Vol. 80 Tuesday, 

No. 230 December 1, 2015 

Part II 

Environmental Protection Agency 

40 CFR Parts 60 and 63 

Petroleum Refinery Sector Risk and Technology Review and New Source 

Performance Standards; Final Rule 


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75178 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2010–0682; FRL–9935–40– 

OAR] 

RIN 2060–AQ75 

Petroleum Refinery Sector Risk and 

Technology Review and New Source 

Performance Standards 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: This action finalizes the 

residual risk and technology review 

conducted for the Petroleum Refinery 

source categories regulated under 

national emission standards for 

hazardous air pollutants (NESHAP) 

Refinery MACT 1 and Refinery MACT 2. 

It also includes revisions to the Refinery 

MACT 1 and MACT 2 rules in 

accordance with provisions regarding 

establishment of MACT standards. This 

action also finalizes technical 

corrections and clarifications for the 

new source performance standards 

(NSPS) for petroleum refineries to 

improve consistency and clarity and 

address issues related to a 2008 industry 

petition for reconsideration. 

Implementation of this final rule will 

result in projected reductions of 5,200 

tons per year (tpy) of hazardous air 

pollutants (HAP) which will reduce 

cancer risk and chronic health effects. 

DATES: This final action is effective on 

February 1, 2016. The incorporation by 

reference of certain publications for part 

63 listed in the rule is approved by the 

Director of the Federal Register as of 

February 1, 2016. The incorporation by 

reference of certain publications for part 

60 listed in the rule were approved by 

the Director of the Federal Register as of 

June 24, 2008. 

ADDRESSES: The Environmental 

Protection Agency (EPA) has established 

a docket for this action under Docket ID 

No. EPA–HQ–OAR–2010–0682. All 

documents in the docket are listed on 

the www.regulations.gov Web site. 

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

http://www.regulations.gov, or in hard 

copy at the EPA Docket Center, WJC 

West Building, Room Number 3334, 

1301 Constitution Ave. NW., 

Washington, DC. The Public Reading 

Room hours of operation are 8:30 a.m. 

to 4:30 p.m. Eastern Standard Time 

(EST), Monday through Friday. The 

telephone number for the Public 

Reading Room is (202) 566–1744, and 

the telephone number for the Air and 

Radiation Docket and Information 

Center is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: For 

questions about this final action, contact 

Ms. Brenda Shine, Sector Policies and 

Programs Division, Refining and 

Chemicals Group (E143–01), Office of 

Air Quality Planning and Standards, 

U.S. Environmental Protection Agency, 

Research Triangle Park, North Carolina, 

27711; telephone number: (919) 541– 

3608; fax number: (919) 541–0246; and 

email address: shine.brenda@epa.gov. 

For specific information regarding the 

risk modeling methodology, contact Mr. 

Ted Palma, Health and Environmental 

Impacts Division (C539–02), Office of 

Air Quality Planning and Standards, 

U.S. Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; telephone number: (919) 541– 

5470; fax number: (919) 541–0840; and 

email address: palma.ted@epa.gov. For 

information about the applicability of 

the NESHAP to a particular entity, 

contact Ms. Maria Malave, Office of 

Enforcement and Compliance 

Assurance, U.S. Environmental 

Protection Agency, William Jefferson 

Clinton Building, 1200 Pennsylvania 

Ave. NW., Washington, DC 20460; 

telephone number: (202) 564–7027; fax 

number: (202) 564–0050; and email 

address: malave.maria@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Preamble Acronyms and 

Abbreviations. We use multiple 

acronyms and terms in this preamble. 

While this list may not be exhaustive, to 

ease the reading of this preamble and for 

reference purposes, the EPA defines the 

following terms and acronyms here: 

10/25 tpy emissions equal to or greater than 

10 tons per year of a single pollutant or 25 

tons per year of cumulative pollutants 

AEGL acute exposure guideline levels 

APCD air pollution control devices 

API American Petroleum Institute 

BAAQMD Bay Area Air Quality 

Management District 

BDT best demonstrated technology 

BLD bag leak detectors 

BSER best system of emission reductions 

Btu/ft2 British thermal units per square foot 

Btu/scf British thermal units per standard 

cubic foot 

CAA Clean Air Act 

CBI confidential business information 

CCU catalytic cracking units 

CDX Central Data Exchange 

CEDRI Compliance and Emissions Data 

Reporting Interface 

CEMS continuous emission monitoring 

system 

CFR Code of Federal Regulations 

CO carbon monoxide 

CO2 carbon dioxide 

CO2e carbon dioxide equivalents 

COMS continuous opacity monitoring 

system 

COS carbonyl sulfide 

CPMS continuous parameter monitoring 

system 

CRA Congressional Review Act 

CRU catalytic reforming units 

CS2 carbon disulfide 

DCU delayed coking units 

EPA Environmental Protection Agency 

ERPG emergency response and planning 

guidelines 

ERT Electronic Reporting Tool 

ESP electrostatic precipitator 

FCCU fluid catalytic cracking unit 

FGCD fuel gas combustion device 

FMP flare management plan 

FR Federal Register 

FTIR Fourier transform infrared 

spectroscopy 

GC gas chromatograph 

GHG greenhouse gases 

H2S hydrogen sulfide 

HAP hazardous air pollutants 

HCl hydrogen chloride 

HCN hydrogen cyanide 

HF hydrogen fluoride 

HFC highest fenceline concentration 

HI hazard index 

HQ hazard quotient 

ICR information collection request 

IRIS Integrated Risk Information System 

km kilometers 

LAER lowest achievable emission rate 

lb/day pounds per day 

LDAR leak detection and repair 

LEL lower explosive limit 

LTD long tons per day 

MACT maximum achievable control 

technology 

MIR maximum individual risk 

mph miles per hour 

MPV miscellaneous process vent 

NAICS North American Industry 

Classification System 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NFS near-field interfering source 

NHVCZ combustion zone net heating value 

Ni nickel 

NOX nitrogen oxides 

NRDC Natural Resources Defense Council 

NSPS new source performance standards 

NTTAA National Technology Transfer and 

Advancement Act 

OAQPS Office of Air Quality Planning and 

standards 

OECA Office of Enforcement and 

Compliance Assurance 

OEHHA Office of Environmental Health 

Hazard Assessment 

OEL open-ended line 

OMB Office of Management and Budget 

PM particulate matter 

PM2.5 particulate matter 2.5 micrometers in 

diameter and smaller 

ppbv parts per billion by volume 

ppm parts per million 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75179 

1This term is common vernacular to describe the 

variety of devices regulated as pressure relief valves 

subject to the requirements in 40 CFR part 63 

subpart CC. 

ppmv parts per million by volume 

PRA Paperwork Reduction Act 

PRD pressure relief device 1

psia pounds per square inch absolute 

psig pounds per square inch gauge 

REL reference exposure level 

REM Model Refinery Emissions Model 

RFA Regulatory Flexibility Act 

RTC response to comment 

RTR Risk and Technology Review 

SAB Science Advisory Board 

SBA Small Business Administration 

SCAQMD South Coast Air Quality 

Management District 

SCR selective catalytic reduction 

SISNOSE significant economic impact on a 

substantial number of small entities 

SO2 sulfur dioxide 

SRP sulfur recovery plant 

SRU sulfur recovery unit 

SSM startup, shutdown and malfunction 

TOSHI target organ-specific hazard index 

tpy tons per year 

UMRA Unfunded Mandates Reform Act 

URE unit risk estimate 

UV–DOAS ultraviolet differential optical 

absorption spectroscopy 

VCS voluntary consensus standards 

VOC volatile organic compounds 

°F degrees Fahrenheit 

DC the concentration difference between 

the highest measured concentration and 

the lowest measured concentration 

mg/m3 micrograms per cubic meter 

Background Information. On June 30, 

2014, the EPA proposed revisions to 

both of the petroleum refinery NESHAP 

based on our residual risk and 

technology review (RTR). In that action, 

we also proposed to revise the NESHAP 

pursuant to CAA section 112(d)(2) and 

(3), to revise the SSM provisions in the 

NESHAP, and to make technical 

corrections to the NSPS to address 

issues related to reconsideration of the 

final NSPS subpart Ja rule in 2008. In 

this action, we are finalizing decisions 

and revisions for these rules. We 

summarize some of the more significant 

comments received regarding the 

proposed rule and provide our 

responses in this preamble. A summary 

of all other public comments on the 

proposal and the EPA’s responses to 

those comments is provided in the 

‘‘Response to Comment’’ document, 

which is available in Docket ID No. 

EPA–HQ–OAR–2010–0682. The ‘‘track 

changes’’ version of the regulatory 

language that incorporates the changes 

in this final action is also available in 

the docket for this rulemaking. 

Organization of this Document. This 

preamble is organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this document 

and other related information? 

C. Judicial Review and Administrative 

Reconsideration 

II. Background 

A. What is the statutory authority for this 

action? 

B. How do the NESHAP and NSPS regulate 

air pollutant emissions from refineries? 

C. What changes did we propose for the 

Petroleum Refinery NESHAP and NSPS 

in our June 30, 2014 RTR proposal? 

III. What is included in this final rule? 

A. What are the final NESHAP 

amendments based on the risk review for 

the Petroleum Refinery source 

categories? 

B. What are the final NESHAP 

amendments based on the technology 

review for the Petroleum Refinery source 

categories? 

C. What are the final NESHAP 

amendments pursuant to section 

112(d)(2) & (3) for the Petroleum 

Refinery source categories? 

D. What are the final NESHAP 

amendments addressing emissions 

during periods of SSM? 

E. What other revisions to the NESHAP 

and NSPS are being promulgated? 

F. What are the requirements for 

submission of performance test data to 

the EPA? 

G. What are the effective and compliance 

dates of the NESHAP and NSPS? 

H. What materials are being incorporated 

by reference? 

IV. What is the rationale for our final 

decisions and amendments to the 

Petroleum Refinery NESHAP and NSPS? 

A. Residual Risk Review for the Petroleum 

Refinery Source Categories 

B. Technology Review for the Petroleum 

Refinery Source Categories 

C. Refinery MACT Amendments Pursuant 

to CAA section 112(d)(2) and (d)(3) 

D. NESHAP Amendments Addressing 

Emissions During Periods of SSM 

E. Technical Amendments to Refinery 

MACT 1 and 2 

F. Technical Amendments to Refinery 

NSPS Subparts J and Ja 

V. Summary of Cost, Environmental, and 

Economic Impacts and Additional 

Analyses Conducted 

A. What are the affected facilities, the air 

quality impacts and cost impacts? 

B. What are the economic impacts? 

C. What are the benefits? 

D. Impacts of This Rulemaking on 

Environmental Justice Populations 

E. Impacts of This Rulemaking on 

Children’s Health 

VI. Statutory and Executive Order Reviews 

A. Executive Orders 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act (PRA) 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution or Use 

I. National Technology Transfer and 

Advancement Act (NTTAA) and 1 CFR 

part 51 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act (CRA) 

I. General Information 

A. Does this action apply to me? 

Regulated Entities. Categories and 

entities potentially regulated by this 

action are shown in Table 1 of this 

preamble. 

TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS FINAL

ACTION

NESHAP and source category NAICSa

Code 

Petroleum Refining Industry ......... 324110 

a North American Industry Classification 

System. 

Table 1 of this preamble is not 

intended to be exhaustive, but rather to 

provide a guide for readers regarding 

entities likely to be affected by the final 

action for the source categories listed. 

To determine whether your facility is 

affected, you should examine the 

applicability criteria in the appropriate 

NESHAP or NSPS. If you have any 

questions regarding the applicability of 

any aspect of these NESHAP or NSPS, 

please contact the appropriate person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section of this 

preamble. 

B. Where can I get a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, an electronic copy of this final 

action will also be available on the 

Internet through the Technology 

Transfer Network (TTN) Web site, a 

forum for information and technology 

exchange in various areas of air 

pollution control. Following signature 

by the EPA Administrator, the EPA will 

post a copy of this final action at: 

http://www.epa.gov/ttn/atw/petref.html. 

Following publication in the Federal 

Register, the EPA will post the Federal 

Register version and key technical 

documents at this same Web site. 

Additional information is available on 

the RTR Web site at http://www.epa.

gov/ttn/atw/rrisk/rtrpg.html. This 

information includes an overview of the 

RTR program, links to project Web sites 


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2The U.S. Court of Appeals has affirmed this 

approach of implementing CAA section 

112(f)(2)(A): NRDC v. EPA, 529 F.3d 1077, 1083 

(D.C. Cir. 2008) (‘‘If EPA determines that the 

existing technology-based standards provide an 

‘ample margin of safety,’ then the Agency is free to 

readopt those standards during the residual risk 

rulemaking.’’). 

for the RTR source categories, and 

detailed emissions and other data we 

used as inputs to the risk assessments. 

C. Judicial Review and Administrative 

Reconsideration 

Under CAA section 307(b)(1), judicial 

review of this final action is available 

only by filing a petition for review in 

the United States Court of Appeals for 

the District of Columbia Circuit by 

February 1, 2016. Under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by the EPA to 

enforce the requirements. 

Section 307(d)(7)(B) of the CAA 

further provides that ‘‘[o]nly an 

objection to a rule or procedure which 

was raised with reasonable specificity 

during the period for public comment 

(including any public hearing) may be 

raised during judicial review.’’ This 

section also provides a mechanism for 

the EPA to reconsider the rule ‘‘[i]f the 

person raising an objection can 

demonstrate to the Administrator that it 

was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration 

should submit a Petition for 

Reconsideration to the Office of the 

Administrator, U.S. EPA, Room 3000, 

WJC Building, 1200 Pennsylvania Ave. 

NW., Washington, DC 20460, with a 

copy to both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), U.S. EPA, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460. 

II. Background 

A. What is the statutory authority for 

this action? 

1. NESHAP 

Section 112 of the CAA establishes a 

two-stage regulatory process to address 

emissions of hazardous air pollutants 

(HAP) from stationary sources. In the 

first stage, we must identify categories 

of sources emitting one or more of the 

HAP listed in CAA section 112(b) and 

then promulgate technology-based 

NESHAP for those sources. ‘‘Major 

sources’’ are those that emit, or have the 

potential to emit, any single HAP at a 

rate of 10 tons per year (tpy) or more, 

or 25 tpy or more of any combination of 

HAP. For major sources, these standards 

are commonly referred to as maximum 

achievable control technology (MACT) 

standards and must reflect the 

maximum degree of emission reductions 

of HAP achievable (after considering 

cost, energy requirements, and non-air 

quality health and environmental 

impacts). In developing MACT 

standards, CAA section 112(d)(2) directs 

the EPA to consider the application of 

measures, processes, methods, systems 

or techniques, including but not limited 

to those that reduce the volume of or 

eliminate HAP emissions through 

process changes, substitution of 

materials, or other modifications; 

enclose systems or processes to 

eliminate emissions; collect, capture, or 

treat HAP when released from a process, 

stack, storage, or fugitive emissions 

point; are design, equipment, work 

practice, or operational standards; or 

any combination of the above. 

For these MACT standards, the statute 

specifies certain minimum stringency 

requirements, which are referred to as 

MACT floor requirements, and which 

may not be based on cost 

considerations. See CAA section 

112(d)(3). For new sources, the MACT 

floor cannot be less stringent than the 

emission control achieved in practice by 

the best-controlled similar source. The 

MACT standards for existing sources 

can be less stringent than floors for new 

sources, but they cannot be less 

stringent than the average emission 

limitation achieved by the bestperforming 12-percent of existing 

sources in the category or subcategory 

(or the best-performing 5 sources for 

categories or subcategories with fewer 

than 30 sources). In developing MACT 

standards, we must also consider 

control options that are more stringent 

than the floor, under CAA section 

112(d)(2). We may establish standards 

more stringent than the floor, based on 

the consideration of the cost of 

achieving the emissions reductions, any 

non-air quality health and 

environmental impacts, and energy 

requirements. 

In the second stage of the regulatory 

process, the CAA requires the EPA to 

undertake 2 different analyses, which 

we refer to as the technology review and 

the residual risk review. Under the 

technology review, we must review the 

technology-based standards and revise 

them ‘‘as necessary (taking into account 

developments in practices, processes, 

and control technologies)’’ no less 

frequently than every eight years, 

pursuant to CAA section 112(d)(6). 

Under the residual risk review, we must 

evaluate the risk to public health 

remaining after application of the 

technology-based standards and revise 

the standards, if necessary, to provide 

an ample margin of safety to protect 

public health or to prevent, taking into 

consideration costs, energy, safety and 

other relevant factors, an adverse 

environmental effect. The residual risk 

review is required within eight years 

after promulgation of the technologybased standards, pursuant to CAA 

section 112(f). In conducting the 

residual risk review, if the EPA 

determines that the current standards 

provide an ample margin of safety to 

protect public health, it is not necessary 

to revise the MACT standards pursuant 

to CAA section 112(f).2 For more 

information on the statutory authority 

for this rule, see 79 FR 36879. 

2. NSPS 

Section 111 of the CAA establishes 

mechanisms for controlling emissions of 

air pollutants from stationary sources. 

Section 111(b) of the CAA provides 

authority for the EPA to promulgate 

NSPS that apply only to newly 

constructed, reconstructed and modified 

sources. Once the EPA has elected to set 

NSPS for new and modified sources in 

a given source category, CAA section 

111(d) calls for regulation of existing 

sources, with certain exceptions 

explained below. 

Specifically, section 111(b) of the 

CAA requires the EPA to establish 

emission standards for any category of 

new and modified stationary sources 

that the Administrator, in his or her 

judgment, finds ‘‘causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ The EPA has 

previously made endangerment findings 

under this section of the CAA for more 

than 60 stationary source categories and 

subcategories that are now subject to 

NSPS. 

Section 111 of the CAA gives the EPA 

significant discretion to identify the 

affected facilities within a source 

category that should be regulated. To 

define the affected facilities, the EPA 

can use size thresholds for regulation 

and create subcategories based on 

source type, class or size. Emission 

limits also may be established either for 

equipment within a facility or for an 

entire facility. For listed source 

categories, the EPA must establish 

‘‘standards of performance’’ that apply 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75181 

3Specific statutory and regulatory provisions 

define what constitutes a modification or 

reconstruction of a facility. 40 CFR 60.14 provides 

that an existing facility is modified and, therefore, 

subject to an NSPS, if it undergoes any physical 

change in the method of operation which increases 

the amount of any air pollutant emitted by such 

source or which results in the emission of any air 

pollutant not previously emitted. 40 CFR 60.15, in 

turn, provides that a facility is reconstructed if 

components are replaced at an existing facility to 

such an extent that the capital cost of the new 

equipment/components exceed 50-percent of what 

is believed to be the cost of a completely new 

facility. 

to sources that are constructed, 

modified or reconstructed after the EPA 

proposes the NSPS for the relevant 

source category.3

The EPA also has significant 

discretion to determine the appropriate 

level for the standards. Section 111(a)(1) 

of the CAA provides that NSPS are to 

reflect the degree of emission limitation 

achievable through the application of 

the best system of emission reduction 

which (taking into account the cost of 

achieving such reduction and any nonair quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated. This level of 

control is commonly referred to as best 

demonstrated technology (BDT) or the 

best system of emission reduction 

(BSER). The standard that the EPA 

develops, based on the BSER achievable 

at that source, is commonly a numerical 

emission limit, expressed as a 

performance level (i.e., a rate-based 

standard). Generally, the EPA does not 

prescribe a particular technological 

system that must be used to comply 

with a NSPS. Rather, sources remain 

free to elect whatever combination of 

measures will achieve equivalent or 

greater control of emissions. 

Costs are also considered in 

evaluating the appropriate standard of 

performance for each category or 

subcategory. The EPA generally 

compares control options and estimated 

costs and emission impacts of multiple, 

specific emission standard options 

under consideration. As part of this 

analysis, the EPA considers numerous 

factors relating to the potential cost of 

the regulation, including industry 

organization and market structure, 

control options available to reduce 

emissions of the regulated pollutant(s) 

and costs of these controls. 

B. How do the NESHAP and NSPS 

regulate air pollutant emissions from 

refineries? 

The EPA promulgated the petroleum 

refinery NESHAP pursuant to CAA 

section 112(d)(2) and (3) for refineries 

located at major sources in two separate 

rules. On August 18, 1995, the first 

petroleum refinery MACT standard was 

promulgated in 40 CFR part 63, subpart 

CC (60 FR 43620). This rule is known 

as ‘‘Refinery MACT 1’’ and covers the 

‘‘Sources Not Distinctly Listed,’’ 

meaning it includes all emissions 

sources from petroleum refinery process 

units, except those listed separately 

under the section 112(c) source category 

list and expected to be regulated by 

other MACT standards (for example, 

boilers and process heaters). Some of 

the emission sources regulated in 

Refinery MACT 1 include miscellaneous 

process vents (MPV), storage vessels, 

wastewater, equipment leaks, gasoline 

loading racks, marine tank vessel 

loading and heat exchange systems. 

On April 11, 2002 (67 FR 17762), EPA 

promulgated a second MACT standard 

regulating certain process vents that 

were listed as a separate source category 

under CAA section 112(c) and that were 

not addressed as part of the Refinery 

MACT 1. This standard, which is 

referred to as ‘‘Refinery MACT 2’’, 

covers process vents on catalytic 

cracking units (CCU) (including FCCU), 

CRU and SRU and is codified as 40 CFR 

part 63, subpart UUU. 

Finally, on October 28, 2009, we 

revised Refinery MACT 1 by adding 

MACT standards for heat exchange 

systems, which the EPA had not 

addressed in the original 1995 Refinery 

MACT 1 rule (74 FR 55686). In this 

same 2009 action, we updated the crossreferences to the General Provisions in 

40 CFR part 63. On June 20, 2013 (78 

FR 37133), we promulgated minor 

revisions to the heat exchange 

provisions of Refinery MACT 1. 

On September 27, 2012, Air Alliance 

Houston, California Communities 

Against Toxics and other environmental 

and public health groups filed a lawsuit 

alleging that the EPA missed statutory 

deadlines to review and revise Refinery 

MACT 1 and 2. The EPA reached an 

agreement to settle that litigation and 

entered into a Consent Decree. The 

Consent Decree provides for the 

Administrator to sign a final action no 

later than September 30, 2015. 

Refinery NSPS subparts J and Ja 

regulated criteria pollutant emissions, 

including particulate matter (PM), sulfur 

dioxide (SO2), nitrogen oxides (NOX) 

and carbon monoxide (CO) from FCCU 

catalyst regenerators, fuel gas 

combustion devices (FGCD) and sulfur 

recovery plants. Refinery NSPS subpart 

Ja also regulates criteria pollutant 

emissions from fluid coking units and 

DCU. 

The NSPS for petroleum refineries (40 

CFR part 60, subpart J) were 

promulgated in 1974, amended in 1976 

and amended again in 2008, following 

a review of the standards. As part of the 

review that led to the 2008 amendments 

to the Refinery NSPS subpart J, the EPA 

developed separate standards of 

performance for new process units (40 

CFR part 60, subpart Ja). However, the 

EPA received multiple petitions for 

reconsideration on issues related to 

those standards. The Administrator 

granted the petitions for 

reconsideration. The EPA addressed 

petition issues related to process heaters 

and flares by promulgating amendments 

to the Refinery NSPS subparts J and Ja 

on September 12, 2012 (77 FR 56422). 

In this action, we are finalizing 

technical corrections and clarifications 

to NSPS subparts J and Ja raised by 

American Petroleum Institute (API) in 

their 2008 petition for reconsideration 

that were not addressed by the final 

NSPS amendments of 2012. 

The petroleum refining industry 

consists of facilities that engage in 

converting crude oil into refined 

products, including liquefied petroleum 

gas, gasoline, kerosene, aviation fuel, 

diesel fuel, fuel oils, lubricating oils and 

feedstocks for the petrochemical 

industry. Currently, 142 facilities have 

emission sources regulated by either or 

both Refinery MACT 1 and 2. 

Petroleum refinery activities start 

with the receipt of crude oil for storage 

at the refinery, include all the petroleum 

handling and refining operations, and 

terminate with loading of refined 

products into pipelines, tank or rail 

cars, tank trucks, or ships or barges that 

take products from the refinery to 

distribution centers. Petroleum-specific 

process units include FCCU and CRU. 

Other units and processes found at 

petroleum refineries (as well as at many 

other types of manufacturing facilities) 

include storage vessels and wastewater 

treatment plants. HAP emitted by this 

industry include organics (e.g., 

acetaldehyde, benzene, formaldehyde, 

hexane, phenol, naphthalene, 2- 

methylnaphthalene, dioxins, furans, 

ethyl benzene, toluene and xylene); 

reduced sulfur compounds (i.e., 

carbonyl sulfide (COS), carbon disulfide 

(CS2))); inorganics (e.g., hydrogen 

chloride (HCl), hydrogen cyanide 

(HCN), chlorine, hydrogen fluoride 

(HF)); and metals (e.g., antimony, 

arsenic, beryllium, cadmium, 

chromium, cobalt, lead, mercury, 

manganese and nickel (Ni)). This 

industry also emits criteria pollutants 

and other non-HAP, including NOX, 

PM, SO2, volatile organic compounds 

(VOC), CO, greenhouse gases (GHG) and 

total reduced sulfur. 


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75182 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

C. What changes did we propose for the 

Petroleum Refinery NESHAP and NSPS 

in our June 30, 2014, RTR proposal? 

On June 30, 2014, the EPA published 

a proposed rule in the Federal Register 

addressing the RTR for the Petroleum 

Refinery NESHAP, 40 CFR part 63, 

subparts CC and UUU. The proposal 

also included changes pursuant to 

section 112(d)(2) and (3) and technical 

revisions to the NSPS. Specifically, we 

proposed: 

(1) Pursuant to CAA sections 

112(d)(2) and (3): 

a. Refinery MACT 1: 

• Adding MACT Standards for DCU 

decoking operations. 

• Adding operational requirements 

for flares used as APCD in Refinery 

MACT 1 and 2. 

• Adding requirements and 

clarifications for vent control bypasses 

in Refinery MACT 1. 

b. Refinery MACT 2: 

• Revising the CRU purge vent 

exemption. 

(2) Pursuant to CAA sections 

112(d)(6) and 112(f)(2): 

• Revising Refinery MACT 1 to crossreference the corresponding storage 

vessel requirements in the Generic 

MACT (40 CFR part 63, subpart WW, as 

applicable), and revising the definition 

of Group 1 storage vessels to include 

smaller capacity storage vessels and to 

include storage vessels storing materials 

with lower vapor pressures. 

(3) Pursuant to CAA section 112(d)(6): 

a. Refinery MACT 1: 

• Allowing refineries to meet the leak 

detection and repair (LDAR) 

requirements in Refinery MACT 1 by 

monitoring for leaks using optical gas 

imaging in place of EPA Method 21, 

once the monitoring protocol set forth in 

Appendix K is promulgated. 

• Amending the Marine Tank Vessel 

Loading Operations NESHAP, 40 CFR 

part 63, subpart Y, to delete the 

exclusion for marine vessel loading 

operations at petroleum refineries. 

• Establishing a fenceline monitoring 

work practice standard to improve the 

management of fugitive emissions. 

b. Refinery MACT 2: 

• Incorporating requirements 

consistent with those in Refinery NSPS 

subpart Ja for FCCU including: 

• Requiring the use of 3-hour 

averages rather than daily averages for 

parameter operating limits (e.g., 

depending on the type of control device: 

Opacity, total power, secondary current, 

pressure drop, and/or liquid-to-gas 

ratio). 

• Removing the Refinery NSPS 

subpart J incremental PM emissions 

allowance for post combustion devices 

when burning liquid or solid fuels, and 

removing the 30 percent opacity limit 

for units complying with NSPS subpart 

J. 

• Adding requirements for FCCU 

controls to include bag leak detectors 

(BLD) as an option to continuous 

opacity monitoring system (COMS). 

• Incorporating total power and the 

secondary current operating limits for 

electrostatic precipitators (ESP). 

• Requiring daily checks of the air or 

water pressure to the spray nozzles on 

jet ejector-type wet scrubber or other 

type of wet scrubber equipped with 

atomizing spray nozzles. 

• Requiring FCCU periodic 

performance testing on a frequency of 

once every 5 years, as opposed to the 

current rule, which only requires an 

initial performance test. 

• Including a correlation equation for 

the use of oxygen-enriched air for SRU. 

• Allowing SRU subject to Refinery 

NSPS subpart Ja with a capacity greater 

than 20 long tons per day (LTD) to 

comply with Refinery NSPS subpart Ja 

as a means of complying with Refinery 

MACT 2. 

(4) Other proposed changes include: 

• Removing exemptions from the rule 

requirements for periods of SSM in 

order to ensure that the NESHAP are 

consistent with the court decision in 

Sierra Club v. EPA, 551 F. 3d 1019 (D.C. 

Cir. 2008). 

• Clarifying requirements related to 

open-ended valves or lines. 

• Adding electronic reporting 

requirements. 

• Updating the General Provisions 

cross-reference tables. 

• Making technical corrections and 

clarifications to NSPS subparts J and Ja. 

III. What is included in this final rule? 

This action finalizes the EPA’s 

determinations pursuant to the RTR 

provisions of CAA section 112 for the 

Petroleum Refinery source categories 

and amends the Petroleum Refinery 

NESHAP based on those 

determinations. This action also 

finalizes other changes to the NESHAP 

including revising Refinery MACT 1 

and 2 pursuant to CAA section 112 

(d)(2) and (3), including revising 

requirements for flares and pressure 

relief devices (PRD). This action 

finalizes changes to the SSM provisions 

to ensure that the subparts are 

consistent with the court decision in 

Sierra Club v. EPA, 551 F. 3d 1019 (D.C. 

Cir. 2008), adds electronic reporting 

requirements in Refinery MACT 1 and 

2; and updates the General Provisions 

cross-reference tables. Finally, this 

action finalizes technical corrections 

and clarifications to Refinery NSPS 

subparts J and Ja to address issues raised 

in the reconsideration of these rules. 

A. What are the final NESHAP 

amendments based on the risk review 

for the Petroleum Refinery source 

categories? 

The EPA is promulgating final 

amendments to the Petroleum Refinery 

NESHAP pursuant to CAA section 

112(f) that expand the existing Refinery 

MACT 1 control requirements and 

extend these requirements to smaller 

tanks and tanks with lower vapor 

pressures. Specifically, consistent with 

the proposal, the EPA is amending 

Refinery MACT 1 by revising the 

definition of Group 1 storage vessels to 

include storage vessels with capacities 

greater than or equal to 20,000 gallons 

but less than 40,000 gallons if the 

maximum true vapor pressure is 1.0 

psia or greater and to include storage 

tanks greater than 40,000 gallons if the 

maximum true vapor pressure is 0.75 

psia or greater. The EPA is also adding 

a cross-reference to the storage vessel 

requirements in the Generic MACT (40 

CFR part 63, subpart WW and subpart 

CC), which include requirements for 

guide pole controls and other fittings as 

well as inspection requirements. After 

considering the public comments, the 

final amendments include minor 

changes from our proposed 

requirements to clarify language and 

correct typographical and referencing 

errors. 

B. What are the final NESHAP 

amendments based on the technology 

review for the Petroleum Refinery source 

categories? 

1. Refinery MACT 1 

We determined that there are 

developments in practices, processes 

and control technologies that warrant 

revisions to the MACT standards for this 

source category. Therefore, to satisfy the 

requirements of CAA section 112(d)(6), 

we are revising the MACT standards to 

amend 40 CFR part 63, subpart Y to 

delete the exclusion for marine vessel 

loading operations at petroleum 

refineries. Removing this exclusion will 

require small marine vessel loading 

operations (i.e., operations with HAP 

emissions less than 10/25 tpy) and 

offshore marine vessel loading 

operations to use submerged filling 

based on the cargo filling line 

requirements in 46 CFR 153.282, as 

proposed. 

We are also finalizing a fenceline 

monitoring work practice standard to 

improve the management of fugitive 

emissions and finalizing EPA Methods 

325A and 325B to support the work 


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practice, with some changes from 

proposal to address issues raised by 

commenters. Key revisions include: 

New provisions for reduced monitoring 

for facilities with consistently low 

fenceline concentrations; requirements 

for alternatives to passive monitoring; 

revised placement guidance to allow 

perimeter monitoring within a facility’s 

property boundary provided all sources 

are encompassed within the monitoring 

perimeter; reductions in the number of 

monitors required for subareas and 

segregated areas; clarifications on 

monitor placement for internal 

roadways or other right-of-ways and 

marine docks; and revised timelines for 

submitting periodic reports (quarterly 

rather than semiannually) and 

implementing the work practice 

standard (2 years after promulgation 

rather than 3 years as proposed). We are 

also revising Refinery MACT 1 storage 

vessel requirements as described above 

under the risk review, as proposed. 

2. Refinery MACT 2 

We determined that there are 

developments in practices, processes 

and control technologies that warrant 

revisions to the MACT standards for this 

source category. Therefore, to satisfy the 

requirements of CAA section 112(d)(6), 

we are revising the Refinery MACT 2 

standard for FCCU subject to Refinery 

NSPS subpart J or those electing to 

comply with the Refinery NSPS subpart 

J requirements. As proposed, we are 

removing the incremental PM limit 

when burning liquid or solid fuels. We 

are finalizing a 20-percent opacity 

operating limit evaluated on a 3-hour 

average, which differs from the proposal 

to eliminate the 30-percent opacity limit 

and instead allow only for a site-specific 

opacity operating limit or control device 

parameter monitoring. As proposed, we 

are finalizing requirements to make 

Refinery MACT 2 consistent with 

Refinery NSPS subpart Ja for FCCU by 

including 3-hour averages rather than 

daily averages for parameter operating 

limits, and by including 3-hour averages 

rather than daily averages for the sitespecific opacity operating limit. We are 

also finalizing requirements, as 

proposed, for FCCU controls to include 

adding BLD as an option to COMS, 

incorporating total power and the 

secondary current operating limits for 

ESP and requiring daily checks of the 

air or water pressure to the spray 

nozzles on jet ejector-type wet scrubbers 

or other types of wet scrubbers 

equipped with atomizing spray nozzles. 

Finally, we are finalizing, as 

proposed, requirements for FCCU 

periodic performance testing at a 

frequency of once every 5 years rather 

than the current requirements for a onetime initial performance test. However, 

for owners or operators complying with 

the Refinery NSPS subpart J option 

(with the 20-percent opacity operating 

limit discussed above), if the PM 

emissions are within 80-percent of the 

PM limit during any periodic 

performance test (i.e., emissions exceed 

0.8 lb PM/1,000 lbs of coke burn-off), 

the refinery owner or operator must 

conduct subsequent performance tests 

on an annual basis. Based on comments 

received, we are also adding 

requirements in the final rule for owners 

or operators of FCCU to conduct a onetime test for HCN emissions from the 

FCCU concurrent with their first 

periodic performance test, which must 

be conducted on or before August 1, 

2017 for all FCCU subject to Refinery 

MACT 2. 

For SRU, as proposed, we are 

finalizing a correlation equation for the 

use of oxygen-enriched air. 

Additionally, as proposed, we are 

finalizing requirements to allow sulfur 

recovery plants subject to Refinery 

NSPS subpart Ja with a capacity greater 

than 20 LTD to comply with Refinery 

NSPS subpart Ja as a means of 

complying with Refinery MACT 2. 

C. What are the final NESHAP 

amendments pursuant to section 

112(d)(2) & (3) for the Petroleum 

Refinery source categories? 

1. Refinery MACT 1 

We are finalizing MACT standards for 

DCU decoking operations that require 

that each coke drum be depressured to 

a closed blowdown system until the 

coke drum pressure is 2 psig with minor 

revisions from proposal. Specifically, 

we are finalizing provisions for existing 

DCU affected sources to average over a 

60-cycle (i.e., 60 batch) basis to comply 

with the 2 psig limit, rather than the 

proposed requirement to meet the 2 psig 

limit on a per venting event basis. In 

addition, we are finalizing requirements 

for new DCU affected sources to 

depressure to 2.0 psig on a per-event, 

not-to-exceed basis, adding one 

significant digit to the limit for new 

DCU affected sources. For both new and 

existing DCU affected sources, we are 

finalizing specific provisions for DCU 

with water overflow design and for 

double quenching. 

We are finalizing operational 

requirements and the associated 

monitoring, recordkeeping and 

reporting requirements for flares used as 

APCD in Refinery MACT 1 and 2 with 

revisions to the requirements proposed. 

Prior to these amendments, Refinery 

MACT 1 and 2 cross-referenced the 

General Provisions requirements at 40 

CFR 63.11(b). As proposed, this final 

action replaces the cross reference to the 

General Provisions and incorporates 

enhanced flare operational requirements 

directly into the Refinery MACT 

regulations. As proposed, the final rule 

amendments require that refinery flares 

operate with continuously lit pilot 

flames at all times. Consistent with our 

proposal, we are finalizing requirements 

for flares to operate with no visible 

emissions and comply with 

consolidated requirements related to 

flare tip velocity, but in the final rule 

these direct emissions limits apply 

when flare vent gas flow is below the 

smokeless capacity of the flare rather 

than at all times. Above the smokeless 

capacity of the flare, we are establishing 

a work practice standard related to the 

visible emissions and velocity limits; 

these work practice standards are 

described in more detail in section 

III.D.1 of this preamble. 

We are finalizing new operational 

requirements related to combustion 

zone gas properties with revisions from 

proposal. In response to comments on 

the proposal, we are finalizing 

requirements that flares meet a 

minimum operating limit of 270 BTU/

scf NHVcz on a 15-minute average, and 

are allowing refinery owners or 

operators to use a corrected heat content 

of 1,212 BTU/scf for hydrogen to 

demonstrate compliance with this 

operating limit. We had proposed two 

separate sets of limits, one being more 

stringent if an olefins/hydrogen mixture 

was present in the waste gas. For each 

set of limits, we proposed three different 

alternative combustion zone operating 

limits: One based on the combustion 

zone net heat content with no correction 

for the heat content of hydrogen, one 

based on the lower flammability limit 

and one based on the combustibles 

concentration. We proposed that these 

limits be determined on a 15-minute 

‘‘feed-forward’’ block average approach 

(i.e., compositional data are collected 

every 15 minutes, after which 

adjustments are made). We have 

included an additional option for 

refiners to comply where more frequent 

data are collected (using direct net 

heating value monitoring) to calculate 

the combustion limit using net heating 

value data from the same 15-minute 

block period. We are simplifying the 

compliance approach to a single 

operating limit based only on the 

combustion zone net heating value 

(with a hydrogen correction). As 

proposed, we are requiring refinery 

owners or operators to characterize the 

composition of waste gas, assist gas and 


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fuel to demonstrate compliance with the 

operational requirements. 

As proposed, we are also finalizing in 

this rule a burden reduction option to 

use grab sampling every 8 hours rather 

than continuous vent gas composition 

or heat content monitors. We are also 

including, based on public comment, 

provisions to conduct limited initial 

sampling and process knowledge to 

characterize flare gas composition for 

flares in ‘‘dedicated’’ service as an 

alternative to collecting grab samples 

during each specific event. We are 

finalizing a requirement for daily visible 

emissions observations as proposed, 

but, based on public comment, we are 

allowing owners or operators to use 

video surveillance cameras to 

demonstrate compliance with the 

visible emissions limit as an alternative 

to the daily visible emissions 

observations. 

For PRD, we are finalizing 

requirements for monitoring systems 

that are capable of identifying and 

recording the time and duration of each 

pressure release to the atmosphere, as 

proposed. Certain PRD with low set 

pressures or low emission potential or 

in liquid service would not be subject to 

these monitoring requirements. We are 

finalizing requirements to minimize or 

prevent atmospheric releases of HAP 

through PRD. Instead of the proposed 

prohibition on such releases, we are 

finalizing work practice requirements 

that require both preventive measures as 

well as root cause analysis and 

corrective action that will incentivize 

refinery owners or operators to 

eliminate the causes of the releases. 

We are finalizing requirements for 

bypass lines with minor revisions from 

those proposed. Specifically, we are not 

adopting the proposed requirement to 

install quantitative flow monitors and 

thus are leaving in place the 

requirement to use flow indicators on 

bypass lines. In addition, we are 

maintaining the requirements to 

estimate and report the quantity of 

organic HAP released. In response to 

public comment, we are also clarifying 

changes to remove the proposed 

reference to air intrusion and specifying 

that reporting of bypasses is only 

required when ‘‘regulated material’’ is 

discharged to the atmosphere as a result 

of a bypass of a control device. 

We are also finalizing revisions to the 

definition of miscellaneous process 

vent, as proposed. These revisions 

include deletion of exclusions 

associated with episodic releases and 

vents from in situ sampling systems. As 

proposed, the final amendments require 

that these vents must meet the standards 

applicable to MPV. 

2. Refinery MACT 2 

For CRU vents, we are finalizing the 

vessel pressure limit exclusion of 5 psig 

to apply only to passive 

depressurization, as proposed. 

D. What are the final NESHAP 

amendments addressing emissions 

during periods of SSM? 

We are finalizing, as proposed, 

changes to Refinery MACT 1 and 2 to 

eliminate the SSM exemption. 

Consistent with Sierra Club v. EPA, 551 

F. 3d 1019 (D.C. Cir. 2008), the EPA has 

established standards in this rule that 

apply at all times. EPA is revising Table 

6 of subpart CC of 40 CFR part 63 and 

Table 44 to subpart UUU of 40 CFR part 

63 (the General Provisions Applicability 

Tables) to change several references 

related to requirements that apply 

during periods of SSM. We also are 

eliminating or revising certain 

recordkeeping and reporting 

requirements related to the eliminated 

SSM exemptions. We also are removing 

or modifying inappropriate, 

unnecessary or redundant language in 

the absence of the SSM exemption. 

Further, for certain emission sources in 

both MACT 1 and 2, we are establishing 

standards to address emissions during 

these periods. These are described 

below. 

1. Refinery MACT 1 

We are finalizing a work practice 

standard for PRD that requires refinery 

owners or operators to establish 

prevention measures for each PRD in 

organic HAP service. Under the work 

practice standard, where a direct release 

occurs, the refinery is required to 

perform root cause analysis and 

implement corrective action. The work 

practice standard also limits the number 

of events that a PRD may release to the 

atmosphere during a 3-year period, as 

explained further in the section IV.D. of 

this preamble. 

We are also finalizing a work practice 

standard for emergency flaring events 

that requires refinery owners or 

operators to establish prevention 

measures, including the development of 

a flare management plan (FMP), and 

perform root cause analysis and 

implement corrective action following 

flaring events during which the velocity 

of waste gas going to the flare or visible 

emissions limits (i.e., opacity) at the 

flare tip are exceeded, and to limit the 

number of these events allowed in a 3- 

year period, as explained further in 

section IV.D. of this preamble. Both of 

these work practice standards are 

consistent with the EPA’s goal to 

improve the effectiveness of the rules. 

These requirements will provide a 

strong incentive for facilities, over time, 

to better operate their processes to 

prevent PRD and flare releases. 

We are also finalizing requirements 

for opening process equipment to the 

atmosphere during maintenance events 

after draining and purging to a closed 

system, provided the hydrocarbon 

content is less than or equal to 10- 

percent of the lower explosive limit 

(LEL). For those situations where 10- 

percent LEL cannot be demonstrated, 

the equipment may be opened and 

vented to the atmosphere if the pressure 

is less than or equal to 5 psig, provided 

there is no active purging of the 

equipment to the atmosphere until the 

LEL criterion is met. This 5 psig 

allowance is only available during 

shutdown. We are also providing 

additional allowances for situations 

where it is not technically feasible to 

depressurize a control system where 

there is no more than 72 lbs VOC per 

day vented to the atmosphere, 

consistent with our Group 1 

applicability cutoff for control of 

process vents, or for catalyst changeout 

activities where hydrotreater pyrophoric 

catalyst must be purged. Provisions to 

demonstrate that process equipment is 

opened only after the LEL, pressure or 

mass in the vessel requirement is met 

includes documenting the procedures 

for equipment openings and procedures 

for verifying that the openings meet the 

specific, above-discussed requirements 

using site-specific procedures used to 

de-inventory equipment for safety 

purposes (i.e., hot work or vessel entry 

procedures). 

2. Refinery MACT 2 

The Refinery MACT 2 standards 

regulate all HAP emissions from the 

three refinery process vents subject to 

Refinery MACT 2. For FCCU, the 

standard specifies a CO limit as a 

surrogate for organic HAP and specifies 

a PM limit (or Ni limit) as a surrogate 

for metal HAP. Compliance with the 

organic HAP emissions limit is 

demonstrated using a continuous CO 

monitor; compliance with the metal 

HAP emissions limit is demonstrated 

using either COMS or control device 

parameter monitoring systems (CPMS). 

At proposal, with the removal of the 

exemptions in the Refinery MACT 2 

rule for periods of startup and 

shutdown, we recognized the need for 

alternative standards during some 

startup and shutdown situations, and 

we proposed alternative requirements. 

For this final rule, we are including a 

1-percent minimum oxygen limit as an 

alternative to the 500 ppmv hourly CO 

limit during FCCU startup for partial 


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burn FCCU with CO boilers, as 

proposed. We are extending that 

alternative limit to all FCCU and 

extending it to apply during shutdown. 

We are not finalizing the proposed 

alternative opacity limit for FCCU 

during startup. Instead, based on public 

comments received, we are finalizing an 

alternative minimum cyclone face 

velocity limit as a means to demonstrate 

compliance with the PM limit during 

both startup and shutdown, regardless 

of the type of FCCU and its control 

device. We are finalizing alternative 

standards for sulfur recovery plant 

(SRP) incinerator temperature and 

excess oxygen limits during SRP 

shutdown, as proposed, and we are 

extending the proposed alternative 

standards to startup as well. 

E. What other revisions to the NESHAP 

and NSPS are being promulgated? 

We are finalizing technical 

amendments to NSPS subparts J and Ja 

with limited changes from what we 

proposed. First, in response to 

comments, we are revising the NSPS 

requirements that a flow sensor have a 

‘‘measurement sensitivity’’ of no more 

than 5-percent of the flow rate to an 

‘‘accuracy’’ requirement that the flow 

sensor have an accuracy of 5-percent of 

the flow rate. This change will make the 

requirements more clear and consistent 

between the flow meter requirements in 

the NSPS and the MACT standards 

since it is the same flow meter subject 

to these requirements. We are also 

revising flare flow rate accuracy 

requirements in Refinery NSPS subpart 

Ja to make them consistent with those 

we are finalizing in Refinery MACT 1. 

Finally, we are revising 40 CFR 

60.101a(b) to begin as ‘‘Except for flares 

and delayed coking units . . .’’ to 

correct an inadvertent error. We 

proposed revisions to this sentence 

solely to allow sources subject to 

Refinery NSPS subpart J to comply with 

the provisions in Refinery NSPS subpart 

Ja instead. However, the words ‘‘and 

delayed coking units’’ were 

inadvertently omitted from the initial 

part of the sentence. Thus, as intended, 

we are finalizing revisions to this 

sentence to allow sources subject to 

Refinery NSPS subpart J to comply with 

the provisions in Refinery NSPS subpart 

Ja. 

F. What are the requirements for 

submission of performance test data to 

the EPA? 

As proposed, the EPA is taking a step 

to increase the ease and efficiency of 

data submittal and data accessibility. 

Specifically, the EPA is finalizing the 

requirement for owners or operators of 

Petroleum Refinery facilities to submit 

electronic copies of certain required 

performance test reports through the 

EPA’s Central Data Exchange (CDX) 

using the Compliance and Emissions 

Data Reporting Interface (CEDRI). The 

EPA believes that the electronic 

submittal of the reports addressed in 

this rulemaking will increase the 

usefulness of the data contained in 

those reports, is in keeping with current 

trends in data availability, will further 

assist in the protection of public health 

and the environment and will 

ultimately result in less burden on the 

regulated community. Electronic 

reporting can also eliminate paperbased, manual processes, thereby saving 

time and resources, simplifying data 

entry, eliminating redundancies, 

minimizing data reporting errors and 

providing data quickly and accurately to 

the affected facilities, air agencies, the 

EPA and the public. 

As mentioned in the preamble of the 

proposal, the EPA Web site that stores 

the submitted electronic data, WebFIRE, 

will be easily accessible to everyone and 

will provide a user-friendly interface 

that any stakeholder could access. By 

making the records, data and reports 

addressed in this rulemaking readily 

available, the EPA, the regulated 

community and the public will benefit 

when the EPA conducts its CAArequired technology and risk-based 

reviews. As a result of having reports 

readily accessible, our ability to carry 

out comprehensive reviews will be 

increased and achieved within a shorter 

period of time. 

We anticipate fewer or less substantial 

information collection requests (ICRs) in 

conjunction with prospective CAArequired technology and risk-based 

reviews may be needed. We expect this 

to result in a decrease in time spent by 

industry to respond to data collection 

requests. We also expect the ICRs to 

contain less extensive stack testing 

provisions, as we will already have 

stack test data electronically. Reduced 

testing requirements would be a cost 

savings to industry. The EPA should 

also be able to conduct these required 

reviews more quickly. While the 

regulated community may benefit from 

a reduced burden of ICRs, the general 

public benefits from the agency’s ability 

to provide these required reviews more 

quickly, resulting in increased public 

health and environmental protection. 

Air agencies could benefit from more 

streamlined and automated review of 

the electronically submitted data. 

Having reports and associated data in 

electronic format will facilitate review 

through the use of software ‘‘search’’ 

options, as well as the downloading and 

analyzing of data in spreadsheet format. 

The ability to access and review air 

emission report information 

electronically will assist air agencies to 

more quickly and accurately determine 

compliance with the applicable 

regulations, potentially allowing a faster 

response to violations which could 

minimize harmful air emissions. This 

benefits both air agencies and the 

general public. 

For a more thorough discussion of 

electronic reporting required by this 

rule, see the discussion in the preamble 

of the proposal. In summary, in addition 

to supporting regulation development, 

control strategy development, and other 

air pollution control activities, having 

an electronic database populated with 

performance test data will save 

industry, air agencies, and the EPA 

significant time, money, and effort 

while improving the quality of emission 

inventories, air quality regulations, and 

enhancing the public’s access to this 

important information. 

G. What are the effective and 

compliance dates of the NESHAP and 

NSPS? 

The final amendments to the NESHAP 

and NSPS in this action are effective on 

February 1, 2016. As proposed, new 

sources must comply with these 

requirements by the effective date of the 

final rule or upon startup, whichever is 

later. 

As proposed, existing sources are 

required to comply with the final DCU 

and CRU requirements no later than 3 

years after the effective date of the final 

rule. Similarly, as proposed, owners or 

operators are required to comply with 

the new operating and monitoring 

requirements for existing flares no later 

than 3 years after the effective date of 

the final rule. 

We proposed to provide 3 years from 

the effective date of the final rule for 

refinery owners or operators to install 

and begin monitoring (collecting 

samples) around the fenceline of their 

existing facility. If refinery owners and 

operators determined that a site-specific 

monitoring plan was needed, they 

would also need to submit and receive 

approval for such a plan during the 3- 

year compliance period. Based on 

information submitted during the 

comment period, we are finalizing 

requirements that refinery owners or 

operators begin collecting samples 

around the fenceline within 2 years of 

the effective date of the final rule. Based 

on information submitted during the 

comment period, 1 year is sufficient 

time to identify proper monitoring 

locations and to install the required 

monitoring stations around the facility 


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4The requirements in § 63.655(i)(5)(iii)(G) 

associated with this incorporation by reference have 

not changed, but are being modified to properly be 

incorporated into § 63.14(s). 

fenceline. However, owners or operators 

may need additional monitoring 

systems to account for near-field 

interfering sources (NFS), for which the 

development and approval of a sitespecific fenceline monitoring plan is 

required. We expect that the sitespecific fenceline monitoring plans can 

take an additional year to develop, 

submit and obtain approval. 

Consequently, we are providing 2 years 

from the effective date of the final rule 

for refinery owners or operators to 

install and begin collecting samples 

around the fenceline of their facility. 

As proposed, we are requiring that 

existing sources comply with the 

submerged filling requirement for 

marine vessel loading on the effective 

date of the final rule. 

As proposed, we are providing 18 

months after the effective date of the 

final rule to conduct required 

performance tests and comply with any 

revised operating limits for FCCU. 

We proposed to require refinery 

owners or operators to comply with the 

revisions to the SSM provisions of 

Refinery MACT 1 and 2 on the effective 

date of the final rule. As proposed, this 

final rule requires refinery owners or 

operators to comply with the limits in 

Refinery MACT 2 or the alternative 

limits in this final rule during startup 

and shutdown for FCCU and SRU on the 

effective date of the final rule. 

The flare work practice standards for 

high-load flaring events (events 

exceeding the smokeless capacity of the 

flare) require development of FMP (or 

revision of an existing plan) to 

specifically consider emergency 

shutdown and other high load events. In 

this FMP, refinery owners or operators 

must consider measures that can be 

implemented to reduce the frequency 

and magnitude of these high-load flaring 

events. This may include installation of 

a flare gas recovery system. 

Additionally, the work practice 

standards will require refinery owners 

or operators to identify and implement 

measures that may involve process 

changes. Therefore, we are establishing 

a compliance date of 3 years from the 

effective date of the final rule for 

refinery owners or operators to comply 

with the work practice standards for 

high load flaring events. We also note 

that this compliance period is consistent 

with the compliance time provided for 

the flare operating limits. 

For atmospheric PRD in HAP service 

we are establishing a work practice 

standard that requires a process hazard 

analysis and implementation of a 

minimum of three redundant measures 

to prevent atmospheric releases. 

Alternately, refinery owners or 

operators may elect to install closed 

vent systems to route these PRD to a 

flare, drain (for liquid thermal relief 

valves) or other control system. We 

anticipate that sources will need to 

identify the most appropriate preventive 

measures or control approach; design, 

install and test the system; install 

necessary process instrumentation and 

safety systems; and may need to time 

installations with equipment shutdown 

or maintenance outages. Therefore, we 

have established a compliance date of 3 

years from the effective date of the final 

rule for refinery owners or operators to 

comply with the work practice 

standards for atmospheric PRD. 

As proposed, we are requiring 

compliance with the electronic 

reporting provisions for performance 

tests conducted for Refinery MACT 1 

and 2 on the effective date of the final 

rule. 

Finally, we are finalizing additional 

requirements for storage vessels under 

CAA sections 112(d)(6) and (f)(2) with a 

compliance date 90 days after the 

effective date of the final rule, as 

proposed. 

H. What materials are being 

incorporated by reference? 

In this final rule, the EPA is including 

regulatory text that includes 

incorporation by reference. In 

accordance with requirements of 1 CFR 

51.5, the EPA is incorporating by 

reference the following documents 

described in the amendments to 40 CFR 

63.14: 

• ASTM D1945–03 (Reapproved 

2010), Standard Test Method for 

Analysis of Natural Gas by Gas 

Chromatography, (Approved January 1, 

2010). 

• ASTM D1945–14, Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography. 

• ASTM D6196–03 (Reapproved 

2009), Standard Practice for Selection of 

Sorbents, Sampling, and Thermal 

Desorption Analysis Procedures for 

Volatile Organic Compounds in Air, 

(Approved March 1, 2009). 

• ASTM D6348–03 (Reapproved 

2010), Standard Test Method for 

Determination of Gaseous Compounds 

by Extractive Direct Interface Fourier 

Transform Infrared (FTIR) Spectroscopy, 

including Annexes A1 through A8, 

(Approved October 1, 2010). 

• ASTM D6348–12e1, Standard Test 

Method for Determination of Gaseous 

Compounds by Extractive Direct 

Interface Fourier Transform Infrared 

(FTIR) Spectroscopy. 

• ASTM D6420–99 (Reapproved 

2010), Standard Test Method for 

Determination of Gaseous Organic 

Compounds by Direct Interface Gas 

Chromatography-Mass Spectrometry. 

• ASTM UOP539–12, Refinery Gas 

Analysis by GC. 

• BS EN 14662–4:2005, Ambient air 

quality—Standard method for the 

measurement of benzene 

concentrations—Part 4: Diffusive 

sampling followed by thermal 

desorption and gas chromatography, 

June 27, 2005. 

• EPA–454/B–08–002, Quality 

Assurance Handbook for Air Pollution 

Measurement Systems, Volume IV: 

Meteorological Measurements, Version 

2.0 (Final), March 2008. 

• EPA–454/R–99–005, Meteorological 

Monitoring Guidance for Regulatory 

Modeling Applications, February 2000. 

• ISO 16017–2:2003(E): Indoor, 

ambient and workplace air—Sampling 

and analysis of volatile organic 

compounds by sorbent tube/thermal 

desorption/capillary gas 

chromatography—Part 2: Diffusive 

sampling, May 15, 2003. 

• 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, 2003.4

The EPA has made, and will continue 

to make, these documents available 

electronically through 

www.regulations.gov and/or in hard 

copy at the appropriate EPA office (see 

the ADDRESSES section of this preamble 

for more information). 

IV. What is the rationale for our final 

decisions and amendments to the 

Petroleum Refinery NESHAP and 

NSPS? 

A. Residual Risk Review for the 

Petroleum Refinery Source Categories 

1. What did we propose pursuant to 

CAA section 112(f) for the Petroleum 

Refinery source categories? 

The results of our residual risk review 

for the Petroleum Refinery source 

categories were published in the June 

30, 2014 proposal at (79 FR 36934 

through 36942), and included 

assessment of chronic and acute 

inhalation risk, as well as multipathway 

and environmental risk, to inform our 

decisions regarding acceptability and 

ample margin of safety. The results 

indicated that both the actual and 


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allowable inhalation cancer risks to the 

individual most exposed are no greater 

than approximately 100-in-1 million, 

which is the presumptive limit of 

acceptability. In addition, the maximum 

chronic non-cancer target organ-specific 

hazard index (TOSHI) due to inhalation 

exposures was less than 1. The 

evaluation of acute non-cancer risks, 

which was conservative, showed acute 

risks below a level of concern. Based on 

the results of the refined site-specific 

multipathway analysis, we also 

concluded that the ingestion cancer risk 

to the individual most exposed through 

ingestion is considerably less than 100- 

in-1 million. In determining risk 

acceptability, we also evaluated 

population impacts because of the large 

number of people living near facilities 

in the source category. We estimated 

that 5-million people are exposed to 

increased cancer risks of greater than 1- 

in-1 million and 100,000 people are 

exposed to increased cancer risks of 

greater than 10-in-1 million, but, as 

noted previously, no individual is 

exposed to increased cancer risks of 

greater than 100-in-1 million. 

Considering the above information, we 

proposed that the risks remaining after 

implementation of the existing NESHAP 

for the Refinery MACT 1 and 2 source 

categories is acceptable. However, we 

noted that the risks based on allowable 

emissions are at the presumptive limit 

of acceptable risk, and that a large 

number of people are exposed to risks 

of greater than 1-in-1 million, and we 

solicited comment on whether EPA 

should conclude that the risk was 

unacceptable based on the health 

information before the Agency. We also 

proposed that the original Refinery 

MACT 1 and 2 MACT standards, along 

with the proposed requirements for 

storage vessels, provide an ample 

margin of safety to protect public health. 

Finally, we proposed that it is not 

necessary to set a more stringent 

standard to prevent, taking into 

consideration costs, energy, safety, and 

other relevant factors, an adverse 

environmental effect. 

2. How did the risk review change for 

the Petroleum Refinery source 

categories? 

As part of the final risk assessment, 

we conducted a screening level analysis 

of how the information we received 

during the public comment period, 

along with the changes we are making 

to the proposed rule, would change our 

proposed risk estimates (More details 

can be found in the ‘‘Final Residual Risk 

Assessment for the Petroleum Refining 

Source Sector’’, Docket ID No. EPA– 

HQ–OAR–2010–0682). 

First, we received approximately 20 

emissions inventory updates for specific 

facilities. These updates included 

revised emission estimates, revised 

release latitude/longitude locations and 

other release characteristic revisions. 

The updates provided evidence that the 

quantity of HAP emitted at these 

specific facilities is lower than 

considered in the risk modeling for the 

proposed rule. Our assessment of the 

effects of these changes suggests that the 

cancer maximum individual risk (MIR) 

based on actual emissions may be closer 

to 40-in-1 million, as opposed to 60-in1 million, as projected at proposal. We 

did not quantify the reductions in 

chronic or acute non-cancer risks from 

these updates. We calculated allowable 

emissions using the Refinery Emissions 

Model (REM), which estimates 

emissions based on each refinery’s 

capacities and throughputs [See 

discussion at 79 FR 36888, June 30, 

2014.] The allowable emission estimates 

for point and fugitive sources were not 

specific to a particular latitude/

longitude location so we assumed them 

to release from the centroid of the 

facility. Therefore, the predicted cancer 

MIR of approximately 100-in-1 million 

based on allowable emissions and 

reported in the proposal risk 

characterization does not change based 

on the submitted emissions revisions. 

We did not quantify changes to other 

actual risk metrics as part of the 

screening level analysis (i.e., incidence, 

populations in risk bins, multipathway 

and ecological analyses), but we would 

expect some minor reductions from 

those presented in the proposed risk 

characterization. 

Second, we are establishing work 

practice standards in the final rule for 

PRD releases and emergency flaring 

events, which under the proposed rule 

would not have been allowed. Thus, 

because we did not consider such nonroutine emissions under our risk 

evaluation for the proposed rule, we 

performed a screening assessment of 

risk associated with these non-routine 

events for the final rule. [We provide 

further details on the screening 

approach in ‘‘Final Residual Risk 

Assessment for the Petroleum Refining 

Source Sector’’ in Docket ID No. EPA– 

HQ–OAR–2010–0682.] We extracted 

information on these events from the 

2011 Petroleum Refinery ICR data that 

included the process unit identification, 

mass of emissions, duration of release, 

and description of the incident. We 

identified the highest HAP mass 

releases for both PRDs and flares from 

these non-routine events. We assumed 

these HAP emission releases could 

occur at any facility in the source 

category. Our analysis suggests that 

these HAP emissions could increase the 

MIR based on actual emissions by as 

much as 2-in-1 million. Because the 

PRD and flaring events were the worst 

case HAP mass emission release events 

reported in the 2011 Refinery ICR for 

the source category, we are assuming 

that actual and allowable risks are no 

different for these events (i.e., a MIR of 

2-in-1 million). A MIR increase of 2-in1 million attributable to these events, 

added to our previous estimate for 

allowable risk at proposal will not 

appreciably change our proposed 

determination that the MIR based on 

allowable emissions are approximately 

100-in-1 million. We note that the MIR 

estimate attributable to these nonroutine PRD and flaring events was 

estimated using a conservative, 

screening-level assessment, while the 

MIR estimate at proposal was based on 

a refined risk assessment. By adding a 

screening estimate to a refined risk 

estimate, we are merely defining an 

upper limit that we expect the 

combined risks from both the routine 

and non-routine emissions to be. 

Similarly, we estimate chronic noncancer hazard index (HI) values 

attributable to the additional exposures 

resulting from non-routine flaring and 

PRD HAP emissions to be well below 1 

(HIimmune-system of 0.007) such that there 

is no appreciable change in the 

maximum chronic non-cancer HI of 0.9 

estimated at proposal for routine 

emissions, which was based on 

neurological effects. 

The screening analysis projects that 

the maximum predicted acute noncancer risk from non-routine PRD and 

flare emissions results in a hazard 

quotient (HQ) based on a recommended 

reference exposure level limit (REL) of 

up to 14 from benzene emissions. While 

the analysis shows that there is a 

potential for HQs exceeding 1 for 

benzene, because of the many 

uncertainties and conservative nature of 

this screening analysis, the likelihood of 

such exposure and risk are low. At 

proposal, we projected a HQ based on 

the REL for benzene of up to 2 from 

routine emissions. If we conservatively 

combine the routine and non-routine 

emissions analyses, we would expect 

the potential for HQs based on the REL 

for benzene to have the potential to 

increase above 2. However, as projected 

at proposal, we estimate that the acute 

HQs calculated using acute exposure 

guideline levels (AEGL) and emergency 

response and planning guidelines 

(ERPG) values for all pollutants 

including benzene would still be well 


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5 Integrated Risk Information System (IRIS). IRIS 

Guidance documents available at http://www.epa.

gov/iris/backgrd.html. 

6http://yosemite.epa.gov/sab/sabproduct.nsf/0/

b031ddf79cffded38525734f00649caf!Open

Document&TableRow=2.3#2. 

below 1 considering both routine and 

non-routine emissions. 

Considering all of these factors, we do 

not project risks to be significantly 

different from what we proposed. Based 

on the risk analysis, as informed by the 

screening level analysis based on 

information obtained during the 

comment period, we are finalizing our 

determination that the risk remaining 

after promulgation of the NESHAP is 

acceptable. 

3. What key comments did we receive 

on the risk review and what are our 

responses? 

We received numerous comments on 

the residual risk assessment analyses 

and results. We summarize the key 

comments received below, along with 

our responses. A complete summary of 

all public comments received and our 

responses are in the ‘‘Response to 

Comment’’ Document in the public 

docket (Docket ID No. EPA–HQ–OAR– 

2010–0682). 

Comment: Several commenters agreed 

that the EPA has correctly concluded 

that the proposed rule requirements 

protect the public with an ample margin 

of safety from refinery emissions. Other 

commenters noted that EPA found 

residual risks remaining after 

implementation of the MACT standards 

to be acceptable, and in light of the 

acceptability determination argued that 

the proposed changes to the rule are not 

justified. The commenters noted that the 

EPA’s detailed emissions inventory 

assessment and risk modeling results 

demonstrated that, at every U.S. 

refinery, category-specific risks are 

below the EPA’s presumptive limit of 

acceptable risk (i.e., cancer risk of less 

than 100-in-1 million). 

Other commenters stated the EPA’s 

risk estimates are understated and that 

the EPA should reduce the benchmark 

of what it considers acceptable lifetime 

cancer risk instead of the upper limit of 

100-in-1 million. One commenter 

provided an extensive critique of the 

cancer, chronic and acute affects levels 

used in the risk assessment and 

recommended that the EPA use 

California Office of Environmental 

Health Hazard Assessment’s (OEHHA) 

new toxicity values for several 

chemicals. The commenter provided 

some references for the approaches used 

to derive the California values. The 

commenter also asserted that risks 

would be unacceptable had these more 

protective values been used in the risk 

assessment. Some commenters stated 

the risks from petroleum refinery 

emissions are underestimated because 

the EPA did not but should have 

included interaction of multiple 

pollutants, accounted for exposure to 

multiple sources, and assessed the 

cumulative risks from facility-wide 

emissions and multiple nearby sources 

impacting an area. 

Response: The approximately 100-in1 million benchmark was established in 

the Benzene NESHAP (54 FR 38044, 

September 14, 1989), which Congress 

specifically referenced in CAA section 

112(f)(2)(B). While this presumptive 

level provides a benchmark for judging 

the acceptability of MIR, it is important 

to recognize that it does not constitute 

a rigid line for making that 

determination. The EPA considers the 

specific uncertainties of the emissions, 

health effects and risk information for 

the source category in question when 

deciding whether the risk posed by that 

source category is acceptable. In 

addition, the source category-specific 

decision of what constitutes an 

acceptable level of risk is a holistic one; 

that is, the EPA considers all potential 

health impacts—chronic and acute, 

cancer and non-cancer, and 

multipathway—along with their 

uncertainties, when determining 

whether the source category presents an 

unacceptable risk. 

Regarding the comment that in light 

of the acceptability determination the 

proposed changes to the rule are not 

justified, we note that we also are 

required to ensure that the standards 

provide an ample margin of safety to 

protect public health. That analysis is 

separate from the acceptability analysis, 

and the determination of acceptability 

does not automatically lead us to 

conclude that the standards provide an 

ample margin of safety to protect public 

health. 

Regarding the comments that the EPA 

should use the new California OEHHA 

values, we disagree. The EPA’s 

chemical-specific toxicity values are 

derived using risk assessment 

guidelines and approaches that are well 

established and vetted through the 

scientific community, and follow 

rigorous peer review processes.5 The 

RTR program gives preference to the 

EPA values for use in risk assessments 

and uses other values, as appropriate, 

when those values are derived with 

methods and peer review processes 

consistent with those followed by the 

EPA. The approach for selecting 

appropriate toxicity values for use in the 

RTR Program has been endorsed by the 

Science Advisory Board (SAB).6

The EPA scientists reviewed the 

information provided by the commenter 

regarding the California values and 

concluded that further information is 

needed to evaluate the scientific basis 

and rationale for the recent changes in 

California OEHHA risk assessment 

methods. The EPA will work on 

gathering the necessary information to 

conduct an evaluation of the scientific 

merit and the appropriateness of the use 

of California OEHHA’s new toxicity 

values in the agency decisions. Until the 

EPA has completed its evaluation, it is 

premature to determine what role these 

values might play in the RTR process. 

Therefore, the EPA did not use the new 

California OEHHA toxicity values as 

part of this current action. For more 

detailed responses regarding 

appropriate reference values for specific 

pollutants, see the ‘‘Response to 

Comment’’ document in the public 

docket (Docket ID No. EPA–HQ–OAR– 

2010–0682). 

Concerning comments that we should 

consider aggregate risks from multiple 

pollutants and sources, we note that we 

have done this to the extent it is 

appropriate to do so. We modeled 

whole-facility risks for both chronic 

cancer and non-cancer impacts to 

understand the risk contribution of the 

sources within the Petroleum Refinery 

source categories. The individual cancer 

risks for the source categories were 

aggregated for all carcinogens. In 

assessing non-cancer hazard from 

chronic exposures to pollutants that 

have similar modes of action or (where 

this information is absent) that affect the 

same target organ, we summed the HQs. 

This process creates, for each target 

organ, a TOSHI, defined as the sum of 

HQs for individual HAP that affect the 

same organ or organ system. Wholefacility risks were estimated based on 

the 2011 ICR emissions data obtained 

from facilities, which included 

emissions from all sources at the 

refinery, not just Refinery MACT 1 and 

2 emission sources (e.g., emissions were 

included for combustion units and units 

subject to the Hazardous Organic 

NESHAP, if present at the refinery). We 

disagree with the commenter’s assertion 

that additional quantitative assessment 

of risks from sources outside the source 

category is required under the statute. 

The statute requires the EPA to provide 

the quantitative risk information 

necessary to inform RTR regulatory 

decisions, and to this end, the EPA 

conducted a comprehensive assessment 

of the risks associated with exposure to 

the HAP emitted by the source category 

and supplemented that with additional 


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information available about other 

possible concurrent and relevant risks. 

Further, the risk assessment modeling 

accounts for the effects of multiple 

facilities that may be in close proximity 

when estimating concentration and risk 

impacts at each block centroid. When 

evaluating the risks associated with a 

particular source category, we combined 

the impacts of all facilities within the 

same source category and assessed 

chronic exposure and risk for all census 

blocks with at least one resident (i.e., 

locations where people may reasonably 

be assumed to reside). The MIR 

considers the combined impacts of all 

sources in the category that may be in 

close proximity (i.e., cumulative impact 

of all refineries). 

Comment: Several commenters stated 

that the EPA underestimated exposure 

because emissions are underreported 

and underestimated. The commenters 

noted that for the risk assessment for the 

refineries rule, the EPA evaluated (1) the 

emissions reported to the agency 

pursuant to the 2011 Petroleum Refinery 

ICR as sources’ ‘‘actual’’ emissions, and 

(2) the emissions the EPA estimates that 

the existing standards currently allow 

sources to emit using the REM, which 

it describes as ‘‘allowable’’ emissions. 

According to the commenters, both the 

EPA’s ‘‘actual’’ and ‘‘allowable’’ 

emissions data sets are incomplete and 

undercount emissions, causing the EPA 

to significantly underestimate the 

resulting risk in its risk analysis. For 

example, the commenters noted that the 

EPA assumed the flare destruction 

efficiency to be 98 percent, while the 

EPA’s own estimates suggest flare 

efficiency is 93.9 percent. The 

commenters also noted that the EPA has 

further understated risks by ignoring 

emissions during unplanned SSM 

events and by ignoring HAP for which 

no reference values are established. One 

commenter cited the TCEQ Emissions 

Event Database as evidence that SSM 

emissions are a severe public health 

problem because data show that nearly 

1 million pounds of HAP are reported 

from Texas refineries between 2009 and 

2013. According to these commenters, 

the EPA needs to adopt standards that 

provide greater protection, including 

protection from the risks of accidents. 

Response: We used the best and most 

robust facility-specific HAP emissions 

inventory available to us, which was the 

2011 ICR, in performing the analysis for 

the proposed rule. We conducted a 

thorough and exhaustive review of the 

data submitted through the ICR and we 

followed up on source-specific 

information on a facility-by-facility 

basis, as documented in the ‘‘Emissions 

Data Quality Memorandum and 

Development of the Risk Model Input 

File’’ (see Docket ID No. EPA–HQ– 

OAR–2010–0682–0076). In addition, we 

took steps ahead of issuing the 2011 ICR 

to make sure that facilities could, as 

accurately as practicable, estimate their 

HAP emissions for purposes of 

responding to the inventory portion of 

that ICR. We prepared a Refinery 

Protocol to provide guidance to refinery 

owners or operators to use the best 

available, site-specific data when 

developing their emissions inventory, to 

ensure all emission sources are included 

in the inventory, and to have a 

consistent set of emission factors that all 

respondents use if no site-specific 

emissions data were available. If sitespecific emissions data were available, 

sites were to use these data 

preferentially over the default factors. 

We developed the default factors 

provided in the protocol from the best 

data available at the time. 

The ICR-submitted information for 

allowable emissions did not include 

emission estimates for all HAP and all 

emission sources. Consequently, we 

used the REM to estimate allowable 

emissions. The REM relies on model 

plants that vary based on throughput 

capacity. Each model plant contains 

process-specific default emission 

factors, adjusted for compliance with 

the Refinery MACT 1 and 2 emission 

standards. 

We agree with the commenters that 

studies have shown that many refinery 

flares are operating less efficiently than 

98 percent. Prior to proposing this rule, 

we conducted a flare ad hoc peer review 

to advise the EPA on factors affecting 

flare performance (see discussion in the 

June 30, 2014, proposal at 79 FR 36905). 

However, we disagree with the 

commenters that the risk analysis 

should consider this level of 

performance since the existing MACT 

standard does not allow it. For purposes 

of the risk analysis, we evaluate whether 

it is necessary to tighten the existing 

MACT standard in order to provide an 

ample margin of safety. Thus, in 

reviewing whether the existing 

standards provide an ample margin of 

safety, we review the level of emissions 

the MACT standards allow. In the 

present case, we considered the level of 

performance assumed in establishing 

the MACT standard for purposes of 

determining whether the MACT 

standard provides an ample margin of 

safety. However, we did recognize that 

facilities were experiencing 

performance issues with flares and that 

many flares were not meeting the 

assumed performance level at the time 

we promulgated the MACT standard. 

Thus, we proposed, and are finalizing, 

revisions to the flare operating 

requirements to ensure that the flares 

meet the required performance level. 

These provisions are consistent with the 

EPA’s goals to improve the effectiveness 

of our rules. 

Similarly, we do not include startup, 

shutdown (including maintenance 

events) and malfunction emissions that 

are not allowed under the standard as 

part of our evaluation of whether the 

standards provide an ample margin of 

safety. Regarding the HAP emissions 

from SSM events that the commenter is 

concerned with, we note that our review 

of the TCEQ incident database indicates 

that many of the large reported release 

events were of SO2 emissions and only 

a few had significant HAP emissions. 

Because in the final rule we are 

establishing work practice standards for 

PRD and emergency flaring events, we 

performed a screening-level risk 

analysis to address changes in facility 

HAP emission releases due to these 

events. Details on this analysis are 

presented in the final risk report for the 

source category (For more details see 

Appendix 13 of the ‘‘Final Residual Risk 

Assessment for the Petroleum Refining 

Source Sector,’’ Docket ID No. EPA– 

HQ–OAR–2010–0682). 

As for HAP with no reference value, 

the SAB addressed this issue in its May 

7, 2010, response to the EPA 

Administrator. In that response, the 

SAB Panel recommended that, for HAP 

that do not have dose-response values 

from the EPA’s list, the EPA should 

consider and use, as appropriate, 

additional sources for such values that 

have undergone adequate and rigorous 

scientific peer review. The SAB panel 

further recommended that the inclusion 

of additional sources of dose-response 

values into the EPA’s list should be 

adequately documented in a transparent 

manner in any residual risk assessment 

case study. We agree with this approach 

and have considered other sources of 

dose-response data when conducting 

our risk determinations under RTR. 

However, in some instances no sources 

of information beyond the EPA’s list are 

available. Compounds without health 

benchmarks are typically those without 

significant health effects compared to 

compounds with health benchmarks, 

and in such cases we assume these 

compounds will have a negligible 

contribution to the overall health risks 

from the source category. A tabular 

summary of HAPs that have dose 

response values for which an exposure 

assessment was conducted is presented 

in Table 3.1–1 of the ‘‘Final Residual 

Risk Assessment for the Petroleum 

Refining Source Sector’’, Docket ID No. 

EPA–HQ–OAR–2010–0682. 


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Comment: A few commenters asserted 

that the EPA should decide that it is 

unjust and inconsistent with the CAA’s 

health protection purpose to allow the 

high health risks caused by refineries to 

fall disproportionately on communities 

of color and lower income communities 

who are least equipped to deal with the 

resulting health effects. Because of that 

disparity, the commenter stated that the 

EPA should recognize that the risks 

found are unacceptable and set stronger 

national standards for all exposed 

Americans. 

Response: For this rulemaking, the 

EPA conducted both pre- and postcontrol risk-based assessments with 

analysis of various socio-economic 

factors for populations living near 

petroleum refineries (see Docket ID Nos. 

EPA–HQ–OAR–2010–0682–0226 and 

–0227) and determined that there are 

more African-Americans, Other and 

multiracial groups, Hispanics, lowincome individuals, and individuals 

with less than a high school diploma 

compared to national averages. In 

determining the need for tighter residual 

risk standards, the EPA strives to limit 

to no higher than 100-in-1 million the 

estimated cancer risk for persons living 

near a plant if exposed to the maximum 

pollutant concentration for 70 years and 

to protect the greatest number of 

persons to an individual lifetime risk of 

no higher than 1-in-1 million. Although 

we consider the risk for all people 

regardless of racial or socioeconomic 

status, communities near petroleum 

refineries will particularly benefit from 

the risk reductions associated with this 

rule. In particular, as discussed later, 

the fenceline monitoring work practice 

standard will be a further improvement 

in the way fugitive emissions are 

managed and will provide an extra 

measure of protection for surrounding 

communities. 

4. What is the rationale for our final 

decisions for the risk review? 

As described in section IV.A.2 of this 

preamble, we performed a screeninglevel analysis to assess the risks 

associated with inventory updates we 

received for specific facilities and with 

emissions events that were previously 

not included in the risk assessment 

because the proposed rule did not allow 

them. Because we are finalizing work 

practice standards to regulate emission 

events associated with PRD releases and 

emergency flaring, we considered the 

effect these work practice standards 

would have on risks. As discussed in 

section IV.A.2 of this preamble, we 

project that accounting for these 

emergency events in the baseline risks 

after implementation of the MACT 

standards does not appreciably change 

the risks, and at most, could increase 

the proposed rule estimate of MIR by 

approximately 2-in-1 million. Therefore, 

we would project that any controls 

applied to these emergency events, 

including the work practice standards 

for PRDs and emergency flaring in this 

final rule, would not appreciably change 

the proposed post-control risks. 

Although we would anticipate minimal 

additional risk reductions, we reviewed 

more stringent alternatives to the work 

practice standards for PRD releases and 

emergency flaring events included in 

this final rule, and we found that the 

costs of increasing flare capacity to 

control all PRD releases and to eliminate 

all visible emissions during emergency 

flaring were too high. We estimate the 

capital costs of applying the velocity 

and visible emissions limit at all times 

would be approximately $3 billion, and 

we estimate that the costs of controlling 

all PRD releases with flares would be 

approximately $300 million. [See the 

discussion in the ‘‘Flare Control Option 

Impacts for Final Refinery Sector Rule’’, 

Docket ID No. EPA–HQ–OAR–2010– 

0682 and the PRD work practice 

standard discussion in section IV.C of 

this preamble.] Further, we did not 

receive comments on additional control 

technologies that we should have 

considered for other emission sources 

(e.g., tanks, DCUs) beyond those 

considered and described at proposal. 

Consequently, as discussed in section 

IV.A.2, we conclude that the risks from 

the Petroleum Refinery source 

categories are acceptable and that, with 

the additional requirements for storage 

vessels that we are finalizing, as 

proposed, the Refinery MACT 1 and 2 

rules provide an ample margin of safety 

to protect public health. We also 

maintain, based on the rationale 

presented in the preamble to the 

proposed rule, that the current 

standards prevent, taking into 

consideration costs, energy, safety and 

other relevant factors, an adverse 

environmental effect. 

B. Technology Review for the Petroleum 

Refinery Source Categories 

1. What did we propose pursuant to 

CAA section 112(d)(6) for the Refinery 

MACT 1 (40 CFR part 63, subpart CC) 

source category? 

The results of our technology review 

for the Petroleum Refinery source 

categories were published in the June 

30, 2014, proposal at (79 FR 36913 

through 36928). The technology review 

was conducted for both MACT source 

categories as described below. 

a. Refinery MACT 1 

Refinery MACT 1 sources include 

MPV, storage vessels, equipment leaks, 

gasoline loading racks, marine vessel 

loading operations, cooling towers/heat 

exchange systems and wastewater. 

Based on technology reviews for the 

sources described above, we proposed 

that it was not necessary to revise 

Refinery MACT 1 requirements for 

MPV, gasoline loading racks, cooling 

towers/heat exchange systems, and 

wastewater. For storage vessels, we 

proposed revisions pursuant to the 

technology review. Specifically, we 

proposed to cross-reference the storage 

vessel requirements in the Generic 

MACT (40 CFR part 63, subpart WW) to 

require controls on floating roof fittings 

(e.g., guidepoles, ladder wells and 

access hatches) and to revise the 

definition of Group 1 storage vessels to 

include smaller tanks with lower vapor 

pressures. For equipment leaks, we 

proposed to allow refineries to meet 

LDAR requirements in Refinery MACT 

1 by monitoring for leaks via optical gas 

imaging in place of the EPA Method 21, 

using monitoring requirements to be 

specified in a not-yet-proposed 

appendix K to 40 CFR part 60. For 

marine vessel loading, we proposed to 

amend the Marine Tank Vessel Loading 

Operations MACT standards (40 CFR 

part 63, subpart Y) to require small 

marine vessel loading operations (i.e., 

operations with HAP emissions less 

than 10/25 tpy) and offshore marine 

vessel loading operations at petroleum 

refineries to use submerged filling based 

on the cargo filling line requirements in 

46 CFR 153.282. 

We also proposed an additional work 

practice standard under the technology 

review to manage fugitive emissions 

from the entire petroleum refinery 

through a fenceline monitoring and 

corrective action standard. As part of 

the work practice standard, we specified 

the monitoring technology and 

approach that must be used, and we 

developed a fenceline benzene 

concentration action level above which 

refinery owners or operators would be 

required to implement corrective action 

to reduce their fenceline concentration 

to below this action level. The action 

level we proposed was consistent with 

the emissions projected from fugitive 

sources compliant with the provisions 

of the refinery MACT standards as 

modified by the additional controls 

proposed for storage vessels. 

b. Refinery MACT 2 

The Refinery MACT 2 source category 

regulates HAP emissions from FCCU, 

CRU and SRU process vents. We 


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proposed to revise Refinery MACT 2 to 

incorporate the developments in 

monitoring practices and control 

technologies reflected in Refinery NSPS 

subpart Ja (73 FR 35838). This included 

proposing to incorporate the Refinery 

NSPS subpart Ja PM limit for new FCCU 

sources and to revise the monitoring 

provisions in Refinery MACT 2 to 

require all FCCU sources to meet 

operating limits consistent with the 

requirements in Refinery NSPS subpart 

Ja. The existing MACT standard 

provided that a refiner could 

demonstrate compliance with the PM 

limit in the MACT by meeting the 30- 

percent opacity limit requirement of 

Refinery NSPS subpart J; we proposed 

to eliminate that provision and instead 

establish control device operating limits 

or site-specific opacity limits similar to 

those required in Refinery NSPS subpart 

Ja. We also proposed to incorporate the 

use of 3-hour averages rather than daily 

averages for monitoring data to 

demonstrate compliance with the FCCU 

site-specific opacity and Ni operating 

limits. We proposed additional control 

device-specific monitoring alternatives 

for various control devices on FCCU, 

including BLD monitoring as an option 

to COMs for owners or operators of 

FCCU using fabric filter-type control 

systems, and total power and secondary 

current operating limits for owners or 

operators of ESPs. We also proposed to 

add a requirement to perform daily 

checks of the air or water pressure to 

atomizing spray nozzles for owners or 

operators of FCC wet gas scrubbers. 

Finally, we proposed to require a 

performance test once every 5 years for 

all FCCU in place of the one-time 

performance test required by the current 

Refinery MACT 2. 

At proposal, we did not identify any 

developments in practices, processes 

and control technologies for CRU 

process vents based on our technology 

review. For SRU, we proposed to 

include the Refinery NSPS subpart Ja 

allowance for oxygen-enriched air as a 

development in practice and to allow 

SRU to comply with Refinery NSPS 

subpart Ja as a means of complying with 

Refinery MACT 2. 

2. How did the technology review 

change for the Petroleum Refinery 

source categories? 

a. Refinery MACT 1 

We are finalizing most of our 

technology review decisions for 

Refinery MACT 1 emissions sources as 

proposed; however, as described briefly 

below, we are revising certain proposed 

requirements. 

We are not taking final action 

adopting the use of appendix K to 40 

CFR part 60 for optical gas imaging for 

refinery equipment subject to the LDAR 

requirements in Refinery MACT 1 

because we have not yet proposed 

appendix K. 

After considering the public 

comments, we are finalizing the 

proposed fenceline monitoring 

requirements, with a few revisions. 

First, we have made numerous 

clarifications in this final rule to the 

language for the fenceline monitoring 

siting method and analytical method 

(i.e., Methods 325 A and B, 

respectively). Specific comments on 

these methods, along with our responses 

and explanations of the revisions to the 

regulatory text are discussed in the 

‘‘Response to Comment’’ document. 

Second, we are finalizing a revised 

compliance schedule for fenceline 

monitoring, which will require refinery 

owners or operators to have the 

fenceline monitors in place and 

collecting benzene concentration data 

no later than 2 years from the effective 

date of the final rule, as opposed to 3 

years in the proposed rule. Third, we 

have removed the requirement for 

refinery owners or operators to obtain 

the EPA approval for the corrective 

action plan. Fourth, we are requiring the 

submittal of the fenceline monitoring 

data on a quarterly basis, as opposed to 

on a semiannual basis as proposed. 

Fifth, we are providing guidelines for 

operators to use in requesting use of an 

alternative fenceline monitoring 

technology to the passive sorbent 

samplers set forth in Method 325B. 

Finally, to reduce the burden of 

monitoring, we are finalizing provisions 

that would allow refinery owners or 

operators to reduce the frequency of 

fenceline monitoring for areas that 

consistently stay well below the 

fenceline benzene concentration action 

level. Specifically, we are allowing 

refinery owners or operators to monitor 

every other two weeks (i.e., skip period 

monitoring) if over a two-year period, 

each sample collected at a specific 

monitoring location is at or below 0.9 

mg/m3. If every sample collected from 

that sampling location during the 

subsequent 2-years is at or below 0.9 mg/ 

m3, the monitoring frequency may be 

reduced from every other two weeks to 

quarterly. After an additional two years, 

the monitoring can be reduced to 

semiannually and finally to annually, 

provided the samples continue to be at 

or below 0.9 mg/m3 during all sampling 

events at that location. If at any time a 

sample for a monitoring location that is 

monitored at a reduced frequency 

returns a concentration greater than 0.9 

mg/m3, the owner or operator must 

return to the original sampling 

requirements for one quarter (monitor 

every two weeks for the next six 

monitoring periods for that location); if 

every sample collected from this quarter 

is at or below 0.9 ug/m3, then the 

sampling frequency reverts back to the 

reduced monitoring frequency for that 

monitoring location; if not then the 

sampling frequency reverts back to the 

original biweekly monitoring frequency. 

b. Refinery MACT 2 

We are finalizing, as proposed, our 

determination that it is not necessary to 

revise the requirements for CRU 

pursuant to the technology review and 

we are finalizing our determination that 

it is necessary to revise the MACT for 

SRU and FCCU. For SRU, we are 

finalizing the revisions as proposed. For 

FCCU, we are making modifications to 

the proposed requirements in light of 

public comment. 

As discussed previously, we proposed 

to remove the alternative in Refinery 

MACT 2 for owners or operators to 

demonstrate compliance with the PM 

limits on FCCU by meeting a 30-percent 

opacity standard as provided in 

Refinery NSPS subpart J and instead 

make the FCCU operating limits in 

Refinery MACT 2 consistent with 

Refinery NSPS subpart Ja. Based on the 

Refinery NSPS subpart J review in 2008, 

we determined that a 30-percent opacity 

limit does not adequately assure 

compliance with the PM emissions limit 

(see discussion in the proposed rule at 

79 FR 36929, June 30, 2014). Thus, we 

included other monitoring approaches 

in Refinery NSPS subpart Ja. 

Comments received on this proposal, 

along with data available to the Agency, 

confirmed that the 30-percent opacity 

standard is not adequate on its own to 

demonstrate compliance with the PM 

(or metal HAP) emissions limit in 

Refinery MACT 2. We also received 

comments that the site-specific opacity 

alternative, which is the only 

compliance option proposed for FCCU 

with tertiary cyclones, would essentially 

require owners or operators with these 

FCCU configurations to meet an opacity 

limit of 10-percent. According to 

commenters, opacity increases with 

decreasing particle size, so that it is 

common to exceed 10-percent opacity 

during soot blowing or other similar 

events that produce very fine 

particulates even though mass 

emissions have not changed 

appreciably. 

Based on the available data, we have 

determined that a 20-percent opacity 

operating limit is well correlated with 


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facilities meeting a limit of 1.0 lb PM/ 

1,000 lbs coke burn-off. Therefore, we 

are retaining the option in Refinery 

MACT 2 to comply with Refinery NSPS 

subpart J except we are adding a 20- 

percent opacity operating limit in 

Refinery MACT 2, evaluated on a 3-hour 

basis. To ensure that FCCU owners or 

operators complying with the Refinery 

NSPS subpart J option can meet the 1.0 

lb PM/1,000 lbs emissions limit at all 

times, we are finalizing requirements 

that owners or operators conduct the 

performance test during higher PM 

periods, such as soot blowing. Where 

the PM emissions are within 80-percent 

of the PM limit during any periodic 

performance test, we are requiring the 

refinery owner or operator to conduct 

subsequent performance tests on an 

annual basis instead of on a 5-year basis. 

We are finalizing our proposed 

requirement that compliance with the 

control device operating limits in the 

other compliance alternatives be 

demonstrated on a 3-hour basis, instead 

of the 24-hour basis currently allowed 

in Refinery MACT 2. 

3. What key comments did we receive 

on the technology review, and what are 

our responses? 

a. Refinery MACT 1 

The majority of comments received 

regarding the proposed amendments to 

Refinery MACT 1 pursuant to our 

technology review dealt with the 

proposed fenceline monitoring 

requirements. The primary comments 

on the fenceline monitoring 

requirements are in this section along 

with our responses. Comment 

summaries and the EPA’s responses for 

additional issues raised regarding the 

proposed requirements resulting from 

our technology review are in the 

‘‘Response to Comment’’ document in 

the public docket (Docket ID No. EPA– 

HQ–OAR–2010–0682). 

i. Legal Authority and Need for 

Fenceline Monitoring 

Comment: Numerous commenters 

claimed that the proposed fenceline 

monitoring program would unlawfully 

impose what is effectively an ambient 

air quality standard for benzene, which 

is not authorized by CAA section 112, 

which only authorizes the control of 

emission sources. The commenters 

argued it is an ambient standard because 

sources are required to meet the 

benzene level set or ‘‘perform injunctive 

relief which may or may not address the 

source of the benzene.’’ The commenter 

quoted language from the proposal as 

support that EPA has described the 

benzene level as an ambient standard: 

‘‘We are proposing a HAP concentration 

to be measured in the ambient air 

around a refinery, that if exceeded, 

would trigger corrective action to 

minimize fugitive emissions.’’ 79 FR at 

36920 (June 30, 2014). The commenter 

further noted that this requirement is 

not just ‘‘monitoring’’ because it 

establishes a ‘‘not-to-be exceeded’’ level. 

Therefore, the commenters stated, the 

EPA should not finalize this portion of 

the proposal. 

Response: We disagree with the 

comment that the fenceline proposal is 

an ambient air standard. First, the 

owner or operator must place the 

monitors on the facility fenceline to 

measure emissions from the facility, i.e., 

on the property of the refiner. While we 

recognize that we used the term 

‘‘ambient air’’ in the preamble to the 

proposal, we note that the placement 

requirements for the monitors make 

clear that the monitors are not 

monitoring ambient air, which EPA has 

defined at 40 CFR 50.1(e) as ‘‘that 

portion of the atmosphere, external to 

buildings, to which the general public 

has access.’’ Second, the proposed EPA 

Method 325A sets out procedures to 

subtract background concentrations and 

contributions to the fenceline benzene 

concentrations from non-refinery 

emission sources, so that the benzene 

concentrations measured are 

attributable to the refinery. In other 

words, the fenceline monitoring work 

practice standard uses a benzene 

concentration difference, referred to as 

the DC (essentially an upwind and 

downwind concentration difference) to 

isolate the refinery’s emissions 

contribution. 

Furthermore, we disagree that the fact 

that refiners are required to perform 

corrective action if the fenceline 

benzene concentration action level is 

exceeded makes the benzene action 

level an ambient standard. As an initial 

matter sources are not directly 

responsible for demonstrating that an 

area is meeting an ambient standard; 

rather that burden falls on states. See 

e.g., CAA section 110(a)(2). Moreover, 

the ‘‘corrective action’’ is simply that 

sources must ensure that fugitive 

emission sources on the property are not 

emitting HAP at levels that will result 

in exceedances of the fenceline benzene 

concentration action level. In other 

words, the purpose of the fenceline 

monitoring work practice is to ensure 

that sources are limiting HAP emissions 

at the fenceline, which are solely 

attributable to emissions from sources 

within the facility. In fact, the fenceline 

benzene concentration action level was 

established using emissions inventories 

reported by the facilities, assuming 

compliance with the MACT standards. 

Finally, monitoring is conducted as part 

of the work practice standard to identify 

sources that will require additional 

controls to reduce their impact on the 

fenceline benzene concentration. In that 

sense, the fenceline monitoring work 

practice standard is not different than, 

for example, our MACT standard for 

refinery heat exchangers. If a facility is 

exceeding the relevant cooling water 

pollutant concentration ‘‘level’’ when it 

performs a periodic test, it must 

undertake corrective action to bring the 

concentration down below the action 

level. 

Comment: Several commenters noted 

that EPA’s authority under section 

112(d) is to set ‘‘emissions standards’’ 

and quoted the CAA definition of that 

term: ‘‘A requirement . . . which limits 

the quantity, rate, or concentration of 

emissions of air pollutants on a 

continuous basis, including any 

requirement relating to the operation or 

maintenance of a source to assure 

continuous emission reduction, and any 

design, equipment, work practice or 

operational standard promulgated under 

this Act.’’ 42 U.S.C. 7602(k). The 

commenters argued that the proposed 

fenceline monitoring standard does not 

meet this definition because it would 

not ‘‘limit the quantity, rate, or 

concentration of emissions’’ from any 

given emissions point. Also, the 

commenters claimed that the EPA did 

not designate fenceline monitoring as a 

work practice under CAA section 112(h) 

since the EPA did not even mention 

CAA section 112(h), nor did it conduct 

any analysis to show that fenceline 

monitoring meets the CAA section 

112(h) factors. 

Response: We disagree with the 

commenters’ assertion that the proposed 

fenceline monitoring work practice 

standard is not authorized under CAA 

section 112(d)(6). Contrary to the 

commenter’s claims, we specifically 

proposed the fenceline monitoring 

standard under CAA section 112(d)(6) to 

be a work practice standard that is 

applied broadly to fugitive emissions 

sources located at petroleum refineries. 

As discussed above, the proposed 

standard does more than impose 

monitoring as some commenters 

suggested; it also will limit emissions 

from refineries because it requires the 

owner or operator to identify and reduce 

HAP emissions through a monitoring 

and repair program, as do many work 

practice standards authorized under 

CAA Section 112(h) and 112(d). 

We note that the sources addressed by 

the fenceline monitoring standard— 

refinery fugitive emissions sources such 

as wastewater collection and treatment 


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operations, equipment leaks, heat 

exchange systems and storage vessels in 

the Refinery MACT 1 rule—are already 

subject to work practice standards. Our 

review of these requirements indicates 

that this fenceline monitoring work 

practice standard would be a further 

improvement in the way fugitive 

emissions are managed and would 

provide an extra measure of protection 

for surrounding communities. The 

commenter claims EPA did not analyze 

how the fenceline monitoring 

requirement meets the criteria in section 

112(h). However, that is a 

misinterpretation of how the criteria 

apply. The criteria are assessed with 

regard to whether it is feasible to 

‘‘prescribe or enforce an emission 

standard for a source’’, and do not apply 

to the work practice standard. 

Consistent with the criteria in section 

112(h)(2), we determined and 

established that work practice standards 

are appropriate for these Refinery 

MACT fugitive emissions at the time we 

established the initial MACT standard. 

In the proposal, (79 FR at 36919, June 

30, 2014), we reaffirmed that it is 

impracticable to directly measure 

fugitive emission sources at refineries 

but did not consider it necessary to 

reiterate these findings as part of this 

proposal to revise the existing MACT for 

these sources under CAA section 

112(d)(6). We note that the commenters 

do not provide any grounds to support 

a reevaluation of whether these fugitive 

emission sources are appropriately 

regulated by a work practice standard. 

Comment: Several commenters 

questioned the EPA’s authority under 

the CAA to promulgate a rule that 

amounts to an ongoing information 

gathering and reporting obligation. The 

commenters stated that the EPA has not 

demonstrated that the proposed 

fenceline monitoring program 

represents an actual emission reduction 

technology improvement. A commenter 

stated that compliance assurance 

methods, including monitoring, for 

fugitive emissions and other emission 

standards are established as part of the 

emission standard and EPA’s authority 

to gather information that is not directly 

required for compliance with a specific 

standard but is related to air emissions 

is found in CAA section 114. Under 

CAA section 114, the requirement must 

be related to one of the stated purposes 

and must be reasonable. The commenter 

did not believe that the EPA has 

demonstrated that the costs of fenceline 

monitoring are reasonable in light of the 

information already available to the EPA 

and in light of many other means by 

which the EPA could obtain such 

information. 

Response: We disagree with the 

commenters’ assertion that the authority 

for the fenceline monitoring 

requirement falls under CAA section 

114 and not CAA section 112(d) because 

it is an ‘‘ongoing information gathering 

and reporting obligation.’’ The issue 

here is not whether EPA could have 

required the fenceline monitoring 

requirement under CAA section 114, but 

rather did EPA support that it was a 

development in processes practices or 

controls technology under section 

112(d)(6). 

As an initial matter, we disagree with 

the commenters’ characterization of the 

fenceline monitoring standard as ‘‘an 

information gathering and reporting 

obligation.’’ We have repeatedly stated 

that we consider the fenceline 

monitoring requirement to be a work 

practice standard that will ensure 

sources take corrective action if 

monitored benzene levels (as a surrogate 

for HAP emissions from fugitive 

emissions sources) exceed the fenceline 

benzene concentration action level. The 

standard requires refinery owners or 

operators to monitor the benzene 

concentration at the refinery perimeter, 

to evaluate the refinery’s contribution as 

estimated by taking the concentration 

difference between the highest and 

lowest concentrations (DC) in each 

period, and to conduct root cause 

analysis and take corrective action to 

minimize emissions if the concentration 

difference is higher (on an annual 

average) than the benzene concentration 

action level. Thus, the fenceline 

monitoring requirement goes well 

beyond ‘‘information gathering and 

reporting.’’ 

In addition, the commenters again 

read section 112(d)(6) too narrowly by 

suggesting that a program considered as 

a development must be a ‘‘technology’’ 

improvement. Section 112(d)(6) of the 

CAA requires the EPA to review and 

revise the MACT standards, as 

necessary, taking into account 

developments in ‘‘practices, processes 

and control technologies.’’ Consistent 

with our long-standing practice for the 

technology review of MACT standards, 

in section III.C of the proposal (see 79 

FR 36900, June 30, 2014), we list five 

types of ‘‘developments’’ we consider. 

Fenceline monitoring fits squarely 

within two of those five types of 

developments (emphasis added): 

• Any add-on control technology or 

other equipment that was not identified 

and considered during development of 

the original MACT standards. 

• Any work practice or operational 

procedure that was not identified or 

considered during development of the 

original MACT standards. 

As used here, ‘‘other equipment’’ is 

clearly separate from and in addition to 

‘‘add-on control’’ technology and is 

broad enough to include monitoring 

equipment. In this case, fenceline 

monitoring is a type of equipment that 

we did not identify and consider during 

development of the original MACT 

standards. Additionally, the fenceline 

standard is a work practice standard, 

involving monitoring, root cause 

analysis and corrective action not 

identified at the time of the original 

MACT standards. Therefore, the 

fenceline requirements are a 

development in practices that will 

improve how facilities manage fugitive 

emissions and EPA appropriately relied 

on section 112(d)(6) in requiring this 

standard. 

Comment: Some commenters 

contended that because the fenceline 

monitoring standard is in essence an 

ambient standard, the only justification 

that can be used to support it would be 

under CAA section 112(f)(2). The 

commenters stated that EPA determined 

that the MACT standards pose an 

acceptable level of risk and protect the 

public health with an ample margin of 

safety and thus, section 112(f) does not 

support imposition of the fenceline 

monitoring requirement. Several 

commenters stated that the Agency 

expressly acknowledges that imposition 

of additional emission standards for 

fugitive emissions from refinery sources 

are not warranted under CAA section 

112(f). Some commenters suggested that 

because the existing MACT standards 

protect public health with an ample 

margin of safety, the fenceline 

monitoring requirement imposes an 

unnecessary burden on industry 

because it is not necessary to achieve 

acceptable risk or provide an ample 

margin of safety. 

Response: EPA is not relying on 

section 112(f)(2) as the basis for the 

fenceline monitoring requirement. As 

provided in a previous response to 

comment, we disagree with the 

commenters that the fenceline 

monitoring requirement is an ambient 

standard and therefore, we do not need 

to consider what authority would be 

appropriate for establishing an ambient 

standard that would apply to fugitive 

sources of emissions at refineries. We 

also disagree with the commenters who 

suggest that EPA may not require 

fenceline monitoring pursuant to 

section 112(d)(6) because EPA has not 

determined that fenceline monitoring is 

necessary to ensure an acceptable level 

of risk or the provide an ample margin 

of safety. Section 112(d)(6) does not 


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require EPA to factor in the health 

considerations provided in section 

112(f)(2) when making a determination 

whether it is ‘‘necessary’’ to revise the 

MACT. 

Comment: Commenters stated that the 

pilot studies undertaken by the EPA and 

pilot studies undertaken by the refining 

industry (see the API Fenceline Study in 

the docket for this rulemaking) 

demonstrate either that there is no 

underestimation of emissions and thus, 

no need for the fenceline monitoring 

work practice standard, or that fenceline 

benzene data cannot be used to validate 

emission estimates. Commenters stated 

that none of the refineries in the API 

study of the proposed refinery fenceline 

standard had study-averaged DC 

concentrations that exceeded the 

proposed action level of 9 mg/m3 and 

thus the study provides some evidence 

that U.S. refineries are not 

underestimating emissions. 

Furthermore, the commenter stated that 

there is significant ambient air 

monitoring performed that further 

supports low benzene concentrations in 

the vicinities of refineries and cited 

ambient monitoring data collected by 

the Southeast Texas Regional Planning 

Commission Air Quality Group and the 

Texas Commission on Environmental 

Quality (TCEQ). 

Response: We disagree that the API 

fenceline study demonstrates that there 

is no underestimation of emissions. The 

API report referred to by the commenter 

actually shows higher DC concentrations 

than what we expected, when we 

compare the distribution of DC’s 

presented in the API fenceline study to 

the distribution of benzene 

concentrations at the 142 refineries we 

modeled (see memorandum ‘‘Fenceline 

Ambient Benzene Concentrations 

Surrounding Petroleum Refineries’’, 

EPA–HQ–OAR–2010–0682–0208). [Note 

that API did not identify the facilities in 

their study, so we were not able to 

perform a one-to-one comparison of the 

measured DC concentrations with the 

modeled fenceline concentrations.] 

Furthermore, the API conducted the 

study primarily during the fall and 

winter months (October to March) when 

the ambient temperatures are lower than 

the annual averages. While this may not 

impact equipment leak emissions, 

temperature can have a significant 

impact on emissions from storage 

vessels and wastewater treatment 

systems, so it is likely that the annual 

average DC for the facilities tested could 

be higher than the ‘‘winter’’ averages 

measured in the API study. Based on 

our review of the API study data, we 

interpret the results to indicate that 

there may be higher concentrations of 

benzene on the fenceline attributable to 

fugitive emissions than anticipated at 

some facilities. These studies are an 

indication that the standard we are 

finalizing will achieve the goal of 

ensuring that the owners or operators 

manage fugitive emissions within the 

refinery. 

This regulatory approach also fits 

with the EPA’s goals to improve the 

effectiveness of rules. Specifically, in 

this case, we are improving the 

effectiveness of the rule in two ways. 

First, we are establishing a fenceline 

benzene trigger to manage overall 

fugitive HAP emissions, rather than 

establishing further requirements on 

many individual emission points. 

Secondly, the rule incentivizes facilities 

to reduce fugitive HAP emissions below 

the fenceline benzene trigger by 

providing regulatory options for 

reduced monitoring. 

Regarding ambient monitoring data, 

we note that existing ambient monitors 

are not located at the fenceline; they are 

located away from sources, and 

concentrations typically decrease 

exponentially with distance from the 

emissions source. We are encouraged 

that data referenced by the commenter 

indicate that ambient levels of benzene 

are within levels that are protective of 

human health in communities, but note 

that analysis of benzene concentrations 

in communities does not necessarily 

indicate that refineries located near 

these communities are adequately 

managing their fugitive HAP emissions. 

Comment: Several commenters 

reiterated that they do not believe the 

proposed fenceline monitoring is a 

technology development for equipment 

leaks, storage vessels or wastewater 

sources. However, if the EPA finalizes 

the fenceline monitoring requirements, 

the commenters suggested that there is 

no longer a need or regulatory basis for 

imposing both the fenceline monitoring 

requirements and the existing MACT 

standards for fugitive HAP emission 

sources. Thus, the EPA should remove 

the current MACT requirements for 

LDAR, storage vessels and wastewater 

handling and treatment from Refinery 

MACT 1 if the EPA promulgates 

fenceline monitoring. Addition of 

fenceline monitoring on top of the 

existing MACT requirements, they 

argue, would violate the Executive 

Order 12866 mandate to avoid 

redundant, costly regulatory 

requirements that provide no emission 

reductions. 

Response: We disagree that the 

fenceline monitoring standards we are 

finalizing in this rule are redundant to 

MACT emissions standards for fugitive 

HAP emissions sources. The MACT 

standards impose requirements on 

fugitive HAP emissions sources 

consistent with the requirements in 

CAA section 112(d)(2) & (3), and the 

fenceline monitoring requirement is not 

a replacement for those requirements. 

Rather, based on our review of these 

standards, we concluded that fenceline 

monitoring is a development in 

practices, processes or control 

technologies that would improve 

management of fugitive emissions in a 

cost-effective manner. In selecting this 

development as an across-the-board 

means of improving management of 

fugitive emissions, we rejected other 

more costly developments that would 

have applied independently to each 

fugitive emissions source. Requiring 

refineries to establish a fenceline 

monitoring program that identifies HAP 

emission sources that cause elevated 

benzene concentrations at the fenceline 

and correcting high emissions through a 

more focused effort augments but does 

not replace the existing requirements. 

We found that, through early 

identification of significant fugitive 

HAP releases through fenceline 

monitoring, compliance with the 

existing MACT standards for these 

emissions sources could be improved 

and that it was necessary to revise the 

existing standards because fenceline 

monitoring is a cost-effective 

development in processes, practices, 

and control technologies. 

We note that the existing MACT 

requirements are based on the MACT 

floor (the best performers), and as such, 

provide a significant degree of emission 

reductions from the baseline. The action 

level for the fenceline work practice 

standard, by contrast, is not based on 

the best performers but rather on the 

highest value expected on the fenceline 

from any refinery, based on the 

modeling of refinery emission 

inventories. As such it is not 

representative of the best performers 

and could not be justified as meeting the 

requirements of section 112(d)(2)and 

(3). If we were to remove the existing 

standards for fugitive emission sources 

at the refinery, we would not be able to 

justify that sources are meeting the level 

of control we identified as the MACT 

floor when we first promulgated the 

MACT. Nor could we justify the 

fenceline monitoring program we are 

promulgating as representing the MACT 

floor because we considered cost (and 

not the best performers as previously 

noted) in identifying the components of 

the program. Although the fenceline 

monitoring standard on its own cannot 

be justified as meeting the MACT floor 

requirement for each of the separate 


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types of fugitive emission sources, that 

does not mean that it is not an effective 

enhancement of those MACT 

requirements. To the contrary, it works 

in tandem with the existing MACT 

requirements to provide improved 

management of fugitive emissions and, 

in that sense, it is precisely the type of 

program that we believe Congress had in 

mind when enacting section 112(d)(6). 

ii. Rule Should Require Real-Time 

Monitoring Technology for Fenceline 

Monitoring. 

Comment: Numerous commenters 

stated that the proposed fenceline 

standards, which require monitoring 

using 2-week integrated passive 

samplers, are flawed and weak for a 

number of reasons, including that the 

monitoring method does not provide 

real-time data, does not provide 

adequate spatial coverage of the 

fenceline, and does not provide a 

mechanism to identify the specific 

emission source impacting the fenceline 

to manage fugitive emissions. Several 

commenters suggested that this 

monitoring technology is not state of the 

art. They claimed that there are superior 

systems in place at refineries that are 

technically and economically feasible, 

including at Shell Deer Park, Texas; BP 

Whiting, Indiana; and Chevron 

Richmond, California. Further, they 

claimed that these systems more 

effectively achieve the objective of 

reducing fugitive emissions. They 

claimed several systems are superior to 

the proposed system, including openpath systems such as ultraviolet 

differential optical absorption (UV 

DOAS) and Fourier transform infrared 

spectroscopy (FTIR), as well as point 

monitors such as gas chromatographs. A 

number of commenters suggested that 

open-path monitors should be required, 

stating that this technology is capable of 

providing real-time analysis and data on 

air pollution, is able to analyze multiple 

pollutants simultaneously at low, nearambient concentrations, and is capable 

of providing more complete geographic 

coverage. 

