From: Higgins, Cortney <Cortney_Higgins@omb.eop.gov> 

Sent: Wednesday, May 14, 2014 5:09 PM 

To: Lassiter, Penny; Shine, Brenda 

Cc: Thundiyil, Karen 

Subject: A few final edits on the Petroleum Refinery RTR 

Hi Penny and Brenda, 

Attached are two additional comments in redline that I’ve received on the draft. Additionally, can 

you take one last look at the package and make sure you use consistent language for the fenceline 

monitoring “concentration action level.” You’ve also used “action trigger level,” “trigger benzene 

concentration,” and maybe other terms -- potentially introducing confusion. 

Regards, 

Cortney 

<< RefineryRTR_2060_AQ75_NPRM_RTR_20140514_comments.docx >> 
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6560-50-P 

EO-12866_Refinery RTR 2060-AQ-75 NPRM_20140514 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Parts 60 and 63 

[EPA-HQ-OAR-2010-0682; FRL-9720-4] 

RIN 2060-AQ75 

Petroleum Refinery Sector Risk and Technology Review and New 

Source Performance Standards 

AGENCY: Environmental Protection Agency. 

ACTION: Proposed rule. 

SUMMARY: This action proposes amendments to the national 

emission standards for hazardous air pollutants for petroleum 

refineries (40 CFR part 63, subparts CC and UUU) to address the 

risk remaining after application of the standards promulgated in 

1995 and 2002. This action also proposes amendments to the 

national emission standards for hazardous air pollutants for 

petroleum refineries based on the results of the Environmental 

Protection Agency (EPA) review of developments in practices, 

processes and control technologies and includes new monitoring, 

recordkeeping and reporting requirements. The EPA is also 

proposing new requirements related to emissions during periods 

of startup, shutdown and malfunction to ensure that the 

standards are consistent with court opinions issued since 

promulgation of the standards. This action also proposes 
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technical corrections and clarifications for new source 

performance standards for petroleum refineries (40 CFR part 60, 

subparts J and Ja) to improve consistency and clarity and 

address issues raised after the 2008 rule promulgation. 

Implementation of this proposed rule will result in projected 

reductions of 1,760 tons per year (tpy) of hazardous air 

pollutants (HAP), which will reduce cancer risk and chronic 

health effects. 

DATES: Comments. Comments must be received on or before [INSERT 

DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

A copy of comments on the information collection provisions 

should be submitted to the Office of Management and Budget (OMB) 

on or before [INSERT DATE 30 DAYS AFTER DATE OF PUBLICATION IN 

THE FEDERAL REGISTER]. 

Public Hearing. The EPA will be holding public hearings on this 

proposed rule on DATES at LOCATION and CITY. 

ADDRESSES: Comments. Submit your comments, identified by Docket 

ID Number EPA-HQ-OAR-2010-0682, by one of the following methods: 

 http://www.regulations.gov: Follow the on-line instructions 

for submitting comments. 

 Email: a-and-r-docket@epa.gov. Attention Docket ID Number 

EPA-HQ-OAR-2010-0682. 
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 Fax: (202) 566-9744. Attention Docket ID Number EPA-HQ-OAR2010-0682. 

 Mail: U.S. Postal Service, send comments to: EPA Docket 

Center, William Jefferson Clinton (WJC) West Building (Air 

Docket), Attention Docket ID Number EPA-HQ-OAR-2010-0682, 

U.S. Environmental Protection Agency, Mailcode: 28221T, 

1200 Pennsylvania Ave., NW, Washington, DC 20460. Please 

include a total of two copies. In addition, please mail a 

copy of your comments on the information collection 

provisions to the Office of Information and Regulatory 

Affairs, Office of Management and Budget (OMB), Attn: Desk 

Officer for EPA, 725 17th Street, NW, Washington, DC 20503. 

 Hand Delivery: U.S. Environmental Protection Agency, WJC 

West Building (Air Docket), Room 3334, 1301 Constitution 

Ave., NW, Washington, DC 20004. Attention Docket ID Number 

EPA-HQ-OAR-2010-0682. Such deliveries are only accepted 

during the Docket’s normal hours of operation, and special 

arrangements should be made for deliveries of boxed 

information. 

Instructions. Direct your comments to Docket ID Number EPAHQ-OAR-2010-0682. The EPA’s policy is that all comments received 

will be included in the public docket without change and may be 

made available online at http://www.regulations.gov, including 
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any personal information provided, unless the comment includes 

information claimed to be confidential business information 

(CBI) or other information whose disclosure is restricted by 

statute. Do not submit information that you consider to be CBI 

or otherwise protected through http://www.regulations.gov or 

email. The http://www.regulations.gov website is an “anonymous 

access” system, which means the EPA will not know your identity 

or contact information unless you provide it in the body of your 

comment. If you send an email comment directly to the EPA 

without going through http://www.regulations.gov, your email 

address will be automatically captured and included as part of 

the comment that is placed in the public docket and made 

available on the Internet. If you submit an electronic comment, 

the EPA recommends that you include your name and other contact 

information in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, 

the EPA may not be able to consider your comment. Electronic 

files should not include special characters or any form of 

encryption and be free of any defects or viruses. For additional 

information about the EPA’s public docket, visit the EPA Docket 

Center homepage at: http://www.epa.gov/dockets. 

Docket. The EPA has established a docket for this 

rulemaking under Docket ID Number EPA-HQ-OAR-2010-0682. All 
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documents in the docket are listed in the regulations.gov index. 

Although listed in the index, some information is not publicly 

available, e.g., 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. Publicly available docket 

materials are available either electronically in regulations.gov 

or in hard copy at the EPA Docket Center, WJC West Building, 

Room 3334, 1301 Constitution Ave., NW, Washington, DC. The 

Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal holidays. The telephone number 

for the Public Reading Room is (202) 566-1744, and the telephone 

number for the EPA Docket Center is (202) 566-1742. 

Public Hearing. The public hearing will be held on [INSERT 

DATE] at [INSERT LOCATION, ADDRESS, ROOM NUMBER IF AVAILABLE]. 

The hearing will convene at [INSERT TIME] XXX a.m. (Eastern 

Standard Time) and end at [INSERT TIME] XXX p.m. (Eastern 

Standard Time). A lunch break will be held from [INSERT TIME] 

XXX pm. (Eastern Standard Time) until [INSERT TIME] XXX pm 

(Eastern Standard Time). Please contact Ms. Virginia Hunt at 

(919) 541-0832 or at hunt.virginia@epa.gov to register to speak 

at the hearing. The last day to pre-register in advance to speak 

at the hearing will be [INSERT DATE]. Additionally, requests to 

speak will be taken the day of the hearing at the hearing 
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registration desk, although preferences on speaking times may 

not be able to be fulfilled. If you require the service of a 

translator or special accommodations such as audio description, 

please let us know at the time of registration. 

FOR FURTHER INFORMATION: For questions about this proposed 

action, contact Ms. Brenda Shine, Sector Policies and Programs 

Division (E143-01), Office of Air Quality Planning and Standards 

(OAQPS), 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 (OAQPS), 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 National Emissions Standards for Hazardous 

Air Pollutants (NESHAP) or the New Source Performance Standards 

(NSPS) to a particular entity, contact Maria Malave, Office of 

Enforcement and Compliance Assurance (OECA), telephone number: 

(202) 564–7027; fax number: (202) 564–0050; and email address: 

malave.maria@epa.gov. 

SUPPLEMENTARY INFORMATION: 
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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 

ACGIH American Conference of Governmental Industrial 

Hygienists 

ADAF age-dependent adjustment factors 

AEGL acute exposure guideline levels 

AERMOD air dispersion model used by the HEM-3 model 

APCD air pollution control devices 

API American Petroleum Institute 

BDT best demonstrated technology 

BLD bag leak detectors 

BSER best system of emission reduction 

Btu/ft2

 British thermal units per square foot 

Btu/scf British thermal units per standard cubic foot 

CAA Clean Air Act 

CalEPA California EPA 

CBI confidential business information 

CCU catalytic cracking units 

Ccz combustion zone combustibles concentration 

CDDF chlorinated dibenzodioxins and furans 

CDX Central Data Exchange 

CEDRI Compliance and Emissions Data Reporting Interface 

CEMS continuous emissions 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 

CRU catalytic reforming units 

CS2 carbon disulfide 

DCU delayed coking units 

DIAL differential absorption light detection and ranging 

EBU enhanced biological unit 

EPA Environmental Protection Agency 
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ERPG emergency response planning guidelines 

ERT Electronic Reporting Tool 

ESP electrostatic precipitator 

FCCU fluid catalytic cracking units 

FGCD fuel gas combustion devices 

FR Federal Register 

FTIR Fourier transform infrared spectroscopy 

g PM/kg grams particulate matter per kilogram 

GC gas chromatograph 

GHG greenhouse gases 

GPS global positioning system 

H2S hydrogen sulfide 

HAP hazardous air pollutants 

HCl hydrogen chloride 

HCN hydrogen cyanide 

HEM-3 Human Exposure Model, Version 1.1.0 

HF hydrogen fluoride 

HFC highest fenceline concentration 

HI hazard index 

HQ hazard quotient 

ICR Information Collection Request 

IRIS Integrated Risk Information System 

km kilometers 

lb/day pounds per day 

LDAR leak detection and repair 

LFL lower flammability limit 

LFLcz combustion zone lower flammability limit 

LMC lowest measured concentration 

LOAEL lowest-observed-adverse-effect level 

LTD long tons per day 

MACT maximum achievable control technology 

mg/kg-day milligrams per kilogram per day 

mg/L milligrams per liter 

mg/m3

 milligrams per cubic meter 

Mg/yr megagrams per year 

MFC measured fenceline concentration 

MFR momentum flux ratio 

MIR maximum individual risk 

mph miles per hour 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

NAS National Academy of Sciences 

NATA National Air Toxics Assessment 

NEI National Emissions Inventory 

NESHAP National Emissions Standards for Hazardous Air 

Pollutants 

NFS near-field interfering source 
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NHVcz combustion zone net heating value 

Ni nickel 

NIOSH National Institutes for Occupational Safety and 

Health 

NOAEL no-observed-adverse-effect level 

NOX nitrogen oxides 

NRC National Research Council 

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 

OMB Office of Management and Budget 

OSC off-site source contribution 

OTM other test method 

PAH polycyclic aromatic hydrocarbons 

PB-HAP hazardous air pollutants known to be persistent and 

bio-accumulative in the environment 

PBT persistent, bioaccumulative, and toxic 

PCB polychlorinated biphenyls 

PEL probable effect level 

PM particulate matter 

PM2.5 particulate matter 2.5 micrometers in diameter and 

smaller 

POM polycyclic organic matter 

ppm parts per million 

ppmv parts per million by volume 

ppmw parts per million by weight 

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 

RfC reference concentration 

RfD reference dose 

RTR residual risk and technology review 

SAB Science Advisory Board 

SBA Small Business Administration 

SBAR Small Business Advocacy Review 

SCR selective catalytic reduction 

SISNOSE significant economic impact on a substantial number 

of small entities 

S/L/Ts state, local and tribal air pollution control 

agencies 

SO2 sulfur dioxide 

SRU sulfur recovery unit 

SSM startup, shutdown and malfunction 
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STEL short-term exposure limit 

TEQ toxicity equivalent 

TLV threshold limit value 

TOC total organic carbon 

TOSHI target organ-specific hazard index 

tpy tons per year 

TRIM.FaTE Total Risk Integrated Methodology.Fate, Transport, 

and Ecological Exposure model 

TTN Technology Transfer Network 

UB uniform background 

UF uncertainty factor 

UMRA Unfunded Mandates Reform Act 

URE unit risk estimate 

UV-DOAS ultraviolet differential optical absorption 

spectroscopy 

VCS voluntary consensus standards 

VOC volatile organic compounds 

WJC William Jefferson Clinton 

°F degrees Fahrenheit 

ΔC the concentration difference between the highest 

measured concentration and the lowest measured 

concentration 

μg/m3

 micrograms per cubic meter 

The EPA also defines the following abbreviations for 

regulations cited within this preamble: 

AWP Alternative Work Practice To Detect Leaks 

From Equipment (40 CFR 63.11(c), (d) and (e)) 

Benzene NESHAP National Emission Standards for Hazardous Air 

Pollutants: Benzene Emissions from Maleic 

Anhydride Plants, Ethylbenzene/Styrene 

Plants, Benzene Storage Vessels, Benzene 

Equipment Leaks, and Coke By-Product Recovery 

Plants (40 CFR part 61, subpart L as of 

publication in the Federal Register at 54 FR 

38044, September 14, 1989) 

BWON National Emission Standard for Benzene Waste 

Operations (40 CFR part 61, subpart FF) 

Generic MACT National Emission Standards for Storage 

Vessels (40 CFR part 63, subpart WW) 

HON National Emission Standards for Organic 

Hazardous Air Pollutants (40 CFR part 63, 

subparts F, G and H) 
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Marine Vessel MACT National Emission Standards for Marine Tank 

Vessel Loading Operations (40 CFR part 63, 

subpart Y) 

Refinery MACT 1 National Emission Standards for Hazardous Air 

Pollutants From Petroleum Refineries (40 CFR 

part 63, subpart CC) 

Refinery MACT 2 National Emission Standards for Hazardous Air 

Pollutants for Petroleum Refineries: 

Catalytic Cracking Units, Catalytic Reforming 

Units, and Sulfur Recovery Units (40 CFR part 

63, subpart UUU) 

Refinery NSPS J Standards of Performance for Petroleum 

Refineries (40 CFR part 60, subpart J) 

Refinery NSPS Ja Standards of Performance for Petroleum 

Refineries for which Construction, 

Reconstruction, or Modification Commenced 

After May 14, 2007 (40 CFR part 60, subpart 

Ja) 

Organization of This Document. The information in 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. What should I consider as I prepare my comments for the EPA? 

D. Public Hearing 

II. Background 

A. What is the statutory authority for this action? 

B. What are the source categories and how do the NESHAP and NSPS 

regulate emissions? 

C. What data collection activities were conducted to support 

this action? 

D. What other relevant background information and data are 

available? 

III. Analytical Procedures 

A. How did we estimate post-MACT risks posed by the source 

categories? 

B. How did we consider the risk results in making decisions for 

this proposal? 

C. How did we perform the technology review? 

IV. Analytical Results and Proposed Decisions 
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A. What actions are we taking pursuant to CAA sections 112(d)(2) 

and 112(d)(3)? 

B. What are the results and proposed decisions based on our 

technology review? 

C. What are the results of the risk assessment and analyses? 

D. What are our proposed decisions regarding risk acceptability, 

ample margin of safety and adverse environmental effects? 

E. What other actions are we proposing? 

F. What compliance dates are we proposing? 

V. Summary of Cost, Environmental and Economic Impacts 

A. What are the affected sources, the air quality impacts and 

cost impacts? 

B. What are the economic impacts? 

C. What are the benefits? 

VI. Request for Comments 

VII. Submitting Data Corrections 

VIII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

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 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

A redline version of the regulatory language that 

incorporates the proposed changes in this action is available in 

the docket for this action (Docket ID No. EPA-HQ-OAR-2010-0682). 
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I. General Information 

A. Does this action apply to me? 

Table 1 of this preamble lists the industries that are the 

subject of this proposal. Table 1 is not intended to be 

exhaustive but rather to provide a guide for readers regarding 

the entities that this proposed action is likely to affect. 

These proposed standards, once promulgated, will be directly 

applicable to the affected sources. Thus, federal, state, local 

and tribal government entities would not be affected by this 

proposed action. As defined in the “Initial List of Categories 

of Sources Under Section 112(c)(1) of the Clean Air Act 

Amendments of 1990” (see 57 FR 31576, July 16, 1992), the 

“Petroleum Refineries - Catalytic Cracking (Fluid and other) 

Units, Catalytic Reforming Units, and Sulfur Plant Units” source 

category and the “Petroleum Refineries - Other Sources Not 

Distinctly Listed” both consist of any facility engaged in 

producing gasoline, naphthas, kerosene, jet fuels, distillate 

fuel oils, residual fuel oils, lubricants, or other products 

from crude oil or unfinished petroleum derivatives. The first of 

these source categories includes process vents associated with 

the following refinery process units: catalytic cracking (fluid 

and other) units, catalytic reforming units and sulfur plant 

units. The second source category includes all emission sources 

associated with refinery process units except the process vents 
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listed in the Petroleum Refineries – Catalytic Cracking (Fluid 

and Other) Units, Catalytic Reforming Units, and Sulfur Plant 

Units Source Category. The emission sources included in this 

source category include, but are not limited to, miscellaneous 

process vents (vents other than those listed in Petroleum 

Refineries – Catalytic Cracking (Fluid and Other) Units, 

Catalytic Reforming Units, and Sulfur Plant Units Source 

Category), equipment leaks, storage vessels, wastewater, 

gasoline loading, marine vessel loading, and heat exchange 

systems. 

Table 1. Industries Affected by this Proposed Action 

Industry 

NAICSa

Code Examples of Regulated Entities 

Petroleum Refining 

Industry 

324110 Petroleum refinery sources that 

are subject to 40 CFR part 60, 

subpart J and Ja and 40 CFR part 

63, subparts CC and UUU a

 North American Industry Classification System 

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 action is available on the Internet through the 

EPA’s Technology Transfer Network (TTN) website, 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 proposed action on the TTN’s 
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policy and guidance page for newly proposed or promulgated rules 

at: http://www.epa.gov/ttn/oarpg/t3pfpr.html. Following 

publication in the Federal Register, the EPA will post the 

Federal Register version of the proposal and key technical 

documents on the project website: 

http://www.epa.gov/ttn/atw/petref.html. Information on the 

overall residual risk and technology review (RTR) program is 

available at the following website: 

http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. 

C. What should I consider as I prepare my comments for the EPA? 

Submitting CBI. Do not submit information containing CBI to 

the EPA through http://www.regulations.gov or email. Clearly 

mark the part or all of the information that you claim to be 

CBI. For CBI information on a disk or CD-ROM that you mail to 

the EPA, mark the outside of the disk or CD-ROM as CBI and then 

identify electronically within the disk or CD-ROM the specific 

information that is claimed as CBI. In addition to one complete 

version of the comments that includes information claimed as 

CBI, you must submit a copy of the comments that does not 

contain the information claimed as CBI for inclusion in the 

public docket. If you submit a CD-ROM or disk that does not 

contain CBI, mark the outside of the disk or CD-ROM clearly that 

it does not contain CBI. Information not marked as CBI will be 

included in the public docket and the EPA’s electronic public 
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docket without prior notice. Information marked as CBI will not 

be disclosed except in accordance with procedures set forth in 

40 Code of Federal Regulations (CFR) part 2. Send or deliver 

information identified as CBI only to the following address: 

Roberto Morales, OAQPS Document Control Officer (C404-02), 

OAQPS, U.S. Environmental Protection Agency, Research Triangle 

Park, North Carolina 27711, Attention Docket ID Number EPA-HQOAR-2010-0682. 

D. Public Hearing 

The hearing will provide interested parties the opportunity 

to present data, views or arguments concerning the proposed 

action. The EPA will make every effort to accommodate all 

speakers who arrive and register. Because this hearing will be 

at a U.S. governmental facility, individuals planning to attend 

the hearing should be prepared to show valid picture 

identification to the security staff in order to gain access to 

the meeting room. In addition, you will need to obtain a 

property pass for any personal belongings you bring with you. 

