359 

Environmental Protection Agency § 60.103a 

the request as submitted until it is approved. 

(iii) The request shall also be submitted to the following address: U.S. 

Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143–01), 

Attention: Refinery Sector Lead, 109 

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

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

(4) The approval process for a request 

for a facility-specific NOX emissions 

limit is described in paragraphs (i)(4)(i) 

through (iii) of this section. 

(i) Approval by the Administrator of 

a facility-specific NOX emissions limit 

request will be based on the completeness, accuracy and reasonableness of 

the request. Factors that the EPA will 

consider in reviewing the request for 

approval include, but are not limited 

to, the following: 

(A) A demonstration that the process 

heater meets one of the four classes of 

process heaters outlined in paragraphs 

(i)(1) of this section; 

(B) A description of the low-NOX

burner designs and other combustion 

modifications considered for reducing 

NOX emissions; 

(C) The combustion modification option selected; and 

(D) The operating conditions (firing 

rate, heater box temperature and excess oxygen concentration) at which 

the NOX emission level was established. 

(ii) If the request is approved by the 

Administrator, a facility-specific NOX

emissions limit will be established at 

the NOX emission level demonstrated 

in the approved request. 

(iii) If the Administrator finds any 

deficiencies in the request, the request 

must be revised to address the deficiencies and be re-submitted for approval. 

[73 FR 35867, June 24, 2008, as amended at 77 

FR 56466, Sep. 12, 2012] 

§ 60.103a Design, equipment, work 

practice or operational standards. 

(a) Except as provided in paragraph 

(g) of this section, each owner or operator that operates a flare that is subject to this subpart shall develop and 

implement a written flare management 

plan no later than the date specified in 

paragraph (b) of this section. The flare 

management plan must include the information described in paragraphs 

(a)(1) through (7) of this section. 

(1) A listing of all refinery process 

units, ancillary equipment, and fuel 

gas systems connected to the flare for 

each affected flare. 

(2) An assessment of whether discharges to affected flares from these 

process units, ancillary equipment and 

fuel gas systems can be minimized. The 

flare minimization assessment must 

(at a minimum) consider the items in 

paragraphs (a)(2)(i) through (iv) of this 

section. The assessment must provide 

clear rationale in terms of costs (capital and annual operating), natural gas 

offset credits (if applicable), technical 

feasibility, secondary environmental 

impacts and safety considerations for 

the selected minimization alternative(s) or a statement, with justifications, that flow reduction could not be 

achieved. Based upon the assessment, 

each owner or operator of an affected 

flare shall identify the minimization 

alternatives that it has implemented 

by the due date of the flare management plan and shall include a schedule 

for the prompt implementation of any 

selected measures that cannot reasonably be completed as of that date. 

(i) Elimination of process gas discharge to the flare through process operating changes or gas recovery at the 

source. 

(ii) Reduction of the volume of process gas to the flare through process operating changes. 

(iii) Installation of a flare gas recovery system or, for facilities that are 

fuel gas rich, a flare gas recovery system and a co-generation unit or combined heat and power unit. 

(iv) Minimization of sweep gas flow 

rates and, for flares with water seals, 

purge gas flow rates. 

(3) A description of each affected 

flare containing the information in 

paragraphs (a)(3)(i) through (vii) of this 

section. 

(i) A general description of the flare, 

including the information in paragraphs (a)(3)(i)(A) through (G) of this 

section. 

(A) Whether it is a ground flare or 

elevated (including height). 


lpowell on DSK54DXVN1OFR with $$_JOB
360 

§ 60.103a 40 CFR Ch. I (7–1–15 Edition) 

(B) The type of assist system (e.g., 

air, steam, pressure, non-assisted). 

(C) Whether it is simple or complex 

flare tip (e.g., staged, sequential). 

(D) Whether the flare is part of a cascaded flare system (and if so, whether 

the flare is primary or secondary). 

(E) Whether the flare serves as a 

backup to another flare. 

(F) Whether the flare is an emergency flare or a non-emergency flare. 

(G) Whether the flare is equipped 

with a flare gas recovery system. 

(ii) Description and simple process 

flow diagram showing the interconnection of the following components of the 

flare: flare tip (date installed, manufacturer, nominal and effective tip diameter, tip drawing); knockout or 

surge drum(s) or pot(s) (including dimensions and design capacities); flare 

header(s) and subheader(s); assist system; and ignition system. 