The commenters also stated that the 

benefits of real-time monitors are 

particularly important in communities 

close to refineries, where they believe 

refinery emissions are a major source of 

toxic pollutants and short-term upset 

events that can have significant public 

health impacts. In particular, the 

commenters stated that open-path 

monitors promote an individual’s rightto-know, in real-time, about harmful 

pollution events affecting their 

communities, and will allow refinery 

owners or operators to immediately 

identify fugitive emissions and 

undertake swift corrective action to 

reduce these emissions. Some 

commenters suggested that, if the EPA 

rejects these open-path real-time 

monitors, then at a minimum the EPA 

should require the use of active daily 

monitoring, such as auto-gas 

chromatograph (GC) systems. 

Finally, a number of commenters 

recommended that the EPA provide 

sufficient flexibility in its regulations to 

allow state and local jurisdictions to 

develop, demonstrate, and subsequently 

require the use of alternative monitoring 

programs, provided these monitoring 

programs are at least equivalent to those 

in the final rule. 

Response: We understand that many 

commenters believe real-time 

monitoring would not only help refinery 

owners or operators in identifying 

emission sources, but also would warn 

the community of releases in real time. 

Both open-path systems and active 

sampling systems (such as auto-GCs) 

mentioned by the commenters, are 

monitoring systems capable of yielding 

monitoring data quickly—ranging from 

a few minutes to about a day. However, 

these ‘‘real-time’’ systems have not been 

demonstrated to be able to achieve all of 

the goals stated by the commenters— 

specifically, able to provide real-time 

analysis and data on multiple pollutants 

simultaneously at low-, near-ambient 

concentrations, with more complete 

geographic (or spatial) coverage of the 

fenceline. 

The real-time open-path systems 

suggested by the commenters are all 

limited in that they are not sensitive 

enough to detect benzene at the levels 

needed to ensure that fenceline 

monitoring achieves its intended goal. 

The fenceline monitoring system needs 

to be capable of measuring at sub-ppbv 

levels—well below the 9 mg/m3

fenceline benzene concentration action 

level in the final rule, in order to 

determine the DC. In the proposal, we 

discussed two open-path monitoring 

technologies, FTIR and UV–DOAS. For 

the proposed rule, we analyzed the 

feasibility of employing UV–DOAS over 

FTIR because the UV–DOAS is more 

sensitive to detection of benzene than 

FTIR, as we described in the proposal. 

We reviewed performance data on 

several UV–DOAS systems in support of 

the proposed rule, and for this final 

rule, we considered information 

submitted during the comment period. 

We found that the lowest detection limit 

reported for any commercially-available 

UV–DOAS system is on the order of 3 

ppbv over a 200-meter path length, 

whereas the fenceline benzene 

concentration action level is 2.8 ppbv 

(equivalent concentration to 9 mg/m3). 

This system is being installed at the 

Shell Deer Park refinery but has not 

been field validated yet. Thus, we do 

not yet know the detection capabilities 

of the system, as installed. Based on the 

lowest reported detection limit, it 

cannot achieve the detection levels 

needed to demonstrate compliance with 

the fenceline standard in this final rule. 

This system also will only cover 

approximately 5 percent of the fenceline 

at Shell Deer Park, instead of the full 

fenceline coverage of the passive 

diffusive tube monitoring system we 

proposed. Facilities would have to 

deploy a monitoring system consisting 

of many open-path monitors to achieve 

the same spatial coverage as the passive 

diffusive tube monitoring system. 

For the final rule, we also reviewed 

other UV–DOAS systems in operation at 

refineries that commenters identified. 

However, reported detection limits for 

these systems are even higher than for 

the type of system being installed at 

Shell Deer Park. For example, we 

reviewed the open-path UV–DOAS 

system information from BP Whiting 

and found that they were able to verify 

a detection limit of 8 ppbv path average 

concentration for benzene over a 1,500- 

meter optical path. This is well above 

the 2.8 ppbv fenceline benzene 

concentration action level, let alone the 

sub-ppbv levels necessary to determine 

the DC. Moreover, this system, though 

commercially available, was optimized 

by developing alternative software to 

improve the detection limit (see 

memorandum ‘‘Meeting Minutes for 

April 21, 2015, Meeting Between the 

U.S. EPA and BP Whiting’’ in Docket ID 

No. EPA–HQ–OAR–2010–0682). Thus, 

the system, as installed, would not be 

readily available to other refineries. We 

reviewed data for the UV–DOAS system 

at the Chevron Richmond refinery and 

found that this system, with optical path 

lengths ranging from 500 to 1,000 

meters, has a reported benzene 

detection limit of 5 ppbv averaged over 

the path length. Again, this is above the 

fenceline benzene concentration action 

level at the fenceline established in this 

final rule. In addition, we could not find 

any information to support the reported 

detection limit. We note that the public 

Web site operated by the City of 

Richmond, California indicates that 

information provided by the system is 

informational only, not quality assured, 

and not to be used for emergency 

response or health purposes. 

We also disagree with the 

commenter’s claim that if the EPA does 

not finalize requirements for real-time 

open-path monitors then, at a minimum, 

the EPA should require active daily 

monitoring. There are two methods of 


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active monitoring. One method, which 

we will refer to as the ‘‘auto-GC 

method,’’ uses a dedicated gas 

chromatograph at each monitoring 

location and can return ambient air 

concentration results multiple times a 

day or even hourly. The other method, 

which we refer to as ‘‘method 2,’’ uses 

an active pump to collect gas in a 

sorbent tube or in an evacuated canister 

over a 1-day period, for later analysis at 

a central location. While active 

sampling monitoring networks are 

capable of measuring multiple 

pollutants and would likely be able to 

detect benzene at sub-ppbv levels as 

necessary to demonstrate compliance 

with the fenceline requirements in this 

final rule, they consist of discreet 

monitors and would not provide any 

better spatial coverage of the refinery 

fenceline than a passive diffusive tube 

monitoring network. Further, as shown 

in Table 9 of the proposed rule (see 79 

FR 36923, June 30, 2014), like open-path 

systems, an active sampling monitoring 

network would cost many times that of 

a passive diffusive tube monitoring 

network. At proposal, we estimated the 

costs of active daily sampling based on 

‘‘method 2’’ to be approximately 10 

times higher than for the proposed 

passive monitoring (see memorandum 

‘‘Fenceline Monitoring Technical 

Support Document’’, Docket ID No. 

EPA–HQ–OAR–2010–0682–0210). We 

note that this type of active daily 

sampling based on method 2 does not 

necessarily yield results within 24 hours 

as the sample analysis would be 

conducted separately. We did not 

specifically estimate the costs of an 

auto-GC alternative, but the capital costs 

would be at least 20 to 30 times that for 

the passive diffusive tube system, would 

require shelters and power supplies at 

all monitoring locations and would have 

operating costs similar to the ‘‘method 

2’’ active monitoring option we 

considered. 

To date, there are no commerciallyavailable, real-time open-path monitors 

capable of detecting benzene at the subppbv levels necessary to demonstrate 

compliance with the fenceline 

requirements in this final rule. Only a 

system that can detect such levels will 

result in effective action by facilities to 

identify and control fugitive emissions 

in excess of those contemplated by the 

MACT standards. Further, active 

monitoring systems, while potentially 

capable of detecting benzene at subppbv levels, like open-path systems, 

become very costly when enough 

monitors are located around the facility 

to approach the spatial coverage of the 

passive diffusive tubes. However, we 

believe that the state of technology is 

advancing and that the capabilities of 

these systems will continue to improve 

and that the costs will likely decrease. 

If a refinery owner or operator can 

demonstrate that a particular technology 

would be able to comply with the 

fenceline standards, the owner or 

operator can request the use of an 

alternative test method under the 

provisions of 40 CFR 63.7(f). A 

discussion of the specific requirements 

for these requests can be found in the 

first comment and response summary of 

Chapter 8.3 of the ‘‘Response to 

Comment’’ document. 

Comment: One commenter stated that 

the required monitoring should include 

real-time monitoring of all chemicals 

released by refineries that pose risks to 

human health. The commenter stated 

that the limited scope of monitoring 

required by the proposed rule appears to 

be guided by the EPA’s judgment that 

fugitive, or ‘‘unintended’’ emissions 

pose the greatest threat to public health. 

On the contrary, communities may well 

suffer from the effects of chemicals 

released into the air under normal, 

permitted emissions. A more expansive 

monitoring strategy would account for 

both routine and fugitive emissions. 

Several commenters noted that 

monitoring is limited to benzene as 

opposed to multiple HAP. One 

commenter noted that ill health 

experienced by refinery neighbors is 

due in large part to the synergistic 

effects of multiple chemicals. Therefore, 

the commenter stated that it is essential 

that the rule require monitoring of the 

full range of chemicals with health 

implications. Other commenters 

recommended that the fenceline 

monitoring requirement be amended to 

include additional contaminants, such 

as VOC, that may negatively impact 

human health and the environment. 

Conversely, other commenters stated 

that the EPA has appropriately selected 

benzene as a target analyte and 

surrogate for HAP emissions from 

petroleum refineries, as benzene is a 

common constituent in refinery 

feedstocks and numerous refinery 

streams, and is present in most HAPcontaining streams in a refinery. 

Response: As part of the CAA section 

112(d)(6) technology review, the EPA 

identified the fenceline monitoring 

standard as a development in practices, 

processes or control technologies that 

could improve management of fugitive 

HAP emissions. Thus, to the extent the 

commenter is suggesting that the EPA 

require the fenceline monitoring system 

to monitor for emissions of non-HAP 

pollutants, such request goes beyond the 

scope of our action. Furthermore, to the 

extent that the commenter is raising 

health concerns, although we address 

residual risk remaining after 

implementation of the MACT standards 

under CAA section 112(f)(2), we note 

that the MACT standards themselves, 

including this requirement, are aimed at 

protecting public health, especially in 

surrounding communities. As we 

explained in the proposal, and as we 

determine for this final rule, the MACT 

standards as modified by additional 

requirements for storage vessels, 

provide an ample margin of safety to 

protect public health. We did not 

propose and are not finalizing a 

fenceline monitoring requirement as 

necessary to provide an ample margin of 

safety under CAA section 112(f)(2). 

Petroleum refining emissions can 

contain hundreds of different 

compounds, including many different 

HAP, and no single method can detect 

every HAP potentially emitted from 

refineries. While several HAP are 

amenable to quantification via passive 

diffusive tube monitoring using the 

same adsorbent tubes used for benzene 

(e.g., toluene, xylenes and ethyl 

benzene, which have uptake rates in 

Table 12.1 in Method 325B), we selected 

benzene as a surrogate because it is 

present in nearly all refinery fugitive 

emissions. By selecting a single HAP as 

a surrogate for all fugitive HAP, we are 

able to establish a clear action level, 

which simplifies the determination of 

compliance for refinery owners or 

operators and simplifies the ability of 

regulators and the public to determine 

whether sources are complying with the 

work practice standard. As described in 

the proposal preamble, benzene is 

ubiquitous at refineries and present in 

nearly all refinery process streams, 

including crude oil, gasoline and 

wastewater. Additionally, benzene is 

primarily emitted from ground level, 

fugitive sources that are the focus of the 

work practice standard. Thus, we 

conclude that monitoring of benzene is 

appropriate and sufficient to identify 

emission events for which the 

monitoring program is targeting. 

Consequently, we are not requiring 

quantification of other pollutants 

although refinery owners or operators 

could choose to analyze the diffusive 

tube samples for additional HAP in 

conducting root cause analysis and 

corrective action. 

iii. Fenceline Monitoring Action Level 

Comment: Several commenters stated 

that the action level for fenceline 

monitoring (i.e., 9 mg/m3 or 2.8 ppbv), 

was set too high. Some of these 

commenters noted that the EPA selected 

9 mg/m3 as the highest modeled benzene 


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7To the extent that the commenters are 

suggesting that EPA must re-perform the MACT 

floor analysis for purposes of setting a standard 

pursuant to section 112(d)(6), we note that the D.C. 

Circuit has rejected this argument numerous times, 

most recently in National Association for Surface 

Finishing et al. v. EPA No. 12–1459 in the U.S. 

Court of Appeals for the District of Columbia. 

8Although we did not establish this limit to 

address residual risk under CAA section 112(f)(2), 

the limit was derived from the same inventory used 

for our risk modelling. Thus, based on our current 

reference concentration for benzene, the 9 mg/m3

action level will also ensure that people living near 

the refinery will not be exposed to cancer risks 

exceeding 100-in-1 million. 

concentration at any refinery fenceline. 

One commenter stated that this was 

arbitrary and capricious and stated the 

action threshold level makes little sense 

because only 2 of the 142 modeled 

facilities are expected to have fenceline 

concentrations above 4 mg/m3. Several 

commenters noted that the average 

modeled benzene concentration is 0.8 

mg/m3, which is more than an order of 

magnitude less than the proposed 

fenceline benzene concentration action 

level. 

Two commenters argued for a lower 

action level threshold, citing the 

proposed California OEHHA rule, which 

finalized new and revised benzene 

reference exposure levels (REL) that are 

more stringent than the ones the EPA 

used in the residual risk assessment 

supporting the proposed rule. 

Two commenters stated that while the 

fenceline benzene concentration action 

level of 9 mg/m3 is relatively protective 

compared to standards adopted by many 

states, including Louisiana and Texas, it 

is still 80-percent higher than the 

European Union’s standard of 5 mg/m3. 

The commenter urged the agency to 

consider adopting a stricter standard 

comparable to what other industrialized 

nations use. 

Several commenters stated that the 

EPA’s 9 mg/m3 action level is 

inconsistent with the statutory text and 

objectives of CAA sections 112(d) and 

(f), which direct the EPA to focus on the 

best-performing, lowest-emitting 

sources, in order to require the 

‘‘maximum achievable’’ emission 

reductions. The commenters stated that 

the EPA promulgated the 9 mg/m3 limit 

without properly following the statutory 

requirements for establishing MACT 

floor limits, pointing out that the EPA 

made no determination of whether or 

not these general models were 

representative of the emissions levels 

actually achieved by the submitting 

refinery, and no connection was drawn 

between the best performing sources 

and the eventual 9 mg/m3 limit. 

On the other hand, several 

commenters opposed the 9 mg/m3 action 

level suggesting that it was not 

achievable and that it is arbitrary. Some 

commenters noted that emission/

dispersion models are always very sitespecific and do not necessarily yield a 

result that is reliable or reproducible. 

Several commenters stated that 

additional studies are necessary to allow 

the agency to account for these variables 

and set a more appropriate 

concentration corrective action level. 

Commenters suggested a 2-year data 

gathering effort at all refineries and data 

evaluation before determining a specific 

threshold to use. 

Several commenters recommended 

action levels ranging from 15 mg/m3 to 

20 mg/m3 of benzene to account for the 

variability expected in monitoring data. 

The commenters stated that modeling 

biases have underestimated the 

necessary action level to achieve the 

stated goals of the program. 

Response: First, it is important to note 

that the purpose of the standard has not 

changed between proposal and 

promulgation, namely that it is a 

technology-based standard that is an 

advancement in practices to manage 

fugitive emissions. It is not intended to 

be a separate or new MACT standard 

promulgated pursuant to CAA sections 

112(d)(2) and (3) for which a ‘‘floor’’ 

analysis would be required.7 Nor is it a 

standard that we are promulgating 

pursuant to CAA section 112(f)(2) as 

necessary to provide an ample margin of 

safety to protect public health or 

prevent an adverse environmental 

effect.8 Thus, claims that a standard 

should reflect European Union healthbased standards or the California 

OEHHA rule are misplaced. We also 

disagree with the suggestion that the 

proposed monitoring requirement will 

allow for higher emissions. As noted 

elsewhere, we are retaining all of the 

source-specific requirements for fugitive 

emissions sources that exist in Refinery 

MACT 1. 

We disagree with the commenters that 

suggest that the proposed action level of 

9 mg/m3 is too low and may not be 

achievable even for well-performing 

facilities. As discussed in the preamble 

for the proposed rule, we selected the 9 

mg/m3 benzene action level because it is 

the highest value on the fenceline 

predicted by the dispersion modeling 

and, thus, is a level that we estimate 

that no refinery should exceed when in 

full compliance with the MACT 

standards, as amended by this final rule. 

All of the results of our pilot study, the 

API study, and the other ambient 

monitoring data near refineries clearly 

indicate that this level is achievable. 

Furthermore, we expect the fenceline 

concentration difference measured 

following the procedures in the final 

rule to be indicative of refinery source 

contributions and we have provided 

procedures to isolate these 

concentrations from outside sources, as 

well as background. 

We expect that the fenceline 

monitoring standard will result in 

improved fugitive HAP emissions 

management as it will alert the refinery 

owners or operators of fugitive sources 

releasing high levels of HAPs, such as 

large leaks, faulty tank seals, etc. 

iv. Fenceline Monitoring Root Cause 

Analysis and Corrective Action 

Provisions 

Comment: A number of commenters 

objected to the proposal’s ‘‘open-ended’’ 

provisions allowing the EPA to direct 

refinery owners or operators to change 

their operations in order to achieve the 

fenceline limit, with no regulatory 

limits on costs and without 

consideration of the impact to safe 

operations or operability of the plant. 

Another commenter stated that the EPA 

must properly assess the costs 

associated with the root cause analysis/ 

corrective action requirements and 

should establish a cost effectiveness 

threshold for any required root cause 

analysis/corrective action to ensure that 

limited resources are effectively and 

efficiently applied for the control of 

emissions. 

One commenter stated the proposed 

fenceline benzene concentration action 

level is effectively an ambient air 

standard, because corrective action to 

achieve that level is required and that if 

a facility’s initial corrective action is 

unsuccessful, the rule provides that 

further action is required and the EPA 

must approve that further corrective 

action plan. Thus, the commenter 

argued, the EPA would essentially be 

able to dictate corrective actions, with 

no bounds on what could be required 

and no consideration of whether any 

cost-effective actions are available to 

assure the action level is met. The 

commenter continued that such a 

requirement converts a work practice 

program to an emission limitation and 

such ambient air limits are not 

authorized by CAA section 112. Several 

commenters noted that LDAR and 

current work practice programs have no 

similar requirement for the EPA 

approval, and the commenters suggested 

that the requirement for the EPA 

approval of any second corrective action 

should not be included in 40 CFR 

63.658(h). 

Another commenter recommended 

that, if after corrective action, a facility 

still has an exceedance for the next 

sampling episode, then the facility 

should be required to do more than it 


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did after the first root cause analysis, as 

the prior corrective action clearly did 

not correct the problem. The commenter 

stated that one corrective action 

measure the EPA should include in all 

such instances is higher-quality 

monitoring such as UV–DOAS for at 

least 1 year to monitor, identify, correct 

and assure ongoing compliance after the 

exceedance problem is fixed. 

Response: The ‘‘on-going’’ 

requirement to achieve the fenceline 

benzene concentration action level is no 

different in concept from the LDAR 

requirements for equipment or heat 

exchange systems in the Refinery MACT 

1 rule, which requires the refinery 

owner or operator to repair the source 

of the emissions regardless of what it 

takes until compliance with the 

standard is achieved. 

We disagree with the claim that the 

EPA must assess the costs associated 

with the root cause analysis/corrective 

action requirements and establish a cost 

effectiveness threshold for any required 

root cause analysis/corrective action to 

ensure that limited resources are 

effectively and efficiently applied for 

the control of emissions. We did not 

attempt to project the costs of the root 

cause analysis/corrective action for at 

least two reasons. First, based on the 

dispersion modeling of the benzene 

emissions reported in response to the 

inventory section of the 2011 ICR, we 

project that no refinery should exceed 

that fenceline benzene concentration 

action level if in full compliance with 

the MACT standards, as amended by 

this action. Thus, assuming compliance 

with the MACT standards, we would 

expect that there are no costs for root 

cause analysis/corrective action. To the 

extent that there are exceedances of the 

action level, the premise of the fenceline 

monitoring is to provide the refinery 

owners or operators with the flexibility 

to identify the most efficient approaches 

to reduce the emissions that are 

impacting the fenceline level. Since the 

choice of control is a very site-specific 

decision, we would have no way to 

know how to estimate the costs. Thus, 

the source is in the best position to 

ensure that resources are effectively and 

efficiently spent to address any 

exceedance. 

We intended the proposed 

requirement for refinery owners or 

operators to submit a corrective action 

plan for the EPA approval to provide the 

Administrator with information that 

they were making a good-faith effort to 

reduce emissions below the fenceline 

benzene concentration action level, as 

expeditiously as practicable. However, 

we understand the importance for 

refinery owners or operators to begin 

corrective action as soon as possible, 

without having to wait for the EPA 

approval. Therefore, we are finalizing 

the requirement for refinery owners or 

operators to submit such plans but we 

are not finalizing the requirement that 

the EPA must approve the plan prior to 

the corrective action being taken. 

We previously responded to 

comments regarding UV–DOAS or other 

open-path monitoring systems in this 

section, explaining that the current 

detection limits for these systems 

exceeds the action level threshold and, 

thus, these systems would not provide 

usable data to inform corrective action. 

Thus, we disagree that the EPA should 

require these systems for all facilities 

whose first attempt at corrective action 

is ineffective. 

v. Fenceline Monitor Siting 

Requirements 

Comment: Numerous commenters 

provided suggestions on, or requested 

clarification of, the monitor siting 

requirements. Several commenters 

stated that proposed Method 325A uses 

the terms ‘‘fenceline or property 

boundary,’’ while it should consistently 

use the term ‘‘property boundary’’ or 

even ‘‘property line’’ as the fenceline 

location. Several commenters stated that 

Sections 8.2.2.1.4 and 8.2.2.3 of Draft 

Method 325A specify that samplers be 

placed just beyond the intersection 

where the measured angle intersects the 

property boundary and this could 

require placing monitors on other 

people’s property, in a road, in a water 

body or in a railroad right-of-way. The 

commenters suggested that facilities 

should be allowed to place monitors at 

any vector location that meets other 

requirements between the property 

boundary and the source nearest the 

property boundary. They stated that 

facilities need this clarification to avoid 

obstructions (e.g., buildings or trees) 

that may be at the property line. 

Numerous commenters requested that 

the rule clarify where monitors need to 

be placed in special circumstance, such 

as refineries bisected by a road, railroad 

or other public right-of-way or a 

boundary next to a navigable waterway. 

Several commenters stated that refiners 

should not need to place monitors on 

these property boundaries or other 

property boundaries where there are no 

residences within 500 feet of the 

property line. Commenters also asked if 

areas that had non-refinery operations, 

but are still inside the property 

boundary, would be included for 

purposes of determining where to site 

monitors. 

A few commenters expressed concern 

about the approach for determining the 

number of required monitors at a site 

based on the acreage, noting that it is 

unfair to small facilities and will leave 

gaps in monitoring coverage for very 

large facilities. Some commenters 

recommended amending the proposed 

rule to require the placement of 

fenceline monitors at fixed distances 

along facilities’ perimeters with no 

maximum number of monitors. Some 

commenters stated that the rule should 

specify an acceptable range on the 

2,000-foot spacing requirement or the 

radial placement requirement as it may 

be necessary to address accessibility or 

safety concerns. Several commenters 

suggested that a lower minimum 

number of sampling monitors should be 

required for very small refineries or 

small ‘‘subareas.’’ These commenters 

noted that refineries often include 

disconnected parcels that can be very 

small (e.g., 10 acres or less). If each 

disconnected parcel must be treated as 

a separate subarea, then both sampler 

siting options in Draft Method 325A 

would result in unnecessarily large 

numbers of samplers extremely close 

together. Some commenters 

recommended that Method 325A 

specify that samplers need not be placed 

closer than 500 feet (versus the normal 

2,000-foot interval specified in Option 

2) along the fenceline from an adjoining 

sampler, regardless of whether the 

radial or linear approach is used and 

should waive the minimum number of 

samplers specified in Sections 8.2.2.1.1, 

8.2.2.2.1, and 8.2.3.1. Another 

commenter added that the rule should 

waive the requirement for additional 

samplers in Sections 8.2.2.1.5 and 

8.2.3.5 if the 500-foot minimum spacing 

criterion is compromised. 

Response: We agree that the Method 

325A should provide clear and 

consistent language. We have revised 

the language to be consistent in referring 

to the ‘‘property boundary’’. We have 

also revised the Method to allow 

placement of monitors at any radial 

distance along either a vector location or 

linear location (that meets the other 

placement requirements) between the 

property boundary and the source 

nearest the property boundary. That is, 

the monitors do not need to be placed 

exactly on the property boundary or 

outside of the property boundary. They 

may be placed within the property 

closer to the center of the plant as long 

as the monitor is still external to all 

potential emission sources. We do note 

that if the monitors are placed farther in 

from the property boundary, the owner 

or operator should take care to ensure, 

if possible, that the radial distance from 

the sources to the monitors is at least 50 


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meters. If the perimeter line of the 

actual placement of the fenceline 

monitors is closer than 50 meters to one 

or more sources, then the additional 

monitor citing requirements will apply. 

We have revised subparagraphs of 

Section 8.2.2 to provide this allowance. 

This clarification should address issues 

related to obstructions such as tall walls 

located at the facility boundary. 

We intended that the fenceline 

monitoring would create a monitoring 

perimeter capable of detecting 

emissions from all fugitive emission 

sources at the refinery facility. We have 

long established that a road or other 

right of way that bisects a plant site does 

not make the plant site two separate 

facilities, and, thus, would not be 

considered part of the property 

boundary. As we agree that monitors 

need only be placed around the 

property boundary of the facility, it 

would not be necessary to place 

monitors along a road or other right-ofway that bisects a facility. We have 

clarified this in the final rule and 

Method 325A. 

If the facility is bounded by a 

waterway on one or more sides, then the 

shoreline is the facility boundary and 

monitors should be placed along this 

boundary. If the waterway bisects the 

facility, the waterway would be 

considered internal to the facility and 

monitors would only be needed at the 

facility perimeter. 

Regarding the comment that monitors 

should not be required where there is no 

residence within 500 feet of the 

property line, we disagree. We proposed 

and are finalizing the fenceline 

monitoring standards under CAA 

section 112(d)(6) as a means to improve 

fugitive HAP emissions management, 

regardless of whether there are people 

living near a given boundary of the 

facility. 

Regarding the clarification requested 

about monitor placement considering 

non-refinery operations, the property 

boundary monitors should be placed 

outside of all sources at the refinery. 

This is because moving the monitoring 

line inward to exclude the non-refinery 

source could lead to an underestimation 

of the DC compared to the monitoring 

external of the entire site. If the nonrefinery source is suspected of 

contributing significantly to the 

maximum concentration measured at 

the fenceline, a site-specific monitoring 

plan and monitoring location specific 

near-field interfering source (NFS) 

corrections will be needed to address 

this situation. 

Section 8.2.3 of Method 325A 

includes language to provide some 

flexibility when using the linear 

placement (±10% or ±250 feet). We 

consider it reasonable to provide similar 

placement allowance criteria for the 

radial placement option (±1 degree). We 

are not providing requirements that 

would allow small area refineries to use 

fewer than 12 monitoring sites. We do 

not consider that any refinery would be 

so small as to warrant fewer than 12 

monitors; however, we did not 

necessarily consider very small subareas 

for irregularly shaped facilities or 

segregated operations. When 

considering these subareas, we agree 

that fewer than 12 monitoring sites 

should be appropriate. Therefore, we 

have provided that monitors do not 

need to be placed closer than 152 meters 

(500 feet) (or 76 meters (250 feet) if 

known sources are within 50 meters 

(162 feet) of the monitoring perimeter, 

which is likely for these subareas or 

segregated areas) with a stipulation that 

a minimum of 3 monitoring locations be 

used per subarea or segregated area. We 

note, however, that this distance 

provision does not obviate the near 

source extra monitoring siting 

requirements or the requirement to have 

a minimum of three monitors per 

subarea or segregated area. 

If facility owners or operators have 

questions regarding the required 

locations of monitors for a specific 

application, they should contact the 

EPA (or designated authority) to resolve 

questions about acceptable monitoring 

placement. 

vi. Compliance Time for Fenceline 

Monitoring Requirements 

Comment: Some commenters 

supported EPA’s proposal to provide 3 

years to put a fenceline monitoring 

program in place, but the commenters 

believe that timing is unclear in the 

proposed regulatory language, which 

appears in Table 11 to subpart CC, and 

requested that the EPA add the initial 

compliance date to 40 CFR 63.658(a). 

One commenter stated that instituting 

this program for all 142 major source 

U.S. refineries would require 

considerable time. Based on their 

experience with their pilot study, one 

commenter noted that commercially 

available weather guards meeting the 

specifications of proposed Method 325A 

are not available and would need to be 

fabricated. Additionally, a commenter 

stated that only a limited number of 

laboratories in the U.S. are able to 

perform the necessary analyses. 

According to the commenter, 

considerable time and effort will be 

needed to qualify additional laboratories 

and to expand the capacity of existing 

laboratories to handle the samples from 

142 refineries. 

Other commenters disagreed with the 

EPA’s proposed compliance time and 

suggested that the EPA shorten the 

timeline for implementation at 

refineries so that possible corrective 

action occurs much sooner than 

proposed. The commenters suggested 

that deployment of passive samplers can 

proceed more promptly than proposed, 

especially since the EPA has 

simultaneously proposed specific 

‘‘monitor siting and sample collection 

requirements as EPA method 325A of 40 

CFR part 63, Appendix A, and specific 

methods analyzing the sorbent tube 

samples as EPA Method 325B of 40 CFR 

part 63, Appendix A.’’ Moreover, the 

commenter noted, a principal reason 

that the EPA selected passive monitors 

over active monitors was due to the 

relative ‘‘ease of deployment.’’ The 

commenter claimed this ease of 

deployment rationale is undermined by 

a 3-year grace period to deploy passive 

monitors when the EPA is providing 

very specific criteria for their use. The 

commenter suggested that the EPA 

require full compliance with the passive 

monitoring requirement within 1 year of 

the effective date of the rule. 

Response: While we realize that it 

will take some time for the refinery 

owners or operators to understand the 

final rule and develop a compliant 

monitoring program, we agree that in 

requiring the passive sampler 

monitoring system, we recognized the 

ease of implementation and 

deployment. Although industry 

commenters identified issues they faced 

in the API pilot study while trying to 

implement the monitoring method, we 

note that the 12 facilities that 

participated in the API pilot study 

installed the fenceline monitors and 

began sampling in late 2013 with 

relative ease and within months of 

obtaining the draft methods. Thus, we 

disagree with the suggestion that 3 years 

is insufficient and agree with other 

commenters that 3 years is in fact too 

long. However, we also are aware that 

the API pilot facilities used the direct 

DC approach proposed and did not 

attempt to develop site-specific 

monitoring programs to correct for 

interfering near-field sources. Although 

we expect that facilities could complete 

direct implementation of the proposed 

fenceline monitoring requirement 

within 1 year after the effective date of 

the rule, as suggested by some 

commenters, facilities that choose to 

develop a site-specific monitoring plan 

would need a longer period of time. 

Therefore, we are finalizing 

requirements that specify that facilities 

must begin monitoring for the official 


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determination of DC values no later than 

2 years after the effective date of the 

rule. 

vii. Fenceline Monitoring 

Recordkeeping and Reporting 

Requirements 

Comment: Some commenters 

suggested that facilities should be 

required to submit the monitoring data 

via the ERT only if they exceed the 

fenceline benzene concentration action 

level and that all remaining data should 

be kept on-site and available for 

inspection or upon request of the EPA, 

citing that this is consistent with EPA’s 

semiannual NESHAP reporting of only 

exceptions (i.e., deviations). Other 

commenters requested that the EPA 

only post the rolling annual average 

concentration values and not the 2-week 

monitoring data. These commenters 

indicated concern that if errors are 

present in the raw data that are 

submitted semiannually to the EPA, the 

data, errors and all, will be released to 

the public and correcting them will not 

take place or will not take place in a 

timely manner. One commenter added 

that there is very little useful 

information that can be gleaned from 

the raw data and posting it simply 

invites misunderstandings. 

Commenters also stated that the EPA 

should adopt reporting requirements to 

ensure that facilities report the 

monitoring data appropriately. 

Specifically, commenters recommended 

that 40 CFR 63.655(h)(8)(i) should be 

clarified to only require reporting of 

valid data and cautioned that data 

should be processed to allow accurate 

calculations of annual averages to be 

used for reporting and evaluation. To 

accomplish this, commenters 

recommended that the rule provide 75 

days from the end of a 6-month 

sampling period to report to the EPA, 

rather than the proposed 45-day period, 

in order to provide adequate time to 

obtain quality-assured results for all 2- 

week sampling periods. 

One commenter applauded the 

proposal’s requirements for electronic 

reporting of the fenceline concentration 

data and making the resulting 

information publicly available. 

However, the commenter recommended 

that the EPA consider a more truncated 

data reporting period that is more 

consistent with the associated 

milestones of collecting a 14-day 

sampling episode. As is, the commenter 

claimed, the proposed rule would have 

a lag time of up to 7.5 months between 

data collection and posting. The 

commenter indicated that data reporting 

on a more frequent schedule will not 

only provide transparency, but will 

provide states and local agencies with 

information about air quality at 

refineries at a frequency that could 

allow informed activities to address 

leaks much more quickly and protect 

public health. 

Response: We disagree with the 

commenters who suggest that facilities 

only report the rolling annual average or 

only exceedances of the fenceline 

benzene concentration action level 

because the commenters believe there is 

little information to be gleaned from the 

raw data. Monitoring data are useful in 

understanding emissions, testing 

programs, and in determining and 

ensuring compliance. We generally 

require reporting of all test data, not just 

values calculated from test data and/or 

where a facility exceeds an emissions or 

operating limit. For example, when we 

conduct risk and technology reviews for 

source categories, we are adding 

requirements for facilities to submit 

performance test data into the ERT, not 

just performance test data that indicates 

an exceedance of an applicable 

requirement. In the Mercury and Air 

Toxics Rule, we require facilities to 

report direct measurements made with 

CEMS, such as gas concentrations, and 

we require hourly reporting of all 

measured and calculated emissions 

values (see discussion at 77 FR 9374, 

February 16, 2012). In particular, for the 

fenceline monitoring requirements in 

this final rule, we offer facilities options 

for delineating background benzene 

emissions and benzene emissions not 

attributable to the refinery, and we offer 

options for reduced monitoring, making 

it even more necessary that we have all 

of the data to review to ensure that 

testing and analyses are being done 

correctly and in compliance with the 

requirements set out in the regulations, 

and that root cause analyses and 

corrective actions are being performed 

where necessary. Therefore, as 

proposed, we are finalizing the 

requirements that facilities report the 

individual 2-week sampling period 

results for each monitor, in addition to 

the calculated DC values in their 

quarterly reporting. 

Regarding commenters’ concerns that 

facilities post accurate data and have 

sufficient time to perform quality 

assurance on the data, in the final rule, 

we have established provisions for how 

sources are to address outliers and data 

corrections. Additionally, as proposed, 

we do not require an initial report until 

facilities have collected 1 year of data so 

that facilities do not report the data 

until a rolling annual average value can 

be determined. This will allow refinery 

staff and analytical laboratories to iron 

out any issues that might arise as they 

implement these methods for the first 

time. Once this initial data collection 

period is complete, we anticipate that 

data quality issues should be infrequent. 

Therefore, we are providing a 45-day 

period following each quarterly period 

before facilities must submit the 

monitoring results, which should 

provide facilities adequate time to 

correct any data errors prior to reporting 

the data. 

Regarding comments that suggest 

reporting each 2-week sample result 

soon after its collection, we disagree. 

This frequency would put undue 

burden on the refinery owners or 

operators in trying to collect, review and 

quality assure the data prior to 

reporting. However, we agree with 

commenters that more frequent 

reporting of the fenceline monitoring 

data would be useful. Therefore, we 

have revised the reporting frequency for 

the fenceline monitoring data to be 

quarterly in the final rule rather than 

semiannually as proposed. 

Additionally, we understand that there 

is a lot of interest in how these data will 

be presented to the public, and we plan 

to reach out to all stakeholders on 

appropriate approaches for presenting 

this information in ways that are helpful 

and informative. 

b. Refinery MACT 2 

This section provides comment and 

responses for the key comments 

received regarding the technology 

review amendments proposed for 

Refinery MACT 2. Comment summaries 

and the EPA’s responses for additional 

issues raised regarding the proposed 

requirements resulting from our 

technology review are in the ‘‘Response 

to Comment’’ document in the public 

docket (Docket ID No. EPA–HQ–OAR– 

2010–0682). 

i. FCCU 

We received comments on the 

consideration of developments in 

pollution controls, the averaging time 

for FCCU PM limits, and the FCCU 

opacity limit, as discussed below. 

Comment: One commenter stated that 

the EPA failed to consider 

developments in pollution controls for 

HAP from FCCUs for two reasons. First, 

the commenter contended that cost is 

not a valid consideration to evaluate if 

a ‘‘development’’ in pollution control is 

necessary pursuant to section 

7412(d)(2), (3), (6), unless the EPA is 

setting a ‘‘beyond-the-floor’’ 

requirement. 

Second, the commenter claimed that 

the EPA’s review of developments is 

nearly 10 years old and misses some 

important pollution control 


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improvements in the industry. For 

example, the commenter noted that 

Valero Benicia installed a combination 

of controls in 2012 including a scrubber, 

SCR and CO Boiler that combine 

exhaust streams from the FCCU and 

coking and reportedly eliminate HAP 

emissions entirely from these sources. 

The commenter also asserted that EPA 

consent decrees impose lower effective 

limits on PM than the EPA considered 

under the technology review. The 

commenter identified the BP Whiting 

facility as subject to 0.7 lb PM/1,000 lbs 

coke burn-off at one FCCU and 0.9 lb 

PM/1,000 lbs coke burn-off at another 

and claimed these limits are lower than 

the 1.0 lb PM/1,000 lbs coke burn-off 

limit currently mandated by Refinery 

MACT 2. 

Response: We disagree that we cannot 

consider costs when determining if it is 

necessary to revise an existing MACT 

standard based on developments in 

practices, processes and control 

technologies. The commenter suggests 

that we cannot consider costs because of 

the requirements in CAA section 

112(d)(2) and (3) for establishing initial 

MACT standards and which do not 

allow for consideration of costs until the 

second, ‘‘beyond the floor’’ phase of the 

analysis. As discussed previously in this 

preamble where we respond to 

comments on the fenceline monitoring 

requirements, to the extent that the 

commenters are suggesting that EPA 

must re-perform the MACT floor 

analysis for purposes of setting a 

standard pursuant to section 112(d)(6), 

we note that the D.C. Circuit has 

rejected this argument numerous times, 

most recently in National Association 

for Surface Finishing et al. v. EPA No. 

12–1459 in the U.S. Court of Appeals for 

the District of Columbia. 

Regarding the claim that the EPA did 

not consider the types of controls at the 

Valero and BP facilities, we disagree. 

The control measures for both of those 

facilities are controls that existed at the 

time of the development of the MACT 

standard. Thus, we did not identify 

these technologies as developments in 

control technologies during the 

technology review. However, we did 

identify developments in processes or 

practices that reflect better control by 

the existing technology and we 

reviewed modified emission limits that 

reflect that better level of control. The 

commenter suggested that we failed to 

consider a level of zero when the Valero 

facility was able to achieve zero 

emissions through a combined SCR, 

boiler and scrubber. However, the 

commenter provided no information to 

support such a claim and we are 

skeptical that such a result could be 

achieved. We note that the SCR is 

designed specifically to reduce NOX

emissions, and would not be capable of 

reducing significantly, much less 

eliminating completely, HAP emissions. 

Similarly, based on our long-standing 

understanding of the processes, neither 

a boiler nor a scrubber could achieve 

such a result. Regarding the level of 

emissions achieved at the BP Whiting 

facility, we note that we evaluated 

control systems that can meet 0.5 lb PM/ 

1,000 lb coke burn-off, which is a lower 

limit than that at BP Whiting. We 

determined that these were costeffective to require for new units that 

are installing a new control system. 

However, we determined that 

retrofitting controls designed to meet a 

PM limit of 1.0 lb PM/1,000 lbs coke 

burn-off to now meet a limit of 0.5 lb 

PM/1,000 lbs coke burn-off was not 

cost-effective when considering PM and 

PM2.5 emissions reductions. We 

projected the cost of the 0.5 lb PM/1,000 

lbs coke burn-off limit in retrofit cases 

to be $23,000 per ton PM emissions 

reduced. To meet a limit of 0.7 lb PM/ 

1,000 lbs coke burn-off or 0.9 lb PM/

1,000 lbs coke burn-off, as is the case for 

BP Whiting, the retrofit costs would be 

similar to this 0.5 lb PM/1,000 lb coke 

burn-off option, but the reductions 

would be even less, resulting in costs 

over $23,000 per ton. As metal HAP 

content of FCCU PM is approximately 

0.1 to 0.2-percent of the total PM, the 

cost of requiring this lower limit for 

existing FCCU is over $10 million per 

ton of metal HAP reduced. Therefore, 

we determined that it is not necessary 

to revise the PM standard for existing 

FCCU sources. 

Comment: Refinery MACT 2 requires 

the owner or operator to demonstrate 

compliance with the PM FCCU limits by 

complying with the operating limits 

established during the performance test 

on a daily (i.e., 24-hour) average basis. 

Several commenters objected to the 

EPA’s proposal to revise this 

requirement to a 3-hour averaging time. 

Commenters restated EPA’s arguments 

for 3-hour averaging time as: (1) Daily 

average could allow FCCUs to exceed 

limits for short periods while still 

complying with the daily average, (2) 

consistency with NSPS subpart Ja and 

(3) consistency with duration of testing. 

The commenters stated that the EPA 

had not provided any data that show 

that the daily average could allow 

FCCUs to exceed limits for short periods 

and, therefore, the EPA is using a 

hypothetical compliance assurance 

argument to change emission limits. The 

commenters stated that a change in 

emission limits is not authorized by 

CAA section 112 because the emission 

limitations in Refinery MACT 2 for 

FCCUs were established as daily 

averages following the floor and ample 

margin of safety requirements in section 

112(d)(2) of the CAA. 

The commenters also state that the 

EPA’s additional arguments for the 

change to a 3-hour average are irrelevant 

and legally deficient. The commenters 

stated that the combination of a 

numerical emission limit and an 

averaging period frames the stringency 

of a limitation and that a reduction in 

either of those factors results in a 

significant lowering of the operating 

limit. The commenters conclude that 

the EPA has proposed to change the 

stringency of the requirements without 

justification, and the CAA requires that 

such a change in stringency be justified 

pursuant to CAA section 112(d)(6) or 

(f)(2). The commenters stated that 

increasing stringency for consistency 

with NSPS rules is not a criterion for a 

CAA section 112(d)(6) action. Rather 

that section requires a change to be due 

to ‘‘developments.’’ The only change in 

technology since the 2002 promulgation 

of Refinery MACT 2 is the availability 

of PM continuous emission monitoring 

system (CEMS), which is unproven. 

One commenter noted that changing 

the averaging time is a very significant 

modification considering that the 

compliance limits would apply for 

periods of SSM. This commenter stated 

that it is unlikely that existing 

operations can consistently be in 

compliance with a new 3-hour average 

since the current daily averaging was 

put in place to recognize that there will 

be periods of operating variability that 

do not represent the longer term 

performance of an FCCU. The 

commenters recommended that the EPA 

retain the daily averaging requirement. 

Response: We disagree with the 

commenters’ statement that reducing 

the averaging time from a 24-hour basis 

to a 3-hour basis for demonstrating 

compliance with the FCCU PM emission 

limit, using operating limits established 

during the performance test, is a change 

to the MACT floor. The emission limit 

of 1.0 lb PM/1,000 lbs coke burn-off is 

the MACT floor, and we are not 

changing the PM emissions limit (or 

alternate Ni limits) in Table 1 to subpart 

UUU (except to remove the incremental 

PM limit that did not comport with the 

MACT floor emissions limitation). 

However, whether or not it is a 

change from the MACT floor is not 

relevant. Pursuant to CAA section 

112(d)(6), the EPA must revise MACT 

standards ‘‘as necessary’’ considering 

developments in practices, processes 

and control technologies. For this 


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exercise, we considered any of the 

following to be a ‘‘development’’: 

• Any add-on control technology or 

other equipment that was not identified 

and considered during development of 

the original MACT standards. 

• Any improvements in add-on 

control technology or other equipment 

(that were identified and considered 

during development of the original 

MACT standards) that could result in 

additional emissions reduction. 

• Any work practice or operational 

procedure that was not identified or 

considered during development of the 

original MACT standards. 

• Any process change or pollution 

prevention alternative that could be 

broadly applied to the industry and that 

was not identified or considered during 

development of the original MACT 

standards. 

• Any significant changes in the cost 

(including cost effectiveness) of 

applying controls (including controls 

the EPA considered during the 

development of the original MACT 

standards). 

In determining whether there are 

‘‘developments,’’ we review, among 

other things, EPA regulations 

promulgated after adoption of the 

MACT, such as the NSPS we identified 

in this instance. We identified the 

enhanced monitoring requirements for 

these operating limits as a development 

in practices that will help ensure FCCU 

owners or operators are properly 

operating control devices and, thus, are 

meeting the PM emission limit at all 

times. We further determined that this 

enhanced monitoring was cost effective 

and proposed that it was necessary to 

revise the existing standard pursuant to 

CAA section 112(d)(6). 

While we do not have continuous PM 

emissions data that show actual 

deviations of the PM limit, we do not 

need such data in order to conclude that 

such deviations could occur when daily 

averages are used. The Refinery MACT 

2 (i.e., subpart UUU) rule requires 

owners or operators to establish 

operating limits based on three 1-hour 

runs during the performance test. As a 

matter of simple mathematics, a source 

could demonstrate that it is meeting the 

operating limit based on a 24-hour 

average but could be exceeding the 1.0 

lb PM/1,000 lbs coke burn-off emission 

limit based on a 24-hour average or for 

one or more individual 3-hour periods 

during that 24-hour average. For 

example, an owner or operator could 

operate with a power input 5-percent 

higher than the operating limit for 23 

hours, have the ESP off (zero power) for 

one hour, and still comply with a 24- 

hour average operating limit. However, 

it would be difficult for this same unit 

to meet the 1.0 lb PM/1,000 lbs coke 

burn-off emissions limit over a 24-hour 

period, and it certainly would not meet 

the limit for every 3-hour period during 

that day. As the operating limit can be 

established to correspond with 1.0 lb 

PM/1,000 lbs coke burn-off, the 5- 

percent higher power input would 

likely correspond with a 0.95 lb PM/

1,000 lbs coke burn-off emissions rate 

(5-percent lower). Uncontrolled 

emissions are typically 6 to 8 lbs/1,000 

lbs coke burn-off. Thus, this unit would 

have emissions averaging approximately 

1.2 lbs PM/1,000 lbs coke burn-off 

during this 24-hour period [i.e., 

(0.95*23+7)/24], but would be in 

compliance with the 24-hour average 

operating limit. The unit would 

obviously also be out of compliance 

with the 3-hour average over the period 

when the power was turned off. We also 

have concerns that the operating limits 

are not always linear with the 

emissions, so that the longer averaging 

times do not effectively ensure 

compliance with the PM emissions 

limit. Therefore, as proposed, we are 

finalizing the requirement for owners or 

operators to comply with the operating 

limits on a 3-hour basis, rather than the 

24-hour basis currently in the rule. 

Comment: The technology review for 

FCCUs resulted in the EPA proposing to 

remove the 30-percent opacity 

alternative limit for demonstrating 

compliance with the PM emissions limit 

that is available for refineries complying 

with the Refinery NSPS 40 CFR part 63, 

subpart J. Two commenters supported 

the EPA’s proposed removal of the 30- 

percent opacity limit for FCCUs. Other 

commenters stated that current 

technology is good enough for a 10- or 

20-percent opacity limit. On the other 

hand, several commenters stated that 

the proposed removal of the 30-percent 

opacity limit must meet the criteria 

specified in CAA section 112(d)(6) and 

(f)(2), which requires analysis of the 

statutory basis, environmental impacts, 

costs, operational and compliance 

feasibility and impacts, that the EPA has 

not conducted. The commenters 

claimed that had the EPA conducted a 

proper analysis, the EPA would have 

determined that the proposed change to 

remove the 30-percent opacity limit is 

not necessary or supportable. 

Additionally, these commenters stated 

that since the underlying PM emissions 

limit is unchanged, there is no emission 

reduction justification for this proposed 

change, and the change would not meet 

the CAA section 112(d)(6) requirement 

of being cost effective. The commenters 

also noted that processes or practices for 

existing FCCUs have not changed, as 

required for a CAA section 112(d)(6) 

revision. 

Several commenters urged the EPA to 

maintain the 30-percent opacity limit 

for these FCCUs. As a practicable and 

cost-effective alternative to address the 

EPA’s concern as to whether 

compliance with a 30-percent opacity 

limit ensures compliance with the PM 

emissions limit, commenters suggested 

annual performance tests to confirm that 

the FCCU is meeting the PM emissions 

limit, rather than performance tests 

every 5 years, as proposed. 

One commenter stated that the EPA 

never intended for the opacity limit in 

Refinery NSPS subpart J to be used to 

demonstrate compliance with the PM 

emissions limit, but instead to assure 

the PM controls operate properly. The 

commenter stated that the EPA’s 

conclusion that the 30-percent opacity 

limit may not be sufficiently stringent to 

ensure compliance with the underlying 

PM emissions limit is based on a false 

premise as to the purpose of the opacity 

standard because as the EPA states, 

‘‘Opacity of emissions is indicative of 

whether control equipment is properly 

maintained and operated.’’ 

Several commenters stated that the 

proposed elimination of the 30-percent 

opacity limit currently in Refinery 

MACT 2 leaves existing FCCUs that use 

cyclones with no viable alternative 

approach to demonstrate compliance 

with the PM emissions limit without 

adding or replacing controls. They 

stated the other approaches for 

demonstrating compliance with the PM 

emissions limit in Refinery MACT 2 

(such as development of a site-specific 

opacity limit) do not work for them. The 

commenters stated that although they 

believe that more frequent performance 

tests would show that the FCCUs are in 

fact meeting the PM emissions limit, the 

absence of the 30-percent opacity limit 

would force FCCUs using cyclones for 

PM control to install additional, costly 

PM controls (e.g., ESPs or wet gas 

scrubbers). They projected that these 

additional controls would cost tens of 

millions of dollars per FCCU and would 

require at least 3 years of compliance 

time. Additionally, one commenter 

stated that even FCCUs with additional 

downstream PM controls would not be 

able to achieve a site-specific limit at all 

times and needed the availability of the 

alternative 30-percent opacity limit. One 

commenter estimated that installing an 

ESP to meet the proposed 10-percent 

opacity limit would cost approximately 

$121,000/ton, assuming a 32 tpy PM 

emission reduction. The commenter 

noted that the ESP would also increase 

GHG emissions and require more energy 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75203 

9Compliance Investigations and Enforcement of 

Existing Air Emission Regulations at Region 5 

Petroleum Refineries. U.S. Environmental 

Protection Agency, Region 5—Air and Radiation, 

Chicago, Illinois. March 9, 1998. 

resources from the facility. The 

commenter concluded that installing an 

ESP is neither cost effective nor 

appropriate considering non-air quality 

environmental and health impacts and 

energy requirements, and recommended 

that the EPA maintain the current NSPS 

subpart J alternative limits and add 

additional alternative limits into 

Refinery MACT 2 only as optional limits 

for demonstrating compliance with the 

PM emissions limit. 

Response: In promulgating Refinery 

MACT 2, the EPA identified the 1.0 lb 

PM/1,000 lbs coke burn-off limit as the 

MACT floor but allowed a compliance 

option for FCCUs subject to Refinery 

NSPS subpart J to comply with an 

opacity limit up to 30 percent with one 

6-minute allowance to exceed the 30- 

percent opacity in any 1-hour period. As 

stated in the proposal, compliance 

studies have shown that the 30-percent 

opacity limit does not correlate well 

with the 1.0 lb PM/1,000 lbs coke burnoff limit, and that an FCCU can comply 

with the 30-percent opacity limit while 

its emissions exceed the PM emissions 

limit.9 Regardless of whether the 30- 

percent opacity limit in Refinery NSPS 

subpart J was designed to ‘‘ensure that 

the control device was operated 

properly,’’ Refinery MACT 2 allows 

sources subject to NSPS subpart J to use 

the 30-percent opacity limit to 

demonstrate continuous compliance 

with the PM emissions limit. We have 

determined that the 30-percent opacity 

limit is inadequate for the purpose of 

demonstrating continuous compliance 

with the PM emissions limits in 

Refinery MACT 2. As such, we 

proposed to remove this opacity limit 

and require the owner or operator to 

either demonstrate compliance with the 

PM emissions limit by continuously 

monitoring the control device 

parameters established during the 

performance test or establish and 

monitor a site-specific opacity limit. For 

clarity, we note that we proposed to 

allow a site-specific opacity limit, not a 

10-percent opacity limit as some 

commenters suggest. The site-specific 

opacity limit can be significantly higher 

than 10 percent, but it cannot be lower 

than 10 percent. 

While the compliance study indicates 

that a 30-percent opacity limit does not 

correlate well with a 1.0 lb PM/1,000 lbs 

coke burn-off emissions limit, further 

review of this same study indicates that 

a 20-percent opacity limit provides a 

reasonable correlation with units 

meeting the 1.0 lb PM/1,000 lbs coke 

burn-off emissions limit. We also 

reviewed the data submitted by the 

commenters regarding PM emissions 

and opacity correlation. While the data 

suggest that there is variability and 

uncertainty in the PM/opacity 

correlation, the data do not support that 

a 30-percent opacity limit would ensure 

compliance even when considering the 

uncertainty associated with the PM/

opacity correlation. Based on the 

variability of the 3-run average opacity 

limits, we determined that, if the 3-hour 

average opacity exceeded 20-percent, 

then it was highly likely (98 to 99- 

percent confidence) that the FCCU 

emissions from the unit tested would 

exceed the PM emissions limit. 

After considering the public 

comments, reviewing the data submitted 

with those comments, and further 

review of the compliance study, in this 

final rule we are adding a 20-percent 

opacity limit, evaluated on a 3-hour 

average basis for units subject to NSPS 

subpart J. As we noted above, a 20- 

percent opacity limit provides a 

reasonable correlation with the PM 

emissions limit, and an exceedance of 

this 20-percent opacity limit will 

provide evidence that the PM emissions 

limit is exceeded. However, it is 

possible that units could still exceed the 

PM emissions limit while complying 

with the 20-percent opacity limit, if 

those units operate close to the 1 lb PM/ 

1,000 lbs coke burn-off emissions limit. 

To address this concern, we considered 

the commenters’ suggestion to require a 

performance test annually rather than 

once every 5 years. Some commenters 

suggested that this option specifically 

apply to FCCUs with cyclones, but this 

option is applicable to any control 

system operating very near the PM 

emissions limit and using an opacity 

limit to demonstrate continuous 

compliance. We have determined that 

the Refinery NSPS subpart J compliance 

procedures in Refinery MACT 2, in 

combination with a 20-percent opacity 

limit demonstrated on a 3-hour average 

basis and with annual performance tests 

when a test indicates PM emissions are 

greater than 80-percent of the limit (i.e., 

0.80 lb PM/1,000 lbs coke burn-off), will 

ensure continuous compliance with the 

PM emissions limit. FCCUs with 

measured PM emissions during the 

performance test at or below 0.80 lb PM/ 

1000 lbs of coke burn-off will remain 

subject to the requirement to conduct 

performance tests once every 5 years, 

consistent with the requirements we 

proposed. 

We do not agree with commenters 

that the proposed opacity revision 

would add significant cost or 

compliance burden. The control devicespecific monitoring parameters that 

were proposed rely on parameters 

commonly used to control the operation 

of the control device, so the monitoring 

systems should be already available. 

Further, since we are merely changing 

the opacity limit, we expect these units 

will already have opacity monitoring 

systems needed to demonstrate 

compliance with the PM emissions limit 

and would not incur costs for new 

equipment. 

Comment: Several commenters stated 

that they agree with the EPA’s 

determination in the proposal that the 

current CO limits provide adequate 

control of HCN. Two commenters stated 

that there are limited HCN emissions 

data and that more data are needed 

before the Agency can appropriately 

determine whether an HCN standard is 

necessary and justified. One commenter 

noted that the process undertaken by 

the EPA to estimate HCN emissions was 

flawed, and likely overestimates HCN 

emissions significantly. Another 

commenter stated that they performed 

HCN stack testing at three refineries and 

subsequent modeling at two refineries 

and concluded that the ambient HCN 

emissions were well below the 

applicable health limits. 

In contrast, some commenters 

expressed concerns about high HCN 

levels. One commenter stated that the 

EPA should consider re-evaluating the 

benefit of low NOX emissions from the 

FCCU, if that is indeed the cause of 

higher HCN emissions, because 

exposing people to HCN is not 

acceptable. The commenter also noted 

that the community now also has the 

increased dangers of storing and 

transporting aqueous ammonia, which 

is used in some cases to achieve low 

NOX emissions from the FCCU. 

One commenter stated that the EPA 

must set stronger HCN standards on 

FCCU emissions because of the high 

release amounts reported, the fact that 

non-cancer risk is driven by emissions 

of HCN from FCCU, and the fact that the 

EPA has never set standards for HCN 

emissions. The commenter provided a 

report that they believe shows that the 

EPA has not shown that CO is a 

reasonable or lawful surrogate to control 

HCN and has not shown that the 

conditions necessary for a surrogate are 

met with regard to CO and HCN, which 

is an inorganic nonmetallic HAP. 

Further, the report indicates that SCR is 

a reasonable and cost effective method 

for controlling HCN and that the EPA 

failed to review and consider other 

viable methods to control HCN and 

must do so to satisfy its legal obligations 

in this rulemaking. 


tkelley on DSK3SPTVN1PROD with RULES2
75204 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

10U.S. EPA, 2001. Petroleum Refineries: Catalytic 

Cracking Units, Catalytic Reforming Units, and 

Sulfur Recovery Units—Background Information for 

Promulgated Standards and Response to Comments. 

Final Report.EPA–453/R–01–011. June. p. 1–19. 

Response: At the time we 

promulgated the MACT, we determined 

that the control strategy used by the best 

performing facilities to reduce organic 

HAP emissions was the use of complete 

combustion, which occurs when the CO 

concentration is reduced to 500 ppmv 

(see the proposal for Refinery MACT 2 

at 63 FR 48899, September 11, 1998). 

We rejected arguments that some 

facilities operate at CO levels well 

below 500 ppmv and, thus, the MACT 

floor should be set at a lower CO 

concentration because once CO 

concentrations reached 500 ppmv, there 

was no longer a correlation between 

reduced CO concentrations and reduced 

HAP concentrations. And, in fact, 

emissions of certain HAP, such as 

formaldehyde, tended to increase as CO 

concentrations were reduced below 500 

ppmv.10

In the current rulemaking action, we 

determined at the time of the proposed 

rule that this also holds true for HCN 

emissions. That is, once CO emissions 

are reduced to below 500 ppmv (i.e., 

complete combustion is achieved), we 

no longer see a direct correlation 

between CO concentrations and HCN 

emissions. 

All of the HCN emissions data we 

have were reported from units operating 

at or below the 500 ppmv CO limit (i.e., 

in the complete combustion range), so it 

is not surprising that there is not a 

strong correlation between CO and HCN 

from the FCCU ICR source test data. 

However, catalyst vendor data and 

combustion kinetic theory support the 

fact that, in the partial burn mode (with 

CO concentrations of 2 to 6-percent, 

which is 20,000 to 60,000 ppmv), HCN 

concentrations exiting the FCCU 

regenerator are much greater than for 

units using complete combustion FCCU 

regenerators or the concentration exiting 

a post-combustion device used in 

conjunction with a partial burn FCCU 

regenerator. Therefore, we maintain that 

complete combustion is the primary 

control needed to achieve controlled 

levels of HCN emissions. 

We initially thought the higher levels 

of HCN emissions that were reported by 

sources achieving complete combustion 

might be due to a switch away from 

platinum-based combustion promoters 

to palladium-based combustion 

promoters. However, many of the units 

that were tested and that had some of 

the lowest HCN emissions used 

palladium-based oxygen promoters. 

Therefore, it appears unlikely that 

palladium-based catalyst promoters are 

linked to the higher HCN emissions. We 

also evaluated one commenter’s 

argument that CO is not a good 

surrogate for HCN emissions, but that 

SCR are a reasonable and cost-effective 

control strategy. We are not aware of 

any data that suggest that an SCR 

removes HCN and the commenter did 

not provide any support for that 

premise. At proposal, we evaluated 

HCN control on units using extra 

oxygen or converting back to platinumbased promoters to oxidize any HCN 

formed. This would cause more NOX

formation, which would then require 

post-combustion NOX control, such as 

an SCR. However, if HCN emissions are 

not a function of CO concentration 

beyond that required to achieve 

complete combustion (as noted by the 

commenter), then more aggressive 

combustion conditions and the use of an 

SCR (to remove the NOX formed) may 

not be a viable control strategy. 

Therefore, considering all of the data 

currently available and the comments 

received regarding HCN emissions and 

controls, we maintain that the only 

proven control technique is the use of 

complete combustion as defined by a 

CO level of 500 ppmv or less. We are 

not establishing a more stringent CO 

level because, once complete 

combustion is achieved, (i.e., CO 

concentrations drop below 500 ppmv), 

no further reduction in HCN emissions 

are achieved. 

For the purposes of Refinery MACT 2, 

we consider the emission limits and 

operating requirements for organic HAP 

in Tables 8 through 14 to subpart UUU 

of part 63 adequate to also limit HCN 

emissions. 

Finally, we understand concerns 

about the reported HCN emissions being 

higher than anticipated and the need for 

more data to better determine HCN 

emissions levels. To address these 

concerns, we are finalizing a 

requirement that facility owners or 

operators conduct a performance test for 

HCN from all FCCU at the same time 

they conduct the first PM performance 

test on the FCCU following 

promulgation of this rule. Facility 

owners or operators that conducted a 

performance test for HCN from a FCCU 

in response to the refinery ICR or 

subsequent to the 2011 Petroleum 

Refinery ICR following appropriate 

methods are not required to retest that 

FCCU. 

4. What is the rationale for our final 

approach for the technology review? 

a. Refinery MACT 1 

We did not receive substantive 

comments concerning our proposal that 

it was not necessary to revise Refinery 

MACT 1 requirements for MPV, gasoline 

loading racks and cooling towers/heat 

exchange systems. Based on the 

rationale provided in the preamble to 

the proposed rule, we are taking final 

action concluding that it is not 

necessary pursuant to CAA section 

112(d)(6) to revise the MACT 

requirements for MPV, gasoline loading 

racks and cooling towers/heat exchange 

systems emission sources at refineries. 

We proposed that the options for 

additional wastewater controls are not 

cost effective and thus it was not 

necessary to revise the MACT for these 

emission sources. We received public 

comments suggesting that emissions 

from wastewater systems are higher 

than modeled and that we should 

develop additional technology 

standards for wastewater treatment 

systems regardless of cost. As we 

discussed in the proposal, emissions 

from wastewater are difficult to measure 

and emission estimates rely on process 

data and empirical correlations, which 

introduces uncertainty into the 

estimates. Although we do not have 

evidence, based on the process data we 

collected, that emissions are higher than 

modeled at proposal, we note that the 

fenceline monitoring program 

effectively ensures that wastewater 

emissions are not significantly greater 

than those included in the emissions 

inventory and modeled in the risk 

assessment. Furthermore, we believe 

that cost is a valid consideration in 

determining whether it is necessary 

within the meaning of section 112(d)(6) 

to revise requirements and that we are 

not required to establish additional 

controls regardless of cost. 

Consequently, we conclude that it is not 

necessary to revise the Refinery MACT 

1 requirements for wastewater systems 

pursuant to CAA section 112(d)(6). 

For storage vessels, we identified a 

number of options, including requiring 

tank fitting controls for external and 

internal floating roof tanks, controlling 

smaller tanks with lower vapor 

pressures and requiring additional 

monitoring to prevent roof landings, 

liquid level overfills and to identify 

leaking vents as developments in 

practices, processes and control 

technology. We proposed to crossreference the storage vessel 

requirements in the Generic MACT 

(effectively requiring additional control 

for tank roof fittings) and to revise the 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75205 

definition of Group 1 storage vessels to 

include smaller tanks with lower vapor 

pressures. We received comments that 

we could have required additional 

controls on tanks and monitoring for 

landings, overfills and leaking vents 

described above. We also received 

comments related to clarifications of 

specific rule references and overlap 

provisions. We addressed these 

comments in the ‘‘Response to 

Comments’’ document, and we maintain 

that the additional control options 

described by the commenters (tank roof 

landing/degassing requirements or use 

of geodesic domes to retrofit external 

floating roofs) are not cost-effective. 

Consequently, based on the rationale 

provided in the preamble to the 

proposed rule and our consideration of 

public comments, we are finalizing the 

requirements as proposed with minor 

clarifications of the rule references. 

However, as with wastewater systems, 

we note that the fenceline monitoring 

program will ensure that the owner or 

operator is effectively managing fugitive 

emissions sources and should detect 

landings, overfills, and leaking vents. 

For equipment leaks, we identified 

specific developments in practices, 

processes and control technologies that 

included requiring repair of leaking 

components at lower leak definitions, 

requiring monitoring of connectors, and 

allowing the use of the optical imaging 

camera as an alternative method of 

monitoring for leaks. We proposed to 

establish an alternative method for 

refineries to meet LDAR requirements in 

Refinery MACT 1. This alternative 

would allow refineries to monitor for 

leaks via optical gas imaging in place of 

EPA Method 21, using monitoring 

requirements to be specified in a not yet 

proposed appendix K to 40 CFR part 60. 

However, the development of appendix 

K is taking longer than anticipated. 

Therefore, we are not finalizing this 

alternative monitoring method in 

Refinery MACT 1. 

We received comments suggesting 

that additional requirements be imposed 

to further reduce emissions from leaking 

equipment components, such as 

requiring ‘‘leakless’’ equipment, 

reducing the leak threshold, and 

eliminating delay of repair provisions. 

As provided in the ‘‘Response to 

Comments’’ document, we do not agree 

that these additional requirements are 

cost-effective. Based on the rationale 

provided in the preamble to the 

proposed rule and our consideration of 

public comments, we conclude that it is 

not necessary to revise the Refinery 

MACT 1 requirements for equipment 

leaks. Again, however, the fenceline 

monitoring program is intended to 

ensure that large leaks from fugitive 

emissions sources, including equipment 

leaks, are more quickly identified and 

repaired, thereby helping to reduce 

emissions from leaking equipment 

components. 

For marine vessel loading, we 

identified control of marine vessel 

loading operations with HAP emissions 

of less than 10/25 tpy and the use of 

lean oil absorption systems as 

developments that we considered in the 

technology review. We proposed to 

amend 40 CFR part 63, subpart Y to 

require small marine vessel loading 

operations (i.e., operations with HAP 

emissions less than 10/25 tpy) and 

offshore marine vessel loading 

operations to use submerged filling 

based on the cargo filling line 

requirements in 46 CFR 153.282. We 

received comments that other options 

considered during the technology 

review of the standard were costeffective for small marine vessel loading 

operations and should be required. As 

provided in the ‘‘Response to 

Comments,’’ we continue to believe 

those other controls are not costeffective because of the high costs of 

controls for limited additional organic 

HAP emission reduction. Therefore, we 

are finalizing these amendments as 

proposed. 

Finally, we proposed that it was 

necessary to revise the MACT to require 

fenceline monitoring as a means to 

manage fugitive emissions from the 

entire petroleum refinery, which 

includes sources such as wastewater 

collection and treatment operations, 

equipment leaks and storage vessels. We 

received numerous comments regarding 

the proposed requirement to conduct 

fenceline monitoring, many of which we 

address above and the remainder of 

which we respond to in the ‘‘Response 

to Comments’’ document. After 

considering comments, we maintain 

that the proposed work practice 

standard is authorized under section 

112 of the CAA and will improve 

fugitive management at the refinery. 

Therefore, we are finalizing the key 

components of fenceline monitoring 

work practice as proposed. These 

requirements include the use of passive 

diffusive tube samplers (although we are 

providing a mechanism to request 

approval for alternative monitoring 

systems provided certain criteria are 

met), the 9 mg/m3 on a rolling annual 

average basis action level, and the need 

to perform corrective action to comply 

with the action level. 

Based on public comments received, 

we are making numerous revisions to 

clarify the fenceline monitor siting 

requirements. This includes provisions 

to allow siting of monitors within the 

property boundary as long as all 

emissions sources at the refinery are 

included within the monitoring 

perimeter. We are also clarifying that we 

do not consider public roads or public 

waterways that bisect a refinery to be 

property boundaries, and owners or 

operators do not need to place monitors 

along the internal public right-of-ways. 

We are also providing provisions to 

allow fixed placement of monitors at 

500 feet intervals (with a minimum of 

3 monitors) for subareas or segregated 

areas. If an emissions source is near the 

monitoring perimeter, an additional 

monitor siting requirement would still 

apply. The 500 feet provision is 

provided to reduce burden for facilities 

with irregular shapes or noncontiguous 

property areas that we did not fully 

consider at proposal. 

We also received comments on the 

compliance time and reporting 

requirements associated with the 

fenceline monitoring provisions. Upon 

consideration of public comments, we 

have revised the compliance period to 2 

years after the effective date of the final 

rule. Thus, beginning no later than 2 

years after the effective date of the rule, 

the source must have a fenceline 

monitoring system that is collecting 

samples such that the first rolling 

annual average DC value would be 

completed no later than 3 years after the 

effective date of the final rule. Facilities 

will have 45 days after the completion 

of the first year of sampling, as 

proposed, to submit the initial data set. 

We are reducing the proposed 

compliance period from 3 years to 2 

years because the passive diffusive tube 

monitors are easy to deploy and pilot 

study demonstrations indicate that 

significant time is not needed to deploy 

the monitors. However, the reduced 

compliance period still provides time to 

resolve site-specific monitor placement 

issues and to provide time to develop 

and implement a site-specific 

monitoring plan, if needed. We are 

increasing the fenceline monitoring 

reporting frequency (after the first year 

of data collection) from semiannually to 

quarterly to provide more timely 

dissemination of the data collected via 

this monitoring program. 

b. Refinery MACT 2 

We proposed to revise Refinery 

MACT 2 to incorporate the 

developments in monitoring practices 

and control technologies reflected in the 

Refinery NSPS subpart Ja limits and 

monitoring provisions (73 FR 35838, 

June 24, 2008). We are finalizing most 

of these provisions as proposed. 

Specifically, we are incorporating the 


tkelley on DSK3SPTVN1PROD with RULES2
75206 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

11The EPA has authority under CAA section 

112(d)(2) and (d)(3) to set MACT standards for 

previously unregulated emission points. EPA also 

retains the discretion to revise a MACT standard 

under the authority of section 112(d)(2) and (3), see 

Portland Cement Ass’n v. EPA, 665 F.3d 177, 189 

(D.C. Cir. 2011), such as when it identifies an error 

in the original standard. See also Medical Waste 

Institute v. EPA, 645 F. 3d at 426 (upholding EPA 

action establishing MACT floors, based on postcompliance data, when originally-established floors 

were improperly established). 

Refinery NSPS subpart Ja PM limit for 

new FCCU sources. We are also 

finalizing compliance options for FCCU 

that are not subject to Refinery NSPS 

subpart J or Ja. These options would 

allow such sources to elect to comply 

with the Refinery NSPS subpart Ja 

monitoring provisions to demonstrate 

compliance with the emissions PM 

limit. We are revising the averaging 

period for the control device operating 

limits or site-specific opacity limits to 

be on a 3-hour average basis in order to 

more directly link the operating limit to 

the duration of the performance test 

runs, on which they are based, as 

proposed. We are incorporating 

additional control device-specific 

monitoring alternatives for various 

control devices on FCCU, including 

BLD monitoring as an option to COMS 

for owners or operators of FCCU using 

fabric filter-type control systems and 

total power and secondary current 

operating limits for owners or operators 

of ESPs. We are adding an additional 

requirement to perform daily checks of 

the air or water pressure to atomizing 

spray nozzles for owners or operators of 

FCCU wet gas scrubbers not subject to 

the pressure drop operating limit, as 

proposed. Finally, we finalizing 

requirements to conduct a performance 

test at least once every 5 years for all 

FCCU, as proposed. These requirements 

are being finalized to ensure that control 

devices are continuously operated in a 

manner similar to the operating 

conditions of the performance test and 

to ensure that the emissions limits, 

which are assessed based on the results 

of three 1-hour test runs, are achieved 

at all times. 

We also proposed to eliminate the 

Refinery NSPS subpart J compliance 

option that allows refineries to meet the 

30-percent opacity emissions limit 

requirement and revise the MACT to 

include control device operating limits 

or site-specific opacity limits identical 

to those required in Refinery NSPS 

subpart Ja. We received numerous 

comments, particularly from owners or 

operators of FCCU that employ tertiary 

cyclones to control FCCU PM emissions. 

According to the commenters, opacity is 

not a direct indicator of PM emissions 

because finer particles will increase 

opacity readings without a 

corresponding mass increase in PM 

emissions. Additionally, the 

commenters stated that the site-specific 

opacity limit generally leads to a sitespecific operating limit of 10-percent 

opacity, which is too stringent and does 

not adequately account for variability 

between PM emissions and opacity 

readings. According to the commenters, 

FCCU with tertiary cyclones would 

need to be retrofitted with expensive 

and costly controls in order to meet the 

10-percent opacity limit, even though 

they are meeting the 1 lb/1000 lbs coke 

burn PM emissions limit. It was not our 

intent to require units to retrofit their 

controls simply to meet the site-specific 

opacity limit. However, the existing 30- 

percent opacity limit in the subpart J 

compliance option is not adequate to 

ensure compliance with the PM 

emissions limit at all times. After 

reviewing the public comments and 

available data, we determined that, 

rather than removing the subpart J 

compliance option altogether, it is 

sufficient to add an opacity operating 

limit of 20-percent opacity determined 

on a 3-hour average basis to the existing 

subpart J compliance option and to 

require units complying with this 

operating limit to conduct annual 

performance tests (rather than one every 

5 years) when the PM emissions 

measured during the source test are 

greater than 0.80 lb PM/1,000 lbs coke 

burn-off. These provisions improve 

assurance that these units are, in fact, 

achieving the required PM emissions 

limitation without requiring units to 

retrofit controls due to variability in the 

correlation of PM emissions and 

opacity. 

We did not propose to revise the 

organic HAP emissions limits for FCCU 

to further address HCN emissions. We 

received numerous comments on this 

issue. We continue to believe that 

complete combustion is the appropriate 

control needed to control HCN 

emissions. Consequently, for the 

purposes of Refinery MACT 2, we are 

not changing the MACT standards to 

further reduce emissions of HCN. 

However, we understand that there are 

uncertainties and high variability in 

HCN emissions measured from FCCU. 

In order to address the need for more 

data to better characterize HCN 

emissions levels, we are finalizing a 

requirement for refinery owners or 

operators to conduct a performance test 

for HCN from all FCCU (except those 

units that were tested previously using 

acceptable methods as outlined in the 

2011 Refinery ICR) during the first PM 

test required as part of the on-going 

compliance requirements for FCCU 

metal HAP emissions. These data will 

be useful to the EPA in understanding 

HCN emissions from FCU and may help 

to inform future regulatory reviews for 

this source category. 

We proposed that there have been no 

developments in practices, processes, 

and control technologies for CRU based 

on our technology review and that 

therefore it is not necessary to revise 

these standards. Based on the rationale 

provided in the preamble to the 

proposed rule and our consideration of 

public comments, we are finalizing our 

conclusion. 

For SRU, we identified the Refinery 

NSPS subpart Ja allowance for oxygenenriched air as a development in 

practice and we proposed that it was 

necessary to revise the MACT to allow 

SRU to comply with Refinery subpart Ja 

as a means of complying with Refinery 

MACT 2. The key issue identified by 

commenters was that Refinery NSPS 

subpart Ja includes a flow monitoring 

alternative for determining the average 

oxygen concentration in the enriched air 

stream and that this was not included in 

the proposed amendments to Refinery 

MACT 2. This was an oversight on our 

part. We are, based on the rationale 

provided in the preamble to the 

proposed rule and our consideration of 

public comments, finalizing the SRU 

revisions as proposed but with 

inclusion of the flow monitoring 

alternative provisions that are in 

Refinery NSPS subpart Ja for this 

source. 

C. Refinery MACT Amendments 

Pursuant to CAA Section 112(d)(2) and 

(d)(3) 

1. What did we propose pursuant to 

CAA section 112(d)(2) and (d)(3) for the 

Petroleum Refinery source categories? 

We proposed the following revisions 

to the Refinery MACT 1 and 2 standards 

pursuant to CAA section 112(d)(2) and 

(3) 11: (1) Adding MACT standards for 

DCU decoking operations; (2) revising 

the CRU purge vent pressure exemption; 

(3) adding operational requirements for 

flares used as APCD in Refinery MACT 

1 and 2; and (4) adding requirements 

and clarifications for vent control 

bypasses in Refinery MACT 1. 

For DCU, we proposed to require that 

prior to venting or draining, each coke 

drum must be depressured to a closed 

blowdown system until the coke drum 

vessel pressure is 2 psig or less. As 

proposed, the 2 psig limit would apply 

to each vessel opening/venting/draining 

event at new or existing affected DCU 

facilities. 

For the CRU, we proposed to require 

that any emissions during the active 


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purging or depressuring of CRU vessels 

meet the applicable organic HAP 

emission limitations in Tables 15 and 16 

to subpart UUU regardless of the vessel 

pressure. 

For flares, we proposed to remove 

cross references to the General 

Provisions requirements for flares used 

as control devices at 40 CFR 63.11(b) 

and to incorporate enhanced flare 

operational requirements directly into 

the Refinery MACT rules. The proposed 

rule amendments included: 

• A ban on flaring of halogenated 

vent streams. 

• A requirement to operate with 

continuously lit pilot flames at all times 

and to equip the pilot system with an 

automated device to relight the pilot if 

it is extinguished. 

• A requirement to operate with no 

visible emissions except for periods not 

to exceed a total of 5 minutes during 

any 2 consecutive hours and to monitor 

for visible emissions daily. 

• A requirement to operate with the 

flare tip velocity less than 60-feet-persecond or the velocity limit calculated 

by an equation provided in the 

proposed rule. 

• A requirement to meet one of three 

combustion zone gas properties 

operating limits based on the net 

heating value, lower flammability limit, 

or combustion concentration. Owners or 

operators could elect to comply with 

any one of the three limits at any time. 

Two separate sets of operating limits 

were proposed: One for gas streams not 

meeting all three ‘‘hydrogen-olefin 

interaction criteria’’ specified in the rule 

and a more stringent set of limits for gas 

streams meeting all three hydrogenolefin interaction criteria. The 

combustion zone net heating value 

considered steam assist rates but not 

‘‘perimeter air’’ assist rates. 

• For air-assisted flares, a 

requirement to meet an additional 

‘‘dilution parameter’’ operating limit 

determined based on the combustion 

zone net heating values above, the 

diameter of the flare and the perimeter 

air assist rates. 

The proposed amendments for flares 

also included detailed monitoring 

requirements to determine these 

operating parameters either through 

continuous parameter monitoring 

systems or grab sampling, detailed 

calculation instructions for determining 

these parameters on a 15-minute block 

average, and detailed recordkeeping and 

reporting requirements. We also 

proposed provisions to allow owners or 

operators to request alternative 

emissions limitations that would apply 

in place of the proposed operating 

limits. 

We proposed to revise the definition 

of MPV to remove the current exclusion 

for in situ sampling systems (onstream 

analyzers). We also proposed to limit 

the exclusion for gaseous streams routed 

to a fuel gas system to apply only to 

those systems for which any flares 

receiving gas from the fuel gas system 

are in compliance with the proposed 

flare monitoring and operating limits. 

We note that we also proposed revisions 

related to monitoring of bypass lines, 

but these revisions were proposed to 

address concerns related to SSM 

releases and are described in further 

detail in section IV.D. of this preamble. 

We proposed that emissions of HAP 

may not be discharged to the 

atmosphere from PRD in organic HAP 

service to address concerns related to 

SSM releases. To ensure compliance 

with this proposed amendment, we 

proposed to require that sources 

monitor PRD using a system that is 

capable of identifying and recording the 

time and duration of each pressure 

release and of notifying operators that a 

pressure release has occurred. This 

proposed requirement was addressed in 

section IV.A.4. of the preamble for the 

proposal. 

2. How did the revisions pursuant to 

CAA section 112(d)(2) and (3) change 

since proposal? 

We proposed identical standards for 

existing and new DCU decoking 

operations, but we are finalizing 

standards for new and existing sources 

that are not identical. We are finalizing 

provisions that will require owners or 

operators of existing DCU sources to 

comply with a 2 psig limit averaged 

over 60 cycles (i.e., 60 venting events), 

rather than meet the 2 psig limit on a 

per venting event basis, as proposed. We 

are finalizing provisions that will 

require owners or operators of new DCU 

sources to comply with a 2.0 psig limit 

on a per event, not-to-exceed basis. We 

are adding one significant digit to the 

limit for new DCU affected sources 

because our re-review of permit 

requirements conducted in response to 

comments identified that the best 

performing DCU source is required to 

comply with a 2.0 psig limit on a per 

event basis. In response to comments 

regarding the proposed prohibition on 

draining prior to achieving the pressure 

limit, we are finalizing specific 

provisions for DCU with water overflow 

design and for double quenching. 

For flares, we are not finalizing the 

ban that we proposed on halogenated 

vent streams and we are not finalizing 

the proposed requirement to equip the 

flare pilot system with an automated 

device to relight an extinguished pilot. 

We are revising the MACT to include 

the proposed no visible emissions limit 

and the flare tip velocity limit as direct 

emissions limits only when the flare 

vent gas flow rate is below the 

smokeless capacity of the flare. Under 

the revised standard, when the flare is 

operating above the smokeless capacity, 

an exceedance of the no visible 

emission limit and/or flare tip velocity 

limit is not a violation of the standard 

but instead triggers a work practice 

standard. Flares operate above the 

smokeless capacity only when there is 

an emergency release event and thus the 

work practice standard is intended to 

address emissions during such 

emergency release events. (See section 

IV.D. of this preamble for more details 

regarding this work practice standard). 

We are also adding provisions that 

would allow sources to use video 

surveillance of the flare as an alternative 

to daily Method 22 visible emissions 

observations. 

For flares, we are also simplifying the 

combustion zone gas property operating 

limits by finalizing a requirement only 

for the net heating value of the 

combustion zone gas. We are finalizing 

requirements that flares meet a 

minimum operating limit of 270 BTU/

scf NHVcz on a 15-minute average, as 

proposed, and we are allowing refinery 

owners or operators to use a corrected 

heat content of 1212 BTU/scf for 

hydrogen to demonstrate compliance 

with this operating limit. We are not 

finalizing separate combustion zone 

operating limits for gases meeting the 

hydrogen-olefin interaction criteria that 

were proposed. We are also not 

finalizing the alternative combustion 

zone operating limits based on lower 

flammability limit or combustibles 

concentration. 

We are finalizing ‘‘dilution 

parameter’’ requirements for air-assisted 

flares, but we are providing a limit only 

for the net heating value dilution 

parameter. Similar to the requirements 

we are finalizing for the combustion 

zone parameters, we are finalizing 

requirements that flares meet a 

minimum operating limit of 22 BTU/ft2

NHVdil on a 15-minute average, as 

proposed, and we are allowing refinery 

owners or operators to use a corrected 

heat content of 1,212 BTU/scf for 

hydrogen to demonstrate compliance 

with this operating limit. We are not 

finalizing separate dilution parameter 

operating limits for gases meeting the 

hydrogen-olefin interaction criteria that 

were proposed. We are also not 

finalizing the alternative dilution 

parameter operating limits based on 

lower flammability limit or 

combustibles concentration. 


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We are providing an alternative to use 

initial sampling period and process 

knowledge for flares in dedicated 

service as an alternative to continuous 

or on-going grab sample requirements 

for determining waste gas net heat 

content. 

We are finalizing revisions to the 

definition of MPV, as proposed. 

We are establishing work practice 

standards that apply to PRD releases in 

place of the proposed prohibition on 

PRD releases to the atmosphere. The 

work practice standards that we are 

finalizing for PRD require refiners to 

establish proactive, preventative 

measures for each PRD to identify and 

correct direct releases of HAP to the 

atmosphere as a result of pressure 

release events. Over time, these 

proactive measures will reduce the 

occurrence of releases and the 

magnitude of releases when they occur, 

while avoiding the environmental 

disbenefits of having additional flare 

capacity on standby to control these 

unpredictable and infrequent events. 

Refinery owners or operators will be 

required to perform a root cause 

analysis/corrective action following 

such pressure release events. In 

addition, a second release event in a 3- 

year period from the same PRD with the 

same root cause on the same equipment 

is a deviation of the work practice 

standard. A third release event in a 

3-year period from the same PRD is a 

deviation of the work practice standard 

regardless of the root cause. PRD release 

events related to force majeure events 

are not considered in these hard limits. 

3. What key comments did we receive 

on the proposed revisions pursuant to 

CAA section 112(d)(2) and (3) and what 

are our responses? 

i. DCU 

Comment: Several commenters argued 

that the EPA incorrectly set the MACT 

floor emission limitation for DCU. 

Commenters noted that CAA section 

112(d)(3)(A) states that the MACT limit 

for existing sources ‘‘shall not be less 

stringent, and may be more stringent 

than the average emission limitation 

achieved by the best performing 12- 

percent of the existing sources’’ 

excluding those first achieving that level 

within 18 months prior to proposal or 

30 months prior to promulgation, 

whichever is later. According to the 

commenters, the EPA failed to follow 

this procedure in setting the 2 psig vent 

limit as a MACT floor because the EPA 

incorrectly considered permit limits and 

other non-performance based criteria 

instead of basing the MACT floor on the 

actual performance of sources. 

Commenters stated that the EPA 

improperly considered permit limits 

that should have been excluded from 

consideration, as well as considering 

permit limits for closed facilities instead 

of using more accurate data from 

operating DCUs at sources that 

submitted actual emissions data. 

Specifically, commenters stated that the 

DCU at the non-operational plant 

(Hovensa) should not be included. One 

commenter noted that they operate one 

of the South Coast DCU listed as subject 

to a 2 psig limit and asserted that it does 

not currently meet that emission 

limitation. The commenter claimed that 

significant capital investment would be 

required in order for the DCU to comply 

with the 2 psig limit. According to one 

commenter, data for six of the eight 

DCU they claim the EPA considered for 

the MACT floor should not be counted 

in determining the limit that represents 

the average emission limitation actually 

achieved 18 months prior to the 

proposal. 

Response: CAA section 112(d)(3)(A) 

states that the existing source standard 

shall not be less stringent than the 

average emission limitation achieved by 

the best performing 12-percent of the 

existing sources (for which the 

Administrator has emissions 

information), excluding those sources 

that have, within 18 months before the 

emission standard is proposed or within 

30 months before such standard is 

promulgated, whichever is later, first 

achieved a level of emission rate or 

emission reduction which complies, or 

would comply if the source is not 

subject to such standard, with the 

lowest achievable emission rate (as 

defined by section 171) applicable to the 

source category and prevailing at the 

time, in the category or subcategory for 

categories and subcategories with 30 or 

more sources. We consider a 2 psig 

emissions limitation to be equivalent to 

the lowest achievable emission rate 

(LAER) emission limits. Thus, we agree 

with the commenter that sources that 

first meet the 2 psig limit on or after 

December 30, 2012, should be excluded 

from the MACT floor analysis. We also 

agree that under CAA section 

112(d)(3)(A), the MACT floor analysis 

focuses on those sources that are 

achieving the emission limit (i.e., the 

emission limitation ‘‘achieved by 

. . . ’’). The EPA has previously 

determined that the 6th-percentile unit 

is a reasonable estimate of the average 

emission limitation achieved by the best 

performing 12-percent of sources 

especially when averaging across units 

with and without control requirements. 

As noted in our DCU MACT floor 

analysis memorandum (Docket ID No. 

EPA–HQ–OAR–2010–0682–0203), the 

6th-percentile is represented by the 

fifth-best performing DCU. If we exclude 

the two South Coast refineries and the 

two Marathon Garyville DCU because 

these sources were not implementing 

the 2 psig permit limit prior to 

December 30, 2012, the fifth-best 

performing DCU would be represented 

by the Bay Area refineries (4.6 psig). 

However, based on the 2011 Petroleum 

Refinery ICR responses, 25 out of 75 (33- 

percent) DCU have a ‘‘typical coke drum 

pressure when first vented to the 

atmosphere’’ of 2 psig or less and 10 out 

of 75 (13-percent) DCU have a ‘‘typical 

coke drum pressure when first vented to 

the atmosphere’’ of 1 psig or less. While 

we acknowledge that these data 

represent ‘‘typical’’ operations and not 

necessarily a never-to-be-exceeded 

emissions limitation, we conclude that 

this information is sufficient for us to 

conclude that the average emission 

limitation achieved by the best 

performing 12-percent of sources is 

consistent with a 2 psig emissions 

limitation. This is because facility 

owners or operators commonly target to 

operate at approximately half the 

allowable emissions limit to ensure that 

they can comply with the emissions 

limit at all times. Therefore, we 

maintain that an average venting 

pressure of 2 psig is the MACT floor 

level for decoking operation at existing 

sources based on the ICR responses and 

considering the average performance 

expected. 

Comment: Four commenters 

suggested that the 2 psig limit, if 

finalized, should be based on a rolling 

30-day average per DCU rather than a 

never to be exceeded ‘‘instantaneous’’ 

standard. According to the commenters, 

an instantaneous standard is 

unnecessary to address HAPs with 

chronic health impacts and adds cost 

and compliance challenges. According 

to the commenters, chronic health 

impacts are not materially affected by 

short-term variability, but instead 

depend on the average concentration of 

exposure over a 70-year lifetime; 

therefore, there is no health based or 

environmental reason for requiring an 

instantaneous limit. The commenters 

noted that there would be additional 

capital costs to comply with a 2 psig 

not-to-be-exceeded limit compared to a 

30-day average 2 psig limit vent 

pressure. One commenter specifically 

requested that the EPA also confirm that 

a pressure of 2.4 psig is compliant with 

the 2 psig limit vent pressure. Another 

commenter also requested clarification 

that the vent pressure can be rounded to 


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one significant figure when determining 

compliance. 

Response: For new sources, the 

MACT floor emission limit for DCU is 

based on the best-performing source. 

Based on this and other comments 

received, we again reviewed existing 

permit conditions. Based on this review, 

we found that one of the permit 

requirements specified the pressure 

limit as 2.0 psig for each coke drum 

venting event. Therefore, we are 

finalizing the new source MACT floor as 

2.0 psig on a per coke drum venting 

event basis. 

As discussed in response to the 

previous comment, we are basing the 

MACT floor for existing source DCU on 

responses we received from the 2011 

Petroleum Refinery ICR. Because the 

ICR requested the ‘‘typical coke drum 

pressure when first vented to the 

atmosphere,’’ we do not consider the 

information provided in ICR responses 

to reflect a ‘‘never-to-be-exceeded’’ 

limit. Therefore, we evaluated whether 

it is reasonable to allow averaging, and 

if so, what averaging period should be 

provided. 

Health risks are not considered in 

establishing MACT requirements, so we 

do not consider the argument that 

chronic effects are evaluated over a 70- 

year period to be relevant to a 

determination of the MACT floor. 

However, a primary consideration 

regarding averaging periods is how the 

averaging period was considered in 

setting the floor and whether the 

intended reductions will occur under a 

different averaging period. According to 

the heat balance method for estimating 

DCU emissions, DCU decoking 

operations emissions are directly 

proportional to the average bed 

temperature. While the relationship is 

not exactly linear, the average bed 

temperature is expected to be a function 

of the venting pressure. Moreover, the 

shape of the pressure-temperature 

correlation curve is such that the 

emissions at 6 psig are almost exactly 

but not quite three times the emissions 

at 2 psig. Given the expected linearity 

of the emissions with venting pressures, 

we are not concerned with an 

occasional venting event above 2 psig 

because the average emissions from a 

facility meeting an average 2 psig 

pressure limit would be identical to the 

emissions achieved by a facility that 

vented each time at 2 psig. That is, 

given the expected linearity in the 

projected DCU emissions to the venting 

pressure, we conclude that it is 

reasonable to allow averaging across 

events and that the precise averaging 

period is not a critical concern. 

Most industry commenters requested 

a 30-day average. However, different 

facilities have different numbers of 

DCU, different numbers of drums per 

DCU and different cycle times. 

Consequently, basing the averaging 

period across a given time period would 

result in significantly different number 

of venting events included in a 30-day 

average for different facilities and 

generally provide more flexibility to 

larger refineries and less flexibility to 

smaller refineries. Based on the ICR 

responses, almost half of all DCU 

operate with two drums and about 90- 

percent of DCU have two to four coke 

drums; however, a few DCU have six or 

even eight drums. Also, based on the 

ICR responses, the average complete 

coke drum cycle time is 32 hours, but 

can be as short as 18 hours and as long 

as 48 hours. Reviewing the ICR 

responses, we found that a 30-day 

average would include 30 events for 

some facilities and more than 250 

events at other facilities. 

Since the existing source MACT 

standards apply ‘‘in combination’’ to 

‘‘all releases associated with decoking 

operations’’ at a given facility, we 

determined that it was reasonable to 

consider an averaging period that 

applies to the number of venting events 

from all coke drums at the facility rather 

than to all coke drums for a specific 

DCU for a specified period of time. This 

provides a more consistent basis for the 

averaging period and allows the same 

operational flexibility for small 

refineries as large refineries. Based on 

the ICR responses, the median (typical) 

DCU has 60 venting events in a 30-day 

period. Providing an averaging period of 

60 venting events provides a more 

consistent averaging basis for all 

facilities, regardless of the number of 

DCU at the facility and the number of 

drums and cycle times for different 

DCU. Additionally, it eliminates issues 

with respect to how to handle operating 

days versus non-operating days, e.g., in 

the event of a turn-around resulting in 

a limited number of venting events in a 

30-calendar day period. Therefore, we 

are establishing a 2 psig limit based on 

a 60-event average considering all coke 

drum venting events at an existing 

source and we are finalizing a 2.0 psig 

limit on a per coke drum venting event 

for DCU at new sources. 

We have consistently maintained our 

policy to round to the last digit 

provided in the emission limit, a 

pressure of 2.4 psig would round to 2 

psig and would be compliant with a 

requirement to depressure each coke 

drum to a closed blowdown system 

until the coke drum vessel pressure is 

2 psig or less, but it would not be 

compliant with the revised new source 

provision to depressure until the coke 

drum vessel pressure is 2.0 psig or less. 

A coke drum pressure of 2.04, however, 

would be compliant with the revised 

new source requirement pressure limit 

of 2.0 psig. 

ii. Refinery Flares 

Comment: Several commenters 

suggested that the proposed flare 

operating limits were too complex. The 

commenters recommended that the EPA 

eliminate the dual flare combustion 

zone heat content limits related to the 

proposed hydrogen-olefin interaction 

criteria and instead finalize a single 

combustion zone net heating value of 

approximately 200 BTU/scf, which 

would minimize the unnecessary 

burning of supplemental gas but still 

ensure good combustion efficiency. 

A few commenters suggested that the 

EPA based the proposed combustion 

zone limits on an invalid data analysis, 

that the 1 minute PFTIR data should not 

be used to establish combustion 

efficiency correlations, and that the 

emission limits should be set so as to 

provide an equal chance of false 

positives and negatives. A few 

commenters suggested that the EPA 

should assign hydrogen a heating value 

of 1,212 BTU/scf to more accurately 

reflect its flammability in a NHV basis 

and that doing so is consistent with 

some recent flare consent decrees and 

would help reduce natural gas 

supplementation for facilities 

complying only with the NHVcz metric. 

Several commenters suggested that 

neither scientific literature nor the 

available flare test data support the 

EPA’s claim of an adverse hydrogenolefin interaction on combustion 

efficiency and that the EPA should not 

finalize the more restrictive combustion 

zone operating limits for all flare types. 

These commenters suggested that the 

EPA did not provide any evidence the 

assumed hydrogen-olefin effect actually 

exists; that statistical analysis 

demonstrates the EPA developed their 

limit based on random differences in 

data; that the PFTIR data analysis 

method of using the individual minuteby-minute data instead of the test 

average data is flawed and leads to 

invalid conclusions; and that proper 

analysis of the data demonstrates the 

more stringent operating limits for 

hydrogen-olefin conditions cannot be 

supported. 

Some commenters suggested that 

there is evidence to support more 

stringent flare combustion zone limits 

for a narrowly defined high 

concentration propylene-only condition 

as outlined in some of the recent flare 


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consent decrees but that the flare test 

data do not support more stringent 

operating limits for the proposed 

hydrogen-olefins criteria by the EPA. 

Additionally, one commenter suggested 

that if the EPA decides to proceed with 

the more restrictive combustion zone 

limits for the hydrogen-olefins 

interaction cases then the final rule 

should not expand beyond an 

interaction between hydrogen and 

propylene. 

Several commenters suggested that 

the proposed 15-minute feed forward 

averaging time for flares (e.g., 

combustion zone parameters, air-assist 

dilution parameters and associated flow 

rates) is arbitrary, unrealistic and 

unworkable and that the feed forward 

compliance determination should not be 

finalized and, if it is finalized, the 

averaging time should be extended to 

1-hour, 3-hour, or 24-hour. To support 

these suggested averaging periods, 

commenters claimed that typical 

standards for combustion devices are 

averaged over these suggested 

timeframes, noting as an example, 

recent refinery flare consent decrees that 

contain a 3-hour average. The 

commenters also asserted that both a GC 

and calorimeter will be needed to obtain 

data rapidly enough to try and maintain 

a 15-minute average; that the feed 

forward approach requires calculation 

artifices to attempt to correct for the fact 

that compliance cannot be determined 

until the averaging period is over; and 

that a longer averaging time is needed 

for instrument and control response 

time. 

Response: In addressing these 

comments, we further analyzed the flare 

emissions test data. First, to address 

concerns that the minute-by-minute 

analysis produced flawed results, we recompiled the data into approximate 

‘‘15-minute averages’’ to the extent 

practical based on the duration of a 

given test run (e.g., a 10-minute run was 

used as 1 run and a 32-minute run was 

divided into 2 runs of 16 minutes each). 

We do not find significant differences in 

the data or that different conclusions 

would be drawn from the data based on 

this approach as compared with the 

minute-by-minute analysis used for the 

proposed rule. 

Next, we evaluated the 15-minute run 

data using the normal net heating value 

for hydrogen of 274 Btu/scf, which is 

the value we used in the analysis for the 

proposed rule and also evaluated the 

data using the 1,212 Btu/scf, the value 

recommended by some commenters. 

The 1,212 Btu/scf value is based on a 

comparison between the lower 

flammability limit and net heating value 

of hydrogen compared to light organic 

compounds and has been used in 

several consent decrees to which the 

EPA is a party. Based on our analysis, 

we determined that using a 1,212 Btu/ 

scf value for hydrogen greatly improves 

the correlation between combustion 

efficiency and the combustion zone net 

heating value over the entire array of 

data. Using the net heating value of 

1,212 Btu/scf for hydrogen also greatly 

reduced the number of ‘‘type 2 failures’’ 

(instances when the combustion 

efficiency is high, but the gas does not 

meet the NHVcz limit). One of the 

primary motivations for the proposed 

approach to provide alternative limits 

based on lower flammability limits and 

combustibles concentrations was to 

reduce these type 2 failures. Therefore, 

we proposed all three of these 

parameters (i.e., NHVcz, LFL and total 

combustibles) and allowed flare owners 

or operators to comply with any of the 

parameter limits at any time. When 

using the net heating value of 1,212 Btu/ 

scf for hydrogen, the other two 

alternatives no longer provide any 

improvement in the ability to predict 

good flare performance. Consequently, 

we are simplifying the operating limits 

to use only NHVcz. 

Next, we re-evaluated whether to 

finalize the proposed dual combustion 

zone operating limits for refinery flares 

that met certain hydrogen-olefins 

interactions or to finalize a single 

combustion zone net heating value 

limit. The newly re-compiled PFTIR run 

average flare dataset suggests that higher 

operating limits may be appropriate for 

some olefin-hydrogen mixtures. 

However, the dataset using 15-minute 

test average runs is much smaller than 

the set using 1-minute runs and thus 

creates a greater level of uncertainty. In 

addition, we cannot definitively 

conclude that a dual combustion zone 

limit for refinery flares meeting certain 

hydrogen-olefins interactions is 

appropriate given these uncertainties. 

Thus, in order to minimize these 

uncertainties and streamline the 

compliance requirements, we used all of 

the 15-minute test run average data 

together as a single dataset in an effort 

to determine an appropriate, singular 

combustion zone net heating value 

operational limit. 

Finally, we conducted a Monte Carlo 

analysis to help assess the impacts of 

extending the averaging time on the test 

average flare dataset of 15-minute runs 

to 1-hour or 3-hour averaging time 

alternatives. While we consider it 

reasonable to provide a longer averaging 

time for logistical reasons, the Monte 

Carlo analysis demonstrated, consistent 

with concerns described in our 

proposal, that short periods of poor 

performance can dramatically limit the 

ability of a flare to achieve the desired 

control efficiency. Consequently, we 

find it necessary to finalize the 

proposed 15-minute averaging period to 

ensure that the 98-percent control 

efficiency for flares is achieved at all 

times. However, we understand that 

flare vent gas flow and composition are 

variable. While a short averaging time is 

needed to ensure adequate control given 

this variability, we also understand the 

complications that this variability 

places on flare process control in efforts 

to meet the NHVcz limit. Therefore, we 

are clarifying that the 270 Btu/scf 

NHVcz value is an operational limit that 

must be calculated according to the 

requirements in this rule. We also 

clarify that compliance with this 

operational limit must be evaluated 

using the equations and calculation 

methods provided in the rule. We 

proposed a feed forward calculation 

method to allow refinery owners or 

operators a means by which to adjust 

steam (or air) and, if necessary, 

supplemental natural gas flow, in order 

to meet the limit. In other words, ‘‘feed 

forward’’ refers to the fact that the rule 

requires the refinery owners or 

operators to use the net heating value of 

the vent gas (NHVvg) going into the flare 

in one 15-minute period to adjust the 

assist media (i.e., steam or air) and/or 

the supplemental gas in the next 15- 

minute period, as necessary for the 

equation in the rule to calculate an 

NHVcz limit of 270 BTU/scf or greater. 

We recognize that when a subsequent 

measurement value is determined, the 

instantaneous NHVcz based on that 

compositional analysis and the flow 

rates that exist at the time may not be 

above 270 Btu/scf. We clarify that this 

is not a deviation of the operating limit. 

Rather, the owner or operator is only 

required to make operational 

adjustments based on that information 

to achieve, at a minimum, the net 

heating value limit for the subsequent 

15-minute block average. Failure to 

make adjustments to assist media or 

supplemental natural gas using the 

equation provided for calculating an 

NHVcz limit of 270 BTU/scf, using the 

NHVvg from the previous period, would 

be a deviation of the operating limit. 

Alternatively, if the owner or operator 

is able to directly measure the NHVvg 

on a more frequent basis, such as with 

a calorimeter (and optional hydrogen 

analyzer), the process control system is 

able to adjust more quickly, and the 

owner or operator can make adjustments 

to assist media or supplemental natural 

gas more quickly. In this manner, the 

owner or operator is not limited by 


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relying on NHVvg data that may not 

represent the current conditions. 

Therefore, the owner or operator may 

opt to use the NHVvg from the same 

period to comply with the operating 

limit. 

Based on the results of all of our 

analyses, the EPA is finalizing a single 

minimum NHVcz operating limit for 

flares subject to the Petroleum Refinery 

MACT standards of 270 BTU/scf during 

any 15-minute period. The agency 

believes, given the results from the 

various data analyses conducted, that 

this operating limit is appropriate, 

reasonable and will ensure that refinery 

flares meet 98-percent destruction 

efficiency at all times when operated in 

concert with the other suite of 

requirements refinery flares need to 

achieve (e.g., flare tip velocity 

requirements, visible emissions 

requirements, and continuously lit pilot 

flame requirements). For more detail 

regarding our data re-analysis, please 

see the memorandum titled ‘‘Flare 

Control Option Impacts for Final 

Refinery Sector Rule’’ in Docket ID No. 

EPA–HQ–OAR–2010–0682. 

Comment: Numerous commenters 

objected to the proposed requirements 

to have the velocity and visible 

emissions limits apply at all times for 

flares. Commenters suggested that flares 

are not designed to meet the visible 

emissions and flare tip velocity 

requirements when being operated 

beyond their smokeless capacity and 

suggested several alternative 

approaches: remove the visible 

emissions and flare tip velocity 

requirements from the rule altogether; 

exempt flares from these requirements 

during emergencies; or add a 

requirement to maintain a visible flame 

present at all times or include a work 

practice standard in the rule when flares 

are operated beyond their smokeless 

capacity at full hydraulic load. The 

commenters identified full hydraulic 

load as the maximum flow the flare can 

receive based on the piping diameter of 

the flare header and operating pressure 

of processes connected to the flare 

header system. They also specified that 

full hydraulic load would only occur if 

all sources connected to the flare header 

vented at the same time, which might 

result from an emergency shutdown due 

to a plant-wide power failure. 

According to commenters, flares are 

typically designed to operate in a 

smokeless manner at 20 to 30-percent of 

full hydraulic load. Thus, they claimed, 

flares have two different design 

capacities: A ‘‘smokeless capacity’’ to 

handle normal operations and typical 

process variations and a ‘‘hydraulic load 

capacity’’ to handle very large volumes 

of gases discharged to the flare as a 

result of an emergency shutdown. 

According to commenters, this is 

inherent in all flare designs and it has 

not previously been an issue because 

the flare operating limits did not apply 

during malfunction events. However, if 

flares are required to operate in a 

smokeless capacity during emergency 

releases, the commenters claimed that 

refineries would have to quadruple the 

number of flares at each refinery to 

control an event that may occur once 

every 2 to 5 years. 

To support their suggestions, 

commenters pointed out that flaring 

during emergencies is the optimum way 

of handling very large releases and that 

the flare test data clearly demonstrate 

that visible emissions and/or high flare 

tip velocity do not suggest poor 

destruction efficiency during such 

events. The commenters also argued 

that operators should not have 

conflicting safety and environmental 

considerations to deal with during these 

times. The commenters stated that 

refiners are still subject to a civil suit 

even if the EPA uses its enforcement 

discretion where such a release would 

violate the limit and in order to avoid 

such liability, many new flares would 

have to be built. Commenters estimated 

that 500 new large flare systems at a 

capital cost in excess of $10–20 billion 

would need to be built because of the 

amount of smokeless design capacity 

that would be needed and that this 

significant investment would take the 

industry at least a decade to install. 

Response: At the time of the proposed 

rule, we did not have any information 

indicating that flares were commonly 

operated during emergency releases at 

exit velocities greater than 400 ft/sec 

(which is 270 miles per hour (mph)). 

Similarly, we did not have information 

to indicate that flares were commonly 

designed to have a smokeless capacity 

that is only 20 to 30-percent of their 

‘‘hydraulic load capacity.’’ While we are 

uncertain that refineries actually would 

install additional flares to the degree the 

commenters claim, based on the 

possibility that there may be an event 

every 2 to 5 years that would result in 

a deviation of the smokeless limit, we 

also recognize that it would be 

environmentally detrimental to operate 

hundreds of flares on hot standby in an 

effort to never have any releases to a 

flare that exceed the smokeless capacity 

of that flare. This is because operating 

hundreds of new flares to prevent 

smoking during these rare events will 

generate more ongoing emissions from 

idling flares than the no visible 

emissions limit might prevent during 

one of these events. Therefore, we 

considered alternative operating limits 

or alternative standards that could apply 

during these emergency release events. 

As an alternative to the proposed 

requirement that flares meet the visible 

emissions and velocity limits at all 

times, we considered a work practice 

standard for the limited times when the 

flow to the flare exceeds the smokeless 

capacity of the flare. Owners or 

operators of flares would establish the 

smokeless capacity of the flare based on 

design specification of the flare. Below 

this smokeless capacity, the velocity 

and visible emissions standards would 

apply as proposed. Above the smokeless 

capacity, flares would be required to 

perform root cause analysis and take 

corrective action to prevent the 

recurrence of a similarly caused event. 

Multiple events from the same flare in 

a given time period would be a 

deviation of the work practice standard. 

Force majeure events would not be 

included in the event count for this 

requirement. 

Based on industry claims that there is 

a hydraulic load flaring event, on 

average, every 4.4 years, we assumed 

the best performers would have no more 

than one event every 6 years, or a 

probability of 16.7-percent of having an 

event in any given year. We found that, 

over a long period of time such as 20 

years, half of these best performers 

would have 2 events in a 3 year period, 

which would still result in over half the 

‘‘best performing’’ flares having a 

deviation of the work practice standard 

if it was limited to 2 events in 3 years. 

Conversely, only 6 percent would have 

3 events in 3 years over this same time 

horizon. Based on this analysis, 3 events 

in 3 years would appear to be 

‘‘achievable’’ for the average of the best 

performing flares. 

Pursuant to CAA section 112(d)(2) 

and (3), we are finalizing a work 

practice standard for flares that is based 

on the best practices of the industry, 

and considers the rare hydraulic load 

events that inevitably occur at even the 

best performing facilities. 

The best performing facilities have 

flare management plans that include 

measures to minimize flaring during 

events that may cause a significant 

release of material to a flare. Therefore, 

we are requiring owners or operators of 

affected flares to develop a flare 

management plan specifically to 

identify procedures that will be 

followed to limit discharges to the flare 

as a result of process upsets or 

malfunctions that cause the flare to 

exceed its smokeless capacity. We are 

specifically requiring refinery owners or 

operators to implement appropriate 

prevention measures applicable to these 


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emergency flaring events (similar to the 

prevention measures we are requiring in 

this final rule to minimize the 

likelihood of a PRD release). Refiners 

will be required to develop a flare 

minimization plan that describes these 

proactive measures and reports 

smokeless capacity. Refiners will need 

to conduct a specific root cause analysis 

and take corrective action for any flare 

event above smokeless design capacity 

that also exceeds the velocity and/or 

visible emissions limit. If the root cause 

analysis indicates that the exceedance is 

caused by operator error or poor 

maintenance, the exceedance is a 

deviation from the work practice 

standard. A second event within a 

rolling 3-year period from the same root 

cause on the same equipment is a 

deviation from the standard. Events 

caused by force majeure, which is 

defined in this subpart, would be 

excluded from a determination of 

whether there has been a second event. 

Finally, and again excluding force 

majeure events, a third opacity or 

velocity limit exceedance occurring 

from the same flare in a rolling 3-year 

period is a deviation of the work 

practice standard, regardless of the 

cause. 

Comment: Several commenters 

suggested that the EPA should revise the 

combustion efficiency requirements to 

apply only to steam-assisted flares used 

as Refinery MACT control devices 

during periods of time that the flares are 

controlling Refinery MACT regulated 

streams. One commenter suggested that 

the EPA misused the TCEQ data in 

proposing the NHVcz metric and that the 

proposed limits are overly conservative. 

