Reserved. 63.1(b)(3) No 63.1(c)(1) Yes 63.1(c)(2) No Area sources are not subject to subpart CC. 63.1(c)(3)– 63.1(c)(4) No Reserved.Page 158 of 175

Reference Applies to subpart CC Comment 63.1(c)(5) Yes Except that sources are not required to submit notifications overridden by this table. 63.1(d) No Reserved. 63.1(e) No No CAA section 112(j) st andard 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-refe rence to §63.9(b) is changed to §63.9(b)(4) and (5). Subpar t CC overrides §63.9 (b)(2). 63.5(b)(5) No Reserved. 63.5(b)(6) Yes 63.5(c) No Reserved. 63.5(d)(1)(i) Yes Except that the application shall be submitted as soon as practicable before startup, but no later than 90 days after the promulgation date of subpart CC if the construction or reconstruction had commenced and initial startup had not occurred before the promulgation of subpart CC. 63.5(d)(1)(ii) Yes Except that for affect ed sources subject to subpart CC, emission estimates specified in §63.5(d)(1)(ii)(H) are not required , and §63.5(d)(1)(ii)(G) and (I) are Reserved and do not apply

. 63.5(d)(1)(iii) No Subpart CC §63.655(f) specifies Notification of Compliance Status report requirements. 63.5(d)(2) Yes 63.5(d)(3) Yes 63.5(d)(4) Yes 63.5(e) Yes 63.5(f) Yes Except that the cross-ref erence in §63.5(f)(2) to §63.9(b)(2) does not apply. 63.6(a) YesPage 159 of 175

Reference Applies to subpart CC Comment 63.6(b)(1)– 63.6(b)(5) No Subpart CC specifies complian ce dates and notifications for sources subject to subpart CC. 63.6(b)(6) No Reserved. 63.6(b)(7) Yes 63.6(c)(1)– 63.6(c)(2) No §63.640 of subpart CC specifies the compliance date. 63.6(c)(3)– 63.6(c)(4) No Reserved. 63.6(c)(5) Yes 63.6(d) No Reserved. 63.6(e)(1 )(i) and (ii ) Yes No Except the startup, shutdown, or malfunction plan does not apply to Group 2 emission point s that are not part of an emissions averaging group. b See §63.642(n) for general duty requirement. 63.6(e)(1)(iii) Yes 63.6(e)(2) No Reserved. 63.6(e)(3)(i) Yes No Except the startup, shutdown, or malfunction plan does not apply to Group 2 emission point s 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 No 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 No Except for the heat exchange system standards, which apply at all times. 63.6(f)(2) and (3) Yes Except the phrase “as specified in §63.7(c)” in §63.6(f)(2)(iii)(D) does not apply because subpart CC does not require a site-s pecific test plan. 63.6(f)(3) Yes Except the cross-re ferences to §63.6(f)(1) and §63.6(e)(1)(i) are changed to §63.642(n). 63.6(g) Yes 63.6(h)(1) No 63.6(h)(1) and 63.6(h)(2) Yes Except §63.6(h)(2)(ii) , which is reserved. 63.6(h)(3) No Reserved. 63.6(h)(4) No Notification of visible em ission test not requ ired in subpart CC. 63.6(h)(5) No Visible emission requirem ents 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) YesPage 160 of 175

Reference Applies to subpart CC Comment 63.6(h)(9) No Subpart CC does not require opacity standards. 63.6(i) Yes Except for §63.6(i)(15), which is reserved. 63.6(j) Yes 63.7(a)(1) Yes 63.7(a)(2) Yes Except test results must be submitted in the Notification of Compliance Status report due 150 days after compliance date, as specified in §63.655(f) of subpart CC. 63.7(a)(3) Yes 63.7(a)(4) Yes 63.7(b) No Yes Subpart Except subpart CC requires notification of performance test at least 30 da ys (rather than 60 days) prior to the performance test. 63.7(c) No Subpart CC does not requ ire a site-specific test plan. 63.7(d) Yes 63.7(e)(1) Yes No Except the performance test must be conducted at the maximum representative capacity as specified in §63.642(d)(3) of subpart CC. See §63.642(d)(3). 63.7(e)(2)– 63.7(e)(4) Yes 63.7(f) No Subpart CC specifies ap plicable methods and provides alternatives without additiona l notification or approval. 63.7(g) No Performance test reporting specified in §63.655(f). 63.7(h)(1) Yes 63.7(h)(2) Yes 63.7(h)(3) Yes Yes, except site-specifi c test plans shall not be required, and where §63.7(g)(3) specifies submittal by the date the site-specific test plan is due, the date shall be 90 days prior to the Notification of Compliance Status report in §63.655(f). 63.7(h)(4)(i) Yes 63.7(h)(4)(ii) No Site-specific test pl ans are not required in subpart CC. 63.7(h)(4)(iii) and (iv) Yes 63.7(h)(5) Yes 63.8(a)(1) and (2) Yes 63.8(a)(3) No Reserved. 63.8(a )(4 ) Yes Except §63.8(a)(3), which is reserved. that for a flare complying with §63.670, the cross-reference to §63.11 in this paragraph does not include §63.11(b). 63.8(b) Yes 63.8(c)(1) Yes Except §63.8(c)(1)(i) and §63.8(c)(iii).Page 161 of 175