(iii) Flare design parameters, including the maximum vent gas flow rate; 

minimum sweep gas flow rate; minimum purge gas flow rate (if any); maximum supplemental gas flow rate; maximum pilot gas flow rate; and, if the 

flare is steam-assisted, minimum total 

steam rate. 

(iv) Description and simple process 

flow diagram showing all gas lines (including flare, purge (if applicable), 

sweep, supplemental and pilot gas) that 

are associated with the flare. For 

purge, sweep, supplemental and pilot 

gas, identify the type of gas used. Designate which lines are exempt from sulfur, H2S or flow monitoring and why 

(e.g., natural gas, inherently low sulfur, pilot gas). Designate which lines 

are monitored and identify on the process flow diagram the location and type 

of each monitor. 

(v) For each flow rate, H2S, sulfur 

content, pressure or water seal monitor 

identified in paragraph (a)(3)(iv) of this 

section, provide a detailed description 

of the manufacturer’s specifications, 

including, but not limited to, make, 

model, type, range, precision, accuracy, calibration, maintenance and 

quality assurance procedures. 

(vi) For emergency flares, secondary 

flares and flares equipped with a flare 

gas recovery system designed, sized 

and operated to capture all flows except those resulting from startup, 

shutdown or malfunction: 

(A) Description of the water seal, including the operating range for the liquid level. 

(B) Designation of the monitoring option elected (flow and sulfur monitoring or pressure and water seal liquid 

level monitoring). 

(vii) For flares equipped with a flare 

gas recovery system: 

(A) A description of the flare gas recovery system, including number of 

compressors and capacity of each compressor. 

(B) A description of the monitoring 

parameters used to quantify the 

amount of flare gas recovered. 

(C) For systems with staged compressors, the maximum time period required to begin gas recovery with the 

secondary compressor(s), the monitoring parameters and procedures used 

to minimize the duration of releases 

during compressor staging and a justification for why the maximum time 

period cannot be further reduced. 

(4) An evaluation of the baseline flow 

to the flare. The baseline flow to the 

flare must be determined after implementing the minimization assessment 

in paragraph (a)(2) of this section. 

Baseline flows do not include pilot gas 

flow or purge gas flow (i.e., gas introduced after the flare’s water seal) provided these gas flows remain reasonably constant (i.e., separate flow monitors for these streams are not required). Separate baseline flow rates 

may be established for different operating conditions provided that the 

management plan includes: 

(i) A primary baseline flow rate that 

will be used as the default baseline for 

all conditions except those specifically 

delineated in the plan; 

(ii) A description of each special condition for which an alternate baseline 

is established, including the rationale 

for each alternate baseline, the daily 

flow for each alternate baseline and the 

expected duration of the special conditions for each alternate baseline; and 

(iii) Procedures to minimize discharges to the affected flare during 

each special condition described in 

paragraph (a)(4)(ii) of this section, unless procedures are already developed 

for these cases under paragraph (a)(5) 


lpowell on DSK54DXVN1OFR with $$_JOB
361 

Environmental Protection Agency § 60.103a 

through (7) of this section, as applicable. 

(5) Procedures to minimize or eliminate discharges to the flare during the 

planned startup and shutdown of the 

refinery process units and ancillary 

equipment that are connected to the 

affected flare, together with a schedule 

for the prompt implementation of any 

procedures that cannot reasonably be 

implemented as of the date of the submission of the flare management plan. 

(6) Procedures to reduce flaring in 

cases of fuel gas imbalance (i.e., excess 

fuel gas for the refinery’s energy 

needs), together with a schedule for the 

prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission 

of the flare management plan. 

(7) For flares equipped with flare gas 

recovery systems, procedures to minimize the frequency and duration of 

outages of the flare gas recovery system and procedures to minimize the 

volume of gas flared during such outages, together with a schedule for the 

prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission 

of the flare management plan. 

(b) Except as provided in paragraph 

(g) of this section, each owner or operator required to develop and implement a written flare management plan 

as described in paragraph (a) of this 

section must submit the plan to the 

Administrator as described in paragraphs (b)(1) through (3) of this section. 

(1) The owner or operator of a newly 

constructed or reconstructed flare 

must develop and implement the flare 

management plan by no later than the 

date that the flare becomes an affected 

facility subject to this subpart, except 

for the selected minimization alternatives in paragraph (a)(2) and/or the 

procedures in paragraphs (a)(5) though 

(a)(7) of this section that cannot reasonably be implemented by that date, 

which the owner or operator must implement in accordance with the schedule in the flare management plan. The 

owner or operator of a modified flare 

must develop and implement the flare 

management plan by no later than November 11, 2015 or upon startup of the 

modified flare, whichever is later. 