The commenter requested that the EPA 

work with stakeholders to conduct 

additional testing to determine what, if 

any, operating parameters are 

appropriate and necessary to achieve an 

adequate destruction efficiency for nonsteam-assisted flares. 

Response: We disagree with the 

commenters that the combustion 

efficiency requirements should apply 

only to steam-assisted flares. The 

available data (for runs where steam 

assist is turned off) as well as the 

available combustion theories suggest 

that the combustion zone net heating 

value minimum limit, which is the vent 

gas net heating value for unassisted or 

perimeter air-assisted flares, is 

necessary to ensure proper flare 

performance. While we agree that 

additional data on air-assisted flares 

would allow for a more robust analysis, 

the data we do have strongly indicate 

that air-assisted flares can be overassisted and that the combustion 

efficiency of air-assisted flares that are 

over-assisted is below 98-percent 

control efficiency. 

Comment: A few commenters 

suggested that the proposed flare 

regulations should not apply to part 63, 

subpart R (gasoline loading) and subpart 

Y (marine vessel loading) facilities, and 

to part 61, subpart FF (benzene waste) 

facilities. The commenters 

recommended that flares associated 

with gasoline loading, marine vessel 

loading and wastewater treatment 

emissions need to comply only with the 

General Provisions for flares. Some of 

these commenters argued that these 

sources are more consistent in flow and 

composition than other refinery sources, 

so the new requirements are not 

necessary to ensure good combustion for 

these ‘‘dedicated’’ flares. Some 

commenters suggested that operators of 

flares with consistent flow and 

composition be allowed to use process 

knowledge or engineering judgment 

rather than be required to install 

continuous monitors or be subject to 

ongoing grab sampling requirements. 

Some commenters noted that the 

required control efficiency for some 

refinery emissions sources subject to 

subpart CC sources is 95-percent. One 

commenter also requested that the EPA 

provide overlap provisions so flares 

used to control sources from different 

MACT sources would not have 

duplicative requirements. 

Response: The regulatory revisions 

that we are finalizing apply to 

petroleum refinery sources subject to 

part 63, subparts CC and UUU. Gasoline 

loading, marine vessel loading and 

wastewater treatment operations that are 

part of the refinery affected source as 

defined at 40 CFR 63.640 are subject to 

subpart CC. Gasoline loading, marine 

vessel loading and wastewater treatment 

operations located at non-refinery 

source categories are not subject to part 

63, subpart CC and, thus, would not be 

subject to the revisions to subpart CC 

being finalized in this action. To the 

extent that the commenters are 

requesting that the EPA establish flare 

requirements that would apply to flares 

that are not part of the refinery affected 

source, that request is beyond the scope 

of this rulemaking, which only 

addresses revisions to Refinery MACT 1 

and 2. When we issue rules addressing 

requirements for other sources with 

flares, we will consider issues similar to 

those we considered in this action and 

determine at that time whether revisions 

to those other flare requirements are 

necessary. 

The commenters note that some 

subpart CC emissions sources have only 

a control efficiency requirement of 95- 

percent. While this may be true, where 

the owner or operator chooses to control 

these sources through the use of a flare, 

operation of that flare was subject to 

operational requirements in the General 

Provisions at 40 CFR 63.11 and the best 

performing flares were achieving 98- 

percent control at the time the General 

Provisions were promulgated. At the 

time the General Provisions were 

promulgated, we received no comments 

that the EPA should set different 

operational limits for flares that are 

controlling emissions from sources 

where the standard may vary by level of 

control efficiency and we see no basis 

to do so now. The purpose of the 

revisions to the flare operating 

requirements is to ensure that flares are 

operating consistent with the MACT 

floor requirements for any and all 

sources that may use flares as a control 

device (79 FR 36905, June 30, 2014). As 

the MACT floor control requirements of 

certain refinery sources that allow the 

use of a flare as a control device is 98- 

percent, we established operational 

limits to ensure flares used as control 

devices meet this MACT requirement. 

To the extent that the commenters are 

requesting that the EPA establish an 

alternative monitoring approach for 

flares in dedicated service that have 

consistent composition and flow, we 

agree that these types of flares, which 

have limited flare vent gas streams, do 

not need to have the same type of ongoing monitoring requirements as those 

with more variable waste streams. Thus, 

we are establishing an option that 

refinery owners or operators can use to 

demonstrate compliance with the 

operating requirements for flares that 

are in dedicated service to a specific 

emission source, such as a wastewater 

treatment operation. Refinery owners or 

operators will need to submit an 

application for the use of this 

alternative. The application must 

include a description of the system, 

characterization of the vent gases that 

could be routed to the flare based on a 

minimum of 7 grab samples (14 daily 

grab samples for continuously operated 

flares) and specification of the net 

heating value that will be used for all 

flaring events (based on the minimum 

net heating value of the grab samples). 

We are also allowing engineering 

estimates to characterize the amount of 

gas flared and the amount of assist gas 

introduced into the system. For 

example, the use of fan curves to 

estimate air assist rates is acceptable. 

Flare owners or operators would use the 

net heating value determined from the 

initial sampling phase and measured or 

estimated flare vent gas and assist gas 


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flow rates, if applicable, to demonstrate 

compliance with the standards. 

Comment: A few commenters 

suggested that the EPA’s proposed work 

practice and monitoring standards for 

flares are CAA section 112(d) 

‘‘developments’’ required by law and 

supported by the evidence, and reflect 

best practices at many refineries today. 

One commenter suggested that the EPA 

must allow companies with consent 

decrees to meet their consent decree 

requirements as an alternative 

compliance approach and in lieu of the 

proposed requirements. 

Response: We proposed the enhanced 

monitoring requirements and operating 

limits under authority of CAA sections 

112(d)(2) and (d)(3) to ensure that flares 

used to control regulated Refinery 

MACT 1 or 2 gas streams are meeting 

the prescribed control efficiencies 

established at the time the MACT 

standard was promulgated. And, we 

continue to believe that these revisions 

are appropriate under CAA sections 

112(d)(2) and (d)(3). The commenter has 

not suggested, and we do not believe, 

that the revisions promulgated would 

differ in substance if they were instead 

promulgated under CAA section 

112(d)(6). 

In general, we expect that the NHVcz

monitoring requirements that we are 

finalizing for flares will be consistent 

with the requirements in various 

consent decrees. However, we have not 

conducted a rigorous evaluation of 

equivalency between various 

requirements and therefore we are not at 

this time providing an allowance for 

flare owners or operators to comply 

with the NHVcz operating limits and any 

provisions for necessary monitoring 

needed in the consent decree in lieu of 

the NHVcz limits and monitoring 

requirements established in this rule. In 

the event that an owner or operator 

wishes to continue complying only with 

the requirements of a consent decree, 

the rule contains provisions by which 

owner or operator can seek approval for 

alternative limits that are at least 

equivalent to the performance achieved 

from complying with the operating 

limits included in the final rule. 

iii. Pressure Relief Devices 

Comment: Several commenters 

suggested that the EPA develop a work 

practice approach for atmospheric PRD 

rather than a prohibition on releases. 

One commenter recommended that the 

EPA establish a work practice standard 

for atmospheric PRDs that requires 

refiners to implement a base level of 

preventative measures including: Basic 

process controls, instrumented alarms, 

documented and verified routine 

inspection and maintenance programs, 

safety-instrumented systems, disposal 

systems, provide redundant equipment, 

increase vessel design pressure and 

systems that reduce fire exposure on 

equipment. Additionally, the 

commenter recommended that the EPA 

require refiners to perform root cause 

analysis and implement corrective 

action in the event of a release. The 

commenter stated these requirements 

would be similar to the root cause 

analysis/corrective action requirements 

recently promulgated for flares under 

NSPS subpart Ja and provided specific 

regulatory language for a proposed work 

practice approach. (See section 2.4.1.8 

in Docket item EPA–HQ–OAR–2010– 

0682–0583.) One commenter requested 

that the EPA allow a process for 

companies to submit an application for 

case-by-case limits to be approved by 

the agency, either the EPA or a 

delegated state similar to the alternate 

NOX limits for process heaters provided 

in NSPS subpart Ja. This commenter 

recommended that the EPA establish 

reasonable work practice standards, 

specifically suggesting that the EPA 

develop work practice standards 

consistent with API 521. The 

commenter stated that the EPA should 

provide an implementation period for 

compliance that goes beyond the 

timeframe provided under CAA section 

112(d). The commenter added that the 

EPA should adopt specified changes to 

the definition of an atmospheric 

pressure relief safety valve and provided 

suggested regulatory language for a 

proposed work practice standard for 

PRDs in EPA–HQ–OAR–2010–0682– 

0549. 

Another commenter stated that the 

EPA should require, as the Bay Area Air 

Quality Management District 

(BAAQMD) does, that any refinery that 

has a reportable PRD event must take 

certain steps to prevent such releases in 

the future (BAAQMD Rule 8–28–304). 

In particular, such a refinery must create 

a Process Hazard Analysis, meet the 

Prevention Measures Procedures 

specified in section 8–28–405, and 

conduct a failure analysis of the 

incident, to prevent recurrence of 

similar incidents (Id. Reg. section 8–28– 

304.1). If a second release occurs, then, 

within one year, the facility must vent 

its PRDs to a vapor recovery or disposal 

system that meets certain requirements 

(Id. Reg. section 8–28–304.2). The 

commenter asserted that the EPA’s 

prohibition on releases to the 

atmosphere from PRD will ensure that 

refineries take the necessary steps to 

prevent such releases, or install control 

devices so that any releases from PRDs 

that must occur are vented through a 

control device to reduce the amount of 

toxic air pollution they emit. At a 

minimum, the commenter stated, the 

EPA must prohibit these uncontrolled 

emissions and require monitoring and 

reporting to assure compliance and 

ensure that the emission standards 

apply at all times, as required by the 

Act. The commenter argued that the 

EPA must also, however, consider 

requiring the additional developments 

that have been put into place in the 

BAAQMD and also require control 

devices to be used for all PRD, as some 

local air districts require. In addition, 

the commenter supported the EPA’s 

monitoring and reporting requirements 

for PRD releases and the proposed 

electronic reporting requirements, 

which the EPA recognized are needed to 

assure compliance and assist with 

future rulemakings and as that provision 

requires, the EPA also must make all 

information reported publicly available 

online promptly and in an accessible 

and understandable format. 

Response: We agree that, under the 

proposal, refineries would consider 

installing add-on controls to comply 

with the prohibition on atmospheric 

releases from PRDs. In addition, they 

would consider venting these control 

devices to existing control devices, 

including flares. However, it may not be 

feasible to vent some or all of the PRDs 

to existing flares if the flares are near 

their hydraulic load capacity based on 

the processes already connected to the 

flares. Flares have negative secondary 

impacts when operated at idle 

conditions for the vast majority of time, 

which could be the case if they were 

installed solely to address PRD releases. 

These secondary impacts result from 

GHG, CO and NOX emissions. Some 

PRDs may vent materials that are not 

compatible with flare control and would 

need to be vented to other controls. 

To estimate the impact of the 

proposed prohibition on venting PRDs 

to the atmosphere, we estimated that at 

least one new flare per facility would be 

required to handle releases from PRDs, 

based on the number of atmospheric 

PRDs reported at refineries; that 60- 

percent of the PRDs could be piped to 

existing controls at minimal costs and 

the other 40-percent would have to be 

piped to new flares; and that, on 

average, each new flare would service 

40 PRDs. Based on these assumptions, 

151 new flares would be needed or 

approximately one new flare per 

refinery. At a capital cost of $2 million 

for each new flare, which would not 

include long pipe runs, if needed, to 

PRD that are dispersed across the plant, 

we estimate that the capital cost of the 


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prohibition on venting to the 

atmosphere would exceed $300 million. 

Considering the fuel needed 

(approximately 50,000 scf/day per flare) 

and a natural gas price of $4.50 per 

1,000 scf, we estimate the annual 

operating cost for these new flares to be 

$12 million. 

PRDs are unique in that they are 

designed for the purpose of releasing or 

‘‘popping’’ as a safety measure to 

address pressure build-up in various 

systems—pipes, tanks, reactors—at a 

facility. These pressure build-ups are 

typically a sign of a malfunction of the 

underlying equipment. While it would 

be difficult to regulate most malfunction 

events because they are unpredictable 

and can vary widely, in the case of 

PRDs, they are equipment installed 

specifically to release during 

malfunctions and as such, we have 

information on PRDs in our 2011 

Refinery ICR and through the SCAAMD 

and BAAQ rules to establish standards 

for them. After reviewing these 

comments, we thus examined whether it 

would be feasible to regulate these 

devices under CAA section 112(d)(2) 

and (3). 

After reviewing the comments, we 

agree with the commenters who suggest 

that the BAAQMD rule, as well as a 

similar South Coast Air Quality 

Management District (SCAQMD) rule 

that address PRD releases (SCAQMD 

Rule 1173), provide work practice 

standards that reflect the level of control 

that applies to the best performers. 

Consequently, we developed a work 

practice standard for PRD based on a 

detailed MACT analysis considering the 

requirements in these rules. Our 

rationale for the selected MACT 

requirements is provided in section 

IV.C.4 of this preamble. The work 

practice standards that we are finalizing 

for PRDs require refiners to establish 

proactive measures for each affected 

PRD to prevent direct release of HAP to 

the atmosphere as a result of pressure 

release events. In the event of an 

atmospheric release, we are requiring 

refinery owners or operators to conduct 

root cause analysis to determine the 

cause of a PRD release event. If the root 

cause was due to operator error or 

negligence, then the release would be a 

deviation of the standard. For any other 

release (not including those caused by 

force majeure events), the owner or 

operator would have to implement 

corrective action. A second release due 

to the same root cause for the same 

equipment in a 3-year period would be 

a deviation of the work practice 

standard. Finally, a third release in a 3- 

year period would be a deviation of the 

work practice standard, regardless of the 

root cause. Force majeure events would 

not count in determining whether there 

has been a second or third event. 

With respect to defining ‘‘atmospheric 

pressure relief safety valve’’ as 

suggested by the commenter, we note 

that the June 30, 2014, proposed 

amendments in 40 CFR 63.648(j) used 

the term ‘‘relief valve’’ because this was 

a defined term in Refinery MACT 1. 

However, the proposed amendments 

included clauses such as ‘‘if the relief 

valve does not consist of or include a 

rupture disk.’’ Thus, we specifically 

intended to apply the pressure relief 

management requirements broadly to 

‘‘pressure relief devices’’ and not just 

‘‘valves.’’ To clarify this, we have 

revised the regulatory language to use 

the term ‘‘pressure relief device’’ rather 

than ‘‘relief valve’’ to clearly include 

rupture disks or similar types of 

equipment that may be used for 

pressure relief. 

4. What is the rationale for our final 

approach and final decisions for the 

revisions pursuant to CAA section 

112(d)(2) and (3)? 

We revised the MACT floor 

determination for DCU sources. CAA 

section 112(d)(3)(A) requires the MACT 

floor for existing sources to exclude 

‘‘. . . those sources that have, within 18 

months before the emission standard is 

proposed or within 30 months before 

such standard is promulgated, 

whichever is later, first achieved a level 

of emission rate or emission reduction 

which complies, or would comply if the 

source is not subject to such standard, 

with the lowest achievable emission rate 

(as defined by section 171) applicable to 

the source category and prevailing at the 

time, in the category or subcategory for 

categories and subcategories with 30 or 

more sources.’’ Because we have 

determined that a 2 psig emissions 

limitation is equivalent with a LAER 

emission limit for DCU, we revised the 

MACT floor analysis in order to exclude 

sources that first met the 2 psig limit on 

or after December 30, 2012. For existing 

sources, based on the revised MACT 

analysis, we concluded that the MACT 

floor is still 2 psig. However, because 

the information on which we relied was 

submitted in response to the 2011 

Petroleum Refinery ICR which 

requested ‘‘typical’’ venting pressures 

and because providing an allowance to 

average across venting periods does not 

reduce the emissions reductions 

achieved, we are providing a 60-event 

averaging period for existing sources in 

response to public comments received. 

For new DCU sources, our revised 

analysis identified one DCU subject to 

permit emission limitations of 2.0 psig 

pressure limit prior to venting on a per 

event basis. Under CAA section 

112(d)(3), the MACT standard for new 

sources cannot be less stringent than the 

emission control achieved in practice by 

the best-controlled similar source. Thus, 

we are finalizing a limit of 2.0 for new 

DCU sources. We note that as 2.0 psig 

limit is more stringent than a 2 psig 

limit because of the rounding 

convention of rounding to the number 

of significant digits for which the 

standard is expressed. For example, a 

2.4 psig venting pressure is compliant 

with a 2 psig limit, while it is not 

compliant with a 2.0 psig limit. 

We evaluated the costs of requiring 

existing sources to meet a 2.0 psig limit 

as a beyond-the-MACT-floor option. We 

determined the incremental cost of 

going from a 2 psig limit with an 

allowance to average over 60 events to 

a 2.0 psig limit on a per event basis was 

approximately $70,000 per ton of HAP 

reduced considering VOC credits. Based 

on this high incremental costeffectiveness, we concluded that the 

MACT floor requirement for existing 

DCU sources was MACT. As discussed 

in detail in the proposal, we do not 

consider it technically feasible to meet 

a 1 psig pressure limit (effectively a 1.4 

psig limit) on a not-to-be-exceeded 

basis. Thus, we rejected this beyond the 

floor control option for both existing 

and new DCU sources. See the 

memorandum titled ‘‘Reanalysis of 

MACT for Delayed Coking Unit 

Decoking Operations’’ in Docket ID No. 

EPA–HQ–OAR–2010–0682 for 

additional details regarding our reanalysis of MACT for DCU decoking 

operations. 

In response to comments received on 

the prohibition of draining prior to 

achieving the proposed pressure limit 

(see Section 7.2.1 in the ‘‘National 

Emission Standards for Hazardous Air 

Pollutants from Petroleum Refineries— 

Background Information for Final 

Amendments: Summary of Public 

Comments and Responses’’ in Docket ID 

No. EPA–HQ–OAR–2010–0682), we are 

providing specific provisions to allow 

for draining under special conditions. 

The specific provision and our rationale 

for providing them are provided below. 

First, we learned that certain DCU are 

designed to completely fill the drum 

with water and allow the water to 

overflow in the overhead line and drain 

to a receiving tank in order to more 

effectively cool the coke bed. Owners or 

operators of this DCU design were 

concerned that the water overflow may 

be considered a drain and also stated 

that overhead temperature rather than 

pressure would be a better indicator of 

effective bed cooling. In reviewing this 


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type of DCU design, we find that this 

design has some unique advantages to 

traditional DCU to effect better cooling 

of the coke drum, and therefore we do 

not want to preclude its use. Based on 

saturated steam properties, we 

determined that an overhead 

temperature of 220 °F would achieve 

equivalent or greater emissions 

reductions than a 2 psig pressure 

limitation and an overhead temperature 

of 218 °F would achieve equivalent or 

greater emissions reductions than a 2.0 

psig pressure limitation. Therefore, we 

are including these temperature limits 

as alternatives to the 2 or 2.0 psig 

pressure limitations for existing and 

new DCU affected sources, respectively. 

With respect to the overflow ‘‘drain,’’ 

we remain concerned with emissions 

from draining superheated water. 

However, if submerged fill is used in the 

atmospheric tank receiving the overflow 

water, the superheated water will be 

cooled by the water within the tank and 

emissions that occur during the 

conventional draining of water (from the 

flashing of superheated water into 

steam) can be prevented. Therefore, we 

are allowing the use of water overflow 

provided the overflow ‘‘drain’’ water is 

hard-piped to the receiving tank via a 

submerged fill pipe (pipe below the 

existing liquid level) whenever the 

overflow water exceeds 220 °F. 

Second, we received comments that, 

for conventional DCU (those not 

designed to allow water overflow), there 

is a limit to the maximum water level 

in the drum, which limits to some 

extent how much cooling water can be 

added to the coke drum. In rare cases, 

the coke drum does not cool sufficiently 

using the typical cooling steps. In this 

case, the common industry practice is to 

partially drain the coke drum and refill 

it with additional cooling water. This 

‘‘double-quench’’ process is needed for 

safety reasons to sufficiently cool the 

coke drum contents prior to the 

decoking operations. Therefore, 

commenters requested provisions to 

allow double-quenching of the coke 

drum. We recognize the safety issues 

associated with coke blow-out during 

coke cutting if there is a portion of the 

coke bed that is not sufficiently cooled 

and we agree that double-quenching is 

an effective means to cool the coke 

drum in those rare instances that the 

typical cooling cycle does not 

sufficiently cool the coke drum 

contents, so we considered granting the 

commenters’ request. As noted 

previously, the primary concern with 

early draining of the coke drum is the 

emissions that are expected to occur as 

a result of draining superheated water. 

We recognize, however, that the water 

temperature near the bottom of the coke 

drum is typically much lower than at 

the top of the coke drum. If the 

temperature of the water drained from 

the bottom of the coke drum remains 

below 210 °F, this would minimize 

steam flashing and associated HAP 

emissions since the water drained 

would not be superheated. We conclude 

that the use of double quenching is 

appropriate for cases when the coke 

drum is not sufficiently cooled using the 

normal cooling procedures provided the 

temperature of the water drained 

remains below 210 °F, and it is 

consistent with the practices of the best 

performing sources. Consequently, we 

are finalizing provisions to allow the 

use of double-quenching for DCU 

provided the temperature of the water 

drained remains below 210 °F. 

For the CRU, we are finalizing the 

proposed revisions to require CRU that 

employ active purging to meet the 

MACT emissions limitations in Tables 

15 and 16 in subpart UUU at all times 

regardless of vessel pressure. We 

received limited comments regarding 

our proposal; these comments generally 

concerned the costs associated with the 

proposed emissions limitations. As 

discussed in our proposal, and based on 

data submitted in response to the ICR, 

emissions using active purging are 

much higher than those not using active 

purging. In the original rule, we based 

the MACT floor on the best performing 

facilities that used sequential 

pressurizations and depressurizations 

rather than active purging. Thus, in the 

proposal, we concluded that allowing 

owners or operators to actively purge 

while at low pressures was inconsistent 

with the MACT floor emissions 

limitations achieved by the best 

performing 12-percent of sources when 

the MACT floor was originally 

established. As we are simply requiring 

these facilities to meet the same 

emission levels determined to be 

MACT, we do not consider costs of 

potential additional controls to be a 

viable rationale to allow these units to 

emit several times more HAP than the 

units upon which the MACT 

requirements were based and the 

emissions levels achieved in practice by 

the vast majority of other CRU sources. 

For flares, we are finalizing proposed 

revisions to include detailed flare 

monitoring and operating requirements. 

We are including the flaring provisions 

for refineries in the Refinery MACT 

rules and removing the cross-references 

to the flaring requirements in the 

General Provisions. The final regulatory 

requirements differ from the proposed 

requirements in several respects. First, 

we are not finalizing the ban on 

halogenated vent streams because we 

did not include sufficient justification 

or include cost estimates for this 

proposed provision and we did not 

include any monitoring requirements to 

ensure compliance with this ban on 

halogenated vent streams. 

We are finalizing the proposed no 

visible emissions limit and the flare tip 

velocity limit but they will apply only 

when the flare vent gas flow rate is 

below the smokeless capacity of the 

flare. We received a number of 

comments stating that the no visible 

emissions limit and the flare tip velocity 

limit cannot be met during large 

malfunctions and emergency shutdown 

events. In response to comments, we are 

finalizing work practice standards for 

emergency flaring events using the 

proposed no visible emission limit and 

flare tip velocity limit as thresholds in 

the final rule to trigger root cause 

analysis when the flare vent gas flow 

rate is above the smokeless capacity of 

the flare. The final work practice 

standard includes requirements to 

develop a flare management plan, to 

implement prevention measures, and to 

perform root cause analysis and 

implement corrective action following 

each flaring event that exceeds the 

smokeless capacity of the flare. There is 

also a limit on the number of these 

flaring events that a given flare may 

have in the 3-year period. We are 

establishing these provisions because 

we now recognize that flares have two 

different design capacities: A smokeless 

design capacity and a hydraulic load 

capacity. We determined that the 

proposed visible emissions limit and the 

flare tip velocity limit for very large 

flow events are not the MACT floor for 

such events. The final work practice 

standards for flaring events are based on 

the best performing facilities and will 

result in emission reductions in a 

technically feasible manner without any 

negative secondary impacts. 

We consider it appropriate to 

establish a work practice standard for 

flares as provided in CAA section 

112(h). While it is possible to monitor 

gaseous streams going into the flare (as 

we have required for the flare operating 

requirements) it is not possible to design 

and construct a conveyance to capture 

the emissions from a flare. While 

knowledge of the composition and flow 

of gases entering the flare provides a 

reasonable basis for establishing 

operating requirements for normal 

operations, we have no data on flare 

performance under conditions in the 

hydraulic load range. While smoke in 

the flare exhaust is an indication of 

incomplete combustion, it is uncertain 


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how much deterioration of HAP 

destruction efficiency occurs during a 

smoking event. We also consider that 

the application of a measurement 

methodology for flare exhaust is not 

practicable due to technological and 

economic limitations. Passive FTIR has 

been used to determine combustion 

efficiency in flare exhaust, but these are 

essentially manual tests, and the 

measurement accuracy is dependent on 

how well the monitor is aligned with 

the flare exhaust plume. Changes in 

wind direction require manual 

movement of the monitoring system. It 

is also unclear if these systems can 

accurately measure combustion 

efficiency during high smoking events. 

These systems also require very 

specialized expertise, and we consider 

that it is both technologically and 

economically infeasible to measure flare 

exhaust emissions, particularly during 

high load events. Consequently, for 

emergency flare releases, we conclude 

that it is appropriate to establish a work 

practice standard as provided in CAA 

section 112(h). 

We also received comments that the 

daily visible emissions observations 

were burdensome and unnecessary and 

some commenters suggested that 

facilities be allowed to use video 

surveillance cameras. We concluded 

that video surveillance cameras would 

be at least as effective as the proposed 

daily 5-minute visible emissions 

observations using Method 22. We are 

finalizing the proposed visible 

emissions monitoring requirements 

Method 22 and the alternative of using 

video surveillance cameras. 

We are simplifying the combustion 

zone gas property operating limits in 

response to public comments received. 

Specifically, we are finalizing 

requirements that all flares meet a 

minimum operating limit of 270 BTU/

scf NHVcz on a 15-minute average, and 

we are providing that refiners use a 

corrected heat content of 1,212 BTU/scf 

for hydrogen to demonstrate compliance 

with this operating limit. We 

determined that a corrected heat content 

of 1212 BTU/scf for hydrogen provided 

a better indication of flare performance 

than without the correction. We also 

determined that the other combustion 

zone parameters, which were primarily 

proposed to provide suitable methods 

for flares that had high hydrogen 

concentrations, were no longer 

necessary when a 1,212 Btu/scf net 

heating value is used for hydrogen. 

Therefore, we are not finalizing the 

alternative combustion zone operating 

limits based on lower flammability limit 

or combustibles concentration. We are 

also not finalizing separate combustion 

zone operating limits for gases meeting 

the proposed hydrogen-olefin 

interaction criteria. In our revised 

analysis of the data, we analyzed all of 

the data together and determined the 

270 Btu/scf NHVcz operating limit 

provided in the final rule would 

adequately ensure that flares achieve the 

desired 98-percent control efficiency 

regardless of the composition of gas sent 

to the flare. 

For air-assisted flares, we are 

finalizing the additional ‘‘dilution 

parameter’’ operating limit only for the 

net heating value dilution parameter, 

NHVdil. Similar to the requirements we 

are finalizing for the combustion zone 

parameters, we are finalizing 

requirements that flares meet a 

minimum operating limit of 22 BTU/ft2

NHVdil on a 15-minute average, and we 

are providing that refiners use a 

corrected heat content of 1,212 BTU/scf 

for hydrogen to demonstrate compliance 

with this operating limit. For the 

reasons explained above, we are not 

finalizing the proposed alternative 

dilution parameter operating limits 

based on lower flammability limit or 

combustibles concentration, and we are 

not finalizing separate dilution 

parameter operating limits for gases 

meeting the proposed hydrogen-olefin 

interaction criteria. 

For flares in dedicated service, we are 

establishing an alternative to continuous 

or on-going grab sample requirements 

for determining waste gas net heating 

content to reduce the burden of 

sampling for flare waste gases that have 

consistent compositions. Flares in 

dedicated service can use initial 

sampling period and process knowledge 

to determine a fixed net heating value 

of the flare vent gas to be used in the 

calculations of NHVcz and, if applicable, 

NHVdil. 

We are revising the definition of MPV 

to remove the exemption for in situ 

sampling systems for the reasons 

provided in the proposed rule. 

We received comments 

recommending that a work practice 

standard be adopted for PRD rather than 

the proposed prohibition of atmospheric 

PRD releases. Commenters stated that 

the prohibition was infeasible due to the 

proposed immediate timing of the 

requirement and impractical due to cost 

considerations. After reviewing these 

comments as well as the BAAQMD rule 

(Regulation 8, Rule 8–28–304) and the 

SCAQMD rule (Rule 1173), we have 

determined that the work practice 

standards in these rules reflect the level 

of control that applies to the best 

performers. Therefore, we proceeded to 

evaluate appropriate MACT 

requirements based on the provisions in 

these rules. 

The BAAQMD rule requires sources 

to implement a minimum of three 

prevention measures to limit the 

possibility of a release. The BAAQMD 

uses a ‘‘release event’’ threshold of 10 

lbs/day of organic or inorganic 

pollutants; the SCAQMD rule effectively 

uses a release event threshold of 500 lbs 

VOC/day. When a release event occurs, 

both rules require that the refiner 

perform a root cause analysis and take 

corrective action (including additional 

prevention measures). In addition, both 

rules require piping the PRD to a flare 

if there are more than two release events 

(releases above a certain release size 

threshold) in a 5-year period. Both rules 

include a number of exemptions for 

certain types of PRD that are not 

expected to release significant amounts 

of pollutants to the air or that are not 

feasible to control because of pressure 

considerations. These include PRD 

associated with storage tanks, vacuum 

systems and equipment in heavy liquid 

service as well as liquid thermal relief 

valves that are vented to process drains. 

There are five refineries subject to the 

BAAQMD rule and seven refineries 

subject to the SCAQMD rule, accounting 

for 8-percent of refineries nationwide 

and representing the industry’s best 

performers. We consider the BAAQMD 

rule to be the more stringent of the two 

because this rule requires sources to 

implement a minimum of three 

prevention measures to limit the 

possibility of a release (the SCAQMD 

rule has no similar requirement) and 

uses a lower mass threshold for what is 

considered a ‘‘release event’’ (10 lbs/day 

of organic or inorganic pollutants versus 

the 500 lbs VOC release threshold in the 

SCAQMD rule). Therefore, the 

BAAQMD rule is considered to be the 

MACT floor requirement for PRDs 

associated with new affected sources 

and the SCAQMD rule is considered to 

be the MACT floor for PRDs associated 

with existing affected sources. 

In general, an open PRD is essentially 

the same as a miscellaneous process 

vent that is vented directly to the 

atmosphere. Consistent with our 

treatment of miscellaneous process 

vents and consistent with the two 

California rules, we believe that it is 

appropriate to exclude certain types of 

PRD that have very low potential to emit 

based on their type of service, size and/ 

or pressure. For example, PRD that have 

a potential to emit less than 72 pounds 

per day of VOC, considering the size of 

the valve opening, design release 

pressure, and equipment contents, 

would be considered in a similar 

manner as Group 2 miscellaneous 


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12The SCAQMD rule requires PRD to be vented 

to a flare or other control device if there is a single 

release in excess of 2,000 pounds of VOC in a 24- 

hour period or three releases in excess of 500 

pounds of VOC in a 5-year period or, alternatively, 

pay a $350,000 fee. Thus, the SCAQMD rule would 

allow, for example, two releases of over 500 pounds 

of VOC each within a 5-year period without any 

penalty provided a third event did not occur. If a 

third event did occur, the refinery owner or 

operator would then have to vent the PRD to a flare 

or other control system or pay a fee ($350,000) for 

the third release over 500 pounds of VOC. 

process vents and would not require 

additional control. The two California 

rule requirements do not apply to PRD 

on storage tanks and vacuum systems. 

Most of these PRD have a design release 

pressure of 2.5 psig and thus have a very 

limited potential to emit. It is 

technically infeasible to pipe these 

sources to a flare (or other similar 

control system) because the back 

pressure in the flare header system 

generally exceeds 2.5 psig. We note that 

some storage tanks can operate at 

elevated pressure (i.e., pressure tanks). 

Therefore, rather than follow exactly the 

requirements in the California rules, we 

determined it more practical to exclude 

PRD with design release pressure of less 

than 2.5 psig. 

Any release from a PRD in heavy 

liquid service would have a visual 

indication of a leak and any repairs to 

the valve would have to be further 

inspected and, if necessary, repaired 

under the existing equipment leak 

provisions. Therefore, consistent with 

the BAAQMD rule, we are exempting 

PRD in heavy liquid service from the 

work practice standards we are 

establishing in this final rule. 

Both the BAAQMD and SCAQMD 

rules exempt thermal expansion valves 

that are ‘‘vented to process drains or 

back to the pipeline.’’ We are unclear 

what is meant by ‘‘vented to process 

drains’’; however, if a liquid is released 

from a PRD via hard-piping to a drain 

system that meets the control 

requirements specified in Refinery 

MACT 1, we consider that these PRD are 

controlled and they would not be 

subject to the work practice standard 

established in this final rule. Similarly, 

all PRD in light liquid service that are 

hard-piped to a controlled drain system 

(or back to the process or pipeline) are 

otherwise subject to a MACT 

requirement and would not be subject to 

the work practice standard. 

In considering thermal relief valves 

not vented to process drains or back to 

the pipeline, we expect that releases 

from these thermal relief valves will be 

small and generally under the release 

event thresholds specified in the 

California rules. Therefore, the work 

practice standards do not apply to PRD 

that are designed solely to release due 

to liquid thermal expansion. 

The primary goal of the PRD work 

practice standard is to reduce the size 

and frequency of releases. The 

SCAQMD rule is targeted towards fairly 

large releases (compared to the direct 

PRD releases reported in response to the 

Refinery ICR), so it will reduce the 

frequency of large releases, but it does 

little to reduce the frequency of smaller 

releases. To more effectively reduce the 

size and frequency of all releases, we 

consider it important to require the 

implementation of prevention measures 

(as required in the BAAQMD rule) and 

require root cause analysis and 

corrective action for PRD releases from 

all PRD subject to the work practice 

standard. While we recognize that if a 

PRD opens for a short period of time, 

the release might be below the release 

thresholds in the SCAQMD rules, we 

believe the release may be indicative of 

an important issue or design flaw. 

Because the potential for large 

emissions exist from the PRD subject to 

the work practice standard, we think it 

is reasonable to require a root cause 

analysis be conducted and appropriate 

corrective action implemented to 

potentially identify this issue and 

prevent a second release which, if the 

issue remains uncorrected, could be 

significant. 

Requiring that prevention measures 

be implemented on all PRD subject to 

the work practice standard and not 

establishing a release threshold for 

release events is a variation from the 

SCAQMD rule. However, we also 

considered the allowable release 

frequency. We believe that our adoption 

of this approach is balanced by our not 

adopting the SCAQMD provisions 

requiring that PRD be vented to a flare 

or other control system or that refiners 

pay a fee if there are multiple releases 

of a certain size within a specified 

timeframe.12 In place of this system, we 

are limiting the number of events from 

each PRD that can occur in a 3 year time 

period (2, if root causes are different), 

and in place of a fine, or routing to 

control, stating that the 3rd release in 3 

years for any root cause is a deviation 

of the standard. 

Because we are not including a size 

threshold for release events as in the 

SCAQMD rule, it is natural to assume 

release events would occur more 

frequently than release events subject to 

the SCAQMD rules. Also, based on our 

Monte Carlo analysis of random rare 

events, we note that it is quite likely to 

have two or three events in a 5-year 

period when a long time horizon (e.g., 

20 years) is considered. Therefore, 

considering our analysis of emergency 

flaring events and the lack of a 500 lb/ 

day release threshold, we considered it 

reasonable to use a 3-year period rather 

than a 5-year period as the basis of a 

deviation of the work practice standard. 

The SCAQMD work practice 

standards do not apply to releases that 

are demonstrated to ‘‘result from natural 

disasters, acts of war or terrorism, or 

external power curtailment beyond the 

refinery’s control, excluding power 

curtailment due to an interruptible 

service agreement.’’ These types of 

events, which we are referring to as 

‘‘force majeure’’ events, are beyond the 

control of the refinery owner or 

operator. We are providing that these 

events should not be included in the 

event count, but that they would be 

subject to the root cause analysis in 

order to confirm whether the release 

was caused by a force majeure event. 

Consistent with the requirements in 

the SCAQMD rule, we are requiring 

refinery owners or operators to conduct 

a root cause analysis for a PRD release 

event. If the root cause was due to 

operator error or negligence, then the 

release would be a deviation of the 

standard. For any other release (not 

including those caused by force majeure 

events), the owner or operator would 

have to implement corrective action. We 

consider that a second release due to the 

same root cause for the same equipment 

in a 3-year period would be a deviation 

of the work practice standard. This 

provision will help ensure that root 

cause/corrective action are conducted 

effectively. Finally, a third release in a 

3-year period (not including those 

caused by force majeure events) would 

be a deviation of the work practice 

standard, regardless of the root cause. 

While we are using a 3-year interval 

rather than the 5-year interval provided 

in the SCAQMD, we consider that the 

requirements as included in this final 

rule (i.e., the inclusion of prevention 

measure requirements and no 

thresholds for release events) will 

achieve equivalent if not greater 

emissions reductions than the SCAQMD 

rule. We also consider that, given the 

prevention measure requirements and a 

3-year period, there is less likelihood of 

unusual random events that happen 

over a short period of time that may 

cause refinery owners or operators to 

feel compelled to vent the PRD to a flare 

to eliminate concerns regarding 

potential non-compliance. Thus, we 

project that the requirements that we 

have included in the final rule will 

achieve emissions reductions 

commensurate to or exceeding the 

requirements in the SCAQMD rule (that 

serves as the MACT floor for existing 

sources) but will achieve those 


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reductions in a more cost-effective 

manner. 

We also considered requiring all PRD 

to be vented through a closed vent 

system to a control device as an 

alternative beyond-the-MACT floor 

requirement. While this requirement 

would provide additional emission 

reductions beyond those we are 

establishing as the MACT floor, these 

reduction come at significant costs. 

Capital costs for requiring control of all 

atmospheric PRD is estimated to be 

approximately $300 million compared 

to $11 million for the requirements 

described above. The total annualized 

cost for requiring control of all 

atmospheric PRD is estimated to be 

approximately $41 million/year 

compared to $3.3 million/year for the 

requirements described above. We 

estimate that the incremental costeffectiveness of requiring control of all 

atmospheric PRD compared to the 

requirements described above exceeds 

$1 million per ton of HAP reduced. 

Consequently, we conclude that this is 

not a cost-effective option for existing 

sources. 

The final requirements that we have 

developed for PRD achieve equal or 

greater emission reductions than those 

achieved by the SCAQMD rule (MACT 

floor). To the extent those requirements 

are more stringent that the SCAQMD, 

they are cost-effective. We could not 

identify an alternative requirement that 

provided further emission reductions in 

a cost-effective manner. Thus, we 

conclude that the work practice 

standards described above represent 

MACT for existing sources. 

The BAAQMD rule, which represents 

the requirements applicable to the best 

performing sources, is the basis for new 

source MACT for PRD. Based on the 

specific provisions for PRD in the 

BAAQMD rule, we conclude that the 

MACT floor requirement is to have all 

PRD in HAP service associated with a 

new affected source vented through a 

closed vent system to a control device. 

As with existing sources, the PRD WPS 

would also contain the same exclusions 

(e.g., heavy liquid service PRDs, thermal 

expansion valves, liquid PRDs that are 

hard-piped to controlled drains, PRD 

with release pressures of less than 2.5 

psig, PRD with emission potential of 

less than 72 lbs/day, and PRD on mobile 

equipment). These provisions are 

similar to the applicability provisions of 

the BAAQMD rule. Thus, we retain the 

same applicability of the work practice 

standard for PRDs on new or existing 

equipment, but all affected PRD on a 

new source would be required to be 

controlled. This is essentially equivalent 

to the proposed requirement of no 

atmospheric releases. We could not 

identify a control option more stringent 

than the BAAQMD rule as applied to 

new sources. Therefore, we conclude 

that venting all PRD in HAP service 

through a closed vent system to a flare 

or similar control system is MACT for 

PRD associated with new affected 

sources. 

We consider it appropriate to 

establish a work practice standard for 

PRD as provided in CAA section 112(h). 

While it may be possible to design and 

construct a conveyance for PRD 

releases, we consider that the 

application of a measurement 

methodology for PRDs is not practicable 

due to technological and economic 

limitations. First, it is not practicable to 

use a measurement methodology for 

PRD releases. The venting time can be 

very short and may vary widely in 

composition and flow rate. The oftenshort duration of an event makes it 

infeasible to collect a grab sample of the 

gases when a release occurs, and a 

single grab sample would not account 

for potential variation in vent gas 

composition. It would be economically 

prohibitive to construct an appropriate 

conveyance and install and operate 

continuous monitoring systems for each 

individual PRD in order to attempt to 

quantitatively measure a release event 

that may occur only a few times in a 3- 

year period. Additionally, we have not 

identified an available, technically 

feasible continuous emission 

monitoring systems that can determine 

a mass VOC or HAP release quantity 

accurately given the flow, composition 

and composition variability of potential 

PRD releases from refineries. 

Consequently, we conclude that it is 

appropriate to establish a work practice 

standard for PRD releases as provided in 

CAA section 112(h). 

D. NESHAP Amendments Addressing 

Emissions During Periods of SSM 

1. What amendments did we propose to 

address emissions during periods of 

SSM? 

We proposed to eliminate the SSM 

exemption in 40 CFR part 63, subparts 

CC and UUU. Consistent with Sierra 

Club v. EPA, we proposed standards in 

these rules that apply at all times. We 

also proposed several revisions to Table 

6 of subpart CC of 40 CFR part 63 and 

to Table 44 to subpart UUU of 40 CFR 

part 63 (the General Provisions 

Applicability tables for each subpart), 

including eliminating the incorporation 

of the General Provisions’ requirement 

that the source develop an SSM plan, 

and eliminating and revising certain 

recordkeeping and reporting 

requirements related to the SSM 

exemption. 

For Refinery MACT 1, we proposed 

that the use of a bypass at any time to 

divert a Group 1 miscellaneous process 

vent to the atmosphere is a deviation of 

the emission standard, and specified 

that refiners install, maintain and 

operate a continuous parameter 

monitoring system (CPMS) for flow that 

is capable of recording the volume of 

gas that bypasses the APCD. 

We also proposed to revise the 

definition of MPV to remove the 

exclusion for ‘‘Episodic or non-routine 

releases such as those associated with 

startup, shutdown, malfunction, 

maintenance, depressuring and catalyst 

transfer operations.’’ We also proposed 

that the control requirements for Group 

1 MPV apply at all times, including 

startup and shutdowns. 

For Refinery MACT 2, we proposed 

alternate standards for three emission 

sources for periods of startup or 

shutdown. We proposed PM standards 

for startup of FCCU controlled with an 

ESP under Refinery MACT 2 because of 

safety concerns associated with 

operating an ESP during an FCCU 

startup. For FCCU controlled by an ESP, 

we proposed a 30-percent opacity limit 

(on a 6-minute rolling average basis) 

during the period that torch oil is used 

during FCCU startup. For startup of 

FCCU without a post-combustion device 

under Refinery MACT 2, we proposed a 

CO standard based on an excess oxygen 

concentration of 1 volume percent (dry 

basis) based on a 1-hour average. For 

periods of SRU shutdown, we proposed 

to allow diverting the SRU purge gases 

to a flare meeting the design and 

operating requirements in 40 CFR 

63.670 (or, for a limited transitional 

time period, 40 CFR 63.11) or to a 

thermal oxidizer operated at a minimum 

temperature of 1,200 °F and a minimum 

outlet oxygen concentration of 2 volume 

percent (dry basis). For other emission 

sources in Refinery MACT 2, we 

proposed that the requirements that 

apply during normal operations should 

apply during startup and shutdown. 

2. How did the SSM provisions change 

since proposal? 

a. Refinery MACT 1 

We proposed that when process 

equipment is opened to the atmosphere 

(e.g., for maintenance), the existing MPV 

emissions limits apply. In this final rule, 

we are instead finalizing startup and 

shutdown provisions that apply to these 

venting events. These startup and 

shutdown provisions are work practice 

standards that allow refinery owners or 

operators to open process equipment 


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during startup and shutdown provided 

that the equipment is drained and 

purged to a closed system until the 

hydrocarbon content is less than or 

equal to 10-percent of the LEL. For those 

situations where 10-percent LEL cannot 

be demonstrated (no direct 

measurement location), the equipment 

may be opened and vented to the 

atmosphere if the pressure is less than 

or equal to 5 psig. Active purging of the 

equipment is only allowed after the 10- 

percent LEL level is achieved, regardless 

of the pressure of the equipment/vessel. 

We are establishing a separate 

requirement for very small process 

equipment, defined as equipment where 

it is physically impossible to release 

more than 72 lbs VOC per equipment 

opening based on the size and contents 

of the equipment. This definition is 

consistent with the Group 1 

applicability cutoff for control of 

miscellaneous process vents. We also 

developed requirements specific to 

catalyst changeout activities where 

pyrophoric catalyst (e.g., hydrotreater or 

hydrocracker catalysts) must be purged 

using recovered hydrogen. These 

provisions include: Documenting the 

procedures for equipment openings and 

procedures for verifying that events 

meet the specific conditions above using 

site procedures used to de-inventory 

equipment for safety purposes (i.e., hot 

work or vessel entry procedures) and 

documenting any deviations from the 

work practice standard requirements. 

b. Refinery MACT 2 

We are expanding the proposed 1- 

percent minimum oxygen operating 

limit alternative for organic HAP to 

apply for all FCCU startup and 

shutdown events (rather than only 

partial burn FCCU with CO boilers 

during startup). We are replacing the 

proposed opacity limit alternative to the 

metal HAP standard with a minimum 

cyclone face velocity limit and we are 

extending that alternative limit to all 

FCCU (regardless of control device) for 

both startup and shutdown in this final 

rule. 

We are extending the proposed 

alternative for SRU to monitor 

incinerator temperature and excess 

oxygen limits during SRU shutdowns to 

also apply during periods of startup. 

3. What key comments did we receive 

on the SSM revisions and what are our 

responses? 

a. Refinery MACT 1 

Comment: Many commenters stated 

that the proposed extension of the MPV 

definition to episodic maintenance 

startup and shutdown vents and 

elimination of the SSM exception for 

storage tanks would create hundreds or 

thousands of new vents per refinery per 

year and generate massive on-going 

burdens. The commenters argued that 

the EPA has not included in the record 

any analysis of the potential 

environmental benefits, costs or 

operational and compliance feasibility 

and impacts associated with this 

requirement and that many of these 

requirements will result in delayed and 

extended equipment and process 

outages. One commenter asserted that 

the EPA has articulated no justification 

for applying emission standards to these 

events, nor any analysis consistent with 

CAA section 112 for a determination 

that MACT standards are appropriately 

applied to these emission events under 

the criteria in CAA section 112(d). 

Many commenters stated that every 

time a vessel is opened for inspection or 

maintenance each vent point will have 

to be evaluated as a potential MPV or 

storage tank vent. If a particular vent 

point (e.g., bleeder) used for 

maintenance, startup or shutdown 

handles material that is initially greater 

than 20 ppm HAP, then it is a MPV. If 

there is a potential to emit greater than 

or equal 72 lbs/day of VOC, then it is 

a Group 1 MPV and must be controlled. 

If there is a potential of less than 72 lb/ 

day VOC release, then it is a Group 2 

MPV and subject to recordkeeping 

requirements. Commenters stated that in 

a refinery there would be tens or more 

such activities per day associated with 

normal maintenance and inspection; 

during turnarounds, there could be 

hundreds of such MPVs. Commenters 

added that these MPVs may then need 

to be individually accounted for and 

permitted creating an unnecessary 

permitting and recordkeeping burden 

for these periodic emissions. 

Commenters recommended a general 

set of work practice requirements for 

maintenance, startup and shutdown of 

vents, based on state requirements, that 

do not impose the permitting, notice 

and evaluation requirements associated 

with identifying these vents 

individually. Commenters explained 

that states have dealt with these 

episodic vents by establishing them as 

a special class of process vent with 

limited recordkeeping requirements and 

subject to a work practice standard, 

rather than the normal MPV 

requirements. A key element of these 

work practices is clear identification of 

the criteria for releasing these vents to 

the atmosphere and for routing these 

vents to control after hydrocarbon is 

reintroduced, which the commenters 

asserted the current rule does not 

provide. Commenters proposed that a 

work practice standard could include 

removing process liquids to the extent 

practical and depressuring smaller 

volume equipment until a pressure of 

<5 psig is achieved and/or purging and 

depressuring to a control device until 

the vent has a hydrocarbon 

concentration of less than 10-percent of 

the LEL. The commenters suggested that 

these standards should provide clear 

easily monitored criteria for when this 

equipment can be vented to the 

atmosphere, and should not impose the 

permitting, notice and evaluation 

requirements associated with 

identifying these vents as individual 

MPVs. One commenter provided draft 

regulatory language for a work practice 

requirement. 

Response: We proposed to eliminate 

the episodic and non-routine emission 

exclusion in order to ensure that the 

MACT includes emission limits that 

apply at all times consistent with the 

holding in Sierra Club. At the time of 

the proposal, we expected that 

essentially all SSM event emissions 

would be routed to flares that are 

subject to the MACT standards and, 

thus, would serve to control these 

emissions. However, we recognize that 

maintenance activities that require 

equipment openings are a separate class 

of startup/shutdown emissions because 

there must be a point in time when the 

vessel can be opened and any emissions 

vented to the atmosphere. We 

acknowledge that it would require a 

significant effort to identify and 

characterize each of these potential 

release points for permitting purposes. 

In considering these comments and 

whether we should establish a separate 

limit that would apply to these 

equipment openings, we reviewed state 

permit requirements and the practices 

employed by the best performing 

sources. We found that some state or 

local agencies required depressuring to 

5 psig prior to atmospheric releases 

while others required the gases to have 

organic concentrations at or below 10- 

percent of LEL prior to atmospheric 

venting. In the final rule, we are 

establishing a requirement that prior to 

opening process equipment to the 

atmosphere, the equipment must first be 

drained and purged to a closed system 

so that the hydrocarbon content is less 

than or equal to 10-percent of the LEL. 

For those situations where 10-percent 

LEL cannot be demonstrated, the 

equipment may be opened and vented 

to the atmosphere if the pressure is less 

than or equal to 5 psig, provided there 

is no active purging of the equipment to 

the atmosphere until the LEL criterion 

is met. For equipment where it is not 

technically possible to depressurize to a 


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control system, we allow venting to the 

atmosphere where there is no more than 

72 lbs VOC per day potential, consistent 

with our Group 1 applicability cutoff for 

control of process vents. For catalyst 

changeout activities where hydrotreater 

pyrophoric catalyst must be purged we 

have provided limited allowances for 

direct venting. Provisions to 

demonstrate compliance with this work 

practice include documenting the 

procedures for equipment openings and 

procedures for verifying that events 

meet the specific conditions above using 

site procedures used to de-inventory 

equipment for safety purposes (i.e., hot 

work or vessel entry procedures). 

b. Refinery MACT 2 

Comment: Several commenters noted 

that there was a proposed specific 

alternative metal HAP/PM standard for 

startup of an FCCU controlled with an 

ESP, but took issue with the fact that no 

alternative PM limits were proposed for 

startup of FCCU equipped with other 

types of PM controls, or for any FCCU 

during periods of shutdown or hot 

standby. Regarding the proposed 

alternative for startup, which would 

provide an alternative in the form of an 

opacity limit when torch oil is in use, 

commenters stated that there are serious 

process safety concerns which prevent 

most FCCU ESPs from being operated 

when torch oil is in the regenerator, that 

is, during periods of startup, shutdown 

and hot standby. To avoid the 

possibility of a fire and explosion, the 

commenters claimed ESPs are usually 

de-energized and bypassed during these 

periods and, consequently, these FCCUs 

are generally unable to meet the 

proposed 30-percent opacity limit. 

Several commenters stated that the 

EPA’s limits on FCCU opacity during 

SSM are unreasonable and ignore the 

technical requirements for transitional 

operations of those units. The 

commenters indicated that they have 

ESPs located downstream of the CO 

boiler and claimed that for safety 

reasons the CO boiler cannot operate 

during startup, shutdown or hot 

standby. Further, a commenter 

indicated that the ESP cannot operate if 

the CO boiler is not operating and thus 

both the CO boiler and the ESP must be 

bypassed during startup, shutdown, and 

hot standby operations. 

Another commenter stated that the 

EPA offers no data to support the 

achievability of this requirement in 

practice and discusses information for 

26 startup/shutdown events that found 

that none complied with a 30-percent 

opacity requirement. Several 

commenters also noted that experience 

has shown that the 30-percent opacity 

limit is unachievable during these 

periods for FCCUs controlled with 

tertiary cyclones, when regenerator gas 

flow is below cyclone minimum design 

flow. 

Several commenters suggested that 

the EPA establish a standard based on 

the operation of FCCU catalyst 

regenerators’ internal cyclones that 

function to retain the catalyst in the 

regenerators and thereby minimize 

catalyst and metal HAP emissions from 

the regenerators. Additional control to 

meet the Refinery MACT 2 emission 

limit of not more than 1.0 lb PM/1,000 

lbs coke burn-off is provided by a bag 

house, wet gas scrubber (WGS), ESP or 

tertiary (external) cyclone. The 

efficiency of a cyclone is a function of 

the inlet gas velocity. Assuring adequate 

velocity to the internal cyclones ensures 

that the catalyst sent to these additional 

controls is minimized and ensures that 

they are operating as effectively as 

possible. Similarly, even if the FCCU 

cannot meet the normal opacity limits 

during startup, shutdown or hot standby 

(e.g. due to the ESP being off-line for 

safety reasons or the tertiary cyclones or 

WGS operating at non-routine 

conditions), assuring adequate velocity 

to the internal regenerator cyclones will 

control and minimize particulate 

emissions. Several commenters stated 

support for another commenter’s 

position that all FCCUs should be 

allowed the option of complying with a 

20 feet/second minimum inlet velocity 

to the primary regenerator cyclones 

during periods of startup and shutdown, 

including hot standby, and these 

commenters provided additional 

technical explanations in their 

comments. 

On the other hand, some commenters 

seemed to support the proposed opacity 

limits, but suggested minor revisions. 

One commenter noted that the 

SCAQMD has granted Valero’s request 

for variances from visible emission 

standards during startup of the FCCU of 

up to 65-percent opacity for up to five 

minutes, in aggregate, during any 1-hour 

period, and 30-percent as an hourly 

average for the remaining period, during 

startup events. The application of this 

variance reflects the unavailability and/ 

or ineffectiveness of the ESP during the 

startup condition. Another commenter 

recommended that either the opacity 

standard should be raised or the time 

period for averaging should be extended 

so FCCUs can be operated safely during 

SSM events and still remain in 

compliance. 

Response: We have reviewed the data 

submitted by the commenters to support 

their assertion that the 30-percent 

opacity limit (determined on a 6-minute 

average basis) is not achievable during 

startup and shutdown events. While the 

data are limited, and it is unclear if the 

data provided are indicative of the 

performance achieved by the best 

performing sources, we do not have 

adequate data to refute the assertion that 

the 30-percent opacity limit (determined 

on a 6-minute average basis) is not 

achievable during startup and shutdown 

events. We considered the two options 

suggested by the commenters, the 

minimum velocity for the internal FCCU 

regenerator cyclones and the 30-percent 

hourly average opacity limit excluding 5 

minutes not exceeding 65-percent 

opacity. Again, due to the limited data 

available during startup and shutdown 

events, we are not able to determine 

which requirement would provide 

greater HAP emissions reduction. 

However, we note that some facilities 

may not be required to have an opacity 

monitoring system in place and opacity 

monitoring is not applicable for FCCU 

controlled with wet scrubbers. 

Therefore, we find that the minimum 

internal cyclone inlet velocity 

requirement is more broadly applicable 

than the opacity limit. Also, based on 

the data provided by the commenters, 

the minimum internal cyclone inlet 

velocity requirement will provide PM 

(and therefore metal HAP) emissions 

reductions during startup and shutdown 

periods. Therefore, considering the 

available data, we conclude that MACT 

for FCCU startup and shutdown events 

is maintaining the minimum internal 

cyclone inlet velocity of 20 feet/second. 

Comment: Several commenters stated 

that the EPA should provide alternate 

standards for startups of FCCU 

equipped with CO boilers and for any 

FCCU during periods of shutdown and 

hot standby. The commenters stated that 

the EPA incorrectly assumes that 

refiners are able to safely and reliably 

start up their FCCU with flue gas boilers 

in service and meet the normal 

operating limit of 500 ppm CO. They 

claimed that most refiners are unable to 

reliably start up their FCCU with flue 

gas boilers in service due to the design 

of the boiler and the fact that many 

boilers are not able to safely and reliably 

handle the transient FCCU operations 

that can occur during startup, 

shutdown, and hot standby. One 

commenter stated that FCCU built with 

CO boilers experience issues with flame 

stability due to fluctuating flue gas 

compositions and rates when starting up 

and shutting down. Accordingly, the 

commenter stated, startup and 

shutdown activities at FCCU using a 

boiler as an APCD are not currently 

meeting the Refinery MACT 2 standard 


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of 500 ppm CO on a 1-hour basis, and 

this level of control does not qualify as 

the MACT floor. The commenter gave 

examples of facilities where FCCU, 

including those equipped with postcombustion control systems, do not 

consistently demonstrate compliance 

with a 500 ppm CO concentration 

standard during all startup and 

shutdown events. 

Commenters stated that reliable boiler 

operation is critical to the overall 

refinery steam system and refineries 

must avoid jeopardizing boiler 

operation to prevent major upsets of 

process operations. A major upset or 

site-wide shutdown could result in 

flaring and emissions of HAP far in 

excess of that emitted while bypassing 

the CO boiler. 

Commenters stated that combustion of 

torch oil in the FCCU regenerator during 

startup is one of the primary reasons the 

CO limit cannot be met during these 

operations. Torch oil is also used during 

shutdown to control the cooling rate 

(and potential equipment damage) and 

during hot standby and, thus, the 

normal CO standard cannot be met at 

these times either. Hot standby is used 

to hold an FCCU regenerator at 

operating temperature for outages where 

a regenerator shutdown is not needed 

and to avoid full FCCU shutdowns. Full 

cold shutdown also increases personnel 

exposures associated with removing 

catalyst and securing equipment. 

Additionally, this can produce 

additional emissions over maintaining 

the unit in hot standby. Commenters 

claimed that because of the variability of 

CO during torch oil operations, it is not 

possible for the EPA to establish a CAA 

section 112(d) standard for startup and 

shutdown activities at FCCU because 

refineries cannot measure a constant 

level of emissions reductions. 

The commenters recommended 

expansion of the proposed standard of 

greater than 1-percent hourly average 

excess regenerator oxygen to all FCCU, 

including units with fired boilers. These 

commenters suggested that maintaining 

an adequate level of excess oxygen for 

the combustion of fuel in the 

regenerator is the best way to minimize 

CO and organic HAP emissions from 

FCCU during these periods. 

Response: After reviewing the 

comments and discussing CO boiler 

operations with facility operators, we 

agree that the 1-percent minimum 

oxygen limit should be more broadly 

applicable to FCCU startup and 

shutdown regardless of the control 

device configuration and have revised 

the final rule accordingly. 

Comment: Several commenters stated 

that the proposed alternative standards 

for SRP shutdowns should be extended 

to startups as well since the normal SRP 

emission limitation cannot always be 

achieved during SRP startups. Several 

commenters gave examples of startup 

activities where this relief is needed, 

and noted there may be other startup 

activities that also need this relief. 

Response: For the control of sulfur 

HAP, we determined that incineration 

effectively controls these HAP. We were 

not aware that there would be unusual 

sulfur loads in the SRU tail gas during 

startup. We agree that the alternative 

standard we proposed for periods of 

shutdown is also the MACT floor for 

periods of startup because incineration 

meeting the limits proposed will 

achieve the MACT control requirements 

for sulfur HAP during periods of either 

startup or shutdown even though sulfur 

loadings during these periods may be 

elevated. For many SRU configurations, 

compliance during normal operations is 

demonstrated by monitoring SO2

emissions. However, during startup and 

shutdown, high sulfur loadings in the 

SRU tail gas entering the incinerator 

will cause high SO2 emissions even 

though sulfur HAP emissions are well 

controlled. Consequently, the proposed 

incinerator operating limits provide a 

better indication of sulfur HAP control 

during startup and shutdown than SO2

emissions. Owners or operators that use 

incinerators or thermal oxidizers during 

normal operations may meet the sitespecific temperature and excess oxygen 

operating limits that were determined 

based on their performance test during 

periods of startup and shutdown. 

4. What is the rationale for our final 

approach and final decisions to address 

emissions during periods of SSM? 

a. Refinery MACT 1 

We did not receive comments 

regarding the proposed amendments to 

Table 6 of subpart CC of 40 CFR part 63; 

therefore, for the reasons provided in 

the preamble to the proposed rule, we 

finalizing these amendments as 

proposed. 

We determined that it was overly 

burdensome and in most cases 

technically infeasible to consider every 

potential equipment or vessel opening 

and classify these ‘‘openings’’ (newly 

classified as MPV in the proposal) as 

either Group 1 or Group 2 MPV. We also 

determined that it is not always 

technically feasible, depending on the 

opening, to demonstrate compliance 

with the MPV emissions limitations. 

After considering the public comments, 

we determined it was appropriate to 

establish separate startup and shutdown 

provisions for MPV associated with 

process equipment openings. We 

reviewed state and local requirements 

and based the final rule requirements on 

the emissions limitations required to be 

followed by the best performing sources. 

Therefore, we are finalizing 

requirements for refinery owners or 

operators to open process equipment 

during these startup and shutdown 

events without directly permitting these 

‘‘vents’’ as Group 1 or Group 2 MPV 

provided that the equipment is drained 

and purged to a closed system until the 

hydrocarbon content is less than or 

equal to 10-percent of the LEL. As 

described in further detail previously in 

this section, we have provided 

provisions for special cases where the 

10-percent LEL limit cannot be 

demonstrated and provisions for less 

significant equipment openings, 

consistent with the practices used by 

the best performing facilities. 

b. Refinery MACT 2 

We did not receive significant 

comments regarding the proposed 

amendments to Table 44 to subpart 

UUU of 40 CFR part 63; therefore, we 

finalizing these amendments as 

proposed. 

In response to comments, we 

determined that the limited provisions 

that were provided for startup only or 

for shutdown only were too limited and 

we have expanded the proposed 

provisions to both startup and 

shutdown regardless of control device 

used. For the FCCU organic HAP 

emissions limit, we are finalizing an 

alternative limit for periods of startup of 

no less than 1-percent oxygen in the 

exhaust gas as proposed, but we are 

extending that alternative limit to 

shutdown and to all FCCU in this final 

rule. 

For the FCCU metal HAP emissions 

limit, we proposed a specific startup 

limit for FCCU controlled be an ESP of 

30-percent opacity. We received 

comments along with limited data 

suggesting that this limit was not 

achievable. Commenters suggested that 

the best performing units maintain a 

minimum face velocity of at least 20 

feet/second to minimize catalyst PM 

losses during startup and shutdowns. 

Operators of wet scrubbers also noted 

that they cannot maintain pressure 

drops and that one cannot meet the PM 

emissions limit normalized by coke 

burn-off rate when the coke burn-off rate 

approaches zero. Consequently, 

commenters stated that the alternative 

limits should be provided for startup 

and shutdown regardless of control 

device. Upon consideration of the 

comments, we determined that it was 

necessary to revise the proposed 


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alternative to be based on minimum 

inlet face velocity to the FCCU 

regenerator internal cyclones and 

provide the alternative for both startup 

and shutdown. We also expanded this 

limit to all FCCU; however, we also 

required FCCU with wet scrubbers to 

meet only the liquid to gas ratio 

operating limit during periods of startup 

and shutdown to allow wet scrubbers to 

use a consistent compliance method at 

all times. 

For SRU, we are finalizing an 

alternative standard during periods of 

startup and shutdown to use a flare that 

meets the operating limits included in 

the final rule or a thermal oxidizer or 

incinerator operated at a minimum 

hourly average temperature of 1,200 °F 

and a minimum hourly average outlet 

oxygen concentration of 2 volume 

percent (dry basis). We proposed these 

alternatives for periods of shutdown 

only, but based on comments received 

regarding startup issues, we determined 

that high sulfur loadings can occur 

during periods of startup and that the 

alternative limit proposed was 

appropriate for both startup and 

shutdown. 

E. Technical Amendments to Refinery 

MACT 1 and 2 

1. What other amendments did we 

propose for Refinery MACT 1 and 2? 

We proposed a number of 

amendments to Refinery MACT 1 and 2 

to address technical issues such as rule 

language clarifications and reference 

corrections. First, we proposed to 

amend Refinery MACT 1 to clarify what 

is meant by ‘‘seal’’ for open-ended 

valves and lines that are ‘‘sealed’’ by the 

cap, blind flange, plug, or second valve 

by stating that sealed means when there 

are no detectable emissions from the 

open-ended valve or line at or above an 

instrument reading of 500 ppm. Second, 

we also proposed electronic reporting 

requirements where owners or operators 

of petroleum refineries must submit 

electronic copies of required 

performance test and performance 

evaluation reports for compliance with 

Refinery MACT 1 and 2 by direct 

computer-to-computer electronic 

transfer using EPA-provided software. 

Third, we proposed to update the 

General Provisions Tables 6 (for 

Refinery MACT 1) and 44 (for Refinery 

MACT 2) to correct cross references and 

to incorporate additional sections of the 

General Provisions that are necessary to 

implement these rules. 

2. How did the other amendments for 

Refinery MACT 1 and 2 change since 

proposal? 

We are not finalizing the definition of 

‘‘seal’’ for open-ended lines as 

proposed. We are finalizing changes to 

update the General Provisions crossreference tables as proposed, with one 

minor change to provide an option for 

the administrator to issue guidance on 

performance test reporting timeframes 

in order to address issues relating to 

submittal of data to the ERT. 

3. What key comments did we receive 

on the other amendments for Refinery 

MACT 1 and 2 and what are our 

responses? 

Comment: Numerous commenters 

objected to the proposal to clarify the 

meaning of ‘‘seal’’ as it relates to openended line (OEL) standards. 

Commenters contend that there is no 

basis for the EPA to assert that the 

proposed definition merely ‘‘clarifies’’ 

an established interpretation of the term 

‘‘seal’’ and stated that the proposed 

revision constitutes an illegal change in 

the requirements for OELs, and the 

clarification should not be finalized. 

One commenter stated that none of 

the MACT standards in place before this 

proposal have stated or suggested that a 

‘‘sealed’’ OEL is one with detectable 

emissions below 500 ppm. This 

commenter added this unique 

interpretation of the requirement to 

‘‘seal’’ an OEL with a cap or plug is 

incompatible with the historical 

interpretation of this requirement by 

affected facilities and by the EPA, and 

the EPA has not issued any sort of 

definitive guidance or interpretation 

setting out this position. The commenter 

detailed numerous references to 

considerations the EPA has made 

relative to OEL requirements in LDAR 

programs. In addition to the examples 

cited, the commenter noted that in 2006, 

the EPA proposed to add a ‘‘no 

detectible emissions’’ limit and 

monitoring requirement for OELs to 

NSPS VV (71 FR 65317, November 7, 

2006). Two commenters noted that the 

proposed monitoring was not finalized 

in either NSPS VV or VVa (72 FR 64860, 

November 16, 2007) because it was not 

considered BDT due to the low emission 

reductions and the cost effectiveness of 

the requirement. Another commenter 

agreed that there is no explanation 

provided for why this information could 

now support the need for a new OEL 

seal standard that requires monitoring to 

ensure compliance when it was deemed 

to be unjustified previously. 

In addition, the commenter collected 

OEL monitoring data and submitted it to 

the EPA (see Docket Item No. EPA–HQ– 

OAR–2010–0869–0058). Based on these 

data, the commenter asserted that the 

existence of leaks from OELs that are 

not properly sealed is extremely low. 

The commenter noted that the EPA is 

claiming this change is only a 

clarification of current requirements, 

allowing the EPA to bypass the need to 

cite a CAA authorization for this change 

to the existing CAA section 112(d)(2) 

standard or meet the process 

requirements associated with such a 

change, including providing emission 

reduction, cost and burden estimates in 

the record and the associated PRA 

Information Collection Request (ICR). 

Several commenters claimed that this 

clarification would result in retroactive 

impact and also addressed the 

implication of the proposed change on 

other fugitive emissions standards. One 

commenter stated that the EPA cannot 

retroactively reinterpret the OEL 

requirements or define the word ‘‘seal’’ 

and added that the EPA should account 

for the thousands of additional 

monitoring events per year per refinery 

that this new requirement would add to 

LDAR programs and provide proper cost 

justification under CAA sections 

112(d)(6) or 112(f)(2). 

Several commenters also stated that 

the proposed definition will effectively 

change all equipment leak rules in parts 

40 CFR parts 60, 61 and 63 and the 

change should not be finalized. One 

commenter added that by claiming this 

change is only a clarification of current 

requirements, the EPA would set a 

precedent applicable to all OELs in all 

industries subject to any similar OEL 

equipment leak requirement. 

Response: We have decided not to 

finalize the proposed clarification of the 

term ‘‘seal’’ for OELs at this time. The 

fenceline monitoring requirements we 

are finalizing will detect any significant 

leaks from a cap, blind flange, plug or 

second valve that does not properly seal 

an OEL, as well as significant leaks from 

numerous other types of fugitive 

emission sources. 

Comment: A few commenters stated 

that the proposed use of the ERT is not 

appropriate because the costs and 

burdens imposed are additive to the 

costs of producing and submitting the 

written report, and there is no benefit 

that justifies the additional cost. One 

commenter also stated that the EPA has 

not developed or articulated a 

reasonable approach to using 

information that would be uploaded to 

the ERT. The commenters 

recommended that the EPA remove this 

portion of the proposal until the ERT is 

demonstrated to handle all the 

information from refinery performance 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75223 

13EPA’s ‘‘Final Plan for Periodic Retrospective 

Reviews,’’ August 2011. Available at: http://www.

epa.gov/regdarrt/retrospective/documents/

eparetroreviewplan-aug2011.pdf. 

14 Digital Government: Building a 21st Century 

Platform to Better Serve the American People, May 

2012. Available at: https://www.whitehouse.gov/

sites/default/files/omb/egov/digital-government/

digital-government-strategy.pdf. 

tests (rather than only portions), thereby 

eliminating the need for both written 

and electronic reporting and until the 

Agency demonstrates that it is using the 

electronic data to develop improved air 

quality emission factors. 

Other commenters stated that the ERT 

requirement does not supersede or 

replace any state reporting requirements 

and thus the regulated industry will be 

subject to dual reporting requirements. 

These commenters disagreed with the 

preamble claim that eliminating the 

recordkeeping requirements for 

performance test reports is a burden 

savings, and stated that it may duplicate 

burdens already borne by the regulated 

community. 

The commenters expressed further 

concern that duplicative reporting 

requirements will strain the regulated 

industry to comply with deadlines 

established by rule for report submittals. 

One commenter stated that there is no 

mechanism for obtaining extensions for 

special circumstances. Under proposed 

40 CFR 63.655(h)(9)(i), all reports are 

due in 60 days. The commenter claimed 

that by not referencing reporting 

requirements to the General Provisions 

in 40 CFR 63.10(d)(2), there is no 

allowance for obtaining additional time 

due to unforeseen circumstances or due 

to the difficulties involved with 

completing particularly complex 

reports. 

One commenter stated that the 

primary performance test method 

(Method 18) required for determining 

compliance is not currently included in 

the list of methods supported by the 

ERT. The commenter stated that the 

regulated community’s experience with 

Method 18 is that it is a very broad 

methodology and can be exceptionally 

complex to execute and to report. The 

commenter stated that the EPA is aware 

that Method 18 reporting is complex, 

that it may be difficult to incorporate 

into the ERT, and that no time schedule 

has been defined for development or 

implementation for this method. 

The commenter also stated that 

without formal notice of changes to the 

ERT, the regulated community is at risk 

of non-compliance. The only way for 

the regulated community to know that 

changes have occurred in the ERT is to 

monitor the Web site directly because 

the EPA does not formally announce 

changes to the ERT in the Federal 

Register. As such, it would be possible 

for a regulated entity to be unaware of 

changes made such as the incorporation 

of Method 18. The commenter 

expressed concern that the proposal 

language is an open-ended commitment 

subject to change without notice. The 

commenter stated that the EPA should 

clearly indicate when facilities would 

be required to use the ERT when new 

test methods are included in the ERT. 

Response: We disagree that use of the 

ERT for completing stack test reports is 

an added cost and burden. While the 

requirement to report the results of stack 

tests with the ERT does not supersede 

state reporting requirements, we are 

aware of several states that already 

require the use of the ERT, and we are 

aware of more states that are 

considering requiring its use. We note 

that where states will not accept an 

electronic ERT submittal, the ERT 

provides an option to print the report, 

and the printed report can be mailed to 

the state agency. We have no reason to 

believe that the time savings in the 

ability to reuse data elements within 

reports does not, at a minimum, offset 

the cost incurred by printing out and 

mailing a copy of the report and the 

commenters have provided no support 

for their cost claims. 

Furthermore, based on the analysis 

performed for the Electronic Reporting 

and Recordkeeping Requirements for 

the New Source Performance Standards 

Rulemaking (ERRRNSPS) (80 FR 15100), 

electronic reporting results in an overall 

cost savings to industry when 

annualized over a 20-year period. The 

cost savings is achieved through means 

such as standardization of data, 

embedded quality assurance checks, 

automatic calculation routines and 

reduced data entry through the ability to 

reuse data in files instead of starting 

from scratch with each test. As outlined 

in the ERRRNSPS, there are many 

benefits to electronic reporting. These 

benefits span all users of the data—the 

EPA, state and local regulators, the 

regulated entities and the public. We 

note that in the preamble to this 

proposed rule we provided a number of 

reasons why the use of the ERT will 

provide benefit going forward and that 

most of the benefits we outlined were 

longer-term benefits (e.g., reducing 

burden of future information collection 

requests). Additionally, we note that in 

2011, in response to Executive Order 

13563, the EPA developed a plan 13 to 

periodically review its regulations to 

determine if they should be modified, 

streamlined, expanded or repealed in an 

effort to make regulations more effective 

and less burdensome. The plan includes 

replacing outdated paper reporting with 

electronic reporting. In keeping with 

this plan and the White House’s Digital 

Government Strategy, 14 in 2013 the 

EPA issued an agency-wide policy 

specifying that new regulations will 

require reports to be electronic to the 

maximum extent possible. By requiring 

electronic submission of stack test 

reports in this rule, we are taking steps 

to implement this policy. We also 

disagree that we have not developed or 

articulated a reasonable approach to 

using information that would be 

uploaded to the ERT. To the contrary, 

we have discussed at length our plans 

for the use of stack test data collected 

via the ERT. In 2009, we published an 

advanced notice of proposed 

rulemaking (74 FR 52723) for the 

Emissions Factors Program 

Improvements. In that notice, we first 

outlined our intended approach for 

revising our emissions factors 

development procedures. This approach 

included using stack test data collected 

with the ERT. We reiterated this 

position in our ‘‘Recommended 

Procedures for the Development of 

Emissions Factors and Use of the 

WebFIRE Database’’ (http://www.epa.

gov/ttn/chief/efpac/procedures/

procedures81213.pdf), which was 

subject to public notice and comment 

before being finalized in 2013. Finally, 

we discussed uses of these data in the 

preamble to the proposed rule and at 

length in the preamble to the 

ERRRNSPS. 

We think that it is a circular argument 

to say that the agency should eliminate 

the use of the ERT until it demonstrates 

that it is using the electronic data. It 

would be impossible for the agency to 

use data that it does not have. We can 

only use electronic data once we have 

electronic data. We do note that we are 

nearing completion of programming the 

WebFIRE database with our new 

emissions factor development 

procedures and anticipate running the 

routines on existing data sets in the near 

future. 

We continue to improve and upgrade 

the ERT on an ongoing basis. The 

current version of the ERT supports 41 

methods, including EPA Methods 1–4, 

5, 5B, 5F, 25A 26, and 26A. We note 

that the ERT does not currently support 

EPA Method 18, and for performance 

tests using Method 18, the source will 

still have to produce a paper report. 

However, we are aware of the need to 

add Method 18 to the ERT, and we are 

currently looking at developing this 

capability. As noted in the ERRRNSPS, 

when new methods are added to the 


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ERT, we will not only post them to the 

Web site; we will also send out a listserv 

notice to the Clearinghouse for 

Inventories and Emissions Factors 

(CHIEF) listserv. Information on joining 

the CHIEF listserv can be found at 

http://www.epa.gov/ttn/chief/

listserv.html#chief. We are requiring the 

use of the ERT if the method is 

supported by the ERT, as listed on the 

ERT Web site (http://www.epa.gov/ttn/

chief/ert/ert_info.html) at the time of the 

test. We do not agree that it is overly 

burdensome to check a Web site for 

updates prior to conducting a 

performance test. 

We did revise the MACT 1 and 2 

tables referencing reporting 

requirements to the general provisions 

(Table 6 for Refinery MACT 1 and Table 

44 for Refinery MACT 2) to provide 

flexibility in the 60-day reporting 

timeline to accommodate unforeseen 

circumstances or difficulties involved 

with completing particularly complex 

reports. 

4. What is the rationale for our final 

approach and final decisions for the 

other amendments for Refinery MACT 1 

and 2? 

We are not finalizing the definition of 

seal, as proposed. The fenceline 

monitoring work practice standard will 

detect any significant leaks from a cap, 

blind flange, plug or second valve that 

does not properly seal an OEL, as well 

as significant leaks from numerous other 

types of fugitive emission sources. 

We are finalizing requirements for 

electronic reporting, as proposed, with a 

minor clarification. Specifically, we are 

revising Tables 6 in subpart CC and 44 

in subpart UUU, which cross-reference 

the applicable provisions in the General 

Provisions to provide flexibility in the 

ERT 60-day reporting timeline. Refiners 

can seek approval from the EPA or a 

delegated state additional time for 

submittal of data due to unforeseen 

circumstances or due to the difficulties 

involved with completing particularly 

complex reports. 

F. Technical Amendments to Refinery 

NSPS Subparts J and Ja 

1. What amendments did we propose for 

Refinery NSPS Subparts J and Ja? 

We proposed a number of 

amendments to Refinery NSPS subparts 

J and Ja to address reconsideration 

issues and minor technical 

clarifications. First, we proposed 

revisions to 40 CFR 60.100a(b) to 

include a provision that sources subject 

to Refinery NSPS subpart J could elect 

to comply instead with the provisions of 

Refinery NSPS subpart Ja. 

Second, we proposed a series of 

amendments to the requirements for 

SRP in 40 CFR 60.102a, to clarify the 

applicable emission limits for different 

types of SRP based on whether oxygen 

enrichment is used. The amendments 

proposed also clarified that emissions 

averaging across a group of emission 

points within a given SRP is allowed for 

each of the different types of SRP, and 

that emissions averaging is specific to 

the SO2 or reduced sulfur standards 

(and not to the 10 ppmv hydrogen 

sulfide (H2S) limit). We also proposed a 

series of corresponding amendments in 

40 CFR 60.106a to clarify the monitoring 

requirements, particularly when oxygen 

enrichment or emissions averaging is 

used. We also proposed clarifications in 

40 CFR 60.106a to consistently use the 

term ‘‘reduced sulfur compounds’’ 

when referring to the emission limits 

and monitoring devices needed to 

comply with the reduced sulfur 

compound emission limits for sulfur 

recovery plants with reduction control 

systems not followed by incineration. 

Third, we proposed amendments to 

40 CFR 60.102a(g)(1) to clarify that CO 

boilers, while part of the FCCU affected 

facility, can also be FGCD. 

Fourth, we proposed several revisions 

to 40 CFR 60.104a to clarify the 

performance testing requirements. We 

proposed revision to 40 CFR 60.104a(a) 

to clarify that an initial compliance 

demonstration is needed for the H2S 

concentration limit in 40 CFR 

60.103a(h). We proposed revisions to 

the annual PM testing requirement in 40 

CFR 60.104a(b) to clarify that annually 

means once per calendar year, with an 

interval of at least 8 months but no more 

than 16 months between annual tests. 

We also proposed to amend 40 CFR 

60.104a(f) to clarify that the provisions 

of that paragraph are specific to owners 

or operators of an FCCU or FCU that use 

a cyclone to comply with the PM 

emissions limit in 40 CFR 60.102a(b)(1) 

and not to facilities electing to comply 

with the PM emissions limit using a PM 

CEMS. We also proposed to amend 40 

CFR 60.104a(j) to delete the 

requirements to measure flow for the 

H2S concentration limit for fuel gas. 

Fifth, we proposed several 

amendments to clarify the requirements 

for control device operating parameters 

in 40 CFR 60.105a. Specifically, we 

proposed amendments to 40 CFR 

60.105a(b)(1)(ii)(A) to require corrective 

action be completed to repair faulty 

(leaking or plugged) air or water lines 

within 12 hours of identification of an 

abnormal pressure reading during the 

daily checks. We also proposed 

revisions to 40 CFR 60.105a(i) to specify 

that periods when abnormal pressure 

readings for a jet ejector-type wet 

scrubber (or other type of wet scrubber 

equipped with atomizing spray nozzles) 

are not corrected within 12 hours of 

identification and periods when a bag 

leak detection system alarm (for a fabric 

filter) is not alleviated within the time 

period specified in the rule are 

considered to be periods of excess 

emissions. 

We also proposed amendments to 40 

CFR 60.105(b)(1)(iv) and 

60.107a(b)(1)(iv) to provide flexibility in 

span range to accommodate different 

manufacturers of the length-of-stain 

tubes. We also proposed to delete the 

last sentence in 40 CFR 60.105(b)(3)(iii). 

Finally, we proposed clarification to 

the performance test requirements for 

the H2S concentration limit for affected 

flares in 40 CFR 60.107a(e)(1)(ii) and 

(e)(2)(ii) to remove the distinction 

between flares with or without routine 

flow. 

2. How did the amendments to Refinery 

NSPS Subparts J and Ja change since 

proposal? 

We are making very few changes to 

the amendments proposed for Refinery 

NSPS subparts J and Ja. In response to 

comments, we are revising the NSPS 

requirements to replace the 

‘‘measurement sensitivity’’ requirements 

with accuracy requirements consistent 

with those used in Refinery MACT 1 

and 2. Specifically, we are revising 40 

CFR 60.106a(a)(6)(i)(B) and (7)(i)(B) to 

require use of a flow sensor meeting an 

accuracy requirement of ±5-percent over 

the normal range of flow measured or 

10-cubic-feet-per-minute, whichever is 

greater. We are also revising the flare 

accuracy requirements in 40 CFR 

60.107a(f)(1)(ii) to require use of a flow 

sensor meeting an accuracy requirement 

of ±20-percent of the flow rate at 

velocities ranging from 0.1 to 1 feet per 

second and an accuracy of ±5-percent of 

the flow rate for velocities greater than 

1-feet-per-second. 

Finally, we are revising 40 CFR 

60.101a(b) to correct an inadvertent 

error where the phrase ‘‘and delayed 

coking units’’ was not included in the 

proposed sentence revision. 

3. What key comments did we receive 

on the amendments to Refinery NSPS 

Subparts J and Ja and what are our 

responses? 

Comment: Two commenters noted 

concern with the term ‘‘measurement 

sensitivity’’ in proposed 40 CFR 

60.106a(a)(6)(i)(B) and (a)(7)(i)(B) for 

sulfur recovery unit monitoring 

alternatives and in existing regulations 

40 CFR 60.107a(f)(1)(ii) for flares 

because ‘‘sensitivity’’ is not a term 


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found on typical monitoring system data 

sheets. Typical flow meter 

characteristics include terms such as 

accuracy and resolution and the 

commenters requested that the EPA 

revise the terminology to match the 

wording found in 40 CFR part 63, 

subpart CC, Table 13 for flow meters 

(i.e., accuracy requirements). 

Additionally, several commenters 

suggested that the EPA flow monitor 

accuracy specifications are inconsistent 

with those in the SCAQMD Flare Rule 

and many refinery consent decrees. The 

commenters recommended revising 

both the flare flow meter sensitivity 

specification and accuracy specification 

in Refinery MACT 1 Table 13 and in 

Refinery NSPS subpart Ja to be 

consistent with the accuracy 

specification from the Shell Deer Park 

Consent Decree, Appendix 1.10, which 

specifies the required flare flow meter 

accuracy as ‘‘±20% of reading over the 

velocity range of 0.1–1 feet per second 

(ft/s) and ±5% of reading over the 

velocity range of 1–250 ft/s.’’ 

Response: We proposed the term 

‘‘measurement sensitivity’’ in proposed 

40 CFR 60.106a(a)(6)(i)(B) and 

(a)(7)(i)(B) to be internally consistent 

within Refinery NSPS subpart Ja [i.e., 

consistent with the existing language in 

§ 60.107a(f)(1)(ii)]. However, we agree 

with the commenters that this term may 

be unclear. This term is not defined in 

Refinery NSPS subpart Ja and it is not 

commonly used in the flow monitoring 

system’s technical specification sheets. 

Therefore, to be consistent with the 

terminology used by instrument vendors 

and used in Refinery MACT 1 and 2, we 

are revising these sections to replace the 

term ‘‘measurement sensitivity’’ with 

‘‘accuracy.’’ We are also revising the 

flow rate accuracy provisions specific 

for flares to provide an accuracy 

requirement of ±20-percent over the 

velocity range of 0.1–1 ft/s and ±5% for 

velocities exceeding 1 ft/s in 40 CFR 

60.107a(f)(1)(ii) and in Table 13 of 

subpart CC. We are providing this 

provision specifically for flares because 

they commonly operate at high 

turndown ratios. For other flow 

measurements, we are retaining the 10- 

cubic-foot-per-minute accuracy 

requirement. We are also clarifying that 

the ±5-percent accuracy requirement for 

the SRU alternatives apply to the ‘‘the 

normal range of flow measured’’ 

consistent with the requirements in 

Refinery MACT 1 and 2. 

Comment: One commenter stated that 

in the proposed revisions to 40 CFR 

60.100a, (79 FR 36956), the EPA 

proposes to remove the phrase ‘‘and 

delayed coker units’’ from 40 CFR 

60.100a(b). However, we state the 

compliance date for both flares and 

delayed coker units separately in the 

same paragraph. The commenter 

believes the EPA should explain the 

reason for and implications of the 

removal of this phrase. 

Response: The removal of the phrase 

‘‘and delayed coking units’’ from the 

first sentence in 40 CFR 60.100a(b) was 

an inadvertent error. The only revision 

that we intended to make in 40 CFR 

60.100a was to allow owners or 

operators subject to subpart J to elect to 

comply with the requirements in 

subpart Ja. In the final amendments, we 

have included the phrase ‘‘and delayed 

coking units’’ in the first sentence in 40 

CFR 60.100a(b). 

4. What is the rationale for our final 

approach and final decisions for the 

amendments to Refinery NSPS Subparts 

J and Ja? 

We are finalizing amendments for 

Refinery NSPS subparts J and Ja as 

proposed with minor revisions. In 

response to comments, we are revising 

the ‘‘measurement sensitivity’’ 

requirements to be an ‘‘accuracy’’ 

requirement. This change will make the 

requirements more clear and consistent 

between the flow meter requirements in 

the NSPS and the MACT standards 

since the same flow meter will be 

subject to each of these requirements. 

We are also providing a dual accuracy 

requirement for flare flow meters. This 

accuracy requirement is necessary 

because flares, which can have large 

diameters to accommodate high flows, 

are commonly operated at low flow 

rates. Together, this makes it technically 

infeasible for many flares to meet the 

lower flow 10 cfm accuracy 

requirement. Therefore, we are 

providing specific accuracy 

requirements for flares of ±20-percent 

over the velocity range of 0.1–1 ft/s and 

±5-percent for velocities exceeding 1 ft/ 

s, consistent with recent consent 

decrees and equipment vendor 

specifications. 

Finally, we are revising the 

introductory phrase in the first sentence 

in 40 CFR 60.101a(b) to read ‘‘Except for 

flares and delayed coking units . . .’’ to 

correct an inadvertent error. We 

intended to revise this sentence only to 

include the proposed provision to allow 

sources subject to Refinery NSPS 

subpart J to comply with Refinery NSPS 

subpart Ja. The redline text posted on 

our Web site showed no revisions to this 

introductory phrase, but the amendatory 

text did not include the words ‘‘and 

delayed coking units’’ in this phrase. 

This was an inadvertent error, which we 

are correcting in the final rule. 

V. Summary of Cost, Environmental 

and Economic Impacts and Additional 

Analyses Conducted 

A. What are the affected facilities, the 

air quality impacts and cost impacts? 

The sources affected by significant 

amendments to the petroleum refinery 

standards include flares, storage vessels, 

pressure relief devices, fugitive 

emissions and DCU. The amendments 

for other sources subject to one or more 

of the petroleum refinery standards are 

expected to have minimal air quality 

and cost impacts. 

The total capital investment cost of 

the final amendments and standards is 

estimated at $283 million, $112 million 

from the final amendments for storage 

vessels, DCU and fenceline monitoring 

and $171 million from standards to 

ensure compliance. We estimate 

annualized costs of the final 

amendments for storage vessels, DCU 

and fenceline monitoring to be 

approximately $13.0 million, which 

includes an estimated $11.0 million for 

recovery of lost product and the 

annualized cost of capital. We also 

estimated annualized costs of the final 

standards to ensure compliance to be 

approximately $50.2 million. The final 

amendments for storage vessels, DCU 

and fenceline monitoring would achieve 

a nationwide HAP emission reduction 

of 1,323 tpy, with a concurrent 

reduction in VOC emissions of 16,660 

tpy and a reduction in methane 

emissions of 8,700 metric tonnes per 

year. Table 2 of this preamble 

summarizes the cost and emission 

reduction impacts of the final 

amendments, and Table 3 of this 

preamble summarizes the costs of the 

final standards to ensure compliance. 


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TABLE 2—NATIONWIDE IMPACTS OF FINAL AMENDMENTS (2010$) 

Affected source 

Total capital 

investment 

(million $) 

Total 

annualized 

cost without 

credit 

(million $/yr) 

Product 

recovery 

credit 

(million $/yr) 

Total 

annualized 

costs 

(million $/yr) 

Methane 

emission 

reductions 

(metric tpy) 

VOC 

emission 

reductions 

(tpy) 

Cost 

effectiveness ($/ton VOC) 

HAP 

emission 

reductions 

(tpy) 

Cost 

effectiveness ($/ton HAP) 

Storage Vessels ........................ 18.5 3.13 (8.16) (5.03) .................... 14,600 (345) 910 (5,530) 

Delayed Coking Units ............... 81 14.5 (2.80) 11.7 8,700 2,060 5,680 413 28,330 

Fugitive Emissions (Fenceline 

Monitoring) ............................. 12.5 6.36 .................... 6.36 .................... .................... .................... .................... ....................

Total ................................... 112 24.0 (11.0) 13.0 8,700 16,660 780 1,323 9,830 

TABLE 3—NATIONWIDE COSTS OF FINAL AMENDMENTS TO ENSURE COMPLIANCE (2010$) 

Affected Source 

Total capital 

investment 

(million $) 

Total 

annualized 

cost without 

credit 

(million $/yr) 

Product 

recovery 

credit 

(million $/yr) 

Total 

annualized 

costs 

(million $/yr) 

Relief Device Monitoring .................................................................................. 11.1 3.3 ........................ 3.3 

Flare Monitoring ............................................................................................... 160 46.5 ........................ 46.5 

FCCU Testing .................................................................................................. ........................ 0.4 ........................ 0.4 

Total .......................................................................................................... 171 50.2 ........................ 50.2 

The impacts shown in Table 2 do not 

include costs, product recovery credits, 

or emissions reductions associated with 

any root cause analysis or corrective 

action taken in response to the final 

amendments for fenceline monitoring. 

The impacts shown in Table 3 do not 

include (i) the costs or emissions 

reductions associated with any root 

cause analysis and corrective action 

taken in response to the final source 

performance testing at the FCCUs, or (ii) 

emissions reductions associated with 

corrective action taken in response to 

pressure relief device or (iii) emissions 

reductions associated with the flare 

operating and monitoring provisions. 

The operational and monitoring 

requirements for flares at refineries have 

the potential to reduce excess emissions 

from flares by up to approximately 

3,900 tpy of HAP and 33,000 tpy of 

VOC. The operational and monitoring 

requirements for flares also have the 

potential to reduce methane emissions 

by 25,800 metric tonnes per year while 

increasing emissions of carbon dioxide 

(CO2) and nitrous oxide by 267,000 

metric tonnes per year and 2 metric 

tonnes per year, respectively, yielding a 

net reduction in GHG emissions of 

377,000 metric tonnes per year of CO2 

equivalents (CO2e). 

B. What are the economic impacts? 

We performed a national economic 

impact analysis for petroleum product 

producers. All petroleum product 

refiners will incur annual compliance 

costs of less than 1-percent of their 

sales. For all firms, the minimum costto-sales ratio is <0.01-percent; the 

maximum cost-to-sales ratio is 0.87- 

percent; and the mean cost-to-sales ratio 

is 0.03-percent. Therefore, the overall 

economic impact of this proposed rule 

should be minimal for the refining 

industry and its consumers. 

In addition, the EPA performed a 

screening analysis for impacts on small 

businesses by comparing estimated 

annualized engineering compliance 

costs at the firm-level to firm sales. The 

screening analysis found that the ratio 

of compliance cost to firm revenue falls 

below 1-percent for the 28 small 

companies likely to be affected by the 

proposal. For small firms, the minimum 

cost-to-sales ratio is <0.01-percent; the 

maximum cost-to-sales ratio is 0.62- 

percent; and the mean cost-to-sales ratio 

is 0.07-percent. 

More information and details of this 

analysis is provided in the technical 

document ‘‘Economic Impact Analysis 

for Petroleum Refineries Proposed 

Amendments to the National Emissions 

Standards for Hazardous Air 

Pollutants’’, which is available in the 

docket for this rule (Docket ID No. EPA– 

HQ–OAR–2010–0682). 

C. What are the benefits? 

The final rule is anticipated to result 

in a reduction of 1,323 tpy of HAP 

(based on allowable emissions under the 

MACT standards) and 16,660 tpy of 

VOC, not including potential emission 

reductions that may occur as a result of 

the operating and monitoring 

requirements for flares and fugitive 

emission sources via fenceline 

monitoring. These avoided emissions 

will result in improvements in air 

quality and reduced negative health 

effects associated with exposure to air 

pollution of these emissions; however, 

we have not quantified or monetized the 

benefits of reducing these emissions for 

this rulemaking. 

D. Impacts of This Rulemaking on 

Environmental Justice Populations 

To examine the potential impacts on 

vulnerable populations (minority, lowincome and indigenous communities) 

that might be associated with the 

Petroleum Refinery source categories 

addressed in this final rule, we 

evaluated the percentages of various 

social, demographic and economic 

groups in the at-risk populations living 

near the facilities where these sources 

are located and compared them to 

national averages. Our analysis of the 

demographics of the population with 

estimated risks greater than 1-in-1 

million indicates potential disparities in 

risks between demographic groups 

including the African American, Other 

and Multiracial, Hispanic, Below the 

Poverty Level, and Over 25 without a 

High School Diploma when compared 

to the nationwide percentages of those 

groups. These groups will benefit the 

most from the emission reductions 

achieved by this final rulemaking, 

which is projected to result in 1 million 

fewer people exposed to risks greater 

than 1-in-1 million. 

Additionally, these communities will 

benefit from this rulemaking, as this 

rulemaking for the first time ever 

requires fenceline monitoring, and 

reporting of fenceline data. The agency 

during the pre-proposal period and 


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during the comment period received 

feedback from communities on the 

importance of having fenceline 

monitoring in their communities and 

the importance of communities having 

access to this data. The EPA believes 

that vulnerable communities will 

benefit from this data and the 

requirements that EPA has put in place 

in this rulemaking to manage fugitive 

emissions. 

E. Impacts of This Rulemaking on 

Children’s Health 

Under Executive Order 13045 the EPA 

must evaluate the effects of the planned 

regulation on children’s health and 

safety. This action’s health and risk 

assessments are contained in section 

IV.A of this preamble. We believe we 

have adequately estimated risk for 

children, and we do not believe that the 

environmental health risks addressed by 

this action present a disproportionate 

risk to children. When the EPA derives 

exposure reference concentrations and 

unit risk estimates (URE) for HAP, it 

also considers the most sensitive 

populations identified (i.e., children) in 

the available literature, and importantly, 

these are the values used in our risk 

assessments. With regard to children’s 

potentially greater susceptibility to noncancer toxicants, the assessments rely 

on the EPA (or comparable) hazard 

identification and dose-response values 

which have been developed to be 

protective for all subgroups of the 

general population, including children. 

With respect to cancer, the EPA uses the 

age-dependent adjustment factor 

approach, and applies these factors to 

carcinogenic pollutants that are known 

to act via mutagenic mode of action. 

Further details are provided in the 

‘‘Final Residual Risk Assessment for the 

Petroleum Refining Source Sector’’, 

Docket ID No. EPA–HQ–OAR–2010– 

0682. 

VI. Statutory and Executive Order 

Reviews 

A. Executive Orders 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is an economically 

significant regulatory action that was 

submitted to the Office of Management 

and Budget (OMB) for review. Any 

changes made in response to OMB 

recommendations have been 

documented in the docket. The EPA 

prepared an analysis of the potential 

costs and benefits associated with this 

action. This analysis, ‘‘Economic Impact 

Analysis: Petroleum Refineries—Final 

Amendments to the National Emissions 

Standards for Hazardous Air Pollutants 

and New Source Performance 

Standards’’ is available in Docket ID 

Number EPA–HQ–OAR–2010–0682. 

B. Paperwork Reduction Act (PRA) 

The information collection 

requirements in this rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et se. The information collection 

requirements are not enforceable until 

OMB approves them. 

Adequate recordkeeping and 

reporting are necessary to ensure 

compliance with these standards as 

required by the CAA. The ICR 

information collected from 

recordkeeping and reporting 

requirements is also used for 

prioritizing inspections and is of 

sufficient quality to be used as evidence 

in court. 

The ICR document prepared by the 

EPA for the amendments to the 

Petroleum Refinery MACT standards for 

40 CFR part 63, subpart CC has been 

assigned the EPA ICR number 1692.08. 

Burden changes associated with these 

amendments would result from new 

monitoring, recordkeeping and 

reporting requirements. The estimated 

annual increase in recordkeeping and 

reporting burden hours is 99,722 hours; 

the frequency of response is quarterly 

and semiannual for reports for all 

respondents that must comply with the 

rule’s reporting requirements; and the 

estimated average number of likely 

respondents per year is 95 (this is the 

average in the second year). The cost 

burden to respondents resulting from 

the collection of information includes 

the total capital cost annualized over the 

equipment’s expected useful life (about 

$18 million, which includes monitoring 

equipment for fenceline monitoring, 

pressure relief devices, and flares), a 

total operation and maintenance 

component (about $21 million per year 

for fenceline and flare monitoring), and 

a labor cost component (about $8.3 

million per year, the cost of the 

additional 99,722 labor hours). Burden 

is defined at 5 CFR 1320.3(b). 

The ICR document prepared by the 

EPA for the amendments to the 

Petroleum Refinery MACT standards for 

40 CFR part 63, subpart UUU has been 

assigned the EPA ICR number 1844.06. 

Burden changes associated with these 

amendments would result from new 

testing, recordkeeping and reporting 

requirements being finalized with this 

action. The estimated average burden 

per response is 25 hours; the frequency 

of response ranges from annually up to 

every 5 years for respondents that have 

FCCU, and the estimated average 

number of likely respondents per year is 

67. The cost burden to respondents 

resulting from the collection of 

information includes the performance 

testing costs (approximately $778,000 

per year over the first 3 years for the 

initial PM and one-time HCN 

performance tests and $235,000 per year 

starting in the fourth year), and a labor 

cost component (approximately 

$410,000 per year for 4,940 additional 

labor hours). Burden is defined at 5 CFR 

1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. When 

this ICR is approved by OMB, the 

Agency will publish a technical 

amendment to 40 CFR part 9 in the 

Federal Register to display the OMB 

control number for the approved 

information collection requirements 

contained in this final rule. 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have 

a significant economic impact on a 

substantial number of small entities 

(SISNOSE) under the RFA. The small 

entities subject to the requirements of 

this action are small businesses, small 

organizations and small governmental 

jurisdictions. For purposes of assessing 

the impacts of this rule on small 

entities, a small entity is defined as: (1) 

A small business in the petroleum 

refining industry having 1,500 or fewer 

employees (Small Business 

Administration (SBA), 2011); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. Details of this 

analysis are presented in the economic 

impact analysis which can be found in 

the docket for this rule (Docket ID No. 

EPA–HQ–OAR–2010–0682). 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain an 

unfunded mandate of $100 million or 

more as described in UMRA, 2 U.S.C. 

1531–1538, and does not significantly or 

uniquely affect small governments. As 

discussed earlier in this preamble, these 

amendments result in nationwide costs 

of $63.2 million per year for the private 

sector. Additionally, the rule contains 

no requirements that apply to small 


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governments and does not impose 

obligations upon them. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175. The final amendments 

impose no requirements on tribal 

governments. Thus, Executive Order 

13175 does not apply to this action. 

Consistent with the EPA Policy on 

Consultation and Coordination with 

Indian Tribes, the EPA consulted with 

tribal officials during the development 

of the proposed rule and specifically 

solicited comment on the proposed 

amendments from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to Executive 

Order 13045 because the EPA does not 

believe the environmental health or 

safety risks addressed by this action 

present a disproportionate risk to 

children. This action’s health and risk 

assessments are contained in section 

IV.A of this preamble. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution or Use 

This action is not a ‘‘significant 

energy action’’ because it is not likely to 

have a significant adverse effect on the 

supply, distribution or use of energy. 

The overall economic impact of this 

final rule should be minimal for the 

refining industry and its consumers. 

I. National Technology Transfer and 

Advancement Act (NTTAA) and 1 CFR 

Part 51 

This rulemaking involves technical 

standards. Therefore, the EPA 

conducted searches for the Petroleum 

Refinery Sector Risk and Technology 

Review and New Source Performance 

Standards through the Enhanced 

National Standards Systems Network 

(NSSN) Database managed by the 

American National Standards Institute 

(ANSI). We also contacted voluntary 

consensus standards (VCS) 

organizations and accessed and 

searched their databases. We conducted 

searches for EPA Methods 18, 22, 320, 

325A, and 325B of 40 CFR parts 60 and 

63, appendix A. No applicable VCS 

were identified for EPA Method 22. 

The following voluntary consensus 

standards were identified as acceptable 

alternatives to the EPA test methods for 

the purpose of this rule. 

The voluntary consensus standard 

ISO 16017–2:2003(E) ‘‘Air quality— 

Sampling and analysis of volatile 

organic compounds in ambient air, 

indoor air and workplace air by sorbent 

tube/thermal desorption/capillary gas 

chromatography. Part 2: Diffusive 

sampling’’ is an acceptable alternative to 

Method 325A, Sections 1.2, 6.1 and 6.5 

and Method 325B Sections 1.3, 7.1.2, 

7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and A.2. 

This voluntary consensus standard gives 

general guidance for the sampling and 

analysis of volatile organic compounds 

in air. It is applicable to indoor, ambient 

and workplace air. This standard is 

available at International Organization 

for Standardization, ISO Central 

Secretariat, Chemin de Blandonnet 8, 

CP 401, 1214 Vernier, Geneva, 

Switzerland. See https://www.iso.org. 

The voluntary consensus standard BS 

EN 14662–4:2005 ‘‘Ambient Air Quality: 

Standard Method for the Measurement 

of Benzene Concentrations—Part 4: 

Diffusive Sampling Followed By 

Thermal Desorption and Gas 

Chromatography’’ is an acceptable 

alternative to Method 325A, Section 1.2 

and Method 325B, Sections 1.3, 7.1.3, 

7.1.4, 12.2.4, 13.0, A.1.1, and A.2. This 

voluntary consensus standard gives 

general guidance for the sampling and 

analysis of benzene in air by diffusive 

sampling, thermal desorption and 

capillary gas chromatography. This 

standard is available the European 

Committee for Standardization, Avenue 

Marnix 17—B–1000 Brussels. See 

https://www.cen.eu. 

The voluntary consensus standard 

ASTM D6420–99 (2010) ‘‘Test Method 

for Determination of Gaseous Organic 

Compounds by Direct Interface Gas 

Chromatography/Mass Spectrometry’’ is 

an acceptable alternative to EPA Method 

18. This voluntary consensus standard 

employs a direct interface gas 

chromatography/mass spectrometer 

(GCMS) to identify and quantify a list of 

36 volatile organic compounds (the 

compounds are listed in the method). 

The voluntary consensus standard 

ASTM D6196–03 (Reapproved 2009) 

‘‘Standard Practice for Selection of 

Sorbents, Sampling, and Thermal 

Desorption Analysis Procedures for 

Volatile Organic Compounds in Air’’ is 

an acceptable alternative to Method 

325A, Sections 1.2 and 6.1, and Method 

325B, Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 

13.0, A.1.1, and A.2. This voluntary 

consensus standard is intended to assist 

in the selection of sorbents and 

procedures for the sampling and 

analysis of ambient, indoor, and 

workplace atmospheres for a variety of 

common volatile organic compounds. 

The voluntary consensus standards 

ASTM D1945–03 and later revision 

ASTM D1945–14 ‘‘Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography’’ are acceptable for 

natural gas analysis. This voluntary 

consensus standard covers the 

determination of the chemical 

composition of natural gases and similar 

gaseous mixtures. This test method may 

be abbreviated for the analysis of lean 

natural gases containing negligible 

amounts of hexanes and higher 

hydrocarbons, or for the determination 

of one or more components, as required. 

The voluntary consensus standard 

ASTM UOP539–12 ‘‘Refinery Gas 

Analysis by GC’’ is acceptable for 

refinery gas analysis. This voluntary 

consensus standard is for determining 

the composition of refinery gas streams 

or vaporized liquefied petroleum gas 

using a preconfigured, commercially 

available gas chromatograph. 

The voluntary consensus standard 

ASTM D6348–03 (Reapproved 2010) 

including Annexes A1 through A8, 

‘‘Determination of Gaseous Compounds 

by Extractive Direct Interface Fourier 

Transform (FTIR) Spectroscopy’’ is an 

acceptable alternative to EPA Method 

320. This voluntary consensus standard 

is a field test method that employs an 

extractive sampling system to direct 

stationary source effluent to an FTIR 

spectrometer for the identification and 

quantification of gaseous compounds. 

This field test method provides near real 

time analysis of extracted gas samples 

from stationary sources. 

The voluntary consensus standard 

ASTM D6348–12e1 ‘‘Determination of 

Gaseous Compounds by Extractive 

Direct Interface Fourier Transform 

(FTIR) Spectroscopy’’ is an acceptable 

alternative to EPA Method 320 with the 

following two caveats: (1) The test plan 

preparation and implementation in the 

Annexes to ASTM D 6348–03 

(Reapproved 2010), Sections A1 through 

A8 are mandatory; and (2) In ASTM 

D6348–03 (Reapproved 2010) Annex A5 

(Analyte Spiking Technique), the 

percent (%) R must be determined for 

each target analyte (Equation A5.5). In 

order for the test data to be acceptable 

for a compound, %R must be 70% ≥ R 

≤ 130%. If the %R value does not meet 

this criterion for a target compound, the 

test data is not acceptable for that 

compound and the test must be repeated 


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for that analyte (i.e., the sampling and/ 

or analytical procedure should be 

adjusted before a retest). The %R value 

for each compound must be reported in 

the test report, and all field 

measurements must be corrected with 

the calculated %R value for that 

compound by using the following 

equation: 

Reported Result = (Measured 

Concentration in the Stack × 100)/ 

% R. 

This voluntary consensus standard is 

a field test method that employs an 

extractive sampling system to direct 

stationary source effluent to an FTIR 

spectrometer for the identification and 

quantification of gaseous compounds. 

This field test method provides near real 

time analysis of extracted gas samples 

from stationary sources. 

The EPA solicited comments on VCS 

and invited the public to identify 

potentially-applicable VCS; however, 

we did not receive comments regarding 

this aspect of 40 CFR part 60, subparts 

J and Ja, and part 63, subparts CC, UUU, 

and Y. Under 40 CFR 63.7(f) and 63.8(f), 

a source may apply to the EPA for 

permission to use alternative test 

methods or alternative monitoring 

requirements in place of any required 

testing methods, performance 

specifications, or procedures in this 

final rule. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629; 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies and activities on minority 

populations and low-income 

populations in the U.S. The EPA defines 

environmental justice as the fair 

treatment and meaningful involvement 

of all people regardless of race, color, 

national origin or income with respect 

to the development, implementation 

and enforcement of environmental laws, 

regulations and policies. The EPA has 

this goal for all communities and 

persons by working to ensure that 

everyone enjoys the same degree of 

protection from environmental and 

health hazards and equal access to the 

decision-making process to have a 

healthy environment in which to live, 

learn and work. 

The EPA believes the human health or 

environmental risk addressed by this 

action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

populations. As discussed in section 

V.D. of this preamble, the EPA 

conducted an analysis of the 

characteristics of the population with 

greater than 1-in-1 million risk living 

within 50 km of the 142 refineries 

affected by this rulemaking and 

determined that there are more AfricanAmericans, Other and multiracial 

groups, Hispanics, low-income 

individuals, individuals with less than 

a high school diploma compared to 

national averages. Therefore, these 

populations are expected to experience 

the benefits of the risk reductions 

associated with this rule. The results of 

this evaluation are contained in two 

technical reports, ‘‘Risk and Technology 

Review—Analysis of Socio-Economic 

Factors for Populations Living Near 

Petroleum Refineries’’, available in the 

docket for this action (See Docket ID 

Nos. EPA–HQ–OAR–2010–0682–0226 

and -0227). Additionally, a discussion 

of the final risk analysis is included in 

Sections IV.A and V.D of this preamble. 

The EPA has determined that this 

final rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

populations because it maintains or 

increases the level of environmental 

protection for all affected populations 

without having any disproportionately 

high and adverse human health or 

environmental effects on any 

population, including any minority, 

low-income or indigenous populations. 

Further, the EPA believes that 

implementation of this rule will provide 

an ample margin of safety to protect 

public health of all demographic groups. 

K. Congressional Review Act (CRA) 

This action is subject to the CRA, and 

the EPA will submit a rule report to 

each House of the Congress and to the 

Comptroller General of the United 

States. This action is a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). 