Upon leaving the building, you will be required to return this 

property pass to the security desk. No large signs will be 

allowed in the building, cameras may only be used outside of the 

building and demonstrations will not be allowed on federal 

property for security reasons. The EPA may ask clarifying 

questions during the oral presentations but will not respond to 
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the presentations at that time. Written statements and 

supporting information submitted during the comment period will 

be considered with the same weight as oral comments and 

supporting information presented at the public hearing. Written 

comments on the proposed rule must be postmarked by [INSERT DATE 

60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

Commenters should notify Ms. Virginia Hunt if they will need 

specific equipment, or if there are other special needs related 

to providing comments at the hearing. The EPA will provide 

equipment for commenters to show overhead slides or make 

computerized slide presentations if we receive special requests 

in advance. Oral testimony will be limited to 5 minutes for each 

commenter. The EPA encourages commenters to provide the EPA with 

a copy of their oral testimony electronically (via email or CD) 

or in hard copy form. Verbatim transcripts of the hearings and 

written statements will be included in the docket for the 

rulemaking. The EPA will make every effort to follow the 

schedule as closely as possible on the day of the hearing; 

however, please plan for the hearing to run either ahead of 

schedule or behind schedule. Information regarding the hearing 

will be available at: 

http://www.epa.gov/ttnatw01/petrefine/petrefpg.html. 
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II. Background 

A. What is the statutory authority for this action? 

1. NESHAP 

Section 112 of the Clean Air Act (CAA) establishes a twostage regulatory process to address emissions of HAP from 

stationary sources. In the first stage, after the EPA has 

identified categories of sources emitting one or more of the HAP 

listed in CAA section 112(b), CAA section 112(d) requires us to 

promulgate technology-based national emissions standards for 

hazardous air pollutants (NESHAP) for those sources. “Major 

sources” are those that emit or have the potential to emit 10 

tpy or more of a single HAP or 25 tpy or more of any combination 

of HAP. For major sources, the technology-based NESHAP must 

reflect the maximum degree of emissions reductions of HAP 

achievable (after considering cost, energy requirements and nonair quality health and environmental impacts) and are commonly 

referred to as maximum achievable control technology (MACT) 

standards. 

MACT standards must reflect the maximum degree of emissions 

reduction achievable through the application of measures, 

processes, methods, systems or techniques, including, but not 

limited to, measures that (1) reduce the volume of or eliminate 

pollutants through process changes, substitution of materials or 

other modifications; (2) enclose systems or processes to 
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eliminate emissions; (3) capture or treat pollutants when 

released from a process, stack, storage or fugitive emissions 

point; (4) are design, equipment, work practice or operational 

standards (including requirements for operator training or 

certification); or (5) are a combination of the above. CAA 

section 112(d)(2)(A)-(E). The MACT standards may take the form 

of design, equipment, work practice or operational standards 

where the EPA first determines either that (1) a pollutant 

cannot be emitted through a conveyance designed and constructed 

to emit or capture the pollutant, or that any requirement for, 

or use of, such a conveyance would be inconsistent with law; or 

(2) the application of measurement methodology to a particular 

class of sources is not practicable due to technological and 

economic limitations. CAA section 112(h)(1)-(2). 

The MACT “floor” is the minimum control level allowed for 

MACT standards promulgated under CAA section 112(d)(3) and may 

not be based on cost considerations. For new sources, the MACT 

floor cannot be less stringent than the emissions control that 

is achieved in practice by the best-controlled similar source. 

The MACT floor for existing sources can be less stringent than 

floors for new sources but not less stringent than the average 

emissions limitation achieved by the best-performing 12 percent 

of existing sources in the category or subcategory (or the bestperforming five sources for categories or subcategories with 
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fewer than 30 sources). In developing MACT standards, the EPA 

must also consider control options that are more stringent than 

the floor. We may establish standards more stringent than the 

floor based on considerations of the cost of achieving the 

emission reductions, any non-air quality health and 

environmental impacts and energy requirements. 

The EPA is then required to review these 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. CAA section 

112(d)(6). In conducting this review, the EPA is not required to 

recalculate the MACT floor. Natural Resources Defense Council 

(NRDC) v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008). Association 

of Battery Recyclers, Inc. v. EPA, 716 F.3d 667 (D.C. Cir. 

2013). 

The second stage in standard-setting focuses on reducing 

any remaining (i.e., “residual”) risk according to CAA section 

112(f). Section 112(f)(1) required that the EPA by November 1996 

prepare a report to Congress discussing (among other things) 

methods of calculating the risks posed (or potentially posed) by 

sources after implementation of the MACT standards, the public 

health significance of those risks and the EPA’s recommendations 

as to legislation regarding such remaining risk. The EPA 

prepared and submitted the Residual Risk Report to Congress, 
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EPA–453/R–99–001 (Risk Report) in March 1999. CAA section 

112(f)(2) then provides that if Congress does not act on any 

recommendation in the Risk Report, the EPA must analyze and 

address residual risk for each category or subcategory of 

sources 8 years after promulgation of such standards pursuant to 

CAA section 112(d). 

Section 112(f)(2) of the CAA requires the EPA to determine 

for source categories subject to MACT standards whether the 

emission standards provide an ample margin of safety to protect 

public health. Section 112(f)(2)(B) of the CAA expressly 

preserves the EPA’s use of the two-step process for developing 

standards to address any residual risk and the agency’s 

interpretation of “ample margin of safety” developed in the 

National Emissions Standards for Hazardous Air Pollutants: 

Benzene Emissions from Maleic Anhydride Plants, 

Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene 

Equipment Leaks, and Coke By-Product Recovery Plants (Benzene 

NESHAP) (54 FR 38044, September 14, 1989). The EPA notified 

Congress in the Risk Report that the agency intended to use the 

Benzene NESHAP approach in making CAA section 112(f) residual 

risk determinations (EPA–453/R–99–001, p. ES–11). The EPA 

subsequently adopted this approach in its residual risk 

determinations and in a challenge to the risk review for the 

Synthetic Organic Chemical Manufacturing source category, the 
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United States Court of Appeals for the District of Columbia 

Circuit upheld as reasonable the EPA’s interpretation that 

subsection 112(f)(2) incorporates the standards established in 

the Benzene NESHAP. See NRDC v. EPA, 529 F.3d 1077, 1083 (D.C. 

Cir. 2008)(“[S]ubsection 112(f)(2)(B) expressly incorporates the 

EPA’s interpretation of the Clean Air Act from the Benzene 

standard, complete with a citation to the Federal Register.”); 

see also A Legislative History of the Clean Air Act Amendments 

of 1990, vol. 1, p. 877 (Senate debate on Conference Report). 

The first step in the process of evaluating residual risk 

is the determination of acceptable risk. If risks are 

unacceptable, the EPA cannot consider cost in identifying the 

emissions standards necessary to bring risks to an acceptable 

level. The second step is the determination of whether standards 

must be further revised in order to provide an ample margin of 

safety to protect public health. The ample margin of safety is 

the level at which the standards must be set, unless an even 

more stringent standard is necessary to prevent, taking into 

consideration costs, energy, safety and other relevant factors, 

an adverse environmental effect. 

a. Step 1-Determining Acceptability 

The agency in the Benzene NESHAP concluded “that the 

acceptability of risk under section 112 is best judged on the 

basis of a broad set of health risk measures and information” 
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and that the “judgment on acceptability cannot be reduced to any 

single factor.” Id. at 38046. The determination of what 

represents an “acceptable” risk is based on a judgment of “what 

risks are acceptable in the world in which we live” (Risk Report 

at 178, quoting NRDC v. EPA, 824 F. 2d 1146, 1165 (D.C. Cir. 

1987) (en banc) (“Vinyl Chloride”), recognizing that our world 

is not risk-free. 

In the Benzene NESHAP, we stated that “EPA will generally 

presume that if the risk to [the maximum exposed] individual is 

no higher than approximately one in 10 thousand, that risk level 

is considered acceptable.” 54 FR at 38045, September 14, 1989. 

We discussed the maximum individual lifetime cancer risk (or 

maximum individual risk (MIR)) as being “the estimated risk that 

a person living near a plant would have if he or she were 

exposed to the maximum pollutant concentrations for 70 years.” 

Id. We explained that this measure of risk “is an estimate of 

the upper bound of risk based on conservative assumptions, such 

as continuous exposure for 24 hours per day for 70 years.” Id. 

We acknowledged that maximum individual lifetime cancer risk 

“does not necessarily reflect the true risk, but displays a 

conservative risk level which is an upper-bound that is unlikely 

to be exceeded.” Id. 

Understanding that there are both benefits and limitations 

to using the MIR as a metric for determining acceptability, we 
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acknowledged in the Benzene NESHAP that “consideration of 

maximum individual risk * * * must take into account the 

strengths and weaknesses of this measure of risk.” Id. 

Consequently, the presumptive risk level of 100-in-1 million (1-

in-10 thousand) provides a benchmark for judging the 

acceptability of maximum individual lifetime cancer risk, but 

does not constitute a rigid line for making that determination. 

Further, in the Benzene NESHAP, we noted that: 

“[p]articular attention will also be accorded to the weight 

of evidence presented in the risk assessment of potential 

carcinogenicity or other health effects of a pollutant. 

While the same numerical risk may be estimated for an 

exposure to a pollutant judged to be a known human 

carcinogen, and to a pollutant considered a possible human 

carcinogen based on limited animal test data, the same 

weight cannot be accorded to both estimates. In considering 

the potential public health effects of the two pollutants, 

the Agency’s judgment on acceptability, including the MIR, 

will be influenced by the greater weight of evidence for 

the known human carcinogen.” 

Id. at 38046. The agency also explained in the Benzene NESHAP 

that: 

“[i]n establishing a presumption for MIR, rather than a 

rigid line for acceptability, the Agency intends to weigh 

it with a series of other health measures and factors. 

These include the overall incidence of cancer or other 

serious health effects within the exposed population, the 

numbers of persons exposed within each individual lifetime 

risk range and associated incidence within, typically, a 50 

km exposure radius around facilities, the science policy 

assumptions and estimation uncertainties associated with 

the risk measures, weight of the scientific evidence for 

human health effects, other quantified or unquantified 

health effects, effects due to co-location of facilities, 

and co-emission of pollutants.” 
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Id. at 38045. In some cases, these health measures and factors 

taken together may provide a more realistic description of the 

magnitude of risk in the exposed population than that provided 

by maximum individual lifetime cancer risk alone. 

As noted earlier, in NRDC v. EPA, the court held that 

section 112(f)(2) “incorporates the EPA’s interpretation of the 

Clean Air Act from the Benzene Standard.” The court further held 

that Congress’ incorporation of the Benzene standard applies 

equally to carcinogens and non-carcinogens. 529 F.3d at 1081-82. 

Accordingly, we also consider non-cancer risk metrics in our 

determination of risk acceptability and ample margin of safety. 

b. Step 2-Determination of Ample Margin of Safety 

CAA section 112(f)(2) requires the EPA to determine, for 

source categories subject to MACT standards, whether those 

standards provide an ample margin of safety to protect public 

health. As explained in the Benzene NESHAP, “the second step of 

the inquiry, determining an ‘ample margin of safety,’ again 

includes consideration of all of the health factors, and whether 

to reduce the risks even further.... Beyond that information, 

additional factors relating to the appropriate level of control 

will also be considered, including costs and economic impacts of 

controls, technological feasibility, uncertainties and any other 

relevant factors. Considering all of these factors, the agency 

will establish the standard at a level that provides an ample 
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margin of safety to protect the public health, as required by 

section 112.” 54 FR at 38046, September 14, 1989. 

According to CAA section 112(f)(2)(A), if the MACT 

standards for HAP “classified as a known, probable, or possible 

human carcinogen do not reduce lifetime excess cancer risks to 

the individual most exposed to emissions from a source in the 

category or subcategory to less than one in one million,” the 

EPA must promulgate residual risk standards for the source 

category (or subcategory), as necessary to provide an ample 

margin of safety to protect public health. In doing so, the EPA 

may adopt standards equal to existing MACT standards if the EPA 

determines that the existing standards (i.e., the MACT 

standards) are sufficiently protective. 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.”) The EPA must also adopt 

more stringent standards, if necessary, to prevent an adverse 

environmental effect,1

 but must consider cost, energy, safety and 

other relevant factors in doing so. 

 

1

 “Adverse environmental effect” is defined as any significant and widespread 

adverse effect, which may be reasonably anticipated to wildlife, aquatic life 

or natural resources, including adverse impacts on populations of endangered 

or threatened species or significant degradation of environmental qualities 

over broad areas. CAA section 112(a)(7). 
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The CAA does not specifically define the terms “individual 

most exposed,” “acceptable level” and “ample margin of safety.” 

In the Benzene NESHAP, 54 FR at 38044-38045, September 14, 1989, 

we stated as an overall objective: 

In protecting public health with an ample margin of safety 

under section 112, EPA strives to provide maximum feasible 

protection against risks to health from hazardous air 

pollutants by (1) protecting the greatest number of persons 

possible to an individual lifetime risk level no higher 

than approximately 1-in-1 million and (2) limiting to no 

higher than approximately 1-in-10 thousand [i.e., 100-in-1 

million] the estimated risk that a person living near a 

plant would have if he or she were exposed to the maximum 

pollutant concentrations for 70 years. 

The agency further stated that “[t]he EPA also considers 

incidence (the number of persons estimated to suffer cancer or 

other serious health effects as a result of exposure to a 

pollutant) to be an important measure of the health risk to the 

exposed population. Incidence measures the extent of health 

risks to the exposed population as a whole, by providing an 

estimate of the occurrence of cancer or other serious health 

effects in the exposed population.” Id. at 38045. 

In the ample margin of safety decision process, the agency 

again considers all of the health risks and other health 

information considered in the first step, including the 

incremental risk reduction associated with standards more 

stringent than the MACT standard or a more stringent standard 

that EPA has determined is necessary to ensure risk is 
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acceptable. In the ample margin of safety analysis, the agency 

considers additional factors, including costs and economic 

impacts of controls, technological feasibility, uncertainties 

and any other relevant factors. Considering all of these 

factors, the agency will establish the standard “at a level that 

provides an ample margin of safety to protect the public 

health,” as required by CAA section 112(f). 54 FR 38046, 

September 14, 1989. 

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 new source performance standards (NSPS) which 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 
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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 to sources that are constructed, modified or 

reconstructed after the EPA proposes the NSPS for the relevant 

source category.2

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 

 

2

 Specific 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. 
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achieving such reduction and any non-air 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. 
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B. What are the source categories and how do the NESHAP and NSPS 

regulate emissions? 

The source categories include petroleum refineries engaged 

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. Petroleum refinery activities start with 

the receipt of crude oil for storage at the refinery, include 

all 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 refineryspecific process units include fluid catalytic cracking units 

(FCCU) and catalytic reforming units (CRU), as well as units and 

processes found at many types of manufacturing facilities 

(including petroleum refineries), such as 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, 
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mercury, manganese and nickel). Criteria pollutants and other 

non-hazardous air pollutants that are also emitted include 

nitrogen oxides (NOX), particulate matter (PM), sulfur dioxide 

(SO2), volatile organic compounds (VOC), carbon monoxide (CO), 

greenhouse gases (GHG), and total reduced sulfur. 

The federal emission standards that are the primary subject 

of this proposed rulemaking are: 

 National Emission Standards for Hazardous Air Pollutants 

from Petroleum Refineries (40 CFR part 63, subpart CC) 

(Refinery MACT 1); 

 National Emission Standards for Hazardous Air Pollutants 

for Petroleum Refineries: Catalytic Cracking Units, 

Catalytic Reforming Units, and Sulfur Recovery Units (40 

CFR part 63, subpart UUU) (Refinery MACT 2); 

 Standards of Performance for Petroleum Refineries (40 CFR 

part 60, subpart J) (Refinery NSPS J); and 

 Standards of Performance for Petroleum Refineries for 

which Construction, Reconstruction, or Modification 

Commenced After May 14, 2007 (40 CFR part 60, subpart Ja) 

(Refinery NSPS Ja). 

1. Refinery MACT Standards 

The EPA promulgated MACT standards pursuant to CAA section 

112(d)(2) and (3) for refineries located at major sources in 
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three 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 emission sources from petroleum refinery process 

units, except those listed separately under the section 112(c) 

source category list expected to be regulated by other MACT 

standards. Some of the emission sources regulated in Refinery 

MACT 1 include miscellaneous process vents, storage vessels, 

wastewater, equipment leaks, gasoline loading racks, marine tank 

vessel loading and heat exchange systems. 

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 were subsequently regulated under a 

second MACT standard specific to these petroleum refinery 

process vents, codified as 40 CFR part 63, subpart UUU, which we 

promulgated on April 11, 2002 (67 FR 17762). This standard, 

which is referred to as “Refinery MACT 2,” covers process vents 

on catalytic cracking units (CCU) (including FCCU), CRU and 

sulfur recovery units (SRU). 

Finally, on October 28, 2009, we promulgated 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 cross-references to the General 
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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 has reached an agreement to settle that litigation. 

In a consent decree filed January 13, 2014 in the U.S. District 

Court for the District of Columbia, the EPA commits to perform 

the risk and technology review for Refinery MACT 1 and 2 and by 

May 15, 2014, either propose any regulations or propose that 

additional regulations are not necessary. Under the Consent 

Decree, the EPA commits to take final action by April 17, 2015, 

establishing regulations pursuant to the risk and technology 

review or to issue a final determination that revision to the 

existing rules is not necessary. 

2. Refinery NSPS 

Refinery NSPS subparts J and Ja regulate criteria pollutant 

emissions, including PM, SO2, NOX and CO from FCCU catalyst 

regenerators, fuel gas combustion devices (FGCD) and sulfur 

recovery plants. Refinery NSPS Ja also regulates criteria 

pollutant emissions from fluid coking units and delayed coking 

units (DCU). 
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The NSPS for petroleum refineries (40 CFR part 60, subpart 

J; Refinery NSPS 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 

Refinery NSPS J, the EPA developed separate standards of 

performance for new process units (40 CFR part 60, subpart Ja; 

Refinery NSPS Ja). However, the EPA received petitions for 

reconsideration and granted reconsideration on issues related to 

those standards. On December 22, 2008, the EPA addressed 

petition issues related to process heaters and flares by 

proposing amendments to certain provisions. Final amendments to 

Refinery NSPS Ja were promulgated on September 12, 2012 (77 FR 

56422). 

In this action, we are proposing amendments to address 

technical corrections and clarifications raised in a 2008 

industry petition for reconsideration applicable to Refinery 

NSPS Ja. We are addressing these issues in this proposal because 

they also affect sources included within these proposed 

amendments to Refinery MACT 1 and 2. 

C. What data collection activities were conducted to support 

this action? 

In 2010, the EPA began a significant effort to gather 

additional information and perform analyses to determine how to 

address statutory obligations for the Refinery MACT standards 
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and the NSPS. This effort focused on gathering comprehensive 

information through an industry-wide Information Collection 

Request (ICR) on petroleum refineries, conducted under CAA 

section 114 authority. The information not claimed as CBI by 

respondents is available in the docket (see Docket Item Nos. 

EPA-HQ-OAR-2010-0682-0064 through 0069). The EPA issued a single 

ICR (OMB Control Number 2060-0657) for sources covered under 

Refinery MACT 1 and 2 and Refinery NSPS J and Ja. 

On April 1, 2011, the ICR was sent out to the petroleum 

refining industry. In a comprehensive manner, the ICR collected 

information on processing characteristics, crude slate 

characteristics, emissions inventories and source testing to 

fill known data gaps. The ICR had four components: (1) a 

questionnaire on processes and controls to be completed by all 

petroleum refineries (Component 1); (2) an emissions inventory 

to be developed by all petroleum refineries using the emissions 

estimation protocol developed for this effort (Component 2); (3) 

distillation feed sampling and analysis to be conducted by all 

petroleum refineries (Component 3); and (4) emissions source 

testing to be completed in accordance with an EPA-approved 

protocol for specific sources at specific petroleum refineries 

(Component 4). We received responses from 149 refineries. We 

have since learned that seven refineries are synthetic minor 
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sources, bringing the total number of major source refineries 

operating in 2010 to 142. 