(2) The owner or operator must comply with the plan as submitted by the 

date specified in paragraph (b)(1) of 

this section. The plan should be updated periodically to account for 

changes in the operation of the flare, 

such as new connections to the flare or 

the installation of a flare gas recovery 

system, but the plan need be re-submitted to the Administrator only if the 

owner or operator adds an alternative 

baseline flow rate, revises an existing 

baseline as described in paragraph 

(a)(4) of this section, installs a flare gas 

recovery system or is required to 

change flare designations and monitoring methods as described in 

§60.107a(g). The owner or operator must 

comply with the updated plan as submitted. 

(3) All versions of the plan submitted 

to the Administrator shall also be submitted to the following address: U.S. 

Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143–01), 

Attention: Refinery Sector Lead, 109 

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

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

(c) Except as provided in paragraphs 

(f) and (g) of this section, each owner 

or operator that operates a fuel gas 

combustion device, flare or sulfur recovery plant subject to this subpart 

shall conduct a root cause analysis and 

a corrective action analysis for each of 

the conditions specified in paragraphs 

(c)(1) through (3) of this section. 

(1) For a flare: 

(i) Any time the SO2 emissions exceed 227 kilograms (kg) (500 lb) in any 

24-hour period; or 

(ii) Any discharge to the flare in excess of 14,160 standard cubic meters 

(m3) (500,000 standard cubic feet (scf)) 

above the baseline, determined in paragraph (a)(4) of this section, in any 24- 

hour period; or 

(iii) If the monitoring alternative in 

§60.107a(g) is elected, any period when 

the flare gas line pressure exceeds the 

water seal liquid depth, except for periods attributable to compressor staging 

that do not exceed the staging time 

specified in paragraph (a)(3)(vii)(C) of 

this section. 


lpowell on DSK54DXVN1OFR with $$_JOB
362 

§ 60.103a 40 CFR Ch. I (7–1–15 Edition) 

(2) For a fuel gas combustion device, 

each exceedance of an applicable shortterm emissions limit in §60.102a(g)(1) if 

the SO2 discharge to the atmosphere is 

227 kg (500 lb) greater than the amount 

that would have been emitted if the 

emissions limits had been met during 

one or more consecutive periods of excess emissions or any 24-hour period, 

whichever is shorter. 

(3) For a sulfur recovery plant, each 

time the SO2 emissions are more than 

227 kg (500 lb) greater than the amount 

that would have been emitted if the 

SO2 or reduced sulfur concentration 

was equal to the applicable emissions 

limit in §60.102a(f)(1) or (2) during one 

or more consecutive periods of excess 

emissions or any 24-hour period, whichever is shorter. 

(d) Except as provided in paragraphs 

(f) and (g) of this section, a root cause 

analysis and corrective action analysis 

must be completed as soon as possible, 

but no later than 45 days after a discharge meeting one of the conditions 

specified in paragraphs (c)(1) through 

(3) of this section. Special circumstances affecting the number of 

root cause analyses and/or corrective 

action analyses are provided in paragraphs (d)(1) through (5) of this section. 

(1) If a single continuous discharge 

meets any of the conditions specified 

in paragraphs (c)(1) through (3) of this 

section for 2 or more consecutive 24- 

hour periods, a single root cause analysis and corrective action analysis may 

be conducted. 

(2) If a single discharge from a flare 

triggers a root cause analysis based on 

more than one of the conditions specified in paragraphs (c)(1)(i) through (iii) 

of this section, a single root cause 

analysis and corrective action analysis 

may be conducted. 

(3) If the discharge from a flare is the 

result of a planned startup or shutdown 

of a refinery process unit or ancillary 

equipment connected to the affected 

flare and the procedures in paragraph 

(a)(5) of this section were followed, a 

root cause analysis and corrective action analysis is not required; however, 

the discharge must be recorded as described in §60.108a(c)(6) and reported as 

described in §60.108a(d)(5). 

(4) If both the primary and secondary 

flare in a cascaded flare system meet 

any of the conditions specified in paragraphs (c)(1)(i) through (iii) of this section in the same 24-hour period, a single root cause analysis and corrective 

action analysis may be conducted. 

(5) Except as provided in paragraph 

(d)(4) of this section, if discharges 

occur that meet any of the conditions 

specified in paragraphs (c)(1) through 

(3) of this section for more than one affected facility in the same 24-hour period, initial root cause analyses shall 

be conducted for each affected facility. 