List of Subjects 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedures, 

Air pollution control, Hazardous 

substances, Incorporation by reference, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

40 CFR Part 63 

Environmental protection, 

Administrative practice and procedures, 

Air pollution control, Hazardous 

substances, Incorporation by reference, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

Dated: September 29, 2015. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is amended as 

follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart J—Standards of Performance 

for Petroleum Refineries 

■ 2. Section 60.105 is amended by 

revising paragraphs (b)(1)(iv) and 

(b)(3)(iii) to read as follows: 

§ 60.105 Monitoring of emissions and 

operations. 

* * * * * 

(b) * * * 

(1) * * * 

(iv) The supporting test results from 

sampling the requested fuel gas stream/ 

system demonstrating that the sulfur 

content is less than 5 ppmv. Sampling 

data must include, at minimum, 2 

weeks of daily monitoring (14 grab 

samples) for frequently operated fuel gas 

streams/systems; for infrequently 

operated fuel gas streams/systems, 

seven grab samples must be collected 

unless other additional information 

would support reduced sampling. The 

owner or operator shall use detector 

tubes (‘‘length-of-stain tube’’ type 

measurement) following the ‘‘Gas 

Processors Association Standard 2377– 

86 (incorporated by reference—see 

§ 60.17), using tubes with a maximum 

span between 10 and 40 ppmv inclusive 

when 1≤N≤10, where N = number of 

pump strokes, to test the applicant fuel 

gas stream for H2S; and 

* * * * * 

(3) * * * 

(iii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application and the owner or 

operator chooses not to submit new 

information to support an exemption, 

the owner or operator must begin H2S 

monitoring using daily stain sampling to 

demonstrate compliance using length-of 


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stain tubes with a maximum span 

between 200 and 400 ppmv inclusive 

when 1≤N≤5, where N = number of 

pump strokes. The owner or operator 

must begin monitoring according to the 

requirements in paragraph (a)(1) or (2) 

of this section as soon as practicable but 

in no case later than 180 days after the 

operation change. During daily stain 

tube sampling, a daily sample exceeding 

162 ppmv is an exceedance of the 3- 

hour H2S concentration limit. 

* * * * * 

Subpart Ja—Standards of Performance 

for Petroleum Refineries for Which 

Construction, Reconstruction, or 

Modification Commenced After May 14, 

2007 

■ 3. Section 60.100a is amended by 

revising the first sentence of paragraph 

(b) to read as follows: 

§ 60.100a Applicability, designation of 

affected facility, and reconstruction. 

* * * * * 

(b) Except for flares and delayed 

coking units, the provisions of this 

subpart apply only to affected facilities 

under paragraph (a) of this section 

which either commence construction, 

modification or reconstruction after May 

14, 2007, or elect to comply with the 

provisions of this subpart in lieu of 

complying with the provisions in 

subpart J of this part. * * * 

* * * * * 

■ 4. Section 60.101a is amended by: 

■ a. Revising the definition of 

‘‘Corrective action’’; and 

■ b. Adding, in alphabetical order, a 

definition for ‘‘Sour water’’. 

The revision and addition read as 

follows: 

§ 60.101a Definitions. 

* * * * * 

Corrective action means the design, 

operation and maintenance changes that 

one takes consistent with good 

engineering practice to reduce or 

eliminate the likelihood of the 

recurrence of the primary cause and any 

other contributing cause(s) of an event 

identified by a root cause analysis as 

having resulted in a discharge of gases 

from an affected facility in excess of 

specified thresholds. 

* * * * * 

Sour water means water that contains 

sulfur compounds (usually H2S) at 

concentrations of 10 parts per million 

by weight or more. 

* * * * * 

■ 5. Section 60.102a is amended by 

revising paragraphs (b)(1)(i) and (iii), (f), 

and (g)(1) introductory text to read as 

follows: 

§ 60.102a Emissions limitations. 

* * * * * 

(b) * * * 

(1) * * * 

(i) 1.0 gram per kilogram (g/kg) (1 

pound (lb) per 1,000 lb) coke burn-off 

or, if a PM continuous emission 

monitoring system (CEMS) is used, 

0.040 grain per dry standard cubic feet 

(gr/dscf) corrected to 0 percent excess 

air for each modified or reconstructed 

FCCU. 

* * * * * 

(iii) 1.0 g/kg (1 lb/1,000 lb) coke burnoff or, if a PM CEMS is used, 0.040 grain 

per dry standard cubic feet (gr/dscf) 

corrected to 0 percent excess air for each 

affected FCU. 

* * * * * 

(f) Except as provided in paragraph 

(f)(3) of this section, each owner or 

operator of an affected sulfur recovery 

plant shall comply with the applicable 

emission limits in paragraph (f)(1) or (2) 

of this section. 

(1) For a sulfur recovery plant with a 

design production capacity greater than 

20 long tons per day (LTD), the owner 

or operator shall comply with the 

applicable emission limit in paragraph 

(f)(1)(i) or (ii) of this section. If the 

sulfur recovery plant consists of 

multiple process trains or release points, 

the owner or operator shall comply with 

the applicable emission limit for each 

process train or release point 

individually or comply with the 

applicable emission limit in paragraph 

(f)(1)(i) or (ii) as a flow rate weighted 

average for a group of release points 

from the sulfur recovery plant provided 

that flow is monitored as specified in 

§ 60.106a(a)(7); if flow is not monitored 

as specified in § 60.106a(a)(7), the 

owner or operator shall comply with the 

applicable emission limit in paragraph 

(f)(1)(i) or (ii) for each process train or 

release point individually. For a sulfur 

recovery plant with a design production 

capacity greater than 20 long LTD and 

a reduction control system not followed 

by incineration, the owner or operator 

shall also comply with the H2S emission 

limit in paragraph (f)(1)(iii) of this 

section for each individual release 

point. 

(i) For a sulfur recovery plant with an 

oxidation control system or a reduction 

control system followed by incineration, 

the owner or operator shall not 

discharge or cause the discharge of any 

gases into the atmosphere (SO2) in 

excess of the emission limit calculated 

using Equation 1 of this section. For 

Claus units that use only ambient air in 

the Claus burner or that elect not to 

monitor O2 concentration of the air/

oxygen mixture used in the Claus 

burner or for non-Claus sulfur recovery 

plants, this SO2 emissions limit is 250 

ppmv (dry basis) at zero percent excess 

air. 

Where: 

ELS = Emission limit for large sulfur recovery 

plant, ppmv (as SO2, dry basis at zero 

percent excess air); 

k1 = Constant factor for emission limit 

conversion: k1 = 1 for converting to the 

SO2 limit for a sulfur recovery plant with 

an oxidation control system or a 

reduction control system followed by 

incineration and k1 = 1.2 for converting 

to the reduced sulfur compounds limit 

for a sulfur recovery plant with a 

reduction control system not followed by 

incineration; and 

%O2 = O2 concentration of the air/oxygen 

mixture supplied to the Claus burner, 

percent by volume (dry basis). If only 

ambient air is used for the Claus burner 

or if the owner or operator elects not to 

monitor O2 concentration of the air/

oxygen mixture used in the Claus burner 

or for non-Claus sulfur recovery plants, 

use 20.9% for %O2. 

(ii) For a sulfur recovery plant with a 

reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing reduced sulfur 

compounds in excess of the emission 

limit calculated using Equation 1 of this 

section. For Claus units that use only 

ambient air in the Claus burner or for 

non-Claus sulfur recovery plants, this 

reduced sulfur compounds emission 

limit is 300 ppmv calculated as ppmv 

SO2 (dry basis) at 0-percent excess air. 

(iii) For a sulfur recovery plant with 

a reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing hydrogen sulfide 

(H2S) in excess of 10 ppmv calculated 

as ppmv SO2 (dry basis) at zero percent 

excess air. 


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(2) For a sulfur recovery plant with a 

design production capacity of 20 LTD or 

less, the owner or operator shall comply 

with the applicable emission limit in 

paragraph (f)(2)(i) or (ii) of this section. 

If the sulfur recovery plant consists of 

multiple process trains or release points, 

the owner or operator may comply with 

the applicable emission limit for each 

process train or release point 

individually or comply with the 

applicable emission limit in paragraph 

(f)(2)(i) or (ii) as a flow rate weighted 

average for a group of release points 

from the sulfur recovery plant provided 

that flow is monitored as specified in 

§ 60.106a(a)(7); if flow is not monitored 

as specified in § 60.106a(a)(7), the 

owner or operator shall comply with the 

applicable emission limit in paragraph 

(f)(2)(i) or (ii) for each process train or 

release point individually. For a sulfur 

recovery plant with a design production 

capacity of 20 LTD or less and a 

reduction control system not followed 

by incineration, the owner or operator 

shall also comply with the H2S emission 

limit in paragraph (f)(2)(iii) of this 

section for each individual release 

point. 

(i) For a sulfur recovery plant with an 

oxidation control system or a reduction 

control system followed by incineration, 

the owner or operator shall not 

discharge or cause the discharge of any 

gases into the atmosphere containing 

SO2 in excess of the emission limit 

calculated using Equation 2 of this 

section. For Claus units that use only 

ambient air in the Claus burner or that 

elect not to monitor O2 concentration of 

the air/oxygen mixture used in the 

Claus burner or for non-Claus sulfur 

recovery plants, this SO2 emission limit 

is 2,500 ppmv (dry basis) at zero percent 

excess air. 

Where: 

ESS = Emission limit for small sulfur recovery 

plant, ppmv (as SO2, dry basis at zero 

percent excess air); 

k1 = Constant factor for emission limit 

conversion: k1 = 1 for converting to the 

SO2 limit for a sulfur recovery plant with 

an oxidation control system or a 

reduction control system followed by 

incineration and k1 = 1.2 for converting 

to the reduced sulfur compounds limit 

for a sulfur recovery plant with a 

reduction control system not followed by 

incineration; and 

%O2 = O2 concentration of the air/oxygen 

mixture supplied to the Claus burner, 

percent by volume (dry basis). If only 

ambient air is used in the Claus burner 

or if the owner or operator elects not to 

monitor O2 concentration of the air/

oxygen mixture used in the Claus burner 

or for non-Claus sulfur recovery plants, 

use 20.9% for %O2. 

(ii) For a sulfur recovery plant with a 

reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing reduced sulfur 

compounds in excess of the emission 

limit calculated using Equation 2 of this 

section. For Claus units that use only 

ambient air in the Claus burner or for 

non-Claus sulfur recovery plants, this 

reduced sulfur compounds emission 

limit is 3,000 ppmv calculated as ppmv 

SO2 (dry basis) at zero percent excess 

air. 

(iii) For a sulfur recovery plant with 

a reduction control system not followed 

by incineration, the owner or operator 

shall not discharge or cause the 

discharge of any gases into the 

atmosphere containing H2S in excess of 

100 ppmv calculated as ppmv SO2 (dry 

basis) at zero percent excess air. 

(3) The emission limits in paragraphs 

(f)(1) and (2) of this section shall not 

apply during periods of maintenance of 

the sulfur pit, which shall not exceed 

240 hours per year. The owner or 

operator must document the time 

periods during which the sulfur pit 

vents were not controlled and measures 

taken to minimize emissions during 

these periods. Examples of these 

measures include not adding fresh 

sulfur or shutting off vent fans. 

(g) * * * 

(1) Except as provided in (g)(1)(iii) of 

this section, for each fuel gas 

combustion device, the owner or 

operator shall comply with either the 

emission limit in paragraph (g)(1)(i) of 

this section or the fuel gas concentration 

limit in paragraph (g)(1)(ii) of this 

section. For CO boilers or furnaces that 

are part of a fluid catalytic cracking unit 

or fluid coking unit affected facility, the 

owner or operator shall comply with the 

fuel gas concentration limit in 

paragraph (g)(1)(ii) for all fuel gas 

streams combusted in these units. 

* * * * * 

■ 6. Section 60.104a is amended by: 

■ a. Revising the first sentence of 

paragraph (a) and paragraphs (b), (f) 

introductory text, and (h) introductory 

text; 

■ b. Adding paragraph (h)(6); and 

■ c. Removing and reserving paragraphs 

(j)(1) through (3). 

The revisions and additions read as 

follows: 

§ 60.104a Performance tests. 

(a) The owner or operator shall 

conduct a performance test for each 

FCCU, FCU, sulfur recovery plant and 

fuel gas combustion device to 

demonstrate initial compliance with 

each applicable emissions limit in 

§ 60.102a and conduct a performance 

test for each flare to demonstrate initial 

compliance with the H2S concentration 

requirement in § 60.103a(h) according to 

the requirements of § 60.8. * * * 

(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 annually (i.e., 

once per calendar year, with an interval 

of at least 8 months but no more than 

16 months between annual tests) and 

furnish the Administrator a written 

report of the results of each test. 

* * * * * 

(f) The owner or operator of an FCCU 

or FCU that uses cyclones to comply 

with the PM per coke burn-off emissions 

limit in § 60.102a(b)(1) shall establish a 

site-specific opacity operating limit 

according to the procedures in 

paragraphs (f)(1) through (3) of this 

section. 

* * * * * 

(h) The owner or operator shall 

determine compliance with the SO2

emissions limits for sulfur recovery 

plants in § 60.102a(f)(1)(i) and (f)(2)(i) 

and the reduced sulfur compounds and 

H2S emissions limits for sulfur recovery 

plants in § 60.102a(f)(1)(ii), (f)(1)(iii), 

(f)(2)(ii), and (f)(2)(iii) using the 

following methods and procedures: 

* * * * * 

(6) If oxygen or oxygen-enriched air is 

used in the Claus burner and either 

Equation 1 or 2 of this subpart is used 

to determine the applicable emissions 

limit, determine the average O2

concentration of the air/oxygen mixture 

supplied to the Claus burner, in percent 

by volume (dry basis), for the 

performance test using all hourly 

average O2 concentrations determined 


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during the test runs using the 

procedures in § 60.106a(a)(5) or (6). 

* * * * * 

■ 7. Section 60.105a is amended by: 

■ a. Revising paragraphs (b)(1)(i), 

(b)(1)(ii)(A), (b)(2), (h)(1), (h)(3)(i), and 

(i)(1); 

■ b. Redesignating paragraphs (i)(2) 

through (6) as (i)(3) through (7); 

■ c. Adding paragraph (i)(2); and 

■ d. Revising newly redesignated 

paragraph (i)(7). 

The revisions and additions read as 

follows: 

§ 60.105a Monitoring of emissions and 

operations for fluid catalytic cracking units 

(FCCU) and fluid coking units (FCU). 

* * * * * 

(b) * * * 

(1) * * * 

(i) For units controlled using an 

electrostatic precipitator, the owner or 

operator shall use CPMS to measure and 

record the hourly average total power 

input and secondary current to the 

entire system. 

(ii) * * * 

(A) As an alternative to pressure drop, 

the owner or operator of a jet ejector 

type wet scrubber or other type of wet 

scrubber equipped with atomizing spray 

nozzles must conduct a daily check of 

the air or water pressure to the spray 

nozzles and record the results of each 

check. Faulty (e.g., leaking or plugged) 

air or water lines must be repaired 

within 12 hours of identification of an 

abnormal pressure reading. 

* * * * * 

(2) For use in determining the coke 

burn-off rate for an FCCU or FCU, the 

owner or operator shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring the 

concentrations of CO2, O2 (dry basis), 

and if needed, CO in the exhaust gases 

prior to any control or energy recovery 

system that burns auxiliary fuels. A CO 

monitor is not required for determining 

coke burn-off rate when no auxiliary 

fuel is burned and a continuous CO 

monitor is not required in accordance 

with paragraph (h)(3) of this section. 

(i) The owner or operator shall install, 

operate, and maintain each CO2 and O2

monitor according to Performance 

Specification 3 of appendix B to this 

part. 

(ii) The owner or operator shall 

conduct performance evaluations of 

each CO2 and O2 monitor according to 

the requirements in § 60.13(c) and 

Performance Specification 3 of 

appendix B to this part. The owner or 

operator shall use Method 3 of appendix 

A–3 to this part for conducting the 

relative accuracy evaluations. 

(iii) If a CO monitor is required, the 

owner or operator shall install, operate, 

and maintain each CO monitor 

according to Performance Specification 

4 or 4A of appendix B to this part. If this 

CO monitor also serves to demonstrate 

compliance with the CO emissions limit 

in § 60.102a(b)(4), the span value for 

this instrument is 1,000 ppm; otherwise, 

the span value for this instrument 

should be set at approximately 2 times 

the typical CO concentration expected 

in the FCCU of FCU flue gas prior to any 

emission control or energy recovery 

system that burns auxiliary fuels. 

(iv) If a CO monitor is required, the 

owner or operator shall conduct 

performance evaluations of each CO 

monitor according to the requirements 

in § 60.13(c) and Performance 

Specification 4 of appendix B to this 

part. The owner or operator shall use 

Method 10, 10A, or 10B of appendix A– 

3 to this part for conducting the relative 

accuracy evaluations. 

(v) The owner or operator shall 

comply with the quality assurance 

requirements of procedure 1 of 

appendix F to this part, including 

quarterly accuracy determinations for 

CO2 and CO monitors, annual accuracy 

determinations for O2 monitors, and 

daily calibration drift tests. 

* * * * * 

(h) * * * 

(1) The owner or operator shall 

install, operate, and maintain each CO 

monitor according to Performance 

Specification 4 or 4A of appendix B to 

this part. The span value for this 

instrument is 1,000 ppmv CO. 

* * * * * 

(3) * * * 

(i) The demonstration shall consist of 

continuously monitoring CO emissions 

for 30 days using an instrument that 

meets the requirements of Performance 

Specification 4 or 4A of appendix B to 

this part. The span value shall be 100 

ppmv CO instead of 1,000 ppmv, and 

the relative accuracy limit shall be 10 

percent of the average CO emissions or 

5 ppmv CO, whichever is greater. For 

instruments that are identical to Method 

10 of appendix A–4 to this part and 

employ the sample conditioning system 

of Method 10A of appendix A–4 to this 

part, the alternative relative accuracy 

test procedure in section 10.1 of 

Performance Specification 2 of 

appendix B to this part may be used in 

place of the relative accuracy test. 

* * * * * 

(i) * * * 

(1) If a CPMS is used according to 

paragraph (b)(1) of this section, all 3- 

hour periods during which the average 

PM control device operating 

characteristics, as measured by the 

continuous monitoring systems under 

paragraph (b)(1), fall below the levels 

established during the performance test. 

If the alternative to pressure drop CPMS 

is used for the owner or operator of a jet 

ejector type wet scrubber or other type 

of wet scrubber equipped with 

atomizing spray nozzles, each day in 

which abnormal pressure readings are 

not corrected within 12 hours of 

identification. 

(2) If a bag leak detection system is 

used according to paragraph (c) of this 

section, each day in which the cause of 

an alarm is not alleviated within the 

time period specified in paragraph (c)(3) 

of this section. 

* * * * * 

(7) All 1-hour periods during which 

the average CO concentration as 

measured by the CO continuous 

monitoring system under paragraph (h) 

of this section exceeds 500 ppmv or, if 

applicable, all 1-hour periods during 

which the average temperature and O2

concentration as measured by the 

continuous monitoring systems under 

paragraph (h)(4) of this section fall 

below the operating limits established 

during the performance test. 

■ 8. Section 60.106a is amended by: 

■ a. Revising paragraph (a)(1)(i); 

■ b. Adding paragraphs (a)(1)(iv) 

through (vii); 

■ c. Revising paragraphs (a)(2) 

introductory text, (a)(2)(i) and (ii), and 

the first sentence of paragraph (a)(2)(iii); 

■ d. Removing paragraphs (a)(2)(iv) and 

(v); 

■ e. Redesignating paragraphs (a)(2)(vi) 

through (ix) as (a)(2)(iv) through (vii); 

■ f. Revising the first sentence of 

paragraph (a)(3) introductory text and 

paragraph (a)(3)(i); 

■ g. Adding paragraphs (a)(4) through 

(7); and 

■ h. Revising paragraphs (b)(2) and (3). 

The revisions and additions read as 

follows: 

§ 60.106a Monitoring of emissions and 

operations for sulfur recovery plants. 

(a) * * * 

(1) * * * 

(i) The span value for the SO2 monitor 

is two times the applicable SO2

emission limit at the highest O2

concentration in the air/oxygen stream 

used in the Claus burner, if applicable. 

* * * * * 

(iv) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of appendix B to this 

part. 

(v) The span value for the O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 


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(vi) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3 of 

appendix B to this part. The owner or 

operator shall use Methods 3, 3A, or 3B 

of appendix A–2 to this part for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 3B of 

appendix A–2 to this part. 

(vii) The owner or operator shall 

comply with the applicable quality 

assurance procedures of appendix F to 

this part for each monitor, including 

annual accuracy determinations for each 

O2 monitor, and daily calibration drift 

determinations. 

(2) For sulfur recovery plants that are 

subject to the reduced sulfur 

compounds emission limit in 

§ 60.102a(f)(1)(ii) or (f)(2)(ii), the owner 

or operator shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration of reduced 

sulfur compounds and O2 emissions 

into the atmosphere. The reduced sulfur 

compounds emissions shall be 

calculated as SO2 (dry basis, zero 

percent excess air). 

(i) The span value for the reduced 

sulfur compounds monitor is two times 

the applicable reduced sulfur 

compounds emission limit as SO2 at the 

highest O2 concentration in the air/

oxygen stream used in the Claus burner, 

if applicable. 

(ii) The owner or operator shall 

install, operate, and maintain each 

reduced sulfur compounds CEMS 

according to Performance Specification 

5 of appendix B to this part. 

(iii) The owner or operator shall 

conduct performance evaluations of 

each reduced sulfur compounds 

monitor according to the requirements 

in § 60.13(c) and Performance 

Specification 5 of appendix B to this 

part. * * * 

* * * * * 

(3) In place of the reduced sulfur 

compounds monitor required in 

paragraph (a)(2) of this section, the 

owner or operator may install, calibrate, 

operate, and maintain an instrument 

using an air or O2 dilution and 

oxidation system to convert any reduced 

sulfur to SO2 for continuously 

monitoring and recording the 

concentration (dry basis, 0 percent 

excess air) of the total resultant SO2. 

* * * 

(i) The span value for this monitor is 

two times the applicable reduced sulfur 

compounds emission limit as SO2 at the 

highest O2 concentration in the air/

oxygen stream used in the Claus burner, 

if applicable. 

* * * * * 

(4) For sulfur recovery plants that are 

subject to the H2S emission limit in 

§ 60.102a(f)(1)(iii) or (f)(2)(iii), the 

owner or operator shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration of H2S, and 

O2 emissions into the atmosphere. The 

H2S emissions shall be calculated as 

SO2 (dry basis, zero percent excess air). 

(i) The span value for this monitor is 

two times the applicable H2S emission 

limit. 

(ii) The owner or operator shall 

install, operate, and maintain each H2S 

CEMS according to Performance 

Specification 7 of appendix B to this 

part. 

(iii) The owner or operator shall 

conduct performance evaluations for 

each H2S monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 7 of 

appendix B to this part. The owner or 

operator shall use Methods 11 or 15 of 

appendix A–5 to this part or Method 16 

of appendix A–6 to this part for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 15A of 

appendix A–5 to this part. 

(iv) The owner or operator shall 

install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of appendix B to this 

part. 

(v) The span value for the O2 monitor 

must be selected between 10 and 25 

percent, inclusive. 

(vi) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3 of 

appendix B to this part. The owner or 

operator shall use Methods 3, 3A, or 3B 

of appendix A–2 to this part for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 3B of 

appendix A–2 to this part. 

(vii) The owner or operator shall 

comply with the applicable quality 

assurance procedures of appendix F to 

this part for each monitor, including 

annual accuracy determinations for each 

O2 monitor, and daily calibration drift 

determinations. 

(5) For sulfur recovery plants that use 

oxygen or oxygen enriched air in the 

Claus burner and that elects to monitor 

O2 concentration of the air/oxygen 

mixture supplied to the Claus burner, 

the owner or operator shall install, 

operate, calibrate, and maintain an 

instrument for continuously monitoring 

and recording the O2 concentration of 

the air/oxygen mixture supplied to the 

Claus burner in order to determine the 

allowable emissions limit. 

(i) The owner or operator shall install, 

operate, and maintain each O2 monitor 

according to Performance Specification 

3 of appendix B to this part. 

(ii) The span value for the O2 monitor 

shall be 100 percent. 

(iii) The owner or operator shall 

conduct performance evaluations for the 

O2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 3 of 

appendix B to this part. The owner or 

operator shall use Methods 3, 3A, or 3B 

of appendix A–2 to this part for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 3B of 

appendix A–2 to this part. 

(iv) The owner or operator shall 

comply with the applicable quality 

assurance procedures of appendix F to 

this part for each monitor, including 

annual accuracy determinations for each 

O2 monitor, and daily calibration drift 

determinations. 

(v) The owner or operator shall use 

the hourly average O2 concentration 

from this monitor for use in Equation 1 

or 2 of § 60.102a(f), as applicable, for 

each hour and determine the allowable 

emission limit as the arithmetic average 

of 12 contiguous 1-hour averages (i.e., 

the rolling 12-hour average). 

(6) As an alternative to the O2 monitor 

required in paragraph (a)(5) of this 

section, the owner or operator may 

install, calibrate, operate, and maintain 

a CPMS to measure and record the 

volumetric gas flow rate of ambient air 

and oxygen-enriched gas supplied to the 

Claus burner and calculate the hourly 

average O2 concentration of the air/

oxygen mixture used in the Claus 

burner as specified in paragraphs 

(a)(6)(i) through (iv) of this section in 

order to determine the allowable 

emissions limit as specified in 

paragraphs (a)(6)(v) of this section. 

(i) The owner or operator shall install, 

calibrate, operate and maintain each 

flow monitor according to the 

manufacturer’s procedures and 

specifications and the following 

requirements. 

(A) Locate the monitor in a position 

that provides a representative 

measurement of the total gas flow rate. 


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(B) Use a flow sensor meeting an 

accuracy requirement of ±5 percent over 

the normal range of flow measured or 10 

cubic feet per minute, whichever is 

greater. 

(C) Use a flow monitor that is 

maintainable online, is able to 

continuously correct for temperature, 

pressure and, for ambient air flow 

monitor, moisture content, and is able to 

record dry flow in standard conditions 

(as defined in § 60.2) over one-minute 

averages. 

(D) At least quarterly, perform a visual 

inspection of all components of the 

monitor for physical and operational 

integrity and all electrical connections 

for oxidation and galvanic corrosion if 

the flow monitor is not equipped with 

a redundant flow sensor. 

(E) Recalibrate the flow monitor in 

accordance with the manufacturer’s 

procedures and specifications biennially 

(every two years) or at the frequency 

specified by the manufacturer. 

(ii) The owner or operator shall use 

20.9 percent as the oxygen content of 

the ambient air. 

(iii) The owner or operator shall use 

product specifications (e.g., as reported 

in material safety data sheets) for 

percent oxygen for purchased oxygen. 

For oxygen produced onsite, the percent 

oxygen shall be determined by periodic 

measurements or process knowledge. 

(iv) The owner or operator shall 

calculate the hourly average O2

concentration of the air/oxygen mixture 

used in the Claus burner using Equation 

10 of this section: 

Where: 

%O2 = O2 concentration of the air/oxygen 

mixture used in the Claus burner, 

percent by volume (dry basis); 

20.9 = O2 concentration in air, percent dry 

basis; 

Qair = Volumetric flow rate of ambient air 

used in the Claus burner, dscfm; 

%O2,oxy = O2 concentration in the enriched 

oxygen stream, percent dry basis; and 

Qoxy = Volumetric flow rate of enriched 

oxygen stream used in the Claus burner, 

dscfm. 

(v) The owner or operator shall use 

the hourly average O2 concentration 

determined using Equation 8 of 

§ 60.104a(d)(8) for use in Equation 1 or 

2 of § 60.102a(f), as applicable, for each 

hour and determine the allowable 

emission limit as the arithmetic average 

of 12 contiguous 1-hour averages (i.e., 

the rolling 12-hour average). 

(7) Owners or operators of a sulfur 

recovery plant that elects to comply 

with the SO2 emission limit in 

§ 60.102a(f)(1)(i) or (f)(2)(i) or the 

reduced sulfur compounds emission 

limit in § 60.102a(f)(1)(ii) or (f)(2)(ii) as 

a flow rate weighted average for a group 

of release points from the sulfur 

recovery plant rather than for each 

process train or release point 

individually shall install, calibrate, 

operate, and maintain a CPMS to 

measure and record the volumetric gas 

flow rate of each release point within 

the group of release points from the 

sulfur recovery plant as specified in 

paragraphs (a)(7)(i) through (iv) of this 

section. 

(i) The owner or operator shall install, 

calibrate, operate and maintain each 

flow monitor according to the 

manufacturer’s procedures and 

specifications and the following 

requirements. 

(A) Locate the monitor in a position 

that provides a representative 

measurement of the total gas flow rate. 

(B) Use a flow sensor meeting an 

accuracy requirement of ±5 percent over 

the normal range of flow measured or 10 

cubic feet per minute, whichever is 

greater. 

(C) Use a flow monitor that is 

maintainable online, is able to 

continuously correct for temperature, 

pressure, and moisture content, and is 

able to record dry flow in standard 

conditions (as defined in § 60.2) over 

one-minute averages. 

(D) At least quarterly, perform a visual 

inspection of all components of the 

monitor for physical and operational 

integrity and all electrical connections 

for oxidation and galvanic corrosion if 

the flow monitor is not equipped with 

a redundant flow sensor. 

(E) Recalibrate the flow monitor in 

accordance with the manufacturer’s 

procedures and specifications biennially 

(every two years) or at the frequency 

specified by the manufacturer. 

(ii) The owner or operator shall 

correct the flow to 0 percent excess air 

using Equation 11 of this section: 

Where: 

Qadj = Volumetric flow rate adjusted to 0 

percent excess air, dry standard cubic 

feet per minute (dscfm); 

Cmeas = Volumetric flow rate measured by the 

flow meter corrected to dry standard 

conditions, dscfm; 

20.9c = 20.9 percent O2¥0.0 percent O2

(defined O2 correction basis), percent; 

20.9 = O2 concentration in air, percent; and 

%O2 = O2 concentration measured on a dry 

basis, percent. 

(iii) The owner or operator shall 

calculate the flow weighted average SO2

or reduced sulfur compounds 

concentration for each hour using 

Equation 12 of this section: 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75235 

Where: 

Cave = Flow weighted average concentration 

of the pollutant, ppmv (dry basis, zero 

percent excess air). The pollutant is 

either SO2 (if complying with the SO2

emission limit in § 60.102a(f)(1)(i) or 

(f)(2)(i)) or reduced sulfur compounds (if 

complying with the reduced sulfur 

compounds emission limit in 

§ 60.102a(f)(1)(ii) or (f)(2)(ii)); 

N = Number of release points within the 

group of release points from the sulfur 

recovery plant for which emissions 

averaging is elected; 

Cn = Pollutant concentration in the nth release 

point within the group of release points 

from the sulfur recovery plant for which 

emissions averaging is elected, ppmv 

(dry basis, zero percent excess air); 

Qadj,n = Volumetric flow rate of the nth release 

point within the group of release points 

from the sulfur recovery plant for which 

emissions averaging is elected, dry 

standard cubic feet per minute (dscfm, 

adjusted to 0 percent excess air). 

(iv) For sulfur recovery plants that use 

oxygen or oxygen enriched air in the 

Claus burner, the owner or operator 

shall use Equation 10 of this section and 

the hourly emission limits determined 

in paragraph (a)(5)(v) or (a)(6)(v) of this 

section in-place of the pollutant 

concentration to determine the flow 

weighted average hourly emission limit 

for each hour. The allowable emission 

limit shall be calculated as the 

arithmetic average of 12 contiguous 1- 

hour averages (i.e., the rolling 12-hour 

average). 

(b) * * * 

(2) All 12-hour periods during which 

the average concentration of reduced 

sulfur compounds (as SO2) as measured 

by the reduced sulfur compounds 

continuous monitoring system required 

under paragraph (a)(2) or (3) of this 

section exceeds the applicable emission 

limit; or 

(3) All 12-hour periods during which 

the average concentration of H2S as 

measured by the H2S continuous 

monitoring system required under 

paragraph (a)(4) of this section exceeds 

the applicable emission limit (dry basis, 

0 percent excess air). 

■ 9. Section 60.107a is amended by 

revising paragraphs (a)(1)(i) and (ii), 

(b)(1)(iv), the first sentence of paragraph 

(b)(3)(iii), (d)(3), (e)(1) introductory text, 

(e)(1)(ii), (e)(2) introductory text, 

(e)(2)(ii), (e)(2)(vi)(C), (e)(3), (f)(1)(ii), 

and (h)(5) to read as follows: 

§ 60.107a Monitoring of emissions and 

operations for fuel gas combustion devices 

and flares. 

(a) * * * 

(1) * * * 

(i) The owner or operator shall install, 

operate, and maintain each SO2 monitor 

according to Performance Specification 

2 of appendix B to this part. The span 

value for the SO2 monitor is 50 ppmv 

SO2. 

(ii) The owner or operator shall 

conduct performance evaluations for the 

SO2 monitor according to the 

requirements of § 60.13(c) and 

Performance Specification 2 of 

appendix B to this part. The owner or 

operator shall use Methods 6, 6A, or 6C 

of appendix A–4 to this part for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 6 or 6A of 

appendix A–4 to this part. Samples 

taken by Method 6 of appendix A–4 to 

this part shall be taken at a flow rate of 

approximately 2 liters/min for at least 

30 minutes. The relative accuracy limit 

shall be 20 percent or 4 ppmv, 

whichever is greater, and the calibration 

drift limit shall be 5 percent of the 

established span value. 

* * * * * 

(b) * * * 

(1) * * * 

(iv) The supporting test results from 

sampling the requested fuel gas stream/ 

system demonstrating that the sulfur 

content is less than 5 ppmv H2S. 

Sampling data must include, at 

minimum, 2 weeks of daily monitoring 

(14 grab samples) for frequently 

operated fuel gas streams/systems; for 

infrequently operated fuel gas streams/ 

systems, seven grab samples must be 

collected unless other additional 

information would support reduced 

sampling. The owner or operator shall 

use detector tubes (‘‘length-of-stain 

tube’’ type measurement) following the 

‘‘Gas Processors Association Standard 

2377–86 (incorporated by reference— 

see § 60.17), using tubes with a 

maximum span between 10 and 40 

ppmv inclusive when 1≤N≤10, where N 

= number of pump strokes, to test the 

applicant fuel gas stream for H2S; and 

* * * * * 

(3) * * * 

(iii) If the operation change results in 

a sulfur content that is outside the range 

of concentrations included in the 

original application and the owner or 

operator chooses not to submit new 

information to support an exemption, 

the owner or operator must begin H2S 

monitoring using daily stain sampling to 

demonstrate compliance using lengthof-stain tubes with a maximum span 

between 200 and 400 ppmv inclusive 

when 1≤N≤5, where N = number of 

pump strokes. * * * 

* * * * * 

(d) * * * 

(3) As an alternative to the 

requirements in paragraph (d)(2) of this 

section, the owner or operator of a gasfired process heater shall install, operate 

and maintain a gas composition 

analyzer and determine the average F 

factor of the fuel gas using the factors in 

Table 1 of this subpart and Equation 13 

of this section. If a single fuel gas system 

provides fuel gas to several process 

heaters, the F factor may be determined 

at a single location in the fuel gas 

system provided it is representative of 

the fuel gas fed to the affected process 

heater(s). 

Where: 

Fd = F factor on dry basis at 0% excess air, 

dscf/MMBtu. 

Xi = mole or volume fraction of each 

component in the fuel gas. 

MEVi = molar exhaust volume, dry 

standard cubic feet per mole (dscf/mol). 

MHCi = molar heat content, Btu per mole 

(Btu/mol). 

1,000,000 = unit conversion, Btu per 

MMBtu. 

* * * * * 

(e) * * * 

(1) Total reduced sulfur monitoring 

requirements. The owner or operator 

shall install, operate, calibrate and 

maintain an instrument or instruments 

for continuously monitoring and 

recording the concentration of total 

reduced sulfur in gas discharged to the 

flare. 

* * * * * 

(ii) The owner or operator shall 

conduct performance evaluations of 

each total reduced sulfur monitor 

according to the requirements in 

§ 60.13(c) and Performance 

Specification 5 of appendix B to this 

part. The owner or operator of each total 


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reduced sulfur monitor shall use EPA 

Method 15A of appendix A–5 to this 

part for conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference-see § 60.17) is an acceptable 

alternative to EPA Method 15A of 

appendix A–5 to this part. The 

alternative relative accuracy procedures 

described in section 16.0 of Performance 

Specification 2 of appendix B to this 

part (cylinder gas audits) may be used 

for conducting the relative accuracy 

evaluations, except that it is not 

necessary to include as much of the 

sampling probe or sampling line as 

practical. 

* * * * * 

(2) H2S monitoring requirements. The 

owner or operator shall install, operate, 

calibrate, and maintain an instrument or 

instruments for continuously 

monitoring and recording the 

concentration of H2S in gas discharged 

to the flare according to the 

requirements in paragraphs (e)(2)(i) 

through (iii) of this section and shall 

collect and analyze samples of the gas 

and calculate total sulfur concentrations 

as specified in paragraphs (e)(2)(iv) 

through (ix) of this section. 

* * * * * 

(ii) The owner or operator shall 

conduct performance evaluations of 

each H2S monitor according to the 

requirements in § 60.13(c) and 

Performance Specification 7 of 

appendix B to this part. The owner or 

operator shall use EPA Method 11, 15 or 

15A of appendix A–5 to this part for 

conducting the relative accuracy 

evaluations. The method ANSI/ASME 

PTC 19.10–1981 (incorporated by 

reference—see § 60.17) is an acceptable 

alternative to EPA Method 15A of 

appendix A–5 to this part. The 

alternative relative accuracy procedures 

described in section 16.0 of Performance 

Specification 2 of appendix B to this 

part (cylinder gas audits) may be used 

for conducting the relative accuracy 

evaluations, except that it is not 

necessary to include as much of the 

sampling probe or sampling line as 

practical. 

* * * * * 

(vi) * * * 

(C) Determine the acceptable range for 

subsequent weekly samples based on 

the 95-percent confidence interval for 

the distribution of daily ratios based on 

the 10 individual daily ratios using 

Equation 14 of this section. 

Where: 

AR = Acceptable range of subsequent ratio 

determinations, unitless. 

RatioAvg = 10-day average total sulfur-toH2S concentration ratio, unitless. 

2.262 = t-distribution statistic for 95- 

percent 2-sided confidence interval for 10 

samples (9 degrees of freedom). 

SDev = Standard deviation of the 10 daily 

average total sulfur-to-H2S concentration 

ratios used to develop the 10-day average 

total sulfur-to-H2S concentration ratio, 

unitless. 

* * * * * 

(3) SO2 monitoring requirements. The 

owner or operator shall install, operate, 

calibrate, and maintain an instrument 

for continuously monitoring and 

recording the concentration of SO2 from 

a process heater or other fuel gas 

combustion device that is combusting 

gas representative of the fuel gas in the 

flare gas line according to the 

requirements in paragraph (a)(1) of this 

section, determine the F factor of the 

fuel gas at least daily according to the 

requirements in paragraphs (d)(2) 

through (4) of this section, determine 

the higher heating value of the fuel gas 

at least daily according to the 

requirements in paragraph (d)(7) of this 

section, and calculate the total sulfur 

content (as SO2) in the fuel gas using 

Equation 15 of this section. 

Where: 

TSFG = Total sulfur concentration, as SO2, 

in the fuel gas, ppmv. 

CSO2 = Concentration of SO2 in the exhaust 

gas, ppmv (dry basis at 0-percent excess air). 

Fd = F factor gas on dry basis at 0-percent 

excess air, dscf/MMBtu. 

HHVFG = Higher heating value of the fuel 

gas, MMBtu/scf. 

* * * * * 

(f) * * * 

(1) * * * 

(ii) Use a flow sensor meeting an 

accuracy requirement of ±20 percent of 

the flow rate at velocities ranging from 

0.1 to 1 feet per second and an accuracy 

of ±5 percent of the flow rate for 

velocities greater than 1 feet per second. 

* * * * * 

(h) * * * 

(5) Daily O2 limits for fuel gas 

combustion devices. Each day during 

which the concentration of O2 as 

measured by the O2 continuous 

monitoring system required under 

paragraph (c)(6) or (d)(8) of this section 

exceeds the O2 operating limit or 

operating curve determined during the 

most recent biennial performance test. 

PART 63—NATIONAL EMISSION 

STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR SOURCE 

CATEGORIES 

■ 10. The authority citation for part 63 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et se. 

Subpart A—General Provisions 

■ 11. Section 63.14 is amended by: 

■ a. Revising paragraph (h)(14); 

■ b. Redesignating paragraphs (h)(82) 

through (99) as (h)(86) through (103), 

paragraphs (h)(77) through (81) as 

(h)(80) through (84), paragraphs (h)(73) 

through (76) as paragraphs (h)(75) 

through (78), and paragraphs (h)(15) 

through (72) as (16) through (73), 

respectively; 

■ c. Revising newly redesignated 

paragraph (h)(78); 

■ d. Adding paragraphs (h)(15), (74), 

(79), (85), (104) and (j)(2); 

■ e. Redesignating paragraph (m)(3) 

through (21) as (m)(5) through (23), 

respectively, and paragraph (m)(2) as 

(m)(3). 

■ f. Adding paragraphs (m)(2) and (4) 

and (n)(3); and 

■ g. Revising paragraph (s)(1). 

The revisions and additions read as 

follows: 

§ 63.14 Incorporation by reference. 

* * * * * 

(h) * * * 

(14) ASTM D1945–03 (Reapproved 

2010), Standard Test Method for 

Analysis of Natural Gas by Gas 

Chromatography, Approved January 1, 

2010, IBR approved for §§ 63.670(j), 

63.772(h), and 63.1282(g). 

(15) ASTM D1945–14, Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography, Approved 


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November 1, 2014, IBR approved for 

§ 63.670(j). 

* * * * * 

(74) ASTM D6196–03 (Reapproved 

2009), Standard Practice for Selection of 

Sorbents, Sampling, and Thermal 

Desorption Analysis Procedures for 

Volatile Organic Compounds in Air, 

Approved March 1, 2009, IBR approved 

for appendix A to this part: Method 

325A and Method 325B. 

* * * * * 

(78) ASTM D6348–03 (Reapproved 

2010), Standard Test Method for 

Determination of Gaseous Compounds 

by Extractive Direct Interface Fourier 

Transform Infrared (FTIR) Spectroscopy, 

including Annexes A1 through A8, 

Approved October 1, 2010, IBR 

approved for § 63.1571(a), tables 4 and 

5 to subpart JJJJJ, tables 4 and 6 to 

subpart KKKKK, tables 1, 2, and 5 to 

subpart UUUUU and appendix B to 

subpart UUUUU. 

* * * * * 

(79) ASTM D6348–12e1, Standard 

Test Method for Determination of 

Gaseous Compounds by Extractive 

Direct Interface Fourier Transform 

Infrared (FTIR) Spectroscopy, Approved 

February 1, 2012, IBR approved for 

§ 63.1571(a). 

* * * * * 

(85) ASTM D6420–99 (Reapproved 

2010), Standard Test Method for 

Determination of Gaseous Organic 

Compounds by Direct Interface Gas 

Chromatography-Mass Spectrometry, 

Approved October 1, 2010, IBR 

approved for § 63.670(j) and appendix A 

to this part: Method 325B. 

* * * * * 

(104) ASTM UOP539–12, Refinery 

Gas Analysis by GC, Copyright 2012 (to 

UOP), IBR approved for § 63.670(j). 

* * * * * 

(j) * * * 

(2) BS EN 14662–4:2005, Ambient air 

quality standard method for the 

measurement of benzene 

concentrations—Part 4: Diffusive 

sampling followed by thermal 

desorption and gas chromatography, 

Published June 27, 2005, IBR approved 

for appendix A to this part: Method 

325A and Method 325B. 

* * * * * 

(m) * * * 

(2) EPA–454/B–08–002, Office of Air 

Quality Planning and Standards 

(OAQPS), Quality Assurance Handbook 

for Air Pollution Measurement Systems, 

Volume IV: Meteorological 

Measurements, Version 2.0 (Final), 

March 24, 2008, IBR approved for 

§ 63.658(d) and appendix A to this part: 

Method 325A. 

* * * * * 

(4) EPA–454/R–99–005, Office of Air 

Quality Planning and Standards 

(OAQPS), Meteorological Monitoring 

Guidance for Regulatory Modeling 

Applications, February 2000, IBR 

approved for appendix A to this part: 

Method 325A. 

* * * * * 

(n) * * * 

(3) ISO 16017–2:2003(E): Indoor, 

ambient and workplace air—sampling 

and analysis of volatile organic 

compounds by sorbent tube/thermal 

desorption/capillary gas 

chromatography—Part 2: Diffusive 

sampling, May 15, 2003, IBR approved 

for appendix A to this part: Method 

325A and Method 325B. 

* * * * * 

(s) * * * 

(1) ‘‘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, January 31, 

2003, IBR approved for §§ 63.654(c) and 

(g), 63.655(i), and 63.11920. 

* * * * * 

Subpart Y—National Emission 

Standards for Marine Tank Vessel 

Loading Operations 

■ 12. Section 63.560 is amended by 

revising paragraph (a)(4) to read as 

follows: 

§ 63.560 Applicability and designation of 

affected source. 

(a) * * * 

(4) Existing sources with emissions 

less than 10 and 25 tons must meet the 

submerged fill standards of 46 CFR 

153.282. 

* * * * * 

Subpart CC—National Emission 

Standards for Hazardous Air Pollutants 

From Petroleum Refineries 

■ 13. Section 63.640 is amended by: 

■ a. Revising paragraphs (a) 

introductory text and (c) introductory 

text; 

■ c. Adding paragraph (c)(9); 

■ d. Revising paragraphs (d)(5), (h), 

(k)(1), (l) introductory text, (l)(2) 

introductory text, (l)(2)(i), (l)(3) 

introductory text, (m) introductory text, 

(n) introductory text, (n)(1) through (5), 

(n)(8) introductory text, and (n)(8)(ii); 

■ e. Adding paragraphs (n)(8)(vii) and 

(viii); 

■ f. Revising paragraph (n)(9)(i); 

■ g. Adding paragraph (n)(10); 

■ h. Revising paragraph (o)(2)(i) 

introductory text; 

■ i. Adding paragraph (o)(2)(i)(D); 

■ j. Revising paragraph (o)(2)(ii) 

introductory text; and 

■ k. Adding paragraphs (o)(2)(ii)(C) and 

(s). 

The revisions and additions read as 

follows: 

§ 63.640 Applicability and designation of 

affected source. 

(a) This subpart applies to petroleum 

refining process units and to related 

emissions points that are specified in 

paragraphs (c)(1) through (9) of this 

section that are located at a plant site 

and that meet the criteria in paragraphs 

(a)(1) and (2) of this section: 

* * * * * 

(c) For the purposes of this subpart, 

the affected source shall comprise all 

emissions points, in combination, listed 

in paragraphs (c)(1) through (9) of this 

section that are located at a single 

refinery plant site. 

* * * * * 

(9) All releases associated with the 

decoking operations of a delayed coking 

unit, as defined in this subpart. 

(d) * * * 

(5) Emission points routed to a fuel 

gas system, as defined in § 63.641, 

provided that on and after January 30, 

2019, any flares receiving gas from that 

fuel gas system are subject to § 63.670. 

No other testing, monitoring, 

recordkeeping, or reporting is required 

for refinery fuel gas systems or emission 

points routed to refinery fuel gas 

systems. 

* * * * * 

(h) 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 (3) of this 

section. 

(1) Marine tank vessels at existing 

sources shall be in compliance with this 

subpart, except for §§ 63.657 through 

63.660, no later than August 18, 1999, 

unless the vessels are included in an 

emissions average to generate emission 

credits. Marine tank vessels used to 

generate credits in an emissions average 

shall be in compliance with this subpart 

no later than August 18, 1998, unless an 

extension has been granted by the 

Administrator as provided in § 63.6(i). 

(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 at the first 

degassing and cleaning activity after 

August 18, 1998, or August 18, 2005, 

whichever is first. 


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(3) An owner or operator may elect to 

comply with the provisions of 

§ 63.648(c) through (i) as an alternative 

to the provisions of § 63.648(a) and (b). 

In such cases, the owner or operator 

shall comply no later than the dates 

specified in paragraphs (h)(3)(i) through 

(iii) of this section. 

(i) Phase I (see table 2 of this subpart), 

beginning on August 18, 1998; 

(ii) Phase II (see table 2 of this 

subpart), beginning no later than August 

18, 1999; and 

(iii) Phase III (see table 2 of this 

subpart), beginning no later than 

February 18, 2001. 

* * * * * 

(k) * * * 

(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 

* * * * * 

(l) If an additional petroleum refining 

process unit is added to a plant site or 

if a miscellaneous process vent, storage 

vessel, gasoline loading rack, marine 

tank vessel loading operation, heat 

exchange system, or decoking operation 

that meets the criteria in paragraphs 

(c)(1) through (9) of this section is added 

to an existing petroleum refinery or if 

another deliberate operational process 

change creating an additional Group 1 

emissions point(s) (as defined in 

§ 63.641) is made to an existing 

petroleum refining process unit, and if 

the addition or process change is not 

subject to the new source requirements 

as determined according to paragraph (i) 

or (j) of this section, the requirements in 

paragraphs (l)(1) through (4) of this 

section shall apply. Examples of process 

changes include, but are not limited to, 

changes in production capacity, or feed 

or raw material where the change 

requires construction or physical 

alteration of the existing equipment or 

catalyst type, or whenever there is 

replacement, removal, or addition of 

recovery equipment. For purposes of 

this paragraph (l) 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). 

* * * * * 

(2) The added emission point(s) and 

any emission point(s) within the added 

or changed petroleum refining process 

unit shall be in compliance with the 

applicable requirements in item (4) of 

table 11 of this subpart by the dates 

specified in paragraph (l)(2)(i) or (ii) of 

this section. 

(i) If a petroleum refining process unit 

is added to a plant site or an emission 

point(s) is added to any existing 

petroleum refining process unit, the 

added emission point(s) shall be in 

compliance upon initial startup of any 

added petroleum refining process unit 

or emission point(s) or by the applicable 

compliance date in item (4) of table 11 

of this subpart, whichever is later. 

* * * * * 

(3) The owner or operator of a 

petroleum refining process unit or of a 

storage vessel, miscellaneous process 

vent, wastewater stream, gasoline 

loading rack, marine tank vessel loading 

operation, heat exchange system, or 

decoking operation meeting the criteria 

in paragraphs (c)(1) through (9) of this 

section that is added to a plant site and 

is subject to the requirements for 

existing sources shall comply with the 

reporting and recordkeeping 

requirements that are applicable to 

existing sources including, but not 

limited to, the reports listed in 

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

section. A process change to an existing 

petroleum refining process unit shall be 

subject to the reporting requirements for 

existing sources including, but not 

limited to, the reports listed in 

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

section. The applicable reports include, 

but are not limited to: 

* * * * * 

(m) If a change that does not meet the 

criteria in paragraph (l) of this section 

is made to a petroleum refining process 

unit subject to this subpart, and the 

change causes a Group 2 emission point 

to become a Group 1 emission point (as 

defined in § 63.641), then the owner or 

operator shall comply with the 

applicable requirements of this subpart 

for existing sources, as specified in item 

(4) of table 11 of this subpart, for the 

Group 1 emission point as expeditiously 

as practicable, but in no event later than 

3 years after the emission point becomes 

Group 1. 

* * * * * 

(n) Overlap of this subpart with other 

regulations for storage vessels. As 

applicable, paragraphs (n)(1), (3), (4), 

(6), and (7) of this section apply for 

Group 2 storage vessels and paragraphs 

(n)(2) and (5) of this section apply for 

Group 1 storage vessels. 

(1) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 2 storage vessel that is 

subject to the provisions of 40 CFR part 

60, subpart Kb, is required to comply 

only with the requirements of 40 CFR 

part 60, subpart Kb, except as provided 

in paragraph (n)(8) of this section. After 

the compliance dates specified in 

paragraph (h) of this section, a Group 2 

storage vessel that is subject to the 

provisions of 40 CFR part 61, subpart Y, 

is required to comply only with the 

requirements of 40 CFR part 61, subpart 

Y, except as provided in paragraph 

(n)(10) of this section. 

(2) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 1 storage vessel that is 

also subject to 40 CFR part 60, subpart 

Kb, is required to comply only with 

either 40 CFR part 60, subpart Kb, 

except as provided in paragraph (n)(8) 

of this section or this subpart. After the 

compliance dates specified in paragraph 

(h) of this section, a Group 1 storage 

vessel that is also subject to 40 CFR part 

61, subpart Y, is required to comply 

only with either 40 CFR part 61, subpart 

Y, except as provided in paragraph 

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

(3) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 2 storage vessel that is 

part of a new source and is subject to 

40 CFR 60.110b, but is not required to 

apply controls by 40 CFR 60.110b or 

60.112b, is required to comply only 

with this subpart. 

(4) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 2 storage vessel that is 

part of a new source and is subject to 

40 CFR 61.270, but is not required to 

apply controls by 40 CFR 61.271, is 

required to comply only with this 

subpart. 

(5) After the compliance dates 

specified in paragraph (h) of this 

section, a Group 1 storage vessel that is 

also subject to the provisions of 40 CFR 

part 60, subpart K or Ka, is required to 

only comply with the provisions of this 

subpart. 

* * * * * 

(8) Storage vessels described by 

paragraph (n)(1) of this section are to 

comply with 40 CFR part 60, subpart 

Kb, except as provided in paragraphs 

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

Storage vessels described by paragraph 

(n)(2) electing to comply with part 60, 

subpart Kb of this chapter shall comply 

with subpart Kb except as provided in 

paragraphs (n)(8)(i) through (viii) of this 

section. 

* * * * * 

(ii) If the owner or operator 

determines that it is unsafe to perform 

the seal gap measurements required in 

§ 60.113b(b) of this chapter or to inspect 

the vessel to determine compliance with 


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§ 60.113b(a) of this chapter because the 

roof appears to be structurally unsound 

and poses an imminent danger to 

inspecting personnel, the owner or 

operator shall comply with the 

requirements in either § 63.120(b)(7)(i) 

or (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 (B) of subpart 

WW. 

* * * * * 

(vii) To be in compliance with 

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

chapter, guidepoles in floating roof 

storage vessels must be equipped with 

covers and/or controls (e.g., pole float 

system, pole sleeve system, internal 

sleeve system or flexible enclosure 

system) as appropriate to comply with 

the ‘‘no visible gap’’ requirement. 

(viii) If a flare is used as a control 

device for a storage vessel, on and after 

January 30, 2019, 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) * * * 

(i) If the owner or operator determines 

that it is unsafe to perform the seal gap 

measurements required in 

§ 60.113a(a)(1) of this chapter because 

the floating roof appears to be 

structurally unsound and poses an 

imminent danger to inspecting 

personnel, the owner or operator shall 

comply with the requirements in either 

§ 63.120(b)(7)(i) or (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 (B) of 

subpart WW. 

* * * * * 

(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 (vi) of this section. 

Storage vessels described by paragraph 

(n)(2) electing to comply with 40 CFR 

part 61, subpart Y, shall comply with 

subpart Y except as provided for in 

paragraphs (n)(10)(i) through (viii) of 

this section. 

(i) Storage vessels that are to comply 

with § 61.271(b) of this chapter are 

exempt from the secondary seal 

requirements of § 61.271(b)(2)(ii) of this 

chapter during the gap measurements 

for the primary seal required by 

§ 61.272(b) of this chapter. 

(ii) If the owner or operator 

determines that it is unsafe to perform 

the seal gap measurements required in 

§ 61.272(b) of this chapter or to inspect 

the vessel to determine compliance with 

§ 61.272(a) of this chapter because the 

roof appears to be structurally unsound 

and poses an imminent danger to 

inspecting personnel, the owner or 

operator shall comply with the 

requirements in either § 63.120(b)(7)(i) 

or (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 (B) of subpart 

WW. 

(iii) If a failure is detected during the 

inspections required by § 61.272(a)(2) of 

this chapter or during the seal gap 

measurements required by § 61.272(b)(1) 

of this chapter, and the vessel cannot be 

repaired within 45 days and the vessel 

cannot be emptied within 45 days, the 

owner or operator may utilize up to two 

extensions of up to 30 additional 

calendar days each. The owner or 

operator is not required to provide a 

request for the extension to the 

Administrator. 

(iv) If an extension is utilized in 

accordance with paragraph (n)(10)(iii) of 

this section, the owner or operator shall, 

in the next periodic report, identify the 

vessel, provide the information listed in 

§ 61.272(a)(2) or (b)(4)(iii) of this 

chapter, and describe the nature and 

date of the repair made or provide the 

date the storage vessel was emptied. 

(v) Owners and operators of storage 

vessels complying with 40 CFR part 61, 

subpart Y, may submit the inspection 

reports required by § 61.275(a), (b)(1), 

and (d) of this chapter as part of the 

periodic reports required by this 

subpart, rather than within the 60-day 

period specified in § 61.275(a), (b)(1), 

and (d) of this chapter. 

(vi) The reports of rim seal 

inspections specified in § 61.275(d) of 

this chapter are not required if none of 

the measured gaps or calculated gap 

areas exceed the limitations specified in 

§ 61.272(b)(4) of this chapter. 

Documentation of the inspections shall 

be recorded as specified in § 61.276(a) of 

this chapter. 

(vii) To be in compliance with 

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

guidepoles in floating roof storage 

vessels must be equipped with covers 

and/or controls (e.g., pole float system, 

pole sleeve system, internal sleeve 

system or flexible enclosure system) as 

appropriate to comply with the ‘‘no 

visible gap’’ requirement. 

(viii) If a flare is used as a control 

device for a storage vessel, on and after 

January 30, 2019, 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) * * * 

(2) * * * 

(i) Comply with paragraphs 

(o)(2)(i)(A) through (D) of this section. 

* * * * * 

(D) If a flare is used as a control 

device, on and after January 30, 2019, 

the flare shall meet the requirements of 

§ 63.670. Prior to January 30, 2019, the 

flare shall meet the applicable 

requirements of 40 CFR part 61, subpart 

FF, and subpart G of this part, or the 

requirements of § 63.670. 

(ii) Comply with paragraphs 

(o)(2)(ii)(A) through (C) of this section. 

* * * * * 

(C) If a flare is used as a control 

device, on and after January 30, 2019, 

the flare shall meet the requirements of 

§ 63.670. Prior to January 30, 2019, the 

flare shall meet the applicable 

requirements of 40 CFR part 61, subpart 

FF, and subpart G of this part, or the 

requirements of § 63.670. 

* * * * * 

(s) Overlap of this subpart with other 

regulation for flares. On January 30, 

2019, flares that are subject to the 

provisions of 40 CFR 60.18 or 63.11 and 

subject to this subpart are required to 

comply only with the provisions 

specified in this subpart. Prior to 

January 30, 2019, flares that are subject 

to the provisions of 40 CFR 60.18 or 

63.11 and elect to comply with the 

requirements in §§ 63.670 and 63.671 

are required to comply only with the 

provisions specified in this subpart. 

■ 14. Section 63.641 is amended by: 

■ a. Adding, in alphabetical order, 

definitions of ‘‘Assist air,’’ ‘‘Assist 

steam,’’ ‘‘Center steam,’’ ‘‘Closed 

blowdown system,’’ ‘‘Combustion 

zone,’’ ‘‘Combustion zone gas,’’ 

‘‘Decoking operations,’’ ‘‘Delayed coking 

unit,’’ ‘‘Flare,’’ ‘‘Flare purge gas,’’ ‘‘Flare 

supplemental gas,’’ ‘‘Flare sweep gas,’’ 

‘‘Flare vent gas,’’ ‘‘Flexible enclosure 

device,’’ ‘‘Force majeure event,’’ ‘‘Lower 

steam,’’ ‘‘Net heating value,’’ ‘‘Perimeter 

assist air,’’ ‘‘Pilot gas,’’ ‘‘Premix assist 

air,’’ ‘‘Regulated material,’’ ‘‘Thermal 

expansion relief valve,’’ ‘‘Total steam,’’ 

and ‘‘Upper steam’’; and 

■ b. Revising the definitions of 

‘‘Delayed coker vent,’’ ‘‘Emission 

point,’’ ‘‘Group 1 storage vessel,’’ 

‘‘Miscellaneous process vent,’’ 

‘‘Periodically discharged,’’ and 

‘‘Reference control technology for 

storage vessels.’’ 

The revisions and additions read as 

follows: 

§ 63.641 Definitions. 

* * * * * 

Assist air means all air that 

intentionally is introduced prior to or at 


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a flare tip through nozzles or other 

hardware conveyance for the purposes 

including, but not limited to, protecting 

the design of the flare tip, promoting 

turbulence for mixing or inducing air 

into the flame. Assist air includes 

premix assist air and perimeter assist 

air. Assist air does not include the 

surrounding ambient air. 

Assist steam means all steam that 

intentionally is introduced prior to or at 

a flare tip through nozzles or other 

hardware conveyance for the purposes 

including, but not limited to, protecting 

the design of the flare tip, promoting 

turbulence for mixing or inducing air 

into the flame. Assist steam includes, 

but is not necessarily limited to, center 

steam, lower steam and upper steam. 

* * * * * 

Center steam means the portion of 

assist steam introduced into the stack of 

a flare to reduce burnback. 

Closed blowdown system means a 

system used for depressuring process 

vessels that is not open to the 

atmosphere and is configured of piping, 

ductwork, connections, accumulators/

knockout drums, and, if necessary, flow 

inducing devices that transport gas or 

vapor from process vessel to a control 

device or back into the process. 

* * * * * 

Combustion zone means the area of 

the flare flame where the combustion 

zone gas combines for combustion. 

Combustion zone gas means all gases 

and vapors found just after a flare tip. 

This gas includes all flare vent gas, total 

steam, and premix air. 

* * * * * 

Decoking operations means the 

sequence of steps conducted at the end 

of the delayed coking unit’s cooling 

cycle to open the coke drum to the 

atmosphere in order to remove coke 

from the coke drum. Decoking 

operations begin at the end of the 

cooling cycle when steam released from 

the coke drum is no longer discharged 

via the unit’s blowdown system but 

instead is vented directly to the 

atmosphere. Decoking operations 

include atmospheric depressuring 

(venting), deheading, draining, and 

decoking (coke cutting). 

Delayed coker vent means a 

miscellaneous process vent that 

contains uncondensed vapors from the 

delayed coking unit’s blowdown 

system. Venting from the delayed coker 

vent is typically intermittent in nature, 

and occurs primarily during the cooling 

cycle of a delayed coking unit coke 

drum when vapor from the coke drums 

cannot be sent to the fractionator 

column for product recovery. The 

emissions from the decoking operations, 

which include direct atmospheric 

venting, deheading, draining, or 

decoking (coke cutting), are not 

considered to be delayed coker vents. 

Delayed coking unit means a refinery 

process unit in which high molecular 

weight petroleum derivatives are 

thermally cracked and petroleum coke 

is produced in a series of closed, batch 

system reactors. A delayed coking unit 

includes, but is not limited to, all of the 

coke drums associated with a single 

fractionator; the fractionator, including 

the bottoms receiver and the overhead 

condenser; the coke drum cutting water 

and quench system, including the jet 

pump and coker quench water tank; and 

the coke drum blowdown recovery 

compressor system. 

* * * * * 

Emission point means an individual 

miscellaneous process vent, storage 

vessel, wastewater stream, equipment 

leak, decoking operation or heat 

exchange system associated with a 

petroleum refining process unit; an 

individual storage vessel or equipment 

leak associated with a bulk gasoline 

terminal or pipeline breakout station 

classified under Standard Industrial 

Classification code 2911; a gasoline 

loading rack classified under Standard 

Industrial Classification code 2911; or a 

marine tank vessel loading operation 

located at a petroleum refinery. 

* * * * * 

Flare means a combustion device 

lacking an enclosed combustion 

chamber that uses an uncontrolled 

volume of ambient air to burn gases. For 

the purposes of this rule, the definition 

of flare includes, but is not necessarily 

limited to, air-assisted flares, steamassisted flares and non-assisted flares. 

Flare purge gas means gas introduced 

between a flare header’s water seal and 

the flare tip to prevent oxygen 

infiltration (backflow) into the flare tip. 

For a flare with no water seal, the 

function of flare purge gas is performed 

by flare sweep gas and, therefore, by 

definition, such a flare has no flare 

purge gas. 

Flare supplemental gas means all gas 

introduced to the flare in order to 

improve the combustible characteristics 

of combustion zone gas. 

Flare sweep gas means, for a flare 

with a flare gas recovery system, the gas 

intentionally introduced into the flare 

header system to maintain a constant 

flow of gas through the flare header in 

order to prevent oxygen buildup in the 

flare header; flare sweep gas in these 

flares is introduced prior to and 

recovered by the flare gas recovery 

system. For a flare without a flare gas 

recovery system, flare sweep gas means 

the gas intentionally introduced into the 

flare header system to maintain a 

constant flow of gas through the flare 

header and out the flare tip in order to 

prevent oxygen buildup in the flare 

header and to prevent oxygen 

infiltration (backflow) into the flare tip. 

Flare vent gas means all gas found just 

prior to the flare tip. This gas includes 

all flare waste gas (i.e., gas from facility 

operations that is directed to a flare for 

the purpose of disposing of the gas), that 

portion of flare sweep gas that is not 

recovered, flare purge gas and flare 

supplemental gas, but does not include 

pilot gas, total steam or assist air. 

Flexible enclosure device means a seal 

made of an elastomeric fabric (or other 

material) which completely encloses a 

slotted guidepole or ladder and 

eliminates the vapor emission pathway 

from inside the storage vessel through 

the guidepole slots or ladder slots to the 

outside air. 

* * * * * 

Force majeure event means a release 

of HAP, either directly to the 

atmosphere from a relief valve or 

discharged via a flare, that is 

demonstrated to the satisfaction of the 

Administrator to result from an event 

beyond the refinery owner or operator’s 

control, such as natural disasters; acts of 

war or terrorism; loss of a utility 

external to the refinery (e.g., external 

power curtailment), excluding power 

curtailment due to an interruptible 

service agreement; and fire or explosion 

originating at a near or adjoining facility 

outside of the refinery owner or 

operator’s control that impacts the 

refinery’s ability to operate. 

* * * * * 

Group 1 storage vessel means: 

(1) Prior to February 1, 2016: 

(i) A storage vessel at an existing 

source that has a design capacity greater 

than or equal to 177 cubic meters and 

stored-liquid maximum true vapor 

pressure greater than or equal to 10.4 

kilopascals and stored-liquid annual 

average true vapor pressure greater than 

or equal to 8.3 kilopascals and annual 

average HAP liquid concentration 

greater than 4 percent by weight total 

organic HAP; 

(ii) A storage vessel at a new source 

that has a design storage capacity greater 

than or equal to 151 cubic meters and 

stored-liquid maximum true vapor 

pressure greater than or equal to 3.4 

kilopascals and annual average HAP 

liquid concentration greater than 2 

percent by weight total organic HAP; or 

(iii) A storage vessel at a new source 

that has a design storage capacity greater 

than or equal to 76 cubic meters and 

less than 151 cubic meters and storedVerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00064 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2

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liquid maximum true vapor pressure 

greater than or equal to 77 kilopascals 

and annual average HAP liquid 

concentration greater than 2 percent by 

weight total organic HAP. 

(2) On and after February 1, 2016: 

(i) A storage vessel at an existing 

source that has a design capacity greater 

than or equal to 151 cubic meters 

(40,000 gallons) and stored-liquid 

maximum true vapor pressure greater 

than or equal to 5.2 kilopascals (0.75 

pounds per square inch) and annual 

average HAP liquid concentration 

greater than 4 percent by weight total 

organic HAP; 

(ii) A storage vessel at an existing 

source that has a design storage capacity 

greater than or equal to 76 cubic meters 

(20,000 gallons) and less than 151 cubic 

meters (40,000 gallons) and storedliquid maximum true vapor pressure 

greater than or equal to 13.1 kilopascals 

(1.9 pounds per square inch) and annual 

average HAP liquid concentration 

greater than 4 percent by weight total 

organic HAP; 

(iii) A storage vessel at a new source 

that has a design storage capacity greater 

than or equal to 151 cubic meters 

(40,000 gallons) and stored-liquid 

maximum true vapor pressure greater 

than or equal to 3.4 kilopascals (0.5 

pounds per square inch) and annual 

average HAP liquid concentration 

greater than 2 percent by weight total 

organic HAP; or 

(iv) A storage vessel at a new source 

that has a design storage capacity greater 

than or equal to 76 cubic meters (20,000 

gallons) and less than 151 cubic meters 

(40,000 gallons) and stored-liquid 

maximum true vapor pressure greater 

than or equal to 13.1 kilopascals (1.9 

pounds per square inch) and annual 

average HAP liquid concentration 

greater than 2 percent by weight total 

organic HAP. 

* * * * * 

Lower steam means the portion of 

assist steam piped to an exterior annular 

ring near the lower part of a flare tip, 

which then flows through tubes to the 

flare tip, and ultimately exits the tubes 

at the flare tip. 

* * * * * 

Miscellaneous process vent means a 

gas stream containing greater than 20 

parts per million by volume organic 

HAP that is continuously or periodically 

discharged from a petroleum refining 

process unit meeting the criteria 

specified in § 63.640(a). Miscellaneous 

process vents include gas streams that 

are discharged directly to the 

atmosphere, gas streams that are routed 

to a control device prior to discharge to 

the atmosphere, or gas streams that are 

diverted through a product recovery 

device prior to control or discharge to 

the atmosphere. Miscellaneous process 

vents include vent streams from: Caustic 

wash accumulators, distillation tower 

condensers/accumulators, flash/

knockout drums, reactor vessels, 

scrubber overheads, stripper overheads, 

vacuum pumps, steam ejectors, hot 

wells, high point bleeds, wash tower 

overheads, water wash accumulators, 

blowdown condensers/accumulators, 

and delayed coker vents. Miscellaneous 

process vents do not include: 

(1) Gaseous streams routed to a fuel 

gas system, provided that on and after 

January 30, 2019, any flares receiving 

gas from the fuel gas system are in 

compliance with § 63.670; 

(2) Pressure relief device discharges; 

(3) Leaks from equipment regulated 

under § 63.648; 

(4) [Reserved] 

(5) In situ sampling systems (onstream 

analyzers) until January 30, 2019. After 

this date, these sampling systems will 

be included in the definition of 

miscellaneous process vents; 

(6) Catalytic cracking unit catalyst 

regeneration vents; 

(7) Catalytic reformer regeneration 

vents; 

(8) Sulfur plant vents; 

(9) Vents from control devices such as 

scrubbers, boilers, incinerators, and 

electrostatic precipitators applied to 

catalytic cracking unit catalyst 

regeneration vents, catalytic reformer 

regeneration vents, and sulfur plant 

vents; 

(10) Vents from any stripping 

operations applied to comply with the 

wastewater provisions of this subpart, 

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

subpart FF; 

(11) Emissions associated with 

delayed coking unit decoking 

operations; 

(12) Vents from storage vessels; 

(13) Emissions from wastewater 

collection and conveyance systems 

including, but not limited to, 

wastewater drains, sewer vents, and 

sump drains; and 

(14) Hydrogen production plant vents 

through which carbon dioxide is 

removed from process streams or 

through which steam condensate 

produced or treated within the 

hydrogen plant is degassed or deaerated. 

Net heating value means the energy 

released as heat when a compound 

undergoes complete combustion with 

oxygen to form gaseous carbon dioxide 

and gaseous water (also referred to as 

lower heating value). 

* * * * * 

Perimeter assist air means the portion 

of assist air introduced at the perimeter 

of the flare tip or above the flare tip. 

Perimeter assist air includes air 

intentionally entrained in lower and 

upper steam. Perimeter assist air 

includes all assist air except premix 

assist air. 

Periodically discharged means 

discharges that are intermittent and 

associated with routine operations, 

maintenance activities, startups, 

shutdowns, malfunctions, or process 

upsets. 

* * * * * 

Pilot gas means gas introduced into a 

flare tip that provides a flame to ignite 

the flare vent gas. 

* * * * * 

Premix assist air means the portion of 

assist air that is introduced to the flare 

vent gas, whether injected or induced, 

prior to the flare tip. Premix assist air 

also includes any air intentionally 

entrained in center steam. 

* * * * * 

Reference control technology for 

storage vessels means either: 

(1) For Group 1 storage vessels 

complying with § 63.660: 

(i) An internal floating roof, including 

an external floating roof converted to an 

internal floating roof, meeting the 

specifications of § 63.1063(a)(1)(i) and 

(b); 

(ii) An external floating roof meeting 

the specifications of § 63.1063(a)(1)(ii), 

(a)(2), and (b); or 

(iii) [Reserved] 

(iv) A closed-vent system to a control 

device that reduces organic HAP 

emissions by 95 percent, or to an outlet 

concentration of 20 parts per million by 

volume (ppmv). 

(v) For purposes of emissions 

averaging, these four technologies are 

considered equivalent. 

(2) For all other storage vessels: 

(i) An internal floating roof meeting 

the specifications of § 63.119(b) of 

subpart G except for § 63.119(b)(5) and 

(6); 

(ii) An external floating roof meeting 

the specifications of § 63.119(c) of 

subpart G except for § 63.119(c)(2); 

(iii) An external floating roof 

converted to an internal floating roof 

meeting the specifications of § 63.119(d) 

of subpart G except for § 63.119(d)(2); or 

(iv) A closed-vent system to a control 

device that reduces organic HAP 

emissions by 95 percent, or to an outlet 

concentration of 20 parts per million by 

volume. 

(v) For purposes of emissions 

averaging, these four technologies are 

considered equivalent. 

* * * * * 

Regulated material means any stream 

associated with emission sources listed 


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75242 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

in § 63.640(c) required to meet control 

requirements under this subpart as well 

as any stream for which this subpart or 

a cross-referencing subpart specifies that 

the requirements for flare control 

devices in § 63.670 must be met. 

* * * * * 

Thermal expansion relief valve means 

a pressure relief valve designed to 

protect equipment from excess pressure 

due to thermal expansion of blocked 

liquid-filled equipment or piping due to 

ambient heating or heat from a heat 

tracing system. Pressure relief valves 

designed to protect equipment from 

excess pressure due to blockage against 

a pump or compressor or due to fire 

contingency are not thermal expansion 

relief valves. 

* * * * * 

Total steam means the total of all 

steam that is supplied to a flare and 

includes, but is not limited to, lower 

steam, center steam and upper steam. 

Upper steam means the portion of 

assist steam introduced via nozzles 

located on the exterior perimeter of the 

upper end of the flare tip. 

* * * * * 

■ 15. Section 63.642 is amended by: 

■ a. Adding paragraph (b); 

■ b. Revising paragraphs (d)(3), (e), (i), 

(k) introductory text, (k)(1), (l) 

introductory text, and (l)(2); and 

■ c. Adding paragraph (n). 

The revisions and additions read as 

follows: 

§ 63.642 General standards. 

* * * * * 

(b) The emission standards set forth in 

this subpart shall apply at all times. 

* * * * * 

(d) * * * 

(3) Performance tests shall be 

conducted according to the provisions 

of § 63.7(e) except that performance 

tests shall be conducted at maximum 

representative operating capacity for the 

process. During the performance test, an 

owner or operator shall operate the 

control device at either maximum or 

minimum representative operating 

conditions for monitored control device 

parameters, whichever results in lower 

emission reduction. An owner or 

operator shall not conduct a 

performance test during startup, 

shutdown, periods when the control 

device is bypassed or periods when the 

process, monitoring equipment or 

control device is not operating properly. 

The owner/operator may not conduct 

performance tests during periods of 

malfunction. The owner or operator 

must record the process information 

that is necessary to document operating 

conditions during the test and include 

in such record an explanation to 

support that the test was conducted at 

maximum representative operating 

capacity. Upon request, the owner or 

operator shall make available to the 

Administrator such records as may be 

necessary to determine the conditions of 

performance tests. 

* * * * * 

(e) All applicable records shall be 

maintained as specified in § 63.655(i). 

* * * * * 

(i) The owner or operator of an 

existing source shall demonstrate 

compliance with the emission standard 

in paragraph (g) of this section by 

following the procedures specified in 

paragraph (k) of this section for all 

emission points, or by following the 

emissions averaging compliance 

approach specified in paragraph (l) of 

this section for specified emission 

points and the procedures specified in 

paragraph (k)(1) of this section. 

* * * * * 

(k) The owner or operator of an 

existing source may comply, and the 

owner or operator of a new source shall 

comply, with the applicable provisions 

in §§ 63.643 through 63.645, 63.646 or 

63.660, 63.647, 63.650, and 63.651, as 

specified in § 63.640(h). 

(1) The owner or operator using this 

compliance approach shall also comply 

with the requirements of §§ 63.648 and/ 

or 63.649, 63.654, 63.655, 63.657, 

63.658, 63.670 and 63.671, as 

applicable. 

* * * * * 

(l) The owner or operator of an 

existing source may elect to control 

some of the emission points within the 

source to different levels than specified 

under §§ 63.643 through 63.645, 63.646 

or 63.660, 63.647, 63.650, and 63.651, as 

applicable according to § 63.640(h), by 

using an emissions averaging 

compliance approach as long as the 

overall emissions for the source do not 

exceed the emission level specified in 

paragraph (g) of this section. The owner 

or operator using emissions averaging 

shall meet the requirements in 

paragraphs (l)(1) and (2) of this section. 

* * * * * 

(2) Comply with the requirements of 

§§ 63.648 and/or 63.649, 63.654, 63.652, 

63.653, 63.655, 63.657, 63.658, 63.670 

and 63.671, as applicable. 

* * * * * 

(n) At all times, the owner or operator 

must operate and maintain any affected 

source, including associated air 

pollution control equipment and 

monitoring equipment, in a manner 

consistent with safety and good air 

pollution control practices for 

minimizing emissions. The general duty 

to minimize emissions does not require 

the owner operator to make any further 

efforts to reduce emissions if levels 

required by the applicable standard 

have been achieved. Determination of 

whether a source is operating in 

compliance with operation and 

maintenance requirements will be based 

on information available to the 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operation and maintenance 

procedures, review of operation and 

maintenance records, and inspection of 

the source. 

■ 16. Section 63.643 is amended by 

revising paragraphs (a) introductory text 

and (a)(1) and adding paragraph (c) to 

read as follows: 

§ 63.643 Miscellaneous process vent 

provisions. 

(a) The owner or operator of a Group 

1 miscellaneous process vent as defined 

in § 63.641 shall comply with the 

requirements of either paragraph (a)(1) 

or (2) of this section or, if applicable, 

paragraph (c) of this section. The owner 

or operator of a miscellaneous process 

vent that meets the conditions in 

paragraph (c) of this section is only 

required to comply with the 

requirements of paragraph (c) of this 

section and § 63.655(g)(13) and (i)(12) 

for that vent. 

(1) Reduce emissions of organic 

HAP’s using a flare. On and after 

January 30, 2019, the flare shall meet 

the requirements of § 63.670. Prior to 

January 30, 2019, the flare shall meet 

the requirements of § 63.11(b) of subpart 

A or the requirements of § 63.670. 

* * * * * 

(c) An owner or operator may 

designate a process vent as a 

maintenance vent if the vent is only 

used as a result of startup, shutdown, 

maintenance, or inspection of 

equipment where equipment is emptied, 

depressurized, degassed or placed into 

service. The owner of operator does not 

need to designate a maintenance vent as 

a Group 1 or Group 2 miscellaneous 

process vent. The owner or operator 

must comply with the applicable 

requirements in paragraphs (c)(1) 

through (3) of this section for each 

maintenance vent. 

(1) Prior to venting to the atmosphere, 

process liquids are removed from the 

equipment as much as practical and the 

equipment is depressured to a control 

device, fuel gas system, or back to the 

process until one of the following 

conditions, as applicable, is met. 

(i) The vapor in the equipment served 

by the maintenance vent has a lower 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75243 

explosive limit (LEL) of less than 10 

percent. 

(ii) If there is no ability to measure the 

LEL of the vapor in the equipment based 

on the design of the equipment, the 

pressure in the equipment served by the 

maintenance vent is reduced to 5 psig 

or less. Upon opening the maintenance 

vent, active purging of the equipment 

cannot be used until the LEL of the 

vapors in the maintenance vent (or 

inside the equipment if the maintenance 

is a hatch or similar type of opening) 

equipment is less than 10 percent. 

(iii) The equipment served by the 

maintenance vent contains less than 72 

pounds of VOC. 

(iv) If the maintenance vent is 

associated with equipment containing 

pyrophoric catalyst (e.g., hydrotreaters 

and hydrocrackers) at refineries that do 

not have a pure hydrogen supply, the 

LEL of the vapor in the equipment must 

be less than 20 percent, except for one 

event per year not to exceed 35 percent. 

(2) Except for maintenance vents 

complying with the alternative in 

paragraph (c)(1)(iii) of this section, the 

owner or operator must determine the 

LEL or, if applicable, equipment 

pressure using process instrumentation 

or portable measurement devices and 

follow procedures for calibration and 

maintenance according to 

manufacturer’s specifications. 

(3) For maintenance vents complying 

with the alternative in paragraph 

(c)(1)(iii) of this section, the owner or 

operator shall determine mass of VOC in 

the equipment served by the 

maintenance vent based on the 

equipment size and contents after 

considering any contents drained or 

purged from the equipment. Equipment 

size may be determined from equipment 

design specifications. Equipment 

contents may be determined using 

process knowledge. 

■ 17. Section 63.644 is amended by 

revising paragraphs (a) introductory 

text, (a)(2), and (c) to read as follows: 

§ 63.644 Monitoring provisions for 

miscellaneous process vents. 

(a) Except as provided in paragraph 

(b) of this section, each owner or 

operator of a Group 1 miscellaneous 

process vent that uses a combustion 

device to comply with the requirements 

in § 63.643(a) shall install the 

monitoring equipment specified in 

paragraph (a)(1), (2), (3), or (4) of this 

section, depending on the type of 

combustion device used. All monitoring 

equipment shall be installed, calibrated, 

maintained, and operated according to 

manufacturer’s specifications or other 

written procedures that provide 

adequate assurance that the equipment 

will monitor accurately and, except for 

CPMS installed for pilot flame 

monitoring, must meet the applicable 

minimum accuracy, calibration and 

quality control requirements specified 

in table 13 of this subpart. 

* * * * * 

(2) Where a flare is used prior to 

January 30, 2019, a device (including 

but not limited to a thermocouple, an 

ultraviolet beam sensor, or an infrared 

sensor) capable of continuously 

detecting the presence of a pilot flame 

is required, or the requirements of 

§ 63.670 shall be met. Where a flare is 

used on and after January 30, 2019, the 

requirements of § 63.670 shall be met. 

* * * * * 

(c) The owner or operator of a Group 

1 miscellaneous process vent using a 

vent system that contains bypass lines 

that could divert a vent stream away 

from the control device used to comply 

with paragraph (a) of this section either 

directly to the atmosphere or to a 

control device that does not comply 

with the requirements in § 63.643(a) 

shall comply with either paragraph 

(c)(1) or (2) of this section. Use of the 

bypass at any time to divert a Group 1 

miscellaneous process vent stream to 

the atmosphere or to a control device 

that does not comply with the 

requirements in § 63.643(a) is an 

emissions standards violation. 

Equipment such as low leg drains and 

equipment subject to § 63.648 are not 

subject to this paragraph (c). 

(1) Install, calibrate and maintain a 

flow indicator that determines whether 

a vent stream flow is present at least 

once every hour. A manual block valve 

equipped with a valve position 

indicator may be used in lieu of a flow 

indicator, as long as the valve position 

indicator is monitored continuously. 

Records shall be generated as specified 

in § 63.655(h) and (i). The flow indicator 

shall be installed at the entrance to any 

bypass line that could divert the vent 

stream away from the control device to 

the atmosphere; or 

(2) Secure the bypass line valve in the 

non-diverting position with a car-seal or 

a lock-and-key type configuration. A 

visual inspection of the seal or closure 

mechanism shall be performed at least 

once every month to ensure that the 

valve is maintained in the non-diverting 

position and that the vent stream is not 

diverted through the bypass line. 

* * * * * 

■ 18. Section 63.645 is amended by 

revising paragraphs (e)(1) and (f)(2) to 

read as follows: 

§ 63.645 Test methods and procedures for 

miscellaneous process vents. 

* * * * * 

(e) * * * 

(1) Methods 1 or 1A of 40 CFR part 

60, appendix A–1, as appropriate, shall 

be used for selection of the sampling 

site. For vents smaller than 0.10 meter 

in diameter, sample at the center of the 

vent. 

* * * * * 

(f) * * * 

(2) The gas volumetric flow rate shall 

be determined using Methods 2, 2A, 2C, 

2D, or 2F of 40 CFR part 60, appendix 

A–1 or Method 2G of 40 CFR part 60, 

appendix A–2, as appropriate. 

* * * * * 

■ 19. Section 63.646 is amended by 

adding introductory text and revising 

paragraph (b)(2) to read as follows: 

§ 63.646 Storage vessel provisions. 

Upon a demonstration of compliance 

with the standards in § 63.660 by the 

compliance dates specified in 

§ 63.640(h), the standards in this section 

shall no longer apply. 

* * * * * 

(b) * * * 

(2) When an owner or operator and 

the Administrator do not agree on 

whether the annual average weight 

percent organic HAP in the stored liquid 

is above or below 4 percent for a storage 

vessel at an existing source or above or 

below 2 percent for a storage vessel at 

a new source, an appropriate method 

(based on the type of liquid stored) as 

published by EPA or a consensus-based 

standards organization shall be used. 

Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street NW., 6th floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http://

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http://

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.naesb.org). 

* * * * * 


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■ 20. Section 63.647 is amended by: 

■ a. Revising paragraph (a); 

■ b. Redesignating paragraph (c) as 

paragraph (d); and 

■ c. Adding paragraph (c). 

The revisions and additions read as 

follows: 

§ 63.647 Wastewater provisions. 

(a) Except as provided in paragraphs 

(b) and (c) of this section, each owner 

or operator of a Group 1 wastewater 

stream shall comply with the 

requirements of §§ 61.340 through 

61.355 of this chapter for each process 

wastewater stream that meets the 

definition in § 63.641. 

* * * * * 

(c) If a flare is used as a control 

device, on and after January 30, 2019, 

the flare shall meet the requirements of 

§ 63.670. Prior to January 30, 2019, the 

flare shall meet the applicable 

requirements of part 61, subpart FF of 

this chapter, or the requirements of 

§ 63.670. 

* * * * * 

■ 21. Section 63.648 is amended by: 

■ a. Adding paragraph (a)(3); 

■ b. Revising paragraph (c) introductory 

text; and 

■ c. Adding paragraphs (c)(11) and (12) 

and (j). 

The revisions and additions read as 

follows: 

§ 63.648 Equipment leak standards. 

(a) * * * 

(3) If a flare is used as a control 

device, on and after January 30, 2019, 

the flare shall meet the requirements of 

§ 63.670. Prior to January 30, 2019, the 

flare shall meet the applicable 

requirements of part 60, subpart VV of 

this chapter, or the requirements of 

§ 63.670. 

* * * * * 

(c) In lieu of complying with the 

existing source provisions of paragraph 

(a) in this section, an owner or operator 

may elect to comply with the 

requirements of §§ 63.161 through 

63.169, 63.171, 63.172, 63.175, 63.176, 

63.177, 63.179, and 63.180 of subpart H 

except as provided in paragraphs (c)(1) 

through (12) and (e) through (i) of this 

section. 

* * * * * 

(11) [Reserved] 

(12) If a flare is used as a control 

device, on and after January 30, 2019, 

the flare shall meet the requirements of 

§ 63.670. Prior to January 30, 2019, the 

flare shall meet the applicable 

requirements of §§ 63.172 and 63.180, or 

the requirements of § 63.670. 

* * * * * 

(j) Except as specified in paragraph 

(j)(4) of this section, the owner or 

operator must comply with the 

requirements specified in paragraphs 

(j)(1) and (2) of this section for pressure 

relief devices, such as relief valves or 

rupture disks, in organic HAP gas or 

vapor service instead of the pressure 

relief device requirements of § 60.482–4 

or § 63.165, as applicable. Except as 

specified in paragraphs (j)(4) and (5) of 

this section, the owner or operator must 

also comply with the requirements 

specified in paragraph (j)(3) of this 

section for all pressure relief devices. 

(1) Operating requirements. Except 

during a pressure release, operate each 

pressure relief device in organic HAP 

gas or vapor service with an instrument 

reading of less than 500 ppm above 

background as detected by Method 21 of 

40 CFR part 60, appendix A–7. 

(2) Pressure release requirements. For 

pressure relief devices in organic HAP 

gas or vapor service, the owner or 

operator must comply with the 

applicable requirements in paragraphs 

(j)(2)(i) through (iii) of this section 

following a pressure release. 

(i) If the pressure relief device does 

not consist of or include a rupture disk, 

conduct instrument monitoring, as 

specified in § 60.485(b) or § 63.180(c), as 

applicable, no later than 5 calendar days 

after the pressure relief device returns to 

organic HAP gas or vapor service 

following a pressure release to verify 

that the pressure relief device is 

operating with an instrument reading of 

less than 500 ppm. 

(ii) If the pressure relief device 

includes a rupture disk, either comply 

with the requirements in paragraph 

(j)(2)(i) of this section (not replacing the 

rupture disk) or install a replacement 

disk as soon as practicable after a 

pressure release, but no later than 5 

calendar days after the pressure release. 

The owner or operator must conduct 

instrument monitoring, as specified in 

§ 60.485(b) or § 63.180(c), as applicable, 

no later than 5 calendar days after the 

pressure relief device returns to organic 

HAP gas or vapor service following a 

pressure release to verify that the 

pressure relief device is operating with 

an instrument reading of less than 500 

ppm. 

(iii) If the pressure relief device 

consists only of a rupture disk, install a 

replacement disk as soon as practicable 

after a pressure release, but no later than 

5 calendar days after the pressure 

release. The owner or operator may not 

initiate startup of the equipment served 

by the rupture disk until the rupture 

disc is replaced. The owner or operator 

must conduct instrument monitoring, as 

specified in § 60.485(b) or § 63.180(c), as 

applicable, no later than 5 calendar days 

after the pressure relief device returns to 

organic HAP gas or vapor service 

following a pressure release to verify 

that the pressure relief device is 

operating with an instrument reading of 

less than 500 ppm. 

(3) Pressure release management. 

Except as specified in paragraphs (j)(4) 

and (5) of this section, the owner or 

operator shall comply with the 

requirements specified in paragraphs 

(j)(3)(i) through (v) of this section for all 

pressure relief devices in organic HAP 

service no later than January 30, 2019. 

(i) The owner or operator must equip 

each affected pressure relief device with 

a device(s) or use a monitoring system 

that is capable of: 

(A) Identifying the pressure release; 

(B) Recording the time and duration 

of each pressure release; and 

(C) Notifying operators immediately 

that a pressure release is occurring. The 

device or monitoring system may be 

either specific to the pressure relief 

device itself or may be associated with 

the process system or piping, sufficient 

to indicate a pressure release to the 

atmosphere. Examples of these types of 

devices and systems include, but are not 

limited to, a rupture disk indicator, 

magnetic sensor, motion detector on the 

pressure relief valve stem, flow monitor, 

or pressure monitor. 

(ii) The owner or operator must apply 

at least three redundant prevention 

measures to each affected pressure relief 

device and document these measures. 

Examples of prevention measures 

include: 

(A) Flow, temperature, level and 

pressure indicators with deadman 

switches, monitors, or automatic 

actuators. 

(B) Documented routine inspection 

and maintenance programs and/or 

operator training (maintenance 

programs and operator training may 

count as only one redundant prevention 

measure). 

(C) Inherently safer designs or safety 

instrumentation systems. 

(D) Deluge systems. 

(E) Staged relief system where initial 

pressure relief valve (with lower set 

release pressure) discharges to a flare or 

other closed vent system and control 

device. 

(iii) If any affected pressure relief 

device releases to atmosphere as a result 

of a pressure release event, the owner or 

operator must perform root cause 

analysis and corrective action analysis 

according to the requirement in 

paragraph (j)(6) of this section and 

implement corrective actions according 

to the requirements in paragraph (j)(7) of 

this section. The owner or operator must 

also calculate the quantity of organic 

HAP released during each pressure 


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release event and report this quantity as 

required in § 63.655(g)(10)(iii). 

Calculations may be based on data from 

the pressure relief device monitoring 

alone or in combination with process 

parameter monitoring data and process 

knowledge. 

(iv) The owner or operator shall 

determine the total number of release 

events occurred during the calendar 

year for each affected pressure relief 

device separately. The owner or 

operator shall also determine the total 

number of release events for each 

pressure relief device for which the root 

cause analysis concluded that the root 

cause was a force majeureevent, 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. 

(B) A second release event not 

including force majeure events from a 

single pressure relief device in a 3 

calendar year period for the same root 

cause for the same equipment. 

(C) A third release event not including 

force majeure events from a single 

pressure relief device in a 3 calendar 

year period for any reason. 

(4) Pressure relief devices routed to a 

control device. If all releases and 

potential leaks from a pressure relief 

device are routed through a closed vent 

system to a control device, back into the 

process or to the fuel gas system, the 

owner or operator is not required to 

comply with paragraph (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 (j)(4), all 

references to ‘‘Group 1 miscellaneous 

process vent’’ in § 63.644 mean 

‘‘pressure relief device.’’ If a pressure 

relief device complying with this 

paragraph (j)(4) is routed to the fuel gas 

system, then on and after January 30, 

2019, 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) of this 

section. 

(i) Pressure relief devices in heavy 

liquid service, as defined in § 63.641. 

(ii) Pressure relief devices that only 

release material that is liquid at 

standard conditions (1 atmosphere and 

68 degrees Fahrenheit) and that are 

hard-piped to a controlled drain system 

(i.e., a drain system meeting the 

requirements for Group 1 wastewater 

streams in § 63.647(a)) or piped back to 

the process or pipeline. 

(iii) Thermal expansion relief valves. 

(iv) Pressure relief devices designed 

with a set relief pressure of less than 2.5 

psig. 

(v) Pressure relief devices that do not 

have the potential to emit 72 lbs/day or 

more of VOC based on the valve 

diameter, the set release pressure, and 

the equipment contents. 

(vi) Pressure relief devices on mobile 

equipment. 

(6) Root cause analysis and corrective 

action analysis. A root cause analysis 

and corrective action analysis must be 

completed as soon as possible, but no 

later than 45 days after a release event. 

Special circumstances affecting the 

number of root cause analyses and/or 

corrective action analyses are provided 

in paragraphs (j)(6)(i) through (iv) of this 

section. 

(i) You may conduct a single root 

cause analysis and corrective action 

analysis for a single emergency event 

that causes two or more pressure relief 

devices installed on the same 

equipment to release. 

(ii) You may conduct a single root 

cause analysis and corrective action 

analysis for a single emergency event 

that causes two or more pressure relief 

devices to release, regardless of the 

equipment served, if the root cause is 

reasonably expected to be a force 

majeure event, as defined in this 

subpart. 

(iii) Except as provided in paragraphs 

(j)(6)(i) and (ii) of this section, if more 

than one pressure relief device has a 

release during the same time period, an 

initial root cause analysis shall be 

conducted separately for each pressure 

relief device that had a release. If the 

initial root cause analysis indicates that 

the release events have the same root 

cause(s), the initially separate root cause 

analyses may be recorded as a single 

root cause analysis and a single 

corrective action analysis may be 

conducted. 

(7) Corrective action implementation. 

Each owner or operator required to 

conduct a root cause analysis and 

corrective action analysis as specified in 

paragraphs (j)(3)(iii) and (j)(6) of this 

section shall implement the corrective 

action(s) identified in the corrective 

action analysis in accordance with the 

applicable requirements in paragraphs 

(j)(7)(i) through (iii) of this section. 

(i) All corrective action(s) must be 

implemented within 45 days of the 

event for which the root cause and 

corrective action analyses were required 

or as soon thereafter as practicable. If an 

owner or operator concludes that no 

corrective action should be 

implemented, the owner or operator 

shall record and explain the basis for 

that conclusion no later than 45 days 

following the event. 

(ii) For corrective actions that cannot 

be fully implemented within 45 days 

following the event for which the root 

cause and corrective action analyses 

were required, the owner or operator 

shall develop an implementation 

schedule to complete the corrective 

action(s) as soon as practicable. 

(iii) No later than 45 days following 

the event for which a root cause and 

corrective action analyses were 

required, the owner or operator shall 

record the corrective action(s) 

completed to date, and, for action(s) not 

already completed, a schedule for 

implementation, including proposed 

commencement and completion dates. 

■ 22. Section 63.649 is amended by 

revising definition of Cc term in the 

equation in paragraph (c)(6)(i) to read as 

follows: 

§ 63.649 Alternative means of emission 

limitation: Connectors in gas/vapor service 

and light liquid service. 

* * * * * 

(c) * * * 

(6) * * * 

(i) * * * 

Cc = Optional credit for removed connectors 

= 0.67 × net number (i.e., the total 

number of connectors removed minus 

the total added) of connectors in organic 

HAP service removed from the process 

unit after the applicability date set forth 

in § 63.640(h)(3)(iii) for existing process 

units, and after the date of start-up for 

new process units. If credits are not 

taken, then Cc = 0. 

* * * * * 

■ 23. Section 63.650 is amended by 

revising paragraph (a) and adding 

paragraph (d) to read as follows: 

§ 63.650 Gasoline loading rack provisions. 

(a) Except as provided in paragraphs 

(b) through (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 of this part, §§ 63.421, 

63.422(a) through (c) and (e), 63.425(a) 

through (c) and (e) through (i), 63.427(a) 

and (b), and 63.428(b), (c), (g)(1), (h)(1) 

through (3), and (k). 

* * * * * 


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(d) If a flare is used as a control 

device, on and after January 30, 2019, 

the flare shall meet the requirements of 

§ 63.670. Prior to January 30, 2019, the 

flare shall meet the applicable 

requirements of subpart R of this part, 

or the requirements of § 63.670. 

■ 24. Section 63.651 is amended by 

revising paragraphs (a) and (d) and 

adding paragraph (e) to read as follows: 

§ 63.651 Marine tank vessel loading 

operation provisions. 

(a) Except as provided in paragraphs 

(b) through (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. 

* * * * * 

(d) The compliance time of 4 years 

after promulgation of 40 CFR part 63, 

subpart Y, does not apply. The 

compliance time is specified in 

§ 63.640(h)(1). 

(e) If a flare is used as a control 

device, on and after January 30, 2019, 

the flare shall meet the requirements of 

§ 63.670. Prior to January 30, 2019, the 

flare shall meet the applicable 

requirements of subpart Y of this part, 

or the requirements of § 63.670. 

■ 25. Section 63.652 is amended by: 

■ a. Revising paragraph (a); 

■ b. Removing and reserving paragraph 

(f)(2); and 

■ c. Revising paragraphs (g)(2)(iii)(B)(1), 

(h)(3), (k) introductory text, and (k)(3). 

The revisions and additions read as 

follows: 

§ 63.652 Emissions averaging provisions. 

(a) This section applies to owners or 

operators of existing sources who seek 

to comply with the emission standard in 

§ 63.642(g) by using emissions averaging 

according to § 63.642(l) rather than 

following the provisions of §§ 63.643 

through 63.645, 63.646 or 63.660, 

63.647, 63.650, and 63.651. Existing 

marine tank vessel loading operations 

located at the Valdez Marine Terminal 

source may not comply with the 

standard by using emissions averaging. 

* * * * * 

(g) * * * 

(2) * * * 

(iii) * * * 

(B) * * * 

(1) The percent reduction shall be 

measured according to the procedures 

in § 63.116 of subpart G if a combustion 

control device is used. For a flare 

meeting the criteria in § 63.116(a) of 

subpart G or § 63.670, as applicable, or 

a boiler or process heater meeting the 

criteria in § 63.645(d) 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. 

* * * * * 

(h) * * * 

(3) Emissions from storage vessels 

shall be determined as specified in 

§ 63.150(h)(3) of subpart G, except as 

follows: 

(i) For storage vessels complying with 

§ 63.646: 

(A) All references to § 63.119(b) in 

§ 63.150(h)(3) of subpart G shall be 

replaced with: § 63.119(b) or § 63.119(b) 

except for § 63.119(b)(5) and (6). 

(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). 

(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) Section 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) Section 63.1063(a)(1)(ii), (a)(2), 

and (b) shall apply instead of § 63.119(c) 

in § 63.150(h)(3) of subpart G. 

(C) Section 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. 

* * * * * 

(k) The owner or operator shall 

demonstrate that the emissions from the 

emission points proposed to be 

included in the average will not result 

in greater hazard or, at the option of the 

State or local permitting authority, 

greater risk to human health or the 

environment than if the emission points 

were controlled according to the 

provisions in §§ 63.643 through 63.645, 

63.646 or 63.660, 63.647, 63.650, and 

63.651, as applicable. 

* * * * * 

(3) An emissions averaging plan that 

does not demonstrate an equivalent or 

lower hazard or risk to the satisfaction 

of the State or local permitting authority 

shall not be approved. The State or local 

permitting authority may require such 

adjustments to the emissions averaging 

plan as are necessary in order to ensure 

that the average will not result in greater 

hazard or risk to human health or the 

environment than would result if the 

emission points were controlled 

according to §§ 63.643 through 63.645, 

63.646 or 63.660, 63.647, 63.650, and 

63.651, as applicable. 

* * * * * 

■ 26. Section 63.653 is amended by 

revising paragraphs (a) introductory 

text, (a)(3)(i) and (ii), and (a)(7) to read 

as follows: 

§ 63.653 Monitoring, recordkeeping, and 

implementation plan for emissions 

averaging. 

(a) For each emission point included 

in an emissions average, the owner or 

operator shall perform testing, 

monitoring, recordkeeping, and 

reporting equivalent to that required for 

Group 1 emission points complying 

with §§ 63.643 through 63.645, 63.646 

or 63.660, 63.647, 63.650, and 63.651, as 

applicable. The specific requirements 

for miscellaneous process vents, storage 

vessels, wastewater, gasoline loading 

racks, and marine tank vessels are 

identified in paragraphs (a)(1) through 

(7) of this section. 

* * * * * 

(3) * * * 

(i) Perform the monitoring or 

inspection procedures in § 63.646 and 

either § 63.120 of subpart G or § 63.1063 

of subpart WW, as applicable; and 

(ii) For closed vent systems with 

control devices, conduct an initial 

design evaluation as specified in 

§ 63.646 and either § 63.120(d) of 

subpart G or § 63.985(b) of subpart SS, 

as applicable. 

* * * * * 

(7) If an emission point in an 

emissions average is controlled using a 

pollution prevention measure or a 

device or technique for which no 

monitoring parameters or inspection 

procedures are specified in §§ 63.643 

through 63.645, 63.646 or 63.660, 

63.647, 63.650, and 63.651, as 

applicable, the owner or operator shall 

establish a site-specific monitoring 

parameter and shall submit the 

information specified in § 63.655(h)(4) 

in the Implementation Plan. 

* * * * * 

■ 27. Section 63.655 is amended by: 

■ a. Revising paragraphs (f) introductory 

text, (f)(1) introductory text, (f)(1)(i)(A) 

introductory text, (f)(1)(i)(A)(2) and (3), 

(f)(1)(i)(B) introductory text, 

(f)(1)(i)(B)(2), (f)(1)(i)(D)(2), (f)(1)(iv) 

introductory text, and (f)(1)(iv)(A); 

■ b. Adding paragraphs (f)(1)(vii) and 

(viii); 

■ c. Revising paragraphs (f)(2) 

introductory text, (f)(3) introductory 

text, the first sentence of (f)(6), (g) 

introductory text, (g)(1) through (5), 

(g)(6)(i)(D), (g)(6)(iii), and (g)(7)(i); 


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■ d. Adding paragraphs (g)(10) through 

(14); 

■ e. Removing and reserving paragraph 

(h)(1); 

■ f. Revising paragraphs (h)(2) 

introductory text, (h)(2)(i)(B), (h)(2)(ii), 

and (h)(5)(iii); 

■ g. Adding paragraphs (h)(8) and (9) 

and (i) introductory text; 

■ h. Revising paragraph (i)(1) 

introductory text and paragraph 

(i)(1)(ii); 

■ i. Adding paragraphs (i)(1)(v) and (vi); 

■ j. Redesignating paragraphs (i)(4) and 

(5) as paragraphs (i)(5) and (6), 

respectively; 

■ k. Adding paragraph (i)(4); 

■ l. Revising newly redesignated 

paragraph (i)(5) introductory text; and 

■ m. Adding paragraphs (i)(7) through 

(12). 

The revisions and additions read as 

follows: 

§ 63.655 Reporting and recordkeeping 

requirements. 

* * * * * 

(f) Each owner or operator of a source 

subject to this subpart shall submit a 

Notification of Compliance Status report 

within 150 days after the compliance 

dates specified in § 63.640(h) with the 

exception of Notification of Compliance 

Status reports submitted to comply with 

§ 63.640(l)(3) and for storage vessels 

subject to the compliance schedule 

specified in § 63.640(h)(2). Notification 

of Compliance Status reports required 

by § 63.640(l)(3) and for storage vessels 

subject to the compliance dates 

specified in § 63.640(h)(2) shall be 

submitted according to paragraph (f)(6) 

of this section. This information may be 

submitted in an operating permit 

application, in an amendment to an 

operating permit application, in a 

separate submittal, or in any 

combination of the three. If the required 

information has been submitted before 

the date 150 days after the compliance 

date specified in § 63.640(h), a separate 

Notification of Compliance Status report 

is not required within 150 days after the 

compliance dates specified in 

§ 63.640(h). If an owner or operator 

submits the information specified in 

paragraphs (f)(1) through (5) of this 

section at different times, and/or in 

different submittals, later submittals 

may refer to earlier submittals instead of 

duplicating and resubmitting the 

previously submitted information. Each 

owner or operator of a gasoline loading 

rack classified under Standard 

Industrial Classification Code 2911 

located within a contiguous area and 

under common control with a 

petroleum refinery subject to the 

standards of this subpart shall submit 

the Notification of Compliance Status 

report required by subpart R of this part 

within 150 days after the compliance 

dates specified in § 63.640(h). 

(1) The Notification of Compliance 

Status report shall include the 

information specified in paragraphs 

(f)(1)(i) through (viii) of this section. 

(i) * * * 

(A) Identification of each storage 

vessel subject to this subpart, and for 

each Group 1 storage vessel subject to 

this subpart, the information specified 

in paragraphs (f)(1)(i)(A)(1) through (3) 

of this section. This information is to be 

revised each time a Notification of 

Compliance Status report is submitted 

for a storage vessel subject to the 

compliance schedule specified in 

§ 63.640(h)(2) or to comply with 

§ 63.640(l)(3). 

* * * * * 

(2) For storage vessels subject to the 

compliance schedule specified in 

§ 63.640(h)(2) that are not complying 

with § 63.646, the anticipated 

compliance date. 

(3) For storage vessels subject to the 

compliance schedule specified in 

§ 63.640(h)(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 operator shall submit: 

* * * * * 

(2) The design evaluation 

documentation specified in 

§ 63.120(d)(1)(i) of subpart G or 

§ 63.985(b)(1)(i) of subpart SS (as 

applicable), if the owner or operator 

elects to prepare a design evaluation; or 

* * * * * 

(D) * * * 

(2) All visible emission readings, heat 

content determinations, flow rate 

measurements, and exit velocity 

determinations made during the 

compliance determination required by 

§ 63.120(e) of subpart G or § 63.987(b) of 

subpart SS or § 63.670(h), as applicable; 

and 

* * * * * 

(iv) For miscellaneous process vents 

controlled by flares, initial compliance 

test results including the information in 

paragraphs (f)(1)(iv)(A) and (B) of this 

section. 

(A) All visible emission readings, heat 

content determinations, flow rate 

measurements, and exit velocity 

determinations made during the 

compliance determination required by 

§§ 63.645 and 63.116(a) of subpart G or 

§ 63.670(h), as applicable; and 

* * * * * 

(vii) For pressure relief devices in 

organic HAP service subject to the 

requirements in § 63.648(j)(3)(i) and (ii), 

this report shall include the information 

specified in paragraphs (f)(1)(vii)(A) and 

(B) of this section. 

(A) A description of the monitoring 

system to be implemented, including 

the relief devices and process 

parameters to be monitored, and a 

description of the alarms or other 

methods by which operators will be 

notified of a pressure release. 

(B) A description of the prevention 

measures to be implemented for each 

affected pressure relief device. 

(viii) For each delayed coking unit, 

identification of whether the unit is an 

existing affected source or a new 

affected source and whether monitoring 

will be conducted as specified in 

§ 63.657(b) or (c). 

(2) If initial performance tests are 

required by §§ 63.643 through 63.653, 

the Notification of Compliance Status 

report shall include one complete test 

report for each test method used for a 

particular source. On and after February 

1, 2016, performance tests shall be 

submitted according to paragraph (h)(9) 

of this section. 

* * * * * 

(3) For each monitored parameter for 

which a range is required to be 

established under § 63.120(d) of subpart 

G or § 63.985(b) of subpart SS for storage 

vessels or § 63.644 for miscellaneous 

process vents, the Notification of 

Compliance Status report shall include 

the information in paragraphs (f)(3)(i) 

through (iii) of this section. 

* * * * * 

(6) Notification of Compliance Status 

reports required by § 63.640(l)(3) and for 

storage vessels subject to the 

compliance dates specified in 

§ 63.640(h)(2) shall be submitted no 

later than 60 days after the end of the 

6-month period during which the 

change or addition was made that 

resulted in the Group 1 emission point 

or the existing Group 1 storage vessel 

was brought into compliance, and may 

be combined with the periodic 

report. * * * 

(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 information specified 

in paragraphs (g)(1) through (7) of this 

section or paragraphs (g)(9) through (14) 

of this section 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 

events identified in paragraphs (g)(1) 


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through (7) of this section or paragraphs 

(g)(9) through (14) of this section 

occurred during the 6-month period 

unless emissions averaging is utilized. 

Quarterly reports must be submitted for 

emission points included in emission 

averages, as provided in paragraph (g)(8) 

of this section. An owner or operator 

may submit reports required by other 

regulations in place of or as part of the 

Periodic Report required by this 

paragraph (g) if the reports contain the 

information required by paragraphs 

(g)(1) through (14) of this section. 

(1) For storage vessels, Periodic 

Reports shall include the information 

specified for Periodic Reports in 

paragraphs (g)(2) through (5) of this 

section. Information related to gaskets, 

slotted membranes, and sleeve seals is 

not required for storage vessels that are 

part of an existing source complying 

with § 63.646. 

(2) Internal floating roofs. (i) An 

owner or operator who elects to comply 

with § 63.646 by using a fixed roof and 

an internal floating roof or by using an 

external floating roof converted to an 

internal floating roof shall submit the 

results of each inspection conducted in 

accordance with § 63.120(a) of subpart G 

in which a failure is detected in the 

control equipment. 