Information collected through the ICR was used to establish 

the baseline emissions and control levels for purposes of the 

regulatory reviews, to identify the most effective control 

measures, and to estimate the environmental and cost impacts 

associated with the regulatory options considered. As part of 

the information collection process, we provided a protocol for 

survey respondents to follow in developing the emissions 

inventories under Component 2 (Emission Estimation Protocol for 

Petroleum Refineries, available as Docket Item Number EPA-HQOAR-2010-0682-0060). The protocol contained detailed guidance 

for estimating emissions from typical refinery emission sources 

and was intended to provide a measure of consistency and 

replicability for emission estimates across the refining 

industry. Prior to issuance of the ICR, the protocol was 

publicly disseminated and underwent several revisions after 

public comments were received. Draft and final versions of the 

emission estimation protocol are provided in the docket to this 

rule (Docket ID Number EPA-HQ-OAR-2010-0682). The protocol 

provided a hierarchy of methodologies available for estimating 

emissions that corresponded to the level of information 

available at refineries. For each emission source, the various 

emission measurement or estimation methods specific to that 
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source were ranked in order of preference, with “Methodology 

Rank 1” being the preferred method, followed by “Methodology 

Rank 2,” and so on. Refinery owners and operators were requested 

through the ICR to use the highest ranked method (with 

Methodology Rank 1 being the highest) for which data were 

available. Methodology Ranks 1 or 2 generally relied on 

continuous emission measurements. When continuous measurement 

data were not available, engineering calculations or sitespecific emission factors (Methodology Ranks 3 and 4) were 

specified in the protocol by EPA; these methods generally needed 

periodic, site-specific measurements. When site-specific 

measurement or test data were not available, default emission 

factors (Methodology Rank 5) were provided in the protocol by 

EPA. 

As we reviewed the ICR-submitted emissions inventories, we 

determined that, in some cases, refiners either did not follow 

the protocol methodology or made an error in their calculations. 

This was evident because pollutants that we expected to be 

reported from certain emission sources were either not reported 

or were reported in amounts that were not consistent with the 

protocol methodology. In these cases, we contacted the 

refineries and, based on their replies, made corrections to 

emission estimates. The original Component 2 submittals, 

documentation of the changes as a result of our review, and the 
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final emissions inventories we relied on for our analyses are 

available in the technical memorandum entitled Emissions Data 

Quality Memorandum and Development of the Risk Model Input File, 

in Docket ID Number EPA-HQ-OAR-2010-0682. 

Collected emissions test data (test reports, continuous 

emissions monitoring system (CEMS) data and other continuous 

monitoring system data) were used to assess the effectiveness of 

existing control measures, to fill data gaps and to examine 

variability in emissions. The ICR requested source testing for a 

total of 90 specific process units at 75 particular refineries 

across the industry. We received a total of 72 source tests; in 

some cases, refinery sources claimed that units we requested to 

be tested were no longer in operation, did not exist or did not 

have an emission point to the atmosphere (this was the case for 

hydrocrackers). In other cases, refiners claimed they were not 

able to conduct testing because of process characteristics. For 

example, source testing of DCU proved to be difficult because 

the moisture content of the steam vent required a significant 

amount of gas to be sampled to account for dilution. Venting 

periods of less than 20 minutes did not accommodate this 

strategy and, therefore, if refiners vented for less than 20 

minutes, they did not sample their steam vent. As a result, only 

two DCU tests out of eight requested were received as part of 
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Component 4. Results of the stack test data are compiled and 

available in Docket ID Number EPA-HQ-OAR-2010-0682. 

D. What other relevant background information and data are 

available? 

Over the past several years, the EPA has worked with the 

Texas Commission on Environmental Quality and industry 

representatives to better characterize proper flare performance. 

Flares are used to control emissions from various vents at 

refineries as well as at other types of facilities not in the 

petroleum refinery source categories, such as chemical and 

petrochemical manufacturing facilities. In April 2012, we 

released a technical report for peer review that discussed our 

observations regarding the operation and performance of flares. 

The report was a result of the analysis of several flare 

efficiency studies and flare performance test reports. To 

provide an objective evaluation of our analysis, we asked a 

third party to facilitate an ad hoc peer review process of the 

technical report. This third party established a balanced peer 

review panel of reviewers from outside the EPA. These reviewers 

consisted of individuals that could be considered “technical 

combustion experts” within four interest groups: the refinery 

industry, industrial flare consultants, academia, and 

environmental stakeholders. 
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The EPA developed a charge statement with ten charge 

questions for the review panel. The peer reviewers were asked to 

perform a thorough review of the technical report and answer the 

charge questions to the extent possible, based on their 

technical expertise. The details of the peer review process and 

the charge questions, as well as comments received from the peer 

review process, were posted online to the Consolidated Petroleum 

Refinery Rulemaking Repository at the EPA's Technology Transfer 

Network Air Toxics Web Site (see 

http://www.epa.gov/ttn/atw/petref.html). These items are also 

provided in a memorandum entitled Peer Review of “Parameters for 

Properly Designed and Operated Flares” (see Docket ID Number 

EPA-HQ-OAR-2010-0682). After considering the comments received 

from the peer review process, we developed a final technical 

memorandum (see technical memorandum, Flare Performance Data: 

Summary of Peer Review Comments and Additional Data Analysis for 

Steam-Assisted Flares, in Docket ID Number EPA-HQ-OAR-2010-

0682). 

III. Analytical Procedures 

In this section, we describe the analyses performed to 

support the proposed decisions for the RTR and other issues 

addressed in this proposal. 
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A. How did we estimate post-MACT risks posed by the source 

categories? 

The EPA conducted a risk assessment that provided estimates 

of the MIR posed by the HAP emissions from each source in the 

source categories, the hazard index (HI) for chronic exposures 

to HAP with the potential to cause non-cancer health effects, 

and the hazard quotient (HQ) for acute exposures to HAP with the 

potential to cause non-cancer health effects. The assessment 

also provided estimates of the distribution of cancer risks 

within the exposed populations, cancer incidence and an 

evaluation of the potential for adverse environmental effects 

for each source category. The eight sections that follow this 

paragraph describe how we estimated emissions and conducted the 

risk assessment. The docket for this rulemaking (Docket ID 

Number EPA-HQ-OAR-2010-0682) contains the following document 

which provides more information on the risk assessment inputs 

and models: Draft Residual Risk Assessment for the Petroleum 

Refining Source Sector. The methods used to assess risks (as 

described in the eight primary steps below) are consistent with 

those peer-reviewed by a panel of the EPA’s Science Advisory 

Board (SAB) in 2009 and described in their peer review report 
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issued in 20103

; they are also consistent with the key 

recommendations contained in that report. 

1. How did we estimate actual emissions and identify the 

emissions release characteristics? 

We compiled data sets using the ICR emission inventory 

submittals as a starting point. The data sets were refined 

following an extensive quality assurance check of source 

locations, emission release characteristics, annual emission 

estimates and FCCU release parameters. They were then updated 

based on additional information received from refineries. In 

addition, we supplemented these data with results from stack 

testing, which were required later than the inventories under 

the ICR. As the stack test information was received, we compared 

these data against the refined emission inventories and the 

default emission factors provided in the Emission Estimation 

Protocol for Petroleum Refineries (Docket Item Number EPA-HQOAR-2010-0682-0060). 

Based on the stack test data for FCCU, we calculated that, 

on average, HCN emissions were a factor of 10 greater than the 

average emission factor of 770 pounds per barrel FCCU feed 

provided in the protocol. Therefore, we revised the HCN 

 

3

 U.S. EPA SAB. Risk and Technology Review (RTR) Risk Assessment 

Methodologies: For Review by the EPA’s Science Advisory board with Case 

Studies – MACT I Petroleum Refining Sources and Portland Cement 

Manufacturing, May 2010. 
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emissions for FCCU in the emissions inventory used for the risk 

modeling runs (the results are presented in this preamble). For 

the 10 facilities that performed a stack test to determine HCN 

emissions from their FCCU, we used the actual emissions measured 

during the stack tests in place of the inventories originally 

supplied in response to the ICR. For those facilities that did 

not perform a stack test, but reported HCN emissions in the 

emissions inventory portion of the ICR, we increased the 

emissions of HCN by a factor of 10, assuming the original 

emission inventory estimates for FCCU HCN emissions were based 

on the default emission factor in the protocol. The emissions 

inventory from the ICR and documentation of the changes made to 

the file as a result of our review are contained in the 

technical memorandum entitled Emissions Data Quality Memorandum 

and Development of the Risk Model Input File, in Docket ID 

Number EPA-HQ-OAR-2010-0682 and available on our website.4

2. How did we estimate MACT-allowable emissions? 

The available emissions data in the RTR dataset (i.e., the 

emissions inventory) include estimates of the mass of HAP 

emitted during the specified annual time period. In some cases, 

these “actual” emission levels are lower than the emission 

levels required to comply with the MACT standards. The emissions 

 

4

 The emissions inventory and the revised emissions modeling file can also be 

found at http://www.epa.gov/ttn/atw/petref.htm. 
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level allowed to be emitted by the MACT standards is referred to 

as the “MACT-allowable” emissions level. We discussed the use of 

both MACT-allowable and actual emissions in the final Coke Oven 

Batteries residual risk rule (70 FR 19998–19999, April 15, 2005) 

and in the proposed and final Hazardous Organic NESHAP residual 

risk rules (71 FR 34428, June 14, 2006, and 71 FR 76609, 

December 21, 2006, respectively). In those previous actions, we 

noted that assessing the risks at the MACT-allowable level is 

inherently reasonable since these risks reflect the maximum 

level facilities could emit and still comply with national 

emission standards. We also explained that it is reasonable to 

consider actual emissions, where such data are available, in 

both steps of the risk analysis, in accordance with the Benzene 

NESHAP approach. (54 FR 38044, September 14, 1989.) 

We requested allowable emissions data in the ICR. However, 

unlike for actual emissions, where the ICR specified the use of 

the Emission Estimation Protocol for Petroleum Refineries 

(available as Docket Item Number EPA-HQ-OAR-2010-0682-0060), we 

did not specify a method to calculate allowable emissions. As a 

result, in our review of these data and when comparing estimates 

between facilities, we found that facilities did not estimate 

allowable emissions consistently across the industry. In 

addition, facilities failed to report allowable emissions for 

many emission points, likely because they did not know how to 
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translate a work practice or performance standard into an 

allowable emission estimate and they did not know how to 

speciate individual HAP where the MACT standard is based on a 

surrogate, such as PM or VOC. Therefore, the ICR-submitted 

information for allowable emissions did not include emission 

estimates for all HAP and sources of interest. Consequently, we 

used our Refinery Emissions Model (REM Model) to estimate 

allowable emissions. The REM model 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. 

The risks associated with the allowable emissions were 

evaluated using the same dispersion modeling practices, exposure 

assumptions and health benchmarks as the actual risks. However, 

because each refinery’s allowable emissions were calculated by 

using model plants, selected based on each refinery’s actual 

capacities and throughputs, emission estimates for point sources 

are not specific to a particular latitude/longitude location. 

Therefore, for risk modeling purposes, all allowable emissions 

were assumed to be released from the centroid of the facility. 

(Note: for fugitive (area) sources, the surface area was 

selected by the size of the model plant and the release point 

was shifted to the southwest so the center of the fugitive area 

was near the centroid of the facility). The emission and risk 
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estimates for the actual emission inventory were compared to the 

allowable emissions and risk estimates. For most work practices, 

where allowable emission estimates are difficult to predict, the 

actual risk estimates were higher than those projected using the 

REM Model estimates. Consequently, we post-processed the two 

risk files, taking the higher risk estimates from the actual 

emissions inventory for sources subject to work practice 

standards, such as process equipment leaks, and sources that 

were not covered in the REM Model, combining them with the risk 

estimates from sources with more readily determined allowable 

emissions. The combined post-processed allowable risk estimates 

provide a high estimate of the risk allowed under Refinery MACT 

1 and 2. The REM Model assumptions and emission estimates, along 

with the post-processing of risk estimate results that produced 

the final risk estimates for the allowable emissions, are 

provided in the docket (see Refinery Emissions and Risk 

Estimates for Modeled “Allowable” Emissions in Docket ID Number 

EPA-HQ-OAR-2010-0682). 

3. How did we conduct dispersion modeling, determine inhalation 

exposures and estimate individual and population inhalation 

risks? 

Both long-term and short-term inhalation exposure 

concentrations and health risks from the source categories 

addressed in this proposal were estimated using the Human 
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Exposure Model (Community and Sector HEM-3 version 1.1.0). The 

HEM–3 performs three primary risk assessment activities: (1) 

conducting dispersion modeling to estimate the concentrations of 

HAP in ambient air, (2) estimating long-term and short-term 

inhalation exposures to individuals residing within 50 

kilometers (km) of the modeled sources5

, and (3) estimating 

individual and population-level inhalation risks using the 

exposure estimates and quantitative dose-response information. 

The air dispersion model used by the HEM–3 model (AERMOD) 

is one of the EPA’s preferred models for assessing pollutant 

concentrations from industrial facilities.6

 To perform the 

dispersion modeling and to develop the preliminary risk 

estimates, HEM-3 draws on three data libraries. The first is a 

library of meteorological data, which is used for dispersion 

calculations. This library includes 1 year (2011) of hourly 

surface and upper air observations for 824 meteorological 

stations, selected to provide coverage of the United States and 

Puerto Rico. A second library of United States Census Bureau 

census block7

 internal point locations and populations provides 

the basis of human exposure calculations (U.S. Census, 2010). In 

 

5

 This metric comes from the Benzene NESHAP. See 54 FR 38046, September 14, 

1989. 

6

 U.S. EPA. Revision to the Guideline on Air Quality Models: Adoption of a 

Preferred General Purpose (Flat and Complex Terrain) Dispersion Model and 

Other Revisions (70 FR 68218, November 9, 2005). 

7

 A census block is the smallest geographic area for which census statistics 

are tabulated. 
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addition, for each census block, the census library includes the 

elevation and controlling hill height, which are also used in 

dispersion calculations. A third library of pollutant unit risk 

factors and other health benchmarks is used to estimate health 

risks. These risk factors and health benchmarks are the latest 

values recommended by the EPA for HAP and other toxic air 

pollutants. These values are available at: 

http://www.epa.gov/ttn/atw/toxsource/summary.html and are 

discussed in more detail later in this section. 

In developing the risk assessment for chronic exposures, we 

used the estimated annual average ambient air concentrations of 

each HAP emitted by each source for which we have emissions data 

in the source category. The air concentrations at each nearby 

census block centroid were used as a surrogate for the chronic 

inhalation exposure concentration for all the people who reside 

in that census block. We calculated the MIR for each facility as 

the cancer risk associated with a continuous lifetime (24 hours 

per day, 7 days per week, and 52 weeks per year for a 70-year 

period) exposure to the maximum concentration at the centroid of 

inhabited census blocks. Individual cancer risks were calculated 

by multiplying the estimated lifetime exposure to the ambient 

concentration of each of the HAP (in micrograms per cubic meter 

(μg/m3

)) by its unit risk estimate (URE). The URE is an upper 

bound estimate of an individual’s probability of contracting 
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cancer over a lifetime of exposure to a concentration of 1 

microgram of the pollutant per cubic meter of air. For residual 

risk assessments, we generally use URE values from the EPA’s 

Integrated Risk Information System (IRIS). For carcinogenic 

pollutants without EPA IRIS values, we look to other reputable 

sources of cancer dose-response values, often using California 

EPA (CalEPA) URE values, where available. In cases where new, 

scientifically credible dose-response values have been developed 

in a manner consistent with the EPA guidelines and have 

undergone a peer review process similar to that used by the EPA, 

we may use such dose-response values in place of, or in addition 

to, other values, if appropriate. 

We note here that several carcinogens emitted by facilities 

in these source categories have a mutagenic mode of action. For 

these compounds, we applied the age-dependent adjustment factors 

(ADAF) described in the EPA’s Supplemental Guidance for 

Assessing Susceptibility from Early-Life Exposure to 

Carcinogens.8 This adjustment has the effect of increasing the 

estimated lifetime risks for these pollutants by a factor of 

1.6. Although only a small fraction of the total polycyclic 

organic matter (POM) emissions were reported as individual 

 

8

 Supplemental Guidance for Assessing Susceptibility from Early-Life Exposure 

to Carcinogens. Risk Assessment Forum, U.S. Environmental Protection Agency, 

Washington, DC. EPA/630/R-03/003F. March 2005. Available at 

http://www.epa.gov/ttn/atw/childrens_supplement_final.pdf. 
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compounds, the EPA expresses carcinogenic potency of POM 

relative to the carcinogenic potency of benzo[a]pyrene, based on 

evidence that carcinogenic POM have the same mutagenic mode of 

action as does benzo[a]pyrene. The EPA’s Science Policy Council 

recommends applying the ADAF to all carcinogenic polycyclic 

aromatic hydrocarbons (PAH) for which risk estimates are based 

on potency relative to benzo[a]pyrene. Accordingly, we have 

applied the ADAF to the benzo[a]pyrene-equivalent mass portion 

of all POM mixtures. 

The EPA estimated incremental individual lifetime cancer 

risks associated with emissions from the facilities in the 

source categories as the sum of the risks for each of the 

carcinogenic HAP (including those classified as carcinogenic to 

humans, likely to be carcinogenic to humans, and suggestive 

evidence of carcinogenic potential9

) emitted by the modeled 

sources. Cancer incidence and the distribution of individual 

cancer risks for the population within 50 km of the sources were 

also estimated for the source categories as part of this 

 

9

 These classifications also coincide with the terms "known carcinogen, 

probable carcinogen, and possible carcinogen," respectively, which are the 

terms advocated in the EPA's previous Guidelines for Carcinogen Risk 

Assessment, published in 1986 (51 FR 33992, September 24, 1986). Summing the 

risks of these individual compounds to obtain the cumulative cancer risks is 

an approach that was recommended by the EPA's SAB in their 2002 peer review 

of EPA's National Air Toxics Assessment (NATA) entitled, NATA - Evaluating 

the National-scale Air Toxics Assessment 1996 Data -- an SAB Advisory, 

available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/214C6E915BB04E14852570CA007A682C/$

File/ecadv02001.pdf. 
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assessment by summing individual risks. A distance of 50 km is 

consistent with both the analysis supporting the 1989 Benzene 

NESHAP (54 FR 38044, September 14, 1989) and the limitations of 

Gaussian dispersion models, including AERMOD. 

To assess the risk of non-cancer health effects from 

chronic exposures, we summed the HQ for each of the HAP that 

affects a common target organ system to obtain the HI for that 

target organ system (or target organ-specific HI, TOSHI). The HQ 

is the estimated exposure divided by the chronic reference 

level, which is a value selected from one of several sources. 

First, the chronic reference level can be the EPA Reference 

Concentration (RfC) 

(http://www.epa.gov/riskassessment/glossary.htm), defined as “an 

estimate (with uncertainty spanning perhaps an order of 

magnitude) of a continuous inhalation exposure to the human 

population (including sensitive subgroups) that is likely to be 

without an appreciable risk of deleterious effects during a 

lifetime.” Alternatively, in cases where an RfC from the EPA’s 

IRIS database is not available or where the EPA determines that 

using a value other than the RfC is appropriate, the chronic 

reference level can be a value from the following prioritized 

sources: (1) The Agency for Toxic Substances and Disease 

Registry Minimum Risk Level 

(http://www.atsdr.cdc.gov/mrls/index.asp), which is defined as 
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“an estimate of daily human exposure to a hazardous substance 

that is likely to be without an appreciable risk of adverse noncancer health effects (other than cancer) over a specified 

duration of exposure”; (2) the CalEPA Chronic Reference Exposure 

Level (REL) 

(http://www.oehha.ca.gov/air/hot_spots/pdf/HRAguidefinal.pdf), 

which is defined as “the concentration level (that is expressed 

in units of μg/m3

 for inhalation exposure and in a dose expressed 

in units of milligram per kilogram per day (mg/kg-day) for oral 

exposures), at or below which no adverse health effects are 

anticipated for a specified exposure duration”; or (3), as noted 

above, a scientifically credible dose-response value that has 

been developed in a manner consistent with the EPA guidelines 

and has undergone a peer review process similar to that used by 

the EPA, in place of or in concert with other values. 