Reference Applies to subpart CC Comment 63.8(c)(1)(i) No See §63.642(n). 63.8(c)(1)(iii) No 63.8(c)(2) Yes 63.8(c)(3) Yes Except that verification of operational status shall, at a minimum, include completion of the manufacturer’s written specifications or recommendations for installation, operation, and calibration of the system or other written procedures that provide adequate assurance that the equipment would monitor accurately. 63.8(c)(4) Yes Except that for sources other than flares, subpart CC specifies the monitoring cycl e frequency specified in §63.8(c)(4)(ii) is “once every hour” rather than “for each successive 15-minute period.” 63.8(c)(5)– 63.8(c)(8) No Subpart CC specifies conti nuous monitoring system requirements. 63.8(d) No Subpart CC specifies quality control procedures for continuous monitoring systems. 63.8(e) No Yes Subpart CC does not require performance evaluations; however, this shall not abr ogate 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 s ubmitting 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 s ubmitting 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 requ ire continuous emission monitors. 63.8(g) No Subpart CC specifies data reduction procedures in § § 63.655(i)(3 ) and 63.671(d ). 63.9(a) Yes Except that the owner or operator does not need to send a copy of each notification subm itted 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 requi red in §63.9(b)(1)(iii). 63.9(b)(2) No A separate Initial Notif ication report is not required under subpart CC. 63.9(b)(3) No Reserved.Page 162 of 175

Reference Applies to subpart CC Comment 63.9(b)(4) Yes Except for subparagrap hs §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 notifi cation of performance test at least 30 days (rather than 60 da ys) 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 No 63.10(b)(2)(ii) Yes No §63.655(i) of subpart CC specifies the records that must be kept. 63.10(b)(2)(iii) No 63.10(b)(2)(iv) Yes No 63.10(b)(2)(v) Yes No 63.10(b)(2)(vi) Yes 63.10(b)(2)(vii) No §63.655(i) of subpart CC specifie s records to be kept for parameters measured with continuous monitors. 63.10(b)(2)(viii) Yes 63.10(b)(2)(ix) Yes 63.10(b)(2)(x) Yes 63.10(b)(2)(xi) No 63.10(b)(2)(xii) Yes 63.10(b)(2)(xiii) No 63.10(b)(2)(xiv) Yes 63.10(b)(3) No 63.10(c)(1)– 63.10(c)(6) No 63.10(c)(7) and 63.10(c)(8) Yes 63.10(c)(9) No Reserved. 63.10(c)( 9 10 )– 63.10(c)( 15 11 ) No §63.655(i) of subpart CC specifies the records that must be kept.Page 163 of 175

Reference Applies to subpart CC Comment 63.10(c)(12)– 63.10(c)(15) No 63.10(d)(1) Yes 63.10(d)(2) No Although §63.655(f) of subpart CC specifies performance test reporting

. , EPA may approve other timeframes for submittal of performance test data 63.10(d)(3) No Results of visible emissi ons test are included in Compliance Status Report as specified in §63.655(f). 63.10(d)(4) Yes 63.10(d)(5 )(i ) Yes b No Except that reports required by §63.10(d)(5)(i) may be submitted at the same time as periodic reports specified in §63.655(g) of subpart CC specifies the reporting requirements