If the initial root cause analyses indicate that the discharges have the same 

root cause(s), the initial root cause 

analyses can be recorded as a single 

root cause analysis and a single corrective action analysis may be conducted. 

(e) Except as provided in paragraphs 

(f) and (g) of this section, each owner 

or operator of a fuel gas combustion 

device, flare or sulfur recovery plant 

subject to this subpart shall implement 

the corrective action(s) identified in 

the corrective action analysis conducted pursuant to paragraph (d) of 

this section in accordance with the applicable requirements in paragraphs 

(e)(1) through (3) of this section. 

(1) All corrective action(s) must be 

implemented within 45 days of the discharge for which the root cause and 

corrective action analyses were required or as soon thereafter as practicable. If an owner or operator concludes that corrective action should 

not be conducted, the owner or operator shall record and explain the basis 

for that conclusion no later than 45 

days following the discharge as specified in §60.108a(c)(6)(ix). 

(2) For corrective actions that cannot 

be fully implemented within 45 days 

following the discharge for which the 

root cause and corrective action analyses were required, the owner or operator shall develop an implementation 

schedule to complete the corrective action(s) as soon as practicable. 

(3) No later than 45 days following 

the discharge for which a root cause 

and corrective action analyses were required, the owner or operator shall 


lpowell on DSK54DXVN1OFR with $$_JOB
363 

Environmental Protection Agency § 60.103a 

record the corrective action(s) completed to date, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates as 

specified in §60.108a(c)(6)(x). 

(f) Modified flares shall comply with 

the requirements of paragraphs (c) 

through (e) of this section by November 11, 2015 or at startup of the modified flare, whichever is later. Modified 

flares that were not affected facilities 

subject to subpart J of this part prior 

to becoming affected facilities under 

§60.100a shall comply with the requirements of paragraph (h) of this section 

and the requirements of §60.107a(a)(2) 

by November 11, 2015 or at startup of 

the modified flare, whichever is later. 

Modified flares that were affected facilities subject to subpart J of this part 

prior to becoming affected facilities 

under §60.100a shall comply with the 

requirements of paragraph (h) of this 

section and the requirements of 

§60.107a(a)(2) by November 13, 2012 or at 

startup of the modified flare, whichever is later, except that modified 

flares that have accepted applicability 

of subpart J under a federal consent decree shall comply with the subpart J 

requirements as specified in the consent decree, but shall comply with the 

requirements of paragraph (h) of this 

section and the requirements of 

§60.107a(a)(2) by no later than November 11, 2015. 

(g) An affected flare subject to this 

subpart located in the Bay Area Air 

Quality Management District 

(BAAQMD) may elect to comply with 

both BAAQMD Regulation 12, Rule 11 

and BAAQMD Regulation 12, Rule 12 as 

an alternative to complying with the 

requirements of paragraphs (a) through 

(e) of this section. An affected flare 

subject to this subpart located in the 

South Coast Air Quality Management 

District (SCAQMD) may elect to comply with SCAQMD Rule 1118 as an alternative to complying with the requirements of paragraphs (a) through 

(e) of this section. The owner or operator of an affected flare must notify 

the Administrator that the flare is in 

compliance with BAAQMD Regulation 

12, Rule 11 and BAAQMD Regulation 12, 

Rule 12 or SCAQMD Rule 1118. The 

owner or operator of an affected flare 

shall also submit the existing flare 

management plan to the following address: U.S. Environmental Protection 

Agency, Office of Air Quality Planning 

and Standards, Sector Policies and 

Programs Division, U.S. EPA Mailroom 

(E143–01), Attention: Refinery Sector 

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

also be submitted to 

refinerynsps@epa.gov. 

(h) Each owner or operator shall not 

burn in any affected flare any fuel gas 

that contains H2S in excess of 162 ppmv 

determined hourly on a 3-hour rolling 

average basis. The combustion in a 

flare of process upset gases or fuel gas 

that is released to the flare as a result 

of relief valve leakage or other emergency malfunctions is exempt from 

this limit. 

(i) Each owner or operator of a delayed coking unit shall depressure each 

coke drum to 5 lb per square inch 

gauge (psig) or less prior to discharging 

the coke drum steam exhaust to the atmosphere. Until the coke drum pressure reaches 5 psig, the coke drum 

steam exhaust must be managed in an 

enclosed blowdown system and the 

uncondensed vapor must either be recovered (e.g., sent to the delayed coking unit fractionators) or vented to the 

fuel gas system, a fuel gas combustion 

device or a flare. 