The EPA also evaluated screening estimates of acute 

exposures and risks for each of the HAP at the point of highest 

off-site exposure for each facility (i.e., not just the census 

block centroids), assuming that a person is located at this spot 

at a time when both the peak (hourly) emissions rate and worstcase dispersion conditions occur. The acute HQ is the estimated 

acute exposure divided by the acute dose-response value. In each 

case, the EPA calculated acute HQ values using best available, 

short-term dose-response values. These acute dose-response 
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values, which are described below, include the acute REL, acute 

exposure guideline levels (AEGL) and emergency response planning 

guidelines (ERPG) for 1-hour exposure durations. As discussed 

below, we used realistic assumptions based on knowledge of the 

emission point release characteristics for emission rates, and 

conservative assumptions for meteorology and exposure location 

for our acute analysis. 

As described in the CalEPA’s Air Toxics Hot Spots Program 

Risk Assessment Guidelines, Part I, The Determination of Acute 

Reference Exposure Levels for Airborne Toxicants, an acute REL 

value (http://www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined 

as “the concentration level at or below which no adverse health 

effects are anticipated for a specified exposure duration.” Id. 

at page 2. Acute REL values are based on the most sensitive, 

relevant, adverse health effect reported in the peer-reviewed 

medical and toxicological literature. Acute REL values are 

designed to protect the most sensitive individuals in the 

population through the inclusion of margins of safety. Because 

margins of safety are incorporated to address data gaps and 

uncertainties, exceeding the REL value does not automatically 

indicate an adverse health impact. 

AEGL values were derived in response to recommendations 

from the National Research Council (NRC). As described in 

Standing Operating Procedures (SOP) of the National Advisory 
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Committee on Acute Exposure Guideline Levels for Hazardous 

Substances (http://www.epa.gov/oppt/aegl/pubs/sop.pdf),10 “the 

NRC’s previous name for acute exposure levels—community 

emergency exposure levels—was replaced by the term AEGL to 

reflect the broad application of these values to planning, 

response, and prevention in the community, the workplace, 

transportation, the military, and the remediation of Superfund 

sites.” Id. at 2. 

This document also states that AEGL values “represent 

threshold exposure limits for the general public and are 

applicable to emergency exposures ranging from 10 minutes to 

eight hours.” Id. at 2. The document lays out the purpose and 

objectives of AEGL by stating that “the primary purpose of the 

AEGL program and the National Advisory Committee for Acute 

Exposure Guideline Levels for Hazardous Substances is to develop 

guideline levels for once-in-a-lifetime, short-term exposures to 

airborne concentrations of acutely toxic, high-priority 

chemicals.” Id. at 21. In detailing the intended application of 

AEGL values, the document states that “[i]t is anticipated that 

the AEGL values will be used for regulatory and nonregulatory 

purposes by U.S. Federal and state agencies and possibly the 

international community in conjunction with chemical emergency 

 

10 National Academy of Sciences (NAS), 2001. Standing Operating Procedures for 

Developing Acute Exposure Levels for Hazardous Chemicals, page 2. 
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response, planning and prevention programs. More specifically, 

the AEGL values will be used for conducting various risk 

assessments to aid in the development of emergency preparedness 

and prevention plans, as well as real-time emergency response 

actions, for accidental chemical releases at fixed facilities 

and from transport carriers.” Id. at 31. 

The AEGL–1 value is then specifically defined as “the 

airborne concentration (expressed as ppm (parts per million) or 

mg/m3

 (milligrams per cubic meter)) of a substance above which it 

is predicted that the general population, including susceptible 

individuals, could experience notable discomfort, irritation, or 

certain asymptomatic nonsensory effects. However, the effects 

are not disabling and are transient and reversible upon 

cessation of exposure.” Id. at 3. The document also notes that, 

“Airborne concentrations below AEGL–1 represent exposure levels 

that can produce mild and progressively increasing but transient 

and nondisabling odor, taste, and sensory irritation or certain 

asymptomatic, nonsensory effects.” Id. Similarly, the document 

defines AEGL–2 values as “the airborne concentration (expressed 

as parts per million or milligrams per cubic meter) of a 

substance above which it is predicted that the general 

population, including susceptible individuals, could experience 

irreversible or other serious, long-lasting adverse health 

effects or an impaired ability to escape.” Id. 
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ERPG values are derived for use in emergency response, as 

described in the American Industrial Hygiene Association’s ERP 

Committee document entitled, ERPGS Procedures and 

Responsibilities, which states that, “Emergency Response 

Planning Guidelines were developed for emergency planning and 

are intended as health-based guideline concentrations for single 

exposures to chemicals.”11 Id. at 1. The ERPG–1 value is defined 

as “the maximum airborne concentration below which it is 

believed that nearly all individuals could be exposed for up to 

1 hour without experiencing other than mild transient adverse 

health effects or without perceiving a clearly defined, 

objectionable odor.” Id. at 2. Similarly, the ERPG–2 value is 

defined as “the maximum airborne concentration below which it is 

believed that nearly all individuals could be exposed for up to 

one hour without experiencing or developing irreversible or 

other serious health effects or symptoms which could impair an 

individual’s ability to take protective action.” Id. at 1. 

As can be seen from the definitions above, the AEGL and 

ERPG values include the similarly-defined severity levels 1 and 

2. For many chemicals, a severity level 1 value AEGL or ERPG has 

not been developed because the types of effects for these 

 

11 ERP Committee Procedures and Responsibilities. November 1, 2006. American 

Industrial Hygiene Association. Available at https://www.aiha.org/getinvolved/AIHAGuidelineFoundation/EmergencyResponsePlanningGuidelines/Document

s/ERP-SOPs2006.pdf. 
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chemicals are not consistent with the AEGL-1/ERPG-1 definitions; 

in these instances, we compare higher severity level AEGL–2 or 

ERPG–2 values to our modeled exposure levels to screen for 

potential acute concerns. When AEGL-1/ERPG-1 values are 

available, they are used in our acute risk assessments. 

Acute REL values for 1-hour exposure durations are 

typically lower than their corresponding AEGL–1 and ERPG–1 

values. Even though their definitions are slightly different, 

AEGL–1 values are often the same as the corresponding ERPG–1 

values, and AEGL–2 values are often equal to ERPG–2 values. 

Maximum HQ values from our acute screening risk assessments 

typically result when basing them on the acute REL value for a 

particular pollutant. In cases where our maximum acute HQ value 

exceeds 1, we also report the HQ value based on the next highest 

acute dose-response value (usually the AEGL–1 and/or the ERPG–1 

value). 

To develop screening estimates of acute exposures in the 

absence of hourly emissions data, generally we first develop 

estimates of maximum hourly emissions rates by multiplying the 

average actual annual hourly emissions rates by a default factor 

to cover routinely variable emissions. However, for the 

petroleum refineries category, we incorporated additional 

information and process knowledge in order to better 

characterize acute emissions, as described below. The ICR 
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included input fields for both annual emissions and maximum 

hourly emissions. The maximum hourly emission values were often 

left blank or appeared to be reported in units other than those 

required for this emissions field (pounds per hour). 

Consequently, instead of relying on the inadequate data provided 

in response to the ICR, we elected to estimate the hourly 

emissions based on the reported annual emissions (converted to 

average hourly emissions in terms of pounds per hour) and then 

to apply an escalation factor, considering the different types 

of emission sources and their inherent variability, in order to 

calculate maximum hourly rates. For sources with relatively 

continuous operations and steady state emissions, such as FCCU, 

sulfur recovery plants, and continuous catalytic reformers, a 

factor of 2 was used to estimate the maximum hourly rates from 

the average hourly emission rates. For sources with relatively 

continuous emissions, but with more variability, like storage 

tanks and wastewater systems, a factor of 4 was used to estimate 

the maximum hourly rates from the average hourly emission rates. 

For non-continuous emission sources with more variability, such 

as DCU, cyclic CRU, semi-regenerative CRU, and transfer and 

loading operations, the number of hours in the venting cycle and 

the variability of emissions expected in that cycle were used to 

determine the escalation factor for each emissions source. The 

escalation factors for these processes range from 10 to 60. For 
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more detail regarding escalation factors and the rationale for 

their selection, see Derivation of Hourly Emission Rates for 

Petroleum Refinery Emission Sources Used in the Acute Risk 

Analysis, available in the docket for this rulemaking (Docket ID 

Number EPA-HQ-OAR-2010-0682). 

As part of our acute risk assessment process, for cases 

where acute HQ values from the screening step were less than or 

equal to 1 (even under the conservative assumptions of the 

screening analysis), acute impacts were deemed negligible and no 

further analysis was performed. In cases where an acute HQ from 

the screening step was greater than 1, additional site-specific 

data were considered to develop a more refined estimate of the 

potential for acute impacts of concern. For these source 

categories, the data refinements employed consisted of using the 

site-specific facility layout to distinguish facility property 

from an area where the public could be exposed. These 

refinements are discussed more fully in the Draft Residual Risk 

Assessment for the Petroleum Refining Source Sector, which is 

available in the docket for this rulemaking (Docket ID Number 

EPA-HQ-OAR-2010-0682). Ideally, we would prefer to have 

continuous measurements over time to see how the emissions vary 

by each hour over an entire year. Having a frequency 

distribution of hourly emissions rates over a year would allow 

us to perform a probabilistic analysis to estimate potential 
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threshold exceedances and their frequency of occurrence. Such an 

evaluation could include a more complete statistical treatment 

of the key parameters and elements adopted in this screening 

analysis. Recognizing that this level of data is rarely 

available, we instead rely on the multiplier approach. 

To better characterize the potential health risks 

associated with estimated acute exposures to HAP, and in 

response to a key recommendation from the SAB’s peer review of 

the EPA’s RTR risk assessment methodologies,12 we generally 

examine a wider range of available acute health metrics (e.g., 

REL, AEGL) than we do for our chronic risk assessments. This is 

in response to the SAB’s acknowledgement that there are 

generally more data gaps and inconsistencies in acute reference 

values than there are in chronic reference values. In some 

cases, e.g., when Reference Value Arrays13 for HAP have been 

developed, we consider additional acute values (i.e., 

occupational and international values) to provide a more 

complete risk characterization. 

 

12 The SAB peer review of RTR Risk Assessment Methodologies is available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/4AB3966E263D943A8525771F00668381/$

File/EPA-SAB-10-007-unsigned.pdf. 

13 U.S. EPA. (2009) Chapter 2.9 Chemical Specific Reference Values for 

Formaldehyde in Graphical Arrays of Chemical-Specific Health Effect Reference 

Values for Inhalation Exposures (Final Report). U.S. Environmental Protection 

Agency, Washington, DC, EPA/600/R-09/061, and available on-line at 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=211003. 
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4. How did we conduct the multipathway exposure and risk 

screening? 

The EPA conducted a screening analysis examining the 

potential for significant human health risks due to exposures 

via routes other than inhalation (i.e., ingestion). We first 

determined whether any sources in the source categories emitted 

any hazardous air pollutants known to be persistent and bioaccumulative in the environment (PB-HAP). The PB-HAP compounds 

or compound classes are identified for the screening from the 

EPA’s Air Toxics Risk Assessment Library (available at 

http://www.epa.gov/ttn/fera/risk_atra_vol1.html). 

For the petroleum refinery source categories, we identified 

emissions of cadmium compounds, chlorinated dibenzodioxins and 

furans (CDDF), lead compounds, mercury compounds, 

polychlorinated biphenyls (PCB), and polycylic organic matter 

(POM). Because PB-HAP are emitted by at least one facility, we 

proceeded to the second step of the evaluation. In this step, we 

determined whether the facility-specific emission rates of each 

of the emitted PB–HAP were large enough to create the potential 

for significant non-inhalation human health risks under 

reasonable worst-case conditions. To facilitate this step, we 

developed emissions rate screening levels for each PB–HAP using 

a hypothetical upper-end screening exposure scenario developed 

for use in conjunction with the EPA’s “Total Risk Integrated 
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Methodology. Fate, Transport, and Ecological Exposure” 

(TRIM.FaTE) model. We conducted a sensitivity analysis on the 

screening scenario to ensure that its key design parameters 

would represent the upper end of the range of possible values, 

such that it would represent a conservative but not impossible 

scenario. The facility-specific emissions rates of each of the 

PB–HAP were compared to their corresponding emission rate 

screening values to assess the potential for significant human 

health risks via non-inhalation pathways. We call this 

application of the TRIM.FaTE model the Tier I TRIM- Screen or 

Tier I screen. 

For the purpose of developing emissions rates for our Tier 

I TRIM-Screen, we derived emission levels for each PB-HAP (other 

than lead) at which the maximum excess lifetime cancer risk 

would be 1-in-1 million or, for HAP that cause non-cancer health 

effects, the maximum HQ would be 1. If the emissions rate of any 

PB-HAP exceeds the Tier I screening emissions rate for any 

facility, we conduct a second screen, which we call the Tier II 

TRIM-screen or Tier II screen. In the Tier II screen, the 

location of each facility that exceeded the Tier I emission rate 

is used to refine the assumptions associated with the 

environmental scenario while maintaining the exposure scenario 

assumptions. We then adjust the risk-based Tier I screening 

level for each PB-HAP for each facility based on an 
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understanding of how exposure concentrations estimated for the 

screening scenario change with meteorology and environmental 

assumptions. PB-HAP emissions that do not exceed these new Tier 

II screening levels are considered to pose no unacceptable 

risks. When facilities exceed the Tier II screening levels, it 

does not mean that multi-pathway impacts are significant, only 

that we cannot rule out that possibility based on the results of 

the screen. These facilities may be further evaluated for multipathway risks using the TRIM.FaTE model. 

In evaluating the potential for multi-pathway risk from 

emissions of lead compounds, rather than developing a screening 

emissions rate for them, we compared modeled maximum estimated 

chronic inhalation exposures with the level of the current 

National Ambient Air Quality Standards (NAAQS) for lead.14 Values 

below the level of the primary (health-based) lead NAAQS were 

considered to have a low potential for multi-pathway risk. 

For further information on the multi-pathway analysis 

approach, see the Draft Residual Risk Assessment for the 

 

14 In doing so, EPA notes that the legal standard for a primary NAAQS – that a 

standard is requisite to protect public health and provide an adequate margin 

of safety (CAA Section 109(b)) – differs from the Section 112(f) standard 

(requiring among other things that the standard provide an “ample margin of 

safety”). However, the lead NAAQS is a reasonable measure of determining risk 

acceptability (i.e., the first step of the Benzene NESHAP analysis) since it 

is designed to protect the most susceptible group in the human population – 

children, including children living near major lead emitting sources. 73 FR 

67002/3; 73 FR 67000/3; 73 FR 67005/1, November 12, 2008. In addition, 

applying the level of the primary lead NAAQS at the risk acceptability step 

is conservative, since that primary lead NAAQS reflects an adequate margin of 

safety. 
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Petroleum Refining Source Sector, which is available in the 

docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682). 

5. How did we assess risks considering emissions control 

options? 

In addition to assessing baseline inhalation risks and 

screening for potential multipathway risks, we also estimated 

risks considering the potential emission reductions that would 

be achieved by the control options under consideration. We used 

the same emissions inventory that we used for the risk modeling 

and applied emission reduction estimates for the control options 

we are proposing to calculate the post-control risk. We note 

that for storage vessels, in response to the ICR some facilities 

reported emissions for their tank farm or a group of storage 

vessels rather than for each individual storage vessel. In order 

to calculate emissions for each storage vessel, we used unitspecific data from the ICR to estimate the pre- and post-control 

emissions based on the operating characteristics and controls 

reported for each unit. For example, HAP emissions from each 

storage vessel were estimated based on the size, contents, and 

controls reported for that storage vessel. If additional 

controls would be necessary to comply with proposed requirements 

for storage vessels, the HAP emissions were again estimated 

based on the upgraded controls. The pre- and post-control 

emissions were summed across all storage vessels at the facility 
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to determine a facility-specific emission reduction factor. The 

facility-specific emission reduction factor was then used to 

adjust the emissions for each of the pollutants reported for 

storage vessels at that facility to account for the post-control 

emissions. In this manner, the expected emission reductions were 

applied to the specific HAP and emission points in the source 

category dataset to develop corresponding estimates of risk and 

incremental risk reductions. The resulting emission file used 

for post-control risk analysis is available in the docket for 

this action (Docket ID Number EPA-HQ-OAR-2010-0682). 

6. How did we conduct the environmental risk screening 

assessment? 

a. Adverse Environmental Effect 

The EPA has developed a screening approach to examine the 

potential for adverse environmental effects as required under 

section 112(f)(2)(A) of the CAA. Section 112(a)(7) of the CAA 

defines “adverse environmental effect” as “any significant and 

widespread adverse effect, which may reasonably be anticipated, 

to wildlife, aquatic life, or other natural resources, including 

adverse impacts on populations of endangered or threatened 

species or significant degradation of environmental quality over 

broad areas.” 
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b. Environmental HAP 

The EPA focuses on seven HAP, which we refer to as 

“environmental HAP,” in its screening analysis: five PB-HAP and 

two acid gases. The five PB-HAP are cadmium, dioxins/furans, 

POM, mercury (both inorganic mercury and methyl mercury) and 

lead compounds. The two acid gases are HCl and HF. The rationale 

for including these seven HAP in the environmental risk 

screening analysis is presented below. 

HAP that persist and bioaccumulate are of particular 

environmental concern because they accumulate in the soil, 

sediment and water. The PB-HAP are taken up, through sediment, 

soil, water, and/or ingestion of other organisms, by plants or 

animals (e.g., small fish) at the bottom of the food chain. As 

larger and larger predators consume these organisms, 

concentrations of the PB-HAP in the animal tissues increases as 

does the potential for adverse effects. The five PB-HAP we 

evaluate as part of our screening analysis account for 99.8 

percent of all PB-HAP emissions nationally from stationary 

sources (on a mass basis from the 2005 National Emissions 

Inventory (NEI)). 

In addition to accounting for almost all of the mass of PBHAP emitted, we note that the TRIM.Fate model that we use to 

evaluate multipathway risk allows us to estimate concentrations 

of cadmium compounds, dioxins/furans, POM and mercury in soil, 
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sediment and water. For lead compounds, we currently do not have 

the ability to calculate these concentrations using the 

TRIM.Fate model. Therefore, to evaluate the potential for 

adverse environmental effects from lead, we compare the 

estimated HEM-modeled exposures from the source category 

emissions of lead with the level of the secondary NAAQS for 

lead.15 We consider values below the level of the secondary lead 

NAAQS to be unlikely to cause adverse environmental effects. 

Due to their well-documented potential to cause direct 

damage to terrestrial plants, we include two acid gases, HCl and 

HF, in the environmental screening analysis. According to the 

2005 NEI, HCl and HF account for about 99 percent (on a mass 

basis) of the total acid gas HAP emitted by stationary sources 

in the U.S. In addition to the potential to cause direct damage 

to plants, high concentrations of HF in the air have been linked 

to fluorosis in livestock. Air concentrations of these HAP are 

already calculated as part of the human multipathway exposure 

and risk screening analysis using the HEM3-AERMOD air dispersion 

model, and we are able to use the air dispersion modeling 

 

15 The secondary lead NAAQS is a reasonable measure of determining whether 

there is an adverse environmental effect since it was established considering 

“effects on soils, water, crops, vegetation, man-made materials, animals, 

wildlife, weather, visibility and climate, damage to and deterioration of 

property, and hazards to transportation, as well as effects on economic 

values and on personal comfort and well-being.”
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results to estimate the potential for an adverse environmental 

effect. 