(A) For vessels for which annual 

inspections are required under 

§ 63.120(a)(2)(i) or (a)(3)(ii) of subpart G, 

the specifications and requirements 

listed in paragraphs (g)(2)(i)(A)(1) 

through (3) of this section apply. 

(1) A failure is defined as any time in 

which the internal floating roof is not 

resting on the surface of the liquid 

inside the storage vessel and is not 

resting on the leg supports; or there is 

liquid on the floating roof; or the seal is 

detached from the internal floating roof; 

or there are holes, tears, or other 

openings in the seal or seal fabric; or 

there are visible gaps between the seal 

and the wall of the storage vessel. 

(2) Except as provided in paragraph 

(g)(2)(i)(A)(3) of this section, each 

Periodic Report shall include the date of 

the inspection, identification of each 

storage vessel in which a failure was 

detected, and a description of the 

failure. The Periodic Report shall also 

describe the nature of and date the 

repair was made or the date the storage 

vessel was emptied. 

(3) If an extension is utilized in 

accordance with § 63.120(a)(4) of 

subpart G, the owner or operator shall, 

in the next Periodic Report, identify the 

vessel; include the documentation 

specified in § 63.120(a)(4) of subpart G; 

and describe the date the storage vessel 

was emptied and the nature of and date 

the repair was made. 

(B) For vessels for which inspections 

are required under § 63.120(a)(2)(ii), 

(a)(3)(i), or (a)(3)(iii) of subpart G (i.e., 

internal inspections), the specifications 

and requirements listed in paragraphs 

(g)(2)(i)(B)(1) and (2) of this section 

apply. 

(1) A failure is defined as any time in 

which the internal floating roof has 

defects; or the primary seal has holes, 

tears, or other openings in the seal or 

the seal fabric; or the secondary seal (if 

one has been installed) has holes, tears, 

or other openings in the seal or the seal 

fabric; or, for a storage vessel that is part 

of a new source, the gaskets no longer 

close off the liquid surface from the 

atmosphere; or, for a storage vessel that 

is part of a new source, the slotted 

membrane has more than a 10 percent 

open. 

(2) Each Periodic Report shall include 

the date of the inspection, identification 

of each storage vessel in which a failure 

was detected, and a description of the 

failure. The Periodic Report shall also 

describe the nature of and date the 

repair was made. 

(ii) An owner or operator who elects 

to comply with § 63.660 by using a fixed 

roof and an internal floating roof shall 

submit the results of each inspection 

conducted in accordance with 

§ 63.1063(c)(1), (d)(1), and (d)(2) of 

subpart WW in which a failure is 

detected in the control equipment. For 

vessels for which inspections are 

required under § 63.1063(c) and (d), the 

specifications and requirements listed 

in paragraphs (g)(2)(ii)(A) through (C) of 

this section apply. 

(A) A failure is defined in 

§ 63.1063(d)(1) of subpart WW. 

(B) Each Periodic Report shall include 

a copy of the inspection record required 

by § 63.1065(b) of subpart WW when a 

failure occurs. 

(C) An owner or operator who elects 

to use an extension in accordance with 

§ 63.1063(e)(2) of subpart WW shall, in 

the next Periodic Report, submit the 

documentation required by 

§ 63.1063(e)(2). 

(3) External floating roofs. (i) An 

owner or operator who elects to comply 

with § 63.646 by using an external 

floating roof shall meet the periodic 

reporting requirements specified in 

paragraphs (g)(3)(i)(A) through (C) of 

this section. 

(A) The owner or operator shall 

submit, as part of the Periodic Report, 

documentation of the results of each 

seal gap measurement made in 

accordance with § 63.120(b) of subpart 

G in which the seal and seal gap 

requirements of § 63.120(b)(3), (4), (5), 

or (6) of subpart G are not met. This 

documentation shall include the 

information specified in paragraphs 

(g)(3)(i)(A)(1) through (4) of this section. 

(1) The date of the seal gap 

measurement. 

(2) The raw data obtained in the seal 

gap measurement and the calculations 

described in § 63.120(b)(3) and (4) of 

subpart G. 

(3) A description of any seal condition 

specified in § 63.120(b)(5) or (6) of 

subpart G that is not met. 

(4) A description of the nature of and 

date the repair was made, or the date the 

storage vessel was emptied. 

(B) If an extension is utilized in 

accordance with § 63.120(b)(7)(ii) or 

(b)(8) of subpart G, the owner or 

operator shall, in the next Periodic 

Report, identify the vessel; include the 

documentation specified in 

§ 63.120(b)(7)(ii) or (b)(8) of subpart G, 

as applicable; and describe the date the 

vessel was emptied and the nature of 

and date the repair was made. 

(C) The owner or operator shall 

submit, as part of the Periodic Report, 

documentation of any failures that are 

identified during visual inspections 

required by § 63.120(b)(10) of subpart G. 

This documentation shall meet the 

specifications and requirements in 

paragraphs (g)(3)(i)(C)(1) and (2) of this 

section. 

(1) A failure is defined as any time in 

which the external floating roof has 

defects; or the primary seal has holes or 

other openings in the seal or the seal 

fabric; or the secondary seal has holes, 

tears, or other openings in the seal or 

the seal fabric; or, for a storage vessel 

that is part of a new source, the gaskets 

no longer close off the liquid surface 

from the atmosphere; or, for a storage 

vessel that is part of a new source, the 

slotted membrane has more than 10 

percent open area. 

(2) Each Periodic Report shall include 

the date of the inspection, identification 

of each storage vessel in which a failure 

was detected, and a description of the 

failure. The Periodic Report shall also 

describe the nature of and date the 

repair was made. 

(ii) An owner or operator who elects 

to comply with § 63.660 by using an 

external floating roof shall meet the 

periodic reporting requirements 

specified in paragraphs (g)(3)(ii)(A) and 

(B) of this section. 

(A) For vessels for which inspections 

are required under § 63.1063(c)(2), 

(d)(1), and (d)(3) of subpart WW, the 

owner or operator shall submit, as part 

of the Periodic Report, a copy of the 

inspection record required by 

§ 63.1065(b) of subpart WW when a 

failure occurs. A failure is defined in 

§ 63.1063(d)(1). 


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(B) An owner or operator who elects 

to use an extension in accordance with 

§ 63.1063(e)(2) or (c)(2)(iv)(B) of subpart 

WW shall, in the next Periodic Report, 

submit the documentation required by 

those paragraphs. 

(4) [Reserved] 

(5) An owner or operator who elects 

to comply with § 63.646 or § 63.660 by 

installing a closed vent system and 

control device shall submit, as part of 

the next Periodic Report, the 

information specified in paragraphs 

(g)(5)(i) through (v) of this section, as 

applicable. 

(i) The Periodic Report shall include 

the information specified in paragraphs 

(g)(5)(i)(A) and (B) of this section for 

those planned routine maintenance 

operations that would require the 

control device not to meet the 

requirements of either § 63.119(e)(1) or 

(2) of subpart G, § 63.985(a) and (b) of 

subpart SS, or § 63.670, as applicable. 

(A) A description of the planned 

routine maintenance that is anticipated 

to be performed for the control device 

during the next 6 months. This 

description shall include the type of 

maintenance necessary, planned 

frequency of maintenance, and lengths 

of maintenance periods. 

(B) A description of the planned 

routine maintenance that was performed 

for the control device during the 

previous 6 months. This description 

shall include the type of maintenance 

performed and the total number of 

hours during those 6 months that the 

control device did not meet the 

requirements of either § 63.119(e)(1) or 

(2) of subpart G, § 63.985(a) and (b) of 

subpart SS, or § 63.670, as applicable, 

due to planned routine maintenance. 

(ii) If a control device other than a 

flare is used, the Periodic Report shall 

describe each occurrence when the 

monitored parameters were outside of 

the parameter ranges documented in the 

Notification of Compliance Status 

report. The description shall include: 

Identification of the control device for 

which the measured parameters were 

outside of the established ranges, and 

causes for the measured parameters to 

be outside of the established ranges. 

(iii) If a flare is used prior to January 

30, 2019 and prior to electing to comply 

with the requirements in § 63.670, the 

Periodic Report shall describe each 

occurrence when the flare does not meet 

the general control device requirements 

specified in § 63.11(b) of subpart A and 

shall include: Identification of the flare 

that does not meet the general 

requirements specified in § 63.11(b) of 

subpart A, and reasons the flare did not 

meet the general requirements specified 

in § 63.11(b) of subpart A. 

(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 January 30, 

2019, the Periodic Report shall include 

the items specified in paragraph (g)(11) 

of this section. 

(v) An owner or operator who elects 

to comply with § 63.660 by installing an 

alternate control device as described in 

§ 63.1064 of subpart WW shall submit, 

as part of the next Periodic Report, a 

written application as described in 

§ 63.1066(b)(3) of subpart WW. 

(6) * * * 

(i) * * * 

(D) For data compression systems 

under paragraph (h)(5)(iii) of this 

section, an operating day when the 

monitor operated for less than 75 

percent of the operating hours or a day 

when less than 18 monitoring values 

were recorded. 

* * * * * 

(iii) For periods in closed vent 

systems when a Group 1 miscellaneous 

process vent stream was detected in the 

bypass line or diverted from the control 

device and either directly to the 

atmosphere or to a control device that 

does not comply with the requirements 

in § 63.643(a), report the date, time, 

duration, estimate of the volume of gas, 

the concentration of organic HAP in the 

gas and the resulting mass emissions of 

organic HAP that bypassed the control 

device. For periods when the flow 

indicator is not operating, report the 

date, time, and duration. 

(7) * * * 

(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. 

* * * * * 

(10) For pressure relief devices subject 

to the requirements § 63.648(j), Periodic 

Reports must include the information 

specified in paragraphs (g)(10)(i) 

through (iii) of this section. 

(i) For pressure relief devices in 

organic HAP gas or vapor service, 

pursuant to § 63.648(j)(1), report any 

instrument reading of 500 ppm or 

greater. 

(ii) For pressure relief devices in 

organic HAP gas or vapor service subject 

to § 63.648(j)(2), report confirmation 

that any monitoring required to be done 

during the reporting period to show 

compliance was conducted. 

(iii) For pressure relief devices in 

organic HAP service subject to 

§ 63.648(j)(3), report each pressure 

release to the atmosphere, including 

duration of the pressure release and 

estimate of the mass quantity of each 

organic HAP released, and the results of 

any root cause analysis and corrective 

action analysis completed during the 

reporting period, including the 

corrective actions implemented during 

the reporting period and, if applicable, 

the implementation schedule for 

planned corrective actions to be 

implemented subsequent to the 

reporting period. 

(11) For flares subject to § 63.670, 

Periodic Reports must include the 

information specified in paragraphs 

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

(i) Records as specified in paragraph 

(i)(9)(i) of this section for each 15- 

minute block during which there was at 

least one minute when regulated 

material is routed to a flare and no pilot 

flame is present. 

(ii) Visible emission records as 

specified in paragraph (i)(9)(ii)(C) of this 

section for each period of 2 consecutive 

hours during which visible emissions 

exceeded a total of 5 minutes. 

(iii) The 15-minute block periods for 

which the applicable operating limits 

specified in § 63.670(d) through (f) are 

not met. Indicate the date and time for 

the period, the net heating value 

operating parameter(s) determined 

following the methods in § 63.670(k) 

through (n) as applicable. 

(iv) For flaring events meeting the 

criteria in § 63.670(o)(3): 

(A) The start and stop time and date 

of the flaring event. 

(B) The length of time for which 

emissions were visible from the flare 

during the event. 

(C) The periods of time that the flare 

tip velocity exceeds the maximum flare 

tip velocity determined using the 

methods in § 63.670(d)(2) and the 

maximum 15-minute block average flare 

tip velocity recorded during the event. 

(D) Results of the root cause and 

corrective actions analysis completed 

during the reporting period, including 

the corrective actions implemented 

during the reporting period and, if 

applicable, the implementation 

schedule for planned corrective actions 

to be implemented subsequent to the 

reporting period. 

(12) For delayed coking units, the 

Periodic Report must include the 

information specified in paragraphs 

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

(i) For existing source delayed coking 

units, any 60-cycle average exceeding 

the applicable limit in § 63.657(a)(1). 

(ii) For new source delayed coking 

units, any direct venting event 


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exceeding the applicable limit in 

§ 63.657(a)(2). 

(iii) The total number of double 

quenching events performed during the 

reporting period. 

(iv) For each double quenching 

draining event when the drain water 

temperature exceeded 210 °F, report the 

drum, date, time, the coke drum vessel 

pressure or temperature, as applicable, 

when pre-vent draining was initiated, 

and the maximum drain water 

temperature during the pre-vent 

draining period. 

(13) For maintenance vents subject to 

the requirements in § 63.643(c), Periodic 

Reports must include the information 

specified in paragraphs (g)(13)(i) 

through (iv) of this section for any 

release exceeding the applicable limits 

in § 63.643(c)(1). For the purposes of 

this reporting requirement, owners or 

operators complying with 

§ 63.643(c)(1)(iv) must report each 

venting event for which the lower 

explosive limit is 20 percent or greater. 

(i) Identification of the maintenance 

vent and the equipment served by the 

maintenance vent. 

(ii) The date and time the 

maintenance vent was opened to the 

atmosphere. 

(iii) The lower explosive limit, vessel 

pressure, or mass of VOC in the 

equipment, as applicable, at the start of 

atmospheric venting. If the 5 psig vessel 

pressure option in § 63.643(c)(1)(ii) was 

used and active purging was initiated 

while the lower explosive limit was 10 

percent or greater, also include the 

lower explosive limit of the vapors at 

the time active purging was initiated. 

(iv) An estimate of the mass of organic 

HAP released during the entire 

atmospheric venting event. 

(14) Any changes in the information 

provided in a previous Notification of 

Compliance Status report. 

(h) * * * 

(2) For storage vessels, notifications of 

inspections as specified in paragraphs 

(h)(2)(i) and (ii) of this section. 

(i) * * * 

(B) Except as provided in paragraph 

(h)(2)(i)(C) of this section, if the internal 

inspection required by § 63.120(a)(2), 

(a)(3), or (b)(10) of subpart G 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 advance 

of refilling the vessel with organic HAP, 

the owner or operator shall notify the 

Administrator at least 7 calendar days 

prior to refilling of the storage vessel. 

Notification may be made by telephone 

and immediately followed by written 

documentation demonstrating why the 

inspection was unplanned. This 

notification, including the written 

documentation, may also be made in 

writing and sent so that it is received by 

the Administrator at least 7 calendar 

days prior to the refilling. 

* * * * * 

(ii) In order to afford the 

Administrator the opportunity to have 

an observer present, the owner or 

operator of a storage vessel equipped 

with an external floating roof shall 

notify the Administrator of any seal gap 

measurements. The notification shall be 

made in writing at least 30 calendar 

days in advance of any gap 

measurements required by § 63.120(b)(1) 

or (2) of subpart G or § 63.1062(d)(3) of 

subpart WW. The State or local 

permitting authority can waive this 

notification requirement for all or some 

storage vessels subject to the rule or can 

allow less than 30 calendar days’ notice. 

* * * * * 

(5) * * * 

(iii) An owner or operator may use an 

automated data compression recording 

system that does not record monitored 

operating parameter values at a set 

frequency (for example, once every 

hour) but records all values that meet 

set criteria for variation from previously 

recorded values. 

(A) The system shall be designed to: 

(1) Measure the operating parameter 

value at least once every hour. 

(2) Record at least 24 values each day 

during periods of operation. 

(3) Record the date and time when 

monitors are turned off or on. 

(4) Recognize unchanging data that 

may indicate the monitor is not 

functioning properly, alert the operator, 

and record the incident. 

(5) Compute daily average values of 

the monitored operating parameter 

based on recorded data. 

(B) You must maintain a record of the 

description of the monitoring system 

and data compression recording system 

including the criteria used to determine 

which monitored values are recorded 

and retained, the method for calculating 

daily averages, and a demonstrations 

that they system meets all criteria of 

paragraph (h)(5)(iii)(A) of this section. 

* * * * * 

(8) For fenceline monitoring systems 

subject to § 63.658, within 45 calendar 

days after the end of each quarterly 

reporting period covered by the periodic 

report, each owner or operator shall 

submit the following information to the 

EPA’s Compliance and Emissions Data 

Reporting Interface (CEDRI). (CEDRI can 

be accessed through the EPA’s Central 

Data Exchange (CDX) (https://

cdx.epa.gov/). The owner or operator 

need not transmit this data prior to 

obtaining 12 months of data. 

(i) Individual sample results for each 

monitor for each sampling period 

during the quarterly reporting period. 

For the first reporting period and for any 

period in which a passive monitor is 

added or moved, the owner or operator 

shall report the coordinates of all of the 

passive monitor locations. The owner or 

operator shall determine the coordinates 

using an instrument with an accuracy of 

at least 3 meters. Coordinates shall be in 

decimal degrees with at least five 

decimal places. 

(ii) The biweekly annual average 

concentration difference (Dc) 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 February 1, 2016, if 

required to submit the results of a 

performance test or CEMS performance 

evaluation, the owner or operator shall 

submit the results according to the 

procedures in paragraphs (h)(9)(i) and 

(ii) of this section. 

(i) Within 60 days after the date of 

completing each performance test as 

required by this subpart, the owner or 

operator shall submit the results of the 

performance tests following the 

procedure specified in either paragraph 

(h)(9)(i)(A) or (B) of this section. 

(A) For data collected using test 

methods supported by the EPA’s 

Electronic Reporting Tool (ERT) as 

listed on the EPA’s ERT Web site 

(http://www.epa.gov/ttn/chief/ert/

index.html) at the time of the test, the 

owner or operator must submit the 

results of the performance test to the 

EPA via the CEDRI. (CEDRI can be 

accessed through the EPA’s CDX.) 

Performance test data must be submitted 

in a file format generated through the 

use of the EPA’s ERT or an alternate 

electronic file format consistent with the 

extensible markup language (XML) 

schema listed on the EPA’s ERT Web 

site. If an owner or operator claims that 

some of the performance test 

information being submitted is 

confidential business information (CBI), 

the owner or operator must submit a 

complete file generated through the use 

of the EPA’s ERT or an alternate 

electronic file consistent with the XML 

schema listed on the EPA’s ERT Web 

site, including information claimed to 

be CBI, on a compact disc, flash drive 

or other commonly used electronic 

storage media to the EPA. The electronic 

storage media must be clearly marked as 

CBI and mailed to U.S. EPA/OAQPS/


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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 

(h)(9)(i)(A). 

(B) For data collected using test 

methods that are not supported by the 

EPA’s ERT as listed on the EPA’s ERT 

Web site at the time of the test, the 

owner or operator must submit the 

results of the performance test to the 

Administrator at the appropriate 

address listed in § 63.13. 

(ii) Within 60 days after the date of 

completing each CEMS performance 

evaluation as required by this subpart, 

the owner or operator must submit the 

results of the performance evaluation 

following the procedure specified in 

either paragraph (h)(9)(ii)(A) or (B) of 

this section. 

(A) For performance evaluations of 

continuous monitoring systems 

measuring relative accuracy test audit 

(RATA) pollutants that are supported by 

the EPA’s ERT as listed on the EPA’s 

ERT Web site at the time of the 

evaluation, the owner or operator must 

submit the results of the performance 

evaluation to the EPA via the CEDRI. 

(CEDRI can be accessed through the 

EPA’s CDX.) Performance evaluation 

data must be submitted in a file format 

generated through the use of the EPA’s 

ERT or an alternate file format 

consistent with the XML schema listed 

on the EPA’s ERT Web site. If an owner 

or operator claims that some of the 

performance evaluation information 

being submitted is CBI, the owner or 

operator must submit a complete file 

generated through the use of the EPA’s 

ERT or an alternate electronic file 

consistent with the XML schema listed 

on the EPA’s ERT Web site, including 

information claimed to be CBI, on a 

compact disc, flash drive or other 

commonly used electronic storage 

media to the EPA. The electronic storage 

media must be clearly marked as CBI 

and mailed to U.S. EPA/OAQPS/CORE 

CBI Office, Attention: Group Leader, 

Measurement Policy Group, MD C404– 

02, 4930 Old Page Rd., 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 

(h)(9)(ii)(A). 

(B) For any performance evaluations 

of continuous monitoring systems 

measuring RATA pollutants that are not 

supported by the EPA’s ERT as listed on 

the EPA’s ERT Web site at the time of 

the evaluation, the owner or operator 

must submit the results of the 

performance evaluation to the 

Administrator at the appropriate 

address listed in § 63.13. 

(i) Recordkeeping. Each owner or 

operator of a source subject to this 

subpart shall keep copies of all 

applicable reports and records required 

by this subpart for at least 5 years except 

as otherwise specified in paragraphs 

(i)(1) through (12) of this section. All 

applicable records shall be maintained 

in such a manner that they can be 

readily accessed within 24 hours. 

Records may be maintained in hard 

copy or computer-readable form 

including, but not limited to, on paper, 

microfilm, computer, flash drive, floppy 

disk, magnetic tape, or microfiche. 

(1) Each owner or operator subject to 

the storage vessel provisions in § 63.646 

shall keep the records specified in 

§ 63.123 of subpart G except as specified 

in paragraphs (i)(1)(i) through (iv) of this 

section. Each owner or operator subject 

to the storage vessel provisions in 

§ 63.660 shall keep records as specified 

in paragraphs (i)(1)(v) and (vi) of this 

section. 

* * * * * 

(ii) All references to § 63.122 in 

§ 63.123 of subpart G shall be replaced 

with § 63.655(e). 

* * * * * 

(v) Each owner or operator of a Group 

1 storage vessel subject to the provisions 

in § 63.660 shall keep records as 

specified in § 63.1065 or § 63.998, as 

applicable. 

(vi) Each owner or operator of a Group 

2 storage vessel shall keep the records 

specified in § 63.1065(a) of subpart WW. 

If a storage vessel is determined to be 

Group 2 because the weight percent 

total organic HAP of the stored liquid is 

less than or equal to 4 percent for 

existing sources or 2 percent for new 

sources, a record of any data, 

assumptions, and procedures used to 

make this determination shall be 

retained. 

* * * * * 

(4) For each closed vent system that 

contains bypass lines that could divert 

a vent stream away from the control 

device and either directly to the 

atmosphere or to a control device that 

does not comply with the requirements 

in § 63.643(a), the owner or operator 

shall keep a record of the information 

specified in either paragraph (i)(4)(i) or 

(ii) of this section, as applicable. 

(i) The owner or operator shall 

maintain records of periods when flow 

was detected in the bypass line, 

including the date and time and the 

duration of the flow in the bypass line. 

For each flow event, the owner or 

operator shall maintain records 

sufficient to determine whether or not 

the detected flow included flow of a 

Group 1 miscellaneous process vent 

stream requiring control. For periods 

when the Group 1 miscellaneous 

process vent stream requiring control is 

diverted from the control device and 

released either directly to the 

atmosphere or to a control device that 

does not comply with the requirements 

in § 63.643(a), the owner or operator 

shall include an estimate of the volume 

of gas, the concentration of organic HAP 

in the gas and the resulting emissions of 

organic HAP that bypassed the control 

device using process knowledge and 

engineering estimates. 

(ii) Where a seal mechanism is used 

to comply with § 63.644(c)(2), hourly 

records of flow are not required. In such 

cases, the owner or operator shall record 

the date that the monthly visual 

inspection of the seals or closure 

mechanisms is completed. The owner or 

operator shall also record the 

occurrence of all periods when the seal 

or closure mechanism is broken, the 

bypass line valve position has changed 

or the key for a lock-and-key type lock 

has been checked out. The owner or 

operator shall include an estimate of the 

volume of gas, the concentration of 

organic HAP in the gas and the resulting 

mass emissions of organic HAP from the 

Group 1 miscellaneous process vent 

stream requiring control that bypassed 

the control device or records sufficient 

to demonstrate that there was no flow of 

a Group 1 miscellaneous process vent 

stream requiring control during the 

period. 

(5) The owner or operator of a heat 

exchange system subject to this subpart 

shall comply with the recordkeeping 

requirements in paragraphs (i)(5)(i) 

through (v) of this section and retain 

these records for 5 years. 

* * * * * 

(7) Each owner or operator subject to 

the delayed coking unit decoking 

operations provisions in § 63.657 must 

maintain records specified in 

paragraphs (i)(7)(i) through (iii) of this 

section. 

(i) The average pressure or 

temperature, as applicable, for the 5- 

minute period prior to venting to the 

atmosphere, draining, or deheading the 

coke drum for each cooling cycle for 

each coke drum. 

(ii) If complying with the 60-cycle 

rolling average, each 60-cycle rolling 

average pressure or temperature, as 

applicable, considering all coke drum 

venting events in the existing affected 

source. 

(iii) For double-quench cooling 

cycles: 


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(A) The date, time and duration of 

each pre-vent draining event. 

(B) The pressure or temperature of the 

coke drum vessel, as applicable, for the 

15 minute period prior to the pre-vent 

draining. 

(C) The drain water temperature at 1- 

minute intervals from the start of prevent draining to the complete closure of 

the drain valve. 

(8) For fenceline monitoring systems 

subject to § 63.658, each owner or 

operator shall keep the records specified 

in paragraphs (i)(8)(i) through (x) of this 

section on an ongoing basis. 

(i) Coordinates of all passive 

monitors, including replicate samplers 

and field blanks, and if applicable, the 

meteorological station. The owner or 

operator shall determine the coordinates 

using an instrument with an accuracy of 

at least 3 meters. The coordinates shall 

be in decimal degrees with at least five 

decimal places. 

(ii) The start and stop times and dates 

for each sample, as well as the tube 

identifying information. 

(iii) Sampling period average 

temperature and barometric pressure 

measurements. 

(iv) For each outlier determined in 

accordance with Section 9.2 of Method 

325A of appendix A of this part, the 

sampler location of and the 

concentration of the outlier and the 

evidence used to conclude that the 

result is an outlier. 

(v) For samples that will be adjusted 

for a background, the location of and the 

concentration measured simultaneously 

by the background sampler, and the 

perimeter samplers to which it applies. 

(vi) Individual sample results, the 

calculated Dc for benzene for each 

sampling period and the two samples 

used to determine it, whether 

background correction was used, and 

the annual average Dc calculated after 

each sampling period. 

(vii) Method detection limit for each 

sample, including co-located samples 

and blanks. 

(viii) Documentation of corrective 

action taken each time the action level 

was exceeded. 

(ix) Other records as required by 

Methods 325A and 325B of appendix A 

of this part. 

(x) If a near-field source correction is 

used as provided in § 63.658(i), records 

of hourly meteorological data, including 

temperature, barometric pressure, wind 

speed and wind direction, calculated 

daily unit vector wind direction and 

daily sigma theta, and other records 

specified in the site-specific monitoring 

plan. 

(9) For each flare subject to § 63.670, 

each owner or operator shall keep the 

records specified in paragraphs (i)(9)(i) 

through (xii) of this section up-to-date 

and readily accessible, as applicable. 

(i) Retain records of the output of the 

monitoring device used to detect the 

presence of a pilot flame as required in 

§ 63.670(b) for a minimum of 2 years. 

Retain records of each 15-minute block 

during which there was at least one 

minute that no pilot flame is present 

when regulated material is routed to a 

flare for a minimum of 5 years. 

(ii) Retain records of daily visible 

emissions observations or video 

surveillance images required in 

§ 63.670(h) as specified in the 

paragraphs (i)(9)(ii)(A) through (C), as 

applicable, for a minimum of 3 years. 

(A) If visible emissions observations 

are performed using Method 22 at 40 

CFR part 60, appendix A–7, the record 

must identify whether the visible 

emissions observation was performed, 

the results of each observation, total 

duration of observed visible emissions, 

and whether it was a 5-minute or 2-hour 

observation. If the owner or operator 

performs visible emissions observations 

more than one time during a day, the 

record must also identify the date and 

time of day each visible emissions 

observation was performed. 

(B) If video surveillance camera is 

used, the record must include all video 

surveillance images recorded, with time 

and date stamps. 

(C) For each 2 hour period for which 

visible emissions are observed for more 

than 5 minutes in 2 consecutive hours, 

the record must include the date and 

time of the 2 hour period and an 

estimate of the cumulative number of 

minutes in the 2 hour period for which 

emissions were visible. 

(iii) The 15-minute block average 

cumulative flows for flare vent gas and, 

if applicable, total steam, perimeter 

assist air, and premix assist air specified 

to be monitored under § 63.670(i), along 

with the date and time interval for the 

15-minute block. If multiple monitoring 

locations are used to determine 

cumulative vent gas flow, total steam, 

perimeter assist air, and premix assist 

air, retain records of the 15-minute 

block average flows for each monitoring 

location for a minimum of 2 years, and 

retain the 15-minute block average 

cumulative flows that are used in 

subsequent calculations for a minimum 

of 5 years. If pressure and temperature 

monitoring is used, retain records of the 

15-minute block average temperature, 

pressure and molecular weight of the 

flare vent gas or assist gas stream for 

each measurement location used to 

determine the 15-minute block average 

cumulative flows for a minimum of 2 

years, and retain the 15-minute block 

average cumulative flows that are used 

in subsequent calculations for a 

minimum of 5 years. 

(iv) The flare vent gas compositions 

specified to be monitored under 

§ 63.670(j). Retain records of individual 

component concentrations from each 

compositional analyses for a minimum 

of 2 years. If NHVvg analyzer is used, 

retain records of the 15-minute block 

average values for a minimum of 5 

years. 

(v) Each 15-minute block average 

operating parameter calculated 

following the methods specified in 

§ 63.670(k) through (n), as applicable. 

(vi) [Reserved] 

(vii) All periods during which 

operating values are outside of the 

applicable operating limits specified in 

§ 63.670(d) through (f) when regulated 

material is being routed to the flare. 

(viii) All periods during which the 

owner or operator does not perform flare 

monitoring according to the procedures 

in § 63.670(g) through (j). 

(ix) Records of periods when there is 

flow of vent gas to the flare, but when 

there is no flow of regulated material to 

the flare, including the start and stop 

time and dates of periods of no 

regulated material flow. 

(x) Records when the flow of vent gas 

exceeds the smokeless capacity of the 

flare, including start and stop time and 

dates of the flaring event. 

(xi) Records of the root cause analysis 

and corrective action analysis 

conducted as required in § 63.670(o)(3), 

including an identification of the 

affected facility, the date and duration 

of the event, a statement noting whether 

the event resulted from the same root 

cause(s) identified in a previous 

analysis and either a description of the 

recommended corrective action(s) or an 

explanation of why corrective action is 

not necessary under § 63.670(o)(5)(i). 

(xii) For any corrective action analysis 

for which implementation of corrective 

actions are required in § 63.670(o)(5), a 

description of the corrective action(s) 

completed within the first 45 days 

following the discharge and, for 

action(s) not already completed, a 

schedule for implementation, including 

proposed commencement and 

completion dates. 

(10) [Reserved] 

(11) For each pressure relief device 

subject to the pressure release 

management work practice standards in 

§ 63.648(j)(3), the owner or operator 

shall keep the records specified in 

paragraphs (i)(11)(i) through (iii) of this 

section. 

(i) Records of the prevention measures 

implemented as required in 

§ 63.648(j)(3)(ii), if applicable. 


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(ii) Records of the number of releases 

during each calendar year and the 

number of those releases for which the 

root cause was determined to be a force 

majeure event. Keep these records for 

the current calendar year and the past 

five calendar years. 

(iii) For each release to the 

atmosphere, the owner or operator shall 

keep the records specified in paragraphs 

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

(A) The start and end time and date 

of each pressure release to the 

atmosphere. 

(B) Records of any data, assumptions, 

and calculations used to estimate of the 

mass quantity of each organic HAP 

released during the event. 

(C) Records of the root cause analysis 

and corrective action analysis 

conducted as required in 

§ 63.648(j)(3)(iii), including an 

identification of the affected facility, the 

date and duration of the event, a 

statement noting whether the event 

resulted from the same root cause(s) 

identified in a previous analysis and 

either a description of the recommended 

corrective action(s) or an explanation of 

why corrective action is not necessary 

under § 63.648(j)(7)(i). 

(D) For any corrective action analysis 

for which implementation of corrective 

actions are required in § 63.648(j)(7), a 

description of the corrective action(s) 

completed within the first 45 days 

following the discharge and, for 

action(s) not already completed, a 

schedule for implementation, including 

proposed commencement and 

completion dates. 

(12) For each maintenance vent 

opening subject to the requirements in 

§ 63.643(c), the owner or operator shall 

keep the applicable records specified in 

(i)(12)(i) through (v) of this section. 

(i) The owner or operator shall 

maintain standard site procedures used 

to deinventory equipment for safety 

purposes (e.g., hot work or vessel entry 

procedures) to document the procedures 

used to meet the requirements in 

§ 63.643(c). The current copy of the 

procedures shall be retained and 

available on-site at all times. Previous 

versions of the standard site procedures, 

is applicable, shall be retained for five 

years. 

(ii) If complying with the 

requirements of § 63.643(c)(1)(i) and the 

lower explosive limit at the time of the 

vessel opening exceeds 10 percent, 

identification of the maintenance vent, 

the process units or equipment 

associated with the maintenance vent, 

the date of maintenance vent opening, 

and the lower explosive limit at the time 

of the vessel opening. 

(iii) If complying with the 

requirements of § 63.643(c)(1)(ii) and 

either the vessel pressure at the time of 

the vessel opening exceeds 5 psig or the 

lower explosive limit at the time of the 

active purging was initiated exceeds 10 

percent, identification of the 

maintenance vent, the process units or 

equipment associated with the 

maintenance vent, the date of 

maintenance vent opening, the pressure 

of the vessel or equipment at the time 

of discharge to the atmosphere and, if 

applicable, the lower explosive limit of 

the vapors in the equipment when 

active purging was initiated. 

(iv) If complying with the 

requirements of § 63.643(c)(1)(iii), 

identification of the maintenance vent, 

the process units or equipment 

associated with the maintenance vent, 

the date of maintenance vent opening, 

and records used to estimate the total 

quantity of VOC in the equipment at the 

time the maintenance vent was opened 

to the atmosphere for each applicable 

maintenance vent opening. 

(v) If complying with the 

requirements of § 63.643(c)(1)(iv), 

identification of the maintenance vent, 

the process units or equipment 

associated with the maintenance vent, 

records documenting the lack of a pure 

hydrogen supply, the date of 

maintenance vent opening, and the 

lower explosive limit of the vapors in 

the equipment at the time of discharge 

to the atmosphere for each applicable 

maintenance vent opening. 

■ 28. Section 63.656 is amended by 

revising paragraph (c)(1) to read as 

follows: 

§ 63.656 Implementation and enforcement. 

* * * * * 

(c) * * * 

(1) Approval of alternatives to the 

requirements in §§ 63.640, 63.642(g) 

through (l), 63.643, 63.646 through 

63.652, 63.654, 63.657 through 63.660, 

and 63.670. Where these standards 

reference another subpart, the cited 

provisions will be delegated according 

to the delegation provisions of the 

referenced subpart. Where these 

standards reference another subpart and 

modify the requirements, the 

requirements shall be modified as 

described in this subpart. Delegation of 

the modified requirements will also 

occur according to the delegation 

provisions of the referenced subpart. 

* * * * * 

■ 29. Section 63.657 is added to read as 

follows: 

§ 63.657 Delayed coking unit decoking 

operation standards. 

(a) Except as provided in paragraphs 

(e) and (f) of this section, each owner or 

operator of a delayed coking unit shall 

depressure each coke drum to a closed 

blowdown system until the coke drum 

vessel pressure or temperature 

measured at the top of the coke drum or 

in the overhead line of the coke drum 

as near as practical to the coke drum 

meets the applicable limits specified in 

paragraph (a)(1) or (2) of this section 

prior to venting to the atmosphere, 

draining or deheading the coke drum at 

the end of the cooling cycle. 

(1) For delayed coking units at an 

existing affected source, meet either: 

(i) An average vessel pressure of 2 

psig determined on a rolling 60-event 

average; or 

(ii) An average vessel temperature of 

220 degrees Fahrenheit determined on a 

rolling 60-event average. 

(2) For delayed coking units at a new 

affected source, meet either: 

(i) A vessel pressure of 2.0 psig for 

each decoking event; or 

(ii) A vessel temperature of 218 

degrees Fahrenheit for each decoking 

event. 

(b) Each owner or operator of a 

delayed coking unit complying with the 

pressure limits in paragraph (a)(1)(i) or 

(a)(2)(i) of this section shall install, 

operate, calibrate, and maintain a 

monitoring system, as specified in 

paragraphs (b)(1) through (5) of this 

section, to determine the coke drum 

vessel pressure. 

(1) The pressure monitoring system 

must be in a representative location (at 

the top of the coke drum or in the 

overhead line as near as practical to the 

coke drum) that minimizes or eliminates 

pulsating pressure, vibration, and, to the 

extent practical, internal and external 

corrosion. 

(2) The pressure monitoring system 

must be capable of measuring a pressure 

of 2.0 psig within ±0.5 psig. 

(3) The pressure monitoring system 

must be verified annually or at the 

frequency recommended by the 

instrument manufacturer. The pressure 

monitoring system must be verified 

following any period of more than 24 

hours throughout which the pressure 

exceeded the maximum rated pressure 

of the sensor, or the data recorder was 

off scale. 

(4) All components of the pressure 

monitoring system must be visually 

inspected for integrity, oxidation and 

galvanic corrosion every 3 months, 

unless the system has a redundant 

pressure sensor. 

(5) The output of the pressure 

monitoring system must be reviewed 


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daily to ensure that the pressure 

readings fluctuate as expected between 

operating and cooling/decoking cycles 

to verify the pressure taps are not 

plugged. Plugged pressure taps must be 

unplugged or otherwise repaired prior 

to the next operating cycle. 

(c) Each owner or operator of a 

delayed coking unit complying with the 

temperature limits in paragraph (a)(1)(ii) 

or (a)(2)(ii) of this section shall install, 

operate, calibrate, and maintain a 

continuous parameter monitoring 

system to measure the coke drum vessel 

temperature (at the top of the coke drum 

or in the overhead line as near as 

practical to the coke drum) according to 

the requirements specified in table 13 of 

this subpart. 

(d) The owner or operator of a delayed 

coking unit shall determine the coke 

drum vessel pressure or temperature, as 

applicable, on a 5-minute rolling 

average basis while the coke drum is 

vented to the closed blowdown system 

and shall use the last complete 5-minute 

rolling average pressure or temperature 

just prior to initiating steps to isolate the 

coke drum prior to venting, draining or 

deheading to demonstrate compliance 

with the requirements in paragraph (a) 

of this section. Pressure or temperature 

readings after initiating steps to isolate 

the coke drum from the closed 

blowdown system just prior to 

atmospheric venting, draining, or 

deheading the coke drum shall not be 

used in determining the average coke 

drum vessel pressure or temperature for 

the purpose of compliance with the 

requirements in paragraph (a) of this 

section. 

(e) The owner or operator of a delayed 

coking unit using the ‘‘water overflow’’ 

method of coke cooling must hardpipe 

the overflow water or otherwise prevent 

exposure of the overflow water to the 

atmosphere when transferring the 

overflow water to the overflow water 

storage tank whenever the coke drum 

vessel temperature exceeds 220 degrees 

Fahrenheit. The overflow water storage 

tank may be an open or fixed-roof tank 

provided that a submerged fill pipe 

(pipe outlet below existing liquid level 

in the tank) is used to transfer overflow 

water to the tank. The owner or operator 

of a delayed coking unit using the 

‘‘water overflow’’ method of coke 

cooling shall determine the coke drum 

vessel temperature as specified in 

paragraphs (c) and (d) of this section 

regardless of the compliance method 

used to demonstrate compliance with 

the requirements in paragraph (a) of this 

section. 

(f) The owner or operator of a delayed 

coking unit may partially drain a coke 

drum prior to achieving the applicable 

limits in paragraph (a) of this section in 

order to double-quench a coke drum 

that did not cool adequately using the 

normal cooling process steps provided 

that the owner or operator meets the 

conditions in paragraphs (f)(1) and (2) of 

this section. 

(1) The owner or operator shall 

install, operate, calibrate, and maintain 

a continuous parameter monitoring 

system to measure the drain water 

temperature at the bottom of the coke 

drum or in the drain line as near as 

practical to the coke drum according to 

the requirements specified in table 13 of 

this subpart. 

(2) The owner or operator must 

maintain the drain water temperature 

below 210 degrees Fahrenheit during 

the partial drain associated with the 

double-quench event. 

■ 30. Section 63.658 is added to read as 

follows: 

§ 63.658 Fenceline monitoring provisions. 

(a) The owner or operator shall 

conduct sampling along the facility 

property boundary and analyze the 

samples in accordance with Methods 

325A and 325B of appendix A of this 

part and paragraphs (b) through (k) of 

this section. 

(b) The target analyte is benzene. 

(c) The owner or operator shall 

determine passive monitor locations in 

accordance with Section 8.2 of Method 

325A of appendix A of this part. 

(1) As it pertains to this subpart, 

known sources of VOCs, as used in 

Section 8.2.1.3 in Method 325A of 

appendix A of this part for siting 

passive monitors means a wastewater 

treatment unit, process unit, or any 

emission source requiring control 

according to the requirements of this 

subpart, including marine vessel 

loading operations. For marine loading 

operations that are located offshore, one 

passive monitor should be sited on the 

shoreline adjacent to the dock. 

(2) The owner or operator may collect 

one or more background samples if the 

owner or operator believes that an 

offsite upwind source or an onsite 

source excluded under § 63.640(g) may 

influence the sampler measurements. If 

the owner or operator elects to collect 

one or more background samples, the 

owner of operator must develop and 

submit a site-specific monitoring plan 

for approval according to the 

requirements in paragraph (i) of this 

section. Upon approval of the sitespecific monitoring plan, the 

background sampler(s) should be 

operated co-currently with the routine 

samplers. 

(3) The owner or operator shall collect 

at least one co-located duplicate sample 

for every 10 field samples per sampling 

period and at least two field blanks per 

sampling period, as described in Section 

9.3 in Method 325A of appendix A of 

this part. The co-located duplicates may 

be collected at any one of the perimeter 

sampling locations. 

(4) The owner or operator shall follow 

the procedure in Section 9.6 of Method 

325B of appendix A of this part to 

determine the detection limit of benzene 

for each sampler used to collect 

samples, background samples (if the 

owner or operator elects to do so), colocated samples and blanks. 

(d) The owner or operator shall collect 

and record meteorological data 

according to the applicable 

requirements in paragraphs (d)(1) 

through (3) of this section. 

(1) If a near-field source correction is 

used as provided in paragraph (i)(1) of 

this section or if an alternative test 

method is used that provides timeresolved 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 average 

meteorological data, including 

temperature, barometric pressure, wind 

speed and wind direction and calculate 

daily unit vector wind direction and 

daily sigma theta. 

(2) For cases other than those 

specified in paragraph (d)(1) of this 

section, the owner or operator shall 

collect and record sampling period 

average temperature and barometric 

pressure using either an on-site 

meteorological station in accordance 

with Section 8.3 of Method 325A of 

appendix A of this part or, alternatively, 

using data from a United States Weather 

Service (USWS) meteorological station 

provided the USWS meteorological 

station is within 40 kilometers (25 

miles) of the refinery. 

(3) If an on-site meteorological station 

is used, the owner or operator shall 

follow the calibration and 

standardization procedures for 

meteorological measurements in EPA– 

454/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. 

(1) Sampling period. A 14-day 

sampling period shall be used, unless a 

shorter sampling period is determined 

to be necessary under paragraph (g) or 

(i) of this section. A sampling period is 

defined as the period during which 

sampling tube is deployed at a specific 

sampling location with the diffusive 


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sampling end cap in-place and does not 

include the time required to analyze the 

sample. For the purpose of this subpart, 

a 14-day sampling period may be no 

shorter than 13 calendar days and no 

longer than 15 calendar days, but the 

routine sampling period shall be 14 

calendar days. 

(2) Base sampling frequency. Except 

as provided in paragraph (e)(3) of this 

section, the frequency of sample 

collection shall be once each contiguous 

14-day sampling period, such that the 

beginning of the next 14-day sampling 

period begins immediately upon the 

completion of the previous 14-day 

sampling period. 

(3) Alternative sampling frequency for 

burden reduction. When an individual 

monitor consistently achieves results at 

or below 0.9 mg/m3, the owner or 

operator may elect to use the applicable 

minimum sampling frequency specified 

in paragraphs (e)(3)(i) through (v) of this 

section for that monitoring site. When 

calculating Dc for the monitoring period 

when using this alternative for burden 

reduction, zero shall be substituted for 

the sample result for the monitoring site 

for any period where a sample is not 

taken. 

(i) If every sample at a monitoring site 

is at or below 0.9 mg/m3 for 2 years (52 

consecutive samples), every other 

sampling period can be skipped for that 

monitoring site, i.e., sampling will occur 

approximately once per month. 

(ii) If every sample at a monitoring 

site that is monitored at the frequency 

specified in paragraph (e)(3)(i) of this 

section is at or below 0.9 mg/m3 for 2 

years (i.e., 26 consecutive ‘‘monthly’’ 

samples), five 14-day sampling periods 

can be skipped for that monitoring site 

following each period of sampling, i.e., 

sampling will occur approximately once 

per quarter. 

(iii) If every sample at a monitoring 

site that is monitored at the frequency 

specified in paragraph (e)(3)(ii) of this 

section is at or below 0.9 mg/m3 for 2 

years (i.e., 8 consecutive quarterly 

samples), twelve 14-day sampling 

periods can be skipped for that 

monitoring site following each period of 

sampling, i.e., sampling will occur twice 

a year. 

(iv) If every sample at a monitoring 

site that is monitored at the frequency 

specified in paragraph (e)(3)(iii) of this 

section is at or below 0.9 mg/m3 for an 

2 years (i.e., 4 consecutive semi-annual 

samples), only one sample per year is 

required for that monitoring site. For 

yearly sampling, samples shall occur at 

least 10 months but no more than 14 

months apart. 

(v) If at any time a sample for a 

monitoring site that is monitored at the 

frequency specified in paragraphs 

(e)(3)(i) through (iv) of this section 

returns a result that is above 0.9 mg/m3, 

the sampling site must return to the 

original sampling requirements of 

contiguous 14-day sampling periods 

with no skip periods for one quarter (six 

14-day sampling periods). If every 

sample collected during this quarter is 

at or below 0.9 mg/m3 , the owner or 

operator may revert back to the reduced 

monitoring schedule applicable for that 

monitoring site prior to the sample 

reading exceeding 0.9 mg/m3 If any 

sample collected during this quarter is 

above 0.9 mg/m3, that monitoring site 

must return to the original sampling 

requirements of contiguous 14-day 

sampling periods with no skip periods 

for a minimum of two years. The burden 

reduction requirements can be used 

again for that monitoring site once the 

requirements of paragraph (e)(3)(i) of 

this section are met again, i.e., after 52 

contiguous 14-day samples with no 

results above 0.9 mg/m3 . 

(f) Within 45 days of completion of 

each sampling period, the owner or 

operator shall determine whether the 

results are above or below the action 

level as follows: 

(1) The owner or operator shall 

determine the facility impact on the 

benzene concentration (Dc) for each 14- 

day sampling period according to either 

paragraph (f)(1)(i) or (ii) of this section, 

as applicable. 

(i) Except when near-field source 

correction is used as provided in 

paragraph (i) of this section, the owner 

or operator shall determine the highest 

and lowest sample results for benzene 

concentrations from the sample pool 

and calculate Dc as the difference in 

these concentrations. The owner or 

operator shall adhere to the following 

procedures when one or more samples 

for the sampling period are below the 

method detection limit for benzene: 

(A) If the lowest detected value of 

benzene is below detection, the owner 

or operator shall use zero as the lowest 

sample result when calculating Dc. 

(B) If all sample results are below the 

method detection limit, the owner or 

operator shall use the method detection 

limit as the highest sample result. 

(ii) When near-field source correction 

is used as provided in paragraph (i) of 

this section, the owner or operator shall 

determine Dc using the calculation 

protocols outlined in the approved sitespecific monitoring plan and in 

paragraph (i) of this section. 

(2) The owner or operator shall 

calculate the annual average Dc based 

on the average of the 26 most recent 14- 

day sampling periods. The owner or 

operator shall update this annual 

average value after receiving the results 

of each subsequent 14-day sampling 

period. 

(3) The action level for benzene is 9 

micrograms per cubic meter (mg/m3) on 

an annual average basis. If the annual 

average Dc value for benzene is less than 

or equal to 9 mg/m3, the concentration 

is below the action level. If the annual 

average Dc value for benzene is greater 

than 9 mg/m3, the concentration is above 

the action level, and the owner or 

operator shall conduct a root cause 

analysis and corrective action in 

accordance with paragraph (g) of this 

section. 

(g) Within 5 days of determining that 

the action level has been exceeded for 

any annual average Dc and no longer 

than 50 days after completion of the 

sampling period, the owner or operator 

shall initiate a root cause analysis to 

determine the cause of such exceedance 

and to determine appropriate corrective 

action, such as those described in 

paragraphs (g)(1) through (4) of this 

section. The root cause analysis and 

initial corrective action analysis shall be 

completed and initial corrective actions 

taken no later than 45 days after 

determining there is an exceedance. 

Root cause analysis and corrective 

action may include, but is not limited 

to: 

(1) Leak inspection using Method 21 

of part 60, appendix A–7 of this chapter 

and repairing any leaks found. 

(2) Leak inspection using optical gas 

imaging and repairing any leaks found. 

(3) Visual inspection to determine the 

cause of the high benzene emissions and 

implementing repairs to reduce the level 

of emissions. 

(4) Employing progressively more 

frequent sampling, analysis and 

meteorology (e.g., using shorter 

sampling periods for Methods 325A and 

325B of appendix A of this part, or 

using active sampling techniques). 

(h) If, upon completion of the 

corrective action analysis and corrective 

actions such as those described in 

paragraph (g) of this section, the Dc 

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 mg/ 

m3 or if all corrective action measures 

identified require more than 45 days to 

implement, the owner or operator shall 

develop a corrective action plan that 

describes the corrective action(s) 

completed to date, additional measures 

that the owner or operator proposes to 

employ to reduce fenceline 

concentrations below the action level, 

and a schedule for completion of these 

measures. The owner or operator shall 

submit the corrective action plan to the 


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Administrator within 60 days after 

receiving the analytical results 

indicating that the Dc value for the 14- 

day sampling period following the 

completion of the initial corrective 

action is greater than 9 mg/m3 or, if no 

initial corrective actions were 

identified, no later than 60 days 

following the completion of the 

corrective action analysis required in 

paragraph (g) of this section. 

(i) An owner or operator may request 

approval from the Administrator for a 

site-specific monitoring plan to account 

for offsite upwind sources or onsite 

sources excluded under § 63.640(g) 

according to the requirements in 

paragraphs (i)(1) through (4) of this 

section. 

(1) The owner or operator shall 

prepare and submit a site-specific 

monitoring plan and receive approval of 

the site-specific monitoring plan prior to 

using the near-field source alternative 

calculation for determining Dc provided 

in paragraph (i)(2) of this section. The 

site-specific monitoring plan shall 

include, at a minimum, the elements 

specified in paragraphs (i)(1)(i) through 

(v) of this section. The procedures in 

Section 12 of Method 325A of appendix 

A of this part are not required, but may 

be used, if applicable, when 

determining near-field source 

contributions. 

(i) Identification of the near-field 

source or sources. For onsite sources, 

documentation that the onsite source is 

excluded under § 63.640(g) and 

identification of the specific provision 

in § 63.640(g) that applies to the source. 

(ii) Location of the additional 

monitoring stations that shall be used to 

determine the uniform background 

concentration and the near-field source 

concentration contribution. 

(iii) Identification of the fenceline 

monitoring locations impacted by the 

near-field source. If more than one nearfield source is present, identify the nearfield source or sources that are expected 

to contribute to the concentration at that 

monitoring location. 

(iv) A description of (including 

sample calculations illustrating) the 

planned data reduction and calculations 

to determine the near-field source 

concentration contribution for each 

monitoring location. 

(v) If more frequent monitoring or a 

monitoring station other than a passive 

diffusive tube monitoring station is 

proposed, provide a detailed description 

of the measurement methods, 

measurement frequency, and recording 

frequency for determining the uniform 

background or near-field source 

concentration contribution. 

(2) When an approved site-specific 

monitoring plan is used, the owner or 

operator shall determine Dc for 

comparison with the 9 mg/m3 action 

level using the requirements specified 

in paragraphs (i)(2)(i) through (iii) of 

this section. 

(i) For each monitoring location, 

calculate Dci using the following 

equation. 

Dci = MFCi ¥ NFSi ¥ UB 

Where: 

Dci = The fenceline concentration, corrected 

for background, at measurement location 

i, micrograms per cubic meter (mg/m3). 

MFCi = The measured fenceline 

concentration at measurement location i, 

mg/m3. 

NFSi = The near-field source contributing 

concentration at measurement location i 

determined using the additional 

measurements and calculation 

procedures included in the site-specific 

monitoring plan, mg/m3. For monitoring 

locations that are not included in the 

site-specific monitoring plan as impacted 

by a near-field source, use NFSi = 0 mg/ 

m3. 

UB = The uniform background concentration 

determined using the additional 

measurements included in the sitespecific monitoring plan, mg/m3. If no 

additional measurements are specified in 

the site-specific monitoring plan for 

determining the uniform background 

concentration, use UB = 0 mg/m3. 

(ii) When one or more samples for the 

sampling period are below the method 

detection limit for benzene, adhere to 

the following procedures: 

(A) If the benzene concentration at the 

monitoring location used for the 

uniform background concentration is 

below the method detection limit, the 

owner or operator shall use zero for UB 

for that monitoring period. 

(B) If the benzene concentration at the 

monitoring location(s) used to 

determine the near-field source 

contributing concentration is below the 

method detection limit, the owner or 

operator shall use zero for the 

monitoring location concentration when 

calculating NFSi for that monitoring 

period. 

(C) If a fenceline monitoring location 

sample result is below the method 

detection limit, the owner or operator 

shall use the method detection limit as 

the sample result. 

(iii) Determine Dc for the monitoring 

period as the maximum value of Dci

from all of the fenceline monitoring 

locations for that monitoring period. 

(3) The site-specific monitoring plan 

shall be submitted and approved as 

described in paragraphs (i)(3)(i) through 

(iv) of this section. 

(i) The site-specific monitoring plan 

must be submitted to the Administrator 

for approval. 

(ii) The site-specific monitoring plan 

shall also be submitted to the following 

address: U.S. Environmental Protection 

Agency, Office of Air Quality Planning 

and Standards, Sector Policies and 

Programs Division, U.S. EPA Mailroom 

(E143–01), Attention: Refinery Sector 

Lead, 109 T.W. Alexander Drive, 

Research Triangle Park, NC 27711. 

Electronic copies in lieu of hard copies 

may also be submitted to refineryrtr@

epa.gov. 

(iii) The Administrator shall approve 

or disapprove the plan in 90 days. The 

plan shall be considered approved if the 

Administrator either approves the plan 

in writing, or fails to disapprove the 

plan in writing. The 90-day period shall 

begin when the Administrator receives 

the plan. 

(iv) If the Administrator finds any 

deficiencies in the site-specific 

monitoring plan and disapproves the 

plan in writing, the owner or operator 

may revise and resubmit the sitespecific monitoring plan following the 

requirements in paragraphs (i)(3)(i) and 

(ii) of this section. The 90-day period 

starts over with the resubmission of the 

revised monitoring plan. 

(4) The approval by the Administrator 

of a site-specific monitoring plan will be 

based on the completeness, accuracy 

and reasonableness of the request for a 

site-specific monitoring plan. Factors 

that the Administrator will consider in 

reviewing the request for a site-specific 

monitoring plan include, but are not 

limited to, those described in 

paragraphs (i)(4)(i) through (v) of this 

section. 

(i) The identification of the near-field 

source or sources. For onsite sources, 

the documentation provided that the 

onsite source is excluded under 

§ 63.640(g). 

(ii) The monitoring location selected 

to determine the uniform background 

concentration or an indication that no 

uniform background concentration 

monitor will be used. 

(iii) The location(s) selected for 

additional monitoring to determine the 

near-field source concentration 

contribution. 

(iv) The identification of the fenceline 

monitoring locations impacted by the 

near-field source or sources. 

(v) The appropriateness of the 

planned data reduction and calculations 

to determine the near-field source 

concentration contribution for each 

monitoring location. 

(vi) If more frequent monitoring is 

proposed, the adequacy of the 

description of the measurement and 


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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 paragraphs 

(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 of appendix A of this part. 

(2) The alternative method must be 

validated according to Method 301 in 

appendix A of this part or contain 

performance based procedures and 

indicators to ensure self-validation. 

(3) The method detection limit must 

nominally be at least an order of 

magnitude below the action level, i.e., 

0.9 mg/m3 benzene. The alternate test 

method must describe the procedures 

used to provide field verification of the 

detection limit. 

(4) The spatial coverage must be equal 

to or better than the spatial coverage 

provided in Method 325A of appendix 

A of this part. 

(i) For path average concentration 

open-path instruments, the physical 

path length of the measurement shall be 

no more than a passive sample footprint 

(the spacing that would be provided by 

the sorbent traps when following 

Method 325A). For example, if Method 

325A requires spacing monitors A and 

B 610 meters (2000 feet) apart, then the 

physical path length limit for the 

measurement at that portion of the 

fenceline shall be no more than 610 

meters (2000 feet). 

(ii) For range resolved open-path 

instrument or approach, the instrument 

or approach must be able to resolve an 

average concentration over each passive 

sampler footprint within the path length 

of the instrument. 

(iii) The extra samplers required in 

Sections 8.2.1.3 of Method 325A may be 

omitted when they fall within the path 

length of an open-path instrument. 

(5) At a minimum, non-integrating 

alternative test methods must provide a 

minimum of one cycle of operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. 

(6) For alternative test methods 

capable of real time measurements (less 

than a 5 minute sampling and analysis 

cycle), the alternative test method may 

allow for elimination of data points 

corresponding to outside emission 

sources for purpose of calculation of the 

high point for the two week average. 

The alternative test method approach 

must have wind speed, direction and 

stability class of the same time 

resolution and within the footprint of 

the instrument. 

(7) For purposes of averaging data 

points to determine the Dc for the 14- 

day average high sample result, all 

results measured under the method 

detection limit must use the method 

detection limit. For purposes of 

averaging data points for the 14-day 

average low sample result, all results 

measured under the method detection 

limit must use zero. 

■ 31. Section 63.660 is added to read as 

follows: 

§ 63.660 Storage vessel provisions. 

On and after the applicable 

compliance date for a Group 1 storage 

vessel located at a new or existing 

source as specified in § 63.640(h), the 

owner or operator of a Group 1 storage 

vessel that is part of a new or existing 

source shall comply with the 

requirements in subpart WW or SS of 

this part according to the requirements 

in paragraphs (a) through (i) of this 

section. 

(a) As used in this section, all terms 

not defined in § 63.641 shall have the 

meaning given them in subpart A, WW, 

or SS of this part. The definitions of 

‘‘Group 1 storage vessel’’ (paragraph (2)) 

and ‘‘Storage vessel’’ in § 63.641 shall 

apply in lieu of the definition of 

‘‘Storage vessel’’ in § 63.1061. 

(1) An owner or operator may use 

good engineering judgment or test 

results to determine the stored liquid 

weight percent total organic HAP for 

purposes of group determination. Data, 

assumptions, and procedures used in 

the determination shall be documented. 

(2) When an owner or operator and 

the Administrator do not agree on 

whether the annual average weight 

percent organic HAP in the stored liquid 

is above or below 4 percent for a storage 

vessel at an existing source or above or 

below 2 percent for a storage vessel at 

a new source, an appropriate method 

(based on the type of liquid stored) as 

published by EPA or a consensus-based 

standards organization shall be used. 

Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street NW., 6th Floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http://

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http://

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.naesb.org). 

(b) A floating roof storage vessel 

complying with the requirements of 

subpart WW of this part may comply 

with the control option specified in 

paragraph (b)(1) of this section and, if 

equipped with a ladder having at least 

one slotted leg, shall comply with one 

of the control options as described in 

paragraph (b)(2) of this section. 

(1) In addition to the options 

presented in §§ 63.1063(a)(2)(viii)(A) 

and (B) and 63.1064, a floating roof 

storage vessel may comply with 

§ 63.1063(a)(2)(vii) using a flexible 

enclosure device and either a gasketed 

or welded cap on the top of the 

guidepole. 

(2) Each opening through a floating 

roof for a ladder having at least one 

slotted leg shall be equipped with one 

of the configurations specified in 

paragraphs (b)(2)(i) through (iii) of this 

section. 

(i) A pole float in the slotted leg and 

pole wipers for both legs. The wiper or 

seal of the pole float must be at or above 

the height of the pole wiper. 

(ii) A ladder sleeve and pole wipers 

for both legs of the ladder. 

(iii) A flexible enclosure device and 

either a gasketed or welded cap on the 

top of the slotted leg. 

(c) For the purposes of this subpart, 

references shall apply as specified in 

paragraphs (c)(1) through (6) of this 

section. 

(1) All references to ‘‘the proposal 

date for a referencing subpart’’ and ‘‘the 

proposal date of the referencing 

subpart’’ in subpart WW of this part 

mean June 30, 2014. 

(2) All references to ‘‘promulgation of 

the referencing subpart’’ and ‘‘the 

promulgation date of the referencing 

subpart’’ in subpart WW of this part 

mean February 1, 2016. 

(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 

February 1, 2016. 

(4) All references to ‘‘the proposal 

date of the relevant standard established 

pursuant to CAA section 112(f)’’ in 


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subpart SS of this part mean June 30, 

2014. 

(5) All references to ‘‘the proposal 

date of a relevant standard established 

pursuant to CAA section 112(d)’’ in 

subpart SS of this part mean July 14, 

1994. 

(6) All references to the ‘‘required 

control efficiency’’ in subpart SS of this 

part mean reduction of organic HAP 

emissions by 95 percent or to an outlet 

concentration of 20 ppmv. 

(d) For an uncontrolled fixed roof 

storage vessel that commenced 

construction on or before June 30, 2014, 

and that meets the definition of ‘‘Group 

1 storage vessel’’, paragraph (2), in 

§ 63.641 but not the definition of 

‘‘Group 1 storage vessel’’, paragraph (1), 

in § 63.641, the requirements of § 63.982 

and/or § 63.1062 do not apply until the 

next time the storage vessel is 

completely emptied and degassed, or 

January 30, 2026, whichever occurs 

first. 

(e) Failure to perform inspections and 

monitoring required by this section 

shall constitute a violation of the 

applicable standard of this subpart. 

(f) References in § 63.1066(a) to initial 

startup notification requirements do not 

apply. 

(g) References to the Notification of 

Compliance Status in § 63.999(b) mean 

the Notification of Compliance Status 

required by § 63.655(f). 

(h) References to the Periodic Reports 

in §§ 63.1066(b) and 63.999(c) mean the 

Periodic Report required by § 63.655(g). 

(i) Owners or operators electing to 

comply with the requirements in 

subpart SS of this part for a Group 1 

storage vessel must comply with the 

requirements in paragraphs (i)(1) 

through (3) of this section. 

(1) If a flare is used as a control 

device, the flare shall meet the 

requirements of § 63.670 instead of the 

flare requirements in § 63.987. 

(2) If a closed vent system contains a 

bypass line, the owner or operator shall 

comply with the provisions of either 

§ 63.983(a)(3)(i) or (ii) for each closed 

vent system that contains bypass lines 

that could divert a vent stream either 

directly to the atmosphere or to a 

control device that does not comply 

with the requirements in subpart SS of 

this part. Except as provided in 

paragraphs (i)(2)(i) and (ii) of this 

section, use of the bypass at any time to 

divert a Group 1 storage vessel to either 

directly to the atmosphere or to a 

control device that does not comply 

with the requirements in subpart SS of 

this part is an emissions standards 

violation. Equipment such as low leg 

drains and equipment subject to 

§ 63.648 are not subject to this 

paragraph (i)(2). 

(i) If planned routine maintenance of 

the control device cannot be performed 

during periods that storage vessel 

emissions are vented to the control 

device or when the storage vessel is 

taken out of service for inspections or 

other planned maintenance reasons, the 

owner or operator may bypass the 

control device. 

(ii) Periods for which storage vessel 

control device may be bypassed for 

planned routine maintenance of the 

control device shall not exceed 240 

hours per calendar year. 

(3) If storage vessel emissions are 

routed to a fuel gas system or process, 

the fuel gas system or process shall be 

operating at all times when regulated 

emissions are routed to it. The 

exception in § 63.984(a)(1) does not 

apply. 

■ 32. Section 63.670 is added to read as 

follows: 

§ 63.670 Requirements for flare control 

devices. 

On or before January 30, 2019, the 

owner or operator of a flare used as a 

control device for an emission point 

subject to this subpart shall meet the 

applicable requirements for flares as 

specified in paragraphs (a) through (q) 

of this section and the applicable 

requirements in § 63.671. The owner or 

operator may elect to comply with the 

requirements of paragraph (r) of this 

section in lieu of the requirements in 

paragraphs (d) through (f) of this 

section, as applicable. 

(a) [Reserved] 

(b) Pilot flame presence. The owner or 

operator shall operate each flare with a 

pilot flame present at all times when 

regulated material is routed to the flare. 

Each 15-minute block during which 

there is at least one minute where no 

pilot flame is present when regulated 

material is routed to the flare is a 

deviation of the standard. Deviations in 

different 15-minute blocks from the 

same event are considered separate 

deviations. The owner or operator shall 

monitor for the presence of a pilot flame 

as specified in paragraph (g) of this 

section. 

(c) Visible emissions. The owner or 

operator shall specify the smokeless 

design capacity of each flare and operate 

with no visible emissions, except for 

periods not to exceed a total of 5 

minutes during any 2 consecutive 

hours, when regulated material is routed 

to the flare and the flare vent gas flow 

rate is less than the smokeless design 

capacity of the flare. The owner or 

operator shall monitor for visible 

emissions from the flare as specified in 

paragraph (h) of this section. 

(d) Flare tip velocity. For each flare, 

the owner or operator shall comply with 

either paragraph (d)(1) or (2) of this 

section, provided the appropriate 

monitoring systems are in-place, 

whenever regulated material is routed to 

the flare for at least 15-minutes and the 

flare vent gas flow rate is less than the 

smokeless design capacity of the flare. 

(1) Except as provided in paragraph 

(d)(2) of this section, the actual flare tip 

velocity (Vtip) must be less than 60 feet 

per second. The owner or operator shall 

monitor Vtipusing the procedures 

specified in paragraphs (i) and (k) of this 

section. 

(2) Vtip must be less than 400 feet per 

second and also less than the maximum 

allowed flare tip velocity (Vmax) as 

calculated according to the following 

equation. The owner or operator shall 

monitor Vtip using the procedures 

specified in paragraphs (i) and (k) of this 

section and monitor gas composition 

and determine NHVvg using the 

procedures specified in paragraphs (j) 

and (l) of this section. 

Where: 

Vmax = Maximum allowed flare tip velocity, 

ft/sec. 

NHVvg = Net heating value of flare vent gas, 

as determined by paragraph (l)(4) of this 

section, Btu/scf. 

1,212 = Constant. 

850 = Constant. 

(e) Combustion zone operating limits. 

For each flare, the owner or operator 

shall operate the flare to maintain the 

net heating value of flare combustion 

zone gas (NHVcz) at or above 270 British 

thermal units per standard cubic feet 

(Btu/scf) determined on a 15-minute 

block period basis when regulated 

material is routed to the flare for at least 

15-minutes. The owner or operator shall 

monitor and calculate NHVcz as 

specified in paragraph (m) of this 

section. 

(f) Dilution operating limits for flares 

with perimeter assist air. For each flare 

actively receiving perimeter assist air, 

the owner or operator shall operate the 

flare to maintain the net heating value 

dilution parameter (NHVdil) at or above 

22 British thermal units per square foot 

(Btu/ft2) determined on a 15-minute 

block period basis when regulated 

material is being routed to the flare for 

at least 15-minutes. The owner or 

operator shall monitor and calculate 

NHVdil as specified in paragraph (n) of 

this section. 


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(g) Pilot flame monitoring. The owner 

or operator shall continuously monitor 

the presence of the pilot flame(s) using 

a device (including, but not limited to, 

a thermocouple, ultraviolet beam 

sensor, or infrared sensor) capable of 

detecting that the pilot flame(s) is 

present. 

(h) Visible emissions monitoring. The 

owner or operator shall monitor visible 

emissions while regulated materials are 

vented to the flare. An initial visible 

emissions demonstration must be 

conducted using an observation period 

of 2 hours using Method 22 at 40 CFR 

part 60, appendix A–7. Subsequent 

visible emissions observations must be 

conducted using either the methods in 

paragraph (h)(1) of this section or, 

alternatively, the methods in paragraph 

(h)(2) of this section. The owner or 

operator must record and report any 

instances where visible emissions are 

observed for more than 5 minutes 

during any 2 consecutive hours as 

specified in § 63.655(g)(11)(ii). 

(1) At least once per day, conduct 

visible emissions observations using an 

observation period of 5 minutes using 

Method 22 at 40 CFR part 60, appendix 

A–7. If at any time the owner or 

operator sees visible emissions, even if 

the minimum required daily visible 

emission monitoring has already been 

performed, the owner or operator shall 

immediately begin an observation 

period of 5 minutes using Method 22 at 

40 CFR part 60, appendix A–7. If visible 

emissions are observed for more than 

one continuous minute during any 5- 

minute observation period, the 

observation period using Method 22 at 

40 CFR part 60, appendix A–7 must be 

extended to 2 hours or until 5-minutes 

of visible emissions are observed. 

(2) Use a video surveillance camera to 

continuously record (at least one frame 

every 15 seconds with time and date 

stamps) images of the flare flame and a 

reasonable distance above the flare 

flame at an angle suitable for visual 

emissions observations. The owner or 

operator must provide real-time video 

surveillance camera output to the 

control room or other continuously 

manned location where the camera 

images may be viewed at any time. 

(i) Flare vent gas, steam assist and air 

assist flow rate monitoring. The owner 

or operator shall install, operate, 

calibrate, and maintain a monitoring 

system capable of continuously 

measuring, calculating, and recording 

the volumetric flow rate in the flare 

header or headers that feed the flare as 

well as any supplemental natural gas 

used. Different flow monitoring 

methods may be used to measure 

different gaseous streams that make up 

the flare vent gas provided that the flow 

rates of all gas streams that contribute to 

the flare vent gas are determined. If 

assist air or assist steam is used, the 

owner or operator shall install, operate, 

calibrate, and maintain a monitoring 

system capable of continuously 

measuring, calculating, and recording 

the volumetric flow rate of assist air 

and/or assist steam used with the flare. 

If pre-mix assist air and perimeter assist 

are both used, the owner or operator 

shall install, operate, calibrate, and 

maintain a monitoring system capable of 

separately measuring, calculating, and 

recording the volumetric flow rate of 

premix assist air and perimeter assist air 

used with the flare. Continuously 

monitoring fan speed or power and 

using fan curves is an acceptable 

method for continuously monitoring 

assist air flow rates. 

(1) The flow rate monitoring systems 

must be able to correct for the 

temperature and pressure of the system 

and output parameters in standard 

conditions (i.e., a temperature of 20 °C 

(68 °F) and a pressure of 1 atmosphere). 

(2) Mass flow monitors may be used 

for determining volumetric flow rate of 

flare vent gas provided the molecular 

weight of the flare vent gas is 

determined using compositional 

analysis as specified in paragraph (j) of 

this section so that the mass flow rate 

can be converted to volumetric flow at 

standard conditions using the following 

equation. 

Where: 

Qvol = Volumetric flow rate, standard cubic 

feet per second. 

Qmass = Mass flow rate, pounds per second. 

385.3 = Conversion factor, standard cubic 

feet per pound-mole. 

MWt = Molecular weight of the gas at the 

flow monitoring location, pounds per 

pound-mole. 

(3) Mass flow monitors may be used 

for determining volumetric flow rate of 

assist air or assist steam. Use equation 

in paragraph (i)(2) of this section to 

convert mass flow rates to volumetric 

flow rates. Use a molecular weight of 18 

pounds per pound-mole for assist steam 

and use a molecular weight of 29 

pounds per pound-mole for assist air. 

(4) Continuous pressure/temperature 

monitoring system(s) and appropriate 

engineering calculations may be used in 

lieu of a continuous volumetric flow 

monitoring systems provided the 

molecular weight of the gas is known. 

For assist steam, use a molecular weight 

of 18 pounds per pound-mole. For assist 

air, use a molecular weight of 29 pounds 

per pound-mole. For flare vent gas, 

molecular weight must be determined 

using compositional analysis as 

specified in paragraph (j) of this section. 

(j) Flare vent gas composition 

monitoring. The owner or operator shall 

determine the concentration of 

individual components in the flare vent 

gas using either the methods provided 

in paragraph (j)(1) or (2) of this section, 

to assess compliance with the operating 

limits in paragraph (e) of this section 

and, if applicable, paragraphs (d) and (f) 

of this section. Alternatively, the owner 

or operator may elect to directly monitor 

the net heating value of the flare vent 

gas following the methods provided in 

paragraphs (j)(3) of this section and, if 

desired, may directly measure the 

hydrogen concentration in the flare vent 

gas following the methods provided in 

paragraphs (j)(4) of this section. The 

owner or operator may elect to use 

different monitoring methods for 

different gaseous streams that make up 

the flare vent gas using different 

methods provided the composition or 

net heating value of all gas streams that 

contribute to the flare vent gas are 

determined. 

(1) Except as provided in paragraphs 

(j)(5) and (6) of this section, the owner 

or operator shall install, operate, 

calibrate, and maintain a monitoring 

system capable of continuously 

measuring (i.e., at least once every 15- 

minutes), calculating, and recording the 

individual component concentrations 

present in the flare vent gas. 

(2) Except as provided in paragraphs 

(j)(5) and (6) of this section, the owner 

or operator shall install, operate, and 

maintain a grab sampling system 

capable of collecting an evacuated 

canister sample for subsequent 

compositional analysis at least once 

every eight hours while there is flow of 

regulated material to the flare. 

Subsequent compositional analysis of 

the samples must be performed 

according to Method 18 of 40 CFR part 

60, appendix A–6, ASTM D6420–99 

(Reapproved 2010), ASTM D1945–03 

(Reapproved 2010), ASTM D1945–14 or 

ASTM UOP539–12 (all incorporated by 

reference—see § 63.14). 

(3) Except as provided in paragraphs 

(j)(5) and (6) of this section, the owner 

or operator shall install, operate, 

calibrate, and maintain a calorimeter 

capable of continuously measuring, 

calculating, and recording NHVvg at 

standard conditions. 

(4) If the owner or operator uses a 

continuous net heating value monitor 

according to paragraph (j)(3) of this 

section, the owner or operator may, at 

their discretion, install, operate, 

calibrate, and maintain a monitoring 


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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) of this 

section. 

(i) The owner or operator shall submit 

to the Administrator a written 

application for an exemption from 

monitoring. The application must 

contain the following information: 

(A) A description of the flare gas 

stream/system to be considered, 

including submission of a portion of the 

appropriate piping diagrams indicating 

the boundaries of the flare gas stream/ 

system and the affected flare(s) to be 

considered; 

(B) A statement that there are no 

crossover or entry points to be 

introduced into the flare gas stream/

system (this should be shown in the 

piping diagrams) prior to the point 

where the flow rate of the gas streams 

is measured; 

(C) An explanation of the conditions 

that ensure that the flare gas net heating 

value is consistent and, if flare gas net 

heating value is expected to vary (e.g., 

due to product loading of different 

material), the conditions expected to 

produce the flare gas with the lowest net 

heating value; 

(D) The supporting test results from 

sampling the requested flare gas stream/ 

system for the net heating value. 

Sampling data must include, at 

minimum, 2 weeks of daily 

measurement values (14 grab samples) 

for frequently operated flare gas 

streams/systems; for infrequently 

operated flare gas streams/systems, 

seven grab samples must be collected 

unless other additional information 

would support reduced sampling. If the 

flare gas stream composition can vary, 

samples must be taken during those 

conditions expected to result in lowest 

net heating value identified in 

paragraph (j)(6)(i)(C) of this section. The 

owner or operator shall determine net 

heating value for the gas stream using 

either gas composition analysis or net 

heating value monitor (with optional 

hydrogen concentration analyzer) 

according to the method provided in 

paragraph (l) of this section; and 

(E) A description of how the 2 weeks 

(or seven samples for infrequently 

operated flare gas streams/systems) of 

monitoring results compares to the 

typical range of net heating values 

expected for the flare gas stream/system 

going to the affected flare (e.g., ‘‘the 

samples are representative of typical 

operating conditions of the flare gas 

stream going to the loading rack flare’’ 

or ‘‘the samples are representative of 

conditions expected to yield the lowest 

net heating value of the flare gas stream 

going to the loading rack flare’’). 

(F) The net heating value to be used 

for all flows of the flare vent gas from 

the flare gas stream/system covered in 

the application. A single net heating 

value must be assigned to the flare vent 

gas either by selecting the lowest net 

heating value measured in the sampling 

program or by determining the 95th 

percent confidence interval on the mean 

value of all samples collected using the 

t-distribution statistic (which is 1.943 

for 7 grab samples or 1.771 for 14 grab 

samples). 

(ii) The effective date of the 

exemption is the date of submission of 

the information required in paragraph 

(j)(6)(i) of this section. 

(iii) No further action is required 

unless refinery operating conditions 

change in such a way that affects the 

exempt fuel gas stream/system (e.g., the 

stream composition changes). If such a 

change occurs, the owner or operator 

shall follow the procedures in paragraph 

(j)(6)(iii)(A), (B), or (C) of this section. 

(A) If the operation change results in 

a flare vent gas net heating value that is 

still within the range of net heating 

values included in the original 

application, the owner or operator shall 

determine the net heating value on a 

grab sample and record the results as 

proof that the net heating value assigned 

to the vent gas stream in the original 

application is still appropriate. 

(B) If the operation change results in 

a flare vent gas net heating value that is 

lower than the net heating value 

assigned to the vent gas stream in the 

original application, the owner or 

operator may submit new information 

following the procedures of paragraph 

(j)(6)(i) of this section within 60 days (or 

within 30 days after the seventh grab 

sample is tested for infrequently 

operated process units). 

(C) If the operation change results in 

a flare vent gas net heating value has 

greater variability in the flare gas 

stream/system such the owner or 

operator chooses not to submit new 

information to support an exemption, 

the owner or operator must begin 

monitoring the composition or net heat 

content of the flare vent gas stream 

using the methods in this section (i.e., 

grab samples every 8 hours until such 

time a continuous monitor, if elected, is 

installed). 

(k) Calculation methods for 

cumulative flow rates and determining 

compliance with Vtip operating limits. 

The owner or operator shall determine 

Vtip on a 15-minute block average basis 

according to the following requirements. 

(1) The owner or operator shall use 

design and engineering principles to 

determine the unobstructed cross 

sectional area of the flare tip. The 

unobstructed cross sectional area of the 

flare tip is the total tip area that vent gas 

can pass through. This area does not 

include any stability tabs, stability rings, 

and upper steam or air tubes because 

flare vent gas does not exit through 

them. 

(2) The owner or operator shall 

determine the cumulative volumetric 

flow of flare vent gas for each 15-minute 

block average period using the data from 

the continuous flow monitoring system 

required in paragraph (i) of this section 

according to the following requirements, 

as applicable. If desired, the cumulative 

flow rate for a 15-minute block period 

only needs to include flow during those 

periods when regulated material is sent 

to the flare, but owners or operators may 

elect to calculate the cumulative flow 

rates across the entire 15-minute block 

period for any 15-minute block period 

where there is regulated material flow to 

the flare. 

(i) Use set 15-minute time periods 

starting at 12 midnight to 12:15 a.m., 

12:15 a.m. to 12:30 a.m. and so on 

concluding at 11:45 p.m. to midnight 

when calculating 15-minute block 

average flow volumes. 

(ii) If continuous pressure/

temperature monitoring system(s) and 

engineering calculations are used as 

allowed under paragraph (i)(4) of this 

section, the owner or operator shall, at 

a minimum, determine the 15-minute 

block average temperature and pressure 

from the monitoring system and use 

those values to perform the engineering 

calculations to determine the 

cumulative flow over the 15-minute 

block average period. Alternatively, the 

owner or operator may divide the 15- 

minute block average period into equal 

duration subperiods (e.g., three 5- 

minute periods) and determine the 

average temperature and pressure for 

each subperiod, perform engineering 

calculations to determine the flow for 

each subperiod, then add the volumetric 


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flows for the subperiods to determine 

the cumulative volumetric flow of vent 

gas for the 15-minute block average 

period. 

(3) The 15-minute block average Vtip

shall be calculated using the following 

equation. 

Where: 

Vtip = Flare tip velocity, feet per second. 

Qcum = Cumulative volumetric flow over 15- 

minute block average period, actual 

cubic feet. 

Area = Unobstructed area of the flare tip, 

square feet. 

900 = Conversion factor, seconds per 15- 

minute block average. 

(4) If the owner or operator chooses to 

comply with paragraph (d)(2) of this 

section, the owner or operator shall also 

determine the net heating value of the 

flare vent gas following the 

requirements in paragraphs (j) and (l) of 

this section and calculate Vmax using the 

equation in paragraph (d)(2) of this 

section in order to compare Vtip to Vmax

on a 15-minute block average basis. 

(l) Calculation methods for 

determining flare vent gas net heating 

value. The owner or operator shall 

determine the net heating value of the 

flare vent gas (NHVvg) based on the 

composition monitoring data on a 15- 

minute block average basis according to 

the following requirements. 

(1) If compositional analysis data are 

collected as provided in paragraph (j)(1) 

or (2) of this section, the owner or 

operator shall determine NHVvg of a 

specific sample by using the following 

equation. 

Where: 

NHVvg = Net heating value of flare vent gas, 

Btu/scf. 

i = Individual component in flare vent gas. 

n = Number of components in flare vent gas. 

xi = Concentration of component i in flare 

vent gas, volume fraction. 

NHVi = Net heating value of component i 

according to table 12 of this subpart, Btu/ 

scf. If the component is not specified in 

table 12 of this subpart, the heats of 

combustion may be determined using 

any published values where the net 

enthalpy per mole of offgas is based on 

combustion at 25 °C and 1 atmosphere 

(or constant pressure) with offgas water 

in the gaseous state, but the standard 

temperature for determining the volume 

corresponding to one mole of vent gas is 

20 °C. 

(2) If direct net heating value 

monitoring data are collected as 

provided in paragraph (j)(3) of this 

section but a hydrogen concentration 

monitor is not used, the owner or 

operator shall use the direct output of 

the monitoring system(s) (in Btu/scf) to 

determine the NHVvg for the sample. 

(3) If direct net heating value 

monitoring data are collected as 

provided in paragraph (j)(3) of this 

section and hydrogen concentration 

monitoring data are collected as 

provided in paragraph (j)(4) of this 

section, the owner or operator shall use 

the following equation to determine 

NHVvg for each sample measured via the 

net heating value monitoring system. 

NHVvg = NHVmeasured + 938xH2

Where: 

NHVvg = Net heating value of flare vent gas, 

Btu/scf. 

NHVmeasured = Net heating value of flare vent 

gas stream as measured by the 

continuous net heating value monitoring 

system, Btu/scf. 

xH2 = Concentration of hydrogen in flare vent 

gas at the time the sample was input into 

the net heating value monitoring system, 

volume fraction. 

938 = Net correction for the measured 

heating value of hydrogen (1,212 ¥ 274), 

Btu/scf. 

(4) Use set 15-minute time periods 

starting at 12 midnight to 12:15 a.m., 

12:15 a.m. to 12:30 a.m. and so on 

concluding at 11:45 p.m. to midnight 

when calculating 15-minute block 

averages. 

(5) When a continuous monitoring 

system is used as provided in paragraph 

(j)(1) or (3) of this section and, if 

applicable, paragraph (j)(4) of this 

section, the owner or operator may elect 

to determine the 15-minute block 

average NHVvg using either the 

calculation methods in paragraph 

(l)(5)(i) of this section or the calculation 

methods in paragraph (l)(5)(ii) of this 

section. The owner or operator may 

choose to comply using the calculation 

methods in paragraph (l)(5)(i) of this 

section for some flares at the petroleum 

refinery and comply using the 

calculation methods (l)(5)(ii) of this 

section for other flares. However, for 

each flare, the owner or operator must 

elect one calculation method that will 

apply at all times, and use that method 

for all continuously monitored flare 

vent streams associated with that flare. 

If the owner or operator intends to 

change the calculation method that 

applies to a flare, the owner or operator 

must notify the Administrator 30 days 

in advance of such a change. 

(i) Feed-forward calculation method. 

When calculating NHVvg for a specific 

15-minute block: 

(A) Use the results from the first 

sample collected during an event, (for 

periodic flare vent gas flow events) for 

the first 15-minute block associated 

with that event. 

(B) If the results from the first sample 

collected during an event (for periodic 

flare vent gas flow events) are not 

available until after the second 15- 

minute block starts, use the results from 

the first sample collected during an 

event for the second 15-minute block 

associated with that event. 

(C) For all other cases, use the results 

that are available from the most recent 

sample prior to the 15-minute block 

period for that 15-minute block period 

for all flare vent gas steams. For the 

purpose of this requirement, use the 

time that the results become available 

rather than the time the sample was 

collected. For example, if a sample is 

collected at 12:25 a.m. and the analysis 

is completed at 12:38 a.m., the results 

are available at 12:38 a.m. and these 

results would be used to determine 

compliance during the 15-minute block 

period from 12:45 a.m. to 1:00 a.m. 

(ii) Direct calculation method. When 

calculating NHVvg for a specific 15- 

minute block: 

(A) If the results from the first sample 

collected during an event (for periodic 

flare vent gas flow events) are not 

available until after the second 15- 

minute block starts, use the results from 

the first sample collected during an 

event for the first 15-minute block 

associated with that event. 

(B) For all other cases, use the 

arithmetic average of all NHVvg

measurement data results that become 

available during a 15-minute block to 

calculate the 15-minute block average 

for that period. For the purpose of this 

requirement, use the time that the 

results become available rather than the 

time the sample was collected. For 

example, if a sample is collected at 

12:25 a.m. and the analysis is completed 

at 12:38 a.m., the results are available at 

12:38 a.m. and these results would be 

used to determine compliance during 

the 15-minute block period from 12:30 

a.m. to 12:45 a.m. 

(6) When grab samples are used to 

determine flare vent gas composition: 

(i) Use the analytical results from the 

first grab sample collected for an event 

for all 15-minute periods from the start 

of the event through the 15-minute 

block prior to the 15-minute block in 

which a subsequent grab sample is 

collected. 

(ii) Use the results from subsequent 

grab sampling events for all 15 minute 

periods starting with the 15-minute 

block in which the sample was collected 

and ending with the 15-minute block 

prior to the 15-minute block in which 

the next grab sample is collected. For 


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the purpose of this requirement, use the 

time the sample was collected rather 

than the time the analytical results 

become available. 

(7) If the owner or operator monitors 

separate gas streams that combine to 

comprise the total flare vent gas flow, 

the 15-minute block average net heating 

value shall be determined separately for 

each measurement location according to 

the methods in paragraphs (l)(1) through 

(6) of this section and a flow-weighted 

average of the gas stream net heating 

values shall be used to determine the 

15-minute block average net heating 

value of the cumulative flare vent gas. 

(m) Calculation methods for 

determining combustion zone net 

heating value. The owner or operator 

shall determine the net heating value of 

the combustion zone gas (NHVcz) as 

specified in paragraph (m)(1) or (2) of 

this section, as applicable. 

(1) Except as specified in paragraph 

(m)(2) of this section, determine the 15- 

minute block average NHVcz based on 

the 15-minute block average vent gas 

and assist gas flow rates using the 

following equation. For periods when 

there is no assist steam flow or premix 

assist air flow, NHVcz = NHVvg. 

Where: 

NHVcz = Net heating value of combustion 

zone gas, Btu/scf. 

NHVvg = Net heating value of flare vent gas 

for the 15-minute block period, Btu/scf. 

Qvg = Cumulative volumetric flow of flare 

vent gas during the 15-minute block 

period, scf. 

Qs = Cumulative volumetric flow of total 

steam during the 15-minute block 

period, scf. 

Qa,premix = Cumulative volumetric flow of 

premix assist air during the 15-minute 

block period, scf. 

(2) Owners or operators of flares that 

use the feed-forward calculation 

methodology in paragraph (l)(5)(i) of 

this section and that monitor gas 

composition or net heating value in a 

location representative of the 

cumulative vent gas stream and that 

directly monitor supplemental natural 

gas flow additions to the flare must 

determine the 15-minute block average 

NHVcz using the following equation. 

Where: 

NHVcz = Net heating value of combustion 

zone gas, Btu/scf. 

NHVvg = Net heating value of flare vent gas 

for the 15-minute block period, Btu/scf. 

Qvg = Cumulative volumetric flow of flare 

vent gas during the 15-minute block 

period, scf. 

QNG2 = Cumulative volumetric flow of 

supplemental natural gas to the flare 

during the 15-minute block period, scf. 

QNG1 = Cumulative volumetric flow of 

supplemental natural gas to the flare 

during the previous 15-minute block 

period, scf. For the first 15-minute block 

period of an event, use the volumetric 

flow value for the current 15-minute 

block period, i.e., QNG1=QNG2. 

NHVNG = Net heating value of supplemental 

natural gas to the flare for the 15-minute 

block period determined according to the 

requirements in paragraph (j)(5) of this 

section, Btu/scf. 

Qs = Cumulative volumetric flow of total 

steam during the 15-minute block 

period, scf. 

Qa,premix = Cumulative volumetric flow of 

premix assist air during the 15-minute 

block period, scf. 

(n) Calculation methods for 

determining the net heating value 

dilution parameter. The owner or 

operator shall determine the net heating 

value dilution parameter (NHVdil) as 

specified in paragraph (n)(1) or (2) of 

this section, as applicable. 

(1) Except as specified in paragraph 

(n)(2) of this section, determine the 15- 

minute block average NHVdil based on 

the 15-minute block average vent gas 

and perimeter assist air flow rates using 

the following equation only during 

periods when perimeter assist air is 

used. For 15-minute block periods when 

there is no cumulative volumetric flow 

of perimeter assist air, the 15-minute 

block average NHVdil parameter does not 

need to be calculated. 

Where: 

NHVdil = Net heating value dilution 

parameter, Btu/ft2. 

NHVvg = Net heating value of flare vent gas 

determined for the 15-minute block 

period, Btu/scf. 

Qvg = Cumulative volumetric flow of flare 

vent gas during the 15-minute block 

period, scf. 

Diam = Effective diameter of the 

unobstructed area of the flare tip for flare 

vent gas flow, ft. Use the area as 

determined in paragraph (k)(1) of this 

section and determine the diameter as 

Qs = Cumulative volumetric flow of total 

steam during the 15-minute block 

period, scf. 

Qa,premix = Cumulative volumetric flow of 

premix assist air during the 15-minute 

block period, scf. 

Qa,perimeter = Cumulative volumetric flow of 

perimeter assist air during the 15-minute 

block period, scf. 

(2) Owners or operators of flares that 

use the feed-forward calculation 

methodology in paragraph (l)(5)(i) of 

this section and that monitor gas 

composition or net heating value in a 

location representative of the 

cumulative vent gas stream and that 

directly monitor supplemental natural 

gas flow additions to the flare must 

determine the 15-minute block average 

NHVdil using the following equation 

only during periods when perimeter 

assist air is used. For 15-minute block 

periods when there is no cumulative 


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volumetric flow of perimeter assist air, 

the 15-minute block average NHVdil

parameter does not need to be 

calculated. 

Where: 

NHVdil = Net heating value dilution 

parameter, Btu/ft2. 

NHVvg = Net heating value of flare vent gas 

determined for the 15-minute block 

period, Btu/scf. 

Qvg = Cumulative volumetric flow of flare 

vent gas during the 15-minute block 

period, scf. 

QNG2 = Cumulative volumetric flow of 

supplemental natural gas to the flare 

during the 15-minute block period, scf. 

QNG1 = Cumulative volumetric flow of 

supplemental natural gas to the flare 

during the previous 15-minute block 

period, scf. For the first 15-minute block 

period of an event, use the volumetric 

flow value for the current 15-minute 

block period, i.e., QNG1 =QNG2. 

NHVNG = Net heating value of supplemental 

natural gas to the flare for the 15-minute 

block period determined according to the 

requirements in paragraph (j)(5) of this 

section, Btu/scf. 

Diam = Effective diameter of the 

unobstructed area of the flare tip for flare 

vent gas flow, ft. Use the area as 

determined in paragraph (k)(1) of this 

section and determine the diameter as 

Qs = Cumulative volumetric flow of total 

steam during the 15-minute block 

period, scf. 

Qa,premix = Cumulative volumetric flow of 

premix assist air during the 15-minute 

block period, scf. 

Qa,perimeter = Cumulative volumetric flow of 

perimeter assist air during the 15-minute 

block period, scf. 

(o) Emergency flaring provisions. The 

owner or operator of a flare that has the 

potential to operate above its smokeless 

capacity under any circumstance shall 

comply with the provisions in 

paragraphs (o)(1) through (8) of this 

section. 

(1) Develop a flare management plan 

to minimize flaring during periods of 

startup, shutdown, or emergency 

releases. The flare management plan 

must include the information described 

in paragraphs (o)(1)(i) through (vii) of 

this section. 

(i) A listing of all refinery process 

units, ancillary equipment, and fuel gas 

systems connected to the flare for each 

affected flare. 

(ii) An assessment of whether 

discharges to affected flares from these 

process units, ancillary equipment and 

fuel gas systems can be minimized or 

prevented during periods of startup, 

shutdown, or emergency releases. The 

flare minimization assessment must (at 

a minimum) consider the items in 

paragraphs (o)(1)(ii)(A) through (C) of 

this section. The assessment must 

provide clear rationale in terms of costs 

(capital and annual operating), natural 

gas offset credits (if applicable), 

technical feasibility, secondary 

environmental impacts and safety 

considerations for the selected 

minimization alternative(s) or a 

statement, with justifications, that flow 

reduction could not be achieved. Based 

upon the assessment, each owner or 

operator of an affected flare shall 

identify the minimization alternatives 

that it has implemented by the due date 

of the flare management plan and shall 

include a schedule for the prompt 

implementation of any selected 

measures that cannot reasonably be 

completed as of that date. 

(A) Modification in startup and 

shutdown procedures to reduce the 

quantity of process gas discharge to the 

flare. 

(B) Implementation of prevention 

measures listed for pressure relief 

devices in § 63.648(j)(5) for each 

pressure relief valve that can discharge 

to the flare. 

(C) Installation of a flare gas recovery 

system or, for facilities that are fuel gas 

rich, a flare gas recovery system and a 

co-generation unit or combined heat and 

power unit. 

(iii) A description of each affected 

flare containing the information in 

paragraphs (o)(1)(iii)(A) through (G) of 

this section. 

(A) A general description of the flare, 

including whether it is a ground flare or 

elevated (including height), the type of 

assist system (e.g., air, steam, pressure, 

non-assisted), whether the flare is used 

on a routine basis or if it is only used 

during periods of startup, shutdown or 

emergency release, and whether the 

flare is equipped with a flare gas 

recovery system. 

(B) The smokeless capacity of the flare 

based on design conditions. Note: A 

single value must be provided for the 

smokeless capacity of the flare. 

(C) The maximum vent gas flow rate 

(hydraulic load capacity). 

(D) The maximum supplemental gas 

flow rate. 

(E) For flares that receive assist steam, 

the minimum total steam rate and the 

maximum total steam rate. 

(F) For flares that receive assist air, an 

indication of whether the fan/blower is 

single speed, multi-fixed speed (e.g., 

high, medium, and low speeds), or 

variable speeds. For fans/blowers with 

fixed speeds, provide the estimated 

assist air flow rate at each fixed speed. 

For variable speeds, provide the design 

fan curve (e.g., air flow rate as a 

function of power input). 

(G) Simple process flow diagram 

showing the locations of the flare 

following components of the flare: Flare 

tip (date installed, manufacturer, 

nominal and effective tip diameter, tip 

drawing); knockout or surge drum(s) or 

pot(s) (including dimensions and design 

capacities); flare header(s) and 

subheader(s); assist system; and ignition 

system. 

(iv) Description and simple process 

flow diagram showing all gas lines 

(including flare waste gas, purge or 

sweep gas (as applicable), supplemental 

gas) that are associated with the flare. 

For purge, sweep, supplemental gas, 

identify the type of gas used. Designate 

which lines are exempt from 

composition or net heating value 

monitoring and why (e.g., natural gas, 

gas streams that have been 

demonstrated to have consistent 

composition, pilot gas). Designate which 

lines are monitored and identify on the 

process flow diagram the location and 

type of each monitor. Designate the 

pressure relief devices that are vented to 

the flare. 

(v) For each flow rate, gas 

composition, net heating value or 

hydrogen concentration monitor 

identified in paragraph (o)(1)(iv) of this 

section, provide a detailed description 

of the manufacturer’s specifications, 

including, but not limited to, make, 

model, type, range, precision, accuracy, 

calibration, maintenance and quality 

assurance procedures. 

(vi) For each pressure relief valve 

vented to the flare identified in 

paragraph (o)(1)(iv) of this section, 

provide a detailed description of each 

pressure release valve, including type of 

relief device (rupture disc, valve type) 

diameter of the relief valve, set pressure 

of the relief valve and listing of the 

prevention measures implemented. This 


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information may be maintained in an 

electronic database on-site and does not 

need to be submitted as part of the flare 

management plan unless requested to 

do so by the Administrator. 

(vii) Procedures to minimize or 

eliminate discharges to the flare during 

the planned startup and shutdown of 

the refinery process units and ancillary 

equipment that are connected to the 

affected flare, together with a schedule 

for the prompt implementation of any 

procedures that cannot reasonably be 

implemented as of the date of the 

submission of the flare management 

plan. 

(2) Each owner or operator required to 

develop and implement a written flare 

management plan as described in 

paragraph (o)(1) of this section must 

submit the plan to the Administrator as 

described in paragraphs (o)(2)(i) through 

(iii) of this section. 

(i) The owner or operator must 

develop and implement the flare 

management plan no later than January 

30, 2019 or at startup for a new flare that 

commenced construction on or after 

February 1, 2016. 

(ii) The owner or operator must 

comply with the plan as submitted by 

the date specified in paragraph (o)(2)(i) 

of this section. The plan should be 

updated periodically to account for 

changes in the operation of the flare, 

such as new connections to the flare or 

the installation of a flare gas recovery 

system, but the plan need be resubmitted to the Administrator only if 

the owner or operator alters the design 

smokeless capacity of the flare. The 

owner or operator must comply with the 

updated plan as submitted. 

(iii) All versions of the plan submitted 

to the Administrator shall also be 

submitted to the following address: U.S. 

Environmental Protection Agency, 

Office of Air Quality Planning and 

Standards, Sector Policies and Programs 

Division, U.S. EPA Mailroom (E143–01), 

Attention: Refinery Sector Lead, 109 

T.W. Alexander Drive, Research 

Triangle Park, NC 27711. Electronic 

copies in lieu of hard copies may also 

be submitted to refineryRTR@epa.gov. 

(3) The owner or operator of a flare 

subject to this subpart shall conduct a 

root cause analysis and a corrective 

action analysis for each flow event that 

contains regulated material and that 

meets either the criteria in paragraph 

(o)(3)(i) or (ii) of this section. 

(i) The vent gas flow rate exceeds the 

smokeless capacity of the flare and 

visible emissions are present from the 

flare for more than 5 minutes during any 

2 consecutive hours during the release 

event. 

(ii) The vent gas flow rate exceeds the 

smokeless capacity of the flare and the 

15-minute block average flare tip 

velocity exceeds the maximum flare tip 

velocity determined using the methods 

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

(4) A root cause analysis and 

corrective action analysis must be 

completed as soon as possible, but no 

later than 45 days after a flare flow 

event meeting the criteria in paragraph 

(o)(3)(i) or (ii) of this section. Special 

circumstances affecting the number of 

root cause analyses and/or corrective 

action analyses are provided in 

paragraphs (o)(4)(i) through (v) of this 

section. 

(i) You may conduct a single root 

cause analysis and corrective action 

analysis for a single continuous flare 

flow event that meets both of the criteria 

in paragraphs (o)(3)(i) and (ii) of this 

section. 

(ii) You may conduct a single root 

cause analysis and corrective action 

analysis for a single continuous flare 

flow event regardless of the number of 

15-minute block periods in which the 

flare tip velocity was exceeded or the 

number of 2 hour periods that contain 

more the 5 minutes of visible emissions. 

(iii) You may conduct a single root 

cause analysis and corrective action 

analysis for a single event that causes 

two or more flares that are operated in 

series (i.e., cascaded flare systems) to 

have a flow event meeting the criteria in 

paragraph (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 paragraph 

(o)(3)(i) or (ii) of this section, regardless 

of the configuration of the flares, if the 

root cause is reasonably expected to be 

a force majeure event, as defined in this 

subpart. 

(v) Except as provided in paragraphs 

(o)(4)(iii) and (iv) of this section, if more 

than one flare has a flow event that 

meets the criteria in paragraph (o)(3)(i) 

or (ii) of this section during the same 

time period, an initial root cause 

analysis shall be conducted separately 

for each flare that has a flow event 

meeting the criteria in paragraph 

(o)(3)(i) or (ii) of this section. If the 

initial root cause analysis indicates that 

the flow events have the same root 

cause(s), the initially separate root cause 

analyses may be recorded as a single 

root cause analysis and a single 

corrective action analysis may be 

conducted. 

(5) Each owner or operator of a flare 

required to conduct a root cause 

analysis and corrective action analysis 

as specified in paragraphs (o)(3) and (4) 

of this section shall implement the 

corrective action(s) identified in the 

corrective action analysis in accordance 

with the applicable requirements in 

paragraphs (o)(5)(i) through (iii) of this 

section. 

(i) All corrective action(s) must be 

implemented within 45 days of the 

event for which the root cause and 

corrective action analyses were required 

or as soon thereafter as practicable. If an 

owner or operator concludes that no 

corrective action should be 

implemented, the owner or operator 

shall record and explain the basis for 

that conclusion no later than 45 days 

following the event. 

(ii) For corrective actions that cannot 

be fully implemented within 45 days 

following the event for which the root 

cause and corrective action analyses 

were required, the owner or operator 

shall develop an implementation 

schedule to complete the corrective 

action(s) as soon as practicable. 

(iii) No later than 45 days following 

the event for which a root cause and 

corrective action analyses were 

required, the owner or operator shall 

record the corrective action(s) 

completed to date, and, for action(s) not 

already completed, a schedule for 

implementation, including proposed 

commencement and completion dates. 

(6) The owner or operator shall 

determine the total number of events for 

which a root cause and corrective action 

analyses was required during the 

calendar year for each affected flare 

separately for events meeting the criteria 

in paragraph (o)(3)(i) of this section and 

those meeting the criteria in paragraph 

(o)(3)(ii) of this section. For the purpose 

of this requirement, a single root cause 

analysis conducted for an event that met 

both of the criteria in paragraphs 

(o)(3)(i) and (ii) of this section would be 

counted as an event under each of the 

separate criteria counts for that flare. 

Additionally, if a single root cause 

analysis was conducted for an event that 

caused multiple flares to meet the 

criteria in paragraph (o)(3)(i) or (ii) of 

this section, that event would count as 

an event for each of the flares for each 

criteria in paragraph (o)(3) of this 

section that was met during that event. 

The owner or operator shall also 

determine the total number of events for 

which a root cause and correct action 

analyses was required and the analyses 

concluded that the root cause was a 

force majeure event, as defined in this 

subpart. 

(7) The following events would be a 

violation of this emergency flaring work 

practice standard. 

(i) Any flow event for which a root 

cause analysis was required and the root 


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cause was determined to be operator 

error or poor maintenance. 

(ii) Two visible emissions exceedance 

events meeting the criteria in paragraph 

(o)(3)(i) of this section that were not 

caused by a force majeure event from a 

single flare in a 3 calendar year period 

for the same root cause for the same 

equipment. 

(iii) Two flare tip velocity exceedance 

events meeting the criteria in paragraph 

(o)(3)(ii) of this section 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) of this section 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) of this section that were not 

caused by a force majeure event from a 

single flare in a 3 calendar year period 

for any reason. 

(p) Flare monitoring records. The 

owner or operator shall keep the records 

specified in § 63.655(i)(9). 

(q) Reporting. The owner or operator 

shall comply with the reporting 

requirements specified in 

§ 63.655(g)(11). 

(r) Alternative means of emissions 

limitation. An owner or operator may 

request approval from the Administrator 

for site-specific operating limits that 

shall apply specifically to a selected 

flare. Site-specific operating limits 

include alternative threshold values for 

the parameters specified in paragraphs 

(d) through (f) of this section as well as 

threshold values for operating 

parameters other than those specified in 

paragraphs (d) through (f) of this 

section. The owner or operator must 

demonstrate that the flare achieves 96.5 

percent combustion efficiency (or 98 

percent destruction efficiency) using the 

site-specific operating limits based on a 

performance evaluation as described in 

paragraph (r)(1) of this section. The 

request shall include information as 

described in paragraph (r)(2) of this 

section. The request shall be submitted 

and followed as described in paragraph 

(r)(3) of this section. 

(1) The owner or operator shall 

prepare and submit a site-specific test 

plan and receive approval of the sitespecific performance evaluation plan 

prior to conducting any flare 

performance evaluation test runs 

intended for use in developing sitespecific operating limits. The sitespecific performance evaluation plan 

shall include, at a minimum, the 

elements specified in paragraphs (r)(1)(i) 

through (ix) of this section. Upon 

approval of the site-specific 

performance evaluation plan, the owner 

or operator shall conduct performance 

evaluation test runs for the flare 

following the procedures described in 

the site-specific performance evaluation 

plan. 

(i) The design and dimensions of the 

flare, flare type (air-assisted only, steamassisted only, air- and steam-assisted, 

pressure-assisted, or non-assisted), and 

description of gas being flared, 

including quantity of gas flared, 

frequency of flaring events (if periodic), 

expected net heating value of flare vent 

gas, minimum total steam assist rate. 

(ii) The operating conditions (vent gas 

compositions, vent gas flow rates and 

assist flow rates, if applicable) likely to 

be encountered by the flare during 

normal operations and the operating 

conditions for the test period. 

(iii) A description of (including 

sample calculations illustrating) the 

planned data reduction and calculations 

to determine the flare combustion or 

destruction efficiency. 

(iv) Site-specific operating parameters 

to be monitored continuously during the 

flare performance evaluation. These 

parameters may include but are not 

limited to vent gas flow rate, steam and/ 

or air assist flow rates, and flare vent gas 

composition. If new operating 

parameters are proposed for use other 

than those specified in paragraphs (d) 

through (f) of this section, an 

explanation of the relevance of the 

proposed operating parameter(s) as an 

indicator of flare combustion 

performance and why the alternative 

operating parameter(s) can adequately 

ensure that the flare achieves the 

required combustion efficiency. 

(v) A detailed description of the 

measurement methods, monitored 

pollutant(s), measurement locations, 

measurement frequency, and recording 

frequency proposed for both emission 

measurements and flare operating 

parameters. 

(vi) A description of (including 

sample calculations illustrating) the 

planned data reduction and calculations 

to determine the flare operating 

parameters. 

(vii) The minimum number and 

length of test runs and range of 

operating values to be evaluated during 

the performance evaluation. A sufficient 

number of test runs shall be conducted 

to identify the point at which the 

combustion/destruction efficiency of the 

flare deteriorates. 

(viii) [Reserved] 

(ix) Test schedule. 

(2) The request for flare-specific 

operating limits shall include sufficient 

and appropriate data, as determined by 

the Administrator, to allow the 

Administrator to confirm that the 

selected site-specific operating limit(s) 

adequately ensures that the flare 

destruction efficiency is 98 percent or 

greater or that the flare combustion 

efficiency is 96.5 percent or greater at all 

times. At a minimum, the request shall 

contain the information described in 

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

section. 

(i) The design and dimensions of the 

flare, flare type (air-assisted only, steamassisted only, air- and steam-assisted, 

pressure-assisted, or non-assisted), and 

description of gas being flared, 

including quantity of gas flared, 

frequency of flaring events (if periodic), 

expected net heating value of flare vent 

gas, minimum total steam assist rate. 

(ii) Results of each performance 

evaluation test run conducted, 

including, at a minimum: 

(A) The measured combustion/

destruction efficiency. 

(B) The measured or calculated 

operating parameters for each test run. 

If operating parameters are calculated, 

the raw data from which the parameters 

are calculated must be included in the 

test report. 

(C) Measurement location 

descriptions for both emission 

measurements and flare operating 

parameters. 

(D) Description of sampling and 

analysis procedures (including number 

and length of test runs) and any 

modifications to standard procedures. If 

there were deviations from the approved 

test plan, a detailed description of the 

deviations and rationale why the test 

results or calculation procedures used 

are appropriate. 

(E) Operating conditions (e.g., vent 

gas composition, assist rates, etc.) that 

occurred during the test. 

(F) Quality assurance procedures. 

(G) Records of calibrations. 

(H) Raw data sheets for field 

sampling. 

(I) Raw data sheets for field and 

laboratory analyses. 

(J) Documentation of calculations. 

(iii) The selected flare-specific 

operating limit values based on the 

performance evaluation test results, 

including the averaging time for the 

operating limit(s), and rationale why the 

selected values and averaging times are 

sufficiently stringent to ensure proper 

flare performance. If new operating 

parameters or averaging times are 

proposed for use other than those 

specified in paragraphs (d) through (f) of 

this section, an explanation of why the 


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alternative operating parameter(s) or 

averaging time(s) adequately ensures the 

flare achieves the required combustion 

efficiency. 

(iv) The means by which the owner or 

operator will document on-going, 

continuous compliance with the 

selected flare-specific operating limit(s), 

including the specific measurement 

location and frequencies, calculation 

procedures, and records to be 

maintained. 

(3) The request shall be submitted as 

described in paragraphs (r)(3)(i) through 

(iv) of this section. 

(i) The owner or operator may request 

approval from the Administrator at any 

time upon completion of a performance 

evaluation conducted following the 

methods in an approved site-specific 

performance evaluation plan for an 

operating limit(s) that shall apply 

specifically to that flare. 

(ii) The request must be submitted to 

the Administrator for approval. The 

owner or operator must continue to 

comply with the applicable standards 

for flares in this subpart until the 

requirements in § 63.6(g)(1) are met and 

a notice is published in the Federal 

Register allowing use of such an 

alternative means of emission 

limitation. 

(iii) The request shall also be 

submitted to the following address: U.S. 

Environmental Protection Agency, 

Office of Air Quality Planning and 

Standards, Sector Policies and Programs 

Division, U.S. EPA Mailroom (E143–01), 

Attention: Refinery Sector Lead, 109 

T.W. Alexander Drive, Research 

Triangle Park, NC 27711. Electronic 

copies in lieu of hard copies may also 

be submitted to refineryrtr@epa.gov. 