. 63.10(e) No 63.10(f) Yes 63. 10(d)(5)(ii) 11 Yes Except that actions taken dur ing a startup, shutdown, or malfunction that are not cons istent with the startup, shutdown, and malfunction plan and that cause the source to exceed any applicable emi ssion limitation do not need to be reported within 2 and 7 days of commencing and completing the action, respectively, but must be included in the next periodic report. Except that flares complying with §63.670 are not subject to the requirements of §63.11(b). 63.10(e) No 63.10(f) Yes 63. 11 12 –63.16 Yes

a Wherever subpart A specifies “postmark” dates, submittals may be sent by methods other than the U.S. Mail (e.g., by fax or courier). Submittals shall be sent by the specified dates, but a postmark is not required.

b The plan, and any records or reports of st artup, shutdown, and malfunction do not apply to Group 2 emission points that are not partof an emissions averaging group.

Table 7—Fraction Measured (F M ), Fraction Emitted (F E ), and Fraction Removed (FR) for HAP Compounds in Wastewater Streams Chemical name CAS No. a F m F e Fr Benzene 71432 1.00 0.80 0.99 Biphenyl 92524 0.86 0.45 0.99 Butadiene (1,3) 106990 1.00 0.98 0.99 Carbon disulfide 75150 1.00 0.92 0.99 Cumene 98828 1.00 0.88 0.99Page 164 of 175

Chemical name CAS No. a F m F e Fr Dichloroethane (1,2-) (Ethylene dichloride) 107062 1.00 0.64 0.99 Ethylbenzene 100414 1.00 0.83 0.99 Hexane 110543 1.00 1.00 0.99 Methanol 67561 0.85 0.17 0.31 Methyl isobutyl ket one (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 Chem ical Abstracts Service registry number assigned to specific compounds, isomers, or mixtures of compounds. Table 8—Valve Monitoring Frequency for Phase III Performance level Valve monitoring frequency Leaking valves a (%) ≥ 4 Monthly or QIP. b <4 Quarterly. <3 Semiannual. <2 Annual.

a Percent leaking valves is calculated as a rolli ng average of two consecutive monitoring periods.

b QIP=Quality improvement program. Specified in §63.175 of subpart H of this part. Table 9—Valve Monitoring Frequency for Alternative Performance level Valve monitoring frequency under §63.649 alternative Leaking valves a (%) ≥ 5 Monthly or QIP. b <5 Quarterly. <4 Semiannual. <3 Annual.

a Percent leaking valves is calculated as a rolli ng average of two consecutive monitoring periods.

b QIP=Quality improvement program. Specified in §63.175 of subpart H of this part.Page 165 of 175

Table 10—Miscellaneous Process Vents—Moni toring, Recordkeeping and Reporting Requirements for Complying With 98 Weight -Percent Reduction of Total Organic HAP Emissions or a Limit of 20 Pa rts Per Million by Volume

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

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

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

. 4. Report all daily average temperatures that are outside the range established in the NCS or operating permit and all operating days when insufficient monitoring data are collected f —PR g

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

.

2. Record and report the upstream and downstream temperatures and the temperature difference across the catalyst bed averaged over the full period of the performance test— NCS d

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

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

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

.Page 166 of 175

Control device Parameters to be monitored a Recordkeeping and reporting requirements for monitored parameters 6. Report all operating days when insufficient monitoring data are collected f

. Boiler or process heater with a design heat capacity less than 44 megawatts where the vent stream is not introduced into the flame zone h,i Firebox temperature b (63.644(a)(4)) 1. Continuous records c

.

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

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

. 4. Report all daily average firebox temperatures that are outside the range established in the NCS or operating permit and all operating days when insufficient monitoring data are collected f —PR g

. Flare (if meeting the requirements of 63.643 and 63.644) Presence of a flame at the pilot light (63.644(a)(2)) 1. Hourly records of whether the monitor was continuously operating and whether a pilot flame was continuously present during each hour. 2. Record and report the presence of a flame at the pilot light over the full period of the compliance determination—NCS d

. 3. Record the times and durations of all periods when all pilot flames for a flare are absent or the monitor is not operating. 4. Report the times and durations of all periods when all pilot flames for a flare are absent or the monitor is not operating. Flare (if meeting the requirements of 63.670 and 63.671) The parameters specified in 63.670 1. Records as specified in §63.655(i)(9).Page 167 of 175

Control device Parameters to be monitored a Recordkeeping and reporting requirements for monitored parameters 2. Report information as specified in §63.655(g)(11)—PR g

. 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— PR g

. Monthly inspections of sealed valves [ ( 63.644(c)(2) ] ) 1. Records that monthly inspections were performed.