The EPA acknowledges that other HAP beyond the seven HAP 

discussed above may have the potential to cause adverse 

environmental effects. Therefore, the EPA may include other 

relevant HAP in its environmental risk screening in the future, 

as modeling science and resources allow. The EPA invites comment 

on the extent to which other HAP emitted by the source 

categories may cause adverse environmental effects. Such 

information should include references to peer-reviewed 

ecological effects benchmarks that are of sufficient quality for 

making regulatory decisions, as well as information on the 

presence of organisms located near facilities within the source 

categories that such benchmarks indicate could be adversely 

affected. 

c. Ecological Assessment Endpoints and Benchmarks for PB-HAP 

An important consideration in the development of the EPA’s 

screening methodology is the selection of ecological assessment 

endpoints and benchmarks. Ecological assessment endpoints are 

defined by the ecological entity (e.g., aquatic communities 

including fish and plankton) and its attributes (e.g., frequency 

of mortality). Ecological assessment endpoints can be 

established for organisms, populations, communities or 

assemblages, and ecosystems. 
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For PB-HAP, we evaluated the following community-level 

ecological assessment endpoints to screen for organisms directly 

exposed to HAP in soils, sediment and water: 

 Local terrestrial communities (i.e., soil invertebrates, 

plants) and populations of small birds and mammals that 

consume soil invertebrates exposed to PB-HAP in the 

surface soil. 

 Local benthic (i.e., bottom sediment dwelling insects, 

amphipods, isopods and crayfish) communities exposed to 

PB-HAP in sediment in nearby water bodies. 

 Local aquatic (water-column) communities (including fish 

and plankton) exposed to PB-HAP in nearby surface waters. 

For PB-HAP, we also evaluated the following populationlevel ecological assessment endpoint to screen for indirect HAP 

exposures of top consumers via the bioaccumulation of HAP in 

food chains. 

 Piscivorous (i.e., fish-eating) wildlife consuming PBHAP-contaminated fish from nearby water bodies. 

For cadmium compounds, dioxins/furans, POM and mercury, we 

identified the available ecological benchmarks for each 

assessment endpoint. An ecological benchmark represents a 

concentration of HAP (e.g., 0.77 micrograms of HAP per liter of 

water) that has been linked to a particular environmental effect 
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level (e.g., a no-observed-adverse-effect level (NOAEL)) through 

scientific study. For PB-HAP we identified, where possible, 

ecological benchmarks at the following effect levels: 

 Probable effect level (PEL): Level above which adverse 

effects are expected to occur frequently. 

 Lowest-observed-adverse-effect level (LOAEL): The lowest 

exposure level tested at which there are biologically 

significant increases in frequency or severity of adverse 

effects. 

 No-observed-adverse-effect level (NOAEL): The highest 

exposure level tested at which there are no biologically 

significant increases in the frequency or severity of 

adverse effect. 

We established a hierarchy of preferred benchmark sources 

to allow selection of benchmarks for each environmental HAP at 

each ecological assessment endpoint. In general, the EPA sources 

that are used at a programmatic level (e.g., Office of Water, 

Superfund Program) were used, if available. If not, the EPA 

benchmarks used in regional programs (e.g., Superfund) were 

used. If benchmarks were not available at a programmatic or 

regional level, we used benchmarks developed by other federal 

agencies (e.g., NOAA) or state agencies. 
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Benchmarks for all effect levels are not available for all 

PB-HAP and assessment endpoints. In cases where multiple effect 

levels were available for a particular PB-HAP and assessment 

endpoint, we use all of the available effect levels to help us 

to determine whether ecological risks exist and, if so, whether 

the risks could be considered significant and widespread. 

d. Ecological Assessment Endpoints and Benchmarks for Acid Gases 

The environmental screening analysis also evaluated 

potential damage and reduced productivity of plants due to 

direct exposure to acid gases in the air. For acid gases, we 

evaluated the following ecological assessment endpoint: 

 Local terrestrial plant communities with foliage exposed 

to acidic gaseous HAP in the air. 

The selection of ecological benchmarks for the effects of 

acid gases on plants followed the same approach as for PB-HAP 

(i.e., we examine all of the available chronic benchmarks). For 

HCl, the EPA identified chronic benchmark concentrations. We 

note that the benchmark for chronic HCl exposure to plants is 

greater than the reference concentration for chronic inhalation 

exposure for human health. This means that where EPA includes 

regulatory requirements to prevent an exceedance of the 

reference concentration for human health, additional analyses 

for adverse environmental effects of HCl would not be necessary. 
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For HF, EPA identified chronic benchmark concentrations for 

plants and evaluated chronic exposures to plants in the 

screening analysis. High concentrations of HF in the air have 

also been linked to fluorosis in livestock. However, the HF 

concentrations at which fluorosis in livestock occur are higher 

than those at which plant damage begins. Therefore, the 

benchmarks for plants are protective of both plants and 

livestock. 

e. Screening Methodology 

For the environmental risk screening analysis, the EPA 

first determined whether any petroleum refineries emitted any of 

the seven environmental HAP. For the petroleum refinery source 

categories, we identified emissions of cadmium, dioxins/furans, 

POM, mercury (both inorganic mercury and methyl mercury), lead, 

HCl and HF. 

Because one or more of the seven environmental HAP 

evaluated are emitted by at least one petroleum refinery, we 

proceeded to the second step of the evaluation. 

f. PB-HAP Methodology 

For cadmium, mercury, POM and dioxins/furans, the 

environmental screening analysis consists of two tiers, while 

lead is analyzed differently as discussed earlier. In the first 

tier, we determined whether the maximum facility-specific 

emission rates of each of the emitted environmental HAP were 
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large enough to create the potential for adverse environmental 

effects under reasonable worst-case environmental conditions. 

These are the same environmental conditions used in the human 

multipathway exposure and risk screening analysis. 

To facilitate this step, TRIM.FaTE was run for each PB-HAP 

under hypothetical environmental conditions designed to provide 

conservatively high HAP concentrations. The model was set to 

maximize runoff from terrestrial parcels into the modeled lake, 

which in turn, maximized the chemical concentrations in the 

water, the sediments, and the fish. The resulting media 

concentrations were then used to back-calculate a screening 

threshold emission rate that corresponded to the relevant 

exposure benchmark concentration value for each assessment 

endpoint. To assess emissions from a facility, the reported 

emission rate for each PB-HAP was compared to the screening 

threshold emission rate for that PB-HAP for each assessment 

endpoint. If emissions from a facility do not exceed the Tier I 

threshold, the facility “passes” the screen, and therefore, is 

not evaluated further under the screening approach. If emissions 

from a facility exceed the Tier I threshold, we evaluate the 

facility further in Tier II. 

In Tier II of the environmental screening analysis, the 

screening emission thresholds are adjusted to account for local 

meteorology and the actual location of lakes in the vicinity of 
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facilities that did not pass the Tier I screen. The modeling 

domain for each facility in the Tier II analysis consists of 

eight octants. Each octant contains five modeled soil 

concentrations at various distances from the facility (5 soil 

concentrations x 8 octants = total of 40 soil concentrations per 

facility) and one lake with modeled concentrations for water, 

sediment and fish tissue. In the Tier II environmental risk 

screening analysis, the 40 soil concentration points are 

averaged to obtain an average soil concentration for each 

facility for each PB-HAP. For the water, sediment and fish 

tissue concentrations, the highest value for each facility for 

each pollutant is used. If emission concentrations from a 

facility do not exceed the Tier II threshold, the facility 

passes the screen, and is typically not evaluated further. If 

emissions from a facility exceed the Tier II threshold, the 

facility does not pass the screen and, therefore, may have the 

potential to cause adverse environmental effects. Such 

facilities are evaluated further to investigate factors such as 

the magnitude and characteristics of the area of exceedance. 

g. Acid Gas Methodology 

The environmental screening analysis evaluates the 

potential phytotoxicity and reduced productivity of plants due 

to chronic exposure to acid gases. The environmental risk 

screening methodology for acid gases is a single-tier screen 
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that compares the average off-site ambient air concentration 

over the modeling domain to ecological benchmarks for each of 

the acid gases. Because air concentrations are compared directly 

to the ecological benchmarks, emission-based thresholds are not 

calculated for acid gases as they are in the ecological risk 

screening methodology for PB-HAP. 

For purposes of ecological risk screening, EPA identifies a 

potential for adverse environmental effects to plant communities 

from exposure to acid gases when the average concentration of 

the HAP around a facility exceeds the LOAEL ecological 

benchmark. In such cases, we further investigate factors such as 

the magnitude and characteristics of the area of exceedance 

(e.g., land use of exceedance area, size of exceedance area) to 

determine if there is an adverse environmental effect. 

For further information on the environmental screening 

analysis approach, see section IV.C.5 of this preamble and the 

Draft Residual Risk Assessment for the Petroleum Refining Source 

Sector, which is available in the docket for this action (Docket 

ID Number EPA-HQ-OAR-2010-0682). 

7. How did we conduct facility-wide assessments? 

To put the source category risks in context, following the 

assessment approach outlined in the SAB (2010) review, we 

examine the risks from the entire “facility,” where the facility 

includes all HAP-emitting operations within a contiguous area 
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and under common control. In other words, we examine the HAP 

emissions not only from the source category emission points of 

interest, but also emissions of HAP from all other emission 

sources at the facility for which we have data. 

The emissions inventories provided in response to the ICR 

included emissions information for all emission sources at the 

facilities that are part of the refineries source categories. 

Generally, only a few emission sources located at refineries are 

not subject to either Refinery MACT 1 or 2; the most notable are 

boilers, process heaters and internal combustion engines, which 

are addressed by other MACT standards. 

We analyzed risks due to the inhalation of HAP that are 

emitted “facility-wide” for the populations residing within 50 

km of each facility, consistent with the methods used for the 

source category analysis described above. For these facilitywide risk analyses, the modeled source category risks were 

compared to the facility-wide risks to determine the portion of 

facility-wide risks that could be attributed to each of the 

source categories addressed in this proposal. We specifically 

examined the facility that was associated with the highest 

estimates of risk and determined the percentage of that risk 

attributable to the source category of interest. The Draft 

Residual Risk Assessment for the Petroleum Refining Source 

Sector available through the docket for this action (Docket ID 
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Number EPA-HQ-OAR-2010-0682) provides the methodology and 

results of the facility-wide analyses, including all facilitywide risks and the percentage of source category contribution to 

facility-wide risks. 

8. How did we consider uncertainties in risk assessment? 

In the Benzene NESHAP we concluded that risk estimation 

uncertainty should be considered in our decision-making under 

the ample margin of safety framework. Uncertainty and the 

potential for bias are inherent in all risk assessments, 

including those performed for this proposal. Although 

uncertainty exists, we believe that our approach, which used 

conservative tools and assumptions, ensures that our decisions 

are health protective and environmentally protective. A brief 

discussion of the uncertainties in the emissions datasets, 

dispersion modeling, inhalation exposure estimates and doseresponse relationships follows below. A more thorough discussion 

of these uncertainties is included in the Draft Residual Risk 

Assessment for the Petroleum Refining Source Sector, which is 

available in the docket for this action (Docket ID Number EPAHQ-OAR-2010-0682). 

a. Uncertainties in the Emission Datasets 

Although the development of the RTR datasets involved 

quality assurance/quality control processes, the accuracy of 

emissions values will vary depending on the source of the data, 
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the degree to which data are incomplete or missing, the degree 

to which assumptions made to complete the datasets are accurate, 

errors in emission estimates and other factors. The emission 

estimates considered in this analysis are annual totals for 

2010, and they do not reflect short-term fluctuations during the 

course of a year or variations from year to year. The estimates 

of peak hourly emissions rates for the acute effects screening 

assessment were based on emission adjustment factors applied to 

the average annual hourly emission rates, which are intended to 

account for emission fluctuations due to normal facility 

operations. 

As discussed previously, we attempted to provide a 

consistent framework for reporting of emissions information by 

developing the refinery emissions estimation protocol and 

requesting that refineries follow the protocol when reporting 

emissions inventory data in response to the ICR. This protocol, 

called Emission Estimation Protocol for Petroleum Refineries, is 

available in the docket for this rulemaking (Docket Item Number 

EPA-HQ-OAR-2010-0682-0060). Additionally, we developed our own 

estimates of emissions that are based on the factors provided in 

the protocol and the REM Model. We developed emission estimates 

based on refinery unit capacities, which also provided an 

estimate of allowable emissions. We then conducted risk modeling 

using REM Model estimates and by locating emissions at the 
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centroid of each refinery in an attempt to understand the risk 

associated with emissions from each refinery. Therefore, even if 

there were errors in the emission inventories reported in the 

ICR, as was the case in many instances, emissions for those 

facilities were also modeled using the protocol emission 

factors. The risk modeling of allowable emissions based on 

emission factors and unit capacities did not result in 

significantly different risk results than the actual emissions 

modeling runs. Results of the allowable emissions risk estimates 

are provided in the Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector, which is available in Docket 

ID Number EPA-HQ-OAR-2010-0682. 

b. Uncertainties in Dispersion Modeling 

We recognize there is uncertainty in ambient concentration 

estimates associated with any model, including the EPA’s 

recommended regulatory dispersion model, AERMOD. In using a 

model to estimate ambient pollutant concentrations, the user 

chooses certain options to apply. For RTR assessments, we select 

some model options that have the potential to overestimate 

ambient air concentrations (e.g., not including plume depletion 

or pollutant transformation). We select other model options that 

have the potential to underestimate ambient impacts (e.g., not 

including building downwash). Other options that we select have 

the potential to either under- or overestimate ambient levels 
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(e.g., meteorology and receptor locations). On balance, 

considering the directional nature of the uncertainties commonly 

present in ambient concentrations estimated by dispersion 

models, the approach we apply in the RTR assessments should 

yield unbiased estimates of ambient HAP concentrations. 

c. Uncertainties in Inhalation Exposure 

The EPA did not include the effects of human mobility on 

exposures in the assessment. Specifically, short-term mobility 

and long-term mobility between census blocks in the modeling 

domain were not considered.16 The approach of not considering 

short- or long-term population mobility does not bias the 

estimate of the theoretical MIR (by definition), nor does it 

affect the estimate of cancer incidence because the total 

population number remains the same. It does, however, affect the 

shape of the distribution of individual risks across the 

affected population, shifting it toward higher estimated 

individual risks at the upper end and reducing the number of 

people estimated to be at lower risks, thereby increasing the 

estimated number of people at specific high-risk levels (e.g., 

1-in-10 thousand or 1-in-1 million). 

In addition, the assessment predicted the chronic exposures 

at the centroid of each populated census block as surrogates for 

 

16 Short-term mobility is movement from one micro-environment to another over 

the course of hours or days. Long-term mobility is movement from one 

residence to another over the course of a lifetime. 
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the exposure concentrations for all people living in that block. 

Using the census block centroid to predict chronic exposures 

tends to over-predict exposures for people in the census block 

who live further from the facility and under-predict exposures 

for people in the census block who live closer to the facility. 

Thus, using the census block centroid to predict chronic 

exposures may lead to a potential understatement or 

overstatement of the true maximum impact, but is an unbiased 

estimate of average risk and incidence. We reduce this 

uncertainty by analyzing large census blocks near facilities 

using aerial imagery and adjusting the location of the block 

centroid to better represent the population in the block, as 

well as adding additional receptor locations where the block 

population is not well represented by a single location. 

The assessment evaluates the cancer inhalation risks 

associated with pollutant exposures over a 70-year period, which 

is the assumed lifetime of an individual. In reality, both the 

length of time that modeled emission sources at facilities 

actually operate (i.e., more or less than 70 years) and the 

domestic growth or decline of the modeled industry (i.e., the 

increase or decrease in the number or size of domestic 

facilities) will influence the future risks posed by a given 

source or source category. Depending on the characteristics of 

the industry, these factors will, in most cases, result in an 
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overestimate both in individual risk levels and in the total 

estimated number of cancer cases. However, in the unlikely 

scenario where a facility maintains, or even increases, its 

emissions levels over a period of more than 70 years, residents 

live beyond 70 years at the same location, and the residents 

spend most of their days at that location, then the cancer 

inhalation risks could potentially be underestimated. However, 

annual cancer incidence estimates from exposures to emissions 

from these sources would not be affected by the length of time 

an emissions source operates. 

The exposure estimates used in these analyses assume 

chronic exposures to ambient (outdoor) levels of pollutants. 

Because most people spend the majority of their time indoors, 

actual exposures may not be as high, depending on the 

characteristics of the pollutants modeled. For many of the HAP, 

indoor levels are roughly equivalent to ambient levels, but for 

very reactive pollutants or larger particles, indoor levels are 

typically lower. This factor has the potential to result in an 

overestimate of 25 to 30 percent of exposures.17

In addition to the uncertainties highlighted above, there 

are several factors specific to the acute exposure assessment 

that should be highlighted. The accuracy of an acute inhalation 

 

17 U.S. EPA. National-Scale Air Toxics Assessment for 1996. (EPA 453/R–01–003; 

January 2001; page 85.) 
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exposure assessment depends on the simultaneous occurrence of 

independent factors that may vary greatly, such as hourly 

emissions rates, meteorology and human activity patterns. In 

this assessment, we assume that individuals remain for 1 hour at 

the point of maximum ambient concentration as determined by the 

co-occurrence of peak emissions and worst-case meteorological 

conditions. These assumptions would tend to be worst-case actual 

exposures as it is unlikely that a person would be located at 

the point of maximum exposure during the time when peak 

emissions and worst-case meteorological conditions occur 

simultaneously. 

d. Uncertainties in Dose-Response Relationships 

There are uncertainties inherent in the development of the 

dose-response values used in our risk assessments for cancer 

effects from chronic exposures and non-cancer effects from both 

chronic and acute exposures. Some uncertainties may be 

considered quantitatively, and others generally are expressed in 

qualitative terms. We note as a preface to this discussion a 

point on dose-response uncertainty that is brought out in the 

EPA’s 2005 Cancer Guidelines; namely, that “the primary goal of 

EPA actions is protection of human health; accordingly, as an 

Agency policy, risk assessment procedures, including default 

options that are used in the absence of scientific data to the 

contrary, should be health protective” (EPA 2005 Cancer 
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Guidelines, pages 1–7). This is the approach followed here as 

summarized in the next several paragraphs. A complete detailed 

discussion of uncertainties and variability in dose-response 

relationships is given in the Draft Residual Risk Assessment for 

the Petroleum Refining Source Sector, which is available in the 

docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682). 

Cancer URE values used in our risk assessments are those 

that have been developed to generally provide an upper bound 

estimate of risk. That is, they represent a “plausible upper 

limit to the true value of a quantity” (although this is usually 

not a true statistical confidence limit).18 In some 

circumstances, the true risk could be as low as zero; however, 

in other circumstances, the risk could also be greater.19 When 

developing an upper-bound estimate of risk and to provide risk 

values that do not underestimate risk, health-protective default 

approaches are generally used. To err on the side of ensuring 

adequate health-protection, the EPA typically uses the upper 

bound estimates rather than lower bound or central tendency 

estimates in our risk assessments, an approach that may have 

 

18 IRIS glossary 

(http://ofmpub.epa.gov/sor_internet/registry/termreg/searchandretrieve/glossa

riesandkeywordlists/search.do?details=&glossaryName=IRIS%20Glossary). 

19 An exception to this is the URE for benzene, which is considered to cover a 

range of values, each end of which is considered to be equally plausible, and 

which is based on maximum likelihood estimates. 
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limitations for other uses (e.g., priority-setting or expected 

benefits analysis). 