(j) Alternative means of emission limitation. (1) Each owner or operator subject 

to the provisions of this section may 

apply to the Administrator for a determination of equivalence for any means 

of emission limitation that achieves a 

reduction in emissions of a specified 

pollutant at least equivalent to the reduction in emissions of that pollutant 

achieved by the controls required in 

this section. 

(2) Determination of equivalence to 

the design, equipment, work practice 

or operational requirements of this section will be evaluated by the following 

guidelines: 

(i) Each owner or operator applying 

for a determination of equivalence 

shall be responsible for collecting and 

verifying test data to demonstrate the 

equivalence of the alternative means of 

emission limitation. 


lpowell on DSK54DXVN1OFR with $$_JOB
364 

§ 60.104a 40 CFR Ch. I (7–1–15 Edition) 

(ii) For each affected facility for 

which a determination of equivalence 

is requested, the emission reduction 

achieved by the design, equipment, 

work practice or operational requirements shall be demonstrated. 

(iii) For each affected facility for 

which a determination of equivalence 

is requested, the emission reduction 

achieved by the alternative means of 

emission limitation shall be demonstrated. 

(iv) Each owner or operator applying 

for a determination of equivalence to a 

work practice standard shall commit in 

writing to work practice(s) that provide for emission reductions equal to or 

greater than the emission reductions 

achieved by the required work practice. 

(v) The Administrator will compare 

the demonstrated emission reduction 

for the alternative means of emission 

limitation to the demonstrated emission reduction for the design, equipment, work practice or operational requirements and, if applicable, will consider the commitment in paragraph 

(j)(2)(iv) of this section. 

(vi) The Administrator may condition the approval of the alternative 

means of emission limitation on requirements that may be necessary to 

ensure operation and maintenance to 

achieve the same emissions reduction 

as the design, equipment, work practice or operational requirements. 

(3) An owner or operator may offer a 

unique approach to demonstrate the 

equivalence of any equivalent means of 

emission limitation. 

(4) Approval of the application for 

equivalence to the design, equipment, 

work practice or operational requirements of this section will be evaluated 

by the following guidelines: 

(i) After a request for determination 

of equivalence is received, the Administrator will publish a notice in the 

FEDERAL REGISTER and provide the opportunity for public hearing if the Administrator judges that the request 

may be approved. 

(ii) After notice and opportunity for 

public hearing, the Administrator will 

determine the equivalence of a means 

of emission limitation and will publish 

the determination in the FEDERAL REGISTER. 

(iii) Any equivalent means of emission limitations approved under this 

section shall constitute a required 

work practice, equipment, design or 

operational standard within the meaning of section 111(h)(1) of the CAA. 

(5) Manufacturers of equipment used 

to control emissions may apply to the 

Administrator for determination of 

equivalence for any alternative means 

of emission limitation that achieves a 

reduction in emissions achieved by the 

equipment, design and operational requirements of this section. The Administrator will make an equivalence determination according to the provisions of paragraphs (j)(2) through (4) of 

this section. 

[77 FR 56467, Sep. 12, 2012] 

§ 60.104a Performance tests. 

(a) The owner or operator shall conduct a performance test for each FCCU, 

FCU, sulfur recovery plant, flare and 

fuel gas combustion device to demonstrate initial compliance with each 

applicable emissions limit in §60.102a 

according to the requirements of §60.8. 

The notification requirements of 

§60.8(d) apply to the initial performance test and to subsequent performance tests required by paragraph (b) of 

this section (or as required by the Administrator), but does not apply to performance tests conducted for the purpose of obtaining supplemental data 

because of continuous monitoring system breakdowns, repairs, calibration 

checks and zero and span adjustments. 

(b) The owner or operator of a FCCU 

or FCU that elects to monitor control 

device operating parameters according 

to the requirements in §60.105a(b), to 

use bag leak detectors according to the 

requirements in §60.105a(c), or to use 

COMS according to the requirements in 

§60.105a(e) shall conduct a PM performance test at least once every 12 months 

and furnish the Administrator a written report of the results of each test. 

(c) In conducting the performance 

tests required by this subpart (or as requested by the Administrator), the 

owner or operator shall use the test 

methods in 40 CFR part 60, Appendices 

A–1 through A–8 or other methods as 

specified in this section, except as provided in §60.8(b). 


lpowell on DSK54DXVN1OFR with $$_JOB