2. Record and report all monthly inspections that show the valves are not closed or the seal has been changed—PR g

.

a Regulatory citations are listed in parentheses.

b Monitor may be installed in the firebox or in the ductwork immediately downstream of the firebox before any substantial he at 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 in sufficient monitoring data, as described in §63.655(g)(6)(i)(C) or (D), the durat ion of the period when monito ring 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 pr ocess heaters with a design heat capacity ≥ 44 megawatts or for boilers and process heaters wher e all vent streams are introduced into the flame zone. No recordkeeping or reporti ng associated with monitoring is required for such boilers and process heaters.Page 168 of 175

i Process vents that are routed to refinery fuel gas systems are not re gulated under this subpart provided that on and after [insert date 3 year s and 60 days after date of publication in the Federal Register], any flares rece iving gas from that fuel gas system are in compliance with §63.670 . No monitoring, recordkeepi ng, or reporting is required for boilers and process heaters that combust refinery fuel gas.

Table 11—Compliance Dates and Requirements If the construction/ reconstruction date a is... Then the owner or operator must comply with... And the owner or operator must achieve compliance... Except as provided in... (1) After June 30, 2014 (i) Requirements for new sources in §§63.640 through 63.642, §63.647, §§63.650 through 63.653, and §§63.656 through 63.660 Upon initial startup or [insert date 60 days after date of publication in the Federal Register], whichever is later §63.640(k), (l) and (m)

(ii) The new source requirements in §63.654 for heat exchange systems Upon initial startup or October 28, 2009, whichever is later §63.640(k), (l) and (m)

(2) After September 4, 2007 but on or before June 30, 2014 (i) Requirements for new sources in §§63.640 through 63.653 and 63.656 b,c Upon initial startup §63.640(k), (l) and (m)

(ii) Requirements for new sources in §§63.640 through 63.645, §§63.647 through 63.653, and §§63.656 and 63.657 b On or before [insert date 3 years and 60 days after date of publication in the Federal Register] §63.640(k), (l) and (m)

(iii) Requirements for existing sources in §63.658 On or before [insert date 2 years and 60 days after date of publication in the Federal Register] §63.640(k), (l) and (m)

(iv) Requirements for new sources in §63.660 c On or before [insert date 150 days after date of publication in the Federal Register] §63.640(k), (l) and (m)Page 169 of 175

If the construction/ reconstruction date a is... Then the owner or operator must comply with... And the owner or operator must achieve compliance... Except as provided in... (v) The new source requirements in §63.654 for heat exchange systems Upon initial startup or October 28, 2009, whichever is later §63.640(k), (l) and (m)

(3) After July 14, 1994 but on or before September 4, 2007 (i) Requirements for new sources in §§63.640 through 63.653 and 63.656 d,e Upon initial startup or August 18, 1995, whichever is later §63.640(k), (l) and (m)

(ii) Requirements for new sources in §§63.640 through 63.645, §§63.647 through 63.653, and §§63.656 and 63.657 d On or before [insert date 3 years and 60 days after date of publication in the Federal Register] §63.640(k), (l) and (m)

(iii) Requirements for existing sources in §63.658 On or before [insert date 2 years and 60 days after date of publication in the Federal Register] §63.640(k), (l) and (m)

(iv) Requirements for new sources in §63.660 e On or before [insert date 150 days after date of publication in the Federal Register] §63.640(k), (l) and (m)

(v) The existing source requirements in §63.654 for heat exchange systems On or before October 29, 2012 §63.640(k), (l) and (m)

(4) On or before July 14, 1994 (i) Requirements for existing sources in §§63.640 through 63.653 and 63.656 f,g (a) On or before August 18, 1998 ( 1 ) §63.640(k), (l) and (m) ( 2 ) §63.6(c)(5) of subpart A of this part or unless an extension has been granted by the Administrator as provided in §63.6(i) of subpart A of this partPage 170 of 175

If the construction/ reconstruction date a is... Then the owner or operator must comply with... And the owner or operator must achieve compliance... Except as provided in... (ii) Requirements for existing sources in §§63.640 through 63.645, §§63.647 through 63.653, and §§63.656 and 63.657 f On or before [insert date 3 years and 60 days after date of publication in the Federal Register] §63.640(k), (l) and (m)