Chronic non-cancer RfC and reference dose (RfD) values 

represent chronic exposure levels that are intended to be 

health-protective levels. Specifically, these values provide an 

estimate (with uncertainty spanning perhaps an order of 

magnitude) of a continuous inhalation exposure (RfC) or a daily 

oral exposure (RfD) to the human population (including sensitive 

subgroups) that is likely to be without an appreciable risk of 

deleterious effects during a lifetime. To derive values that are 

intended to be “without appreciable risk,” the methodology 

relies upon an uncertainty factor (UF) approach (U.S. EPA, 1993, 

1994) which considers uncertainty, variability and gaps in the 

available data. The UF are applied to derive reference values 

that are intended to protect against appreciable risk of 

deleterious effects. The UF are commonly default values,20 e.g., 

 

20 According to the NRC report, Science and Judgment in Risk Assessment (NRC, 

1994) “[Default] options are generic approaches, based on general scientific 

knowledge and policy judgment, that are applied to various elements of the 

risk assessment process when the correct scientific model is unknown or 

uncertain.” The 1983 NRC report, Risk Assessment in the Federal Government: 

Managing the Process, defined default option as “the option chosen on the 

basis of risk assessment policy that appears to be the best choice in the 

absence of data to the contrary” (NRC, 1983a, p. 63). Therefore, default 

options are not rules that bind the Agency; rather, the Agency may depart 

from them in evaluating the risks posed by a specific substance when it 

believes this to be appropriate. In keeping with EPA’s goal of protecting 

public health and the environment, default assumptions are used to ensure 

that risk to chemicals is not underestimated (although defaults are not 

intended to overtly overestimate risk). See EPA, 2004, An Examination of EPA 

Risk Assessment Principles and Practices, EPA/100/B–04/001 available at: 

http://www.epa.gov/osa/pdfs/ratf-final.pdf. 
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factors of 10 or 3, used in the absence of compound-specific 

data; where data are available, UF may also be developed using 

compound-specific information. When data are limited, more 

assumptions are needed and more UF are used. Thus, there may be 

a greater tendency to overestimate risk in the sense that 

further study might support development of reference values that 

are higher (i.e., less potent) because fewer default assumptions 

are needed. However, for some pollutants, it is possible that 

risks may be underestimated. 

While collectively termed “UF,” these factors account for a 

number of different quantitative considerations when using 

observed animal (usually rodent) or human toxicity data in the 

development of the RfC. The UF are intended to account for: (1) 

variation in susceptibility among the members of the human 

population (i.e., inter-individual variability); (2) uncertainty 

in extrapolating from experimental animal data to humans (i.e., 

interspecies differences); (3) uncertainty in extrapolating from 

data obtained in a study with less-than-lifetime exposure (i.e., 

extrapolating from sub-chronic to chronic exposure); (4) 

uncertainty in extrapolating the observed data to obtain an 

estimate of the exposure associated with no adverse effects; and 

(5) uncertainty when the database is incomplete or there are 

problems with the applicability of available studies. 
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Many of the UF used to account for variability and 

uncertainty in the development of acute reference values are 

quite similar to those developed for chronic durations, but they 

more often use individual UF values that may be less than 10. 

The UF are applied based on chemical-specific or health effectspecific information (e.g., simple irritation effects do not 

vary appreciably between human individuals, hence a value of 3 

is typically used), or based on the purpose for the reference 

value (see the following paragraph). The UF applied in acute 

reference value derivation include: (1) heterogeneity among 

humans; (2) uncertainty in extrapolating from animals to humans; 

(3) uncertainty in lowest observable adverse effect (exposure) 

level to no observed adverse effect (exposure) level 

adjustments; and (4) uncertainty in accounting for an incomplete 

database on toxic effects of potential concern. Additional 

adjustments are often applied to account for uncertainty in 

extrapolation from observations at one exposure duration (e.g., 

4 hours) to derive an acute reference value at another exposure 

duration (e.g., 1 hour). 

Not all acute reference values are developed for the same 

purpose and care must be taken when interpreting the results of 

an acute assessment of human health effects relative to the 

reference value or values being exceeded. Where relevant to the 

estimated exposures, the lack of short-term dose-response values 
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at different levels of severity should be factored into the risk 

characterization as potential uncertainties. 

Although every effort is made to identify appropriate human 

health effect dose-response assessment values for all pollutants 

emitted by the sources in this risk assessment, some HAP emitted 

by these source categories are lacking dose-response 

assessments. Accordingly, these pollutants cannot be included in 

the quantitative risk assessment, which could result in 

quantitative estimates understating HAP risk. To help to 

alleviate this potential underestimate, where we conclude 

similarity with a HAP for which a dose-response assessment value 

is available, we use that value as a surrogate for the 

assessment of the HAP for which no value is available. To the 

extent use of surrogates indicates appreciable risk, we may 

identify a need to increase priority for new IRIS assessment of 

that substance. We additionally note that, generally speaking, 

HAP of greatest concern due to environmental exposures and 

hazard are those for which dose-response assessments have been 

performed, reducing the likelihood of understating risk. 

Further, HAP not included in the quantitative assessment are 

assessed qualitatively and considered in the risk 

characterization that informs the risk management decisions, 

including with regard to consideration of HAP reductions 

achieved by various control options. 
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For a group of compounds that are unspeciated (e.g., glycol 

ethers), we conservatively use the most protective reference 

value of an individual compound in that group to estimate risk. 

Similarly, for an individual compound in a group (e.g., ethylene 

glycol diethyl ether) that does not have a specified reference 

value, we also apply the most protective reference value from 

the other compounds in the group to estimate risk. 

e. Uncertainties in the Multipathway Assessment 

For each source category, we generally rely on sitespecific levels of PB-HAP emissions to determine whether a 

refined assessment of the impacts from multipathway exposures is 

necessary. This determination is based on the results of a twotiered screening analysis that relies on the outputs from models 

that estimate environmental pollutant concentrations and human 

exposures for four PB-HAP. Two important types of uncertainty 

associated with the use of these models in RTR risk assessments 

and inherent to any assessment that relies on environmental 

modeling are model uncertainty and input uncertainty.21

Model uncertainty concerns whether the selected models are 

appropriate for the assessment being conducted and whether they 

adequately represent the actual processes that might occur for 

 

21 In the context of this discussion, the term “uncertainty” as it pertains to 

exposure and risk encompasses both variability in the range of expected 

inputs and screening results due to existing spatial, temporal, and other 

factors, as well as uncertainty in being able to accurately estimate the true 

result. 
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that situation. An example of model uncertainty is the question 

of whether the model adequately describes the movement of a 

pollutant through the soil. This type of uncertainty is 

difficult to quantify. However, based on feedback received from 

previous EPA SAB reviews and other reviews, we are confident 

that the models used in the screen are appropriate and state-ofthe-art for the multipathway risk assessments conducted in 

support of RTR. 

Input uncertainty is concerned with how accurately the 

models have been configured and parameterized for the assessment 

at hand. For Tier I of the multipathway screen, we configured 

the models to avoid underestimating exposure and risk. This was 

accomplished by selecting upper-end values from nationallyrepresentative data sets for the more influential parameters in 

the environmental model, including selection and spatial 

configuration of the area of interest, lake location and size, 

meteorology, surface water and soil characteristics and 

structure of the aquatic food web. We also assume an ingestion 

exposure scenario and values for human exposure factors that 

represent reasonable maximum exposures. 

In Tier II of the multipathway assessment, we refine the 

model inputs to account for meteorological patterns in the 

vicinity of the facility versus using upper-end national values 

and we identify the actual location of lakes near the facility 
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rather than the default lake location that we apply in Tier I. 

By refining the screening approach in Tier II to account for 

local geographical and meteorological data, we decrease the 

likelihood that concentrations in environmental media are 

overestimated, thereby increasing the usefulness of the screen. 

The assumptions and the associated uncertainties regarding the 

selected ingestion exposure scenario are the same for Tier I and 

Tier II. 

For both Tiers I and II of the multipathway assessment, our 

approach to addressing model input uncertainty is generally 

cautious. We choose model inputs from the upper end of the range 

of possible values for the influential parameters used in the 

models, and we assume that the exposed individual exhibits 

ingestion behavior that would lead to a high total exposure. 

This approach reduces the likelihood of not identifying high 

risks for adverse impacts. 

Despite the uncertainties, when individual pollutants or 

facilities do screen out, we are confident that the potential 

for adverse multipathway impacts on human health is very low. On 

the other hand, when individual pollutants or facilities do not 

screen out, it does not mean that multipathway impacts are 

significant, only that we cannot rule out that possibility and 

that a refined multipathway analysis for the site might be 
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necessary to obtain a more accurate risk characterization for 

the source categories. 

For further information on uncertainties and the Tier I and 

II screening methods, refer to the risk document Appendix 4, 

Technical Support Document for TRIM-Based Multipathway Tiered 

Screening Methodology for RTR. 

f. Uncertainties in the Environmental Risk Screening Assessment 

For each source category, we generally rely on sitespecific levels of environmental HAP emissions to perform an 

environmental screening assessment. The environmental screening 

assessment is based on the outputs from models that estimate 

environmental HAP concentrations. The same models, specifically 

the TRIM.FaTE multipathway model and the AERMOD air dispersion 

model, are used to estimate environmental HAP concentrations for 

both the human multipathway screening analysis and for the 

environmental screening analysis. Therefore, both screening 

assessments have similar modeling uncertainties. 

Two important types of uncertainty associated with the use 

of these models in RTR environmental screening assessments—and 

inherent to any assessment that relies on environmental 

modeling—are model uncertainty and input uncertainty.22

 

22 In the context of this discussion, the term “uncertainty,” as it pertains 

to exposure and risk assessment, encompasses both variability in the range of 

expected inputs and screening results due to existing spatial, temporal, and 

other factors, as well as uncertainty in being able to accurately estimate 

the true result.
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Model uncertainty concerns whether the selected models are 

appropriate for the assessment being conducted and whether they 

adequately represent the movement and accumulation of 

environmental HAP emissions in the environment. For example, 

does the model adequately describe the movement of a pollutant 

through the soil? This type of uncertainty is difficult to 

quantify. However, based on feedback received from previous EPA 

SAB reviews and other reviews, we are confident that the models 

used in the screen are appropriate and state-of-the-art for the 

environmental risk assessments conducted in support of our RTR 

analyses. 

Input uncertainty is concerned with how accurately the 

models have been configured and parameterized for the assessment 

at hand. For Tier I of the environmental screen for PB-HAP, we 

configured the models to avoid underestimating exposure and risk 

to reduce the likelihood that the results indicate the risks are 

lower than they actually are. This was accomplished by selecting 

upper-end values from nationally-representative data sets for 

the more influential parameters in the environmental model, 

including selection and spatial configuration of the area of 

interest, the location and size of any bodies of water, 

meteorology, surface water and soil characteristics and 

structure of the aquatic food web. In Tier I, we used the 

maximum facility-specific emissions for cadmium compounds, 
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dioxins/furans, POM, and mercury and each of the media when 

comparing to ecological benchmarks. This is consistent with the 

conservative design of Tier I of the screen. In Tier II of the 

environmental screening analysis for PB-HAP, we refine the model 

inputs to account for meteorological patterns in the vicinity of 

the facility versus using upper-end national values, and we 

identify the locations of water bodies near the facility 

location. By refining the screening approach in Tier II to 

account for local geographical and meteorological data, we 

decrease the likelihood that concentrations in environmental 

media are overestimated, thereby increasing the usefulness of 

the screen. To better represent widespread impacts, the modeled 

soil concentrations are averaged in Tier II to obtain one 

average soil concentration value for each facility and for each 

PB-HAP. For PB-HAP concentrations in water, sediment and fish 

tissue, the highest value for each facility for each pollutant 

is used. 

For the environmental screening assessment for acid gases, 

we employ a single-tiered approach. We use the modeled air 

concentrations and compare those with ecological benchmarks. 

For both Tiers I and II of the environmental screening 

assessment, our approach to addressing model input uncertainty 

is generally cautious. We choose model inputs from the upper end 

of the range of possible values for the influential parameters 
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used in the models, and we assume that the exposed organism 

(e.g., invertebrate, fish) exhibits ingestion behavior that 

would lead to a high total exposure. This approach reduces the 

likelihood of not identifying potential risks for adverse 

environmental impacts. 

Uncertainty also exists in the ecological benchmarks for 

the environmental risk screening analysis. We established a 

hierarchy of preferred benchmark sources to allow selection of 

benchmarks for each environmental HAP at each ecological 

assessment endpoint. In general, EPA benchmarks used at a 

programmatic level (e.g., Office of Water, Superfund Program) 

were used if available. If not, we used EPA benchmarks used in 

regional programs (e.g., Superfund). If benchmarks were not 

available at a programmatic or regional level, we used 

benchmarks developed by other agencies (e.g., NOAA) or by state 

agencies. 

In all cases (except for lead, which was evaluated through 

a comparison to the NAAQS), we searched for benchmarks at the 

following three effect levels, as described in section III.A.6 

of this preamble: 

1. A no-effect level (i.e., NOAEL). 

2. Threshold-effect level (i.e., LOAEL). 

3. Probable effect level (i.e., PEL). 
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For some ecological assessment endpoint/environmental HAP 

combinations, we could identify benchmarks for all three effect 

levels, but for most, we could not. In one case, where different 

agencies derived significantly different numbers to represent a 

threshold for effect, we included both. In several cases, only a 

single benchmark was available. In cases where multiple effect 

levels were available for a particular PB-HAP and assessment 

endpoint, we used all of the available effect levels to help us 

to determine whether risk exists and if the risks could be 

considered significant and widespread. 

The EPA evaluated the following seven HAP in the 

environmental risk screening assessment: cadmium, 

dioxins/furans, POM, mercury (both inorganic mercury and methyl 

mercury), lead compounds, HCl and HF. These seven HAP represent 

pollutants that can cause adverse impacts for plants and animals 

either through direct exposure to HAP in the air or through 

exposure to HAP that is deposited from the air onto soils and 

surface waters. These seven HAP also represent those HAP for 

which we can conduct a meaningful environmental risk screening 

assessment. For other HAP not included in our screening 

assessment, the model has not been parameterized such that it 

can be used for that purpose. In some cases, depending on the 

HAP, we may not have appropriate multipathway models that allow 

us to predict the concentration of that pollutant. The EPA 
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acknowledges that other HAP beyond the seven HAP that we are 

evaluating may have the potential to cause adverse environmental 

effects and, therefore, the EPA may evaluate other relevant HAP 

in the future, as modeling science and resources allow. 

Further information on uncertainties and the Tier I and II 

environmental screening methods is provided in Appendix 5 of the 

document Technical Support Document for TRIM-Based Multipathway 

Tiered Screening Methodology for RTR: Summary of Approach and 

Evaluation. Also, see the Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector, available in the docket for 

this action (Docket ID Number EPA-HQ-OAR-2010-0682). 

B. How did we consider the risk results in making decisions for 

this proposal? 

As discussed in section II.A.1 of this preamble, in 

evaluating and developing standards under CAA section 112(f)(2), 

we apply a two-step process to address residual risk. In the 

first step, the EPA determines whether risks are acceptable. 

This determination “considers all health information, including 

risk estimation uncertainty, and includes a presumptive limit on 

maximum individual lifetime [cancer] risk (MIR)23 of 

approximately [1-in-10 thousand] [i.e., 100-in-1 million].” 54 

FR 38045, September 14, 1989. If risks are unacceptable, the EPA 

 

23 Although defined as “maximum individual risk,” MIR refers only to cancer 

risk. MIR, one metric for assessing cancer risk, is the estimated risk were 

an individual exposed to the maximum level of a pollutant for a lifetime. 
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must determine the emissions standards necessary to bring risks 

to an acceptable level without considering costs. In the second 

step of the process, the EPA considers whether the emissions 

standards provide an ample margin of safety “in consideration of 

all health information, including the number of persons at risk 

levels higher than approximately 1-in-1 million, as well as 

other relevant factors, including costs and economic impacts, 

technological feasibility, and other factors relevant to each 

particular decision.” Id. The EPA must promulgate tighter 

emission standards if necessary to provide an ample margin of 

safety. 

In past residual risk actions, the EPA considered a number 

of human health risk metrics associated with emissions from the 

categories under review, including the MIR, the number of 

persons in various risk ranges, cancer incidence, the maximum 

non-cancer HI and the maximum acute non-cancer hazard. See, 

e.g., 72 FR 25138, May 3, 2007; 71 FR 42724, July 27, 2006. The 

EPA considered this health information for both actual and 

allowable emissions. See, e.g., 75 FR 65068, October 21, 2010, 

and 75 FR 80220, December 21, 2010). The EPA also discussed risk 

estimation uncertainties and considered the uncertainties in the 

determination of acceptable risk and ample margin of safety in 

these past actions. The EPA considered this same type of 

information in support of this action. 
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The agency is considering these various measures of health 

information to inform our determinations of risk acceptability 

and ample margin of safety under CAA section 112(f). As 

explained in the Benzene NESHAP, “the first step of judgment on 

acceptability cannot be reduced to any single factor,” and thus 

“[t]he Administrator believes that the acceptability of risk 

under [previous] section 112 is best judged on the basis of a 

broad set of health risk measures and information.” 54 FR 38046, 

September 14, 1989. Similarly, with regard to making the ample 

margin of safety determination, “the Agency again considers all 

of the health risk and other health information considered in 

the first step. Beyond that information, additional factors 

relating to the appropriate level of control will also be 

considered, including cost and economic impacts of controls, 

technological feasibility, uncertainties, and any other relevant 

factors.” Id. 

The Benzene NESHAP approach provides flexibility regarding 

factors the EPA may consider in making determinations and how 

the EPA may weigh those factors for each source category. In 

responding to comment on our policy under the Benzene NESHAP, 

the EPA explained that: 

“[t]he policy chosen by the Administrator permits 

consideration of multiple measures of health risk. Not only 

can the MIR figure be considered, but also incidence, the 

presence of non-cancer health effects, and the 

uncertainties of the risk estimates. In this way, the 
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effect on the most exposed individuals can be reviewed as 

well as the impact on the general public. These factors can 

then be weighed in each individual case. This approach 

complies with the Vinyl Chloride mandate that the 

Administrator ascertain an acceptable level of risk to the 

public by employing [her] expertise to assess available 

data. It also complies with the Congressional intent behind 

the CAA, which did not exclude the use of any particular 

measure of public health risk from the EPA’s consideration 

with respect to CAA section 112 regulations, and thereby 

implicitly permits consideration of any and all measures of 

health risk which the Administrator, in [her] judgment, 

believes are appropriate to determining what will ‘protect 

the public health.’” 

See 54 FR at 38057, September 14, 1989. Thus, the level of the 

MIR is only one factor to be weighed in determining 

acceptability of risks. The Benzene NESHAP explained that “an 

MIR of approximately one in 10 thousand should ordinarily be the 

upper end of the range of acceptability. As risks increase above 

this benchmark, they become presumptively less acceptable under 

CAA section 112, and would be weighed with the other health risk 

measures and information in making an overall judgment on 

acceptability. Or, the Agency may find, in a particular case, 

that a risk that includes MIR less than the presumptively 

acceptable level is unacceptable in the light of other health 

risk factors.” Id. at 38045. Similarly, with regard to the ample 

margin of safety analysis, the EPA stated in the Benzene NESHAP 

that: “EPA believes the relative weight of the many factors that 

can be considered in selecting an ample margin of safety can 

only be determined for each specific source category. This 
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occurs mainly because technological and economic factors (along 

with the health-related factors) vary from source category to 

source category.” Id. at 38061. We also consider the 

uncertainties associated with the various risk analyses, as 

discussed earlier in this preamble, in our determinations of 

acceptability and ample margin of safety. 

The EPA notes that it has not considered certain health 

information to date in making residual risk determinations. At 

this time, we do not attempt to quantify those HAP risks that 

may be associated with emissions from other facilities that do 

not include the source categories in question, mobile source 

emissions, natural source emissions, persistent environmental 

pollution or atmospheric transformation in the vicinity of the 

sources in these categories. 