(iv) If the Administrator finds any 

deficiencies in the request, the request 

must be revised to address the 

deficiencies and be re-submitted for 

approval within 45 days of receipt of the 

notice of deficiencies. The owner or 

operator must comply with the revised 

request as submitted until it is 

approved. 

(4) The approval process for a request 

for a flare-specific operating limit(s) is 

described in paragraphs (r)(4)(i) through 

(iii) of this section. 

(i) Approval by the Administrator of 

a flare-specific operating limit(s) request 

will be based on the completeness, 

accuracy and reasonableness of the 

request. Factors that the EPA will 

consider in reviewing the request for 

approval include, but are not limited to, 

those described in paragraphs 

(r)(4)(i)(A) through (C) of this section. 

(A) The description of the flare design 

and operating characteristics. 

(B) If a new operating parameter(s) 

other than those specified in paragraphs 

(d) through (f) of this section is 

proposed, the explanation of how the 

proposed operating parameter(s) serves 

a good indicator(s) of flare combustion 

performance. 

(C) The results of the flare 

performance evaluation test runs and 

the establishment of operating limits 

that ensures that the flare destruction 

efficiency is 98 percent or greater or that 

the flare combustion efficiency is 96.5 

percent or greater at all times. 

(D) The completeness of the flare 

performance evaluation test report. 

(ii) If the request is approved by the 

Administrator, a flare-specific operating 

limit(s) will be established at the level(s) 

demonstrated in the approved request. 

(iii) If the Administrator finds any 

deficiencies in the request, the request 

must be revised to address the 

deficiencies and be re-submitted for 

approval. 

■ 33. Section 63.671 is added to read as 

follows: 

§ 63.671 Requirements for flare monitoring 

systems. 

(a) Operation of CPMS. For each 

CPMS installed to comply with 

applicable provisions in § 63.670, the 

owner or operator shall install, operate, 

calibrate, and maintain the CPMS as 

specified in paragraphs (a)(1) through 

(8) of this section. 

(1) Except for CPMS installed for pilot 

flame monitoring, all monitoring 

equipment must meet the applicable 

minimum accuracy, calibration and 

quality control requirements specified 

in table 13 of this subpart. 

(2) The owner or operator shall ensure 

the readout (that portion of the CPMS 

that provides a visual display or record) 

or other indication of the monitored 

operating parameter from any CPMS 

required for compliance is readily 

accessible onsite for operational control 

or inspection by the operator of the 

source. 

(3) All CPMS must complete a 

minimum of one cycle of operation 

(sampling, analyzing and data 

recording) for each successive 15- 

minute period. 

(4) Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions 

and required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments), the owner or operator 

shall operate all CPMS and collect data 

continuously at all times when 

regulated emissions are routed to the 

flare. 

(5) The owner or operator shall 

operate, maintain, and calibrate each 

CPMS according to the CPMS 

monitoring plan specified in paragraph 

(b) of this section. 

(6) For each CPMS except for CPMS 

installed for pilot flame monitoring, the 

owner or operator shall comply with the 

out-of-control procedures described in 

paragraph (c) of this section. 

(7) The owner or operator shall reduce 

data from a CPMS as specified in 

paragraph (d) of this section. 

(8) The CPMS must be capable of 

measuring the appropriate parameter 

over the range of values expected for 

that measurement location. The data 

recording system associated with each 

CPMS must have a resolution that is 

equal to or better than the required 

system accuracy. 

(b) CPMS monitoring plan. The owner 

or operator shall develop and 

implement a CPMS quality control 

program documented in a CPMS 

monitoring plan that covers each flare 

subject to the provisions in § 63.670 and 

each CPMS installed to comply with 

applicable provisions in § 63.670. The 

owner or operator shall have the CPMS 

monitoring plan readily available onsite at all times and shall submit a copy 

of the CPMS monitoring plan to the 

Administrator upon request by the 

Administrator. The CPMS monitoring 

plan must contain the information listed 

in paragraphs (b)(1) through (5) of this 

section. 

(1) Identification of the specific flare 

being monitored and the flare type (airassisted only, steam-assisted only, airand steam-assisted, pressure-assisted, or 

non-assisted). 

(2) Identification of the parameter to 

be monitored by the CPMS and the 

expected parameter range, including 

worst case and normal operation. 

(3) Description of the monitoring 

equipment, including the information 

specified in paragraphs (b)(3)(i) through 

(vii) of this section. 

(i) Manufacturer and model number 

for all monitoring equipment 

components installed to comply with 

applicable provisions in § 63.670. 

(ii) Performance specifications, as 

provided by the manufacturer, and any 

differences expected for this installation 

and operation. 

(iii) The location of the CPMS 

sampling probe or other interface and a 

justification of how the location meets 

the requirements of paragraph (a)(1) of 

this section. 

(iv) Placement of the CPMS readout, 

or other indication of parameter values, 

indicating how the location meets the 

requirements of paragraph (a)(2) of this 

section. 


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(v) Span of the CPMS. The span of the 

CPMS sensor and analyzer must 

encompass the full range of all expected 

values. 

(vi) How data outside of the span of 

the CPMS will be handled and the 

corrective action that will be taken to 

reduce and eliminate such occurrences 

in the future. 

(vii) Identification of the parameter 

detected by the parametric signal 

analyzer and the algorithm used to 

convert these values into the operating 

parameter monitored to demonstrate 

compliance, if the parameter detected is 

different from the operating parameter 

monitored. 

(4) Description of the data collection 

and reduction systems, including the 

information specified in paragraphs 

(b)(4)(i) through (iii) of this section. 

(i) A copy of the data acquisition 

system algorithm used to reduce the 

measured data into the reportable form 

of the standard and to calculate the 

applicable averages. 

(ii) Identification of whether the 

algorithm excludes data collected 

during CPMS breakdowns, out-ofcontrol periods, repairs, maintenance 

periods, instrument adjustments or 

checks to maintain precision and 

accuracy, calibration checks, and zero 

(low-level), mid-level (if applicable) and 

high-level adjustments. 

(iii) If the data acquisition algorithm 

does not exclude data collected during 

CPMS breakdowns, out-of-control 

periods, repairs, maintenance periods, 

instrument adjustments or checks to 

maintain precision and accuracy, 

calibration checks, and zero (low-level), 

mid-level (if applicable) and high-level 

adjustments, a description of the 

procedure for excluding this data when 

the averages calculated as specified in 

paragraph (e) of this section are 

determined. 

(5) Routine quality control and 

assurance procedures, including 

descriptions of the procedures listed in 

paragraphs (b)(5)(i) through (vi) of this 

section and a schedule for conducting 

these procedures. The routine 

procedures must provide an assessment 

of CPMS performance. 

(i) Initial and subsequent calibration 

of the CPMS and acceptance criteria. 

(ii) Determination and adjustment of 

the calibration drift of the CPMS. 

(iii) Daily checks for indications that 

the system is responding. If the CPMS 

system includes an internal system 

check, the owner or operator may use 

the results to verify the system is 

responding, as long as the system 

provides an alarm to the owner or 

operator or the owner or operator checks 

the internal system results daily for 

proper operation and the results are 

recorded. 

(iv) Preventive maintenance of the 

CPMS, including spare parts inventory. 

(v) Data recording, calculations and 

reporting. 

(vi) Program of corrective action for a 

CPMS that is not operating properly. 

(c) Out-of-control periods. For each 

CPMS installed to comply with 

applicable provisions in § 63.670 except 

for CPMS installed for pilot flame 

monitoring, the owner or operator shall 

comply with the out-of-control 

procedures described in paragraphs 

(c)(1) and (2) of this section. 

(1) A CPMS is out-of-control if the 

zero (low-level), mid-level (if 

applicable) or high-level calibration 

drift exceeds two times the accuracy 

requirement of table 13 of this subpart. 

(2) When the CPMS is out of control, 

the owner or operator shall take the 

necessary corrective action and repeat 

all necessary tests that indicate the 

system is out of control. The owner or 

operator shall take corrective action and 

conduct retesting until the performance 

requirements are below the applicable 

limits. The beginning of the out-ofcontrol period is the hour a performance 

check (e.g., calibration drift) that 

indicates an exceedance of the 

performance requirements established 

in this section is conducted. The end of 

the out-of-control period is the hour 

following the completion of corrective 

action and successful demonstration 

that the system is within the allowable 

limits. The owner or operator shall not 

use data recorded during periods the 

CPMS is out of control in data averages 

and calculations, used to report 

emissions or operating levels, as 

specified in paragraph (d)(3) of this 

section. 

(d) CPMS data reduction. The owner 

or operator shall reduce data from a 

CPMS installed to comply with 

applicable provisions in § 63.670 as 

specified in paragraphs (d)(1) through 

(3) of this section. 

(1) The owner or operator may round 

the data to the same number of 

significant digits used in that operating 

limit. 

(2) Periods of non-operation of the 

process unit (or portion thereof) 

resulting in cessation of the emissions to 

which the monitoring applies must not 

be included in the 15-minute block 

averages. 

(3) Periods when the CPMS is out of 

control must not be included in the 15- 

minute block averages. 

(e) Additional requirements for gas 

chromatographs. For monitors used to 

determine compositional analysis for 

net heating value per § 63.670(j)(1), the 

gas chromatograph must also meet the 

requirements of paragraphs (e)(1) 

through (3) of this section. 

(1) The quality assurance 

requirements are in table 13 of this 

subpart. 

(2) The calibration gases must meet 

one of the following options: 

(i) The owner or operator must use a 

calibration gas or multiple gases that 

include all of compounds listed in 

paragraphs (e)(2)(i)(A) through (K) of 

this section that may be reasonably 

expected to exist in the flare gas stream 

and optionally include any of the 

compounds listed in paragraphs 

(e)(2)(i)(L) through (O) of this section. 

All of the calibration gases may be 

combined in one cylinder. If multiple 

calibration gases are necessary to cover 

all compounds, the owner or operator 

must calibrate the instrument on all of 

the gases. 

(A) Hydrogen. 

(B) Methane. 

(C) Ethane. 

(D) Ethylene. 

(E) Propane. 

(F) Propylene. 

(G) n-Butane. 

(H) iso-Butane. 

(I) Butene (general). It is not necessary 

to separately speciate butene isomers, 

but the net heating value of trans-butene 

must be used for co-eluting butene 

isomers. 

(J) 1,3-Butadiene. It is not necessary to 

separately speciate butadiene isomers, 

but you must use the response factor 

and net heating value of 1,3-butadiene 

for co-eluting butadiene isomers. 

(K) n-Pentane. Use the response factor 

for n-pentane to quantify all C5+ 

hydrocarbons. 

(L) Acetylene (optional). 

(M) Carbon monoxide (optional). 

(N) Propadiene (optional). 

(O) Hydrogen sulfide (optional). 

(ii) The owner or operator must use a 

surrogate calibration gas consisting of 

hydrogen and C1 through C5 normal 

hydrocarbons. All of the calibration 

gases may be combined in one cylinder. 

If multiple calibration gases are 

necessary to cover all compounds, the 

owner or operator must calibrate the 

instrument on all of the gases. 

(3) If the owner or operator chooses to 

use a surrogate calibration gas under 

paragraph (e)(2)(ii) of this section, the 

owner or operator must comply with 

paragraphs (e)(3)(i) and (ii) of this 

section. 

(i) Use the response factor for the 

nearest normal hydrocarbon (i.e., nalkane) in the calibration mixture to 

quantify unknown components detected 

in the analysis. 

(ii) Use the response factor for npentane to quantify unknown 


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components detected in the analysis 

that elute after n-pentane. 

■ 34. The appendix to subpart CC is 

amended in table 6 by: 

■ a. Revising the entries ‘‘63.5(d)(1)(ii)’’ 

and ‘‘63.5(f)’’; 

■ b. Removing the entry ‘‘63.6(e)(1)’’; 

■ c. Adding, in numerical order, the 

entries ‘‘63.6(e)(1)(i) and (ii)’’ and 

‘‘63.6(e)(1)(iii)’’; 

■ d. Revising the entries ‘‘63.6(e)(3)(i),’’ 

‘‘63.6(e)(3)(iii)–63.6(e)(3)(ix),’’ and 

‘‘63.6(f)(1)’’; 

■ e. Removing the entry ‘‘63.6(f)(2) and 

(3)’’; 

■ f. Adding, in numerical order, the 

entries ‘‘63.6(f)(2)’’ and ‘‘63.6(f)(3)’’; 

■ g. Removing the entry ‘‘63.6(h)(1) and 

63.6(h)(2)’’; 

■ h. Adding, in numerical order, the 

entries ‘‘63.6(h)(1)’’ and ‘‘63.6(h)(2)’’; 

■ i. Revising the entries ‘‘63.7(b)’’ and 

‘‘63.7(e)(1)’’; 

■ j. Removing the entry ‘‘63.8(a)’’; 

■ k. Adding, in numerical order, the 

entries ‘‘63.8(a)(1) and (2),’’ ‘‘63.8(a)(3),’’ 

and ‘‘63.8(a)(4)’’; 

■ l. Revising the entry ‘‘63.8(c)(1)’’; 

■ m. Adding, in numerical order, the 

entries ‘‘63.8(c)(1)(i)’’ and 

‘‘63.8(c)(1)(iii)’’; 

■ n. Revising the entries ‘‘63.8(c)(4),’’ 

‘‘63.8(c)(5)–63.8(c)(8),’’ ‘‘63.8(d),’’ 

‘‘63.8(e),’’ ‘‘63.8(g),’’ ‘‘63.10(b)(2)(i),’’ 

‘‘63.10(b)(2)(ii),’’ ‘‘63.10(b)(2)(iv),’’ 

‘‘63.10(b)(2)(v),’’ and ‘‘63.10(b)(2)(vii)’’; 

■ o. Removing the entry ‘‘63.10(c)(9)– 

63.10(c)(15)’’; 

■ p. Adding, in numerical order, the 

entries ‘‘63.10(c)(9),’’ ‘‘63.10(c)(10)– 

63.10(c)(11),’’ and ‘‘63.10(c)(12)– 

63.10(c)(15)’’; 

■ q. Revising the entry ‘‘63.10(d)(2)’’; 

■ r. Removing the entries 

‘‘63.10(d)(5)(i)’’ and ‘‘63.10(d)(5)(ii)’’; 

■ s. Adding, in numerical order, the 

entry ‘‘63.10(d)(5)’’; 

■ t. Removing the entry ‘‘63.11–63.16’’; 

■ u. Adding, in numerical order, the 

entries ‘‘63.11’’ and ‘‘63.12–63.16’’; 

■ v. Revising footnote a. 

■ w. Removing footnote b. 

The revisions and additions read as 

follows: 

Appendix to Subpart CC of Part 63— 

Tables 

* * * * * 

TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART CC a

Reference Applies to 

subpart CC Comment 

*******

63.5(d)(1)(ii) ............................................. Yes ................... Except that for affected sources subject to this subpart, 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(f) ....................................................... Yes ................... Except that the cross-reference in § 63.5(f)(2) to § 63.9(b)(2) does not apply. 

* * * * * * * 

63.6(e)(1)(i) and (ii) .................................. No ..................... See § 63.642(n) for general duty requirement. 

63.6(e)(1)(iii) ............................................. Yes. 

* * * * * * * 

63.6(e)(3)(i) .............................................. No. 

* * * * * * * 

63.6(e)(3)(iii)–63.6(e)(3)(ix) ...................... No. 

63.6(f)(1) .................................................. No. 

63.6(f)(2) .................................................. Yes ................... Except the phrase ‘‘as specified in § 63.7(c)’’ in § 63.6(f)(2)(iii)(D) does not apply 

because this subpart does not require a site-specific test plan. 

63.6(f)(3) .................................................. Yes ................... Except the cross-references to § 63.6(f)(1) and (e)(1)(i) are changed to 

§ 63.642(n). 

*******

63.6(h)(1) ................................................. No. 

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

*******

63.7(b) ...................................................... Yes ................... Except this subpart requires notification of performance test at least 30 days (rather than 60 days) prior to the performance test. 

*******

63.7(e)(1) ................................................. No ..................... See § 63.642(d)(3). 

*******

63.8(a)(1) and (2) ..................................... Yes. 

63.8(a)(3) ................................................. No ..................... Reserved. 

63.8(a)(4) ................................................. Yes ................... Except that for a flare complying with § 63.670, the cross-reference to § 63.11 in 

this paragraph does not include § 63.11(b). 

*******

63.8(c)(1) .................................................. Yes ................... Except § 63.8(c)(1)(i) and (iii). 

63.8(c)(1)(i) .............................................. No ..................... See § 63.642(n). 

63.8(c)(1)(iii) ............................................. No. 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75269 

TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART CC a—Continued 

Reference Applies to 

subpart CC Comment 

*******

63.8(c)(4) .................................................. Yes ................... Except that for sources other than flares, this subpart specifies the monitoring 

cycle frequency specified in § 63.8(c)(4)(ii) is ‘‘once every hour’’ rather than ‘‘for 

each successive 15-minute period.’’ 

63.8(c)(5)–63.8(c)(8) ................................ No ..................... This subpart specifies continuous monitoring system requirements. 

63.8(d) ...................................................... No ..................... This subpart specifies quality control procedures for continuous monitoring systems. 

63.8(e) ...................................................... Yes. 

*******

63.8(g) ...................................................... No ..................... This subpart specifies data reduction procedures in §§ 63.655(i)(3) and 63.671(d). 

*******

63.10(b)(2)(i) ............................................ No. 

63.10(b)(2)(ii) ........................................... No ..................... § 63.655(i) specifies the records that must be kept. 

*******

63.10(b)(2)(iv) .......................................... No. 

63.10(b)(2)(v) ........................................... No. 

*******

63.10(b)(2)(vii) .......................................... No ..................... § 63.655(i) specifies records to be kept for parameters measured with continuous 

monitors. 

*******

63.10(c)(9) ................................................ No ..................... Reserved. 

63.10(c)(10)–63.10(c)(11) ........................ No ..................... § 63.655(i) specifies the records that must be kept. 

63.10(c)(12)–63.10(c)(15) ........................ No. 

*******

63.10(d)(2) ............................................... No ..................... Although § 63.655(f) specifies performance test reporting, EPA may approve other 

timeframes for submittal of performance test data. 

*******

63.10(d)(5) ............................................... No ..................... § 63.655(g) specifies the reporting requirements. 

* * * * * * * 

63.11 ........................................................ Yes ................... Except that flares complying with § 63.670 are not subject to the requirements of 

§ 63.11(b). 

63.12–63.16 ............................................. Yes. 

aWherever subpart A of this part 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. 

■ 35. The appendix to subpart CC is 

amended in table 10 by: 

■ a. Redesignating the entry ‘‘Flare’’ as 

‘‘Flare (if meeting the requirements of 

§§ 63.643 and 63.644)’’; 

■ b. Adding the entry ‘‘Flare (if meeting 

the requirements of §§ 63.670 and 

63.671)’’ after newly redesignated entry 

‘‘Flare (if meeting the requirements of 

§§ 63.643 and 63.644)’’; 

■ c. Revising the entry ‘‘All control 

devices’’; and 

■ d. Revising footnote i. 

The revisions and additions read as 

follows: 

Appendix to Subpart CC of Part 63— 

Tables 

* * * * * 

TABLE 10—MISCELLANEOUS PROCESS VENTS—MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS FOR

COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS

PER MILLION BY VOLUME

Control device Parameters to be monitored a Recordkeeping and reporting requirements for monitored parameters 

*******

Flare (if meeting the requirements 

of §§ 63.670 and 63.671).

The parameters specified in 

§ 63.670.

1. Records as specified in § 63.655(i)(9). 

2. Report information as specified in § 63.655(g)(11)—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. 

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


tkelley on DSK3SPTVN1PROD with RULES2
75270 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 10—MISCELLANEOUS PROCESS VENTS—MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS FOR

COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS

PER MILLION BY VOLUME—Continued 

Control device Parameters to be monitored a Recordkeeping and reporting requirements for monitored parameters 

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. 

* * * * * * * gPR = Periodic Reports described in § 63.655(g). 

* * * * * * * iProcess vents that are routed to refinery fuel gas systems are not regulated under this subpart provided that on and after January 30, 2019, 

any flares receiving gas from that fuel gas system are in compliance with § 63.670. No monitoring, recordkeeping, or reporting is required for 

boilers and process heaters that combust refinery fuel gas. 

■ 36. The appendix to subpart CC is 

amended by adding table 11 to read as 

follows: 

Appendix to Subpart CC of Part 63— 

Tables 

* * * * * 

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 February 1, 

2016, 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 January 30, 2019 .... § 63.640(k), (l) and (m). 

(iii) Requirements for existing 

sources in § 63.658.

On or before January 30, 2018 .... § 63.640(k), (l) and (m). 

(iv) Requirements for new sources 

in § 63.660 c.

On or before April 29, 2016 ......... § 63.640(k), (l) and (m). 

(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 January 30, 2019 .... § 63.640(k), (l) and (m). 

(iii) Requirements for existing 

sources in § 63.658.

On or before January 30, 2018 .... § 63.640(k), (l) and (m). 

(iv) Requirements for new sources 

in § 63.660 e.

On or before April 29, 2016 ......... § 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 

part. 

(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 January 30, 2019 .... § 63.640(k), (l) and (m). 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75271 

TABLE 11—COMPLIANCE DATES AND REQUIREMENTS—Continued 

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 . . . 

(iii) Requirements for existing 

sources in § 63.658.

On or before January 30, 2018 .... § 63.640(k), (l) and (m). 

(iv) Requirements for existing 

sources in § 63.660 g.

On or before April 29, 2016 ......... § 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).

aFor purposes of this table, the construction/reconstruction date means the date of construction or reconstruction of an entire affected source 

or the date of a process unit addition or change meeting the criteria in § 63.640(i) or (j). If a process unit addition or change does not meet the 

criteria in § 63.640(i) or (j), the process unit shall comply with the applicable requirements for existing sources. bBetween 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. cBetween 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. dBetween 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. eBetween 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. fBetween the compliance dates in items (4)(i) and (4)(ii) of this table, the owner or operator may elect to comply with either the requirements in 

item (4)(i) or item (4)(ii) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(ii) of this table. gBetween 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. 

■ 37. The appendix to subpart CC is 

amended by adding table 12 to read as 

follows: 

Appendix to Subpart CC of Part 63— 

Tables 

* * * * * 

TABLE 12—INDIVIDUAL COMPONENT PROPERTIES

Component Molecular 

formula 

MWi

(pounds per 

pound-mole) 

CMNi

(mole per 

mole) 

NHVi

(British 

thermal units 

per standard 

cubic foot) 

LFLi

(volume %) 

Acetylene ............................................................................. C2H2 ............... 26.04 2 1,404 2.5 

Benzene ............................................................................... C6H6 ............... 78.11 6 3,591 1.3 

1,2-Butadiene ...................................................................... C4H6 ............... 54.09 4 2,794 2.0 

1,3-Butadiene ...................................................................... C4H6 ............... 54.09 4 2,690 2.0 

iso-Butane ............................................................................ C4H10 ............. 58.12 4 2,957 1.8 

n-Butane .............................................................................. C4H10 ............. 58.12 4 2,968 1.8 

cis-Butene ............................................................................ C4H8 ............... 56.11 4 2,830 1.6 

iso-Butene ............................................................................ C4H8 ............... 56.11 4 2,928 1.8 

trans-Butene ........................................................................ C4H8 ............... 56.11 4 2,826 1.7 

Carbon Dioxide .................................................................... CO2 ................ 44.01 1 0 ∞ 

Carbon Monoxide ................................................................ CO ................. 28.01 1 316 12.5 

Cyclopropane ....................................................................... C3H6 ............... 42.08 3 2,185 2.4 

Ethane ................................................................................. C2H6 ............... 30.07 2 1,595 3.0 

Ethylene ............................................................................... C2H4 ............... 28.05 2 1,477 2.7 

Hydrogen ............................................................................. H2 ................... 2.02 0 1,212a 4.0 

Hydrogen Sulfide ................................................................. H2S ................ 34.08 0 587 4.0 

Methane ............................................................................... CH4 ................ 16.04 1 896 5.0 

Methyl-Acetylene ................................................................. C3H4 ............... 40.06 3 2,088 1.7 

Nitrogen ............................................................................... N2 ................... 28.01 0 0 ∞ 

Oxygen ................................................................................ O2 ................... 32.00 0 0 ∞ 

Pentane+ (C5+) ................................................................... C5H12 ............. 72.15 5 3,655 1.4 

Propadiene .......................................................................... C3H4 ............... 40.06 3 2,066 2.16 

Propane ............................................................................... C3H8 ............... 44.10 3 2,281 2.1 

Propylene ............................................................................. C3H6 ............... 42.08 3 2,150 2.4 

Water ................................................................................... H2O ................ 18.02 0 0 ∞ 

aThe theoretical net heating value for hydrogen is 274 Btu/scf, but for the purposes of the flare requirement in this subpart, a net heating value 

of 1,212 Btu/scf shall be used. 


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75272 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

■ 38. The appendix to subpart CC is 

amended by adding table 13 to read as 

follows: 

Appendix to Subpart CC of Part 63— 

Tables 

* * * * * 

TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS 

Parameter Minimum accuracy requirements Calibration requirements 

Temperature .................................... ±1 percent over the normal range 

of temperature measured, expressed in degrees Celsius (C), 

or 2.8 degrees C, whichever is 

greater.

Conduct calibration checks at least annually; conduct calibration 

checks following any period of more than 24 hours throughout 

which the temperature exceeded the manufacturer’s specified maximum rated temperature or install a new temperature sensor. 

At least quarterly, inspect all components for integrity and all electrical connections for continuity, oxidation, and galvanic corrosion, 

unless the CPMS has a redundant temperature sensor. 

Record the results of each calibration check and inspection. 

Locate the temperature sensor in a position that provides a representative temperature; shield the temperature sensor system 

from electromagnetic interference and chemical contaminants. 

Flow Rate for All Flows Other Than 

Flare Vent Gas.

±5 percent over the normal range 

of flow measured or 1.9 liters 

per minute (0.5 gallons per 

minute), whichever is greater, 

for liquid flow.

Conduct a flow sensor calibration check at least biennially (every two 

years); conduct a calibration check following any period of more 

than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow 

sensor. 

±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.

At least quarterly, inspect all components for leakage, unless the 

CPMS has a redundant flow sensor. 

±5 percent over the normal range 

measured for mass flow.

Record the results of each calibration check and inspection. 

Locate the flow sensor(s) and other necessary equipment (such as 

straightening vanes) in a position that provides representative flow; 

reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. 

Flare Vent Gas Flow Rate .............. ±20 percent of flow rate at velocities ranging from 0.03 to 0.3 

meters per second (0.1 to 1 feet 

per second).

±5 percent of flow rate at velocities greater than 0.3 meters per 

second (1 feet per second).

Conduct a flow sensor calibration check at least biennially (every two 

years); conduct a calibration check following any period of more 

than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow 

sensor. 

At least quarterly, inspect all components for leakage, unless the 

CPMS has a redundant flow sensor. 

Record the results of each calibration check and inspection. 

Locate the flow sensor(s) and other necessary equipment (such as 

straightening vanes) in a position that provides representative flow; 

reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. 

Pressure .......................................... ±5 percent over the normal operating range or 0.12 kilopascals 

(0.5 inches of water column), 

whichever is greater.

Review pressure sensor readings at least once a week for 

straightline (unchanging) pressure and perform corrective action to 

ensure proper pressure sensor operation if blockage is indicated. 

Using an instrument recommended by the sensor’s manufacturer, 

check gauge calibration and transducer calibration annually; conduct calibration checks following any period of more than 24 hours 

throughout which the pressure exceeded the manufacturer’s specified maximum rated pressure or install a new pressure sensor. 

At least quarterly, inspect all components for integrity, all electrical 

connections for continuity, and all mechanical connections for leakage, unless the CPMS has a redundant pressure sensor. 

Record the results of each calibration check and inspection. 

Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure and minimizes or eliminates 

pulsating pressure, vibration, and internal and external corrosion. 

Net Heating Value by Calorimeter .. ±2 percent of span ........................ Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements should follow manufacturer’s 

recommendations at a minimum. 

Temperature control (heated and/or cooled as necessary) the sampling system to ensure proper year-round operation. 

Where feasible, select a sampling location at least two equivalent diameters downstream from and 0.5 equivalent diameters upstream 

from the nearest disturbance. Select the sampling location at least 

two equivalent duct diameters from the nearest control device, 

point of pollutant generation, air in-leakages, or other point at 

which a change in the pollutant concentration or emission rate occurs. 


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TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS—Continued 

Parameter Minimum accuracy requirements Calibration requirements 

Net Heating Value by Gas Chromatograph.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 inleakages, or other point at which a change in the pollutant concentration occurs. 

Subpart UUU-—National Emission 

Standards for Hazardous Air Pollutants 

for Petroleum Refineries: Catalytic 

Cracking Units, Catalytic Reforming 

Units, and Sulfur Recovery Units 

■ 39. Section 63.1562 is amended by 

revising paragraphs (b)(3) and (f)(5) to 

read as follows: 

§ 63.1562 What parts of my plant are 

covered by this subpart? 

* * * * * 

(b) * * * 

(3) The process vent or group of 

process vents on Claus or other types of 

sulfur recovery plant units or the tail gas 

treatment units serving sulfur recovery 

plants that are associated with sulfur 

recovery. 

* * * * * 

(f) * * * 

(5) Gaseous streams routed to a fuel 

gas system, provided that on and after 

January 30, 2019, any flares receiving 

gas from the fuel gas system are subject 

to § 63.670. 

■ 40. Section 63.1564 is amended by: 

■ a. Revising paragraphs (a)(1) and (2); 

■ b. Adding paragraph (a)(5); 

■ c. Removing the equation following 

paragraph (b)(4)(ii) and adding it after 

paragraph (b)(4)(iii) introductory text; 

■ d. Revising paragraphs (b)(2), (b)(4)(i) 

and (ii), and (b)(4)(iv); and 

■ e. Adding paragraph (c)(5). 

The revisions and additions read as 

follows: 

§ 63.1564 What are my requirements for 

metal HAP emissions from catalytic 

cracking units? 

(a) * * * 

(1) Except as provided in paragraph 

(a)(5) of this section, meet each emission 

limitation in Table 1 of this subpart that 

applies to you. If your catalytic cracking 

unit is subject to the NSPS for PM in 

§ 60.102 of this chapter or is subject to 

§ 60.102a(b)(1) of this chapter, you must 

meet the emission limitations for NSPS 

units. If your catalytic cracking unit is 

not subject to the NSPS for PM, you can 

choose from the four options in 

paragraphs (a)(1)(i) through (vi) of this 

section: 

(i) You can elect to comply with the 

NSPS for PM in § 60.102 of this chapter 

(Option 1a); 

(ii) You can elect to comply with the 

NSPS for PM coke burn-off emission 

limit in § 60.102a(b)(1) of this chapter 

(Option 1b); 

(iii) You can elect to comply with the 

NSPS for PM concentration limit in 

§ 60.102a(b)(1) of this chapter (Option 

1c); 

(iv) You can elect to comply with the 

PM per coke burn-off emission limit in 

§ 60.102a(b)(1) of this chapter (Option 

2); 

(v) You can elect to comply with the 

Nickel (Ni) lb/hr emission limit (Option 

3); or 

(vi) You can elect to comply with the 

Ni per coke burn-off emission limit 

(Option 4). 

(2) Comply with each operating limit 

in Table 2 of this subpart that applies to 

you. When a specific control device may 

be monitored using more than one 

continuous parameter monitoring 

system, you may select the parameter 

with which you will comply. You must 

provide notice to the Administrator (or 

other designated authority) if you elect 

to change the monitoring option. 

* * * * * 

(5) During periods of startup, 

shutdown and hot standby, you can 

choose from the two options in 

paragraphs (a)(5)(i) and (ii) of this 

section: 

(i) You can elect to comply with the 

requirements in paragraphs (a)(1) and 

(2) of this section, except catalytic 

cracking units controlled using a wet 

scrubber must maintain only the liquid 

to gas ratio operating limit (the pressure 

drop operating limit does not apply); or 

(ii) You can elect to maintain the inlet 

velocity to the primary internal cyclones 

of the catalytic cracking unit catalyst 

regenerator at or above 20 feet per 

second. 

(b) * * * 

(2) Conduct a performance test for 

each catalytic cracking unit according to 

the requirements in § 63.1571 and under 

the conditions specified in Table 4 of 

this subpart. 

* * * * * 

(4) * * * 

(i) If you elect Option 1b or Option 2 

in paragraph (a)(1)(ii) or (iv) of this 

section, compute the PM emission rate 

(lb/1,000 lb of coke burn-off) for each 

run using Equations 1, 2, and 3 (if 

applicable) of this section and the sitespecific opacity limit, if applicable, 

using Equation 4 of this section as 

follows: 

Where: 

Rc = Coke burn-off rate, kg/hr (lb/hr); 

Qr = Volumetric flow rate of exhaust gas from 

catalyst regenerator before adding air or 

gas streams. Example: You may measure 

upstream or downstream of an 


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electrostatic precipitator, but you must 

measure upstream of a carbon monoxide 

boiler, dscm/min (dscf/min). You may 

use the alternative in either 

§ 63.1573(a)(1) or (2), as applicable, to 

calculate Qr; 

Qa = Volumetric flow rate of air to catalytic 

cracking unit catalyst regenerator, as 

determined from instruments in the 

catalytic cracking unit control room, 

dscm/min (dscf/min); 

%CO2 = Carbon dioxide concentration in 

regenerator exhaust, percent by volume 

(dry basis); 

%CO = Carbon monoxide concentration in 

regenerator exhaust, percent by volume 

(dry basis); 

%O2 = Oxygen concentration in regenerator 

exhaust, percent by volume (dry basis); 

K1 = Material balance and conversion factor, 

0.2982 (kg-min)/(hr-dscm-%) (0.0186 (lbmin)/(hr-dscf-%)); 

K2 = Material balance and conversion factor, 

2.088 (kg-min)/(hr-dscm) (0.1303 (lbmin)/(hr-dscf)); 

K3 = Material balance and conversion factor, 

0.0994 (kg-min)/(hr-dscm-%) (0.0062 (lbmin)/(hr-dscf-%)); 

Qoxy = Volumetric flow rate of oxygenenriched air stream to regenerator, as 

determined from instruments in the 

catalytic cracking unit control room, 

dscm/min (dscf/min); and 

%Oxy = Oxygen concentration in oxygenenriched air stream, percent by volume 

(dry basis). 

Where: 

E = Emission rate of PM, kg/1,000 kg (lb/ 

1,000 lb) of coke burn-off; 

Cs = Concentration of PM, g/dscm (lb/dscf); 

Qsd = Volumetric flow rate of the catalytic 

cracking unit catalyst regenerator flue 

gas as measured by Method 2 in 

appendix A–1 to part 60 of this chapter, 

dscm/hr (dscf/hr); 

Rc = Coke burn-off rate, kg coke/hr (1,000 lb 

coke/hr); and 

K = Conversion factor, 1.0 (kg2/g)/(1,000 kg) 

(1,000 lb/(1,000 lb)). 

Where: 

Es = Emission rate of PM allowed, kg/1,000 

kg (1b/1,000 lb) of coke burn-off in 

catalyst regenerator; 

1.0 = Emission limitation, kg coke/1,000 kg 

(lb coke/1,000 lb); 

A = Allowable incremental rate of PM 

emissions. Before August 1, 2017, A = 

0.18 g/million cal (0.10 lb/million Btu). 

On or after August 1, 2017, A = 0 g/ 

million cal (0 lb/million Btu); 

H = Heat input rate from solid or liquid fossil 

fuel, million cal/hr (million Btu/hr). 

Make sure your permitting authority 

approves procedures for determining the 

heat input rate; 

Rc = Coke burn-off rate, kg coke/hr (1,000 lb 

coke/hr) determined using Equation 1 of 

this section; and 

K′ = Conversion factor to units to standard, 

1.0 (kg2/g)/(1,000 kg) (103 lb/(1,000 lb)). 

Where: 

Opacity Limit = Maximum permissible 

hourly average opacity, percent, or 10 

percent, whichever is greater; 

Opacityst = Hourly average opacity measured 

during the source test, percent; and 

PMEmRst = PM emission rate measured 

during the source test, lb/1,000 lb coke 

burn. 

(ii) If you elect Option 1c in paragraph 

(a)(1)(iii) of this section, the PM 

concentration emission limit, determine 

the average PM concentration from the 

initial performance test used to certify 

your PM CEMS. 

* * * * * 

(iv) If you elect Option 4 in paragraph 

(a)(1)(vi) of this section, the Ni per coke 

burn-off emission limit, compute your 

Ni emission rate using Equations 1 and 

8 of this section and your site-specific 

Ni operating limit (if you use a 

continuous opacity monitoring system) 

using Equations 9 and 10 of this section 

as follows: 

Where: ENi2 = Normalized mass emission rate of Ni, 

mg/kg coke (lb/1,000 lb coke). 


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Where: 

Opacity2 = Opacity value for use in Equation 

10 of this section, percent, or 10 percent, 

whichever is greater; and 

NiEmR2st = Average Ni emission rate 

calculated as the arithmetic average Ni 

emission rate using Equation 8 of this 

section for each of the performance test 

runs, mg/kg coke. 

Where: 

Ni Operating Limit2 = Maximum permissible 

hourly average Ni operating limit, 

percent-ppmw-acfm-hr/kg coke, i.e., 

your site-specific Ni operating limit; and 

Rc,st = Coke burn rate from Equation 1 of this 

section, as measured during the initial 

performance test, kg coke/hr. 

* * * * * 

(c) * * * 

(5) If you elect to comply with the 

alternative limit in paragraph (a)(5)(ii) of 

this section during periods of startup, 

shutdown, and hot standby, 

demonstrate continuous compliance by: 

(i) Collecting the volumetric flow rate 

from the catalyst regenerator (in acfm) 

and determining the average flow rate 

for each hour. For events lasting less 

than one hour, determine the average 

flow rate during the event. 

(ii) Determining the cumulative crosssectional area of the primary internal 

cyclone inlets in square feet (ft2) using 

design drawings of the primary (firststage) internal cyclones to determine the 

inlet cross-sectional area of each 

primary internal cyclone and summing 

the cross-sectional areas for all primary 

internal cyclones in the catalyst 

regenerator or, if primary cyclones. If all 

primary internal cyclones are identical, 

you may alternatively determine the 

inlet cross-sectional area of one primary 

internal cyclone using design drawings 

and multiply that area by the total 

number of primary internal cyclones in 

the catalyst regenerator. 

(iii) Calculating the inlet velocity to 

the primary internal cyclones in square 

feet per second (ft2/sec) by dividing the 

average volumetric flow rate (acfm) by 

the cumulative cross-sectional area of 

the primary internal cyclone inlets (ft2) 

and by 60 seconds/minute (for unit 

conversion). 

(iv) Maintaining the inlet velocity to 

the primary internal cyclones at or 

above 20 feet per second for each hour 

during the startup, shutdown, or hot 

standby event or, for events lasting less 

than 1 hour, for the duration of the 

event. 

■ 41. Section 63.1565 is amended by 

revising paragraph (a)(1) introductory 

text and adding paragraph (a)(5) to read 

as follows: 

§ 63.1565 What are my requirements for 

organic HAP emissions from catalytic 

cracking units? 

(a) * * * 

(1) Except as provided in paragraph 

(a)(5) of this section, meet each emission 

limitation in Table 8 of this subpart that 

applies to you. If your catalytic cracking 

unit is subject to the NSPS for carbon 

monoxide (CO) in § 60.103 of this 

chapter or is subject to § 60.102a(b)(4) of 

this chapter, you must meet the 

emission limitations for NSPS units. If 

your catalytic cracking unit is not 

subject to the NSPS for CO, you can 

choose from the two options in 

paragraphs (a)(1)(i) through (ii) of this 

section: 

* * * * * 

(5) During periods of startup, 

shutdown and hot standby, you can 

choose from the two options in 

paragraphs (a)(5)(i) and (ii) of this 

section: 

(i) You can elect to comply with the 

requirements in paragraphs (a)(1) and 

(2) of this section; or 

(ii) You can elect to maintain the 

oxygen (O2) concentration in the 

exhaust gas from your catalyst 

regenerator at or above 1 volume 

percent (dry basis). 

* * * * * 

■ 42. Section 63.1566 is amended by 

revising paragraphs (a)(1) introductory 

text, (a)(1)(i), and (a)(4) to read as 

follows: 

§ 63.1566 What are my requirements for 

organic HAP emissions from catalytic 

reforming units? 

(a) * * * 

(1) Meet each emission limitation in 

Table 15 of this subpart that applies to 

you. You can choose from the two 

options in paragraphs (a)(1)(i) and (ii) of 

this section. 

(i) You can elect to vent emissions of 

total organic compounds (TOC) to a 

flare (Option 1). On and after January 

30, 2019, the flare must meet the 

requirements of § 63.670. Prior to 

January 30, 2019, the flare must meet 

the control device requirements in 

§ 63.11(b) or the requirements of 

§ 63.670. 

* * * * * 

(4) The emission limitations in Tables 

15 and 16 of this subpart do not apply 

to emissions from process vents during 

passive depressuring when the reactor 

vent pressure is 5 pounds per square 

inch gauge (psig) or less. The emission 

limitations in Tables 15 and 16 of this 

subpart do apply to emissions from 

process vents during active purging 

operations (when nitrogen or other 

purge gas is actively introduced to the 

reactor vessel) or active depressuring 

(using a vacuum pump, ejector system, 

or similar device) regardless of the 

reactor vent pressure. 

* * * * * 

■ 43. Section 63.1568 is amended by 

revising paragraphs (a)(1) introductory 

text and (a)(1)(i) and adding paragraph 

(a)(4) to read as follows: 

§ 63.1568 What are my requirements for 

HAP emissions from sulfur recovery units? 

(a) * * * 

(1) Meet each emission limitation in 

Table 29 of this subpart that applies to 

you. If your sulfur recovery unit is 

subject to the NSPS for sulfur oxides in 

§ 60.104 or § 60.102a(f)(1) of this 

chapter, you must meet the emission 

limitations for NSPS units. If your sulfur 

recovery unit is not subject to one of 

these NSPS for sulfur oxides, you can 

choose from the options in paragraphs 

(a)(1)(i) through (ii) of this section: 

(i) You can elect to meet the NSPS 

requirements in § 60.104(a)(2) or 

§ 60.102a(f)(1) of this chapter (Option 1); 

or 

* * * * * 

(4) During periods of startup and 

shutdown, you can choose from the 

three options in paragraphs (a)(4)(i) 

through (iii) of this section. 

(i) You can elect to comply with the 

requirements in paragraphs (a)(1) and 

(2) of this section. 

(ii) You can elect to send any startup 

or shutdown purge gases to a flare. On 

and after January 30, 2019, the flare 

must meet the requirements of § 63.670. 

Prior to January 30, 2019, the flare must 

meet the design and operating 

requirements in § 63.11(b) or the 

requirements of § 63.670. 

(iii) You can elect to send any startup 

or shutdown purge gases to a thermal 

oxidizer or incinerator operated at a 


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minimum hourly average temperature of 

1,200 degrees Fahrenheit in the firebox 

and a minimum hourly average outlet 

oxygen (O2) concentration of 2 volume 

percent (dry basis). 

* * * * * 

■ 44. Section 63.1570 is amended by 

revising paragraphs (a) through (d) and 

removing paragraph (g) to read as 

follows: 

§ 63.1570 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

all of the non-opacity standards in this 

subpart at all times. 

(b) You must be in compliance with 

the opacity and visible emission limits 

in this subpart at all times. 

(c) At all times, you must operate and 

maintain any affected source, including 

associated air pollution control 

equipment and monitoring equipment, 

in a manner consistent with safety and 

good air pollution control practices for 

minimizing emissions. The general duty 

to minimize emissions does not require 

you to make any further efforts to 

reduce emissions if levels required by 

the applicable standard have been 

achieved. Determination of whether a 

source is operating in compliance with 

operation and maintenance 

requirements will be based on 

information available to the 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operation and maintenance 

procedures, review of operation and 

maintenance records, and inspection of 

the source. 

(d) During the period between the 

compliance date specified for your 

affected source and the date upon which 

continuous monitoring systems have 

been installed and validated and any 

applicable operating limits have been 

set, you must maintain a log that 

documents the procedures used to 

minimize emissions from process and 

emissions control equipment according 

to the general duty in paragraph (c) of 

this section. 

* * * * * 

■ 45. Section 63.1571 is amended by: 

■ a. Adding paragraphs (a)(5) and (6); 

■ b. Revising paragraph (b)(1); 

■ c. Removing paragraph (b)(4); 

■ d. Redesignating paragraph (b)(5) as 

paragraph (b)(4); and 

■ e. Revising the first sentence of 

paragraph (d)(2) and paragraph (d)(4). 

The revisions and additions read as 

follows: 

§ 63.1571 How and when do I conduct a 

performance test or other initial compliance 

demonstration? 

(a) * * * 

(5) Periodic performance testing for 

PM or Ni. Except as provided in 

paragraphs (a)(5)(i) and (ii) of this 

section, conduct a periodic performance 

test for PM or Ni for each catalytic 

cracking unit at least once every 5 years 

according to the requirements in Table 

4 of this subpart. You must conduct the 

first periodic performance test no later 

than August 1, 2017. 

(i) Catalytic cracking units monitoring 

PM concentration with a PM CEMS are 

not required to conduct a periodic PM 

performance test. 

(ii) Conduct a performance test 

annually if you comply with the 

emission limits in Item 1 (NSPS subpart 

J) or Item 4 (Option 1a) in Table 1 of this 

subpart and the PM emissions measured 

during the most recent performance 

source test are greater than 0.80 g/kg 

coke burn-off. 

(6) One-time performance testing for 

HCN. Conduct a performance test for 

HCN from each catalytic cracking unit 

no later than August 1, 2017 according 

to the applicable requirements in 

paragraphs (a)(6)(i) and (ii) of this 

section. 

(i) If you conducted a performance 

test for HCN for a specific catalytic 

cracking unit between March 31, 2011 

and February 1, 2016, you may submit 

a request to the Administrator to use the 

previously conducted performance test 

results to fulfill the one-time 

performance test requirement for HCN 

for each of the catalytic cracking units 

tested according to the requirements in 

paragraphs (a)(6)(i)(A) through (D) of 

this section. 

(A) The request must include a copy 

of the complete source test report, the 

date(s) of the performance test and the 

test methods used. If available, you 

must also indicate whether the catalytic 

cracking unit catalyst regenerator was 

operated in partial or complete 

combustion mode during the test, the 

control device configuration, including 

whether platinum or palladium 

combustion promoters were used during 

the test, and the CO concentration 

(measured using CO CEMS or manual 

test method) for each test run. 

(B) You must submit a separate 

request for each catalytic cracking unit 

tested and you must submit each 

request to the Administrator no later 

than March 30, 2016. 

(C) The Administrator will evaluate 

each request with respect to the 

completeness of the request, the 

completeness of the submitted test 

report and the appropriateness of the 

test methods used. The Administrator 

will notify the facility within 60 days of 

receipt of the request if it is approved 

or denied. If the Administrator fails to 

respond to the facility within 60 days of 

receipt of the request, the request will 

be automatically approved. 

(D) If the request is approved, you do 

not need to conduct an additional HCN 

performance test. If the request is 

denied, you must conduct an additional 

HCN performance test following the 

requirements in (a)(6)(ii) of this section. 

(ii) Unless you receive approval to use 

a previously conducted performance 

test to fulfill the one-time performance 

test requirement for HCN for your 

catalytic cracking unit as provided in 

paragraph (a)(6)(i) of this section, 

conduct a performance test for HCN for 

each catalytic cracking unit no later 

than August 1, 2017 according to 

following requirements: 

(A) Select sampling port location, 

determine volumetric flow rate, conduct 

gas molecular weight analysis and 

measure moisture content as specified 

in either Item 1 of Table 4 of this 

subpart or Item 1 of Table 11 of this 

subpart. 

(B) Measure HCN concentration using 

Method 320 of appendix A of this part. 

The method ASTM D6348–03 

(Reapproved 2010) including Annexes 

A1 through A8 (incorporated by 

reference—see § 63.14) is an acceptable 

alternative to EPA Method 320 of 

appendix A of this part. The method 

ASTM D6348–12e1 (incorporated by 

reference—see § 63.14) is an acceptable 

alternative to EPA Method 320 of 

appendix A of this part with the 

following two caveats: 

(1) The test plan preparation and 

implementation in the Annexes to 

ASTM D6348–03 (Reapproved 2010), 

Sections A1 through A8 are mandatory; 

and 

(2) In ASTM D6348–03 (Reapproved 

2010) Annex A5 (Analyte Spiking 

Technique), the percent (%) R must be 

determined for each target analyte 

(Equation A5.5). In order for the test 

data to be acceptable for a compound, 

%R must be 70% ≥ R ≤ 130%. If the %R 

value does not meet this criterion for a 

target compound, the test data is not 

acceptable for that compound and the 

test must be repeated for that analyte 

(i.e., the sampling and/or analytical 

procedure should be adjusted before a 

retest). The %R value for each 

compound must be reported in the test 

report, and all field measurements must 

be corrected with the calculated %R 

value for that compound by using the 

following equation: 


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Reported Result = (Measured 

Concentration in the Stack × 100÷/ 

% R. 

(C) Measure CO concentration as 

specified in either Item 2 or 3a of Table 

11 of this subpart. 

(D) Record and include in the test 

report an indication of whether the 

catalytic cracking unit catalyst 

regenerator was operated in partial or 

complete combustion mode and the 

control device configuration, including 

whether platinum or palladium 

combustion promoters were used during 

the test. 

(b) * * * 

(1) Performance tests shall be 

conducted according to the provisions 

of § 63.7(e) except that performance 

tests shall be conducted at maximum 

representative operating capacity for the 

process. During the performance test, 

you must operate the control device at 

either maximum or minimum 

representative operating conditions for 

monitored control device parameters, 

whichever results in lower emission 

reduction. You must not conduct a 

performance test during startup, 

shutdown, periods when the control 

device is bypassed or periods when the 

process, monitoring equipment or 

control device is not operating properly. 

You may not conduct performance tests 

during periods of malfunction. You 

must record the process information 

that is necessary to document operating 

conditions during the test and include 

in such record an explanation to 

support that the test was conducted at 

maximum representative operating 

capacity. Upon request, you must make 

available to the Administrator such 

records as may be necessary to 

determine the conditions of 

performance tests. 

* * * * * 

(d) * * * 

(2) If you must meet the HAP metal 

emission limitations in § 63.1564, you 

elect the option in paragraph (a)(1)(iv) 

in § 63.1564 (Ni per coke burn-off), and 

you use continuous parameter 

monitoring systems, you must establish 

an operating limit for the equilibrium 

catalyst Ni concentration based on the 

laboratory analysis of the equilibrium 

catalyst Ni concentration from the 

initial performance test. * * * 

* * * * * 

(4) Except as specified in paragraph 

(d)(3) of this section, if you use 

continuous parameter monitoring 

systems, you may adjust one of your 

monitored operating parameters (flow 

rate, total power and secondary current, 

pressure drop, liquid-to-gas ratio) from 

the average of measured values during 

the performance test to the maximum 

value (or minimum value, if applicable) 

representative of worst-case operating 

conditions, if necessary. This 

adjustment of measured values may be 

done using control device design 

specifications, manufacturer 

recommendations, or other applicable 

information. You must provide 

supporting documentation and rationale 

in your Notification of Compliance 

Status, demonstrating to the satisfaction 

of your permitting authority, that your 

affected source complies with the 

applicable emission limit at the 

operating limit based on adjusted 

values. 

* * * * * 

■ 46. Section 63.1572 is amended by 

revising paragraphs (c) introductory 

text, (c)(1), (3), and (4) and (d)(1) and (2) 

to read as follows: 

§ 63.1572 What are my monitoring 

installation, operation, and maintenance 

requirements? 

* * * * * 

(c) Except for flare monitoring 

systems, you must install, operate, and 

maintain each continuous parameter 

monitoring system according to the 

requirements in paragraphs (c)(1) 

through (5) of this section. For flares, on 

and after January 30, 2019, you must 

install, operate, calibrate, and maintain 

monitoring systems as specified in 

§§ 63.670 and 63.671. Prior to January 

30, 2019, you must either meet the 

monitoring system requirements in 

paragraphs (c)(1) through (5) of this 

section or meet the requirements in 

§§ 63.670 and 63.671. 

(1) You must install, operate, and 

maintain each continuous parameter 

monitoring system according to the 

requirements in Table 41 of this subpart. 

You must also meet the equipment 

specifications in Table 41 of this subpart 

if pH strips or colormetric tube 

sampling systems are used. You must 

install, operate, and maintain each 

continuous parameter monitoring 

system according to the requirements in 

Table 41 of this subpart. You must meet 

the requirements in Table 41 of this 

subpart for BLD systems. Alternatively, 

before August 1, 2017, you may install, 

operate, and maintain each continuous 

parameter monitoring system in a 

manner consistent with the 

manufacturer’s specifications or other 

written procedures that provide 

adequate assurance that the equipment 

will monitor accurately. 

* * * * * 

(3) Each continuous parameter 

monitoring system must have valid 

hourly average data from at least 75 

percent of the hours during which the 

process operated, except for BLD 

systems. 

(4) Each continuous parameter 

monitoring system must determine and 

record the hourly average of all recorded 

readings and if applicable, the daily 

average of all recorded readings for each 

operating day, except for BLD systems. 

The daily average must cover a 24-hour 

period if operation is continuous or the 

number of hours of operation per day if 

operation is not continuous, except for 

BLD systems. 

* * * * * 

(d) * * * 

(1) You must conduct all monitoring 

in continuous operation (or collect data 

at all required intervals) at all times the 

affected source is operating. 

(2) You may not use data recorded 

during required quality assurance or 

control activities (including, as 

applicable, calibration checks and 

required zero and span adjustments) for 

purposes of this regulation, including 

data averages and calculations, for 

fulfilling a minimum data availability 

requirement, if applicable. You must 

use all the data collected during all 

other periods in assessing the operation 

of the control device and associated 

control system. 

■ 47. Section 63.1573 is amended by: 

■ a. Redesignating paragraphs (b), (c), 

(d), (e), and (f) as paragraphs (c), (d), (e), 

(f), and (g); 

■ b. Adding paragraph (b); and 

■ c. Revising newly redesignated 

paragraphs (c) introductory text, (d) 

introductory text, (f) introductory text, 

and (g)(1) introductory text. 

The revisions and additions read as 

follows: 

§ 63.1573 What are my monitoring 

alternatives? 

* * * * * 

(b) What is the approved alternative 

for monitoring pressure drop? You may 

use this alternative to a continuous 

parameter monitoring system for 

pressure drop if you operate a jet ejector 

type wet scrubber or other type of wet 

scrubber equipped with atomizing spray 

nozzles. You shall: 

(1) Conduct a daily check of the air or 

water pressure to the spray nozzles; 

(2) Maintain records of the results of 

each daily check; and 

(3) Repair or replace faulty (e.g., 

leaking or plugged) air or water lines 

within 12 hours of identification of an 

abnormal pressure reading. 

(c) What is the approved alternative 

for monitoring pH or alkalinity levels? 

You may use the alternative in 


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paragraph (c)(1) or (2) of this section for 

a catalytic reforming unit. 

* * * * * 

(d) Can I use another type of 

monitoring system? You may use an 

automated data compression system. An 

automated data compression system 

does not record monitored operating 

parameter values at a set frequency (e.g., 

once every hour) but records all values 

that meet set criteria for variation from 

previously recorded values. You must 

maintain a record of the description of 

the monitoring system and data 

recording system, including the criteria 

used to determine which monitored 

values are recorded and retained, the 

method for calculating daily averages, 

and a demonstration that the system 

meets all of the criteria in paragraphs 

(d)(1) through (5) of this section: 

* * * * * 

(f) How do I request to monitor 

alternative parameters? You must 

submit a request for review and 

approval or disapproval to the 

Administrator. The request must 

include the information in paragraphs 

(f)(1) through (5) of this section. 

* * * * * 

(g) * * * 

(1) You may request alternative 

monitoring requirements according to 

the procedures in this paragraph if you 

meet each of the conditions in 

paragraphs (g)(1)(i) through (iii) of this 

section: 

* * * * * 

■ 48. Section 63.1574 is amended by 

revising paragraphs (a)(3) introductory 

text and (f)(1) to read as follows: 

§ 63.1574 What notifications must I submit 

and when? 

(a) * * * 

(3) If you are required to conduct an 

initial performance test, performance 

evaluation, design evaluation, opacity 

observation, visible emission 

observation, or other initial compliance 

demonstration, you must submit a 

notification of compliance status 

according to § 63.9(h)(2)(ii). You can 

submit this information in an operating 

permit application, in an amendment to 

an operating permit application, in a 

separate submission, or in any 

combination. In a State with an 

approved operating permit program 

where delegation of authority under 

section 112(l) of the CAA has not been 

requested or approved, you must 

provide a duplicate notification to the 

applicable Regional Administrator. If 

the required information has been 

submitted previously, you do not have 

to provide a separate notification of 

compliance status. Just refer to the 

earlier submissions instead of 

duplicating and resubmitting the 

previously submitted information. 

* * * * * 

(f) * * * 

(1) You must submit the plan to your 

permitting authority for review and 

approval along with your notification of 

compliance status. While you do not 

have to include the entire plan in your 

permit under part 70 or 71 of this 

chapter, you must include the duty to 

prepare and implement the plan as an 

applicable requirement in your part 70 

or 71 operating permit. You must 

submit any changes to your permitting 

authority for review and approval and 

comply with the plan as submitted until 

the change is approved. 

* * * * * 

■ 49. Section 63.1575 is amended by: 

■ a. Revising paragraphs (d) 

introductory text and (d)(1) and (2); 

■ b. Adding paragraph (d)(4); 

■ c. Revising paragraph (e) introductory 

text; 

■ d. Removing and reserving paragraph 

(e)(1); 

■ e. Revising paragraphs (e)(4) and (6) 

and (f)(1) and (2); 

■ f. Removing and reserving paragraph 

(h); and 

■ g. Adding paragraph (k). 

The revisions and additions read as 

follows: 

§ 63.1575 What reports must I submit and 

when? 

* * * * * 

(d) For each deviation from an 

emission limitation and for each 

deviation from the requirements for 

work practice standards that occurs at 

an affected source where you are not 

using a continuous opacity monitoring 

system or a continuous emission 

monitoring system to comply with the 

emission limitation or work practice 

standard in this subpart, the semiannual 

compliance report must contain the 

information in paragraphs (c)(1) through 

(3) of this section and the information 

in paragraphs (d)(1) through (4) of this 

section. 

(1) The total operating time of each 

affected source during the reporting 

period and identification of the sources 

for which there was a deviation. 

(2) Information on the number, date, 

time, duration, and cause of deviations 

(including unknown cause, if 

applicable). 

* * * * * 

(4) The applicable operating limit or 

work practice standard from which you 

deviated and either the parameter 

monitor reading during the deviation or 

a description of how you deviated from 

the work practice standard. 

(e) For each deviation from an 

emission limitation occurring at an 

affected source where you are using a 

continuous opacity monitoring system 

or a continuous emission monitoring 

system to comply with the emission 

limitation, you must include the 

information in paragraphs (c)(1) through 

(3) of this section, in paragraphs (d)(1) 

through (3) of this section, and in 

paragraphs (e)(2) through (13) of this 

section. 

* * * * * 

(4) An estimate of the quantity of each 

regulated pollutant emitted over the 

emission limit during the deviation, and 

a description of the method used to 

estimate the emissions. 

* * * * * 

(6) A breakdown of the total duration 

of the deviations during the reporting 

period and into those that are due to 

control equipment problems, process 

problems, other known causes, and 

other unknown causes. 

* * * * * 

(f) * * * 

(1) You must include the information 

in paragraph (f)(1)(i) or (ii) of this 

section, if applicable. 

(i) If you are complying with 

paragraph (k)(1) of this section, a 

summary of the results of any 

performance test done during the 

reporting period on any affected unit. 

Results of the performance test 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) If you are not complying with 

paragraph (k)(1) of this section, a copy 

of any performance test done during the 

reporting period on any affected unit. 

The report may be included in the next 

semiannual compliance report. The 

copy must include a complete report for 

each test method used for a particular 

kind of emission point tested. For 

additional tests performed for a similar 

emission point using the same method, 

you must submit the results and any 

other information required, but a 

complete test report is not required. A 

complete test report contains a brief 

process description; a simplified flow 

diagram showing affected processes, 

control equipment, and sampling point 

locations; sampling site data; 

description of sampling and analysis 

procedures and any modifications to 

standard procedures; quality assurance 

procedures; record of operating 

conditions during the test; record of 


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preparation of standards; record of 

calibrations; raw data sheets for field 

sampling; raw data sheets for field and 

laboratory analyses; documentation of 

calculations; and any other information 

required by the test method. 

(2) Any requested change in the 

applicability of an emission standard 

(e.g., you want to change from the PM 

standard to the Ni standard for catalytic 

cracking units or from the HCl 

concentration standard to percent 

reduction for catalytic reforming units) 

in your compliance report. You must 

include all information and data 

necessary to demonstrate compliance 

with the new emission standard 

selected and any other associated 

requirements. 

* * * * * 

(k) Electronic submittal of 

performance test and CEMS 

performance evaluation data. For 

performance tests or CEMS performance 

evaluations conducted on and after 

February 1, 2016, if required to submit 

the results of a performance test or 

CEMS performance evaluation, you 

must submit the results according to the 

procedures in paragraphs (k)(1) and (2) 

of this section. 

(1) Within 60 days after the date of 

completing each performance test as 

required by this subpart, you must 

submit the results of the performance 

tests following the procedure specified 

in either paragraph (k)(1)(i) or (ii) of this 

section. 

(i) For data collected using test 

methods supported by the EPA’s 

Electronic Reporting Tool (ERT) as 

listed on the EPA’s ERT Web site 

(http://www.epa.gov/ttn/chief/ert/

index.html) at the time of the test, you 

must submit the results of the 

performance test to the EPA via the 

Compliance and Emissions Data 

Reporting Interface (CEDRI). (CEDRI can 

be accessed through the EPA’s Central 

Data Exchange (CDX) (https://

cdx.epa.gov/).) Performance test data 

must be submitted in a file format 

generated through use of the EPA’s ERT 

or an alternate electronic file format 

consistent with the extensible markup 

language (XML) schema listed on the 

EPA’s ERT Web site. If you claim that 

some of the performance test 

information being submitted is 

confidential business information (CBI), 

you must submit a complete file 

generated through the use of the EPA’s 

ERT or an alternate electronic file 

consistent with the XML schema listed 

on the EPA’s ERT Web site, including 

information claimed to be CBI, on a 

compact disc, flash drive or other 

commonly used electronic storage 

media to the EPA. The electronic storage 

media must be clearly marked as CBI 

and mailed to U.S. EPA/OAQPS/CORE 

CBI Office, Attention: Group Leader, 

Measurement Policy Group, MD C404– 

02, 4930 Old Page Rd., Durham, NC 

27703. The same ERT or alternate file 

with the CBI omitted must be submitted 

to the EPA via the EPA’s CDX as 

described earlier in this paragraph 

(k)(1)(i). 

(ii) For data collected using test 

methods that are not supported by the 

EPA’s ERT as listed on the EPA’s ERT 

Web site at the time of the test, you must 

submit the results of the performance 

test to the Administrator at the 

appropriate address listed in § 63.13. 

(2) Within 60 days after the date of 

completing each CEMS performance 

evaluation required by § 63.1571(a) and 

(b), you must submit the results of the 

performance evaluation following the 

procedure specified in either paragraph 

(k)(2)(i) or (ii) of this section. 

(i) For performance evaluations of 

continuous monitoring systems 

measuring relative accuracy test audit 

(RATA) pollutants that are supported by 

the EPA’s ERT as listed on the EPA’s 

ERT Web site at the time of the 

evaluation, you must submit the results 

of the performance evaluation to the 

EPA via the CEDRI. (CEDRI is accessed 

through the EPA’s CDX.) Performance 

evaluation data must be submitted in a 

file format generated through the use of 

the EPA’s ERT or an alternate file format 

consistent with the XML schema listed 

on the EPA’s ERT Web site. If you claim 

that some of the performance evaluation 

information being submitted is CBI, you 

must submit a complete file generated 

through the use of the EPA’s ERT or an 

alternate electronic file consistent with 

the XML schema listed on the EPA’s 

ERT Web site, including information 

claimed to be CBI, on a compact disc, 

flash drive or other commonly used 

electronic storage media to the EPA. The 

electronic storage media must be clearly 

marked as CBI and mailed to U.S. EPA/ 

OAQPS/CORE CBI Office, Attention: 

Group Leader, Measurement Policy 

Group, MD C404–02, 4930 Old Page Rd., 

Durham, NC 27703. The same ERT or 

alternate file with the CBI omitted must 

be submitted to the EPA via the EPA’s 

CDX as described earlier in this 

paragraph (k)(2)(i). 

(ii) For any performance evaluations 

of continuous monitoring systems 

measuring RATA pollutants that are not 

supported by the EPA’s ERT as listed on 

the EPA’s ERT Web site at the time of 

the evaluation, you must submit the 

results of the performance evaluation to 

the Administrator at the appropriate 

address listed in § 63.13. 

■ 50. Section 63.1576 is amended by 

revising paragraphs (a)(2) and (b)(3) and 

(5) to read as follows: 

§ 63.1576 What records must I keep, in 

what form, and for how long? 

(a) * * * 

(2) The records specified in 

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

section. 

(i) Record the date, time, and duration 

of each startup and/or shutdown period, 

recording the periods when the affected 

source was subject to the standard 

applicable to startup and shutdown. 

(ii) In the event that an affected unit 

fails to meet an applicable standard, 

record the number of failures. For each 

failure record the date, time and 

duration of each failure. 

(iii) For each failure to meet an 

applicable standard, record and retain a 

list of the affected sources or equipment, 

an estimate of the volume of each 

regulated pollutant emitted over any 

emission limit and a description of the 

method used to estimate the emissions. 

(iv) Record actions taken to minimize 

emissions in accordance with 

§ 63.1570(c) and any corrective actions 

taken to return the affected unit to its 

normal or usual manner of operation. 

* * * * * 

(b) * * * 

(3) The performance evaluation plan 

as described in § 63.8(d)(2) for the life 

of the affected source or until the 

affected source is no longer subject to 

the provisions of this part, to be made 

available for inspection, upon request, 

by the Administrator. If the performance 

evaluation plan is revised, you must 

keep previous (i.e., superseded) versions 

of the performance evaluation plan on 

record to be made available for 

inspection, upon request, by the 

Administrator, for a period of 5 years 

after each revision to the plan. The 

program of corrective action should be 

included in the plan required under 

§ 63.8(d)(2). 

* * * * * 

(5) Records of the date and time that 

each deviation started and stopped. 

* * * * * 

■ 51. Section 63.1579 is amended by: 

■ a. Revising the introductory text; 

■ b. Adding, in alphabetical order, a 

new definition of ‘‘Hot standby’’; and 

■ c. Revising the definitions of 

‘‘Deviation’’ and ‘‘PM’’. 

The revisions read as follows: 

§ 63.1579 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the Clean Air Act (CAA), in 

40 CFR 63.2, the General Provisions of 


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this part (§§ 63.1 through 63.15), and in 

this section as listed. If the same term 

is defined in subpart A of this part and 

in this section, it shall have the meaning 

given in this section for purposes of this 

subpart. 

* * * * * 

Deviation means any instance in 

which an affected source subject to this 

subpart, or an owner or operator of such 

a source: 

(1) Fails to meet any requirement or 

obligation established by this subpart, 

including but not limited to any 

emission limit, operating limit, or work 

practice standard; or 

(2) Fails to meet any term or condition 

that is adopted to implement an 

applicable requirement in this subpart 

and that is included in the operating 

permit for any affected source required 

to obtain such a permit. 

* * * * * 

Hot standby means periods when the 

catalytic cracking unit is not receiving 

fresh or recycled feed oil but the 

catalytic cracking unit is maintained at 

elevated temperatures, typically using 

torch oil in the catalyst regenerator and 

recirculating catalyst, to prevent a 

complete shutdown and cold restart of 

the catalytic cracking unit. 

* * * * * 

PM means, for the purposes of this 

subpart, emissions of particulate matter 

that serve as a surrogate measure of the 

total emissions of particulate matter and 

metal HAP contained in the particulate 

matter, including but not limited to: 

Antimony, arsenic, beryllium, 

cadmium, chromium, cobalt, lead, 

manganese, nickel, and selenium as 

measured by Methods 5, 5B or 5F in 

appendix A–3 to part 60 of this chapter 

or by an approved alternative method. 

* * * * * 

■ 52. Table 1 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(a)(1), you shall 

meet each emission limitation in the 

following table that applies to you. 

TABLE 1 TO SUBPART UUU OF PART 63—METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS

For each new or existing catalytic cracking unit . . . You shall meet the following emission limits for 

each catalyst regenerator vent . . . 

1. Subject to new source performance standard (NSPS) for PM in 40 

CFR 60.102 and not electing § 60.100(e).

PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/

1,000 lb) of coke burn-off, and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in 

any 1-hour period. Before August 1, 2017, if the discharged gases 

pass through an incinerator or waste heat boiler in which you burn 

auxiliary or in supplemental liquid or solid fossil fuel, the incremental 

rate of PM emissions must not exceed 43.0 grams per Gigajoule (g/

GJ) or 0.10 pounds per million British thermal units (lb/million Btu) of 

heat input attributable to the liquid or solid fossil fuel; and the opacity 

of emissions must not exceed 30 percent, except for one 6-minute 

average opacity reading in any 1-hour period. 

2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i); or 40 CFR 

60.102 and electing § 60.100(e).

PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) of coke 

burn-off or, if a PM CEMS is used, 0.040 grain per dry standard 

cubic feet (gr/dscf) corrected to 0 percent excess air. 

3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii) .......................... PM emissions must not exceed 0.5 g/kg coke burn-off (0.5 lb/1000 lb 

coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0 

percent excess air. 

4. Option 1a: Elect NSPS subpart J requirements for PM per coke burn 

limit and 30% opacity, not subject to the NSPS for PM in 40 CFR 

60.102 or 60.102a(b)(1).

PM emissions must not exceed the limits specified in Item 1 of this 

table. 

5. Option 1b: Elect NSPS subpart Ja requirements for PM per coke 

burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 

60.102a(b)(1).

PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1000 lb) of coke 

burn-off. 

6. Option 1c: Elect NSPS subpart Ja requirements for PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or 

60.102a(b)(1).

PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent 

excess air. 

7. Option 2: PM per coke burn-off limit, not subject to the NSPS for PM 

in 40 CFR 60.102 or 60.102a(b)(1).

PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1000 lb) of coke 

burn-off in the catalyst regenerator. 

8. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 

60.102 or 60.102a(b)(1).

Nickel (Ni) emissions must not exceed 13,000 milligrams per hour (mg/

hr) (0.029 lb/hr). 

9. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM 

in 40 CFR 60.102 or 60.102a(b)(1).

Ni emissions must not exceed 1.0 mg/kg (0.001 lb/1,000 lb) of coke 

burn-off in the catalyst regenerator. 

■ 53. Table 2 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(a)(2), you shall 

meet each operating limit in the 

following table that applies to you. 

TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

1. Subject to the NSPS for PM in 

40 CFR 60.102 and not electing 

§ 60.100(e).

Continuous opacity monitoring 

system.

Any ................................................ Maintain the 3-hour rolling average opacity of emissions from 

your catalyst regenerator vent 

no higher than 20 percent. 


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TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

2. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i) or electing 

§ 60.100(e).

a. PM CEMS ................................. Any ................................................ Not applicable. 

b. Continuous opacity monitoring 

system used to comply with a 

site-specific opacity limit.

Cyclone or electrostatic precipitator.Maintain the 3-hour rolling average opacity of emissions from 

your catalyst regenerator vent 

no higher than the site-specific 

opacity limit established during 

the performance test. 

c. Continuous parameter monitoring systems.Electrostatic precipitator ............... i. Maintain the daily average coke 

burn-off rate or daily average 

flow rate no higher than the 

limit established in the performance test. 

ii. Maintain the 3-hour rolling average total power and secondary 

current above the limit established in the performance test. 

d. Continuous parameter monitoring systems.Wet scrubber ................................ i. Maintain the 3-hour rolling average liquid-to-gas ratio above 

the limit established in the performance test. 

ii. Except for periods of startup, 

shutdown, and hot standby, 

maintain the 3-hour rolling average pressure drop above the 

limit established in the performance test.1

e. Bag leak detection (BLD) system.Fabric filter .................................... Maintain particulate loading below 

the BLD alarm set point established in the initial adjustment 

of the BLD system or allowable 

seasonal adjustments. 

3. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii).

Any ................................................ Any ................................................ The applicable operating limits in 

Item 2 of this table. 

4. Option 1a: Elect NSPS subpart 

J requirements for PM per coke 

burn limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

Any ................................................ Any ................................................ See Item 1 of this table.

5. Option 1b: Elect NSPS subpart 

Ja requirements for PM per coke 

burn-off limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

Any ................................................ Any ................................................ The applicable operating limits in 

Item 2.b, 2.c, 2.d, and 2.e of 

this table. 

6. Option 1c: Elect NSPS subpart 

Ja requirements for PM concentration limit, not subject to 

the NSPS for PM in 40 CFR 

60.102 or 60.102a(b)(1).

PM CEMS ..................................... Any ................................................ Not applicable. 

7. Option 2: PM per coke burn-off 

limit not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.102a(b)(1).

a. Continuous opacity monitoring 

system used to comply with a 

site-specific opacity limit.

Cyclone, fabric filter, or electrostatic precipitator.See Item 2.b of this table. Alternatively, before August 1, 2017, 

you may maintain the hourly 

average opacity of emissions 

from your catalyst generator 

vent no higher than the sitespecific opacity limit established 

during the performance test. 

b. Continuous parameter monitoring systems.i. Electrostatic precipitator ............ (1) See Item 2.c.i of this table. 

(2) See item 2.c.ii of this table. Alternatively, before August 1, 

2017, you may maintain the 

daily average voltage and secondary current above the limit 

established in the performance 

test. 


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TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

ii. Wet scrubber ............................ (1) See Item 2.d.i of this table. Alternatively, before August 1, 

2017, you may maintain the 

daily average liquid-to-gas ratio 

above the limit established in 

the performance test. 

(2) See Item 2.d.ii of the table. Alternatively, before August 1, 

2017, you may maintain the 

daily average pressure drop 

above the limit established in 

the performance test (not applicable to a wet scrubber of the 

non-venturi jet-ejector design). 

c. Bag leak detection (BLD) system.Fabric filter .................................... See item 2.e of this table. 

8. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 

CFR 60.102.

a. Continuous opacity monitoring 

system.

Cyclone, fabric filter, or electrostatic precipitator.Maintain the 3-hour rolling average Ni operating value no higher than the limit established 

during the performance test. Alternatively, before August 1, 

2017, you may maintain the 

daily average Ni operating 

value no higher than the limit 

established during the performance test. 

b. Continuous parameter monitoring systems.i. Electrostatic precipitator ............ (1) See Item 2.c.i of this table. 

(2) Maintain the monthly rolling 

average of the equilibrium catalyst Ni concentration no higher 

than the limit established during 

the performance test. 

(3) See Item 2.c.ii of this table. Alternatively, before August 1, 

2017, you may maintain the 

daily average voltage and secondary current (or total power 

input) above the established 

during the performance test. 

ii. Wet scrubber ............................ (1) Maintain the monthly rolling 

average of the equilibrium catalyst Ni concentration no higher 

than the limit established during 

the performance test. 

(2) See Item 2.d.i of this table. Alternatively, before August 1, 

2017, you may maintain the 

daily average liquid-to-gas ratio 

above the limit established during the performance test. 

(3) See Item 2.d.ii of this table. Alternatively, before August 1, 

2017, you may maintain the 

daily average pressure drop 

above the limit established during the performance test (not 

applicable to a non-venturi wet 

scrubber of the jet-ejector design). 

c. Bag leak detection (BLD) system.Fabric filter .................................... See item 2.e of this table. 


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TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

9. Option 4: Ni per coke burn-off 

limit not subject to the NSPS for 

PM in 40 CFR 60.102.

a. Continuous opacity monitoring 

system.

Cyclone, fabric filter, or electrostatic precipitator.Maintain the 3-hour rolling average Ni operating value no higher than Ni operating limit established during the performance 

test. Alternatively, before August 1, 2017, you may elect to 

maintain the daily average Ni 

operating value no higher than 

the Ni operating limit established during the performance 

test. 

b. Continuous parameter monitoring systems.i. Electrostatic precipitator ............ (1) Maintain the monthly rolling 

average of the equilibrium catalyst Ni concentration no higher 

than the limit established during 

the performance test. 

(2) See Item 2.c.ii of this table. Alternatively, before August 1, 

2017, you may maintain the 

daily average voltage and secondary current (or total power 

input) above the limit established during the performance 

test. 

ii. Wet scrubber ............................ (1) Maintain the monthly rolling 

average of the equilibrium catalyst Ni concentration no higher 

than the limit established during 

the performance test. 

(2) See Item 2.d.i of this table. Alternatively, before August 1, 

2017, you may maintain the 

daily average liquid-to-gas ratio 

above the limit established during the performance test. 

(3) See Item 2.d.ii of this table. Alternatively, before August 1, 

2017, you may maintain the 

daily average pressure drop 

above the limit established during the performance test (not 

applicable to a non-venturi wet 

scrubber of the jet-ejector design). 

c. Bag leak detection (BLD) system.Fabric filter .................................... See item 2.e of this table. 

10. During periods of startup, shutdown, or hot standby.Any ................................................ Any ................................................ Meet the requirements in 

§ 63.1564(a)(5). 

1 If you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, you can use the alternative in 

§ 63.1573(b), and comply with the daily inspections, recordkeeping, and repair provisions, instead of a continuous parameter monitoring system 

for pressure drop across the scrubber. 

■ 54. Table 3 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(b)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS

For each new or existing catalytic 

cracking unit . . . 

If you use this type of control device for your vent . . . You shall install, operate, and maintain a . . . 

1. Subject to the NSPS for PM in 

40 CFR 60.102 and not electing 

§ 60.100(e).

Any ................................................. Continuous opacity monitoring system to measure and record the 

opacity of emissions from each catalyst regenerator vent. 


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TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

If you use this type of control device for your vent . . . You shall install, operate, and maintain a . . . 

2. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i); or in 

§ 60.102 and electing 

§ 60.100(e); electing to meet the 

PM per coke burn-off limit.

a. Cyclone ......................................

b. Electrostatic precipitator ............

Continuous opacity monitoring system to measure and record the 

opacity of emissions from each catalyst regenerator vent. 

Continuous opacity monitoring system to measure and record the 

opacity of emissions from each catalyst regenerator vent; or continuous parameter monitoring systems to measure and record the 

coke burn-off rate or the gas flow rate entering or exiting the control device,1 the voltage, current, and secondary current to the control device. 

c. Wet scrubber ............................. Continuous parameter monitoring system to measure and record the 

pressure drop across the scrubber,2 the coke burn-off rate or the 

gas flow rate entering or exiting the control device,3 and total liquid 

(or scrubbing liquor) flow rate to the control device. 

d. Fabric Filter ............................... Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent. 

3. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i); or in 

§ 60.102 and electing 

§ 60.100(e); electing to meet the 

PM concentration limit.

Any ................................................. Continuous emission monitoring system to measure and record the 

concentration of PM and oxygen from each catalyst regenerator 

vent. 

4. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii) electing to 

meet the PM per coke burn-off 

limit.

Any ................................................. The applicable continuous monitoring systems in item 2 of this table. 

5. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii) electing to 

meet the PM concentration limit.

Any ................................................. See item 3 of this table. 

6. Option 1a: Elect NSPS subpart 

J, PM per coke burn-off limit, not 

subject to the NSPS for PM in 40 

CFR 60.102 or 60.120a(b)(1).

Any ................................................. See item 1 of this table. 

7. Option 1b: Elect NSPS subpart 

Ja, PM per coke burn-off limit, 

not subject to the NSPS for PM 

in 40 CFR 60.102 or 

60.120a(b)(1).

Any ................................................. The applicable continuous monitoring systems in item 2 of this table. 

8. Option 1c: Elect NSPS subpart 

Ja, PM concentration limit not 

subject to the NSPS for PM in 40 

CFR 60.102 or 60.120a(b)(1).

Any ................................................. See item 3 of this table. 

9. Option 2: PM per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.120a(b)(1).

Any ................................................. The applicable continuous monitoring systems in item 2 of this table. 

10. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 

CFR 60.102 or 60.102a(b)(1).

a. Cyclone ...................................... Continuous opacity monitoring system to measure and record the 

opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the 

gas flow rate entering or exiting the control device.1

b. Electrostatic precipitator ............ Continuous opacity monitoring system to measure and record the 

opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the 

gas flow rate entering or exiting the control device 1; or continuous 

parameter monitoring systems to measure and record the coke 

burn-off rate or the gas flow rate entering or exiting the control device 1 and the voltage and current (to measure the total power to 

the system) and secondary current to the control device. 

c. Wet scrubber ............................. Continuous parameter monitoring system to measure and record the 

pressure drop across the scrubber,2 gas flow rate entering or 

exiting the control device,1 and total liquid (or scrubbing liquor) flow 

rate to the control device. 

d. Fabric Filter ............................... Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent or the monitoring systems specified in item 10.a of this 

table. 

11. Option 4: Ni per coke burn-off 

limit not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.102a(b)(1).

a. Cyclone ...................................... Continuous opacity monitoring system to measure and record the 

opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the 

coke burn-off rate and the gas flow rate entering or exiting the control device.1


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75285 

TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . 

If you use this type of control device for your vent . . . You shall install, operate, and maintain a . . . 

b. Electrostatic precipitator ............ Continuous opacity monitoring system to measure and record the 

opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the 

coke burn-off rate and the gas flow rate entering or exiting the control device 1; or continuous parameter monitoring systems to measure and record the coke burn-off rate or the gas flow rate entering 

or exiting the control device 1 and voltage and current (to measure 

the total power to the system) and secondary current to the control 

device. 

c. Wet scrubber ............................. Continuous parameter monitoring system to measure and record the 

pressure drop across the scrubber,2 gas flow rate entering or 

exiting the control device,1 and total liquid (or scrubbing liquor) flow 

rate to the control device. 

d. Fabric Filter ............................... Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent or the monitoring systems specified in item 11.a of this 

table. 

12. Electing to comply with the operating limits in 

§ 63.1566(a)(5)(iii) during periods 

of startup, shutdown, or hot 

standby.

Any ................................................. Continuous parameter monitoring system to measure and record the 

gas flow rate exiting the catalyst regenerator.1

1 If applicable, you can use the alternative in § 63.1573(a)(1) instead of a continuous parameter monitoring system for gas flow rate. 2 If you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, you can use the alternative in 

§ 63.1573(b) instead of a continuous parameter monitoring system for pressure drop across the scrubber. 

■ 55. Table 4 to subpart UUU of part 63 

is revised to read as follows: 

As stated in §§ 63.1564(b)(2) and 

63.1571(a)(5), you shall meet each 

requirement in the following table that 

applies to you. 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

1. Any ............................................. a. Select sampling port’s location 

and the number of traverse 

ports.

Method 1 or 1A in appendix A–1 

to part 60 of this chapter.

Sampling sites must be located at 

the outlet of the control device 

or the outlet of the regenerator, 

as applicable, and prior to any 

releases to the atmosphere. 

b. Determine velocity and volumetric flow rate.Method 2, 2A, 2C, 2D, or 2F in 

appendix A–1 to part 60 of this 

chapter, or Method 2G in appendix A–2 to part 60 of this 

chapter, as applicable.

c. Conduct gas molecular weight 

analysis.

Method 3, 3A, or 3B in appendix 

A–2 to part 60 of this chapter, 

as applicable.

d. Measure moisture content of 

the stack gas.

Method 4 in appendix A–3 to part 

60 of this chapter.

e. If you use an electrostatic precipitator, record the total number of fields in the control system and how many operated 

during the applicable performance test.

f. If you use a wet scrubber, 

record the total amount (rate) of 

water (or scrubbing liquid) and 

the amount (rate) of make-up 

liquid to the scrubber during 

each test run.


tkelley on DSK3SPTVN1PROD with RULES2
75286 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

2. Subject to the NSPS for PM in 

40 CFR 60.102 and not elect 

§ 60.100(e).

a. Measure PM emissions ............ Method 5, 5B, or 5F (40 CFR part 

60, appendix A–3) to determine 

PM emissions and associated 

moisture content for units without wet scrubbers. Method 5 or 

5B (40 CFR part 60, appendix 

A–3) to determine PM emissions and associated moisture 

content for unit with wet scrubber.

You must maintain a sampling 

rate of at least 0.15 dry standard cubic meters per minute 

(dscm/min) (0.53 dry standard 

cubic feet per minute (dscf/

min)). 

b. Compute coke burn-off rate 

and PM emission rate (lb/1,000 

lb of coke burn-off).

Equations 1, 2, and 3 of 

§ 63.1564 (if applicable).

c. Measure opacity of emissions .. Continuous opacity monitoring 

system.

You must collect opacity monitoring data every 10 seconds 

during the entire period of the 

Method 5, 5B, or 5F performance test and reduce the data 

to 6-minute averages. 

3. Subject to the NSPS for PM in 

40 CFR 60.102a(b)(1) or elect 

§ 60.100(e), electing the PM for 

coke burn-off limit.

a. Measure PM emissions ............ Method 5, 5B, or 5F (40 CFR part 

60, appendix A–3) to determine 

PM emissions and associated 

moisture content for units without wet scrubbers. Method 5 or 

5B (40 CFR part 60, appendix 

A–3) to determine PM emissions and associated moisture 

content for unit with wet scrubber.

You must maintain a sampling 

rate of at least 0.15 dscm/min 

(0.53 dscf/min). 

b. Compute coke burn-off rate 

and PM emission rate (lb/1,000 

lb of coke burn-off).

Equations 1, 2, and 3 of 

§ 63.1564 (if applicable).

c. Establish site-specific limit if 

you use a COMS.

Continuous opacity monitoring 

system.

If you elect to comply with the 

site-specific opacity limit in 

§ 63.1564(b)(4)(i), you must collect opacity monitoring data 

every 10 seconds during the 

entire period of the Method 5, 

5B, or 5F performance test. For 

site specific opacity monitoring, 

reduce the data to 6-minute 

averages; determine and record 

the average opacity for each 

test run; and compute the sitespecific opacity limit using 

Equation 4 of § 63.1564. 

4. Subject to the NSPS for PM in 

40 CFR 60.102a(b)(1) or elect 

§ 60.100(e).

a. Measure PM emissions ............ Method 5, 5B, or 5F (40 CFR part 

60, appendix A–3) to determine 

PM emissions and associated 

moisture content for units without wet scrubbers. Method 5 or 

5B (40 CFR part 60, appendix 

A–3) to determine PM emissions and associated moisture 

content for unit with wet scrubber.

You must maintain a sampling 

rate of at least 0.15 dscm/min 

(0.53 dscf/min). 

5. Option 1a: Elect NSPS subpart 

J requirements for PM per coke 

burn-off limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

See item 2 of this table. .......................................................

6. Option 1b: Elect NSPS subpart 

Ja requirements for PM per coke 

burn-off limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

See item 3 of this table.


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75287 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

7. Option 1c: Elect NSPS requirements for PM concentration, not 

subject to the NSPS for PM in 

40 CFR 60.102 or 60.102a(b)(1).

See item 4 of this table.

8. Option 2: PM per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.102a(b)(1).

See item 3 of this table.

9. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 

CFR 60.102 or 60.102a(b)(1).

a. Measure concentration of Ni ....

b. Compute Ni emission rate (lb/

hr).

Method 29 (40 CFR part 60, appendix A–8).

Equation 5 of § 63.1564.

c. Determine the equilibrium catalyst Ni concentration.XRF procedure in appendix A to 

this subpart1; or EPA Method 

6010B or 6020 or EPA Method 

7520 or 7521 in SW–8462; or 

an alternative to the SW–846 

method satisfactory to the Administrator.

You must obtain 1 sample for 

each of the 3 test runs; determine and record the equilibrium 

catalyst Ni concentration for 

each of the 3 samples; and you 

may adjust the laboratory results to the maximum value 

using Equation 2 of § 63.1571. 

d. If you use a continuous opacity 

monitoring system, establish 

your site-specific Ni operating 

limit.

i. Equations 6 and 7 of § 63.1564 

using data from continuous 

opacity monitoring system, gas 

flow rate, results of equilibrium 

catalyst Ni concentration analysis, and Ni emission rate from 

Method 29 test.

(1) You must collect opacity monitoring data every 10 seconds 

during the entire period of the 

initial Ni performance test; reduce the data to 6-minute averages; and determine and record 

the average opacity from all the 

6-minute averages for each test 

run. 

(2) You must collect gas flow rate 

monitoring data every 15 minutes during the entire period of 

the initial Ni performance test; 

measure the gas flow as near 

as practical to the continuous 

opacity monitoring system; and 

determine and record the hourly 

average actual gas flow rate for 

each test run. 

10. Option 4: Ni per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.102a(b)(1).

a. Measure concentration of Ni. 

b. Compute Ni emission rate (lb/

1,000 lb of coke burn-off).

Method 29 (40 CFR part 60, appendix A–8). 

Equations 1 and 8 of § 63.1564.

c. Determine the equilibrium catalyst Ni concentration.See item 6.c. of this table ............ You must obtain 1 sample for 

each of the 3 test runs; determine and record the equilibrium 

catalyst Ni concentration for 

each of the 3 samples; and you 

may adjust the laboratory results to the maximum value 

using Equation 2 of § 63.1571. 

d. If you use a continuous opacity 

monitoring system, establish 

your site-specific Ni operating 

limit.

i. Equations 9 and 10 of 

§ 63.1564 with data from continuous opacity monitoring system, coke burn-off rate, results 

of equilibrium catalyst Ni concentration analysis, and Ni 

emission rate from Method 29 

test.

(1) You must collect opacity monitoring data every 10 seconds 

during the entire period of the 

initial Ni performance test; reduce the data to 6-minute averages; and determine and record 

the average opacity from all the 

6-minute averages for each test 

run. 


tkelley on DSK3SPTVN1PROD with RULES2
75288 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

(2) You must collect gas flow rate 

monitoring data every 15 minutes during the entire period of 

the initial Ni performance test; 

measure the gas flow rate as 

near as practical to the continuous opacity monitoring system; and determine and record 

the hourly average actual gas 

flow rate for each test run. 

e. Record the catalyst addition 

rate for each test and schedule 

for the 10-day period prior to 

the test.

11. If you elect item 5 Option 1b in 

Table 1, item 7 Option 2 in 

Table 1, item 8 Option 3 in 

Table 1, or item 9 Option 4 in 

Table 1 of this subpart and you 

use continuous parameter monitoring systems.

a. Establish each operating limit in 

Table 2 of this subpart that applies to you.

Data from the continuous parameter monitoring systems and 

applicable performance test 

methods.

b. Electrostatic precipitator or wet 

scrubber: Gas flow rate.

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect gas flow rate 

monitoring data every 15 minutes during the entire period of 

the initial performance test; determine and record the average 

gas flow rate for each test run. 

(2) You must determine and 

record the 3-hr average gas 

flow rate from the test runs. Alternatively, before August 1, 

2017, you may determine and 

record the maximum hourly average gas flow rate from all the 

readings. 

c. Electrostatic precipitator: Total 

power (voltage and current) and 

secondary current.

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect voltage, current, and secondary current 

monitoring data every 15 minutes during the entire period of 

the performance test; and determine and record the average 

voltage, current, and secondary 

current for each test run. Alternatively, before August 1, 2017, 

you may collect voltage and 

secondary current (or total 

power input) monitoring data 

every 15 minutes during the entire period of the initial performance test. 

(2) You must determine and 

record the 3-hr average total 

power to the system for the test 

runs and the 3-hr average secondary current from the test 

runs. Alternatively, before August 1, 2017, you may determine and record the minimum 

hourly average voltage and 

secondary current (or total 

power input) from all the readings. 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75289 

TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

You must . . . Using . . . According to these 

requirements . . . 

d. Electrostatic precipitator or wet 

scrubber: Equilibrium catalyst 

Ni concentration.

Results of analysis for equilibrium 

catalyst Ni concentration.

You must determine and record 

the average equilibrium catalyst 

Ni concentration for the 3 runs 

based on the laboratory results. 

You may adjust the value using 

Equation 1 or 2 of § 63.1571 as 

applicable. 

e. Wet scrubber: Pressure drop 

(not applicable to non-venturi 

scrubber of jet ejector design).

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect pressure 

drop monitoring data every 15 

minutes during the entire period 

of the initial performance test; 

and determine and record the 

average pressure drop for each 

test run. 

(2) You must determine and 

record the 3-hr average pressure drop from the test runs. Alternatively, before August 1, 

2017, you may determine and 

record the minimum hourly average pressure drop from all 

the readings. 

f. Wet scrubber: Liquid-to-gas 

ratio.

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect gas flow rate 

and total water (or scrubbing 

liquid) flow rate monitoring data 

every 15 minutes during the entire period of the initial performance test; determine and record 

the average gas flow rate for 

each test run; and determine 

the average total water (or 

scrubbing liquid) flow for each 

test run. 

(2) You must determine and 

record the hourly average liquid-to-gas ratio from the test 

runs. Alternatively, before August 1, 2017, you may determine and record the hourly average gas flow rate and total 

water (or scrubbing liquid) flow 

rate from all the readings. 

(3) You must determine and 

record the 3-hr average liquidto-gas ratio. Alternatively, before August 1, 2017, you may 

determine and record the minimum liquid-to-gas ratio. 

g. Alternative procedure for gas 

flow rate.

i. Data from the continuous parameter monitoring systems 

and applicable performance test 

methods.

(1) You must collect air flow rate 

monitoring data or determine 

the air flow rate using control 

room instrumentation every 15 

minutes during the entire period 

of the initial performance test. 

(2) You must determine and 

record the 3-hr average rate of 

all the readings from the test 

runs. Alternatively, before August 1, 2017, you may determine and record the hourly average rate of all the readings. 

(3) You must determine and 

record the maximum gas flow 

rate using Equation 1 of 

§ 63.1573. 

1 Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure). 


tkelley on DSK3SPTVN1PROD with RULES2
75290 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

2EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, and EPA Method 7521, Nickel Atomic Absorption, Direct Aspiration are 

included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW– 

846 and Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government 

Publishing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, 

Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building, (Air 

Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 

700, Washington, DC. 

■ 56. Table 5 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(b)(5), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS

For each new and existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

For the following emission 

limit . . . You have demonstrated initial compliance if . . . 

1. Subject to the NSPS for PM in 

40 CFR 60.102 and not electing 

§ 60.100(e).

PM emissions must not exceed 

1.0 g/kg (1.0 lb/1,000 lb) of coke 

burn-off, and the opacity of 

emissions must not exceed 30 

percent, except for one 6-minute 

average opacity reading in any 

1-hour period. Before August 1, 

2017, if the discharged gases 

pass through an incinerator or 

waste heat boiler in which you 

burn auxiliary or supplemental 

liquid or solid fossil fuel, the incremental rate of PM must not 

exceed 43.0 g/GJ or 0.10 lb/million Btu of heat input attributable 

to the liquid or solid fossil fuel; 

and the opacity of emissions 

must not exceed 30 percent, except for one 6-minute average 

opacity reading in any 1-hour 

period.

You have already conducted a performance test to demonstrate initial 

compliance with the NSPS and the measured PM emission rate is 

less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in 

the catalyst regenerator. As part of the Notification of Compliance 

Status, you must certify that your vent meets the PM limit. You are 

not required to do another performance test to demonstrate initial 

compliance. You have already conducted a performance test to 

demonstrate initial compliance with the NSPS and the average 

hourly opacity is no more than 30 percent, except that one 6- 

minute average in any 1-hour period can exceed 30 percent. As 

part of the Notification of Compliance Status, you must certify that 

your vent meets the 30 percent opacity limit. As part of your Notification of Compliance Status, you certify that your continuous opacity monitoring system meets the requirements in § 63.1572. 

2. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i); or in 

§ 60.102 and electing 

§ 60.100(e); electing to meet the 

PM per coke burn-off limit.

PM emissions must not exceed 

1.0 g/kg (1.0 lb PM/1,000 lb) of 

coke burn-off.

You have already conducted a performance test to demonstrate initial 

compliance with the NSPS and the measured PM emission rate is 

less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in 

the catalyst regenerator. As part of the Notification of Compliance 

Status, you must certify that your vent meets the PM limit. You are 

not required to do another performance test to demonstrate initial 

compliance. As part of your Notification of Compliance Status, you 

certify that your BLD; CO2, O2, or CO monitor; or continuous opacity monitoring system meets the requirements in § 63.1572. 

3. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i), electing to 

meet the PM per coke burn-off 

limit.

PM emissions must not exceed 

0.5 g/kg (0.5 lb PM/1,000 lb) of 

coke burn-off).

You have already conducted a performance test to demonstrate initial 

compliance with the NSPS and the measured PM emission rate is 

less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in 

the catalyst regenerator. As part of the Notification of Compliance 

Status, you must certify that your vent meets the PM limit. You are 

not required to do another performance test to demonstrate initial 

compliance. As part of your Notification of Compliance Status, you 

certify that your BLD; CO2, O2, or CO monitor; or continuous opacity monitoring system meets the requirements in § 63.1572. 

4. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i), electing to 

meet the PM concentration limit.

If a PM CEMS is used, 0.040 

grain per dry standard cubic feet 

(gr/dscf) corrected to 0 percent 

excess air.

You have already conducted a performance test to demonstrate initial 

compliance with the NSPS and the measured PM concentration is 

less than or equal to 0.040 grain per dry standard cubic feet (gr/

dscf) corrected to 0 percent excess air. As part of the Notification 

of Compliance Status, you must certify that your vent meets the 

PM limit. You are not required to do another performance test to 

demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your PM CEMS meets the requirements in § 63.1572. 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75291 

TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS—Continued 

For each new and existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

For the following emission 

limit . . . You have demonstrated initial compliance if . . . 

5. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii), electing to 

meet the PM concentration limit.

If a PM CEMS is used, 0.020 gr/

dscf corrected to 0 percent excess air.

You have already conducted a performance test to demonstrate initial 

compliance with the NSPS and the measured PM concentration is 

less than or equal to 0.020 gr/dscf corrected to 0 percent excess 

air. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. You are not required to do 

another performance test to demonstrate initial compliance. As part 

of your Notification of Compliance Status, you certify that your PM 

CEMS meets the requirements in § 63.1572. 

6. Option 1a: Elect NSPS subpart J 

requirements for PM per coke 

burn-off limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

PM emissions must not exceed 

1.0 gram per kilogram (g/kg) 

(1.0 lb/1,000 lb) of coke burnoff, and the opacity of emissions 

must not exceed 30 percent, except for one 6-minute average 

opacity reading in any 1-hour 

period. Before August 1, 2017, 

PM emission must not exceed 

1.0 g/kg (1.0 lb/1,000 lb) of coke 

burn-off in the catalyst regenerator; if the discharged gases 

pass through an incinerator or 

waste heat boiler in which you 

burn auxiliary or supplemental 

liquid or solid fossil fuel, the incremental rate of PM must not 

exceed 43.0 g/GJ (0.10 lb/million Btu) of heat input attributable to the liquid or solid fossil 

fuel; and the opacity of emissions must not exceed 30 percent, except for one 6-minute 

average opacity reading in any 

1-hour period.

The average PM emission rate, measured using EPA Method 5, 5B, 

or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with 

a wet scrubber) (40 CFR part 60, appendix A–3), over the period 

of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission 

rate is calculated using Equations 1, 2, and 3 of § 63.1564. As part 

of the Notification of Compliance Status, you must certify that your 

vent meets the PM limit. The average hourly opacity is no more 

than 30 percent, except that one 6-minute average in any 1-hour 

period can exceed 30 percent. As part of the Notification of Compliance Status, you must certify that your vent meets the 30 percent opacity limit. If you use a continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572. 

7. Option 1b: Elect NSPS subpart 

Ja requirements for PM per coke 

burn-off limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

PM emissions must not exceed 

1.0 g/kg (1.0 lb/1,000 lb) of coke 

burn-off.

The average PM emission rate, measured using EPA Method 5, 5B, 

or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with 

a wet scrubber) (40 CFR part 60, appendix A–3), over the period 

of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission 

rate is calculated using Equations 1, 2, and 3 of § 63.1564. If you 

use a BLD; CO2, O2, CO monitor; or continuous opacity monitoring 

system, your performance evaluation shows the system meets the 

applicable requirements in § 63.1572. 

8. Option 1c: Elect NSPS subpart 

Ja requirements for PM concentration limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

PM emissions must not exceed 

0.040 gr/dscf corrected to 0 percent excess air.

The average PM concentration, measured using EPA Method 5, 5B, 

or 5F (for a unit without a wet scrubber) or Method 5 or 5B (for a 

unit with a wet scrubber) (40 CFR part 60, appendix A–3), over the 

period of the initial performance test, is less than or equal to 0.040 

gr/dscf corrected to 0 percent excess air. Your performance evaluation shows your PM CEMS meets the applicable requirements in 

§ 63.1572. 

9. Option 2: PM per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.102a(b)(1).

PM emissions must not exceed 

1.0 g/kg (1.0 lb/1,000 lb) of coke 

burn-off.

The average PM emission rate, measured using EPA Method 5, 5B, 

or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with 

a wet scrubber) (40 CFR part 60, appendix A–3), over the period 

of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission 

rate is calculated using Equations 1, 2, and 3 of § 63.1564. If you 

use a BLD; CO2, O2, CO monitor; or continuous opacity monitoring 

system, your performance evaluation shows the system meets the 

applicable requirements in § 63.1572. 

10. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 

CFR 60.102 or 60.102a(b)(1).

Nickel (Ni) emissions from your 

catalyst regenerator vent must 

not exceed 13,000 mg/hr (0.029 

lb/hr).

The average Ni emission rate, measured using Method 29 (40 CFR 

part 60, appendix A–8) over the period of the initial performance 

test, is not more than 13,000 mg/hr (0.029 lb/hr). The Ni emission 

rate is calculated using Equation 5 of § 63.1564; and if you use a 

BLD; CO2, O2, or CO monitor; or continuous opacity monitoring 

system, your performance evaluation shows the system meets the 

applicable requirements in § 63.1572. 


tkelley on DSK3SPTVN1PROD with RULES2
75292 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS—Continued 

For each new and existing catalytic 

cracking unit catalyst regenerator 

vent . . . 

For the following emission 

limit . . . You have demonstrated initial compliance if . . . 

11. Option 4: Ni per coke burn-off 

limit not subject to the NSPS for 

PM.

Ni emissions from your catalyst regenerator vent must not exceed 

1.0 mg/kg (0.001 lb/1,000 lb) of 

coke burn-off in the catalyst regenerator.

The average Ni emission rate, measured using Method 29 (40 CFR 

part 60, appendix A–8) over the period of the initial performance 

test, is not more than 1.0 mg/kg (0.001 lb/1,000 lb) of coke burn-off 

in the catalyst regenerator. The Ni emission rate is calculated using 

Equation 8 of § 63.1564; and if you use a BLD; CO2, O2, or CO 

monitor; or continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572. 

■ 57. Table 6 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS

For each new and existing catalytic 

cracking unit . . . 

Subject to this emission limit for 

your catalyst regenerator vent . . . You shall demonstrate continuous compliance by . . . 

1. Subject to the NSPS for PM in 

40 CFR 60.102 and not electing 

§ 60.100(e).

a. PM emissions must not exceed 

1.0 g/kg (1.0 lb/1,000 lb) of coke 

burn-off, and the opacity of 

emissions must not exceed 30 

percent, except for one 6-minute 

average opacity reading in any 

1-hour period. Before August 1, 

2017, if the discharged gases 

pass through an incinerator or 

waste heat boiler in which you 

burn auxiliary or supplemental 

liquid or solid fossil fuel, the incremental rate of PM must not 

exceed 43.0 g/GJ (0.10 lb/million Btu) of heat input attributable to the liquid or solid fossil 

fuel; and the opacity of emissions must not exceed 30 percent, except for one 6-minute 

average opacity reading in any 

1-hour period.

i. Determining and recording each day the average coke burn-off rate 

(thousands of kilograms per hour) using Equation 1 in § 63.1564 

and the hours of operation for each catalyst regenerator. 

ii. Conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit. 

iii. Collecting the continuous opacity monitoring data for each catalyst 

regenerator vent according to § 63.1572 and maintaining each 6- 

minute average at or below 30 percent, except that one 6-minute 

average during a 1-hour period can exceed 30 percent. 

iv. Before August 1, 2017, if applicable, determining and recording 

each day the rate of combustion of liquid or solid fossil fuels (liters/

hour or kilograms/hour) and the hours of operation during which 

liquid or solid fossil-fuels are combusted in the incinerator-waste 

heat boiler; if applicable, maintaining the incremental rate of PM at 

or below 43 g/GJ (0.10 lb/million Btu) of heat input attributable to 

the solid or liquid fossil fuel. 

2. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i), electing to 

meet the PM per coke burn-off 

limit.

PM emissions must not exceed 

1.0 g/kg (1.0 lb PM/1,000 lb) of 

coke burn-off.

Determining and recording each day the average coke burn-off rate 

(thousands of kilograms per hour) using Equation 1 in § 63.1564 

and the hours of operation for each catalyst regenerator; maintaining PM emission rate below 1.0 g/kg (1.0 lb PM/1,000 lb) of coke 

burn-off; and conducting a performance test once every year. 

3. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii), electing to 

meet the PM per coke burn-off 

limit.

PM emissions must not exceed 

0.5 g/kg coke burn-off (0.5 lb/

1000 lb coke burn-off).

Determining and recording each day the average coke burn-off rate 

(thousands of kilograms per hour) using Equation 1 in § 63.1564 

and the hours of operation for each catalyst regenerator; maintaining PM emission rate below 0.5 g/kg (0.5 lb/1,000 lb) of coke burnoff; and conducting a performance test once every year. 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75293 

TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS—Continued 

For each new and existing catalytic 

cracking unit . . . 

Subject to this emission limit for 

your catalyst regenerator vent . . . You shall demonstrate continuous compliance by . . . 

4. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(i), electing to 

meet the PM concentration limit.

If a PM CEMS is used, 0.040 

grain per dry standard cubic feet 

(gr/dscf) corrected to 0 percent 

excess air.

Maintaining PM concentration below 0.040 gr/dscf corrected to 0 percent excess air. 

5. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1)(ii), electing to 

meet the PM concentration limit.

If a PM CEMS is used, 0.020 gr/

dscf corrected to 0 percent excess air.

Maintaining PM concentration below 0.020 gr/dscf corrected to 0 percent excess air. 

6. Option 1a: Elect NSPS subpart J 

requirements for PM per coke 

burn-off limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

See item 1 of this table ................. See item 1 of this table. 

7. Option 1b: Elect NSPS subpart 

Ja requirements for PM per coke 

burn-off limit and 30% opacity, 

not subject to the NSPS for PM 

in 40 CFR 60.102 or 

60.102a(b)(1).

PM emissions must not exceed 

1.0 g/kg (1.0 lb PM/1,000 lb) of 

coke burn-off.

See item 2 of this table. 

8. Option 1c: Elect NSPS subpart 

Ja requirements for PM concentration limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

PM emissions must not exceed 

0.040 gr/dscf corrected to 0 percent excess air.

See item 4 of this table. 

9. Option 2: PM per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.102a(b)(1).

PM emissions must not exceed 

1.0 g/kg (1.0 lb PM/1,000 lb) of 

coke burn-off.

Determining and recording each day the average coke burn-off rate 

and the hours of operation and the hours of operation for each catalyst regenerator by Equation 1 of § 63.1564 (you can use process 

data to determine the volumetric flow rate); maintaining PM emission rate below 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off; and 

conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit. 

10. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 

CFR 60.102 or 60.102a(b)(1).

Ni emissions must not exceed 

13,000 mg/hr (0.029 lb/hr).

Maintaining Ni emission rate below 13,000 mg/hr (0.029 lb/hr); and 

conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit. 

11. Option 4: Ni per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.102a(b)(1).

Ni emissions must not exceed 1.0 

mg/kg (0.001 lb/1,000 lb) of 

coke burn-off in the catalyst regenerator.

Determining and recording each day the average coke burn-off rate 

(thousands of kilograms per hour) and the hours of operation for 

each catalyst regenerator by Equation 1 of § 63.1564 (you can use 

process data to determine the volumetric flow rate); and maintaining Ni emission rate below 1.0 mg/kg (0.001 lb/1,000 lb) of coke 

burn-off in the catalyst regenerator; and conducting a performance 

test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit. 

■ 58. Table 7 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1564(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

1. Subject to NSPS for PM in 40 

CFR 60.102 and not electing 

§ 60.100(e).

Continuous opacity monitoring 

system.

The 3-hour average opacity of 

emissions from your catalyst regenerator vent must not exceed 

20 percent.

Collecting the continuous opacity 

monitoring data for each regenerator vent according to 

§ 63.1572 and maintain each 3- 

hour rolling average opacity of 

emissions no higher than 20 

percent. 


tkelley on DSK3SPTVN1PROD with RULES2
75294 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

2. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1); or 40 CFR 

60.102 and elect § 60.100(e), 

electing to meet the PM per 

coke burn-off limit.

a. Continuous opacity monitoring 

system, used for site-specific 

opacity limit—Cyclone or electrostatic precipitator.

The average opacity must not exceed the opacity established 

during the performance test.

Collecting the hourly and 3-hr rolling average opacity monitoring 

data according to § 63.1572; 

maintaining the 3-hr rolling average opacity at or above the 

site-specific limit established 

during the performance test. 

b. Continuous parametric monitoring systems—electrostatic 

precipitator.

i. The average gas flow rate entering or exiting the control device must not exceed the operating limit established during 

the performance test.

Collecting the hourly and daily average coke burn-off rate or average gas flow rate monitoring 

data according to § 63.1572; 

and maintaining the daily average coke burn-off rate or average gas flow rate at or below 

the limit established during the 

performance test. 

ii. The average total power and 

secondary current to the control 

device must not fall below the 

operating limit established during the performance test.

Collecting the hourly and 3-hr rolling average total power and 

secondary current monitoring 

data according to § 63.1572; 

and maintaining the 3-hr rolling 

average total power and secondary current at or above the 

limit established during the performance test. 

c. Continuous parametric monitoring systems—wet scrubber.i. The average liquid-to-gas ratio 

must not fall below the operating limit established during 

the performance test.

Collecting the hourly and 3-hr rolling average gas flow rate and 

scrubber liquid flow rate monitoring data according to 

§ 63.1572; determining and recording the 3-hr liquid-to-gas 

ratio; and maintaining the 3-hr 

rolling average liquid-to-gas 

ratio at or above the limit established during the performance 

test. 

ii. Except for periods of startup, 

shutdown and hot standby, the 

average pressure drop across 

the scrubber must not fall below 

the operating limit established 

during the performance test.