(iii) Requirements for existing sources in §63.658 On or before [insert date 2 years and 60 days after date of publication in the Federal Register] §63.640(k), (l) and (m)

(iv) Requirements for existing sources in §63.660 g On or before [insert date 150 days after date of publication in the Federal Register] §63.640(k), (l) and (m)

(v) The existing source requirements in §63.654 for heat exchange systems On or before October 29, 2012 §63.640(k), (l) and (m)

a For purposes of this table, the constructi on/reconstruction date means the date of construction or reconstruction of an entire aff ected source or the date of a process unit addition or change meeting the criteria in §63. 640(i) or (j). If a process unit addition or change does not meet the criteria in §63.640(i) or (j), the process unit shall comply with the applicable requirements for existing sources.

b Between the compliance dates in items (2)(i) and (2)(ii) of this table, the owner or operator may elect to comply with either the requirements in item (2)(i) or item (2)(ii) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(ii) of this table.

c Between the compliance dates in items (2)(i) and (2)(iv) of this table, the owner or operator may elect to comply with either the requirements in item (2)(i) or item (2)(iv) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(iv) of this table.

d Between the compliance dates in items (3)(i) and (3)(ii) of this table, the owner or operator may elect to comply with either the requirements in item (3)(i) or item (3)(ii) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(ii) of this table.Page 171 of 175

e Between the compliance dates in items (3)(i) and (3)(iv) of this table, the owner or operator may elect to comply with either the requirements in item (3)(i) or item (3)(iv) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(iv) of this table.

f Between the compliance dates in items (4)(i) a nd (4)(ii) of this table, the owner or operator may elect to comply with either the requirements in item (4)(i) or item (4)(ii) of this table. The requirements in item (4)(i) of this tabl e no longer apply after demonstrated compliance with the requirements in item (4)(ii) of this table.

g Between the compliance dates in items (4)(i) and (4)(iv) of this table, the owner or operator may elect to comply with either the requirements in item (4)(i) or item (4)(iv) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(iv) of this table. Table 12— Individual Component Properties

Component Molecular Formula MW i (poundsper poundmole) CMN i (mole per mole) NHV i (British thermal units per standard cubic foot) LFL i (volume %) Acetylene C 2 H 2 26.04 2 1,404 2.5 Benzene C 6 H 6 78.11 6 3,591 1.3 1,2-Butadiene C 4 H 6 54.09 4 2,794 2.0 1,3-Butadiene C 4 H 6 54.09 4 2,690 2.0 iso-Butane C 4 H 10 58.12 4 2,957 1.8 n-Butane C 4 H 10 58.12 4 2,968 1.8 cis-Butene C 4 H 8 56.11 4 2,830 1.6 iso-Butene C 4 H 8 56.11 4 2,928 1.8 trans-Butene C 4 H 8 56.11 4 2,826 1.7 Carbon Dioxide CO 2 44.01 1 0 ∞ Carbon Monoxide CO 28.01 1 316 12.5 Cyclopropane C 3 H 6 42.08 3 2,185 2.4 Ethane C 2 H 6 30.07 2 1,595 3.0 Ethylene C 2 H 4 28.05 2 1,477 2.7 Hydrogen H 2 2.02 0 1,212 A 4.0 Hydrogen Sulfide H 2 S 34.08 0 587 4.0

Methane CH 4 16.04 1 896 5.0MethylAcetylene C 3 H 4 40.06 3 2,088 1.7 Nitrogen N 2 28.01 0 0 ∞ Oxygen O 2 32.00 0 0 ∞Page 172 of 175

Component Molecular Formula MW i (poundsper poundmole) CMN i (mole per mole) NHV i (British thermal units per standard cubic foot) LFL i (volume %) Pentane+ (C5+) C 5 H 12 72.15 5 3,655 1.4 Propadiene C 3 H 4 40.06 3 2,066 2.16 Propane C 3 H 8 44.10 3 2,281 2.1 Propylene C 3 H 6 42.08 3 2,150 2.4 Water H 2 O 18.02 0 0 ∞