The agency understands the potential importance of 

considering an individual’s total exposure to HAP in addition to 

considering exposure to HAP emissions from the source category 

and facility. We recognize that such consideration may be 

particularly important when assessing non-cancer risks, where 

pollutant-specific health reference levels (e.g., RfCs) are 

based on the assumption that thresholds exist for adverse health 

effects. For example, the agency recognizes that, although 

exposures attributable to emissions from a source category or 

facility alone may not indicate the potential for increased risk 
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of adverse non-cancer health effects in a population, the 

exposures resulting from emissions from the facility in 

combination with emissions from all of the other sources (e.g., 

other facilities) to which an individual is exposed may be 

sufficient to result in increased risk of adverse non-cancer 

health effects. In May 2010, the SAB advised the EPA “that RTR 

assessments will be most useful to decision makers and 

communities if results are presented in the broader context of 

aggregate and cumulative risks, including background 

concentrations and contributions from other sources in the 

area.”24

In response to the SAB recommendations, the EPA is 

incorporating cumulative risk analyses into its RTR risk 

assessments, including those reflected in this proposal. The 

agency is: (1) conducting facility-wide assessments, which 

include source category emission points as well as other 

emission points within the facilities; (2) considering sources 

in the same category whose emissions result in exposures to the 

same individuals; and (3) for some persistent and 

bioaccumulative pollutants, analyzing the ingestion route of 

 

24 EPA’s responses to this and all other key recommendations of the SAB’s 

advisory on RTR risk assessment methodologies (which is available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/4AB3966E263D943A8525771F00668381/$

File/EPA-SAB-10-007-unsigned.pdf) are outlined in a memo to this rulemaking 

docket from David Guinnup entitled, EPA’s Actions in Response to the Key 

Recommendations of the SAB Review of RTR Risk Assessment Methodologies. 
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exposure. In addition, the RTR risk assessments have always 

considered aggregate cancer risk from all carcinogens and 

aggregate non-cancer hazard indices from all non-carcinogens 

affecting the same target organ system. 

Although we are interested in placing source category and 

facility-wide HAP risks in the context of total HAP risks from 

all sources combined in the vicinity of each source, we are 

concerned about the uncertainties of doing so. Because we have 

not conducted in-depth studies of risks due to emissions from 

sources other those at refineries subject to this RTR review, 

such estimates of total HAP risks would have significantly 

greater associated uncertainties than the source category or 

facility-wide estimates. Such aggregate or cumulative 

assessments would compound those uncertainties, making the 

assessments too unreliable. 

C. How did we perform the technology review? 

Our technology review focused on the identification and 

evaluation of developments in practices, processes and control 

technologies that have occurred since the MACT standards were 

promulgated. Where we identified such developments, in order to 

inform our decision of whether it is “necessary” to revise the 

emissions standards, we analyzed the technical feasibility of 

applying these developments, and the estimated costs, energy 

implications, non-air environmental impacts, as well as 
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considering the emission reductions. We also considered the 

appropriateness of applying controls to new sources versus 

retrofitting existing sources. 

Based on our analyses of the available data and 

information, we identified potential developments in practices, 

processes and control technologies. For this 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 
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EPA considered during the development of the original MACT 

standards). 

We reviewed a variety of data sources in our investigation 

of potential practices, processes or controls to consider. Among 

the sources we reviewed were the NESHAP for various industries 

that were promulgated since the MACT standards being reviewed in 

this action. We reviewed the regulatory requirements and/or 

technical analyses associated with these regulatory actions to 

identify any practices, processes and control technologies 

considered in these efforts that could be applied to emission 

sources subject to Refinery MACT 1 or 2, as well as the costs, 

non-air impacts and energy implications associated with the use 

of these technologies. Additionally, we requested information 

from facilities as described in section II.C of this preamble. 

Finally, we reviewed information from other sources, such as 

state and/or local permitting agency databases and industrysupported databases. 

IV. Analytical Results and Proposed Decisions 

A. What actions are we taking pursuant to CAA sections 112(d)(2) 

and 112(d)(3)? 

In this action, we are proposing the following revisions to 

the Refinery MACT 1 and 2 standards pursuant to CAA section 
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112(d)(2) and (3)25: (1) adding MACT standards for DCU decoking 

operations; (2) revising the CRU purge vent pressure exemption; 

(3) adding operational requirements for flares used as air 

pollution control devices (APCD) in Refinery MACT 1 and 2; and 

(4) adding requirements and clarifications for vent control 

bypasses in Refinery MACT 1. The results and proposed decisions 

based on the analyses performed pursuant to CAA section 

112(d)(2) and (3) are presented below. 

1. Delayed Coking Units 

a. Description of Delayed Coker Process Operations and Emissions 

We are proposing to establish MACT standards specific to 

the DCU pursuant to CAA section 112(d)(2) and (3). The DCU uses 

thermal cracking to upgrade heavy feedstocks and to produce 

petroleum coke. Unlike most other refinery operations that are 

continuous, the DCU operates in a semi-batch system. Most DCU 

consist of a large process heater, two or more coking drums, and 

a single product distillation column. The DCU feed is actually 

fed to the unit’s distillation column. Bottoms from the 

distillation column are heated to near cracking temperatures and 

the resulting heavy oil is fed to one of the coking drums. As 

 

25 The 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 post-compliance data, when originallyestablished floors were improperly established). 
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the cracking reactions occur, coke is produced in the drum and 

begins to fill the drum with sponge-like solid coke material. 

During this process, the DCU is a closed system, with the 

produced gas streams piped to the unit’s distillation column for 

product recovery. 

When the first coke drum becomes filled with coke, the feed 

is diverted to the second coke drum and processing continues via 

the second coke drum. The full coke drum, which is no longer 

receiving oil feed, is taken through a number of steps, 

collectively referred to as decoking operations, to remove the 

coke from the drum and prepare the drum for subsequent oil feed 

processing. The decoking steps include: purging, 

cooling/quenching, venting, draining, deheading, and coke 

cutting. A description of these steps and the potential 

emissions from these activities are provided in the next several 

paragraphs. Once the coke is removed, the vessel is re-sealed 

(i.e., the drain valve is closed and the “head” is re-attached), 

pressure tested (typically using steam), purged to remove 

oxygen, then slowly heated to processing temperatures so it can 

go back on-line. When the second coke drum becomes filled with 

coke, feed is diverted back to the first coke drum and the 

second drum is then decoked. In this manner, the DCU allows for 

continuous processing of oil even though the individual coke 

drums operate in cyclical batch fashion. 
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The first step in decoking operations is to purge the coke 

drum with steam. This serves to cool the coke bed and to flush 

oil or reaction products from the coke bed. The steam purge is 

initially sent to the product distillation column and then 

diverted to the unit’s blowdown system. The blowdown system 

serves to condense the steam and other liquids entrained in the 

steam. Nearly all DCU operate a ”closed blowdown” system, such 

that uncondensed gases from the blowdown system are sent to the 

product distillation column or the facility’s light gas plant, 

recovered as fuel gas, or combusted in a flare. In an open 

blowdown system, these uncondensed gases would be vented 

directly to atmosphere. The DCU vent discharge to the blowdown 

system is specifically defined in Refinery MACT 1 as the 

“delayed coker vent.” 

The next step in the decoking process is cooling/quenching 

the coke drum and its contents via the addition of water, 

commonly referred to as quench water, at the bottom of the coke 

drum. The water added to the vessel quickly turns to steam due 

to the high temperature of the coke bed. The water/steam helps 

to further cool the coke bed and “quench” any residual coking 

reactions that may still occur within the hot coke bed. As with 

the steam purge, steam off-gas from the cooling/quenching cycle 

is recovered in the unit’s blowdown system and this vent 
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discharge is specifically defined in Refinery MACT 1 as the 

“delayed coker vent.” 

After several hours, the coke drum is sufficiently cooled 

so that the water level in the drum can be raised to entirely 

cover the coke bed. Although water covers the coke bed, the 

upper portion of the coke bed may still be well above 212 

degrees Fahrenheit (°F) and will continue to generate steam. In 

fact, since the coke drum vessel pressure is greater than 

atmospheric pressure, the equilibrium boiling point of water in 

the vessel is greater than 212 °F. Therefore, the water at the 

top of the coke drum is typically well above 212 °F (superheated 

water). As the coke drum and its contents continue to cool from 

the evaporative cooling effect of the steam generation, the 

steam generation rate and the pressure within the vessel will 

decrease. 

Owners or operators of DCU may use different indicators or 

set points to determine when the system has cooled sufficiently 

to move to the venting step; however, one of the most common 

indicators monitored is the pressure of the coke drum vessel (or 

steam vent line just above the coke drum, where steam exits the 

coke drum en route to the blowdown system). When the vessel has 

cooled sufficiently (e.g., when the coke drum vessel pressure 

reaches the desired set point), valves are opened to allow the 

steam generated in the coke drum to vent directly to the 
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atmosphere rather than the closed blowdown system. This vent is 

commonly referred to as the “coker steam vent” and is typically 

the first direct atmospheric emission release during the 

decoking operations when an enclosed blowdown system is used. 

While this vent gas contains predominately steam, methane and 

ethane, a variety of HAP are also emitted with this steam. These 

HAP include light aromatics (e.g., benzene, toluene, and xylene) 

and light POM (predominately naphthalene and 2-methyl 

naphthalene). The level of HAP emitted from the DCU has been 

found to be a function of the quantity of steam generated (see 

the technical memorandum entitled Impacts Estimates for Delayed 

Coking Units in Docket ID Number EPA-HQ-OAR-2010-0682). 

In general, the next step in the decoking process is 

draining the water from the coke drum by opening a large valve 

at the bottom of the coke drum. The drain water typically falls 

from the coke drum onto a slanted concrete pad that directs the 

water to the coke pit area (where water and coke are collected 

and separated). Some DCU owners or operators initiate draining 

at the same time they initiate venting; other owners or 

operators may allow the vessel to vent for 20 or more minutes 

prior to initiating draining. While draining immediately may 

reduce the amount of steam exiting the unit via the stack, as 

explained below, it is not expected to alter the overall 

emissions from the unit. During the venting and draining 
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process, the pressure of the system falls to atmospheric. Steam 

will be generated until the evaporative cooling effect of that 

steam generation cools the coker quench water to 212 °F. If 

draining is initiated immediately, some of the superheated water 

may drain from the DCU before being cooled. A portion of that 

drained water will then convert to steam during the draining 

process as that superheated water contacts the open atmosphere. 

Therefore, draining quickly is not expected to alter the total 

amount of steam generated from the unit nor alter the overall 

emissions from the unit. It will, however, alter the relative 

proportion of the emissions that are released via the vent 

versus the quench water drain area. 

The next step in the decoking process is “deheading” the 

coke drum. At the top of the coke drum is a large 3- to 5-foot 

diameter opening, which is sealed with a gasketed lid during 

normal operations. When the steam generation rate from the coke 

drum has sufficiently subsided, this gasketed lid is removed to 

allow access for a water drill that will be used to remove coke 

from the drum. The process of removing this lid is referred to 

as “deheading” the coke drum. Different DCU owners or operators 

may use different criteria for when to dehead the coke drum. If 

the coke drum is deheaded soon after venting is initiated, some 

steam and associated HAP emissions may be released from this 

opening. As with draining, it is anticipated that the total 
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volume of steam generated will be a function of the 

temperature/pressure of the coke drum. Deheading the coke drum 

prior to the coke drum contents reaching 212 °F will generally 

mean that some of the steam will be released from the coke drum 

head opening. However, this will not alter the total amount of 

steam generated; it merely alters the location of the release 

(coke drum head opening versus steam vent). The HAP emissions 

from the deheading process are expected to be proportional to 

the amount of steam released in the same manner as the emissions 

from the steam vent. 

The final step of the decoking process is coke cutting. A 

high-pressure water jet is used to drill or cut the coke out of 

the vessel. The drilling water and coke slurry exits the coke 

drum via the drain opening and collects in the coke pit. 

Generally, the coke drum and its contents are sufficiently 

cooled so that this process is not expected to yield significant 

HAP emissions. However, if the other decoking steps are 

performed too quickly, hot spots may exist within the coke bed 

and HAP emissions may occur as water contacts these hot spots 

and additional steam and emissions are released. 

Once the coke is cut out of the drum, the drum is closed 

and prepared to go back on-line. This process includes 

pressurizing with steam to ensure there are no leaks (i.e., that 

the head is properly attached and sealed and the drain valve is 
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fully closed). The vessel is then purged to remove any oxygen 

and heated by diverting the produced gas from the processing 

coke drum through the empty drum prior to sending it to the 

unit’s distillation column. A coke drum cycle is typically 28 to 

36 hours from start of feed to start of the next feed. 

b. How Delayed Coker Vents are Addressed in Refinery MACT 1 

Delayed coker vents are specifically mentioned as an 

example within the first paragraph of the definition of 

“miscellaneous process vent” in 40 CFR 63.641 of Refinery MACT 

1. However, the definition of “miscellaneous process vent” also 

excludes coking unit vents associated with coke drum 

depressuring (at or below a coke drum outlet pressure of 15 

pounds per square inch gauge [psig]), deheading, draining, or 

decoking (coke cutting) or pressure testing after decoking. 

Refinery MACT 1 also includes a definition of “delayed coker 

vent” in 40 CFR 63.641. This vent is typically intermittent in 

nature, and usually occurs only during the initiation of the 

depressuring cycle of the decoking operation when vapor from the 

coke drums cannot be sent to the fractionator column for product 

recovery, but instead is routed to the atmosphere through a 

closed blowdown system or directly to the atmosphere in an open 

blowdown system. The emissions from the decoking phases of DCU 

operations, which include coke drum deheading, draining, or 
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decoking (coke cutting), are not considered to be delayed coker 

vents. 

The first paragraph of the definition of “miscellaneous 

process vent” also includes blowdown condensers/accumulators as 

an example of a miscellaneous process vent. Therefore, the DCU 

blowdown system is a miscellaneous process vent regardless of 

whether or not the blowdown system is associated with a DCU or 

another process unit. Further, the inclusion of the “delayed 

coker vent” as an example of a miscellaneous process vent makes 

it clear that the DCU’s blowdown system vent (if an open 

blowdown system is used) is considered a miscellaneous process 

vent. It is less clear from the regulatory text whether the 

direct venting of the coke drum to the atmosphere via the steam 

vent during the final depressurization is considered to be a 

“delayed coker vent” (i.e., whether direct venting to the 

atmosphere is equivalent to venting “directly to the atmosphere 

in an open blowdown system”). 

The regulatory text is clear that this steam vent is exempt 

from the definition of “miscellaneous process vent” when the 

pressure of the vessel is less than 15 psig. It is also clear 

that the subsequent release points from the decoking operations 

(i.e., deheading, draining, and coke cutting) are excluded from 

both the definition of “delayed coker vent” and the definition 

of “miscellaneous process vent.” Further, based on the 
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statements in the background information document for the August 

1995 final Refinery MACT 1 rule,26 the 15 psig pressure limit for 

the direct venting of the DCU to the atmosphere was not 

established as a MACT floor control level; it was established to 

accommodate all DCU at whatever pressure they typically switched 

from venting to the closed blowdown system to venting directly 

to the atmosphere. Based on this information, as well as the 

data from the 2011 Refinery ICR, refinery enforcement 

settlements and other information available, which indicate that 

all refineries depressurize the coke drum below 15 psig, we have 

determined that the direct atmospheric releases from the DCU 

decoking operations are currently unregulated emissions. These 

unregulated releases include emissions during atmospheric 

depressuring (i.e., the steam vent), deheading, draining, and 

coke cutting. 

c. Evaluation of MACT Emission Limitations for Delayed Coking 

Units 

We evaluated emissions and controls during DCU decoking 

operations in order to identify appropriate MACT emission 

limitations pursuant to CAA section 112(d)(2) and (3). 

Establishing a lower pressure set point at which a DCU owner or 

operator can switch from venting to an enclosed blowdown system 

 

26 National Emission Standards for Hazardous Air Pollutants Petroleum 

Refineries - Background Information for Final Standards; EPA-453/R-95-015b. 
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to venting to the atmosphere is the control technique identified 

for reducing emissions from delayed coking operations. 

Essentially, there is a fixed quantity of steam that will be 

generated as the coke drum and its contents cool. The lower 

pressure set point will require the DCU to vent to the closed 

blowdown system longer, where the organic HAP can be recovered 

or controlled. This will result in fewer emissions released 

during the venting, draining and deheading process. 

We consider this control technique, which is a work 

practice standard, appropriate for the DCU for the reasons 

discussed below for each of the four possible emission points at 

the DCU: draining, deheading, coke cutting and the steam vent. 

For the first three steps, the emissions cannot be emitted 

through a conveyance designed and constructed to emit or capture 

such pollutant. For example, during draining, the drain water 

typically falls from the coke drum onto a slanted concrete pad 

that directs the water to an open coke pit area (where water and 

coke are collected and separated). When the coke drum is 

deheaded, the coke drum head must be removed to provide an 

accessible opening in the drum so the coke cutting equipment can 

be lowered into the drum. This opening cannot be sealed during 

coke cutting because the drilling shaft will occupy the opening 

and the shaft must be free to be lowered or raised during the 

coke cutting process. 
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While the emissions from the fourth point, the DCU steam 

vent, are released via a conveyance designed and constructed to 

emit or capture such pollutant, as provided in CAA section 

112(h)(2)(B), it is not feasible to prescribe or enforce an 

emission standard for the DCU steam vent because the application 

of a measurement methodology for this source is not practicable 

due to technological and economic limitations. 

First, it is not practicable to use a measurement 

methodology for the DCU steam vent. The emissions from the vent 

typically contain 99 percent water, which interferes with common 

sample collection and analysis techniques. Also, the flow rate 

from this vent is not constant; rather, it decreases during the 

venting process as the pressure in the DCU coke drum approaches 

atmospheric pressure. Additionally, the venting time can be very 

short. As part of the ICR, we requested stack testing of eight 

DCU. After discussions with stack testing experts within the 

agency and with outside contractors used by industry to perform 

the tests, we concluded that sources with venting times less 

than 20 minutes would not be able to perform an emissions test 

that would yield valid results. Therefore, only two of the eight 

facilities actually performed the tests. We anticipate all units 

complying with the proposed standards for DCU steam vents would 

vent for less than 20 minutes. 
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Second, it is not feasible to enforce an emission standard 

only on the steam vent because the timing of drainage and 

deheading can alter the portion of the decoking emissions that 

are released from the actual steam vent. If draining and 

deheading are initiated quickly after venting, this will reduce 

the emissions discharged from the vent (although as explained 

above, it does not reduce the emissions from the collective set 

of decoking operations release points). 

Consequently, due to the unique nature of DCU emissions, 

the difficulties associated with monitoring the DCU steam vent, 

and the inability to construct a conveyance to capture emissions 

from all decoking release points, we are proposing that it is 

appropriate to develop work practice standards in place of 

emission limits for the DCU. 

To establish the MACT floor, we then reviewed regulations, 

permits and consent decrees that require coke controls. Refinery 

NSPS Ja establishes a pressure limit of 5 psig prior to allowing 

the coke drum to be vented to the atmosphere. Based on a review 

of permit limits and consent decrees, we found that coke drum 

vessel pressure limits have been established (and achieved) as 

low as 2 psig. There are 75 operating DCU according to the 

Refinery ICR responses, so the sixth percentile is represented 

by the fifth-best performing DCU. We identified eight DCU with 

permit requirements or consent decrees specifying a coke drum 
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venting pressure limit of 2 psig; we did not identify any permit 

or consent decree requirements more stringent than 2 psig. 