Collecting the hourly and 3-hr rolling average pressure drop 

monitoring data according to 

§ 63.1572; and except for periods of startup, shutdown and 

hot standby, maintaining the 3- 

hr rolling average pressure drop 

at or above the limit established 

during the performance test. 

d. BLD—fabric filter ...................... Increases in relative particulate .... Collecting and maintaining 

records of BLD system output; 

determining the cause of the 

alarm within 1 hour of the 

alarm; and alleviating the cause 

of the alarm within 3 hours by 

corrective action. 

3. Subject to NSPS for PM in 40 

CFR 60.102a(b)(1), electing to 

meet the PM concentration limit.

PM CEMS ..................................... Not applicable ............................... Complying with Table 6 of this 

subpart, item 4 or 5. 

4. Option 1a: Elect NSPS subpart 

J requirements for PM per coke 

burn-off limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

Continuous opacity monitoring 

system.

The 3-hour average opacity of 

emissions from your catalyst regenerator vent must not exceed 

20 percent.

Collecting the 3-hr rolling average 

continuous opacity monitoring 

system data according to 

§ 63.1572; and maintaining the 

3-hr rolling average opacity no 

higher than 20 percent. 

5. Option 1b: Elect NSPS subpart 

Ja requirements for PM per coke 

burn-off limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or 60.102a(b)(1).

a. Continuous opacity monitoring 

system.

The opacity of emissions from 

your catalyst regenerator vent 

must not exceed the site-specific opacity operating limit established during the performance test.

Collecting the 3-hr rolling average 

continuous opacity monitoring 

system data according to 

§ 63.1572; maintaining the 3-hr 

rolling average opacity at or 

below the site-specific limit. 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75295 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

b. Continuous parametric monitoring systems—electrostatic 

precipitator.

See item 2.b of this table ............. See item 2.b of this table. 

c. Continuous parametric monitoring systems—wet scrubber.See item 2.c of this table ............. See item 2.c of this table. 

d. BLD—fabric filter ...................... See item 2.d of this table ............. See item 2.d of this table. 

6. Option 1c: Elect NSPS subpart 

Ja requirements for PM concentration limit, not subject to 

the NSPS for PM in 40 CFR 

60.102 or 60.102a(b)(1).

PM CEMS ..................................... Not applicable ............................... Complying with Table 6 of this 

subpart, item 4. 

7. Option 2: PM per coke burn-off 

limit, not subject to the NSPS for 

PM in 40 CFR 60.102 or 

60.102a(b)(1).

a. Continuous opacity monitoring 

system.

The opacity of emissions from 

your catalyst regenerator vent 

must not exceed the site-specific opacity operating limit established during the performance test.

Collecting the hourly and 3-hr rolling average continuous opacity 

monitoring system data according to § 63.1572; and maintaining the 3-hr rolling average 

opacity at or below the site-specific limit established during the 

performance test. Alternatively, 

before August 1, 2017, collecting the hourly average continuous opacity monitoring system data according to 

§ 63.1572; and maintaining the 

hourly average opacity at or 

below the site-specific limit. 

b. Continuous parameter monitoring systems—electrostatic 

precipitator.

i. The average coke burn-off rate 

or average gas flow rate entering or exiting the control device 

must not exceed the operating 

limit established during the performance test.

Collecting the hourly and daily average coke burn-off rate or gas 

flow rate monitoring data according to § 63.1572; and maintaining the daily coke burn-off 

rate or average gas flow rate at 

or below the limit established 

during the performance test. 

ii. The average total power (voltage and current) and secondary 

current to the control device 

must not fall below the operating limit established during 

the performance test.

Collecting the hourly and 3-hr rolling average total power and 

secondary current monitoring 

data according to § 63.1572; 

and maintaining the 3-hr rolling 

average total power and secondary current at or above the 

limit established during the performance test. Alternatively, before August 1, 2017, collecting 

the hourly and daily average 

voltage and secondary current 

(or total power input) monitoring 

data according to § 63.1572; 

and maintaining the daily average voltage and secondary current (or total power input) at or 

above the limit established during the performance test. 


tkelley on DSK3SPTVN1PROD with RULES2
75296 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

c. Continuous parameter monitoring systems—wet scrubber.i. The average liquid-to-gas ratio 

must not fall below the operating limit established during 

the performance test.

Collecting the hourly and 3-hr rolling average gas flow rate and 

scrubber liquid flow rate monitoring data according to 

§ 63.1572; determining and recording the 3-hr liquid-to-gas 

ratio; and maintaining the 3-hr 

rolling average liquid-to-gas 

ratio at or above the limit established during the performance 

test. Alternatively, before August 1, 2017, collecting the 

hourly average gas flow rate 

and water (or scrubbing liquid) 

flow rate monitoring data according to § 63.1572 1; determining and recording the hourly 

average liquid-to-gas ratio; determining and recording the 

daily average liquid-to-gas ratio; 

and maintaining the daily average liquid-to-gas ratio above 

the limit established during the 

performance test. 

ii. Except for periods of startup, 

shutdown and hot standby, the 

average pressure drop across 

the scrubber must not fall below 

the operating limit established 

during the performance test.

Collecting the hourly and 3-hr rolling average pressure drop 

monitoring data according to 

§ 63.1572; and except for periods of startup, shutdown and 

hot standby, maintaining the 3- 

hr rolling average pressure drop 

at or above the limit established 

during the performance test. Alternatively, before August 1, 

2017, collecting the hourly and 

daily average pressure drop 

monitoring data according to 

§ 63.1572; and maintaining the 

daily average pressure drop 

above the limit established during the performance test. 

d. BLD—fabric filter ...................... See item 2.d of this table ............. See item 2.d of this table. 

8. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 

CFR 60.102.

a. Continuous opacity monitoring 

system.

i. The daily average Ni operating 

value must not exceed the sitespecific Ni operating limit established during the performance 

test.

(1) Collecting the hourly average 

continuous opacity monitoring 

system data according to 

§ 63.1572; determining and recording equilibrium catalyst Ni 

concentration at least once a 

week 2; collecting the hourly average gas flow rate monitoring 

data according to § 63.1572 1; 

and determining and recording 

the hourly average Ni operating 

value using Equation 11 of 

§ 63.1564. 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75297 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

(2) Determining and recording the 

3-hour rolling average Ni operating value and maintaining the 

3-hour rolling average Ni operating value below the site-specific Ni operating limit established during the performance 

test. Alternatively, before August 1, 2017, determining and 

recording the daily average Ni 

operating value and maintaining 

the daily average Ni operating 

value below the site-specific Ni 

operating limit established during the performance test. 

b. Continuous parameter monitoring systems—electrostatic 

precipitator.

i. The average gas flow rate entering or exiting the control device must not exceed the operating limit established during 

the performance test.

See item 7.b.i of this table. 

ii. The average total power (voltage and current) and secondary 

current must not fall below the 

level established in the performance test.

See item 7.b.ii of this table. 

iii. The monthly rolling average of 

the equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

Determining and recording the 

equilibrium catalyst Ni concentration at least once a 

week 2; determining and recording the monthly rolling average 

of the equilibrium catalyst Ni 

concentration once each week 

using the weekly or most recent 

value; and maintaining the 

monthly rolling average below 

the limit established in the performance test. 

c. Continuous parameter monitoring systems—wet scrubber.i. The average liquid-to-gas ratio 

must not fall below the operating limit established during 

the performance test..

See item 7.c.i of this table. 

ii. Except for periods of startup, 

shutdown and hot standby, the 

average pressure drop must not 

fall below the operating limit established in the performance 

test.

See item 7.c.ii of this table. 

iii. The monthly rolling average 

equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

Determining and recording the 

equilibrium catalyst Ni concentration at least once a 

week 2; determining and recording the monthly rolling average 

of equilibrium catalyst Ni concentration once each week 

using the weekly or most recent 

value; and maintaining the 

monthly rolling average below 

the limit established in the performance test. 

d. BLD—fabric filter ...................... i. Increases in relative particulate See item 7.d of this table. 


tkelley on DSK3SPTVN1PROD with RULES2
75298 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

ii. The monthly rolling average of 

the equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

Determining and recording the 

equilibrium catalyst Ni concentration at least once a 

week 2; determining and recording the monthly rolling average 

of the equilibrium catalyst Ni 

concentration once each week 

using the weekly or most recent 

value; and maintaining the 

monthly rolling average below 

the limit established in the performance test. 

9. Option 4: Ni per coke burn-off 

limit not subject to the NSPS for 

PM in 40 CFR 60.102.

a. Continuous opacity monitoring 

system.

i. The daily average Ni operating 

value must not exceed the sitespecific Ni operating limit established during the performance 

test.

(1) Collecting the hourly average 

continuous opacity monitoring 

system data according to 

§ 63.1572; collecting the hourly 

average coke burn rate and 

hourly average gas flow rate 

monitoring data according to 

§ 63.15721; determining and recording equilibrium catalyst Ni 

concentration at least once a 

week 2; and determining and recording the hourly average Ni 

operating value using Equation 

12 of § 63.1564. 

(2) Determining and recording the 

3-hour rolling average Ni operating value and maintaining the 

3-hour rolling average Ni operating value below the site-specific Ni operating limit established during the performance 

test Alternatively, before August 

1, 2017, determining and recording the daily average Ni operating value and maintaining 

the daily average Ni operating 

value below the site-specific Ni 

operating limit established during the performance test. 

b. Continuous parameter monitoring systems—electrostatic 

precipitator.

i. The average gas flow rate to 

the control device must not exceed the level established in 

the performance test.

See item 7.b.i of this table. 

ii. The average voltage and secondary current (or total power 

input) must not fall below the 

level established in the performance test.

See item 7.b.ii of this table. 

iii. The monthly rolling average 

equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

See item 8.b.iii of this table. 

c. Continuous parameter monitoring systems—wet scrubber.i. The average liquid-to-gas ratio 

must not fall below the operating limit established during 

the performance test.

See item 7.c.i of this table. 

ii. Except for periods of startup, 

shutdown and hot standby, the 

daily average pressure drop 

must not fall below the operating limit established in the 

performance test.

See item 7.c.ii of this table. 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75299 

TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

iii. The monthly rolling average 

equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

See item 8.c.iii of this table. 

d. BLD—fabric filter ...................... i. See item 2.d of this table .......... See item 2.d of this table. 

ii. The monthly rolling average of 

the equilibrium catalyst Ni concentration must not exceed the 

level established during the performance test.

Determining and recording the 

equilibrium catalyst Ni concentration at least once a 

week 2; determining and recording the monthly rolling average 

of the equilibrium catalyst Ni 

concentration once each week 

using the weekly or most recent 

value; and maintaining the 

monthly rolling average below 

the limit established in the performance test. 

10. During periods of startup, shutdown, or hot standby.Any control device, if elected ....... The inlet velocity limit to the primary internal cyclones of the 

catalytic cracking unit catalyst 

regenerator in 

§ 63.1564(a)(5)(ii).

Meeting the requirements in 

§ 63.1564(c)(5). 

1 If applicable, you can use the alternative in § 63.1573(a)(1) for gas flow rate instead of a continuous parameter monitoring system if you used 

the alternative method in the initial performance test. 2The equilibrium catalyst Ni concentration must be measured by the procedure, Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure) in appendix A to this subpart; or by EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, or 

EPA Method 7521, Nickel Atomic Absorption, Direct Aspiration; or by an alternative to EPA Method 6010B, 6020, 7520, or 7521 satisfactory to 

the Administrator. The EPA Methods 6010B, 6020, 7520, and 7521 are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical 

Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–846 and Updates (document number 955–001–00000–1) are available for 

purchase from the Superintendent of Documents, U.S. Government Publishing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the 

EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or 

at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. These methods are also available at http://www.

epa.gov/epaoswer/hazwaste/test/main.htm. 

■ 59. Table 8 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1565(a)(1), you shall 

meet each emission limitation in the 

following table that applies to you. 

TABLE 8 TO SUBPART UUU OF PART 63—ORGANIC HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS

For each new and existing catalytic cracking unit . . . You shall meet the following emission limit for each catalyst 

regenerator vent . . . 

1. Subject to the NSPS for carbon monoxide (CO) in 40 CFR 60.103 or 

60.102a(b)(4).

CO emissions from the catalyst regenerator vent or CO boiler serving 

the catalytic cracking unit must not exceed 500 parts per million volume (ppmv) (dry basis). 

2. Not subject to the NSPS for CO in 40 CFR 60.103 or 60.102a(b)(4) a. CO emissions from the catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). 

b. If you use a flare to meet the CO limit, then on and after January 

30, 2019, the flare must meet the requirements of § 63.670. Prior to 

January 30, 2019, the flare must meet the requirements for control 

devices in § 63.11(b) and visible emissions must not exceed a total 

of 5 minutes during any 2 consecutive hours, or the flare must meet 

the requirements of § 63.670. 

■ 60. Table 9 to subpart UUU of part 63 

is revised to read as follows: 

As stated in § 63.1565(a)(2), you shall 

meet each operating limit in the 

following table that applies to you. 


tkelley on DSK3SPTVN1PROD with RULES2
75300 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 9 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING

UNITS

For each new or existing catalytic 

cracking unit . . . 

For this type of continuous 

monitoring system . . . 

For this type of control 

device . . . 

You shall meet this operating 

limit . . . 

1. Subject to the NSPS for carbon 

monoxide (CO) in 40 CFR 

60.103 or 60.102a(b)(4).

Continuous emission monitoring 

system.

Not applicable ............................... Not applicable. 

2. Not subject to the NSPS for CO 

in 40 CFR 60.103 or 

60.102a(b)(4).

a. Continuous emission monitoring system. Not applicable ............................... Not applicable. 

b. Continuous parameter monitoring systems. i. Thermal incinerator .................... Maintain the daily average combustion zone temperature 

above the limit established during the performance test; and 

maintain the daily average oxygen concentration in the vent 

stream (percent, dry basis) 

above the limit established during the performance test. 

ii. Boiler or process heater with a 

design heat input capacity 

under 44 MW or a boiler or 

process heater in which all vent 

streams are not introduced into 

the flame zone. 

Maintain the daily average combustion zone temperature 

above the limit established in 

the performance test. 

iii. Flare ......................................... On and after January 30, 2019, 

the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare pilot 

light must be present at all 

times and the flare must be operating at all times that emissions may be vented to it, or 

the flare must meet the requirements of § 63.670. 

3. During periods of startup, shutdown or hot standby.Any ................................................ Any ................................................ Meet the requirements in 

§ 63.1565(a)(5). 

■ 61. Table 10 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1565(b)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 10 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS

For each new or existing catalytic cracking 

unit . . . 

And you use this type of control device for 

your vent . . . 

You shall install, operate, and maintain this 

type of continuous monitoring system . . . 

1. Subject to the NSPS for carbon monoxide 

(CO) in 40 CFR 60.103 or 60.102a(b)(4).

Not applicable ................................................... Continuous emission monitoring system to 

measure and record the concentration by 

volume (dry basis) of CO emissions from 

each catalyst regenerator vent. 

2. Not subject to the NSPS for CO in 40 CFR 

60.103 or 60.102a(b)(4).

a. Thermal incinerator ...................................... Continuous emission monitoring system to 

measure and record the concentration by 

volume (dry basis) of CO emissions from 

each catalyst regenerator vent; or continuous parameter monitoring systems to 

measure and record the combustion zone 

temperature and oxygen content (percent, 

dry basis) in the incinerator vent stream. 

b. Process heater or boiler with a design heat 

input capacity under 44 MW or process 

heater or boiler in which all vent streams 

are not introduced into the flame zone. 

Continuous emission monitoring system to 

measure and record the concentration by 

volume (dry basis) of CO emissions from 

each catalyst regenerator vent; or continuous parameter monitoring systems to 

measure and record the combustion zone 

temperature. 


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TABLE 10 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM

CATALYTIC CRACKING UNITS—Continued 

For each new or existing catalytic cracking 

unit . . . 

And you use this type of control device for 

your vent . . . 

You shall install, operate, and maintain this 

type of continuous monitoring system . . . 

c. Flare ............................................................. On and after January 30, 2019, the monitoring 

systems required in §§ 63.670 and 63.671. 

Prior to January 30, 2019, monitoring device such as a thermocouple, an ultraviolet 

beam sensor, or infrared sensor to continuously detect the presence of a pilot flame, 

or the monitoring systems required in 

§§ 63.670 and 63.671. 

d. No control device ......................................... Continuous emission monitoring system to 

measure and record the concentration by 

volume (dry basis) of CO emissions from 

each catalyst regenerator vent. 

3. During periods of startup, shutdown or hot 

standby electing to comply with the operating limit in § 63.1565(a)(5)(ii).

Any ................................................................... Continuous parameter monitoring system to 

measure and record the concentration by 

volume (dry basis) of oxygen from each catalyst regenerator vent. 

■ 62. Table 11 to subpart UUU of part 

63 is amended by revising the entry for 

item 3 to read as follows: 

* * * * * 

TABLE 11 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS

FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR CARBON

MONOXIDE (CO) 

For . . . You must . . . Using . . . According to these 

requirements . . . 

******

3. Each catalytic cracking unit catalyst regenerator vent if you use 

continuous parameter monitoring systems.

a. Measure the CO concentration 

(dry basis) of emissions exiting 

the control device.

Method 10, 10A, or 10B in appendix A–4 to part 60 of this chapter, as applicable.

b. Establish each operating limit in 

Table 9 of this subpart that applies to you.

Data from the continuous parameter monitoring systems.

c. Thermal incinerator combustion 

zone temperature.

Data from the continuous parameter monitoring systems.Collect temperature monitoring 

data every 15 minutes during 

the entire period of the CO initial performance test; and determine and record the minimum 

hourly average combustion 

zone temperature from all the 

readings. 

d. Thermal incinerator: oxygen, 

content (percent, dry basis) in 

the incinerator vent stream.

Data from the continuous parameter monitoring systems.Collect oxygen concentration (percent, dry basis) monitoring data 

every 15 minutes during the entire period of the CO initial performance test; and determine 

and record the minimum hourly 

average percent excess oxygen 

concentration from all the readings. 

e. If you use a process heater or 

boiler with a design heat input 

capacity under 44 MW or process heater or boiler in which all 

vent streams are not introduced 

into the flame zone, establish 

operating limit for combustion 

zone temperature.

Data from the continuous parameter monitoring systems.Collect the temperature monitoring 

data every 15 minutes during 

the entire period of the CO initial performance test; and determine and record the minimum 

hourly average combustion 

zone temperature from all the 

readings. 


tkelley on DSK3SPTVN1PROD with RULES2
75302 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 11 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS

FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR CARBON

MONOXIDE (CO)—Continued 

For . . . You must . . . Using . . . According to these 

requirements . . . 

f. If you use a flare, conduct visible emission observations.Method 22 (40 CFR part 60, appendix A–7).On and after January 30, 2019, 

meet the requirements of 

§ 63.670. Prior to January 30, 

2019, maintain a 2-hour observation period; and record the 

presence of a flame at the pilot 

light over the full period of the 

test or meet the requirements of 

§ 63.670. 

g. If you use a flare, determine 

that the flare meets the requirements for net heating value of 

the gas being combusted and 

exit velocity.

40 CFR 63.11(b)(6) through (8) .... On and after January 30, 2019, 

the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must 

meet the control device requirements in § 63.11(b) or the requirements of § 63.670. 

■ 63. Table 12 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1565(b)(4), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 12 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC

CRACKING UNITS

For each new and existing catalytic 

cracking unit . . . 

For the following emission 

limit . . . You have demonstrated initial compliance if . . . 

1. Subject to the NSPS for carbon 

monoxide (CO) in 40 CFR 

60.103, 60.100(e), or 

60.102a(b)(4).

CO emissions from your catalyst 

regenerator vent or CO boiler 

serving the catalytic cracking 

unit must not exceed 500 ppmv 

(dry basis).

You have already conducted a performance test to demonstrate initial 

compliance with the NSPS and the measured CO emissions are 

less than or equal to 500 ppm (dry basis). As part of the Notification of Compliance Status, you must certify that your vent meets 

the CO limit. You are not required to conduct another performance 

test to demonstrate initial compliance. You have already conducted 

a performance evaluation to demonstrate initial compliance with the 

applicable performance specification. As part of your Notification of 

Compliance Status, you must certify that your continuous emission 

monitoring system meets the applicable requirements in § 63.1572. 

You are not required to conduct another performance evaluation to 

demonstrate initial compliance. 

2. Not subject to the NSPS for CO 

in 40 CFR 60.103 60.102a(b)(4).

a. CO emissions from your catalyst regenerator vent or CO boiler serving the catalytic cracking 

unit must not exceed 500 ppmv 

(dry basis).

i. If you use a continuous parameter monitoring system, the average 

CO emissions measured by Method 10 over the period of the initial 

performance test are less than or equal to 500 ppmv (dry basis). 

ii. If you use a continuous emission monitoring system, the hourly average CO emissions over the 24-hour period for the initial performance test are not more than 500 ppmv (dry basis); and your performance evaluation shows your continuous emission monitoring 

system meets the applicable requirements in § 63.1572. 

b. If you use a flare, visible emissions must not exceed a total of 

5 minutes during any 2 operating hours.

On and after January 30, 2019, the flare meets the requirements of 

§ 63.670. Prior to January 30, 2019, visible emissions, measured 

by Method 22 during the 2-hour observation period during the initial 

performance test, are no higher than 5 minutes, or the flare meets 

the requirements of § 63.670. 

■ 64. Table 13 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1565(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75303 

TABLE 13 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR

CATALYTIC CRACKING UNITS

For each new and existing 

catalytic cracking unit . . . 

Subject to this emission limit for 

your catalyst regenerator 

vent . . . 

If you must . . . You shall demonstrate continuous 

compliance by . . . 

1. Subject to the NSPS for carbon 

monoxide (CO) in 40 CFR 

60.103, 60.100(e), or 

60.102a(b)(4).

CO emissions from your catalyst 

regenerator vent or CO boiler 

serving the catalytic cracking 

unit must not exceed 500 ppmv 

(dry basis). 

Continuous emission monitoring 

system.

Collecting the hourly average CO 

monitoring data according to 

§ 63.1572; and maintaining the 

hourly average CO concentration at or below 500 ppmv (dry 

basis). 

2. Not subject to the NSPS for CO 

in 40 CFR 60.103 or 

60.102a(b)(4).

a. CO emissions from your catalyst regenerator vent or CO 

boiler serving the catalytic 

cracking unit must not exceed 

500 ppmv (dry basis). 

Continuous emission monitoring 

system. 

Same as item 1. 

b. CO emissions from your catalyst regenerator vent or CO 

boiler serving the catalytic 

cracking unit must not exceed 

500 ppmv (dry basis). 

Continuous parameter monitoring 

system. 

Maintaining the hourly average 

CO concentration below 500 

ppmv (dry basis). 

c. Visible emissions from a flare 

must not exceed a total of 5 

minutes during any 2-hour period. 

Control device-flare ...................... On and after January 30, 2019, 

meeting the requirements of 

§ 63.670. Prior to January 30, 

2019, maintaining visible emissions below a total of 5 minutes 

during any 2-hour operating period, or meeting the requirements of § 63.670. 

■ 65. Table 14 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1565(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS

For each new existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

1. Subject to NSPS for carbon 

monoxide (CO) in 40 CFR 

60.103, 60.100(e), 60.102a(b)(4).

Continuous emission monitoring 

system. 

Not applicable ............................... Complying with Table 13 of this 

subpart, item 1. 

2. Not subject to the NSPS for CO 

in 40 CFR 60.103 or 

60.102a(b)(4).

a. Continuous emission monitoring system.Not applicable ............................... Complying with Table 13 of this 

subpart, item 2.a. 

b. Continuous parameter monitoring systems—thermal incinerator. i. The daily average combustion 

zone temperature must not fall 

below the level established during the performance test. 

Collecting the hourly and daily average temperature monitoring 

data according to § 63.1572; 

and maintaining the daily average combustion zone temperature above the limit established 

during the performance test. 

ii. The daily average oxygen concentration in the vent stream 

(percent, dry basis) must not 

fall below the level established 

during the performance test. 

Collecting the hourly and daily average oxygen concentration 

monitoring data according to 

§ 63.1572; and maintaining the 

daily average oxygen concentration above the limit established during the performance 

test. 

c. Continuous parameter monitoring systems—boiler or process heater with a design heat 

input capacity under 44 MW or 

boiler or process heater in 

which all vent streams are not 

introduced into the flame zone. 

The daily combustion zone temperature must not fall below the 

level established in the performance test. 

Collecting the average hourly and 

daily temperature monitoring 

data according to § 63.1572; 

and maintaining the daily average combustion zone temperature above the limit established 

during the performance test. 


tkelley on DSK3SPTVN1PROD with RULES2
75304 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP 

EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued 

For each new existing catalytic 

cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 

d. Continuous parameter monitoring system—flare. The flare pilot light must be 

present at all times and the 

flare must be operating at all 

times that emissions may be 

vented to it. 

On and after January 30, 2019, 

meeting the requirements of 

§ 63.670. Prior to January 30, 

2019, collecting the flare monitoring data according to 

§ 63.1572 and recording for 

each 1-hour period whether the 

monitor was continuously operating and the pilot light was 

continuously present during 

each 1-hour period, or meeting 

the requirements of § 63.670. 

3. During periods of startup, shutdown or hot standby electing to 

comply with the operating limit in 

§ 63.1565(a)(5)(ii). 

Any control device ........................ The oxygen concentration limit in 

§ 63.1565(a)(5)(ii).

Collecting the hourly average oxygen concentration monitoring 

data according to § 63.1572 

and maintaining the hourly average oxygen concentration at 

or above 1 volume percent (dry 

basis). 

■ 66. Table 15 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 15 TO SUBPART UUU OF PART 63—ORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS

For each applicable process vent for a 

new or existing catalytic reforming 

unit . . . 

You shall meet this emission limit during initial catalyst depressuring and catalyst purging 

operations . . . 

1. Option 1 ................................................ On and after January 30, 2019, vent emissions to a flare that meets the requirements of § 63.670. 

Prior to January 30, 2019, vent emissions to a flare that meets the requirements for control devices in § 63.11(b) and visible emissions from a flare must not exceed a total of 5 minutes during 

any 2-hour operating period, or vent emissions to a flare that meets the requirements of § 63.670. 

*******

■ 67. Table 16 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 16 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC

REFORMING UNITS

For each new or existing catalytic 

reforming unit . . . For this type of control device . . . You shall meet this operating limit during initial catalyst depressuring and purging operations. . . 

1. Option 1: Vent to flare ............... Flare ............................................... On and after January 30, 2019, the flare must meet the requirements 

of § 63.670. Prior to January 30, 2019, the flare pilot light must be 

present at all times and the flare must be operating at all times that 

emissions may be vented to it, or the flare must meet the requirements of § 63.670. 

* * * * * * * 

■ 68. Table 17 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 


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TABLE 17 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM

CATALYTIC REFORMING UNITS

For each applicable process vent 

for a new or existing catalytic 

reforming unit . . . 

If you use this type of control 

device . . . 

You shall install and operate this type of continuous monitoring 

system . . . 

1. Option 1: Vent to a flare ............ Flare ............................................... On and after January 30, 2019, the monitoring systems required in 

§§ 63.670 and 63.671. Prior to January 30, 2019, monitoring device 

such as a thermocouple, an ultraviolet beam sensor, or infrared 

sensor to continuously detect the presence of a pilot flame, or the 

monitoring systems required in §§ 63.670 and 63.671. 

* * * * * * * 

■ 69. Table 18 to subpart UUU of part 

63 is amended by revising the column 

headings and the entry for item 1 to read 

as follows: 

* * * * * 

TABLE 18 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS

FROM CATALYTIC REFORMING UNITS

For each new or existing catalytic 

reforming unit . . . You must . . . Using . . . According to these requirements . . . 

1. Option 1: Vent to a flare ........... a. Conduct visible emission observations.Method 22 (40 CFR part 60, appendix A–7).On and after January 30, 2019, 

the flare must meet the requirements of § 63.670. Prior to January 30, 2019, 2-hour observation period. Record the presence of a flame at the pilot light 

over the full period of the test, 

or the requirements of § 63.670. 

b. Determine that the flare meets 

the requirements for net heating 

value of the gas being combusted and exit velocity.

40 CFR 63.11(b)(6) through (8) .... On and after January 30, 2019, 

the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must 

meet the control device requirements in § 63.11(b) or the requirements of § 63.670. 

* * * * * * * 

■ 70. Table 19 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 19 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC

REFORMING UNITS

For each applicable process vent for a new or 

existing catalytic reforming unit . . . For the following emission limit . . . You have demonstrated initial compliance if . . . 

Option 1 ............................................................ Visible emissions from a flare must not exceed 

a total of 5 minutes during any 2 consecutive hours.

On and after January 30, 2019, the flare 

meets the requirements of § 63.670. Prior to 

January 30, 2019, visible emissions, measured using Method 22 over the 2-hour observation period of the performance test, do 

not exceed a total of 5 minutes, or the flare 

meets the requirements of § 63.670. 

* * * * * * * 

■ 71. Table 20 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 


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75306 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 20 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR

CATALYTIC REFORMING UNITS

For each applicable process vent for a new or 

existing catalytic reforming unit . . . For this emission limit . . . 

You shall demonstrate continuous compliance 

during initial catalyst depressuring and catalyst 

purging operations by . . . 

1. Option 1 ........................................................ Vent emissions from your process vent to a 

flare.

On and after January 30, 2019, meeting the 

requirements of § 63.670. Prior to January 

30, 2019, maintaining visible emissions from 

a flare below a total of 5 minutes during any 

2 consecutive hours, or meeting the requirements of § 63.670. 

* * * * * * * 

■ 72. Table 21 to subpart UUU of part 

63 is amended by revising the entry for 

item 1 to read as follows: 

* * * * * 

TABLE 21 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP 

EMISSIONS FROM CATALYTIC REFORMING UNITS

For each applicable process vent 

for a new or existing catalytic 

reforming unit . . . 

If you use . . . For this operating limit . . . 

You shall demonstrate continuous 

compliance during initial catalyst 

depressuring and purging 

operations by . . . 

1. Option 1 .................................... Flare .............................................. The flare pilot light must be

present at all times and the 

flare must be operating at all 

times that emissions may be 

vented to it.

On and after January 30, 2019, 

meeting the requirements of 

§ 63.670. Prior to January 30, 

2019, collecting flare monitoring 

data according to § 63.1572 and 

recording for each 1-hour period 

whether the monitor was continuously operating and the pilot 

light was continuously present 

during each 1-hour period, or 

meeting the requirements of 

§ 63.670. 

* * * * * * * 

■ 73. Table 22 to subpart UUU of part 

63 is amended by revising the entries for 

items 2 and 3 to read as follows: 

* * * * * 

TABLE 22 TO SUBPART UUU OF PART 63—INORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS

For . . . 

You shall meet this emission limit for each applicable catalytic 

reforming unit process vent during coke burn-off and catalyst 

rejuvenation . . . 

*******

2. Each existing cyclic or continuous catalytic reforming unit .................. Reduce uncontrolled emissions of HCl by 97 percent by weight or to a 

concentration of 10 ppmv (dry basis), corrected to 3 percent oxygen. 

3. Each new semi-regenerative, cyclic, or continuous catalytic reforming unit.Reduce uncontrolled emissions of HCl by 97 percent by weight or to a 

concentration of 10 ppmv (dry basis), corrected to 3 percent oxygen. 

■ 74. Table 24 to subpart UUU of part 

63 is amended by revising the entries for 

items 2 through 4 and footnote 2 to read 

as follows: 

* * * * * 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75307 

TABLE 24 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR INORGANIC HAP EMISSIONS FROM

CATALYTIC REFORMING UNITS

If you use this type of control device for your vent . . . You shall install and operate this type of continuous monitoring 

system . . . 

*******

2. Internal scrubbing system or no control device (e.g., hot regen system) to meet HCl outlet concentration limit.Colormetric tube sampling system to measure the HCl concentration in 

the catalyst regenerator exhaust gas during coke burn-off and catalyst rejuvenation. The colormetric tube sampling system must meet 

the requirements in Table 41 of this subpart. 

3. Internal scrubbing system to meet HCl percent reduction standard ... Continuous parameter monitoring system to measure and record the 

gas flow rate entering or exiting the internal scrubbing system during 

coke burn-off and catalyst rejuvenation; and continuous parameter 

monitoring system to measure and record the total water (or scrubbing liquid) flow rate entering the internal scrubbing system during 

coke burn-off and catalyst rejuvenation; and continuous parameter 

monitoring system to measure and record the pH or alkalinity of the 

water (or scrubbing liquid) exiting the internal scrubbing system during coke burn-off and catalyst rejuvenation.2

4. Fixed-bed gas-solid adsorption system ................................................ Continuous parameter monitoring system to measure and record the 

temperature of the gas entering or exiting the adsorption system during coke burn-off and catalyst rejuvenation; and colormetric tube 

sampling system to measure the gaseous HCl concentration in the 

adsorption system exhaust and at a point within the absorbent bed 

not to exceed 90 percent of the total length of the absorbent bed 

during coke burn-off and catalyst rejuvenation. The colormetric tube 

sampling system must meet the requirements in Table 41 of this 

subpart. 

* * * * * * * 

******* 2 If applicable, you can use the alternative in § 63.1573(c)(1) instead of a continuous parameter monitoring system for pH of the water (or 

scrubbing liquid) or the alternative in § 63.1573(c)(2) instead of a continuous parameter monitoring system for alkalinity of the water (or scrubbing 

liquid). 

* * * * * 

■ 75. Table 25 to subpart UUU of part 

63 is amended by revising the entries for 

items 2.a and 4.a and footnote 1 to read 

as follows: 

* * * * * 

TABLE 25 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR INORGANIC HAP EMISSIONS

FROM CATALYTIC REFORMING UNITS

For each new and existing 

catalytic reforming unit 

using . . . 

You shall . . . Using . . . According to these 

requirements . . . 

*******

2. Wet scrubber ............................ a. Establish operating limit for pH 

level or alkalinity.

i. Data from continuous parameter 

monitoring systems.

Measure and record the pH or alkalinity of the water (or scrubbing liquid) exiting scrubber 

every 15 minutes during the entire period of the performance 

test. Determine and record the 

minimum hourly average pH or 

alkalinity level from the recorded values. 

ii. Alternative pH procedure in 

§ 63.1573(b)(1).

Measure and record the pH of the 

water (or scrubbing liquid) 

exiting the scrubber during coke 

burn-off and catalyst rejuvenation using pH strips at least 

three times during each test 

run. Determine and record the 

average pH level for each test 

run. Determine and record the 

minimum test run average pH 

level. 


tkelley on DSK3SPTVN1PROD with RULES2
75308 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 25 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR INORGANIC HAP EMISSIONS

FROM CATALYTIC REFORMING UNITS—Continued 

For each new and existing 

catalytic reforming unit 

using . . . 

You shall . . . Using . . . According to these 

requirements . . . 

iii. Alternative alkalinity method in 

§ 63.1573(c)(2).

Measure and record the alkalinity 

of the water (or scrubbing liquid) exiting the scrubber during 

coke burn-off and catalyst rejuvenation using discrete titration 

at least three times during each 

test run. Determine and record 

the average alkalinity level for 

each test run. Determine and 

record the minimum test run average alkalinity level. 

* * * * * * * 

4. Internal scrubbing system 

meeting HCl percent reduction 

standard.

a. Establish operating limit for pH 

level or alkalinity.

i. Data from continuous parameter 

monitoring system.

Measure and record the pH alkalinity of the water (or scrubbing 

liquid) exiting the internal scrubbing system every 15 minutes 

during the entire period of the 

performance test. Determine 

and record the minimum hourly 

average pH or alkalinity level 

from the recorded values. 

ii. Alternative pH method in 

§ 63.1573(c)(1).

Measure and in record pH of the 

water (or scrubbing liquid) 

exiting the internal scrubbing 

system during coke burn-off and 

catalyst rejuvenation using pH 

strips at least three times during 

each test run. Determine and 

record the average pH level for 

each test run. Determine and 

record the minimum test run average pH level. 

iii. Alternative alkalinity method in 

§ 63.1573(c)(2).

Measure and record the alkalinity 

water (or scrubbing liquid) 

exiting the internal scrubbing 

system during coke burn-off and 

catalyst rejuvenation using discrete titration at least three 

times during each test run. Determine and record the average 

alkalinity level for each test run. 

Determine and record the minimum test run average alkalinity 

level. 

* * * * * * * 

1The EPA Methods 5050, 9056, 9212 and 9253 are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA 

Publication SW–846, Revision 5 (April 1998). The SW–846 and Updates (document number 955–001–00000–1) are available for purchase from 

the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical 

Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the 

Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. These methods are also available at http://www.epa.gov/epaoswer/

hazwaste/test/main.htm. 

■ 76. Table 28 to subpart UUU of part 

63 is amended by revising the entry for 

item 5 and footnotes 1 and 3 to read as 

follows: 

* * * * * 

TABLE 28 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR INORGANIC HAP 

EMISSIONS FROM CATALYTIC REFORMING UNITS

For each new and existing catalytic reforming 

unit using this type of control device or 

system . . . 

For this operating limit . . . 

You shall demonstrate continuous compliance 

during coke burn-off and catalyst rejuvenation 

by . . . 


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TABLE 28 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR INORGANIC HAP 

EMISSIONS FROM CATALYTIC REFORMING UNITS—Continued 

For each new and existing catalytic reforming 

unit using this type of control device or 

system . . . 

For this operating limit . . . 

You shall demonstrate continuous compliance 

during coke burn-off and catalyst rejuvenation 

by . . . 

*******

5. Moving-bed gas-solid adsorption system 

(e.g., ChlorsorbTM System).

a. The daily average temperature of the gas 

entering or exiting the adsorption system 

must not exceed the limit established during 

the performance test.

Collecting the hourly and daily average temperature monitoring data according to 

§ 63.1572; and maintaining the daily average temperature below the operating limit 

established during the performance test. 

b. The weekly average chloride level on the 

sorbent entering the adsorption system must 

not exceed the design or manufacturer’s 

recommended limit (1.35 weight percent for 

the ChlorsorbTM System).

Collecting samples of the sorbent exiting the 

adsorption system three times per week (on 

non-consecutive days); and analyzing the 

samples for total chloride3; and determining 

and recording the weekly average chloride 

concentration; and maintaining the chloride 

concentration below the design or manufacturer’s recommended limit (1.35 weight percent for the ChlorsorbTM System). 

c. The weekly average chloride level on the 

sorbent exiting the adsorption system must 

not exceed the design or manufacturer’s 

recommended limit (1.8 weight percent for 

the ChlorsorbTM System).

Collecting samples of the sorbent exiting the 

adsorption system three times per week (on 

non-consecutive days); and analyzing the 

samples for total chloride concentration; and 

determining and recording the weekly average chloride concentration; and maintaining 

the chloride concentration below the design 

or manufacturer’s recommended limit (1.8 

weight percent ChlorsorbTM System). 

1 If applicable, you can use either alternative in § 63.1573(c) instead of a continuous parameter monitoring system for pH or alkalinity if you 

used the alternative method in the initial performance test. 

* * * * * * * 3The total chloride concentration of the sorbent material must be measured by the procedure, ‘‘Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure)’’ in appendix A to this subpart; or by using EPA Method 5050, Bomb Preparation Method for 

Solid Waste, combined either with EPA Method 9056, Determination of Inorganic Anions by Ion Chromatography, or with EPA Method 9253, 

Chloride (Titrimetric, Silver Nitrate); or by using EPA Method 9212, Potentiometric Determination of Chloride in Aqueous Samples with Ion-Selective Electrode, and using the soil extraction procedures listed within the method. The EPA Methods 5050, 9056, 9212 and 9253 are included in 

‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–846 and 

Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, 

VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building, (Air Docket), 

Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, 

Washington, DC. These methods are also available at http://www.epa.gov/epaoswer/hazwaste/test/main.htm. 

■ 77. Table 29 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(a)(1), you shall 

meet each emission limitation in the 

following table that applies to you. 

TABLE 29 TO SUBPART UUU OF PART 63—HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS

For . . . You shall meet this emission limit for each process vent . . . 

1. Subject to NSPS. Each new or existing Claus sulfur recovery unit 

part of a sulfur recovery plant with design capacity greater than 20 

long tons per day (LTD) and subject to the NSPS for sulfur oxides in 

40 CFR 60.104(a)(2) or 60.102a(f)(1).

a. 250 ppmv (dry basis) of sulfur dioxide (SO2) at zero percent excess 

air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an oxidation control system or if you use 

a reduction control system followed by incineration. 

b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2

(dry basis) at zero percent excess air, or concentration determined 

using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction 

control system without incineration. 

2. Option 1: Elect NSPS. Each new or existing sulfur recovery unit 

(Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if 

you use an oxidation control system or if you use a reduction control 

system followed by incineration. 

b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2

(dry basis) at zero percent excess air, or concentration determined 

using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction 

control system without incineration. 

3. Option 2: TRS limit. Each new or existing sulfur recovery unit (Claus 

or other type, regardless of size) not subject to the NSPS for sulfur 

oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1).

300 ppmv of total reduced sulfur (TRS) compounds, expressed as an 

equivalent SO2 concentration (dry basis) at zero percent oxygen. 


tkelley on DSK3SPTVN1PROD with RULES2
75310 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

■ 78. Table 30 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(a)(2), you shall 

meet each operating limit in the 

following table that applies to you. 

TABLE 30 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS

For . . . If use this type of control device . . . You shall meet this operating limit . . . 

1. Subject to NSPS. Each new or existing 

Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater 

than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

Not applicable .................................................. Not applicable. 

2. Option 1: Elect NSPS. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

Not applicable .................................................. Not applicable. 

3. Option 2: TRS limit, if using continuous emissions monitoring systems. Each new or existing sulfur recovery unit (Claus or other type, 

regardless of size) not subject to the NSPS 

for sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

Not applicable .................................................. Not applicable. 

4. Option 2: TRS limit, if using continuous parameter monitoring systems. Each new or existing sulfur recovery unit (Claus or other 

type, regardless of size) not subject to the 

NSPS for sulfur oxides in 40 CFR 

60.104(a)(2) or 60.102a(f)(1).

Thermal incinerator .......................................... Maintain the daily average combustion zone 

temperature above the limit established during the performance test; and maintain the 

daily average oxygen concentration in the 

vent stream (percent, dry basis) above the 

limit established during the performance 

test. 

5. Startup or shutdown option 1: Electing to 

comply with § 63.1568(a)(4)(ii). Each new or 

existing sulfur recovery unit (Claus or other 

type, regardless of size) during periods of 

startup or shutdown.

Flare ................................................................. On and after January 30, 2019, meet the applicable requirements of § 63.670. Prior to 

January 30, 2019, meet the applicable requirements of either § 63.11(b) or § 63.670. 

6. Startup or shutdown option 2: Electing to 

comply with § 63.1568(a)(4)(iii). Each new or 

existing sulfur recovery unit (Claus or other 

type, regardless of size) during startup or 

shutdown events.

Thermal incinerator or thermal oxidizer ........... Maintain the hourly average combustion zone 

temperature at or above 1,200 degrees 

Fahrenheit and maintain the hourly average 

oxygen concentration in the exhaust gas 

stream at or above 2 volume percent (dry 

basis). 

■ 79. Table 31 to subpart UUU is revised 

to read as follows: 

As stated in § 63.1568(b)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR

RECOVERY UNITS

For . . . For this limit . . . You shall install and operate this continuous 

monitoring system . . . 

1. Subject to NSPS. Each new or existing 

Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater 

than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1). 

a. 250 ppmv (dry basis) of SO2 at zero percent excess air if you use an oxidation or 

reduction control system followed by incineration.

Continuous emission monitoring system to 

measure and record the hourly average 

concentration of SO2 (dry basis) at zero 

percent excess air for each exhaust stack. 

This system must include an oxygen monitor for correcting the data for excess air. 


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TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR

RECOVERY UNITS—Continued 

For . . . For this limit . . . You shall install and operate this continuous 

monitoring system . . . 

b. 300 ppmv of reduced sulfur compounds 

calculated as ppmv SO2 (dry basis) at zero 

percent excess air if you use a reduction 

control system without incineration.

Continuous emission monitoring system to 

measure and record the hourly average 

concentration of reduced sulfur and oxygen 

(O2) emissions. Calculate the reduced sulfur emissions as SO2 (dry basis) at zero 

percent excess air. Exception: You can use 

an instrument having an air or SO2 dilution 

and oxidation system to convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry 

basis) at zero percent excess air of the resultant SO2 instead of the reduced sulfur 

monitor. The monitor must include an oxygen monitor for correcting the data for excess oxygen. 

c. If you use Equation 1 of 40 CFR 

60.102a(f)(1)(i) to set your emission limit.

i. Complete either item 1.a or item 1.b; and 

ii. Either a continuous emission monitoring 

system to measure and record the O2 concentration for the inlet air/oxygen supplied 

to the system or a continuous parameter 

monitoring system to measure and record 

the volumetric gas flow rate of ambient air 

and purchased oxygen-enriched gas. 

2. Option 1: Elect NSPS. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1). 

a. 250 ppmv (dry basis) of SO2 at zero percent excess air if you use an oxidation or 

reduction control system followed by incineration.

Continuous emission monitoring system to 

measure and record the hourly average 

concentration of SO2 (dry basis), at zero 

percent excess air for each exhaust stack. 

This system must include an oxygen monitor for correcting the data for excess air. 

b. 300 ppmv of reduced sulfur compounds 

calculated as ppmv SO2 (dry basis) at zero 

percent excess air if you use a reduction 

control system without incineration. 

Continuous emission monitoring system to 

measure and record the hourly average 

concentration of reduced sulfur and O2

emissions for each exhaust stack. Calculate 

the reduced sulfur emissions as SO2 (dry 

basis), at zero percent excess air. Exception: You can use an instrument having an 

air or O2 dilution and oxidation system to 

convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis) at zero percent excess air of the resultant SO2 instead of the 

reduced sulfur monitor. The monitor must 

include an oxygen monitor for correcting the 

data for excess oxygen. 

c. If you use Equation 1 of 40 CFR 

60.102a(f)(1)(i) to set your emission limit.

i. Complete either item 2.a or item 2.b; and 

ii. Either a continuous emission monitoring 

system to measure and record the O2 concentration for the inlet air/oxygen supplied 

to the system, or a continuous parameter 

monitoring system to measure and record 

the volumetric gas flow rate of ambient air 

and purchased oxygen-enriched gas. 

3. Option 2: TRS limit. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1). 

a. 300 ppmv of total reduced sulfur (TRS) 

compounds, expressed as an equivalent 

SO2 concentration (dry basis) at zero percent oxygen.

i. Continuous emission monitoring system to 

measure and record the hourly average 

concentration of TRS for each exhaust 

stack; this monitor must include an oxygen 

monitor for correcting the data for excess 

oxygen; or 

ii. Continuous parameter monitoring systems 

to measure and record the combustion 

zone temperature of each thermal incinerator and the oxygen content (percent, dry 

basis) in the vent stream of the incinerator. 


tkelley on DSK3SPTVN1PROD with RULES2
75312 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR

RECOVERY UNITS—Continued 

For . . . For this limit . . . You shall install and operate this continuous 

monitoring system . . . 

4. Startup or shutdown option 1: electing to 

comply with § 63.1568(a)(4)(ii). Each new or 

existing sulfur recovery unit (Claus or other 

type, regardless of size) during periods of 

startup or shutdown. 

Any ................................................................... On and after January 30, 2019, monitoring 

systems as specified in §§ 63.670 and 

63.671. Prior to January 30, 2019, either 

continuous parameter monitoring systems 

following the requirements in § 63.11 (to detect the presence of a flame; to measure 

and record the net heating value of the gas 

being combusted; and to measure and 

record the volumetric flow of the gas being 

combusted) or monitoring systems as specified in §§ 63.670 and 63.671. 

5. Startup or shutdown option 2: electing to 

comply with § 63.1568(a)(4)(iii). Each new or 

existing sulfur recovery unit (Claus or other 

type, regardless of size) during periods of 

startup or shutdown. 

Any ................................................................... Continuous parameter monitoring systems to 

measure and record the firebox temperature of each thermal incinerator or oxidizer 

and the oxygen content (percent, dry basis) 

in the exhaust vent from the incinerator or 

oxidizer. 

■ 80. Table 32 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(b)(2) and (3), 

you shall meet each requirement in the 

following table that applies to you. 

TABLE 32 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR HAP EMISSIONS FROM

SULFUR RECOVERY UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARDS FOR SULFUR OXIDES

For . . . You must . . . Using . . . According to these 

requirements . . . 

1. Option 1: Elect NSPS. Each 

new and existing sulfur recovery 

unit.

a. Measure SO2 concentration (for 

an oxidation or reduction system followed by incineration) or 

measure the concentration of 

reduced sulfur (or SO2 if you 

use an instrument to convert 

the reduced sulfur to SO2) for a 

reduction control system without incineration.

Data from continuous emission 

monitoring system.

Collect SO2 monitoring data every 

15 minutes for 24 consecutive 

operating hours. Reduce the 

data to 1-hour averages computed from four or more data 

points equally spaced over 

each 1-hour period. 

b. Measure O2 concentration for 

the inlet air/oxygen supplied to 

the system, if using Equation 1 

of 40 CFR 60.102a(f)1)(i) to set 

your emission limit. You may 

use either an O2 CEMS method 

in item 1.b.i of this table or the 

flow monitor in item 1.b.ii of this 

table.

i. Data from continuous emission 

monitoring system; or 

Collect O2 monitoring data every 

15 minutes for 24 consecutive 

operating hours. Reduce the 

data to 1-hour averages computed from four or more data 

points equally spaced over 

each 1-hour period; and average over the 24-hour period for 

input to Equation 1 of 40 CFR 

60.102a(f)(1)(i). 

ii. Data from flow monitor for ambient air and purchased oxygen-enriched gas.Collect gas flow rate monitoring 

data every 15 minutes for 24 

consecutive operating hours. 

Reduce the data to 1-hour 

averages computed from 4 or 

more data points equally 

spaced over each 1-hour period; calculate the hourly O2

percent using Equation 10 of 40 

CFR 60.106a(a)(6)(iv); and average over the 24-hour period 

for input to Equation 1 of 40 

CFR 60.102a(f)(1)(i). 

2. Option 2: TRS limit, using 

CEMS. Each new and existing 

sulfur recovery unit.

Measure the concentration of reduced sulfur (or SO2 if you use 

an instrument to convert the reduced sulfur to SO2).

Data from continuous emission 

monitoring system.

Collect TRS data every 15 minutes for 24 consecutive operating hours. Reduce the data to 

1-hour averages computed from 

four or more data points equally 

spaced over each 1-hour period. 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75313 

TABLE 32 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARDS FOR SULFUR OXIDES—Continued 

For . . . You must . . . Using . . . According to these 

requirements . . . 

3. Option 2: TRS limit, if using 

continuous parameter monitoring 

systems. Each new and existing 

sulfur recovery unit.

a. Select sampling port’s location 

and the number of traverse 

ports.

Method 1 or 1A in Appendix A–1 

to part 60 of this chapter.

Sampling sites must be located at 

the outlet of the control device 

and prior to any releases to the 

atmosphere. 

b. Determine velocity and volumetric flow rate.Method 2, 2A, 2C, 2D, or 2F in 

appendix A–1 to part 60 of this 

chapter, or Method 2G in appendix A–2 to part 60 of this 

chapter, as applicable.

c. Conduct gas molecular weight 

analysis; obtain the oxygen 

concentration needed to correct 

the emission rate for excess air.

Method 3, 3A, or 3B in appendix 

A–2 to part 60 of this chapter, 

as applicable.

Take the samples simultaneously 

with reduced sulfur or moisture 

samples. 

d. Measure moisture content of 

the stack gas.

Method 4 in appendix A–3 to part 

60 of this chapter.

Make your sampling time for each 

Method 4 sample equal to that 

for 4 Method 15 samples. 

e. Measure the concentration of 

TRS.

Method 15 or 15A in appendix A– 

5 to part 60 of this chapter, as 

applicable.

If the cross-sectional area of the 

duct is less than 5 square meters (m2) or 54 square feet, you 

must use the centroid of the 

cross section as the sampling 

point. If the cross-sectional area 

is 5 m2 or more and the centroid is more than 1 meter (m) 

from the wall, your sampling 

point may be at a point no closer to the walls than 1 m or 39 

inches. Your sampling rate 

must be at least 3 liters per 

minute or 0.10 cubic feet per 

minute to ensure minimum residence time for the sample inside the sample lines. 

f. Calculate the SO2 equivalent for 

each run after correcting for 

moisture and oxygen.

The arithmetic average of the SO2

equivalent for each sample during the run.

g. Correct the reduced sulfur 

samples to zero percent excess 

air.

Equation 1 of § 63.1568 ...............

h. Establish each operating limit in 

Table 30 of this subpart that 

applies to you.

Data from the continuous parameter monitoring system.

i. Measure thermal incinerator: 

combustion zone temperature.

Data from the continuous parameter monitoring system.Collect temperature monitoring 

data every 15 minutes during 

the entire period of the performance test; and determine and 

record the minimum hourly average temperature from all the 

readings. 

j. Measure thermal incinerator: oxygen concentration (percent, 

dry basis) in the vent stream.

Data from the continuous parameter monitoring system.Collect oxygen concentration (percent, dry basis) data every 15 

minutes during the entire period 

of the performance test; and 

determine and record the minimum hourly average percent 

excess oxygen concentration. 

■ 81. Table 33 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(b)(5), you shall 

meet each requirement in the following 

table that applies to you. 


tkelley on DSK3SPTVN1PROD with RULES2
75314 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY

UNITS

For . . . For the following emission limit . . . You have demonstrated initial 

compliance if . . . 

1. Subject to NSPS: Each new or existing 

Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater 

than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

a. 250 ppmv (dry basis) SO2 at zero percent 

excess air, or concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an oxidation or 

reduction control system followed by incineration.

You have already conducted a performance 

test to demonstrate initial compliance with 

the NSPS and each 12-hour rolling average 

concentration of SO2 emissions measured 

by the continuous emission monitoring system is less than or equal to 250 ppmv (dry 

basis) at zero percent excess air, or the 

concentration determined using Equation 1 

of 40 CFR 60.102a(f)(1)(i). As part of the 

Notification of Compliance Status, you must 

certify that your vent meets the SO2 limit. 

You are not required to do another performance test to demonstrate initial compliance. 

You have already conducted a performance 

evaluation to demonstrate initial compliance 

with the applicable performance specification. As part of your Notification of Compliance Status, you must certify that your continuous emission monitoring system meets 

the applicable requirements in § 63.1572. 

You are not required to do another performance evaluation to demonstrate initial compliance. 

b. 300 ppmv of reduced sulfur compounds 

calculated as ppmv SO2 (dry basis) at zero 

percent excess air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use a reduction control system without incineration.

You have already conducted a performance 

test to demonstrate initial compliance with 

the NSPS and each 12-hour rolling average 

concentration of reduced sulfur compounds 

measured by your continuous emission 

monitoring system is less than or equal to 

300 ppmv, calculated as ppmv SO2 (dry 

basis) at zero percent excess air, or the 

concentration determined using Equation 1 

of 40 CFR 60.102a(f)(1)(i). As part of the 

Notification of Compliance Status, you must 

certify that your vent meets the SO2 limit. 

You are not required to do another performance test to demonstrate initial compliance. 

You have already conducted a performance 

evaluation to demonstrate initial compliance 

with the applicable performance specification. As part of your Notification of Compliance Status, you must certify that your continuous emission monitoring system meets 

the applicable requirements in § 63.1572. 

You are not required to do another performance evaluation to demonstrate initial compliance. 

2. Option 1: Elect NSPS. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an oxidation or 

reduction control system followed by incineration.

Each 12-hour rolling average concentration of 

SO2 emissions measured by the continuous 

emission monitoring system during the initial performance test is less than or equal to 

250 ppmv (dry basis) at zero percent excess air, or the concentration determined 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i); and your performance evaluation shows the monitoring system meets 

the applicable requirements in § 63.1572. 

b. 300 ppmv of reduced sulfur compounds 

calculated as ppmv SO2 (dry basis) at zero 

percent excess air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use a reduction control system without incineration.

Each 12-hour rolling average concentration of 

reduced sulfur compounds measured by the 

continuous emission monitoring system during the initial performance test is less than 

or equal to 300 ppmv, calculated as ppmv 

SO2 (dry basis) at zero percent excess air, 

or the concentration determined using 

Equation 1 of 40 CFR 60.102a(f)(1)(i); and 

your performance evaluation shows the 

continuous emission monitoring system 

meets the applicable requirements in 

§ 63.1572. 


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75315 

TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY

UNITS—Continued 

For . . . For the following emission limit . . . You have demonstrated initial 

compliance if . . . 

3. Option 2: TRS limit. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

300 ppmv of TRS compounds expressed as 

an equivalent SO2 concentration (dry basis) 

at zero percent oxygen.

If you use continuous parameter monitoring 

systems, the average concentration of TRS 

emissions measured using Method 15 during the initial performance test is less than 

or equal to 300 ppmv expressed as equivalent SO2 concentration (dry basis) at zero 

percent oxygen. If you use a continuous 

emission monitoring system, each 12-hour 

rolling average concentration of TRS emissions measured by the continuous emission 

monitoring system during the initial performance test is less than or equal to 300 ppmv 

expressed as an equivalent SO2 (dry basis) 

at zero percent oxygen; and your performance evaluation shows the continuous 

emission monitoring system meets the applicable requirements in § 63.1572. 

■ 82. Table 34 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 34 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR

RECOVERY UNITS

For . . . For this emission limit . . . You shall demonstrate continuous compliance 

by . . . 

1. Subject to NSPS. Each new or existing 

Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater 

than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an oxidation or 

reduction control system followed by incineration.

Collecting the hourly average SO2 monitoring 

data (dry basis, percent excess air) and, if 

using Equation 1 of 40 CFR 

60.102a(f)(1)(i), collecting the hourly O2

concentration or flow monitoring data according to § 63.1572; determining and recording each 12-hour rolling average concentration of SO2; maintaining each 12-hour 

rolling average concentration of SO2 at or 

below the applicable emission limitation; 

and reporting any 12-hour rolling average 

concentration of SO2 greater than the applicable emission limitation in the semiannual 

compliance report required by § 63.1575. 

b. 300 ppmv of reduced sulfur compounds 

calculated as ppmv SO2 (dry basis) at zero 

percent excess air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use a reduction control system without incineration.

Collecting the hourly average reduced sulfur 

(and air or O2 dilution and oxidation) monitoring data and, if using Equation 1 of 40 

CFR 60.102a(f)(1)(i), collecting the hourly 

O2 concentration or flow monitoring data 

according to § 63.1572; determining and recording each 12-hour rolling average concentration of reduced sulfur; maintaining 

each 12-hour rolling average concentration 

of reduced sulfur at or below the applicable 

emission limitation; and reporting any 12- 

hour rolling average concentration of reduced sulfur greater than the applicable 

emission limitation in the semiannual compliance report required by § 63.1575. 


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TABLE 34 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR

RECOVERY UNITS—Continued 

For . . . For this emission limit . . . You shall demonstrate continuous compliance 

by . . . 

2. Option 1: Elect NSPS. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use an oxidation or 

reduction control system followed by incineration.

Collecting the hourly average SO2 data (dry 

basis, percent excess air) and, if using 

Equation 1 of 40 CFR 60.102a(f)(1)(i), collecting the hourly O2 concentration or flow 

monitoring data according to § 63.1572; determining and recording each 12-hour rolling average concentration of SO2; maintaining each 12-hour rolling average concentration of SO2 at or below the applicable emission limitation; and reporting any 12-hour 

rolling average concentration of SO2 greater 

than the applicable emission limitation in 

the semiannual compliance report required 

by § 63.1575. 

b. 300 ppmv of reduced sulfur compounds 

calculated as ppmv SO2 (dry basis) at zero 

percent excess air, or concentration determined using Equation 1 of 40 CFR 

60.102a(f)(1)(i), if you use a reduction control system without incineration.

Collecting the hourly average reduced sulfur 

(and air or O2 dilution and oxidation) monitoring data and, if using Equation 1 of 40 

CFR 60.102a(f)(1)(i), collecting the hourly 

O2 concentration or flow monitoring data 

according to § 63.1572; determining and recording each 12-hour rolling average concentration of reduced sulfur; maintaining 

each 12-hour rolling average concentration 

of reduced sulfur at or below the applicable 

emission limitation; and reporting any 12- 

hour rolling average concentration of reduced sulfur greater than the applicable 

emission limitation in the semiannual compliance report required by § 63.1575. 

3. Option 2: TRS limit. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

300 ppmv of TRS compounds, expressed as 

an SO2 concentration (dry basis) at zero 

percent oxygen or reduced sulfur compounds calculated as ppmv SO2 (dry basis) 

at zero percent excess air.

i. If you use continuous parameter monitoring 

systems, collecting the hourly average TRS 

monitoring data according to § 63.1572 and 

maintaining each 12-hour average concentration of TRS at or below the applicable 

emission limitation; or 

ii. If you use a continuous emission monitoring system, collecting the hourly average 

TRS monitoring data according to 

§ 63.1572, determining and recording each 

12-hour rolling average concentration of 

TRS; maintaining each 12-hour rolling average concentration of TRS at or below the 

applicable emission limitation; and reporting 

any 12-hour rolling average TRS concentration greater than the applicable emission 

limitation in the semiannual compliance report required by § 63.1575. 

■ 83. Table 35 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1568(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 35 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR HAP EMISSIONS

FROM SULFUR RECOVERY UNITS

For . . . For this operating limit . . . You shall demonstrate continuous compliance 

by . . . 

1. Subject to NSPS. Each new or existing 

Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater 

than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

Not applicable .................................................. Meeting the requirements of Table 34 of this 

subpart. 


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TABLE 35 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR HAP EMISSIONS

FROM SULFUR RECOVERY UNITS—Continued 

For . . . For this operating limit . . . You shall demonstrate continuous compliance 

by . . . 

2. Option 1: Elect NSPS. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

Not applicable .................................................. Meeting the requirements of Table 34 of this 

subpart. 

3. Option 2: TRS limit. Each new or existing 

sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for 

sulfur oxides in 40 CFR 60.104(a)(2) or 

60.102a(f)(1).

a. Maintain the daily average combustion 

zone temperature above the level established during the performance test.

Collecting the hourly and daily average temperature monitoring data according to 

§ 63.1572; and maintaining the daily average combustion zone temperature at or 

above the limit established during the performance test 

b. The daily average oxygen concentration in 

the vent stream (percent, dry basis) must 

not fall below the level established during 

the performance test..

Collecting the hourly and daily average O2

monitoring data according to § 63.1572; and 

maintaining the average O2 concentration 

above the level established during the performance test. 

4. Startup or shutdown option 1: Electing to 

comply with § 63.1568(a)(4)(ii). Each new or 

existing sulfur recovery unit (Claus or other 

type, regardless of size) during periods of 

startup or shutdown.

Using a flare meeting the requirements in 

§ 63.11(b) or § 63.670.

On and after January 30, 2019, complying 

with the applicable requirements of 

§ 63.670. Prior to January 30, 2019, complying with the applicable requirements of 

either § 63.11(b) or § 63.670. 

5. Startup or shutdown option 2: Electing to 

comply with § 63.1568(a)(4)(iii). Each new or 

existing sulfur recovery unit (Claus or other 

type, regardless of size) during periods of 

startup or shutdown.

a. Minimum hourly average temperature of 

1,200 degrees Fahrenheit.

Collecting continuous (at least once every 15 

minutes) and hourly average temperature 

monitoring data according to § 63.1572; and 

maintaining the daily average firebox temperature at or above 1,200 degrees Fahrenheit. 

b. Minimum hourly average outlet oxygen 

concentration of 2 volume percent (dry 

basis).

Collecting continuous (at least once every 15 

minutes) and hourly average O2 monitoring 

data according to § 63.1572; and maintaining the average O2 concentration at or 

above 2 volume percent (dry basis). 

■ 84. Table 40 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1572(a)(1) and (b)(1), 

you shall meet each requirement in the 

following table that applies to you. 

TABLE 40 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF

CONTINUOUS OPACITY MONITORING SYSTEMS AND CONTINUOUS EMISSION MONITORING SYSTEMS

This type of continuous opacity or emission monitoring system . . . Must meet these requirements . . . 

1. Continuous opacity monitoring system ................................................ Performance specification 1 (40 CFR part 60, appendix B). 

2. PM CEMS; this monitor must include an O2 monitor for correcting 

the data for excess air.

The requirements in 40 CFR 60.105a(d). 

3. CO continuous emission monitoring system ........................................ Performance specification 4 (40 CFR part 60, appendix B); span value 

of 1,000 ppm; and procedure 1 (40 CFR part 60, appendix F) except 

relative accuracy test audits are required annually instead of quarterly. 

4. CO continuous emission monitoring system used to demonstrate 

emissions average under 50 ppm (dry basis).

Performance specification 4 (40 CFR part 60, appendix B); and span 

value of 100 ppm. 

5. SO2 continuous emission monitoring system for sulfur recovery unit 

with oxidation control system or reduction control system; this monitor must include an O2 monitor for correcting the data for excess air.

Performance specification 2 (40 CFR part 60, appendix B); span value 

of 500 ppm SO2, or if using Equation 1 of 40 CFR 60.102a(f)(1)(i), 

span value of two times the limit at the highest O2 concentration; use 

Methods 6 or 6C (40 CFR part 60, appendix A–4) for certifying the 

SO2 monitor and Methods 3A or 3B (40 CFR part 60, appendix A–2) 

for certifying the O2 monitor; and procedure 1 (40 CFR part 60, appendix F) except relative accuracy test audits are required annually 

instead of quarterly. 


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TABLE 40 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF

CONTINUOUS OPACITY MONITORING SYSTEMS AND CONTINUOUS EMISSION MONITORING SYSTEMS—Continued 

This type of continuous opacity or emission monitoring system . . . Must meet these requirements . . . 

6. Reduced sulfur and O2 continuous emission monitoring system for 

sulfur recovery unit with reduction control system not followed by incineration; this monitor must include an O2 monitor for correcting the 

data for excess air unless exempted.

Performance specification 5 (40 CFR part 60, appendix B), except calibration drift specification is 2.5 percent of the span value instead of 5 

percent; span value is 450 ppm reduced sulfur, or if using Equation 

1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the 

highest O2 concentration; use Methods 15 or 15A (40 CFR part 60, 

appendix A–5) for certifying the reduced sulfur monitor and Methods 

3A or 3B (40 CFR part 60, appendix A–2) for certifying the O2 monitor; if Method 3A or 3B yields O2 concentrations below 0.25 percent 

during the performance evaluation, the O2 concentration can be assumed to be zero and the O2 monitor is not required; and procedure 

1 (40 CFR part 60, appendix F), except relative accuracy test audits, 

are required annually instead of quarterly. 

7. Instrument with an air or O2 dilution and oxidation system to convert 

reduced sulfur to SO2 for continuously monitoring the concentration 

of SO2 instead of reduced sulfur monitor and O2 monitor.

Performance specification 5 (40 CFR part 60, appendix B); span value 

of 375 ppm SO2 or if using Equation 1 of 40 CFR 60.102a(f)(1)(i), 

span value of two times the limit at the highest O2 concentration; use 

Methods 15 or 15A (40 CFR part 60, appendix A–5) for certifying the 

reduced sulfur monitor and 3A or 3B (40 CFR part 60, appendix A– 

2) for certifying the O2 monitor; and procedure 1 (40 CFR part 60, 

appendix F), except relative accuracy test audits, are required annually instead of quarterly. 

8. TRS continuous emission monitoring system for sulfur recovery unit; 

this monitor must include an O2 monitor for correcting the data for 

excess air.

Performance specification 5 (40 CFR part 60, appendix B). 

9. O2 monitor for oxygen concentration ................................................... If necessary due to interferences, locate the oxygen sensor prior to the 

introduction of any outside gas stream; performance specification 3 

(40 CFR part 60, appendix B; and procedure 1 (40 CFR part 60, appendix F), except relative accuracy test audits, are required annually 

instead of quarterly. 

■ 85. Table 41 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1572(c)(1), you shall 

meet each requirement in the following 

table that applies to you. 

TABLE 41 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF

CONTINUOUS PARAMETER MONITORING SYSTEMS

If you use . . . You shall . . . 

1. pH strips ............ Use pH strips with an accuracy of ±10 percent. 

2. pH meter ............ Locate the pH sensor in a position that provides a representative measurement of pH; ensure the sample is properly 

mixed and representative of the fluid to be measured. 

Use a pH sensor with an accuracy of at least ±0.2 pH units. 

Check the pH meter’s calibration on at least one point at least once daily; check the pH meter’s calibration on at least two 

points at least once quarterly; at least monthly, inspect all components for integrity and all electrical components for 

continuity; record the results of each calibration check and inspection. 

3. Colormetric tube 

sampling system.

Use a colormetric tube sampling system with a printed numerical scale in ppmv, a standard measurement range of 1 to 10 

ppmv (or 1 to 30 ppmv if applicable), and a standard deviation for measured values of no more than ±15 percent. System must include a gas detection pump and hot air probe if needed for the measurement range. 

4. CO2, O2, and CO 

monitors for coke 

burn-off rate.

a. Locate the concentration sensor so that it provides a representative measurement of the content of the exit gas stream; 

ensure the sample is properly mixed and representative of the gas to be measured. 

Use a sensor with an accuracy of at least ±1 percent of the range of the sensor or to a nominal gas concentration of ±0.5 

percent, whichever is greater. 

Use a monitor that is able to measure concentration on a dry basis or is able to correct for moisture content and record on 

a dry basis. 

Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours 

throughout which the sensor reading exceeds the manufacturer’s specified maximum operating range or install a new 

sensor; at least quarterly, inspect all components for integrity and all electrical connections for continuity; record the results of each calibration and inspection. 

b. As an alternative, the requirements in 40 CFR 60.105a(b)(2) may be used. 

5. BLD .................... Follow the requirements in 40 CFR 60.105a(c). 

6. Voltage, secondary current, or 

total power input 

sensors.

Use meters with an accuracy of at least ±5 percent over the operating range. 


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TABLE 41 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF

CONTINUOUS PARAMETER MONITORING SYSTEMS—Continued 

If you use . . . You shall . . . 

Each time that the unit is not operating, confirm that the meters read zero. Conduct a calibration check at least annually; 

conduct calibration checks following any period of more than 24 hours throughout which the meter reading exceeds the 

manufacturer’s specified maximum operating range; at least monthly, inspect all components of the continuous parameter monitoring system for integrity and all electrical connections for continuity; record the results of each calibration 

check and inspection. 

7. Pressure/Pressure drop1 sensors.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. 

Use a gauge with an accuracy of at least ±5 percent over the normal operating range or 0.12 kilopascals (0.5 inches of 

water column), whichever is greater. 

Review pressure sensor readings at least once a week for straightline (unchanging) pressure and perform corrective action to ensure 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. 

8. Air flow rate, gas 

flow rate, or total 

water (or scrubbing liquid) flow 

rate sensors.

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. 

If you elect to comply with Option 3 (Ni lb/hr) or Option 4 (Ni lb/1,000 lb of coke burn-off) for the HAP metal emission 

limitations in § 63.1564, install the continuous parameter monitoring system for gas flow rate as close as practical to the 

continuous opacity monitoring system; and if you don’t use a continuous opacity monitoring system, install the continuous parameter monitoring system for gas flow rate as close as practical to the control device. 

Use a flow rate sensor with an accuracy of at least ±5 percent over the normal range of flow measured, or 1.9 liter per 

minute (0.5 gallons per minute), whichever is greater, for liquid flow. 

Use a flow rate sensor with an accuracy of at least ±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. 

Conduct a flow sensor calibration check at least biennially (every two years); conduct a calibration check following any period of more than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow 

rate or install a new flow sensor; at least quarterly, inspect all components for leakage, unless the CPMS has a redundant flow sensor; record the results of each calibration check and inspection. 

9. Temperature 

sensors.

Locate the temperature sensor in the combustion zone, or in the ductwork immediately downstream of the combustion 

zone before any substantial heat exchange occurs or in the ductwork immediately downstream of the regenerator; locate the temperature sensor in a position that provides a representative temperature; shield the temperature sensor system from electromagnetic interference and chemical contaminants. 

Use a temperature sensor with an accuracy of at least ±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. 

10. Oxygen content 

sensors 2.

Locate the oxygen sensor so that it provides a representative measurement of the oxygen content of the exit gas stream; 

ensure the sample is properly mixed and representative of the gas to be measured. 

Use an oxygen sensor with an accuracy of at least ±1 percent of the range of the sensor or to a nominal gas concentration of ±0.5 percent, whichever is greater. 

Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours 

throughout which the sensor reading exceeds the manufacturer’s specified maximum operating range or install a new 

oxygen sensor; at least quarterly, inspect all components for integrity and all electrical connections for continuity; record 

the results of each calibration and inspection. 

1 Not applicable to non-venturi wet scrubbers of the jet-ejector design. 

2This does not replace the requirements for oxygen monitors that are required to use continuous emissions monitoring systems. The requirements in this table apply to oxygen sensors that are continuous parameter monitors, such as those that monitor combustion zone oxygen concentration and regenerator exit oxygen concentration. 

■ 86. Table 43 to subpart UUU is revised 

to read as follows: 

As stated in § 63.1575(a), you shall 

meet each requirement in the following 

table that applies to you. 


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75320 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 43 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR REPORTS

You must submit . . . The report must contain . . . You shall submit the report . . . 

1. A compliance report .................... If there are no deviations from any emission limitation or work practice standard that applies to you, a statement that there were no 

deviations from the standards during the reporting period and that 

no continuous opacity monitoring system or continuous emission 

monitoring system was inoperative, inactive, out-of-control, repaired, or adjusted; if you have a deviation from any emission limitation or work practice standard during the reporting period, the report must contain the information in § 63.1575(c) through (e).

Semiannually according to the requirements in § 63.1575(b). 

2. Performance test and CEMS 

performance evaluation data.

On and after January 30, 2019, the information specified in 

§ 63.1575(k)(1).

Within 60 days after the date of 

completing each test according 

to the requirements in 

§ 63.1575(k). 

■ 87. Table 44 to subpart UUU of part 

63 is revised to read as follows: 

As stated in § 63.1577, you shall meet 

each requirement in the following table 

that applies to you. 

TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU 

Citation Subject Applies to subpart 

UUU Explanation 

§ 63.1(a)(1)–(4) ..................................... General Applicability ........................... Yes .............................

§ 63.1(a)(5) ............................................ [Reserved] .......................................... Not applicable ............

§ 63.1(a)(6) ............................................ ............................................................. Yes ............................. Except the correct mail drop (MD) 

number is C404–04. 

§ 63.1(a)(7)–(9) ..................................... [Reserved] .......................................... Not applicable ............

§ 63.1(a)(10)–(12) ................................. ............................................................. Yes ............................. Except that this subpart specifies calendar or operating day. 

§ 63.1(b)(1) ............................................ Initial Applicability Determination for 

this part.

Yes .............................

§ 63.1(b)(2) ............................................ [Reserved] .......................................... Not applicable ............

§ 63.1(b)(3) ............................................ ............................................................. Yes .............................

§ 63.1(c)(1) ............................................ Applicability of this part after a Relevant Standard has been set under 

this part.

Yes .............................

§ 63.1(c)(2) ............................................ ............................................................. No ............................... Area sources are not subject to this 

subpart. 

§ 63.1(c)(3)–(4) ..................................... [Reserved] .......................................... Not applicable ............

§ 63.1(c)(5) ............................................ ............................................................. Yes .............................

§ 63.1(d) ................................................ [Reserved] .......................................... Not applicable ............

§ 63.1(e) ................................................ Applicability of Permit Program .......... Yes .............................

§ 63.2 .................................................... Definitions ........................................... Yes ............................. § 63.1579 specifies that if the same 

term is defined in subparts A and 

UUU of this part, it shall have the 

meaning given in this subpart. 

§ 63.3 .................................................... Units and Abbreviations ..................... Yes .............................

§ 63.4(a)(1)–(2) ..................................... Prohibited Activities ............................ Yes .............................

§ 63.4(a)(3)–(5) ..................................... [Reserved] .......................................... Not applicable ............

§ 63.4(b)–(c) .......................................... Circumvention and Fragmentation ..... Yes .............................

§ 63.5(a) ................................................ Construction and Reconstruction ....... Yes .............................

§ 63.5(b)(1) ............................................ ............................................................. Yes .............................

§ 63.5(b)(2) ............................................ [Reserved] .......................................... Not applicable ............

§ 63.5(b)(3)–(4) ..................................... ............................................................. Yes ............................. In § 63.5(b)(4), replace the reference 

to § 63.9(b) with § 63.9(b)(4) and 

(5). 

§ 63.5(b)(5) ............................................ [Reserved] .......................................... Not applicable ............

§ 63.5(b)(6) ............................................ ............................................................. Yes .............................

§ 63.5(c) ................................................ [Reserved] .......................................... Not applicable ............

§ 63.5(d)(1)(i) ........................................ Application for Approval of Construction or Reconstruction—General 

Application Requirements.

Yes ............................. Except this subpart specifies the application is submitted as soon as 

practicable before startup but not 

later than 90 days after the promulgation date if construction or reconstruction had commenced and initial startup had not occurred before 

promulgation. 


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TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— 

Continued 

Citation Subject Applies to subpart 

UUU Explanation 

§ 63.5(d)(1)(ii) ........................................ ............................................................. Yes ............................. Except that 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 ............................... This subpart specifies submission of 

notification of compliance status. 

§ 63.5(d)(2) ............................................ ............................................................. Yes .............................

§ 63.5(d)(3) ............................................ ............................................................. Yes .............................

§ 63.5(d)(4) ............................................ ............................................................. Yes .............................

§ 63.5(e) ................................................ Approval of Construction or Reconstruction.Yes .............................

§ 63.5(f)(1) ............................................. Approval of Construction or Reconstruction Based on State Review.Yes .............................

§ 63.5(f)(2) ............................................. ............................................................. Yes ............................. Except that the cross-reference to 

§ 63.9(b)(2) does not apply. 

§ 63.6(a) ................................................ Compliance with Standards and 

Maintenance—Applicability.

Yes .............................

§ 63.6(b)(1)–(4) ..................................... Compliance Dates for New and Reconstructed Sources.Yes .............................

§ 63.6(b)(5) ............................................ ............................................................. Yes ............................. Except that this subpart specifies different compliance dates for 

sources. 

§ 63.6(b)(6) ............................................ [Reserved] .......................................... Not applicable ............

§ 63.6(b)(7) ............................................ Compliance Dates for New and Reconstructed Area Sources That Become Major.Yes .............................

§ 63.6(c)(1)–(2) ..................................... Compliance Dates for Existing 

Sources.

Yes ............................. Except that this subpart specifies different compliance dates for sources 

subject to Tier II gasoline sulfur 

control requirements. 

§ 63.6(c)(3)–(4) ..................................... [Reserved] .......................................... Not applicable ............

§ 63.6(c)(5) ............................................ Compliance Dates for Existing Area 

Sources That Become Major.

Yes .............................

§ 63.6(d) ................................................ [Reserved] .......................................... Not applicable ............

§ 63.6(e)(1)(i) ........................................ General Duty to Minimize Emissions No ............................... See § 63.1570(c) for general duty requirement. 

§ 63.6(e)(1)(ii) ........................................ Requirement to Correct Malfunctions 

as Soon as Possible.

No ...............................

§ 63.6(e)(1)(iii) ....................................... Compliance with Standards and 

Maintenance Requirements.

Yes .............................

§ 63.6(e)(2) ............................................ [Reserved] .......................................... Not Applicable ............

§ 63.6(e)(3)(i) ........................................ Startup, Shutdown, and Malfunction 

Plan Requirements.

No ...............................

§ 63.6(e)(3)(ii) ........................................ [Reserved] .......................................... Not applicable ............

§ 63.6(e)(3)(iii)–(ix) ................................ ............................................................. No ...............................

§ 63.6(f)(1) ............................................. SSM Exemption .................................. No ...............................

§ 63.6(f)(2)(i)–(iii)(C) .............................. Compliance with Standards and 

Maintenance Requirements.

Yes .............................

§ 63.6(f)(2)(iii)(D) ................................... ............................................................. Yes .............................

§ 63.6(f)(2)(iv)–(v) ................................. ............................................................. Yes .............................

§ 63.6(f)(3) ............................................. ............................................................. Yes ............................. Except the cross-references to 

§ 63.6(f)(1) and (e)(1)(i) are 

changed to § 63.1570(c). 

§ 63.6(g) ................................................ Alternative Standard ........................... Yes .............................

§ 63.6(h)(1) ............................................ SSM Exemption for Opacity/VE 

Standards.

No ...............................

§ 63.6(h)(2)(i) ........................................ Determining Compliance with Opacity/VE Standards.No ............................... This subpart specifies methods. 

§ 63.6(h)(2)(ii) ........................................ [Reserved] .......................................... Not applicable ............

§ 63.6(h)(2)(iii) ....................................... ............................................................. Yes .............................

§ 63.6(h)(3) ............................................ [Reserved] .......................................... Not applicable ............

§ 63.6(h)(4) ............................................ Notification of Opacity/VE Observation Date.Yes ............................. Applies to Method 22 (40 CFR part 

60, appendix A–7) tests. 

§ 63.6(h)(5) ............................................ Conducting Opacity/VE Observations No ...............................

§ 63.6(h)(6) ............................................ Records of Conditions During Opacity/VE Observations.Yes ............................. Applies to Method 22 (40 CFR part 

60, appendix A–7) observations. 

§ 63.6(h)(7)(i) ........................................ Report COM Monitoring Data from 

Performance Test.

Yes .............................

§ 63.6(h)(7)(ii) ........................................ Using COM Instead of Method 9 ....... No ...............................


tkelley on DSK3SPTVN1PROD with RULES2
75322 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— 

Continued 

Citation Subject Applies to subpart 

UUU Explanation 

§ 63.6(h)(7)(iii) ....................................... Averaging Time for COM during Performance Test.Yes .............................

§ 63.6(h)(7)(iv) ....................................... COM Requirements ............................ Yes .............................

§ 63.6(h)(7)(v) ....................................... COMS Results and Visual Observations.Yes .............................

§ 63.6(h)(8) ............................................ Determining Compliance with Opacity/VE Standards.Yes .............................

§ 63.6(h)(9) ............................................ Adjusted Opacity Standard ................ Yes .............................

§ 63.6(i)(1)–(14) .................................... Extension of Compliance ................... Yes ............................. Extension of compliance under 

§ 63.6(i)(4) not applicable to a facility that installs catalytic cracking 

feed hydrotreating and receives an 

extended compliance date under 

§ 63.1563(c). 

§ 63.6(i)(15) ........................................... [Reserved] .......................................... Not applicable ............

§ 63.6(i)(16) ........................................... ............................................................. Yes .............................

§ 63.6(j) ................................................. Presidential Compliance Exemption .. Yes .............................

§ 63.7(a)(1) ............................................ Performance Test Requirements Applicability.Yes ............................. Except that this subpart specifies the 

applicable test and demonstration 

procedures. 

§ 63.7(a)(2) ............................................ Performance Test Dates .................... Yes ............................. Except test results must be submitted 

in the Notification of Compliance 

Status report due 150 days after 

the compliance date. 

§ 63.7(a)(3) ............................................ Section 114 Authority ......................... Yes .............................

§ 63.7(a)(4) ............................................ Force Majeure .................................... Yes .............................

§ 63.7(b) ................................................ Notifications ........................................ Yes ............................. Except that this subpart specifies notification at least 30 days prior to 

the scheduled test date rather than 

60 days. 

§ 63.7(c) ................................................ Quality Assurance Program/Site-Specific Test Plan.Yes ............................. Except that when this subpart specifies to use 40 CFR part 60, appendix F, out of control periods are to 

be defined as specified in part 60, 

appendix F. 

§ 63.7(d) ................................................ Performance Test Facilities ................ Yes .............................

§ 63.7(e)(1) ............................................ Performance Testing .......................... No ............................... See § 63.1571(b)(1). 

§ 63.7(e)(2)–(4) ..................................... Conduct of Tests ................................ Yes .............................

§ 63.7(f) ................................................. Alternative Test Method ..................... Yes .............................

§ 63.7(g) ................................................ Data Analysis, Recordkeeping, Reporting.Yes ............................. Except performance test reports must 

be submitted with notification of 

compliance status due 150 days 

after the compliance date, and 

§ 63.7(g)(2) is reserved and does 

not apply. 

§ 63.7(h) ................................................ Waiver of Tests .................................. Yes .............................

§ 63.8(a)(1) ............................................ Monitoring Requirements-Applicability Yes .............................

§ 63.8(a)(2) ............................................ Performance Specifications ................ Yes .............................

§ 63.8(a)(3) ............................................ [Reserved] .......................................... Not applicable ............

§ 63.8(a)(4) ............................................ Monitoring with Flares ........................ Yes ............................. Except that for a flare complying with 

§ 63.670, the cross-reference to 

§ 63.11 in this paragraph does not 

include § 63.11(b). 

§ 63.8(b)(1) ............................................ Conduct of Monitoring ........................ Yes .............................

§ 63.8(b)(2)–(3) ..................................... Multiple Effluents and Multiple Monitoring Systems.Yes ............................. This subpart specifies the required 

monitoring locations. 

§ 63.8(c)(1) ............................................ Monitoring System Operation and 

Maintenance.

Yes .............................

§ 63.8(c)(1)(i) ......................................... General Duty to Minimize Emissions 

and CMS Operation.

No ............................... See § 63.1570(c). 

§ 63.8(c)(1)(ii) ........................................ Keep Necessary Parts for CMS ......... Yes .............................

§ 63.8(c)(1)(iii) ....................................... Requirement to Develop SSM Plan 

for CMS.

No ...............................


tkelley on DSK3SPTVN1PROD with RULES2
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TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— 

Continued 

Citation Subject Applies to subpart 

UUU Explanation 

§ 63.8(c)(2)–(3) ..................................... Monitoring System Installation ........... Yes ............................. Except that this subpart specifies that 

for continuous parameter monitoring systems, operational status 

verification includes completion of 

manufacturer written specifications 

or installation, operation, and calibration of the system or other written procedures that provide adequate assurance that the equipment will monitor accurately. 

§ 63.8(c)(4) ............................................ Continuous Monitoring System Requirements.Yes .............................

§ 63.8(c)(5) ............................................ COMS Minimum Procedures .............. Yes .............................

§ 63.8(c)(6) ............................................ CMS Requirements ............................ Yes .............................

§ 63.8(c)(7)–(8) ..................................... CMS Requirements ............................ Yes .............................

§ 63.8(d)(1)–(2) ..................................... Quality Control Program for CMS ...... Yes .............................

§ 63.8(d)(3) ............................................ Written Procedures for CMS .............. No ...............................

§ 63.8(e) ................................................ CMS Performance Evaluation ............ Yes ............................. Except that results are to be submitted as part of the Notification 

Compliance Status due 150 days 

after the compliance date. 

§ 63.8(f)(1)–(5) ...................................... Alternative Monitoring Methods .......... Yes ............................. Except that this subpart specifies procedures for requesting alternative 

monitoring systems and alternative 

parameters. 

§ 63.8(f)(6) ............................................. Alternative to Relative Accuracy Test Yes ............................. Applicable to continuous emission 

monitoring systems if performance 

specification requires a relative accuracy test audit. 

§ 63.8(g)(1)–(4) ..................................... Reduction of Monitoring Data ............ Yes ............................. Applies to continuous opacity monitoring system or continuous emission monitoring system. 

§ 63.8(g)(5) ............................................ Data Reduction ................................... No ............................... This subpart specifies requirements. 

§ 63.9(a) ................................................ Notification Requirements—Applicability.Yes ............................. Duplicate Notification of Compliance 

Status report to the Regional Administrator may be required. 

§ 63.9(b)(1)–(2) ..................................... Initial Notifications .............................. Yes ............................. Except that notification of construction 

or reconstruction is to be submitted 

as soon as practicable before startup but no later than 30 days after 

the effective date if construction or 

reconstruction had commenced but 

startup had not occurred before the 

effective date. 

§ 63.9(b)(3) ............................................ [Reserved] .......................................... Not applicable ............

§ 63.9(b)(4)–(5) ..................................... Initial Notification Information ............. Yes ............................. Except § 63.9(b)(4)(ii)–(iv), which are 

reserved and do not apply. 

§ 63.9(c) ................................................ Request for Extension of Compliance Yes .............................

§ 63.9(d) ................................................ New Source Notification for Special 

Compliance Requirements.

Yes .............................

§ 63.9(e) ................................................ Notification of Performance Test ........ Yes ............................. Except that notification is required at 

least 30 days before test. 

§ 63.9(f) ................................................. Notification of VE/Opacity Test .......... Yes .............................

§ 63.9(g) ................................................ Additional Notification Requirements 

for Sources with Continuous Monitoring Systems.

Yes .............................

§ 63.9(h) ................................................ Notification of Compliance Status ...... Yes ............................. Except that this subpart specifies the 

notification is due no later than 150 

days after compliance date, and 

except that the reference to 

§ 63.5(d)(1)(ii)(H) in § 63.9(h)(5) 

does not apply. 

§ 63.9(i) ................................................. Adjustment of Deadlines .................... Yes .............................

§ 63.9(j) ................................................. Change in Previous Information ......... Yes .............................

63.10(a) ................................................. Recordkeeping and Reporting Applicability.Yes .............................

§ 63.10(b)(1) .......................................... General Recordkeeping Requirements.Yes .............................


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TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— 

Continued 

Citation Subject Applies to subpart 

UUU Explanation 

§ 63.10(b)(2)(i) ...................................... Recordkeeping of Occurrence and 

Duration of Startups and Shutdowns.

No ...............................

§ 63.10(b)(2)(ii) ...................................... Recordkeeping of Malfunctions .......... No ............................... See § 63.1576(a)(2) for recordkeeping 

of (1) date, time and duration; (2) 

listing of affected source or equipment, and an estimate of the volume of each regulated pollutant 

emitted over the standard; and (3) 

actions taken to minimize emissions and correct the failure. 

§ 63.10(b)(2)(iii) ..................................... Maintenance Records ........................ Yes .............................

§ 63.10(b)(2)(iv)–(v) .............................. Actions Taken to Minimize Emissions 

During SSM.

No ...............................

§ 63.10(b)(2)(vi) ..................................... Recordkeeping for CMS Malfunctions Yes .............................

§ 63.10(b)(2)(vii)–(xiv) ........................... Other CMS Requirements .................. Yes .............................

§ 63.10(b)(3) .......................................... Recordkeeping for Applicability Determinations..Yes .............................

§ 63.10(c)(1)–(6) ................................... Additional Records for Continuous 

Monitoring Systems.

Yes ............................. Except § 63.10(c)(2)–(4), which are 

Reserved and do not apply. 

§ 63.10(c)(7)–(8) ................................... Additional Recordkeeping Requirements for CMS—Identifying 

Exceedances and Excess Emissions.

Yes .............................

§ 63.10(c)(9) .......................................... [Reserved] .......................................... Not applicable ............

§ 63.10(c)(10) ........................................ Recording Nature and Cause of Malfunctions.No ............................... See § 63.1576(a)(2) for malfunctions 

recordkeeping requirements. 

§ 63.10(c)(11) ........................................ Recording Corrective Actions ............. No ............................... See § 63.1576(a)(2) for malfunctions 

recordkeeping requirements. 

§ 63.10(c)(12)–(14) ............................... Additional CMS Recordkeeping Requirements.Yes .............................

§ 63.10(c)(15) ........................................ Use of SSM Plan ................................ No ...............................

§ 63.10(d)(1) .......................................... General Reporting Requirements ...... Yes .............................

§ 63.10(d)(2) .......................................... Performance Test Results .................. No ............................... This subpart requires performance 

test results to be reported as part 

of the Notification of Compliance 

Status due 150 days after the compliance date. 

§ 63.10(d)(3) .......................................... Opacity or VE Observations ............... Yes .............................

§ 63.10(d)(4) .......................................... Progress Reports ............................... Yes .............................

§ 63.10(d)(5) .......................................... SSM Reports ...................................... No ............................... See § 63.1575(d) for CPMS malfunction reporting and § 63.1575(e) for 

COMS and CEMS malfunction reporting. 

§ 63.10(e)(1)–(2) ................................... Additional CMS Reports ..................... Yes ............................. Except that reports of performance 

evaluations must be submitted in 

Notification of Compliance Status. 

§ 63.10(e)(3) .......................................... Excess Emissions/CMS Performance 

Reports.

No ............................... This subpart specifies the applicable 

requirements. 

§ 63.10(e)(4) .......................................... COMS Data Reports .......................... Yes .............................

§ 63.10(f) ............................................... Recordkeeping/Reporting Waiver ...... Yes .............................

§ 63.11(a) .............................................. Control Device and Work Practice 

Requirements Applicability.

Yes .............................

§ 63.11(b) .............................................. Flares .................................................. Yes ............................. Except that flares complying with 

§ 63.670 are not subject to the requirements of § 63.11(b). 

§ 63.11(c)–(e) ........................................ Alternative Work Practice for Monitoring Equipment for Leaks.Yes .............................

§ 63.12 .................................................. State Authority and Delegations ........ Yes .............................

§ 63.13 .................................................. Addresses ........................................... Yes .............................

§ 63.14 .................................................. Incorporation by Reference ................ Yes .............................

§ 63.15 .................................................. Availability of Information and Confidentiality.Yes .............................

§ 63.16 .................................................. Performance Track Provisions ........... Yes .............................


tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75325 

■ 88. Appendix A to subpart UUU of 

part 63 is amended by revising the first 

sentence of section 2.1 and section 7.1.3 

to read as follows: 

Appendix A to Subpart UUU of Part 

63—Determination of Metal 

Concentration on Catalyst Particles 

(Instrumental Analyzer Procedure) 

* * * * * 

2.1 A representative sample of catalyst 

particles is collected, prepared, and analyzed 

for analyte concentration using either energy 

or wavelength dispersive X-ray fluorescent 

(XRF) spectrometry instrumental analyzers. 

* * * 

* * * * * 

7.1.3 Low-Range Calibration Standard. 

Concentration equivalent to 1 to 20 percent 

of the span. The concentration of the lowrange calibration standard should be selected 

so that it is less than either one-fourth of the 

applicable concentration limit or of the 

lowest concentration anticipated in the 

catalyst samples. 

* * * * * 

■ 89. Appendix A to part 63 is amended 

by adding Method 325A and Method 

325B in numerical order to read as 

follows: 

Appendix A to Part 63—Test Methods 

Pollutant Measurement Methods From 

Various Waste Media 

* * * * * 

Method 325A—Volatile Organic 

Compounds from Fugitive and Area Sources: 

Sampler Deployment and VOC Sample 

Collection 

1.0 Scope and Application 

1.1 This method describes collection of 

volatile organic compounds (VOCs) at or 

inside a facility property boundary or from 

fugitive and area emission sources using 

passive (diffusive) tube samplers (PS). The 

concentration of airborne VOCs at or near 

these potential fugitive- or area-emission 

sources may be determined using this 

method in combination with Method 325B. 

Companion Method 325B (Sampler 

Preparation and Analysis) describes 

preparation of sampling tubes, shipment and 

storage of exposed sampling tubes, and 

analysis of sampling tubes collected using 

either this passive sampling procedure or 

alternative active (pumped) sampling 

methods. 

1.2 This method may be used to 

determine the average concentration of the 

select VOCs using the corresponding uptake 

rates listed in Method 325B, Table 12.1. 

Additional compounds or alternative 

sorbents must be evaluated as described in 

Addendum A of Method 325B or by one of 

the following national/international standard 

methods: ISO 16017–2:2003(E), ASTM 

D6196–03 (Reapproved 2009), or BS EN 

14662–4:2005 (all incorporated by 

reference—see § 63.14), or reported in the 

peer-reviewed open literature. 

1.3 Methods 325A and 325B are valid for 

the measurement of benzene. Supporting 

literature (References 1–8) indicates that 

benzene can be measured by flame ionization 

detection or mass spectrometry over a 

concentration range of approximately 0.5 

micrograms per cubic meter (mg/m3) to at 

least 500 mg/m3 when industry standard (3.5 

inch long × 0.25 inch outside diameter (o.d.) 

× 5 mm inner diameter (i.d.)) inert-coated 

stainless steel sorbent tubes packed with 

CarbographTM 1 TD, CarbopackTM B, or 

CarbopackTM X or equivalent are used and 

when samples are accumulated over a period 

of 14 days. 

1.4 This method may be applied to 

screening average airborne VOC 

concentrations at facility property boundaries 

or monitoring perimeters over an extended 

period of time using multiple sampling 

periods (e.g., 26 × 14-day sampling periods). 

The duration of each sampling period is 

normally 14 days. 

1.5 This method requires the collection of 

local meteorological data (wind speed and 

direction, temperature, and barometric 

pressure). Although local meteorology is a 

component of this method, non-regulatory 

applications of this method may use regional 

meteorological data. Such applications risk 

that the results may not identify the precise 

source of the emissions. 

2.0 Summary of the Method 

2.1 Principle of the Method 

The diffusive passive sampler collects VOC 

from air for a measured time period at a rate 

that is proportional to the concentration of 

vapor in the air at that location. 

2.1.1 This method describes the 

deployment of prepared passive samplers, 

including determination of the number of 

passive samplers needed for each survey and 

placement of samplers along or inside the 

facility property boundary depending on the 

size and shape of the site or linear length of 

the boundary. 

2.1.2 The rate of sampling is specific to 

each compound and depends on the 

diffusion constants of that VOC and the 

sampler dimensions/characteristics as 

determined by prior calibration in a standard 

atmosphere (Reference 1). 

2.1.3 The gaseous VOC target compounds 

migrate through a constant diffusion barrier 

(e.g., an air gap of fixed dimensions) at the 

sampling end of the diffusion sampling tube 

and adsorb onto the sorbent. 

2.1.4 Heat and a flow of inert carrier gas 

are then used to extract (desorb) the retained 

VOCs back from the sampling end of the tube 

and transport/transfer them to a gas 

chromatograph (GC) equipped with a 

chromatographic column to separate the 

VOCs and a detector to determine the 

quantity of target VOCs. 

2.1.5 Gaseous or liquid calibration 

standards loaded onto the sampling ends of 

clean sorbent tubes must be used to calibrate 

the analytical equipment. 

2.1.6 This method requires the use of 

field blanks to ensure sample integrity 

associated with shipment, collection, and 

storage of the passive samples. It also 

requires the use of field duplicates to validate 

the sampling process. 

2.1.7 At the end of each sampling period, 

the passive samples are collected, sealed, and 

shipped to a laboratory for analysis of target 

VOCs by thermal desorption gas 

chromatography, as described in Method 

325B. 

2.2 Application of Diffusive Sampling 

2.2.1 This method requires deployment of 

passive sampling tubes on a monitoring 

perimeter encompassing all known emission 

sources at a facility and collection of local 

meteorological data. It may be used to 

determine average concentration of VOC at a 

facility’s ‘‘fenceline’’ using time integrated 

passive sampling (Reference 2). 

2.2.2 Collecting samples and 

meteorological data at progressively higher 

frequencies may be employed to resolve 

shorter term concentration fluctuations and 

wind conditions that could introduce 

interfering emissions from other sources. 

2.2.3 This passive sampling method 

provides a low cost approach to screening of 

fugitive or area emissions compared to active 

sampling methods that are based on pumped 

sorbent tubes or time weighted average 

canister sampling. 

2.2.3.1 Additional passive sampling tubes 

may be deployed at different distances from 

the facility property boundary or from the 

geometric center of the fugitive emission 

source. 

2.2.3.2 Additional meteorological 

measurements may also be collected as 

needed to perform preliminary gradientbased assessment of the extent of the 

pollution plume at ground level and the 

effect of ‘‘background’’ sources contributing 

to airborne VOC concentrations at the 

location. 

2.2.4 Time-resolved concentration 

measurements coupled with time-resolved 

meteorological monitoring may be used to 

generate data needed for source 

apportionment procedures and mass flux 

calculations. 

3.0 Definitions 

(See also Section 3.0 of Method 325B.) 

3.1 Fenceline means the property 

boundary of a facility or internal monitoring 

perimeter established in accordance with the 

requirements in Section 8.2 of this method. 

3.2 Passive sampler (PS) means a specific 

type of sorbent tube (defined in this method) 

that has a fixed dimension air (diffusion) gap 

at the sampling end and is sealed at the other 

end. 

3.3 Passive sampling refers to the activity 

of quantitatively collecting VOC on sorbent 

tubes using the process of diffusion. 

3.4 PSi is the annual average for all PS 

concentration results from location i. 

3.5 PSi3 is the set of annual average 

concentration results for PSi and two sorbent 

tubes nearest to the PS location i. 

3.6 PSip is the concentration from the 

sorbent tube at location i for the test period 

or episode p. 

3.7 Sampling period is the length of time 

each passive sampler is exposed during field 

monitoring. The sampling period for this 

method is 14 days. 

3.8 Sorbent tube (Also referred to as tube, 

PS tube, adsorbent tube, and sampling tube) 

is an inert coated stainless steel tube. 

Standard PS tube dimensions for this method 


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are 3.5-inch (89 mm) long × 0.25-inch (6.4 

mm) o.d. with an i.d. of 5 mm, a crosssectional area of 19.6 mm2 and an air gap of 

15 mm. The central portion of the tube is 

packed with solid adsorbent material 

contained between 2 × 100-mesh stainless 

steel gauzes and terminated with a diffusion 

cap at the sampling end of the tube. These 

axial passive samplers are installed under a 

protective hood during field deployment. 

Note: Glass and glass- (or fused silica-) 

lined stainless steel sorbent tubes (typically 

4 mm i.d.) are also available in various 

lengths to suit different makes of thermal 

desorption equipment, but these are rarely 

used for passive sampling because it is more 

difficult to adequately define the diffusive air 

gap in glass or glass-line tubing. Such tubes 

are not recommended for this method. 

4.0 Sampling Interferences 

4.1 General Interferences 

Passive tube samplers should be sited at a 

distance beyond the influence of possible 

obstructions such as trees, walls, or buildings 

at the monitoring site. Complex topography 

and physical site obstructions, such as bodies 

of water, hills, buildings, and other structures 

that may prevent access to a planned PS 

location must be taken into consideration. 

You must document and report siting 

interference with the results of this method. 

4.2 Background Interference 

Nearby or upwind sources of target 

emissions outside the facility being tested 

can contribute to background concentrations. 

Moreover, because passive samplers measure 

continuously, changes in wind direction can 

cause variation in the level of background 

concentrations from interfering sources 

during the monitoring period. This is why 

local meteorological information, particularly 

wind direction and speed, is required to be 

collected throughout the monitoring period. 

Interfering sources can include neighboring 

industrial facilities, transportation facilities, 

fueling operations, combustion sources, 

short-term transient sources, residential 

sources, and nearby highways or roads. As 

PS data are evaluated, the location of 

potential interferences with respect to PS 

locations and local wind conditions should 

be considered, especially when high PS 

concentration values are observed. 

4.3 Tube Handling 

You must protect the PS tubes from gross 

external contamination during field 

sampling. Analytical thermal desorption 

equipment used to analyze PS tubes must 

desorb organic compounds from the interior 

of PS tubes and exclude contamination from 

external sampler surfaces in the analytical/

sample flow path. If the analytical equipment 

does not comply with this requirement, you 

must wear clean, white, cotton or powderfree nitrile gloves to handle sampling tubes 

to prevent contamination of the external 

sampler surfaces. Sampling tubes must be 

capped with two-piece, brass, 0.25 inch, 

long-term storage caps fitted with combined 

polytetrafluoroethylene ferrules (see Section 

6.1 and Method 325B) to prevent ingress of 

airborne contaminants outside the sampling 

period. When not being used for field 

monitoring, the capped tubes must be stored 

in a clean, air-tight, shipping container to 

prevent the collection of VOCs (see Section 

6.4.2 of Method 325B). 

4.4 Local Weather Conditions and 

Airborne Particulates 

Although air speeds are a constraint for 

many forms of passive samplers, axial tube 

PS devices have such a slow inherent uptake 

rate that they are largely immune to these 

effects (References 4,5). Passive samplers 

must nevertheless be deployed under nonemitting weatherproof hoods to moderate the 

effect of local weather conditions such as 

solar heating and rain. The cover must not 

impede the ingress of ambient air. Sampling 

tubes should also be orientated vertically and 

pointing downwards, to minimize 

accumulation of particulates. 

4.5 Temperature 

The normal working range for field 

sampling for sorbent packing is 0–40 °C 

(References 6,7). Note that most published 

passive uptake rate data for sorbent tubes is 

quoted at 20 °C. Note also that, as a rough 

guide, an increase in temperature of 10 °C 

will reduce the collection capacity for a given 

analyte on a given sorbent packing by a factor 

of 2, but the uptake rate will not change 

significantly (Reference 4). 

5.0 Safety 

This method does not purport to include 

all safety issues or procedures needed when 

deploying or collecting passive sampling 

tubes. Precautions typical of field air 

sampling projects are required. Tripping, 

falling, electrical, and weather safety 

considerations must all be included in plans 

to deploy and collect passive sampling tubes. 

6.0 Sampling Equipment and Supplies, and 

Pre-Deployment Planning 

This section describes the equipment and 

supplies needed to deploy passive sampling 

monitoring equipment at a facility property 

boundary. Details of the passive sampling 

tubes themselves and equipment required for 

subsequent analysis are described in Method 

325B. 

6.1 Passive Sampling Tubes 

The industry standard PS tubes used in 

this method must meet the specific 

configuration and preparation requirements 

described in Section 3.0 of this method and 

Section 6.1 of Method 325B. 

Note: The use of PS tubes packed with 

various sorbent materials for monitoring a 

wide variety of organic compounds in 

ambient air has been documented in the 

literature (References 4–10). Other sorbents 

may be used in standard passive sampling 

tubes for monitoring additional target 

compound(s) once their uptake rate and 

performance has been demonstrated 

following procedures in Addendum A to 

Method 325B. Guidance on sorbent selection 

can also be obtained from relevant national 

and international standard methods such as 

ASTM D6196–03 (Reapproved 2009) 

(Reference 14) and ISO 16017–2:2003(E) 

(Reference 13) (both incorporated by 

reference—see § 63.14). 

6.2 Passive or Diffusive Sampling Cap 

One diffusive sampling cap is required per 

PS tube. The cap fits onto the sampling end 

of the tube during air monitoring. The other 

end of the tube remains sealed with the longterm storage cap. Each diffusive sampling cap 

is fitted with a stainless steel gauze, which 

defines the outer limit of the diffusion air 

gap. 

6.3 Sorbent Tube Protection Cover 

A simple weatherproof hood, suitable for 

protecting passive sampling tubes from the 

worst of the weather (see Section 4.4) 

consists of an inverted cone/funnel 

constructed of an inert, non-outgassing 

material that fits over the diffusive tube, with 

the open (sampling) end of the tube 

projecting just below the cone opening. An 

example is shown in Figure 6.1 (Adapted 

from Reference 13). 


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Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75327 

6.4 Thermal Desorption Apparatus 

If the analytical thermal desorber that will 

subsequently be used to analyze the passive 

sampling tubes does not meet the 

requirement to exclude outer surface 

contaminants from the sample flow path (see 

Section 6.6 of Method 325B), then clean, 

white, cotton or powder-free nitrile gloves 

must be used for handling the passive 

sampling tubes during field deployment. 

6.5 Sorbent Selection 

Sorbent tube configurations, sorbents or 

other VOC not listed in this method must be 

evaluated according to Method 325B, 

Addendum A or ISO 16017–2:2003(E) 

(Reference 13) (incorporated by reference— 

see § 63.14). The supporting evaluation and 

verification data described in Method 325B, 

Addendum A for configurations or 

compounds different from the ones described 

in this method must meet the performance 

requirements of Method 325A/B and must be 

submitted with the test plan for your 

measurement program. 

7.0 Reagents and Standards 

No reagents or standards are needed for the 

field deployment and collection of passive 

sampling tubes. Specifications for sorbents, 

gas and liquid phase standards, preloaded 

standard tubes, and carrier gases are covered 

in Section 7 of Method 325B. 

8.0 Sample Deployment, Recovery, and 

Storage 

Pre-deployment and planning steps are 

required before field deployment of passive 

sampling tubes. These activities include but 

are not limited to conducting a site visit, 

determining suitable and required 

monitoring locations, and determining the 

monitoring frequency to be used. 

8.1 Conducting the Site Visit 

8.1.1 Determine the size and shape of the 

facility footprint in order to determine the 

required number of monitoring locations. 

8.1.2 Identify obstacles or obstructions 

(buildings, roads, fences), hills and other 

terrain issues (e.g., bodies of water or swamp 

land) that could interfere with air parcel flow 

to the sampler or that prevent reasonable 

access to the location. You may use the 

general guidance in Section 4.1 of this 

method during the site visit to identify 

sampling locations. You must evaluate the 

placement of each passive sampler to 

determine if the conditions in this section are 

met. 

8.1.3 Identify to the extent possible and 

record potential off-site source interferences 

(e.g., neighboring industrial facilities, 

transportation facilities, fueling operations, 

combustion sources, short-term transient 

sources, residential sources, nearby 

highways). 

8.1.4 Identify the closest available 

meteorological station. Identify potential 

locations for one or more on-site or near-site 

meteorological station(s) following the 

guidance in EPA–454/B–08–002 (Reference 

11) (incorporated by reference—see § 63.14). 

8.2 Determining Sampling Locations 

(References 2, 3) 

8.2.1 The number and placement of the 

passive samplers depends on the size, the 

shape of the facility footprint or the linear 

distance around the facility, and the 

proximity of emission sources near the 

property boundaries. Aerial photographs or 

site maps may be used to determine the size 

(acreage) and shape of the facility or the 

length of the monitoring perimeter. Place 

passive samplers on an internal monitoring 

perimeter on or inside the facility boundary 

encompassing all emission sources at the 

facility at different angles circling the 

geometric center of the facility or at different 

distances based on the monitoring perimeter 

length of the facility. 

Note: In some instances, permanent air 

monitoring stations may already be located in 

close proximity to the facility. These stations 

may be operated and maintained by the site, 

or local or state regulatory agencies. If access 

to the station is possible, a PS may be 

deployed adjacent to other air monitoring 

instrumentation. A comparison of the 

pollutant concentrations measured with the 

PS to concentrations measured by site 

instrumentation may be used as an optional 

data quality indicator to assess the accuracy 

of PS results. 

8.2.1.1 The monitoring perimeter may be 

located between the property boundary and 

any potential emission source near the 

property boundary, as long as the distance 

from the source to the monitoring perimeter 

is at least 50 meters (162 feet). If a potential 

emissions source is within 50 meters (162 

feet) of the property boundary, the property 

boundary shall be used as the monitoring 

perimeter near that source. 

8.2.1.2 Samplers need only be placed 

around the monitoring perimeter and not 

along internal roads or other right of ways 

that may bisect the facility. 