A The theoretical net heating value for hydroge n is 274 Btu/scf, but for the purposes of the flare requirement in this subpart, a net he ating value of 1,212 Btu/scf shall be used. Table 13—Calibration and Quality Control Requirements for CPMS Parameter Minimum accuracy requirements Calibration requirements Temperature ±1 percent over the normal range of temperature measured, expressed in degrees Celsius (C), or 2.8 degrees C, whichever is greater. Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours throughout which the temperature exceeded the manufacturer’s specified maximum rated temperature or install a new temperature sensor. At least quarterly, inspect all components for integrity and all electrical connections for continuity, oxidation, and galvanic corrosion, unless the CPMS has a redundant temperature sensor. Record the results of each calibration check and inspection. Locate the temperature sensor in a position that provides a representative temperature; shield the temperature sensor system from electromagnet ic interference and chemical contaminants. Flow Rate for All Flows Other Than Flare Vent Gas ±5 percent over the normal range of flow measured or 1.9 liters per minute (0.5 gallons per minute), whichever is greater, for liquid flow. Conduct a flow sensor calibration check at least biennially (every two years); conduct a ca libration check following any period of more than 24 hours throughout which the flow rate exceeded thePage 173 of 175

Parameter Minimum accuracy requirements Calibration requirements ±5 percent over the normal range of flow measured or 280 liters per minute (10 cubic feet per minute), whichever is greater, for gas flow. ±5 percent over the normal range measured for mass flow. manufacturer’s specified maximum rated flow rate or install a new flow sensor. At least quarterly, inspect all components for leakage, unless the CPMS has a redundant flow sensor. Record the results of each calibration check and inspection. Locate the flow sensor(s) and other necessary equipment (such as straightening vanes) in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. Flare Vent Gas Flow Rate ±20 percent of flow rate at velocities ranging from 0.03 to 0.3 meters per second (0.1 to 1 feet per second). ±5 percent of flow rate at velocities greater than 0.3 meters per second (1 feet per second). Conduct a flow sensor calibration check at least biennially (every two years); conduct a ca libration check following any period of more than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow sensor. At least quarterly, inspect all components for leakage, unless the CPMS has a redundant flow sensor. Record the results of each calibration check and inspection. Locate the flow sensor(s) and other necessary equipment (such as straightening vanes) in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. Pressure ±5 percent over the normal operating range or 0.12 kilopascals (0.5 inches of Review pressure sensor readings at least once a week for straightline (unchanging) pressure and perform corrective action to ensurePage 174 of 175

Parameter Minimum accuracy requirements Calibration requirements water column), whichever is greater. proper pressure sensor operation if blockage is indicated. Using an instrument recommended by the sensor’s manufacturer, check gauge calibration and transducer calibration annually; conduct calibration checks following any period of more than 24 hours throughout which the pressure exceeded the manufacturer’s specified maximum rated pressure or install a new pressure sensor. At least quarterly, inspect all components for integrity, all electrical connections for continuity, and all mechanical connections for leakage, unless the CPMS has a redundant pressure sensor. Record the results of each calibration check and inspection. Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure and minimizes or eliminates pulsating pressure, vibration, and internal and external corrosion. Net Heating Value by Calorimeter ±2 percent of span Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements should follow manufacturer’s recommendations at a minimum. Temperature control (heated and/or cooled as necessary) the samplingsystem to ensure proper yearround operation. Where feasible, select a sampling location at least two equivalent diameters downstream from and 0.5 equivalent diameters upstream from the nearest disturbance. Select the sampling location atPage 175 of 175

Parameter Minimum accuracy requirements Calibration requirements least two equivalent duct diameters from the nearest control device, point of pollutant generation, air in-leakages, or other point at which a change in the pollutant concentration or emission rate occurs. Net Heating Value by Gas Chromatogra ph As specified in Performance Specification 9 of 40 CFR part 60, Appendix B. Follow the procedure in Performance Specification 9 of 40 CFR part 60, Appendix B, except that a single daily mid-level calibration check can be used (rather than triplicate analysis), the multi-point calibration can be conducted quarterly (rather than monthly), and the sampling line temperature must be maintained at a minimum temperature of 60 °C (rather than 120 °C). Hydrogen analyzer ±2 percent over the concentration measured or 0.1 volume percent, whichever is greater. Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements should follow manufacturer’s recommendations at a minimum. Select the sampling location at least two equivalent duct diameters from the nearest control device, point of pollutant generation, air in-leakages, or other point at which a change in the pollutant concentration occurs.