8.2.1.3 Extra samplers must be placed 

near known sources of VOCs if the potential 

emission source is within 50 meters (162 

feet) of the boundary and the source location 

is between two monitors. Measure the 

distance (x) between the two monitors and 

place another monitor halfway between (x/2) 

the two monitors. For example, in Figure 8.1, 

the facility added three additional monitors 

(i.e., light shaded sampler locations) and in 

Figure 8.2, the facility added two additional 

monitors to provide sufficient coverage of all 

area sources. 

BILLING CODE 6560–50–P 


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8.2.2 Option 1 for Determining Sampling 

Locations. 

8.2.2.1 For facilities with a regular 

(circular, triangular, rectangular, or square) 

shape, determine the geographic center of the 

facility. 


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Refinery (20% Angle) 

Note: Shaded sources are within 50 meters of the property boundary 

and are located between two monitors. Additional coverage required 

by this method was accomplished by placing the monitors halfway 

between two existing monitors. 

Figure 8.1. Facility with a Regular Shape Between 750 and 1,500 

Acres in Area 

(f) 

(f) 

(f) 

(f) 

(f) 

Refinery (24,000 Feet Perimeter) 

Note: Shaded sources are within 50 meters of the property boundary 

and are located between two monitors. Additional coverqe required 

by this method was accomplished by placing the monitors halfway 

between two existing monitors. 

Figure 8.2. Facility with a Boundary Length of 24,000 feet 
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8.2.2.1.1 For facilities with an area of less 

than or equal to 750 acres, measure angles of 

30 degrees from the center point for a total 

of twelve 30 degree measurements evenly 

spaced (±1 degree). 

8.2.2.1.2 For facilities covering an area 

greater than 750 acres but less than or equal 

to 1,500 acres, measure angles of 20 degrees 

from the center point for a total of eighteen 

20 degree measurements evenly spaced (±1 

degree). Figure 8.1 shows the monitor 

placement around the property boundary of 

a facility with an area between 750 and 1,500 

acres. Monitor placements are represented 

with black dots along the property boundary. 

8.2.2.1.3 For facilities covering an area 

greater than 1,500 acres, measure angles of 15 

degrees from the center point for a total of 

twenty-four 15 degree measurements evenly 

spaced (±1 degree). 

8.2.2.1.4 Locate each sampling point 

where the measured angle intersects the 

outer monitoring perimeter. 

8.2.2.2 For irregularly shaped facilities, 

divide the area into a set of connecting 

subarea circles, triangles or rectangles to 

determine sampling locations. The subareas 

must be defined such that a circle can 

reasonably encompass the subarea. Then 

determine the geometric center point of each 

of the subareas. 

8.2.2.2.1 If a subarea is less than or equal 

to 750 acres (e.g., Figure 8.3), measure angles 

of 30 degrees from the center point for a total 

of twelve 30 degree measurements (±1 

degree). 

8.2.2.2.2 If a subarea is greater than 750 

acres but less than or equal to 1,500 acres 

(e.g., Figure 8.4), measure angles of 20 

degrees from the center point for a total of 

eighteen 20 degree measurements (±1 

degree). 

8.2.2.2.3 If a subarea is greater than 1,500 

acres, measure angles of 15 degrees from the 

center for a total of twenty-four 15 degree 

measurements (±1 degree). 

8.2.2.2.4 Locate each sampling point 

where the measured angle intersects the 

outer monitoring perimeter. Sampling points 

need not be placed closer than 152 meters 

(500 feet) apart (or 76 meters (250 feet) if 

known sources are within 50 meters (162 

feet) of the monitoring perimeter), as long as 

a minimum of 3 monitoring locations are 

used for each subarea. 

8.2.2.2.5 Sampling sites are not needed at 

the intersection of an inner boundary with an 

adjacent subarea. The sampling location must 

be sited where the measured angle intersects 

the subarea’s outer monitoring perimeter. 


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8.2.3 Option 2 for Determining Sampling 

Locations. 

8.2.3.1 For facilities with a monitoring 

perimeter length of less than 7,315 meters 

(24,000 feet), a minimum of twelve sampling 

locations evenly spaced ±10 percent of the 

location interval is required. 

8.2.3.2 For facilities with a monitoring 

perimeter length greater than 7,315 meters 

(24,000 feet), sampling locations are spaced 

610 ±76 meters (2,000 ± 250 feet) apart. 

8.3 Siting a Meteorological Station 

A meteorological station is required at or 

near the facility you are monitoring. A 

number of commercially available 

meteorological stations can be used. 

Information on meteorological instruments 

can be found in EPA–454/R–99–005 

(Reference 11) (incorporated by reference— 

see § 63.14). Some important considerations 

for siting of meteorological stations are 

detailed below. 

8.3.1 Place meteorological stations in 

locations that represent conditions affecting 

the transport and dispersion of pollutants in 

the area of interest. Complex terrain may 

require the use of more than one 

meteorological station. 

8.3.2 Deploy wind instruments over level, 

open terrain at a height of 10 meters (33 feet). 

If possible, locate wind instruments at a 

distance away from nearby structures that is 

equal to at least 10 times the height of the 

structure. 

8.3.3 Protect meteorological instruments 

from thermal radiation and adequately 

ventilate them using aspirated shields. The 

temperature sensor must be located at a 

distance away from any nearby structures 

that is equal to at least four times the height 

of the structure. Temperature sensors must be 

located at least 30 meters (98 feet) from large 

paved areas. 

8.3.4 Collect and record meteorological 

data, including wind speed, wind direction, 

temperature and barometric pressure on an 

hourly basis. Calculate average unit vector 

wind direction, sigma theta, temperature and 

barometric pressure per sampling period to 

enable calculation of concentrations at 

standard conditions. Supply this information 

to the laboratory. 

8.3.5 Identify and record the location of 

the meteorological station by its GPS 

coordinate. 

8.4 Monitoring Frequency 

8.4.1 Sample collection may be 

performed for periods up to 14 days. 

8.4.2 A site screening protocol that meets 

method requirements may be performed by 

collecting samples for a year where each PS 

accumulates VOC for a 14-day sampling 

period. Study results are accumulated for the 

sampling periods (typically 26) over the 

course of one calendar year. To the extent 

practical, sampling tubes should be changed 

at approximately the same time of day at 

each of the monitoring sites. 

8.5 Passive Sampler Deployment 

8.5.1 Clean (conditioned) sorbent tubes 

must be prepared and packaged by the 

laboratory as described in Method 325B and 

must be deployed for sampling within 30 

days of conditioning. 

8.5.2 Allow the tubes to equilibrate with 

ambient temperature (approximately 30 

minutes to 1 hour) at the monitoring location 

before removing them from their storage/

shipping container for sample collection. 

8.5.3 If there is any risk that the 

analytical equipment will not meet the 

requirement to exclude contamination on 

outer tube surfaces from the sample flow 

path (see Section 6.6 of Method 325B), 

sample handlers must wear clean, white, 

cotton or powder-free nitrile gloves during 

PS deployment and collection and 

throughout any other tube handling 

operations. 

8.5.4 Inspect the sampling tubes 

immediately prior to deployment. Ensure 

that they are intact, securely capped, and in 

good condition. Any suspect tubes (e.g., 

tubes that appear to have leaked sorbent) 

should be removed from the sampling set. 

8.5.5 Secure passive samplers so the 

bottom of the diffusive sampling cap is 1.5 

to 3 meters (4.9 to 9.8 feet) above ground 

using a pole or other secure structure at each 

sampling location. Orient the PS vertically 

and with the sampling end pointing 

downward to avoid ingress of particulates. 

Note: Duplicate sampling assemblies must 

be deployed in at least one monitoring 

location for every 10 monitoring locations 

during each field monitoring period. 

8.5.6 Protect the PS from rain and 

excessive wind velocity by placing them 

under the type of protective hood described 

in Section 6.1.3 or equivalent. 

8.5.7 Remove the storage cap on the 

sampling end of the tube and replace it with 

a diffusive sampling cap at the start of the 

sampling period. Make sure the diffusion cap 

is properly seated and store the removed 

storage caps in the empty tube shipping 

container. 

8.5.8 Record the start time and location 

details for each sampler on the field sample 

data sheet (see example in Section 17.0.). 


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8.5.9 Expose the sampling tubes for the 

required sampling period-normally 14-days. 

8.5.10 Field blank tubes (see Section 9.3 

of Method 325B) are stored outside the 

shipping container at representative 

sampling locations around the site, but with 

both long-term storage caps kept in place 

throughout the monitoring exercise. Collect 

at least two field blanks sorbent samples per 

sampling period to ensure sample integrity 

associated with shipment, collection, and 

storage. 

8.6 Sorbent Tube Recovery and 

Meteorological Data Collection 

Recover deployed sampling tubes and field 

blanks as follows: 

8.6.1 After the sampling period is 

complete, immediately replace the diffusion 

end cap on each sampled tube with a longterm storage end cap. Tighten the seal 

securely by hand and then tighten an 

additional quarter turn with an appropriate 

tool. Record the stop date and time and any 

additional relevant information on the 

sample data sheet. 

8.6.2 Place the sampled tubes, together 

with the field blanks, in the storage/shipping 

container. Label the storage container, but do 

not use paints, markers, or adhesive labels to 

identify the tubes. TD-compatible electronic 

(radio frequency identification (RFID)) tube 

labels are available commercially and are 

compatible with some brands of thermal 

desorber. If used, these may be programmed 

with relevant tube and sample information, 

which can be read and automatically 

transcribed into the sequence report by the 

TD system. 

Note: Sampled tubes must not be placed in 

the same shipping container as clean 

conditioned sampling tubes. 

8.6.3 Sampled tubes may be shipped at 

ambient temperature to a laboratory for 

sample analysis. 

8.6.4 Specify whether the tubes are field 

blanks or were used for sampling and 

document relevant information for each tube 

using a Chain of Custody form (see example 

in Section 17.0) that accompanies the 

samples from preparation of the tubes 

through receipt for analysis, including the 

following information: Unique tube 

identification numbers for each sampled 

tube; the date, time, and location code for 

each PS placement; the date, time, and 

location code for each PS recovery; the GPS 

reference for each sampling location; the 

unique identification number of the 

duplicate sample (if applicable); and 

problems or anomalies encountered. 

8.6.5 If the sorbent tubes are supplied 

with electronic (e.g., RFID) tags, it is also 

possible to allocate a sample identifier to 

each PS tube. In this case, the recommended 

format for the identification number of each 

sampled tube is AA–BB–CC–DD–VOC, 

where: 

AA = Sequence number of placement on 

route (01, 02, 03 . . .) 

BB = Sampling location code (01, 02, 

03 . . .) 

CC = 14-day sample period number (01 to 26) 

DD = Sample code (SA = sample, DU = 

duplicate, FB = field blank) 

VOC = 3-letter code for target compound(s) 

(e.g., BNZ for benzene or BTX for 

benzene, toluene, and xylenes) 

Note: Sampling start and end times/dates 

can also be logged using RFID tube tags. 

9.0 Quality Control 

9.1 Most quality control checks are 

carried out by the laboratory and associated 

requirements are in Section 9.0 of Method 

325B, including requirements for laboratory 

blanks, field blanks, and duplicate samples. 

9.2 Evaluate for potential outliers the 

laboratory results for neighboring sampling 

tubes collected over the same time period. A 

potential outlier is a result for which one or 

more PS tube does not agree with the trend 

in results shown by neighboring PS tubes— 

particularly when data from those locations 

have been more consistent during previous 

sampling periods. Accidental contamination 

by the sample handler must be documented 

before any result can be eliminated as an 

outlier. Rare but possible examples of 

contamination include loose or missing 

storage caps or contaminated storage/

shipping containers. Review data from the 

same and neighboring monitoring locations 

for the subsequent sampling periods. If the 

anomalous result is not repeated for that 

monitoring location, the episode can be 

ascribed to transient contamination and the 

data in question must be flagged for potential 

elimination from the dataset. 

9.3 Duplicates and Field Blanks 

9.3.1 Collect at least one co-located/

duplicate sample for every 10 field samples 

to determine precision of the measurements. 

9.3.2 Collect at least two field blanks 

sorbent samples per sampling period to 

ensure sample integrity associated with 

shipment, collection, and storage. You must 

use the entire sampling apparatus for field 

blanks including unopened sorbent tubes 

mounted in protective sampling hoods. The 

tube closures must not be removed. Field 

blanks must be placed in two different 

quadrants (e.g., 90° and 270°) and remain at 

the sampling location for the sampling 

period. 

10.0 Calibration and Standardization 

Follow the calibration and standardization 

procedures for meteorological measurements 

in EPA–454/B–08–002 March 2008 

(Reference 11) (incorporated by reference— 

see § 63.14). Refer to Method 325B for 

calibration and standardization procedures 

for analysis of the passive sampling tubes. 

11.0 Analytical Procedures 

Refer to Method 325B, which provides 

details for the preparation and analysis of 

sampled passive monitoring tubes 

(preparation of sampling tubes, shipment and 

storage of exposed sampling tubes, and 

analysis of sampling tubes). 

12.0 Data Analysis, Calculations and 

Documentation 

12.1 Calculate Annual Average Fenceline 

Concentration. 

After a year’s worth of sampling at the 

facility fenceline (for example, 26 14-day 

samples), the average (PSi) may be calculated 

for any specified period at each PS location 

using Equation 12.1. 

Where: 

PSi = Annual average for location i. 

PSip = Sampling period specific 

concentration from Method 325B. 

i = Location of passive sampler (0 to 360°). 

p = The sampling period. 

N = The number of sampling periods in the 

year (e.g., for 14-day sampling periods, 

from 1 to 26). 

Note: PSip is a function of sampling 

location-specific factors such as the 

contribution from facility sources, unusual 

localized meteorological conditions, 

contribution from nearby interfering sources, 

the background caused by integrated far-field 

sources and measurement error due to 

deployment, handling, siting, or analytical 

errors. 

12.2 Identify Sampling Locations of 

Interest 

If data from neighboring sampling 

locations are significantly different, then you 

may add extra sampling points to isolate 

background contributions or identify facilityspecific ‘‘hot spots.’’ 

12.3 Evaluate Trends 

You may evaluate trends and patterns in 

the PS data over multiple sampling periods 

to determine if elevated concentrations of 

target compounds are due to operations on 

the facility or if contributions from 

background sources are significant. 

12.3.1 Obtain meteorological data 

including wind speed and wind direction or 

unit vector wind data from the on-site 

meteorological station. Use this 

meteorological data to determine the 

prevailing wind direction and speed during 

the periods of elevated concentrations. 

12.3.2 As an option you may perform 

preliminary back trajectory calculations 

(http://ready.arl.noaa.gov/HYSPLIT.php) to 

aid in identifying the source of the 

background contribution to elevated target 

compound concentrations. 


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12.3.3 Information on published or 

documented events on- and off-site may also 

be included in the associated sampling 

period report to explain elevated 

concentrations if relevant. For example, you 

would describe if there was a chemical spill 

on site, or an accident on an adjacent road. 

12.3.4 Additional monitoring for shorter 

periods (See section 8.4) may be necessary to 

allow better discrimination/resolution of 

contributing emission sources if the 

measured trends and associated meteorology 

do not provide a clear assessment of facility 

contribution to the measured fenceline 

concentration. 

12.3.5 Additional records necessary to 

calculate sampling period average target 

compound concentration can be found in 

Section 12.1 of Method 325B. 

13.0 Method Performance 

Method performance requirements are 

described in Method 325B. 

14.0 Pollution Prevention 

[Reserved] 

15.0 Waste Management 

[Reserved] 

16.0 References 

1. Ambient air quality—Standard method for 

measurement of benzene 

concentrations—Part 4: Diffusive 

sampling followed by thermal desorption 

and gas chromatography, BS EN 14662– 

4:2005. 

2. Thoma, E.D., Miller, C.M., Chung, K.C., 

Parsons, N.L. and Shine, B.C. Facility 

Fence Line Monitoring using Passive 

Samplers, J. Air & Waste Mange. Assoc. 

2011, 61:834–842. 

3. Quality Assurance Handbook for Air 

Pollution C Systems, Volume II: Ambient 

Air Quality Monitoring Program, EPA– 

454/B–13–003, May 2013. Available at 

http://www.epa.gov/ttnamti1/files/

ambient/pm25/qa/QA-Handbook-VolII.pdf. 

4. Brown, R.H., Charlton, J. and Saunders, 

K.J.: The development of an improved 

diffusive sampler. Am. Ind. Hyg. Assoc. 

J. 1981, 42(12): 865–869. 

5. Brown, R. H. Environmental use of 

diffusive samplers: evaluation of reliable 

diffusive uptake rates for benzene, 

toluene and xylene. J. Environ. Monit. 

1999, 1 (1), 115–116. 

6. Ballach, J.; Greuter, B.; Schultz, E.; 

Jaeschke, W. Variations of uptake rates in 

benzene diffusive sampling as a function 

of ambient conditions. Sci. Total 

Environ. 1999, 244, 203–217. 

7. Brown, R. H. Monitoring the ambient 

environment with diffusive samplers: 

theory and practical considerations. J 

Environ. Monit. 2000, 2 (1), 1–9. 

8. Buzica, D.; Gerboles, M.; Plaisance, H. The 

equivalence of diffusive samplers to 

reference methods for monitoring O3, 

benzene and NO2 in ambient air. J. 

Environ. Monit. 2008, 10 (9), 1052–1059. 

9. Woolfenden, E. Sorbent-based sampling 

methods for volatile and semi-volatile 

organic compounds in air. Part 2. 

Sorbent selection and other aspects of 

optimizing air monitoring methods. J. 

Chromatogr. A 2010, 1217, (16), 2685– 

94. 

10. Pfeffer, H. U.; Breuer, L. BTX 

measurements with diffusive samplers in 

the vicinity of a cokery: Comparison 

between ORSA-type samplers and 

pumped sampling. J. Environ. Monit. 

2000, 2 (5), 483–486. 

11. US EPA. 2000. Meteorological Monitoring 

Guidance for Regulatory Modeling 

Applications. EPA–454/R–99–005. Office 

of Air Quality Planning and Standards, 

Research Triangle Park, NC. February 

2000. Available at http://www.epa.gov/

scram001/guidance/met/mmgrma.pdf. 

12. Quality Assurance Handbook for Air 

Pollution Measurement Systems. Volume 

IV: Meteorological Measurements 

Version 2.0 Final, EPA–454/B–08–002 

March 2008. Available at http://www.

epa.gov/ttnamti1/files/ambient/met/

Volume%20IV_Meteorological_

Measurements.pdf. 

13. ISO 16017–2:2003(E), Indoor, ambient 

and workplace air—Sampling and 

analysis of volatile organic compounds 

by sorbent tube/thermal desorption/

capillary gas chromatography. Part 2: 

Diffusive sampling. 

14. ASTM D6196–03 (Reapproved 2009): 

Standard practice for selection of 

sorbents, sampling, and thermal 

desorption analysis procedures for 

volatile organic compounds in air. 

17.0 Tables, Diagrams, Flowcharts and 

Validation Data 


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Method 325 A/B 

EXAMPLE FIELD TEST DATA SHEET (FTDS) 

AND 

CHAIN OF CUSTODY 

I. GENERAL INFORMATION 

SITE NAME: 

SITE LOCATION ADDRESS: 

CITY: STATE: ZIP: 

II. SAMPLING DATA 

Sample Ambient ID Sample Barometric 

(Tube) or Start Start Stop Stop Location Temp. Pressure 

# Sorbent blank Date Time Date Time (gps) (oF) (in. Hg) 

III. CUSTODY INFORMATION 

COLLECTED BY: 

Relinquished to Shipper -

Name: Date: Time 

Received by Laboratory -

Name Date: Time 

Sample condition upon receipt: 

Analysis Required: 

Comments: 

Figure 17.1. Example Field Data Form and Chain of Custody 
75334 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

Method 325B—Volatile Organic Compounds 

from Fugitive and Area Sources: 

Sampler Preparation and Analysis 

1.0 Scope and Application 

1.1 This method describes thermal 

desorption/gas chromatography (TD/GC) 

analysis of volatile organic compounds 

(VOCs) from fugitive and area emission 

sources collected onto sorbent tubes using 

passive sampling. It could also be applied to 

the TD/GC analysis of VOCs collected using 

active (pumped) sampling onto sorbent tubes. 

The concentration of airborne VOCs at or 

near potential fugitive- or area-emission 

sources may be determined using this 

method in combination with Method 325A. 

Companion Method 325A (Sampler 

Deployment and VOC Sample Collection) 

describes procedures for deploying the 

sorbent tubes and passively collecting VOCs. 

1.2 The preferred GC detector for this 

method is a mass spectrometer (MS), but 

flame ionization detectors (FID) may also be 

used. Other conventional GC detectors such 

as electron capture (ECD), photoionization 

(PID), or flame photometric (FPD) may also 

be used if they are selective and sensitive to 

the target compound(s) and if they meet the 

method performance criteria provided in this 

method. 

1.3 There are 97 VOCs listed as 

hazardous air pollutants in Title III of the 

Clean Air Act Amendments of 1990. Many of 

these VOC are candidate compounds for this 

method. Compounds with known uptake 

rates for CarbographTM 1 TD, CarbopackTM B, 

or CarbopackTM X are listed in Table 12.1. 

This method provides performance criteria to 

demonstrate acceptable performance of the 

method (or modifications of the method) for 

monitoring one or more of the compounds 

listed Table 12.1. If standard passive 

sampling tubes are packed with other 

sorbents or used for other analytes than those 

listed in Table 12.1, then method 

performance and relevant uptake rates 

should be verified according to Addendum A 

to this method or by one of the following 

national/international standard methods: ISO 

16017–2:2003(E), ASTM D6196–03 

(Reapproved 2009), or BS EN 14662–4:2005 

(all incorporated by reference—see § 63.14), 

or reported in the peer-reviewed open 

literature. 

1.4 The analytical approach using TD/

GC/MS is based on previously published 

EPA guidance in Compendium Method TO– 

17 (http://www.epa.gov/ttnamti1/airtox.

html#compendium) (Reference 1), which 

describes active (pumped) sampling of VOCs 

from ambient air onto tubes packed with 

thermally stable adsorbents. 

1.5 Inorganic gases not suitable for 

analysis by this method include oxides of 

carbon, nitrogen and sulfur, ozone (O3), and 

other diatomic permanent gases. Other 

pollutants not suitable for this analysis 

method include particulate pollutants, (i.e., 

fumes, aerosols, and dusts), compounds too 

labile (reactive) for conventional GC analysis, 

and VOCs that are more volatile than 

propane. 

2.0 Summary of Method 

2.1 This method provides procedures for 

the preparation, conditioning, blanking, and 

shipping of sorbent tubes prior to sample 

collection. 

2.2 Laboratory and field personnel must 

have experience of sampling trace-level 

VOCs using sorbent tubes (References 2,5) 

and must have experience operating thermal 

desorption/GC/multi-detector 

instrumentation. 

2.3 Key steps of this method as 

implemented for each sample tube include: 

Stringent leak testing under stop flow, 

recording ambient temperature conditions, 

adding internal standards, purging the tube, 

thermally desorbing the sampling tube, 

refocusing on a focusing trap, desorbing and 

transferring/injecting the VOCs from the 

secondary trap into the capillary GC column 

for separation and analysis. 

2.4 Water management steps incorporated 

into this method include: (a) Selection of 

hydrophobic sorbents in the sampling tube; 

(b) optional dry purging of sample tubes prior 

to analysis; and (c) additional selective 

elimination of water during primary (tube) 

desorption (if required) by selecting trapping 

sorbents and temperatures such that target 

compounds are quantitatively retained while 

water is purged to vent. 

3.0 Definitions 

(See also Section 3.0 of Method 325A). 

3.1 Blanking is the desorption and 

confirmatory analysis of conditioned sorbent 

tubes before they are sent for field sampling. 

3.2 Breakthrough volume and associated 

relation to passive sampling. Breakthrough 

volumes, as applied to active sorbent tube 

sampling, equate to the volume of air 

containing a constant concentration of 

analyte that may be passed through a sorbent 

tube at a given temperature before a 

detectable level (5 percent) of the input 

analyte concentration elutes from the tube. 

Although breakthrough volumes are directly 

related to active rather than passive 

sampling, they provide a measure of the 

strength of the sorbent-sorbate interaction 

and therefore also relate to the efficiency of 

the passive sampling process. The best direct 

measure of passive sampling efficiency is the 

stability of the uptake rate. Quantitative 

passive sampling is compromised when the 

sorbent no longer acts as a perfect sink—i.e., 

when the concentration of a target analyte 

immediately above the sorbent sampling 

surface no longer approximates to zero. This 

causes a reduction in the uptake rate over 

time. If the uptake rate for a given analyte on 

a given sorbent tube remains relatively 

constant —i.e., if the uptake rate determined 

for 48 hours is similar to that determined for 

7 or 14 days—the user can be confident that 

passive sampling is occurring at a constant 

rate. As a general rule of thumb, such ideal 

passive sampling conditions typically exist 

for analyte:sorbent combinations where the 

breakthrough volume exceeds 100 L 

(Reference 4). 

3.3 Continuing calibration verification 

sample (CCV). Single level calibration 

samples run periodically to confirm that the 

analytical system continues to generate 

sample results within acceptable agreement 

to the current calibration curve. 

3.4 Focusing trap is a cooled, secondary 

sorbent trap integrated into the analytical 

thermal desorber. It typically has a smaller 

i.d. and lower thermal mass than the original 

sample tube allowing it to effectively refocus 

desorbed analytes and then heat rapidly to 

ensure efficient transfer/injection into the 

capillary GC analytical column. 

3.5 High Resolution Capillary Column 

Chromatography uses fused silica capillary 

columns with an inner diameter of 320 mm 

or less and with a stationary phase film 

thickness of 5 mm or less. 

3.6 h is time in hours. 

3.7 i.d. is inner diameter. 

3.8 min is time in minutes. 

3.9 Method Detection Limit is the lowest 

level of analyte that can be detected in the 

sample matrix with 99% confidence. 

3.10 MS–SCAN is the mode of operation 

of a GC quadrupole mass spectrometer 

detector that measures all ions over a given 

mass range over a given period of time. 

3.11 MS–SIM is the mode of operation of 

a GC quadrupole mass spectrometer detector 

that measures only a single ion or a selected 

number of discrete ions for each analyte. 

3.12 o.d. is outer diameter. 

3.13 ppbv is parts per billion by volume. 

3.14 Thermal desorption is the use of 

heat and a flow of inert (carrier) gas to extract 

volatiles from a solid matrix. No solvent is 

required. 

3.15 Total ion chromatogram is the 

chromatogram produced from a mass 

spectrometer detector collecting full spectral 

information. 

3.16 Two-stage thermal desorption is the 

process of thermally desorbing analytes from 

a sorbent tube, reconcentrating them on a 

focusing trap (see Section 3.4), which is then 

itself rapidly heated to ‘‘inject’’ the 

concentrated compounds into the GC 

analyzer. 

3.17 VOC is volatile organic compound. 

4.0 Analytical Interferences 

4.1 Interference from Sorbent Artifacts. 

Artifacts may include target analytes as well 

as other VOC that co-elute 

chromatographically with the compounds of 

interest or otherwise interfere with the 

identification or quantitation of target 

analytes. 

4.1.1 Sorbent decomposition artifacts are 

VOCs that form when sorbents degenerate, 

e.g., when exposed to reactive species during 

sampling. For example, benzaldehyde, 

phenol, and acetophenone artifacts are 

reported to be formed via oxidation of the 

polymeric sorbent Tenax® when sampling 

high concentration (100–500 ppb) ozone 

atmospheres (Reference 5). 

4.1.2 Preparation and storage artifacts are 

VOCs that were not completely cleaned from 

the sorbent tube during conditioning or that 

are an inherent feature of that sorbent at a 

given temperature. 

4.2 Humidity. Moisture captured during 

sampling can interfere with VOC analysis. 

Passive sampling using tubes packed with 

hydrophobic sorbents, like those described in 

this method, minimizes water retention. 

However, if water interference is found to be 

an issue under extreme conditions, one or 

more of the water management steps 

described in Section 2.4 can be applied. 

4.3 Contamination from Sample 

Handling. The type of analytical thermal 


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desorption equipment selected should 

exclude the possibility of outer tube surface 

contamination entering the sample flow path 

(see Section 6.6). If the available system does 

not meet this requirement, sampling tubes 

and caps must be handled only while 

wearing clean, white cotton or powder free 

nitrile gloves to prevent contamination with 

body oils, hand lotions, perfumes, etc. 

5.0 Safety 

5.1 This method does not address all of 

the safety concerns associated with its use. It 

is the responsibility of the user of this 

standard to establish appropriate field and 

laboratory safety and health practices prior to 

use. 

5.2 Laboratory analysts must exercise 

extreme care in working with high-pressure 

gas cylinders. 

5.3 Due to the high temperatures 

involved, operators must use caution when 

conditioning and analyzing tubes. 

6.0 Equipment and Supplies 

6.1 Tube Dimensions and Materials. The 

sampling tubes for this method are 3.5-inches 

(89 mm) long, 1⁄4 inch (6.4 mm) o.d., and 5 

mm i.d. passive sampling tubes (see Figure 

6.1). The tubes are made of inert-coated 

stainless steel with the central section (up to 

60 mm) packed with sorbent, typically 

supported between two 100 mesh stainless 

steel gauze. The tubes have a cross sectional 

area of 19.6 square mm (5 mm i.d.). When 

used for passive sampling, these tubes have 

an internal diffusion (air) gap (DG) of 1.5 cm 

between the sorbent retaining gauze at the 

sampling end of the tube, and the gauze in 

the diffusion cap. 

6.2 Tube Conditioning Apparatus 

6.2.1 Freshly packed or newly purchased 

tubes must be conditioned as described in 

Section 9 using an appropriate dedicated 

tube conditioning unit or the thermal 

desorber. Note that the analytical TD system 

should be used for tube conditioning if it 

supports a dedicated tube conditioning mode 

in which effluent from contaminated tubes is 

directed to vent without passing through key 

parts of the sample flow path such as the 

focusing trap. 

6.2.2 Dedicated tube conditioning units 

must be leak-tight to prevent air ingress, 

allow precise and reproducible temperature 

selection (±5 °C), offer a temperature range at 

least as great as that of the thermal desorber, 

and support inert gas flows in the range up 

to 100 mL/min. 

Note: For safety and to avoid laboratory 

contamination, effluent gases from freshly 

packed or highly contaminated tubes should 

be passed through a charcoal filter during the 

conditioning process to prevent desorbed 

VOCs from polluting the laboratory 

atmosphere. 

6.3 Tube Labeling 

6.3.1 Label the sample tubes with a 

unique permanent identification number and 

an indication of the sampling end of the tube. 

Labeling options include etching and TDcompatible electronic (radio frequency 

identification (RFID)) tube labels. 

6.3.2 To avoid contamination, do not 

make ink markings of any kind on clean 

sorbent tubes or apply adhesive labels. 

Note: TD-compatible electronic (RFID) tube 

labels are available commercially and are 

compatible with some brands of thermal 

desorber. If used, these may be programmed 

with relevant tube and sample information, 

which can be read and automatically 

transcribed into the sequence report by the 

TD system (see Section 8.6 of Method 325A). 

6.4 Blank and Sampled Tube Storage 

Apparatus 

6.4.1 Long-term storage caps. Seal clean, 

blank and sampled sorbent tubes using inert, 

long-term tube storage caps comprising nongreased, 2-piece, 0.25-inch, metal 

SwageLok®-type screw caps fitted with 

combined polytetrafluoroethylene ferrules. 

6.4.2 Storage and transportation 

containers. Use clean glass jars, metal cans or 

rigid, non-emitting polymer boxes. 

Note: You may add a small packet of new 

activated charcoal or charcoal/silica gel to 

the shipping container for storage and 

transportation of batches of conditioned 

sorbent tubes prior to use. Coolers without 

ice packs make suitable shipping boxes for 

containers of tubes because the coolers help 

to insulate the samples from extreme 

temperatures (e.g., if left in a parked vehicle). 

6.5 Unheated GC Injection Unit for Loading 

Standards Onto Blank Tubes 

A suitable device has a simple push fit or 

finger-tightening connector for attaching the 

sampling end of blank sorbent tubes without 

damaging the tube. It also has a means of 

controlling carrier gas flow through the 

injector and attached sorbent tube at 50–100 

mL/min and includes a low emission septum 

cap that allows the introduction of gas or 

liquid standards via appropriate syringes. 

Reproducible and quantitative transfer of 

higher boiling compounds in liquid 

standards is facilitated if the injection unit 

allows the tip of the syringe to just touch the 

sorbent retaining gauze inside the tube. 

6.6 Thermal Desorption Apparatus 

The manual or automated thermal 

desorption system must heat sorbent tubes 

while a controlled flow of inert (carrier) gas 

passes through the tube and out of the 

sampling end. The apparatus must also 

incorporate a focusing trap to quantitatively 

refocus compounds desorbed from the tube. 

Secondary desorption of the focusing trap 

should be fast/efficient enough to transfer the 

compounds into the high resolution capillary 

GC column without band broadening and 

without any need for further pre- or oncolumn focusing. Typical TD focusing traps 

comprise small sorbent traps (Reference 16) 

that are electrically-cooled using multistage 

Peltier cells (References 17, 18). The 

direction of gas flow during trap desorption 

should be the reverse of that used for 

focusing to extend the compatible analyte 

volatility range. Closed cycle coolers offer 

another cryogen-free trap cooling option. 

Other TD system requirements and 

operational stages are described in Section 11 

and in Figures 17–2 through 17–4. 

6.7 Thermal Desorber—GC Interface 

6.7.1 The interface between the thermal 

desorber and the GC must be heated 

uniformly and the connection between the 

transfer line insert and the capillary GC 

analytical column itself must be leak tight. 

6.7.2 A portion of capillary column can 

alternatively be threaded through the heated 

transfer line/TD interface and connected 

directly to the thermal desorber. 

Note: Use of a metal syringe-type needle or 

unheated length of fused silica pushed 

through the septum of a conventional GC 


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injector is not permitted as a means of 

interfacing the thermal desorber to the 

chromatograph. Such connections result in 

cold spots, cause band broadening and are 

prone to leaks. 

6.8 GC/MS Analytical Components 

6.8.1 The GC system must be capable of 

temperature programming and operation of a 

high resolution capillary column. Depending 

on the choice of column (e.g., film thickness) 

and the volatility of the target compounds, it 

may be necessary to cool the GC oven to 

subambient temperatures (e.g., ¥50 °C) at the 

start of the run to allow resolution of very 

volatile organic compounds. 

6.8.2 All carrier gas lines supplying the 

GC must be constructed from clean stainless 

steel or copper tubing. Nonpolytetrafluoroethylene thread sealants. Flow 

controllers, cylinder regulators, or other 

pneumatic components fitted with rubber 

components are not suitable. 

6.9 Chromatographic Columns 

High-resolution, fused silica or equivalent 

capillary columns that provide adequate 

separation of sample components to permit 

identification and quantitation of target 

compounds must be used. 

Note: 100-percent methyl silicone or 5- 

percent phenyl, 95-percent methyl silicone 

fused silica capillary columns of 0.25- to 

0.32-mm i.d. of varying lengths and with 

varying thicknesses of stationary phase have 

been used successfully for non-polar and 

moderately polar compounds. However, 

given the diversity of potential target lists, 

GC column choice is left to the operator, 

subject to the performance criteria of this 

method. 

6.10 Mass Spectrometer 

Linear quadrupole, magnetic sector, ion 

trap or time-of-flight mass spectrometers may 

be used provided they meet specified 

performance criteria. The mass detector must 

be capable of collecting data from 35 to 300 

atomic mass units (amu) every 1 second or 

less, utilizing 70 volts (nominal) electron 

energy in the electron ionization mode, and 

producing a mass spectrum that meets all the 

instrument performance acceptance criteria 

in Section 9 when 50 hg or less of pbromofluorobenzene is analyzed. 

7.0 Reagents and Standards 

7.1 Sorbent Selection 

7.1.1 Use commercially packed tubes 

meeting the requirements of this method or 

prepare tubes in the laboratory using sieved 

sorbents of particle size in the range 20 to 80 

mesh that meet the retention and quality 

control requirements of this method. 

7.1.2 This passive air monitoring method 

can be used without the evaluation specified 

in Addendum A if the type of tubes 

described in Section 6.1 are packed with 4– 

6 cm (typically 400–650 mg) of the sorbents 

listed in Table 12.1 and used for the 

respective target analytes. 

Note: Although CarbopackTM X is the 

optimum sorbent choice for passive sampling 

of 1,3-butadiene, recovery of compounds 

with vapor pressure lower than benzene may 

be difficult to achieve without exceeding 

sorbent maximum temperature limitations 

(see Table 8.1). See ISO 16017–2:2003(E) or 

ASTM D6196–03 (Reapproved 2009) (both 

incorporated by reference—see § 63.14) for 

more details on sorbent choice for air 

monitoring using passive sampling tubes. 

7.1.3 If standard passive sampling tubes 

are packed with other sorbents or used for 

analytes other than those tabulated in Section 

12.0, method performance and relevant 

uptake rates should be verified according to 

Addendum A to this method or by following 

the techniques described in one of the 

following national/international standard 

methods: ISO 16017–2:2003(E), ASTM 

D6196–03 (Reapproved 2009), or BS EN 

14662–4:2005 (all incorporated by 

reference—see § 63.14)—or reported in the 

peer-reviewed open literature. A summary 

table and the supporting evaluation data 

demonstrating the selected sorbent meets the 

requirements in Addendum A to this method 

must be submitted to the regulatory authority 

as part of a request to use an alternative 

sorbent. 

7.1.4 Passive (diffusive) sampling and 

thermal desorption methods that have been 

evaluated at relatively high atmospheric 

concentrations (i.e., mid-ppb to ppm) and 

published for use in workplace air and 

industrial/mobile source emissions testing 

(References 9–20) may be applied to this 

procedure. However, the validity of any 

shorter term uptake rates must be verified 

and adjusted if necessary for the longer 

monitoring periods required by this method 

by following procedures described in 

Addendum A to this method or those 

presented in national/international standard 

methods: ISO 16017–2:2003(E), ASTM 

D6196–03 (Reapproved 2009), or BS EN 

14662–4:2005 (all incorporated by referencesee § 63.14). 

7.1.5 Suitable sorbents for passive 

sampling must have breakthrough volumes of 

at least 20 L (preferably >100 L) for the 

compounds of interest and must 

quantitatively release the analytes during 

desorption without exceeding maximum 

temperatures for the sorbent or 

instrumentation. 

7.1.6 Repack/replace the sorbent tubes or 

demonstrate tube performance following the 

requirements in Addendum A to this method 

at least every 2 years or every 50 uses, 

whichever occurs first. 

7.2 Gas Phase Standards 

7.2.1 Static or dynamic standard 

atmospheres may be used to prepare 

calibration tubes and/or to validate passive 

sampling uptake rates and can be generated 

from pure chemicals or by diluting 

concentrated gas standards. The standard 

atmosphere must be stable at ambient 

pressure and accurate to ±10 percent of the 

target gas concentration. It must be possible 

to maintain standard atmosphere 

concentrations at the same or lower levels 

than the target compound concentration 

objectives of the test. Test atmospheres used 

for validation of uptake rates must also 

contain at least 35 percent relative humidity. 

Note: Accurate, low-(ppb-) level gas-phase 

VOC standards are difficult to generate from 

pure materials and may be unstable 

depending on analyte polarity and volatility. 

Parallel monitoring of vapor concentrations 

with alternative methods, such as pumped 

sorbent tubes or sensitive/selective on-line 

detectors, may be necessary to minimize 

uncertainty. For these reasons, standard 

atmospheres are rarely used for routine 

calibration. 

7.2.2 Concentrated, pressurized gas phase 

standards. Accurate (±5 percent or better), 

concentrated gas phase standards supplied in 

pressurized cylinders may also be used for 

calibration. The concentration of the 

standard should be such that a 0.5–5.0 mL 

volume contains approximately the same 

mass of analytes as will be collected from a 

typical air sample. 

7.2.3 Follow manufacturer’s guidelines 

concerning storage conditions and 

recertification of the concentrated gas phase 

standard. Gas standards must be recertified a 

minimum of once every 12 months. 

7.3 Liquid Standards 

Target analytes can also be introduced to 

the sampling end of sorbent tubes in the form 

of liquid calibration standards. 

7.3.1 The concentration of liquid 

standards must be such that an injection of 

0.5–2 ml of the solution introduces the same 

mass of target analyte that is expected to be 

collected during the passive air sampling 

period. 

7.3.2 Solvent Selection. The solvent 

selected for the liquid standard must be pure 

(contaminants <10 percent of minimum 

analyte levels) and must not interfere 

chromatographically with the compounds of 

interest. 

7.3.3 If liquid standards are sourced 

commercially, follow manufacturer’s 

guidelines concerning storage conditions and 

shelf life of unopened and opened liquid 

stock standards. 

Note: Commercial VOC standards are 

typically supplied in volatile or noninterfering solvents such as methanol. 

7.3.4 Working standards must be stored at 

6 °C or less and used or discarded within two 

weeks of preparation. 

7.4 Gas Phase Internal Standards 

7.4.1 Gas-phase deuterated or fluorinated 

organic compounds may be used as internal 

standards for MS-based systems. 

7.4.2 Typical compounds include 

deuterated toluene, perfluorobenzene and 

perfluorotoluene. 

7.4.3 Use multiple internal standards to 

cover the volatility range of the target 

analytes. 

7.4.4 Gas-phase standards must be 

obtained in pressurized cylinders and 

containing vendor certified gas 

concentrations accurate to ±5 percent. The 

concentration should be such that the mass 

of internal standard components introduced 

is similar to those of the target analytes 

collected during field monitoring. 

7.5 Preloaded Standard Tubes 

Certified, preloaded standard tubes, 

accurate within ±5 percent for each analyte 

at the microgram level and ±10 percent at the 

nanogram level, are available commercially 


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and may be used for auditing and quality 

control purposes. (See Section 9.5 for audit 

accuracy evaluation criteria.) Certified 

preloaded tubes may also be used for routine 

calibration. 

Note: Proficiency testing schemes are also 

available for TD/GC/MS analysis of sorbent 

tubes preloaded with common analytes such 

as benzene, toluene, and xylene. 

7.6 Carrier Gases 

Use inert, 99.999-percent or higher purity 

helium as carrier gas. Oxygen and organic 

filters must be installed in the carrier gas 

lines supplying the analytical system 

according to the manufacturer’s instructions. 

Keep records of filter and oxygen scrubber 

replacement. 

8.0 Sorbent Tube Handling (Before and 

After Sampling) 

8.1 Sample Tube Conditioning 

8.1.1 Sampling tubes must be 

conditioned using the apparatus described in 

Section 6.2. 

8.1.2 New tubes should be conditioned for 

2 hours to supplement the vendor’s 

conditioning procedure. Recommended 

temperatures for tube conditioning are given 

in Table 8.1. 

8.1.3 After conditioning, the blank must 

be verified on each new sorbent tube and on 

10 percent of each batch of reconditioned 

tubes. See Section 9.0 for acceptance criteria. 

TABLE 8.1—EXAMPLE SORBENT TUBE CONDITIONING PARAMETERS

Sampling sorbent 

Maximum 

temperature 

(°C) 

Conditioning 

temperature 

(°C) 

Carrier gas 

flow rate 

Carbotrap® C ............................................................................................................................... >400 350 100 mL/min 

CarbopackTM C 

Anasorb® GCB2 

CarbographTM 1 TD 

Carbotrap®

CarbopackTM B 

Anasorb® GCB1 

Tenax® TA 

CarbopackTM X ............................................................................................................................ 350 330 100 mL/min 

8.2 Capping, Storage and Shipment of 

Conditioned Tubes 

8.2.1 Conditioned tubes must be sealed 

using long-term storage caps (see Section 6.4) 

pushed fully down onto both ends of the PS 

sorbent tube, tightened by hand and then 

tighten an additional quarter turn using an 

appropriate tool. 

8.2.2 The capped tubes must be kept in 

appropriate containers for storage and 

transportation (see Section 6.4.2). Containers 

of sorbent tubes may be stored and shipped 

at ambient temperature and must be kept in 

a clean environment. 

8.2.3 You must keep batches of capped 

tubes in their shipping boxes or wrap them 

in uncoated aluminum foil before placing 

them in their storage container, especially 

before air freight, because the packaging 

helps hold caps in position if the tubes get 

very cold. 

8.3 Calculating the Number of Tubes 

Required for a Monitoring Exercise 

8.3.1 Follow guidance given in Method 

325A to determine the number of tubes 

required for site monitoring. 

8.3.2 The following additional samples 

will also be required: Laboratory blanks as 

specified in Section 9.1.2 (one per analytical 

sequence minimum), field blanks as specified 

in Section 9.3.2 (two per sampling period 

minimum), CCV tubes as specified in Section 

10.9.4. (at least one per analysis sequence or 

every 24 hours), and duplicate samples as 

specified in Section 9.4 (at least one 

duplicate sample is required for every 10 

sampling locations during each monitoring 

period). 

8.4 Sample Collection 

8.4.1 Allow the tubes to equilibrate with 

ambient temperature (approximately 30 

minutes to 1 hour) at the monitoring location 

before removing them from their storage/

shipping container for sample collection. 

8.4.2 Tubes must be used for sampling 

within 30 days of conditioning (Reference 4). 

8.4.3 During field monitoring, the longterm storage cap at the sampling end of the 

tube is replaced with a diffusion cap and the 

whole assembly is arranged vertically, with 

the sampling end pointing downward, under 

a protective hood or shield—See Section 6.1 

of Method 325A for more details. 

8.5 Sample Storage 

8.5.1 After sampling, tubes must be 

immediately resealed with long-term storage 

caps and placed back inside the type of 

storage container described in Section 6.4.2. 

8.5.2 Exposed tubes may not be placed in 

the same container as clean tubes. They 

should not be taken back out of the container 

until ready for analysis and after they have 

had time to equilibrate with ambient 

temperature in the laboratory. 

8.5.3 Sampled tubes must be inspected 

before analysis to identify problems such as 

loose or missing caps, damaged tubes, tubes 

that appear to be leaking sorbent or container 

contamination. Any and all such problems 

must be documented together with the 

unique identification number of the tube or 

tubes concerned. Affected tubes must not be 

analyzed but must be set aside. 

8.5.4 Intact tubes must be analyzed 

within 30 days of the end of sample 

collection (within one week for limonene, 

carene, bis-chloromethyl ether, labile sulfur 

or nitrogen-containing compounds, and other 

reactive VOCs). 

Note: Ensure ambient temperatures stay 

below 23 °C during transportation and 

storage. Refrigeration is not normally 

required unless the samples contain reactive 

compounds or cannot be analyzed within 30 

days. If refrigeration is used, the atmosphere 

inside the refrigerator must be clean and free 

of organic solvents. 

9.0 Quality Control 

9.1 Laboratory Blank 

The analytical system must be 

demonstrated to be contaminant free by 

performing a blank analysis at the beginning 

of each analytical sequence to demonstrate 

that the secondary trap and TD/GC/MS 

analytical equipment are free of any 

significant interferents. 

9.1.1 Laboratory blank tubes must be 

prepared from tubes that are identical to 

those used for field sampling. 

9.1.2 Analysis of at least one laboratory 

blank is required per analytical sequence. 

The laboratory blank must be stored in the 

laboratory under clean, controlled ambient 

temperature conditions. 

9.1.3 Laboratory blank/artifact levels 

must meet the requirements of Section 9.2.2 

(see also Table 17.1). If the laboratory blank 

does not meet requirements, stop and 

perform corrective actions and then reanalyze laboratory blank to ensure it meets 

requirements. 

9.2 Tube Conditioning 

9.2.1 Conditioned tubes must be 

demonstrated to be free of contaminants and 

interference by running 10 percent of the 

blank tubes selected at random from each 

conditioned batch under standard sample 

analysis conditions (see Section 8.1). 

9.2.2 Confirm that artifacts and 

background contamination are ≤ 0.2 ppbv or 

less than three times the detection limit of 

the procedure or less than 10 percent of the 

target compound(s) mass that would be 

collected if airborne concentrations were at 

the regulated limit value, whichever is larger. 

Only tubes that meet these criteria can be 


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used for field monitoring, field or laboratory 

blanks, or for system calibration. 

9.2.3 If unacceptable levels of VOCs are 

observed in the tube blanks, then the 

processes of tube conditioning and checking 

the blanks must be repeated. 

9.3 Field Blanks 

9.3.1 Field blank tubes must be prepared 

from tubes that are identical to those used for 

field sampling—i.e., they should be from the 

same batch, have a similar history, and be 

conditioned at the same time. 

9.3.2 Field blanks must be shipped to the 

monitoring site with the sampling tubes and 

must be stored at the sampling location 

throughout the monitoring exercise. The field 

blanks must be installed under a protective 

hood/cover at the sampling location, but the 

long-term storage caps must remain in place 

throughout the monitoring period (see 

Method 325A). The field blanks are then 

shipped back to the laboratory in the same 

container as the sampled tubes. One field 

blank tube is required for every 10 sampled 

tubes on a monitoring exercise and no less 

than two field blanks should be collected, 

regardless of the size of the monitoring study. 

9.3.3 Field blanks must contain no greater 

than one-third of the measured target analyte 

or compliance limit for field samples (see 

Table 17.1). If either field blank fails, flag all 

data that do not meet this criterion with a 

note that the associated results are estimated 

and likely to be biased high due to field 

blank background. 

9.4 Duplicate Samples 

Duplicate (co-located) samples collected 

must be analyzed and reported as part of 

method quality control. They are used to 

evaluate sampling and analysis precision. 

Relevant performance criteria are given in 

Section 9.9. 

9.5 Method Performance Criteria 

Unless otherwise noted, monitoring 

method performance specifications must be 

demonstrated for the target compounds using 

the procedures described in Addendum A to 

this method and the statistical approach 

presented in Method 301. 

9.6 Method Detection Limit 

Determine the method detection limit 

under the analytical conditions selected (see 

Section 11.3) using the procedure in Section 

15 of Method 301. The method detection 

limit is defined for each system by making 

seven replicate measurements of a 

concentration of the compound of interest 

within a factor of five of the detection limit. 

Compute the standard deviation for the seven 

replicate concentrations, and multiply this 

value by three. The results should 

demonstrate that the method is able to detect 

analytes such as benzene at concentrations as 

low as 50 ppt or 1/3rd (preferably 1/10th) of 

the lowest concentration of interest, 

whichever is larger. 

Note: Determining the detection limit may 

be an iterative process as described in 40 CFR 

part 136, Appendix B. 

9.7 Analytical Bias 

Analytical bias must be demonstrated to be 

within ±30 percent using Equation 9.1. 

Analytical bias must be demonstrated during 

initial setup of this method and as part of the 

CCV carried out with every sequence of 10 

samples or less (see Section 9.14). Calibration 

standard tubes (see Section 10.0) may be 

used for this purpose. 

Where: 

Spiked Value = A known mass of VOCs 

added to the tube. 

Measured Value = Mass determined from 

analysis of the tube. 

9.8 Analytical Precision 

Demonstrate an analytical precision within 

±20 percent using Equation 9.2. Analytical 

precision must be demonstrated during 

initial setup of this method and at least once 

per year. Calibration standard tubes may be 

used (see Section 10.0) and data from CCV 

may also be applied for this purpose. 

Where: 

A1 = A measurement value taken from one 

spiked tube. 

A2 = A measurement value taken from a 

second spiked tube. 

A = The average of A1 and A2. 

9.9 Field Replicate Precision 

Use Equation 9.3 to determine and 

report replicate precision for duplicate 

field samples (see Section 9.4). The 

level of agreement between duplicate 

field samples is a measure of the 

precision achievable for the entire 

sampling and analysis procedure. Flag 

data sets for which the duplicate 

samples do not agree within 30 percent. 

Where: 

F1 = A measurement value (mass) taken from 

one of the two field replicate tubes used 

in sampling. 

F2 = A measurement value (mass) taken from 

the second of two field replicate tubes 

used in sampling. 

F = The average of F1 and F2. 

9.10 Desorption Efficiency and Compound 

Recovery 

The efficiency of the thermal desorption 

method must be determined. 

9.10.1 Quantitative (>95 percent) 

compound recovery must be demonstrated by 

repeat analyses on a same standard tube. 

9.10.2 Compound recovery through the 

TD system can also be demonstrated by 

comparing the calibration check sample 

response factor obtained from direct GC 

injection of liquid standards with that 

obtained from thermal desorption analysis 

response factor using the same column under 

identical conditions. 

9.10.3 If the relative response factors 

obtained for one or more target compounds 

introduced to the column via thermal 

desorption fail to meet the criteria in Section 

9.10.1, you must adjust the TD parameters to 

meet the criteria and repeat the experiment. 

Once the thermal desorption conditions have 

been optimized, you must repeat this test 

each time the analytical system is 

recalibrated to demonstrate continued 

method performance. 

9.11 Audit Samples 

Certified reference standard samples must 

be used to audit this procedure (if available). 

Accuracy within 30 percent must be 


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demonstrated for relevant ambient air 

concentrations (0.5 to 25 ppb). 

9.12 Mass Spectrometer Tuning Criteria 

Tune the mass spectrometer (if used) 

according to manufacturer’s specifications. 

Verify the instrument performance by 

analyzing a 50 hg injection of 

bromofluorobenzene. Prior to the beginning 

of each analytical sequence or every 24 hours 

during continuous GC/MS operation for this 

method demonstrate that the 

bromofluorobenzene tuning performance 

criteria in Table 9.1 have been met. 

TABLE 9.1—GC/MS TUNING CRITERIA 1

Target mass Rel. to mass Lower limit % Upper limit % 

50 ................................................................................................................................................. 95 8 40 

75 ................................................................................................................................................. 95 30 66 

95 ................................................................................................................................................. 95 100 100 

96 ................................................................................................................................................. 95 5 9 

173 ............................................................................................................................................... 174 0 2 

174 ............................................................................................................................................... 95 50 120 

175 ............................................................................................................................................... 174 4 9 

176 ............................................................................................................................................... 174 93 101 

177 ............................................................................................................................................... 176 5 9 

1All ion abundances must be normalized to m/z 95, the nominal base peak, even though the ion abundance of m/z 174 may be up to 120 percent that of m/z 95. 

9.13 Routine CCV at the Start of a 

Sequence 

Run CCV before each sequence of analyses 

and after every tenth sample to ensure that 

the previous multi-level calibration (see 

Section 10.6.3) is still valid. 

9.13.1 The sample concentration used for 

the CCV should be near the mid-point of the 

multi-level calibration range. 

9.13.2 Quantitation software must be 

updated with response factors determined 

from the CCV standard. The percent 

deviation between the initial calibration and 

the CCV for all compounds must be within 

30 percent. 

9.14 CCV at the End of a Sequence 

Run another CCV after running each 

sequence of samples. The initial CCV for a 

subsequent set of samples may be used as the 

final CCV for a previous analytical sequence, 

provided the same analytical method is used 

and the subsequent set of samples is 

analyzed immediately (within 4 hours) after 

the last CCV. 

9.15 Additional Verification 

Use a calibration check standard from a 

second, separate source to verify the original 

calibration at least once every three months. 

9.16 Integration Method 

Document the procedure used for 

integration of analytical data including field 

samples, calibration standards and blanks. 

9.17 QC Records 

Maintain all QC reports/records for each 

TD/GC/MS analytical system used for 

application of this method. Routine quality 

control requirements for this method are 

listed below and summarized in Table 17.1. 

10.0 Calibration and Standardization 

10.1 Calibrate the analytical system using 

standards covering the range of analyte 

masses expected from field samples. 

10.2 Analytical results for field samples 

must fall within the calibrated range of the 

analytical system to be valid. 

10.3 Calibration standard preparation 

must be fully traceable to primary standards 

of mass and/or volume, and/or be confirmed 

using an independent certified reference 

method. 

10.3.1 Preparation of calibration standard 

tubes from standard atmospheres. 

10.3.1.1 Subject to the requirements in 

Section 7.2.1, low-level standard 

atmospheres may be introduced to clean, 

conditioned sorbent tubes in order to 

produce calibration standards. 

10.3.1.2 The standard atmosphere 

generator or system must be capable of 

producing sufficient flow at a constant rate 

to allow the required analyte mass to be 

introduced within a reasonable time frame 

and without affecting the concentration of 

the standard atmosphere itself. 

10.3.1.3 The sampling manifold may be 

heated to minimize risk of condensation but 

the temperature of the gas delivered to the 

sorbent tubes may not exceed 100 °F. 

10.3.1.4 The flow rates passed through 

the tube should be in the order of 50–100 

mL/min and the volume of standard 

atmosphere sampled from the manifold or 

chamber must not exceed the breakthrough 

volume of the sorbent at the given 

temperature. 

10.4 Preparation of calibration standard 

tubes from concentrated gas standards. 

10.4.1 If a suitable concentrated gas 

standard (see Section 7.2.2) can be obtained, 

follow the manufacturer’s recommendations 

relating to suitable storage conditions and 

product lifetime. 

10.4.2 Introduce precise 0.5 to 500.0 mL 

aliquots of the standard to the sampling end 

of conditioned sorbent tubes in a 50–100 mL/ 

min flow of pure carrier gas. 

Note: This can be achieved by connecting 

the sampling end of the tube to an unheated 

GC injector (see Section 6.6) and introducing 

the aliquot of gas using a suitable gas syringe. 

Gas sample valves could alternatively be 

used to meter the standard gas volume. 

10.4.3 Each sorbent tube should be left 

connected to the flow of gas for 2 minutes 

after standard introduction. As soon as each 

spiked tube is removed from the injection 

unit, seal it with long-term storage caps and 

place it in an appropriate tube storage/

transportation container if it is not to be 

analyzed within 24 hours. 

10.5 Preparation of calibration standard 

tubes from liquid standards. 

10.5.1 Suitable standards are described in 

Section 7.3. 

10.5.2 Introduce precise 0.5 to 2 ml 

aliquots of liquid standards to the sampling 

end of sorbent tubes in a flow (50–100 mL/ 

min) of carrier gas using a precision syringe 

and an unheated injector (Section 6.5). The 

flow of gas should be sufficient to completely 

vaporize the liquid standard. 

Note: If the analytes of interest are higher 

boiling than n-decane, reproducible analyte 

transfer to the sorbent bed is optimized by 

allowing the tip of the syringe to gently touch 

the sorbent retaining gauze at the sampling 

end of the tube. 

10.5.3 Each sorbent tube is left connected 

to the flow of gas for 5 minutes after liquid 

standard introduction. 

10.5.3.1 As soon as each spiked tube is 

removed from the injection unit, seal it with 

long-term storage caps and place it in an 

appropriate tube storage container if it is not 

to be analyzed within 24 hours. 

Note: In cases where it is possible to 

selectively purge the solvent from the tube 

while all target analytes are quantitatively 

retained, a larger 2 mL injection may be made 

for optimum accuracy. However, if the 

solvent cannot be selectively purged and will 

be present during analysis, the injection 

volume should be as small as possible (e.g., 

0.5 mL) to minimize solvent interference. 

Note: This standard preparation technique 

requires the entire liquid plug including the 

tip volume be brought into the syringe barrel. 

The volume in the barrel is recorded, the 

syringe is inserted into the septum of the 

spiking apparatus. The liquid is then quickly 

injected. Any remaining liquid in the syringe 

tip is brought back into the syringe barrel. 

The volume in the barrel is recorded and the 

amount spiked onto the tube is the difference 

between the before spiking volume and the 

after spiking volume. A bias occurs with this 

method when sample is drawn continuously 

up into the syringe to the specified volume 


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and the calibration solution in the syringe tip 

is ignored. 

10.6 Preparation of calibration standard 

tubes from multiple standards. 

10.6.1 If it is not possible to prepare one 

standard containing all the compounds of 

interest (e.g., because of chemical reactivity 

or the breadth of the volatility range), 

standard tubes can be prepared from multiple 

gas or liquid standards. 

10.6.2 Follow the procedures described 

in Sections 10.4 and 10.5, respectively, for 

introducing each gas and/or liquid standard 

to the tube and load those containing the 

highest boiling compounds of interest first 

and the lightest species last. 

10.7 Additional requirements for 

preparation of calibration tubes. 

10.7.1 Storage of Calibration Standard 

Tubes 

10.7.1.1 Seal tubes with long-term storage 

caps immediately after they have been 

disconnected from the standard loading 

manifold or injection apparatus. 

10.7.1.2 Calibration standard tubes may 

be stored for no longer than 30 days and 

should be refrigerated if there is any risk of 

chemical interaction or degradation. Audit 

standards (see section 9.11) are exempt from 

this criteria and may be stored for the shelflife specified on their certificates. 

10.8 Keep records for calibration standard 

tubes to include the following: 

10.8.1 The stock number of any 

commercial liquid or gas standards used. 

10.8.2 A chromatogram of the most recent 

blank for each tube used as a calibration 

standard together with the associated 

analytical conditions and date of cleaning. 

10.8.3 Date of standard loading. 

10.8.4 List of standard components, 

approximate masses and associated 

confidence levels. 

10.8.5 Example analysis of an identical 

standard with associated analytical 

conditions. 

10.8.6 A brief description of the method 

used for standard preparation. 

10.8.7 The standard’s expiration date. 

10.9 TD/GC/MS using standard tubes to 

calibrate system response. 

10.9.1 Verify that the TD/GC/MS 

analytical system meets the instrument 

performance criteria given in Section 9.1. 

10.9.2 The prepared calibration standard 

tubes must be analyzed using the analytical 

conditions applied to field samples (see 

Section 11.0) and must be selected to ensure 

quantitative transfer and adequate 

chromatographic resolution of target 

compounds, surrogates, and internal 

standards in order to enable reliable 

identification and quantitation of compounds 

of interest. The analytical conditions should 

also be sufficiently stringent to prevent 

buildup of higher boiling, non-target 

contaminants that may be collected on the 

tubes during field monitoring. 

10.9.3 Calibration range. Each TD/GC/MS 

system must be calibrated at five 

concentrations that span the monitoring 

range of interest before being used for sample 

analysis. This initial multi-level calibration 

determines instrument sensitivity under the 

analytical conditions selected and the 

linearity of GC/MS response for the target 

compounds. One of the calibration points 

must be within a factor of five of the 

detection limit for the compounds of interest. 

10.9.4 One of the calibration points from 

the initial calibration curve must be at the 

same concentration as the daily CCV 

standard (e.g., the mass collected when 

sampling air at typical concentrations). 

10.9.5 Calibration frequency. Each GC/

MS system must be recalibrated with a full 

5-point calibration curve following corrective 

action (e.g., ion source cleaning or repair, 

column replacement) or if the instrument 

fails the daily calibration acceptance criteria. 

10.9.5.1 CCV checks must be carried out 

on a regular routine basis as described in 

Section 9.14. 

10.9.5.2 Quantitation ions for the target 

compounds are shown in Table 10.1. Use the 

primary ion unless interferences are present, 

in which case you should use a secondary 

ion. 

TABLE 10.1—CLEAN AIR ACT VOLATILE ORGANIC COMPOUNDS FOR PASSIVE SORBENT SAMPLING

Compound CAS No. BP 

(°C) 

Vapor 

pressure 

(mmHg) a

MW b

Characteristic ion(s) 

Primary Secondary 

1,1-Dichloroethene ............................. 75–35–4 32 500 96.9 61 96 

3-Chloropropene ................................ 107–05–1 44.5 340 76.5 76 41, 39, 78 

1,1,2-Trichloro-1,2,2-trifluoroethane1,1-Dichloroethane ......................... 75–34–3 57.0 230 99 63 65, 83, 85, 98, 

100 

1,2-Dichloroethane ............................. 107–06–2 83.5 61.5 99 62 98 

1,1,1-Trichloroethane ......................... 71–55–6 74.1 100 133.4 97 99, 61 

Benzene ............................................. 71–43–2 80.1 76.0 78 78 ..............................

Carbon tetrachloride .......................... 56–23–5 76.7 90.0 153.8 117 119 

1,2-Dichloropropane ........................... 78–87–5 97.0 42.0 113 63 112 

Trichloroethene .................................. 79–01–6 87.0 20.0 131.4 95 97, 130, 132 

1,1,2-Trichloroethane ......................... 79–00–5 114 19.0 133.4 83 97, 85 

Toluene .............................................. 108–88–3 111 22.0 92 92 91 

Tetrachloroethene .............................. 127–18–4 121 14.0 165.8 164 129, 131, 166 

Chlorobenzene ................................... 108–90–7 132 8.8 112.6 112 77, 114 

Ethylbenzene ..................................... 100–41–4 136 7.0 106 91 106 

m,p-Xylene ......................................... 108–38–3, 

106–42–3 

138 6.5 106.2 106 91 

Styrene ............................................... 100–42–5 145 6.6 104 104 78 

o-Xylene ............................................. 95–47–6 144 5.0 106.2 106 91 

p-Dichlorobenzene ............................. 106–46–7 173 0.60 147 146 111, 148 

aPressure in millimeters of mercury. 

b Molecular weight. 

11.0 Analytical Procedure 

11.1 Preparation for Sample Analysis 

11.1.1 Each sequence of analyses must be 

ordered as follows: 

11.1.1.1 CCV. 

11.1.1.2 A laboratory blank. 

11.1.1.3 Field blank. 

11.1.1.4 Sample(s). 

11.1.1.5 Field blank. 

11.1.1.6 CCV after 10 field samples. 

11.1.1.7 CCV at the end of the sample 

batch. 

11.2 Pre-desorption System Checks and 

Procedures 

11.2.1 Ensure all sample tubes and field 

blanks are at ambient temperature before 

removing them from the storage container. 

11.2.2 If using an automated TD/GC/MS 

analyzer, remove the long-term storage caps 

from the tubes, replace them with 

appropriate analytical caps, and load them 

into the system in the sequence described in 

Section 11.1. Alternatively, if using a manual 

system, uncap and analyze each tube, one at 

a time, in the sequence described in Section 

11.1. 

11.2.3 The following thermal desorption 

system integrity checks and procedures are 

required before each tube is analyzed. 


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Note: Commercial thermal desorbers 

should implement these steps automatically. 

11.2.3.1 Tube leak test: Each tube must be 

leak tested as soon as it is loaded into the 

carrier gas flow path before analysis to ensure 

data integrity. 

11.2.3.2 Conduct the leak test at the GC 

carrier gas pressure, without heat or gas flow 

applied. Tubes that fail the leak test should 

not be analyzed, but should be resealed and 

stored intact. On automated systems, the 

instrument should continue to leak test and 

analyze subsequent tubes after a given tube 

has failed. Automated systems must also 

store and record which tubes in a sequence 

have failed the leak test. Information on 

failed tubes should be downloaded with the 

batch of sequence information from the 

analytical system. 

11.2.3.3 Leak test the sample flow path. 

Leak check the sample flow path of the 

thermal desorber before each analysis 

without heat or gas flow applied to the 

sample tube. Stop the automatic sequence of 

tube desorption and GC analysis if any leak 

is detected in the main sample flow path. 

This process may be carried out as a separate 

step or as part of Section 11.2.3.2. 

11.2.4 Optional Dry Purge 

11.2.4.1 Tubes may be dry purged with a 

flow of pure dry gas passing into the tube 

from the sampling end, to remove water 

vapor and other very volatile interferents if 

required. 

11.2.5 Internal Standard (IS) Addition 

11.2.5.1 Use the internal standard 

addition function of the automated thermal 

desorber (if available) to introduce a precise 

aliquot of the internal standard to the 

sampling end of each tube after the leak test 

and shortly before primary (tube) 

desorption). 

Note: This step can be combined with dry 

purging the tube (Section 11.2.4) if required. 

11.2.5.2 If the analyzer does not have a 

facility for automatic IS addition, gas or 

liquid internal standard can be manually 

introduced to the sampling end of tubes in 

a flow of carrier gas using the types of 

procedure described in Sections 10.3 and 

10.4, respectively. 

11.2.6 Pre-purge. Each tube should be 

purged to vent with carrier gas flowing in the 

desorption direction (i.e., flowing into the 

tube from the non-sampling end) to remove 

oxygen before heat is applied. This is to 

prevent analyte and sorbent oxidation and to 

prevent deterioration of key analyzer 

components such as the GC column and mass 

spectrometer (if applicable). A series of 

schematics illustrating these steps is 

presented in Figures 17.2 and 17.3. 

11.3 Analytical Procedure 

11.3.1 Steps Required for Thermal 

Desorption 

11.3.1.1 Ensure that the pressure and 

purity of purge and carrier gases supplying 

the TD/GC/MS system, meet manufacturer 

specifications and the requirements of this 

method. 

11.3.1.2 Ensure also that the analytical 

method selected meets the QC requirements 

of this method (Section 9) and that all the 

analytical parameters are at set point. 

11.3.1.3 Conduct predesorption system 

checks (see Section 11.2). 

11.3.1.4 Desorb the sorbent tube under 

conditions demonstrated to achieve >95 

percent recovery of target compounds (see 

Section 9.5.2). 

Note: Typical tube desorption conditions 

range from 280–350 °C for 5–15 minutes with 

a carrier gas flow of 30–100 mL/min passing 

through the tube from the non-sampling end 

such that analytes are flushed out of the tube 

from the sampling end. Desorbed VOCs are 

concentrated (refocused) on a secondary, 

cooled sorbent trap integrated into the 

analytical equipment (see Figure 17.4). The 

focusing trap is typically maintained at a 

temperature between ¥30 and +30 °C during 

focusing. Selection of hydrophobic sorbents 

for focusing and setting a trapping 

temperature of +25 to 27 °C aid analysis of 

humid samples because these settings allow 

selective elimination of any residual water 

from the system, prior to GC/MS analysis. 

Note: The transfer of analytes from the tube 

to the focusing trap during primary (tube) 

desorption can be carried out splitless or 

under controlled split conditions (see Figure 

17.4) depending on the masses of target 

compounds sampled and the requirements of 

the system—sensitivity, required calibration 

range, column overload limitations, etc. 

Instrument controlled sample splits must be 

demonstrated by showing the reproducibility 

using calibration standards. Field and 

laboratory blank samples must be analyzed at 

the same split as the lowest calibration 

standard. During secondary (trap) desorption 

the focusing trap is heated rapidly (typically 

at rates >40 °C/s) with inert (carrier) gas 

flowing through the trap (3–100 mL/min) in 

the reverse direction to that used during 

focusing. 

11.3.1.5 The split conditions selected for 

optimum field sample analysis must also be 

demonstrated on representative standards. 

Note: Typical trap desorption temperatures 

are in the range 250–360 °C, with a ‘‘hold’’ 

time of 1–3 minutes at the highest 

temperature. Trap desorption automatically 

triggers the start of GC analysis. The trap 

desorption can also be carried out under 

splitless conditions (i.e., with everything 

desorbed from the trap being transferred to 

the analytical column and GC detector) or, 

more commonly, under controlled split 

conditions (see Figure 17.4). The selected 

split ratio depends on the masses of target 

compounds sampled and the requirements of 

the system—sensitivity, required calibration 

range, column overload limitations, etc. If a 

split is selected during both primary (trap) 

desorption and secondary (trap) desorption, 

the overall split ratio is the product of the 

two. Such ‘double’ split capability gives 

optimum flexibility for accommodating 

concentrated samples as well as trace-level 

samples on the TD/GC/MS analytical system. 

High resolution capillary columns and most 

GC/MS detectors tend to work best with 

approximately 20–200 ng per compound per 

tube to avoid saturation. The overall split 

ratio must be adjusted such that, when it is 

applied to the sample mass that is expected 

to be collected during field monitoring, the 

amount reaching the column will be 

attenuated to fall within this range. As a rule 

of thumb this means that ∼20 ng samples will 

require splitless or very low split analysis, ∼2 

mg samples will require a split ratio in the 

order of ∼50:1 and 200 mg samples will 

require a double split method with an overall 

split ratio in the order of 2,000:1. 

11.3.1.6 Analyzed tubes must be resealed 

with long-term storage caps immediately 

after analysis (manual systems) or after 

completion of a sequence (automated 

systems). This prevents contamination, 

minimizing the extent of tube reconditioning 

required before subsequent reuse. 

11.3.2 GC/MS Analytical Procedure 

11.3.2.1 Heat/cool the GC oven to its 

starting set point. 

11.3.2.2 If using a GC/MS system, it can 

be operated in either MS-Scan or MS–SIM 

mode (depending on required sensitivity 

levels and the type of mass spectrometer 

selected). As soon as trap desorption and 

transfer of analytes into the GC column 

triggers the start of the GC/MS analysis, 

collect mass spectral data over a range of 

masses from 35 to 300 amu. Collect at least 

10 data points per eluting chromatographic 

peak in order to adequately integrate and 

quantify target compounds. 

11.3.2.3 Use secondary ion quantitation 

only when there are sample matrix 

interferences with the primary ion. If 

secondary ion quantitation is performed, flag 

the data and document the reasons for the 

alternative quantitation procedure. 

11.3.2.4 Data reduction is performed by 

the instruments post processing program that 

is automatically accessed after data 

acquisition is completed at the end of the GC 

run. The concentration of each target 

compound is calculated using the previously 

established response factors for the CCV 

analyzed in Section 11.1.1.6. 

11.3.2.5 Whenever the thermal 

desorption—GC/MS analytical method is 

changed or major equipment maintenance is 

performed, you must conduct a new fivelevel calibration (see Section 10.6.3). System 

calibration remains valid as long as results 

from subsequent CCV are within 30 percent 

of the most recent 5-point calibration (see 

Section 10.9.5). Include relevant CCV data in 

the supporting information in the data report 

for each set of samples. 

11.3.2.6 Document, flag and explain all 

sample results that exceed the calibration 

range. Report flags and provide 

documentation in the analytical results for 

the affected sample(s). 

12.0 Data Analysis, Calculations, and 

Reporting 

12.1 Recordkeeping Procedures for Sorbent 

Tubes 

12.1.1 Label sample tubes with a unique 

identification number as described in Section 

6.3. 

12.1.2 Keep records of the tube numbers 

and sorbent lots used for each sampling 

period. 

12.1.3 Keep records of sorbent tube 

packing if tubes are manually prepared in the 


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laboratory and not supplied commercially. 

These records must include the masses and/ 

or bed lengths of sorbent(s) contained in each 

tube, the maximum allowable temperature 

for that tube and the date each tube was 

packed. If a tube is repacked at any stage, 

record the date of tube repacking and any 

other relevant information required in 

Section 12.1. 

12.1.4 Keep records of the conditioning 

and blanking of tubes. These records must 

include, but are not limited to, the unique 

identification number and measured 

background resulting from the tube 

conditioning. 

12.1.5 Record the location, dates, tube 

identification and times associated with each 

sample collection. Record this information 

on a Chain of Custody form that is sent to the 

analytical laboratory. 

12.1.6 Field sampling personnel must 

complete and send a Chain of Custody to the 

analysis laboratory (see Section 8.6.4 of 

Method 325A for what information to 

include and Section 17.0 of this method for 

an example form). Duplicate copies of the 

Chain of Custody must be included with the 

sample report and stored with the field test 

data archive. 

12.1.7 Field sampling personnel must 

also keep records of the unit vector wind 

direction, sigma theta, temperature and 

barometric pressure averages for the 

sampling period. See Section 8.3.4 of Method 

325A. 

12.1.8 Laboratory personnel must record 

the sample receipt date, and analysis date. 

12.1.9 Laboratory personnel must 

maintain records of the analytical method 

and sample results in electronic or hardcopy 

in sufficient detail to reconstruct the 

calibration, sample, and quality control 

results from each sampling period. 

12.2 Calculations 

12.2.1 Complete the calculations in this 

section to determine compliance with 

calibration quality control criteria (see also 

Table 17.1). 

12.2.1.1 Response factor (RF). Calculate 

the RF using Equation 12.1: 

Where: 

As = Peak area for the characteristic ion of the 

analyte. 

Ais = Peak area for the characteristic ion of 

the internal standard. 

Ms = Mass of the analyte. 

Mis = Mass of the internal standard. 

12.2.1.2 Standard deviation of the 

response factors (SDRF). Calculate the SDRF 

using Equation 12.2: 

Where: 

RFi = RF for each of the calibration 

compounds. 

RF = Mean RF for each compound from the 

initial calibration. 

n = Number of calibration standards. 

12.2.1.3 Percent deviation (%DEV). 

Calculate the %DEV using Equation 12.3: 

Where: 

SDRF = Standard deviation. 

RF = Mean RF for each compound from the 

initial calibration. 

12.2.1.4 Relative percent difference 

(RPD). Calculate the RPD using Equation 

12.4: 

Where: 

R1, R2 = Values that are being compared (i.e., 

response factors in CCV). 

12.2.2 Determine the equivalent 

concentration of compounds in atmospheres 

as follows. 

12.2.3 Correct target concentrations 

determined at the sampling site temperature 

and atmospheric pressure to standard 

conditions (25 °C and 760 mm mercury) 

using Equation 12.5 (Reference 21). 

Where: 

tss = The average temperature during the 

collection period at the sampling site (K). 

Pss = The average pressure at the sampling 

site during the collection period (mm 

Hg). 

U = The diffusive uptake rate (sampling rate) 

(mL/min). 


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12.2.4 For passive sorbent tube samples, 

calculate the concentration of the target 

compound(s) in the sampled air, in mg/m3 by 

using Equation 12.6 (Reference 22). 

Where: 

Cm = The concentration of target compound 

in the air sampled (mg/m3). 

mmeas = The mass of the compound as 

measured in the sorbent tube (mg). 

UNTP = The diffusive uptake rate corrected for 

local conditions (sampling rate) (mL/

min). 

t = The exposure time (minutes). 

Note: Diffusive uptake rates for common 

VOCs, using carbon sorbents packed into 

sorbent tubes of the dimensions specified in 

Section 6.1, are listed in Table 12.1. Adjust 

analytical conditions to keep expected 

sampled masses within range (see Sections 

11.3.1.3 to 11.3.1.5). Best possible method 

detection limits are typically in the order of 

0.1 ppb for 1,3-butadiene and 0.05 ppb for 

volatile aromatics such as benzene for 14-day 

monitoring. However, actual detection limits 

will depend upon the analytical conditions 

selected. 

TABLE 12.1—VALIDATED SORBENTS AND UPTAKE RATES (ML/MIN) FOR SELECTED CLEAN AIR ACT COMPOUNDS

Compound CarbopackTM

Xa

CarbographTM1 

TD 

CarbopackTM

B 

1,1-Dichloroethene .............................................................................................. 0.57 ± 0.14 not available .......... not available. 

3-Chloropropene ................................................................................................. 0.51 ± 0.3 not available .......... not available. 

1,1-Dichloroethane .............................................................................................. 0.57 ± 0.1 not available .......... not available. 

1,2-Dichloroethane .............................................................................................. 0.57 ± 0.08 not available .......... not available. 

1,1,1-Trichloroethane .......................................................................................... 0.51 ± 0.1 not available .......... not available. 

Benzene .............................................................................................................. 0.67 ± 0.06 0.63 ± 0.07b .......... 0.63 ± 0.07b. 

Carbon tetrachloride ........................................................................................... 0.51 ± 0.06 not available .......... not available. 

1,2-Dichloropropane ........................................................................................... 0.52 ± 0.1 not available .......... not available. 

Trichloroethene ................................................................................................... 0.5 ± 0.05 not available .......... not available. 

1,1,2-Trichloroethane .......................................................................................... 0.49 ± 0.13 not available .......... not available. 

Toluene ............................................................................................................... 0.52 ± 0.14 0.56 ± 0.06c .......... 0.56 ± 0.06c. 

Tetrachloroethene ............................................................................................... 0.48 ± 0.05 not available .......... not available. 

Chlorobenzene .................................................................................................... 0.51 ± 0.06 not available .......... not available. 

Ethylbenzene ...................................................................................................... 0.46 ± 0.07 not available .......... 0.50c. 

m,p-Xylene .......................................................................................................... 0.46 ± 0.09 0.47 ± 0.04c .......... 0.47 ± 0.04c. 

Styrene ................................................................................................................ 0.5 ± 0.14 not available .......... not available. 

o-Xylene .............................................................................................................. 0.46 ± 0.12 0.47 ± 0.04c .......... 0.47 ± 0.04c. 

p-Dichlorobenzene .............................................................................................. 0.45 ± 0.05 not available .......... not available. 

a Reference 3, McClenny, J. Environ. Monit. 7:248–256. Based on 24-hour duration. 

b Reference 24, BS EN 14662–4:2005 (incorporated by reference—see § 63.14). Based on 14-day duration. 

c Reference 25, ISO 16017–2:2003(E) (incorporated by reference—see § 63.14). Based on 14-day duration. 

13.0 Method Performance 

The performance of this procedure for VOC 

not listed in Table 12.1 is determined using 

the procedure in Addendum A of this 

Method or by one of the following national/ 

international standard methods: ISO 16017– 

2:2003(E), ASTM D6196–03 (Reapproved 

2009), or BS EN 14662–4:2005 (all 

incorporated by reference—see § 63.14). 

13.1 The valid range for measurement of 

VOC is approximately 0.5 mg/m3 to 5 mg/m3

in air, collected over a 14-day sampling 

period. The upper limit of the useful range 

depends on the split ratio selected (Section 

11.3.1) and the dynamic range of the 

analytical system. The lower limit of the 

useful range depends on the noise from the 

analytical instrument detector and on the 

blank level of target compounds or 

interfering compounds on the sorbent tube 

(see Section 13.3). 

13.2 Diffusive sorbent tubes compatible 

with passive sampling and thermal 

desorption methods have been evaluated at 

relatively high atmospheric concentrations 

(i.e., mid-ppb to ppm) and published for use 

in workplace air and industrial/mobile 

source emissions (References 15–16, 21–22). 

13.3 Best possible detection limits and 

maximum quantifiable concentrations of air 

pollutants range from sub-part-per-trillion 

(sub-ppt) for halogenated species such as 

CCl4 and the freons using an electron capture 

detector (ECD), SIM Mode GC/MS, triple 

quad MS or GC/TOF MS to sub-ppb for 

volatile hydrocarbons collected over 72 hours 

followed by analysis using GC with 

quadrupole MS operated in the full SCAN 

mode. 

13.3.1 Actual detection limits for 

atmospheric monitoring vary depending on 

several key factors. These factors are: 

• Minimum artifact levels. 

• GC detector selection. 

• Time of exposure for passive sorbent 

tubes. 

• Selected analytical conditions, 

particularly column resolution and split 

ratio. 

14.0 Pollution Prevention 

This method involves the use of ambient 

concentrations of gaseous compounds that 

post little or no danger of pollution to the 

environment. 

15.0 Waste Management 

Dispose of expired calibration solutions as 

hazardous materials. Exercise standard 

laboratory environmental practices to 

minimize the use and disposal of laboratory 

solvents. 

16.0 References 

1. Winberry, W. T. Jr., et al., Determination 

of Volatile Organic Compounds in 

Ambient Air Using Active Sampling onto 

Sorbent Tubes: Method TO–17r, Second 

Edition, U.S. Environmental Protection 

Agency, Research Triangle Park, NC 

27711, January 1999. http://www.epa.

gov/ttnamti1/airtox.html#compendium 

2. Ciccioli, P., Brancaleoni, E., Cecinato, A., 

Sparapini, R., and Frattoni, M., 

‘‘Identification and Determination of 

Biogenic and Anthropogenic VOCs in 

Forest Areas of Northern and Southern 

Europe and a Remote Site of the 

Himalaya Region by High-resolution GC– 

MS,’’ J. of Chrom., 643, pp 55–69, 1993. 

3. McClenny, W.A., K.D. Oliver, H.H. 

Jacumin, Jr., E.H. Daughtrey, Jr., D.A. 

Whitaker. 2005. 24 h diffusive sampling 

of toxic VOCs in air onto CarbopackTM

X solid adsorbent followed by thermal 


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desorption/GC/MS analysis—laboratory 

studies. J. Environ. Monit. 7:248–256. 

4. Markes International (www.markes.com/

publications): Thermal desorption 

Technical Support Note 2: Prediction of 

uptake rates for diffusive tubes. 

5. Ciccioli, P., Brancaleoni, E., Cecinato, A., 

DiPalo, C., Brachetti, A., and Liberti, A., 

‘‘GC Evaluation of the Organic 

Components Present in the Atmosphere 

at Trace Levels with the Aid of 

CarbopackTM B for Preconcentration of 

the Sample,’’ J. of Chrom., 351, pp 433– 

449, 1986. 

6. Broadway, G. M., and Trewern, T., ‘‘Design 

Considerations for the Optimization of a 

Packed Thermal Desorption Cold Trap 

for Capillary Gas Chromatography,’’ 

Proc. 13th Int’l Symposium on Capil. 

Chrom., Baltimore, MD, pp 310–320, 

1991. 

7. Broadway, G. M., ‘‘An Automated System 

for use Without Liquid Cryogen for the 

Determination of VOC’s in Ambient 

Air,’’ Proc. 14th Int’l. Symposium on 

Capil. Chrom., Baltimore, MD, 1992. 

8. Gibitch, J., Ogle, L., and Radenheimer, P., 

‘‘Analysis of Ozone Precursor 

Compounds in Houston, Texas Using 

Automated Continuous GCs,’’ in 

Proceedings of the Air and Waste 

Management Association Conference: 

Measurement of Toxic and Related Air 

Pollutants, Air and Waste Management 

Association, Pittsburgh, PA, May 1995. 

9. Vandendriessche, S., and Griepink, B., 

‘‘The Certification of Benzene, Toluene 

and m-Xylene Sorbed on Tenax® TA in 

Tubes,’’ CRM–112 CEC, BCR, EUR12308 

EN, 1989. 

10. MDHS 2 (Acrylonitrile in Air), 

‘‘Laboratory Method Using Porous 

Polymer Adsorption Tubes, and Thermal 

Desorption with Gas Chromatographic 

Analysis,’’ Methods for the 

Determination of Hazardous Substances 

(MDHS), UK Health and Safety 

Executive, Sheffield, UK. 

11. MDHS 22 (Benzene in Air), ‘‘Laboratory 

Method Using Porous Polymer 

Adsorbent Tubes, Thermal Desorption 

and Gas Chromatography,’’ Method for 

the Determination of Hazardous 

Substances (MDHS), UK Health and 

Safety Executive, Sheffield, UK. 

12. MDHS 23 (Glycol Ether and Glycol 

Acetate Vapors in Air), ‘‘Laboratory 

Method Using Tenax® Sorbent Tubes, 

Thermal Desorption and Gas 

Chromatography,’’ Method for the 

Determination of Hazardous Substances 

(MDHS), UK Health and Safety 

Executive, Sheffield, UK. 

13. MDHS 40 (Toluene in air), ‘‘Laboratory 

Method Using Pumped Porous Polymer 

Adsorbent Tubes, Thermal Desorption 

and Gas Chromatography,’’ Method for 

the Determination of Hazardous 

Substances (MDHS), UK Health and 

Safety Executive, Sheffield, UK. 

14. MDHS 60 (Mixed Hydrocarbons (C to C) 

in Air), ‘‘Laboratory Method Using 

Pumped Porous Polymer 3 10 and 

Carbon Sorbent Tubes, Thermal 

Desorption and Gas Chromatography,’’ 

Method for the Determination of 

Hazardous Substances (MDHS), UK 

Health and Safety Executive, Sheffield, 

UK. 

15. Price, J. A., and Saunders, K. J., 

‘‘Determination of Airborne Methyl tertButyl Ether in Gasoline Atmospheres,’’ 

Analyst, Vol. 109, pp. 829–834, July 

1984. 

16. Coker, D. T., van den Hoed, N., Saunders, 

K. J., and Tindle, P. E., ‘‘A Monitoring 

Method for Gasoline Vapour Giving 

Detailed Composition,’’ Ann. Occup, 

Hyg., Vol 33, No. 11, pp 15–26, 1989. 

17. DFG, ‘‘Analytische Methoden zur prufing 

gesundheitsschadlicher Arbeistsstoffe,’’ 

Deutsche Forschungsgemeinschaft, 

Verlag Chemie, Weinheim FRG, 1985. 

18. NNI, ‘‘Methods in NVN Series 

(Luchtkwaliteit; Werkplekatmasfeer),’’ 

Nederlands Normailsatie—Institut, Delft, 

The Netherlands, 1986–88. 

19. ‘‘Sampling by Solid Adsorption 

Techniques,’’ Standards Association of 

Australia Organic Vapours, Australian 

Standard 2976, 1987. 

20. Woolfenden, E. A., ‘‘Monitoring VOCs in 

Air Using Pumped Sampling onto 

Sorbent Tubes Followed by Thermal 

Desorption-capillary GC Analysis: 

Summary of Reported Data and Practical 

Guidelines for Successful Application,’’ 

J. Air & Waste Manage. Assoc., Vol. 47, 

1997, pp. 20–36. 

21. Validation Guidelines for Air Sampling 

Methods Utilizing Chromatographic 

Analysis, OSHA T–005, Version 3.0, May 

2010, http://www.osha.gov/dts/sltc/

methods/chromguide/chromguide.pdf. 

22. ASTM D4597–10, Standard Practice for 

Sampling Workplace Atmospheres to 

collect Gases or Vapors with Solid 

Sorbent Diffusive Samplers. 

23. Martin, http://www.hsl.gov.uk/media/

1619/issue14.pdf. 

24. BS EN 14662–4:2005, Ambient air 

quality—Standard method for the 

measurement of benzene 

concentrations—Part 4: Diffusive 

sampling followed by thermal desorption 

and gas chromatography. 

25. ISO 16017–2:2003(E): Indoor, ambient 

and workplace air—Sampling and 

analysis of volatile organic compounds 

by sorbent tube/thermal desorption/

capillary gas chromatography—Part 2: 

Diffusive sampling. 

17.0 Tables, Diagrams, Flowcharts and 

Validation Data 

TABLE 17.1—SUMMARY OF GC/MS ANALYSIS QUALITY CONTROL PROCEDURES

Parameter Frequency Acceptance criteria Corrective action 

Bromofluorobenzene Instrument 

Tune Performance Check.

Dailya prior to sample analysis ..... Evaluation criteria presented in 

Section 9.5 and Table 9.2.

(1) Retune and or 

(2) Perform Maintenance. 

Five point calibration bracketing 

the expected sample concentration.

Following any major change, repair or maintenance or if daily 

CCV does not meet method requirements. Recalibration not to 

exceed three months.

(1) Percent Deviation (%DEV) of 

response factors ±30%.

(2) Relative Retention Times 

(RRTs) for target peaks ±0.06 

units from mean RRT.

(1) Repeat calibration sample 

analysis. 

(2) Repeat linearity check. 

(3) Prepare new calibration standards as necessary and repeat 

analysis. 

Calibration Verification (CCV Second source calibration 

verification check).

Following the calibration curve ..... The response factor ±30% DEV 

from calibration curve average 

response factor.

(1) Repeat calibration check. 

(2) Repeat calibration curve. 

Laboratory Blank Analysis ............. Daily a following bromofluoro- benzene and calibration check; 

prior to sample analysis.

(1) ≤0.2 ppbv per analyte or ≤3 

times the LOD, whichever is 

greater.

(2) Internal Standard (IS) area response ±40% and IS Retention 

Time (RT) ±0.33 min. of most 

recent calibration check.

(1) Repeat analysis with new 

blank tube. 

(2) Check system for leaks, contamination. 

3) Analyze additional blank. 

Blank Sorbent Tube Certification ... One tube analyzed for each batch 

of tubes cleaned or 10 percent 

of tubes whichever is greater.

<0.2 ppbv per VOC targeted compound or 3 times the LOD, 

whichever is greater.

Reclean all tubes in batch and reanalyze. 

Samples—Internal Standards ........ All samples ................................... IS area response ±40% and IS 

RT ±0.33 min. of most recent 

calibration validation.

Flag Data for possible invalidation. 

aEvery 24 hours. 


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Method 325 A/B 

EXAMPLE FIELD TEST DATA SHEET (FTDS) 

AND 

CHAIN OF CUSTODY 

I. GENERAL INFORMATION 

SITE NAME: 

SITE LOCATION ADDRESS: 

CITY: STATE: ZIP: 

II. SAMPLING DATA 

Sample Ambient ID Sample Barometric 

(Tube) or Start Start Stop Stop Location Temp. Pressure 

# Sorbent blank Date Time Date Time (gps) (oF) (in. Hg) 

III. CUSTODY INFORMATION 

COLLECTED BY: 

Relinquished to Shipper -

Name: Date: Time 

Received by Laboratory -

Name Date: Time 

Sample condition upon receipt: 

Analysis Required: 

Comments: 

Figure 17.1. Example Field Data From and Chain of Custody 
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SOrbentTube 

at Ambient 

Temperature 

T l···························r·················~······ ••• \ 

I ' l : : : : . : 

Cold 

M 1M Sorbeot 

JiiC * Focusing 

Trap 

• • 

•• 

: 

I 

I·····® 

I 

• * Split Flow Vent 

Closed 

• 

• • 

• * 

Desorb Flow Vent Closed 

GCAoalytical 

Column 

Pressure 

Transducer 

CarrierGas ---...-- Supplyln 

To Detector 

--Flow 

•··••··· Pressure, No Flow 

Figure 17.2. Schematic of Ther.mal Desorption Flow Path During 

Leak Testing 
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SorbentTube 

at Ambient 

Temperature 

Carrier Gas 

Supply In 

Pressurised Internal 

Standard (IS) Gas In 

SorbentTube 

at Ambient 

Temperature 

liiE liiE 

•• 

Cold 

Sorbent 

Focusing 

Trap 

Desorb Flow Vent Closed 

·····® 

Split Flow Vent 

Open (optional) 

GC Analytical 

Column 

Pressure 

Transducer 

(optional) CarrierGas;._ ___ , 

Supply In 

Cold * Sorbent 

Ill( Focu~il'lll ·····@ 

*Trap 

Ill 

• Split Flow Vent 

• 

• 

• 

GCAnalvtlcal 

Column 

Pressure 

Tran•duCIIr 

lQOetectcir 

--Flow 

•••••••• Pressure, No Flow 

To Detector 

--Flow 

Vent •••••••• Pressure, No Flow 

Desorb flow Vent Closlild Clrriet Gas 

Sopplyln ----' 

Figure 17.3. Schematic of Thermal Desorption Flow During Purge 

of Air (Top) and Addition of IS Gas to the Sorbent Tube (Bottom) 
75348 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 

BILLING CODE 6560–50–C 

ADDENDUM A to Method 325B—Method 

325 Performance Evaluation 

A.1 Scope and Application 

A.1.1 To be measured by Methods 325A 

and 325B, each new target volatile organic 

compound (VOC) or sorbent that is not listed 

in Table 12.1 must be evaluated by exposing 

the selected sorbent tube to a known 

concentration of the target compound(s) in an 

exposure chamber following the procedure in 

this Addendum or by following the 

procedures in the national/international 

standard methods: ISO 16017–2:2003(E), 


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Sorbent TUbe 

at Elevated 

Temperature 

Carrier Gas 

Supply in 

SorbentTube 

Coolin& 

I 

&Analytical 

Column 

j I'::\ Pressure r···\!:!1 Transducer 

! 

1 

Split Row Vent 

(Optional for Inlet 

Split) 

Desorb Aow Vent Open Carder Gas. ___ _. 

( ........................ . 

i 

Carrier Gas 

Supply in 

Supply In 

GCAnalytlcal 

Column 

SQrbent I'::\ Pressure 

FocuslngTrap ••••v:.:.~ Transducer 

at Elevated 

Temperature 

Split Aow Vent 

(Optional for 

Outlet Split) 

J !--··" 

To l:letector 

-Flow 

•••···•· Pressure, No Flow 

To l:letector 

--Flow 

•·•···•· Pressure, No Flow 

Figure 17.4. Schematic of Ther.mal Desorption Flow Path During 

Primary (Tube) Desorption (Top) and Secondary (Trap) Desorption 

and Transfer to the GC (Bottom) 
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75349 

ASTM D6196–03 (Reapproved 2009), or BS 

EN 14662–4:2005 (all incorporated by 

reference—see § 63.14), or reported in peerreviewed open literature. 

A.1.2 You must determine the uptake rate 

and the relative standard deviation compared 

to the theoretical concentration of volatile 

material in the exposure chamber for each of 

the tests required in this method. If data that 

meet the requirement of this Addendum are 

available in the peer reviewed open literature 

for VOCs of interest collected on your passive 

sorbent tube configuration, then such data 

may be submitted in lieu of the testing 

required in this Addendum. 

A.1.3 You must expose sorbent tubes in 

a test chamber to parts per trillion by volume 

(pptv) and low parts per billion by volume 

(ppbv) concentrations of VOCs in humid 

atmospheres to determine the sorbent tube 

uptake rate and to confirm compound 

capture and recovery. 

A.2 Summary of Method 

Note: The technique described here is one 

approach for determining uptake rates for 

new sorbent/sorbate pairs. It is equally valid 

to follow the techniques described in any one 

of the following national/international 

standards methods: ISO 16017–2:2003(E), 

ASTM D6196–03 (Reapproved 2009), or BS 

EN 14662–4:2005 (all incorporated by 

reference—see § 63.14). 

A.2.1 Known concentrations of VOC are 

metered into an exposure chamber 

containing sorbent tubes filled with media 

selected to capture the volatile organic 

compounds of interest (see Figure A.1 and 

A.2 for an example of the exposure chamber 

and sorbent tube retaining rack). VOC are 

diluted with humid air and the chamber is 

allowed to equilibrate for 6 hours. Clean 

passive sampling devices are placed into the 

chamber and exposed for a measured period 

of time. The passive uptake rate of the 

passive sampling devices is determined using 

the standard and dilution gas flow rates. 

Chamber concentrations are confirmed with 

whole gas sample collection and analysis or 

direct interface volatile organic compound 

measurement methods. 

A.2.2 An exposure chamber and known 

gas concentrations must be used to challenge 

and evaluate the collection and recovery of 

target compounds from the sorbent and tube 

selected to perform passive measurements of 

VOC in atmospheres. 

A.3 Definitions 

A.3.1 cc is cubic centimeter. 

A.3.2 ECD is electron capture detector. 

A.3.3 FID is flame ionization detector. 

A.3.4 LED is light-emitting diode. 

A.3.5 MFC is mass flow controller. 

A.3.6 MFM is mass flow meter. 

A.3.7 min is minute. 

A.3.8 ppbv is parts per billion by volume. 

A.3.9 ppmv is parts per million by 

volume. 

A.3.10 PSD is passive sampling device. 

A.3.11 psig is pounds per square inch 

gauge. 

A.3.12 RH is relative humidity. 

A.3.13 VOC is volatile organic 

compound. 

A.4 Interferences 

A.4.1 VOC contaminants in water can 

contribute interference or bias results high. 

Use only distilled, organic-free water for 

dilution gas humidification. 

A.4.2 Solvents and other VOC-containing 

liquids can contaminate the exposure 

chamber. Store and use solvents and other 

VOC-containing liquids in the exhaust hood 

when exposure experiments are in progress 

to prevent the possibility of contamination of 

VOCs into the chamber through the 

chamber’s exhaust vent. 

Note: Whenever possible, passive sorbent 

evaluation should be performed in a VOC 

free laboratory. 

A.4.3 PSDs should be handled by 

personnel wearing only clean, white cotton 

or powder free nitrile gloves to prevent 

contamination of the PSDs with oils from the 

hands. 

A.4.4 This performance evaluation 

procedure is applicable to only volatile 

materials that can be measured accurately 

with direct interface gas chromatography or 

whole gas sample collection, concentration 

and analysis. Alternative methods to confirm 

the concentration of volatile materials in 

exposure chambers are subject to 

Administrator approval. 

A.5 Safety 

A.5.1 This procedure does not address all 

of the safety concerns associated with its use. 

It is the responsibility of the user of this 

standard to establish appropriate field and 

laboratory safety and health practices and 

determine the applicability of regulatory 

limitations prior to use. 

A.5.2 Laboratory analysts must exercise 

appropriate care in working with highpressure gas cylinders. 

A.6 Equipment and Supplies 

A.6.1 You must use an exposure chamber 

of sufficient size to simultaneously expose a 

minimum of eight sorbent tubes. 

A.6.2 Your exposure chamber must not 

contain VOC that interfere with the 

compound under evaluation. Chambers made 

of glass and/or stainless steel have been used 

successfully for measurement of known 

concentration of selected VOC compounds. 

A.6.3 The following equipment and 

supplies are needed: 

• Clean, white cotton or nitrile gloves; 

• Conditioned passive sampling device 

tubes and diffusion caps; and 

• NIST traceable high resolution digital gas 

mass flow meters (MFMs) or flow controllers 

(MFCs). 

A.7 Reagents and Standards 

A.7.1 You must generate an exposure gas 

that contains between 35 and 75 percent 

relative humidity and a concentration of 

target compound(s) within 2 to 5 times the 

concentration to be measured in the field. 

A.7.2 Target gas concentrations must be 

generated with certified gas standards and 

diluted with humid clean air. Dilution to 

reach the desired concentration must be done 

with zero grade air or better. 

A.7.3 The following reagents and 

standards are needed: 

• Distilled water for the humidification; 

• VOC standards mixtures in high-pressure 

cylinder certified by the supplier (Note: The 

accuracy of the certified standards has a 

direct bearing on the accuracy of the 

measurement results. Typical vendor 

accuracy is ±5 percent accuracy but some 

VOC may only be available at lower accuracy 

(e.g., acrolein at 10 percent)); and 

• Purified dilution air containing less than 

0.2 ppbv of the target VOC. 

A.8 Sample Collection, Preservation and 

Storage 

A.8.1 You must use certified gas 

standards diluted with humid air. Generate 

humidified air by adding distilled organic 

free water to purified or zero grade air. 

Humidification may be accomplished by 

quantitative addition of water to the air 

dilution gas stream in a heated chamber or 

by passing purified air through a humidifying 

bubbler. You must control the relative 

humidity in the test gas throughout the 

period of passive sampler exposure. 

Note: The RH in the exposure chamber is 

directly proportional to the fraction of the 

purified air that passes through the water in 

the bubbler before entering the exposure 

chamber. Achieving uniform humidification 

in the proper range is a trial-and-error 

process with a humidifying bubbler. You 

may need to heat the bubbler to achieve 

sufficient humidity. An equilibration period 

of approximately 15 minutes is required 

following each adjustment of the air flow 

through the humidifier. Several adjustments 

or equilibration cycles may be required to 

achieve the desired RH level. 

Note: You will need to determine both the 

dilution rate and the humidification rate for 

your design of the exposure chamber by trial 

and error before performing method 

evaluation tests. 

A.8.2 Prepare and condition sorbent 

tubes following the procedures in Method 

325B Section 7.0. 

A.8.3 You must verify that the exposure 

chamber does not leak. 

A.8.4 You must complete two evaluation 

tests using a minimum of eight passive 

sampling tubes in each test with less than 5- 

percent depletion of test analyte by the 

samplers. 

A.8.4.1 Perform at least one evaluation at 

two to five times the estimated analytical 

detection limit or less. 

A.8.4.2 Perform second evaluation at a 

concentration equivalent to the middle of the 

analysis calibration range. 

A.8.5 You must evaluate the samplers in 

the test chamber operating between 35 

percent and 75 percent RH, and at 25 ± 5 °C. 

Allow the exposure chamber to equilibrate 

for 6 hours before starting an evaluation. 

A.8.6 The flow rate through the chamber 

must be ≤0.5 meter per second face velocity 

across the sampler face. 

A.8.7 Place clean, ready to use sorbent 

tubes into the exposure chamber for 

predetermined amounts of time to evaluate 

collection and recovery from the tubes. The 

exposure time depends on the concentration 

of volatile test material in the chamber and 

the detection limit required for the sorbent 

tube sampling application. Exposure time 


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should match sample collection time. The 

sorbent tube exposure chamber time may not 

be less than 24 hours and should not be 

longer than 2 weeks. 

A.8.7.1 To start the exposure, place the 

clean PSDs equipped with diffusion caps on 

the tube inlet into a retaining rack. 

A.8.7.2 Place the entire retaining rack 

inside the exposure chamber with the 

diffusive sampling end of the tubes facing 

into the chamber flow. Seal the chamber and 

record the exposure start time, chamber RH, 

chamber temperature, PSD types and 

numbers, orientation of PSDs, and volatile 

material mixture composition (see Figure 

A.2). 

A.8.7.3 Diluted, humidified target gas 

must be continuously fed into the exposure 

chamber during cartridge exposure. Measure 

the flow rate of target compound standard gas 

and dilution air to an accuracy of 5 percent. 

A.8.7.4 Record the time, temperature, and 

RH at the beginning, middle, and end of the 

exposure time. 

A.8.7.5 At the end of the exposure time, 

remove the PSDs from the exposure chamber. 

Record the exposure end time, chamber RH, 

and temperature. 

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Figure A.l. Example Sorbent Tube Exposure Chamber 
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BILLING CODE 6560–50–C 

A.9 Quality Control 

A.9.1 Monitor and record the exposure 

chamber temperature and RH during PSD 

exposures. 

A.9.2 Measure the flow rates of standards 

and purified humified air immediately 

following PSD exposures. 

A.10 Calibration and Standardization 

A.10.1 Follow the procedures described 

in Method 325B Section 10.0 for calibration. 

A.10.2 Verify chamber concentration by 

direct injection into a gas chromatograph 

calibrated for the target compound(s) or by 

collection of an integrated SUMMA canister 

followed by analysis using a 

preconcentration gas chromatographic 

method such as EPA Compendium Method 

TO–15, Determination of VOCs in Air 

Collected in Specially-Prepared Canisters 

and Analyzed By GC/MS. 

A.10.2.1 To use direct injection gas 

chromatography to verify the exposure 

chamber concentration, follow the 

procedures in Method 18 of 40 CFR part 60, 

Appendix A–6. The method ASTM D6420– 

99 (Reapproved 2010) (incorporated by 

reference—see § 63.14) is an acceptable 

alternative to EPA Method 18 of 40 CFR part 

60). 

Note: Direct injection gas chromatography 

may not be sufficiently sensitive for all 

compounds. Therefore, the whole gas 

preconcentration sample and analysis 

method may be required to measure at low 

concentrations. 

A.10.2.2 To verify exposure chamber 

concentrations using SUMMA canisters, 


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prepare clean canister(s) and measure the 

concentration of VOC collected in an 

integrated SUMMA canister over the period 

used for the evaluation (minimum 24 hours). 

Analyze the TO–15 canister sample following 

EPA Compendium Method TO–15. 

A.10.2.3 Compare the theoretical 

concentration of volatile material added to 

the test chamber to the measured 

concentration to confirm the chamber 

operation. Theoretical concentration must 

agree with the measured concentration 

within 30 percent. 

A.11 Analysis Procedure 

Analyze the sorbent tubes following the 

procedures described in Section 11.0 of 

Method 325B. 

A.12 Recordkeeping Procedures for 

Sorbent Tube Evaluation 

Keep records for the sorbent tube 

evaluation to include at a minimum the 

following information: 

A.12.1 Sorbent tube description and 

specifications. 

A.12.2 Sorbent material description and 

specifications. 

A.12.3 Volatile analytes used in the 

sampler test. 

A.12.4 Chamber conditions including 

flow rate, temperature, and relative humidity. 

A.12.5 Relative standard deviation of the 

sampler results at the conditions tested. 

A.12.6 95 percent confidence limit on the 

sampler overall accuracy. 

A.12.7 The relative accuracy of the 

sorbent tube results compared to the direct 

chamber measurement by direct gas 

chromatography or SUMMA canister 

analysis. 

A.13 Method Performance 

A.13.1 Sorbent tube performance is 

acceptable if the relative accuracy of the 

passive sorbent sampler agrees with the 

active measurement method by ±10 percent 

at the 95 percent confidence limit and the 

uptake ratio is equal to greater than 0.5 mL/ 

min (1 ng/ppm-min). 

Note: For example, there is a maximum 

deviation comparing Perkin-Elmer passive 

type sorbent tubes packed with CarbopackTM

X of 1.3 to 10 percent compared to active 

sampling using the following uptake rates. 

1,3-butadiene 

uptake rate 

mL/min 

Estimated 

detection limit 

(2 week) 

Benzene 

uptake rates 

mL/min 

Estimated 

detection limit 

(2 week) 

CarbopackTM X (2 week) ......................................................... 0.61 ± 0.11 a 0.1 ppbv 0.67 a 0.05 ppbv 

a McClenny, W.A., K.D. Oliver, H.H. Jacumin, Jr., E.H. Daughtrey, Jr., D.A. Whitaker. 2005. 24 h diffusive sampling of toxic VOCs in air onto 

CarbopackTM X solid adsorbent followed by thermal desorption/GC/MS analysis—laboratory studies. J. Environ. Monit. 7:248–256. 

A13.2 Data Analysis and Calculations for 

Method Evaluation 

A.13.2.1 Calculate the theoretical 

concentration of VOC standards using 

Equation A.1. 

Where: 

Cf = The final concentration of standard in 

the exposure chamber (ppbv). 

FRi = The flow rate of the target compound 

I (mL/min). 

FRt = The flow rate of all target compounds 

from separate if multiple cylinders are 

used (mL/min). 

FRa = The flow rate of dilution air plus 

moisture (mL/min). 

Cs = The concentration of target compound 

in the standard cylinder (parts per 

million by volume). 

A.13.2.3 Determine the uptake rate of the 

target gas being evaluated using Equation 

A.2. 

Where: 

Mx = The mass of analyte measured on the 

sampling tube (hg). 

Ce = The theoretical exposure chamber 

concentration (hg/mL). 

Tt = The exposure time (minutes). 

A.13.2.4 Estimate the variance (relative 

standard deviation (RSD)) of the intersampler results at each condition tested using 

Equation A.3. RSD for the sampler is 

estimated by pooling the variance estimates 

from each test run. 

Where: 

Xi = The measured mass of analyte found on 

sorbent tube i. 

Xi = The mean value of all Xi. 

n = The number of measurements of the 

analyte. 

A.13.2.4 Determine the percent relative 

standard deviation of the inter-sampler 

results using Equation A.4. 


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A.13.2.5 Determine the 95 percent 

confidence interval for the sampler results 

using Equation A.5. The confidence interval 

is determined based on the number of test 

runs performed to evaluate the sorbent tube 

and sorbent combination. For the minimum 

test requirement of eight samplers tested at 

two concentrations, the number of tests is 16 

and the degrees of freedom are 15. 

Where: 

D95% = 95 percent confidence interval. 

%RSD = percent relative standard deviation. 

t0.95 = The Students t statistic for f degrees 

of freedom at 95 percent confidence. 

f = The number of degrees of freedom. 

n = Number of samples. 

A.13.2.6 Determine the relative accuracy 

of the sorbent tube combination compared to 

the active sampling results using Equation 

A.6. 

Where: 

RA = Relative accuracy. 

Xi = The mean value of all Xi. 

Xi = The average concentration of analyte 

measured by the active measurement 

method. 

D95% = 95 percent confidence interval. 

A.14 Pollution Prevention 

This method involves the use of ambient 

concentrations of gaseous compounds that 

post little or no pollution to the environment. 

A.15 Waste Management 

Expired calibration solutions should be 

disposed of as hazardous materials. 

A.16 References 

1. ISO TC 146/SC 02 N 361 Workplace 

atmospheres—Protocol for evaluating the 

performance of diffusive samplers. 

[FR Doc. 2015–26486 Filed 11–30–15; 8:45 am] 

BILLING CODE 6560–50–P 


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