Refinery owners and operators were asked to provide the “typical 

coke drum pressure just prior to venting” for each DCU in their 

responses to the Refinery ICR, and the responses indicate that 

four DCU operate such that the typical venting pressure is 1 

psig or less. However, this “typical coke drum pressure” does 

not represent a not-to-be-exceeded pressure limit; it is 

expected that these units are operated this way to meet a 

pressure limit of 2 psig. We do not have information to indicate 

whether these facilities are always depressurized at 1 psig or 

less. Moreover, there were only four units for which a typical 

venting pressure of 1 psig was identified and the MACT floor for 

existing sources is represented by the fifth-best operating DCU, 

not the best-performing unit. Therefore, we are proposing that 

the MACT floor for DCU decoking operations is to depressure at 2 

psig or less prior to venting to the atmosphere for existing 

sources. We are also proposing that the MACT floor for new 

sources is 2 psig, since the best-performing source is permitted 

to depressure at 2 psig or less. For additional details on the 

MACT floor analysis, see memorandum entitled MACT Analysis for 

Delayed Coking Unit Decoking Operations in Docket ID Number EPAHQ-OAR-2010-0682. 
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We then considered control options beyond the floor level 

of 2 psig to determine if additional emission reductions could 

be cost-effectively achieved. We considered establishing a 

venting pressure limit of 1 psig or less, since four facilities 

reported in the ICR that the typical coke drum pressure prior to 

depressurizing was 1 psig. There are several technical 

difficulties associated with establishing a pressure limit at 

this lower level. First, the lowest pressure at any point in a 

closed blowdown system is generally designed to be no lower than 

0.5 psig. Consequently, the DCU compressor system would operate 

with an inlet pressure of no less than 0.5 psig. Second, there 

are several valves and significant piping (for cooling and 

condensing steam) between the DCU drum and the recovery 

compressor. There is an inherent pressure drop when a fluid 

flows through a pipe or valve. Two valves are used for all DCU 

lines to make sure that the unit is either blocked off from the 

processing fluids or blocked in so there are no product losses 

out the steam line during processing. Considering the need for 

two valves and piping needed in the cooling system, DCU designed 

for a minimal pressure loss will generally still have a 0.5 to 1 

psig pressure drop between the DCU drum and the recovery 

compressor inlet, even for a new DCU designed to minimize this 

pressure drop. Finally, in order to meet a 1 psig pressure limit 

at all times, the DCU closed vent system would need to be 
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designed to achieve a vessel pressure of approximately 0.5 psig. 

Given the above considerations, it is not technically feasible 

for new or existing DCU to routinely achieve a vessel pressure 

of 0.5 psig in order to comply with a never-to-be-exceeded drum 

vessel pressure of 1 psig. As noted previously, facilities that 

“typically” achieve vessel pressures of about 1 psig or less are 

expected to do so in order to meet a never-to-be-exceeded drum 

vessel pressure limit of 2 psig and they are not expected to be 

able to comply with a never-to-be-exceeded drum vessel pressure 

limit of 1 psig. 

We considered setting additional work practice standards 

regarding draining, deheading, and coke cutting. The decoking 

emissions can be released from a variety of locations, and the 

2-psig-or-less limit for depressurizing the coke drum will 

effectively reduce the emissions from all of these emission 

points, provided that atmospheric venting via the DCU steam vent 

is the first step in the decoking process. However, it is 

possible to start draining water prior to opening the steam 

vent. We are concerned that owners or operators may adopt this 

practice as a means to reduce pressure in the coke drum prior to 

venting the drum to the atmosphere. Initiating water draining 

prior to reaching 2 psig would result in draining water that is 

hotter than it would be had the drum been sufficiently cooled 

(i.e., the pressure limit achieved) prior to draining the 
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vessel, effectively diverting HAP emissions to the water drain 

area rather than capturing these HAP in the enclosed blowdown 

system, where they can be either recovered or controlled. 

Therefore, we are proposing that the coke drum must reach 2 psig 

or less prior to any decoking operations, which includes 

atmospheric venting, draining, deheading, and coke cutting. 

We could not identify any other emission reduction options 

that could lower the emissions from the DCU decoking operations. 

Since we could not identify a technically feasible control 

option beyond the MACT floor, we determined that the MACT floor 

pressure limit of 2 psig is MACT for existing sources. We also 

determined that the same technical limitations of going beyond 

the 2 psig pressure limit for existing sources exist for new 

sources; therefore we determined that the MACT floor pressure 

limit of 2 psig is MACT for new sources. We request comment on 

whether depressurizing to 2 psig prior to venting to the 

atmosphere is the appropriate MACT floor and whether it is 

appropriate to include restrictions for the other three decoking 

operations draining, deheading and coke cutting, in the MACT 

requirements. We request comments on whether we have adequately 

interpreted the information that indicates that there is 

currently no applicable MACT floor for delayed coking. If 

Refinery MACT 1 currently provided standards for DCU based on 

the MACT floor, we would evaluate whether it is necessary to 
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revise such delayed coking standards under the risk and 

technology review requirements of the Act (i.e., CAA section 

112(f) and 112(d)(6)) as discussed later in this preamble. 

Finally, we request comment and supporting information on 

any other practices that may be used to limit emissions during 

the decoking operations. 

d. Evaluation of Cost and Environmental Impacts of MACT Emission 

Limitations for Delayed Coking Units 

DCU that cannot currently meet the 2 psig pressure limit 

would be expected to install a device (compressor or steam 

ejector system) to lower the DCU vessel pressure. In the 

Refinery NSPS Ja impact analysis, facilities not able to meet 

the pressure threshold were assumed to purchase and install a 

larger compressor to lower the blowdown system pressure. Other 

approaches to lowering blowdown system (and coke drum) pressure 

exist. Specifically, steam ejectors have been identified as a 

method to help existing units depressurize more fully in order 

to achieve a set vessel pressure or drum bed temperature. 

Upgrading the closed vent system to reduce pressure losses or to 

increase steam condensing capacity may also allow the DCU to 

depressurize more quickly while the emissions are still vented 

to the closed blowdown system. This is important because delays 

in the decoking operations may impact process feed rates. That 

is, if the decoking and drum preparation steps take too long, 
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the feed rate to the other coke unit must be reduced to prevent 

overfilling one coke drum prior to being able to switch to the 

other coke drum. This issue is less critical for DCU that 

operate with 3 or 4 drums per distillation column, but a 

consistent increase in the decoking times across all drums may 

still limit the capacity of the DCU at some petroleum 

refineries. 

For existing sources, we assumed all DCU that reported a 

“typical drum pressure prior to venting” of more than 2 psig 

would install and operate a steam ejector system to reduce the 

coke drum pressure to 2 psig prior to venting to atmosphere or 

draining. 

The operating costs of the steam ejector system are offset, 

to some extent, by the additional recovered vapors. Vapors from 

the additional gases routed to the blowdown system contain high 

levels of methane (approximately 70 percent by volume on a dry 

basis) based on DCU steam vent test data. If these vapors are 

directed to the closed blowdown system rather than to the 

atmosphere, generally the dry gas can be recovered in the 

refinery fuel gas system or light-ends gas plant. This recovered 

methane is expected to off-set natural gas purchases for the 

fuel gas system. 

For new sources, it is anticipated that the DCU’s closed 

vent system could be designed to achieve a 2 psig vessel 
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pressure with no significant increase in capital or operating 

costs. Designing the system to vent at a lower pressure would 

also result in additional vapor recovery, which is expected to 

off-set any additional capital costs associated with the low 

pressure design closed vent system. 

The costs of complying with the 2 psig coke drum threshold 

prior to venting or draining are summarized in Table 2 of this 

preamble. The costs are approximately $1,000 per ton of VOC 

reduced and approximately $5,000 per ton of organic HAP reduced 

when considering VOC and methane recovery credits. In addition 

to VOC and HAP reductions, the proposed control option will 

result in a reduction in methane emissions of 18,000 tpy or 

343,000 metric tonnes per year of carbon dioxide equivalents 

(CO2e), assuming a global warming potential of 21 for methane. 

Table 2. Nationwide Emissions Reduction and Cost Impacts of 

Control Option for Delayed Coking Units at Petroleum Refineries 

Control 

Option 

Capital 

Cost 

(million 

$) 

Annualized 

Costs 

Without 

Recovery 

Credits 

(million 

$/yr) 

Emissions 

Reduction, VOC 

(tpy) 

Emissions 

Reduction, HAP 

(tpy) 

Cost 

Effectiveness 

($/ton 

HAP) 

Total 

Annualized 

Costs 

with VOC 

Recovery 

Credit 

(million 

$/yr) 

Overall 

Cost 

Effectiveness with 

VOC 

Recovery 

Credit 

($/ton 

HAP) 

2 psig 52 10.2 4,250 850 12,000 3.98 4,700 

2. CRU Vents 

A CRU is designed to reform (i.e., change the chemical 

structure of) naphtha into higher-octane aromatics. Over time, 
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coke deposits form on the reforming catalyst, which reduces the 

catalyst activity. When catalyst activity is reduced to a 

certain point, the catalyst is regenerated by burning the coke 

off of the catalyst. Prior to this coke burn-off process, the 

catalyst (or reactor vessel containing the catalyst) must be 

removed from active service and organics remaining on the 

catalyst (or in the reactor) must be purged from the system. 

This is generally accomplished by depressurizing the vessel to a 

certain vessel pressure, then re-pressurizing the vessel with 

nitrogen and depressurizing the vessel again. The repressurization and depressurization process is repeated several 

times until all organics have been purged from the system. The 

organic HAP emissions from this depressurization/purge cycle 

vent are typically controlled by directing the purge gas 

directly to the CRU process heater or venting the gas to a 

flare. 

Refinery MACT 2 requires a 98-percent reduction of organic 

HAP measured as total organic carbon (TOC) or non-methane TOC or 

an outlet concentration of 20 ppmv or less (dry basis, as 

hexane, corrected to 3-percent oxygen), whichever is less 

stringent, for this CRU depressurization/purge cycle vent 

(purging prior to coke-burn-off). The emission limits for 

organic HAP for the CRU do not apply to emissions from process 

vents during depressuring and purging operations when the 
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reactor vent pressure is 5 psig or less. The Refinery MACT 2 

requirements were based on the typical operation of CRU 

utilizing sequential pressurization and passive 

depressurization. The 5 psig pressure limit exclusion was 

provided based on state permit conditions, which recognized that 

depressurization to an APCD (without other active motive of 

flow) is limited by the back pressure of the control system, 

which is often a flare or process heater. Source testing 

information collected from the 2011 Refinery ICR indicates that 

facilities have interpreted the rule to allow the 5 psig 

pressure limit exclusion to be used by units using active 

purging techniques (such as continuous nitrogen purge or vacuum 

pump on the CRU reactor at low pressures) to discharge to the 

atmosphere without emission controls. The information collected 

indicates that HAP emissions from a continuous, active purging 

technique could result in emissions of HAP from CRU 

depressurization vents much higher than expected to be allowed 

under the Refinery MACT 2 requirements, which presumed 

sequential re-pressurization and purging cycles. The testing 

information received indicated that at one facility, the active 

purge vent had non-methane TOC concentrations of 700 to 10,000 

ppmv (dry basis, as hexane, corrected to 3-percent oxygen) 

compared to less than 10 ppmv for the typical passive purge vent 

tested. The annual HAP emissions for the CRU with the active 
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purge vent were estimated to exceed 10 tpy, while a comparable 

unit using the cyclic re-pressurization and passive 

depressurization purge technique is projected to have HAP 

emissions of less than 0.1 tpy. 

Therefore, we are proposing to amend the exclusion in 40 

CFR 63.1566(a)(4) to clarify the application of the 5 psig 

exclusion, consistent with the MACT floor under CAA section 

112(d)(2) and (3). Specifically, we are limiting the vessel 

pressure limit exclusion to apply only to passive vessel 

depressurization. Units utilizing active purging techniques have 

a motive of flow that can be used to direct the purge gas to a 

control system, regardless of the CRU vessel pressure. If a CRU 

owner or operator uses active purging techniques (e.g., a 

continual nitrogen purge) or active vessel depressurization 

(e.g., vacuum pump), then the 98-percent reduction or 20 ppmv 

TOC emission limits would apply to these discharges regardless 

of the vessel pressure. 

3. Refinery Flares 

The EPA is proposing under CAA section 112(d)(2) and (3) to 

amend the operating and monitoring requirements for petroleum 

refinery flares. We have determined that the current 

requirements for flares are not adequate to ensure compliance 

with the Refinery MACT standards. In the development of Refinery 

MACT 1, the EPA determined that the average emission limitation 
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achieved by the best-performing 12 percent of existing sources 

was established as the use of combustion controls for 

miscellaneous process vents. Further, the EPA stated that “data 

analyses conducted in developing previous NSPS and the [National 

Emission Standards for Organic Hazardous Air Pollutants (40 CFR 

part 63, subparts F, G, and H)] HON determined that combustion 

controls can achieve 98-percent organic HAP reduction or an 

outlet organic HAP concentration of 20 ppmv for all vent 

streams” (59 FR 36139, July 15, 1994). The requirements 

applicable to flares at refineries are set forth in the General 

Provisions to 40 CFR part 63 and are cross-referenced in 

Refinery MACT 1 and 2. In general, flares used as APCD were 

expected to achieve 98-percent HAP destruction efficiencies when 

designed and operated according to the requirements in the 

General Provisions. Recent studies on flare performance, 

however, indicate that these General Provisions requirements are 

inadequate to ensure proper performance of refinery flares, 

particularly when assist steam or assist air is used. Over the 

last decade, flare minimization efforts at petroleum refineries 

have led to an increasing number of flares operating at well 

below their design capacity, and while this effort has resulted 

in reduced flaring of gases at refineries, situations of overassisting with steam or air have become exacerbated, leading to 

the degradation of flare combustion efficiency. Therefore, these 
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amendments are necessary to ensure that refineries that use 

flares as APCD meet the MACT standards at all times when 

controlling HAP emissions. 

Refinery MACT 1 and 2 require flares used as an APCD to 

meet the operational requirements set forth in the General 

Provisions at 40 CFR 63.11(b). These General Provisions 

requirements specify that flares shall be: (1) steam-assisted, 

air-assisted, or non-assisted; (2) operated at all times when 

emissions may be vented to them; (3) designed for and operated 

with no visible emissions (except for periods not to exceed a 

total of 5 minutes during any 2 consecutive hours); and (4) 

operated with the presence of a pilot flame at all times. The 

General Provisions also specify requirements for both the 

minimum heat content of gas combusted in the flare and maximum 

exit velocity at the flare tip. The General Provisions only 

specify monitoring requirements for the presence of the pilot 

flame and the operation of a flare with no visible emissions. 

For all other operating limits, Refinery MACT 1 and 2 require an 

initial performance evaluation to demonstrate compliance but 

there are no specific monitoring requirements to ensure 

continuous compliance. As noted previously, flare performance 

tests conducted over the past few years suggest that the current 

regulatory requirements are insufficient to ensure that refinery 
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flares are operating consistently with the 98-percent HAP 

destruction efficiencies that we determined were the MACT floor. 

In 2012, the EPA compiled information and test data 

collected on flares and summarized its preliminary findings on 

operating parameters that affect flare combustion efficiency 

(see technical report, Parameters for Properly Designed and 

Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). The 

EPA submitted the report, along with a charge statement and a 

set of charge questions to an external peer review panel.27 The 

panel concurred with the EPA’s assessment that three primary 

factors affect flare performance: (1) the flow of the vent gas 

to the flare; (2) the amount of assist media (e.g., steam or 

air) added to the flare; and (3) the combustibility of the vent 

gas/assist media mixture in the combustion zone (i.e., the net 

heating value, lower flammability, and/or combustibles 

concentration) at the flare tip. 

Following is a discussion of requirements we are proposing 

for refinery flares, along with impacts and costs associated 

with these new requirements. Specifically, this action proposes 

that refinery flares operate pilot flame systems continuously 

and with automatic re-ignition systems and that refinery flares 

operate with no visible emissions. In addition, this action also 

 

27 These documents can also be found at 

http://www.epa.gov/ttn/atw/petref.html. 
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consolidates requirements related to flare tip velocity and 

proposes new operational and monitoring requirements related to 

the combustion zone gas. Prior to these proposed amendments, 

Refinery MACT 1 and 2 cross-reference the General Provisions 

requirements at 40 CFR 63.11(b) for the operational requirements 

for flares used as APCD. Rather than revising the General 

Provisions requirements for flares, which would impact dozens of 

different source categories, this proposal will specify all 

refinery flare operational and monitoring requirements 

specifically in Refinery MACT 1 and cross-reference these same 

requirements in Refinery MACT 2. All of the requirements for 

flares operating at petroleum refineries in this proposed 

rulemaking are intended to ensure compliance with the Refinery 

MACT 1 and 2 standards when using a flare as an APCD. 

a. Pilot Flames 

Refinery MACT 1 and 2 reference the flare requirements in 

the General Provisions, which require a flare used as an APCD 

device to operate with a pilot flame present at all times. Pilot 

flames are proven to improve flare flame stability; even short 

durations of an extinguished pilot could cause a significant 

reduction in flare destruction efficiency. In this action, we 

are proposing to remove the cross-reference to the General 

Provisions and instead include the requirement that flares 

operate with a pilot flame at all times and be continuously 
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monitored for using a thermocouple or any other equivalent 

device in Refinery MACT 1 and 2. We are also proposing to amend 

Refinery MACT 1 and 2 to add a new operational requirement to 

use automatic relight systems for all flare pilot flames. An 

automatic relight system provides a quicker response time to 

relighting a snuffed-out flare compared to manual methods and 

thereby results in improved flare flame stability. In 

comparison, manual relighting is much more likely to result in a 

longer period where the pilot remains unlit. Because of safety 

issues with manual relighting, we anticipate that nearly all 

refinery flares are already equipped with an automated device to 

relight the pilot flame in the event it is extinguished. Also, 

due to the possibility that a delay in relighting the pilot 

could result in a flare not meeting the 98-percent destruction 

efficiency for the period when the pilot flame is out, we are 

proposing to amend Refinery MACT 1 and 2 to add this requirement 

to ensure that the pilot operates at all times. 

b. Visible Emissions 

Refinery MACT 1 and 2 reference the flare requirements in 

the General Provisions, which require a flare used as an APCD to 

operate with visible emissions for no more than 5 minutes in a 

2-hour period. Owners or operators of these flares are required 

to conduct an initial performance demonstration for visible 

emissions using EPA Method 22 of 40 CFR part 60, Appendix A-7. 
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We are proposing to remove the cross-reference to the General 

Provisions and include the limitation on visible emissions in 

Refinery MACT 1 and 2. In addition, we are proposing to amend 

Refinery MACT 1 and 2 to add a requirement that a visible 

emissions test be conducted each day and whenever visible 

emissions are observed from the flare. We are proposing that 

owners or operators of flares monitor visible emissions at a 

minimum of once per day using an observation period of 5 minutes 

and EPA Method 22 of 40 CFR part 60, Appendix A-7. Additionally, 

any time there are visual emissions from the flare, we are 

proposing that another 5-minute visible emissions observation 

period be performed using EPA Method 22 of 40 CFR part 60, 

Appendix A-7, even if the minimum required daily visible 

emission monitoring has already been performed. For example, if 

an employee observes visual emissions or receives notification 

of such by the community, the owner or operator of the flare 

would be required to perform a 5-minute EPA Method 22 

observation in order to check for compliance upon initial 

observation or notification of such event. We are also proposing 

that if visible emissions are observed for greater than one 

continuous minute during any of the required 5-minute 

observation periods, the monitoring period shall be extended to 

2 hours. 
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Industry representatives have suggested to the EPA that 

flare combustion efficiency is highest at the incipient smoke 

point (the point at which black smoke begins to form within the 

flame). They stated that the existing limit for visible 

emissions could be increased from 5 minutes to 10 minutes in a 

2-hour period to encourage operation near the incipient smoke 

point (see memorandum, Meeting Minutes for February 19, 2013, 

Meeting Between the U.S. EPA and Representatives from the 

Petroleum Refining Industry, in Docket ID Number EPA-HQ-OAR2010-0682). While we agree that operating near the incipient 

smoke point results in good combustion at the flare tip, we 

disagree that the allowable period for visible emissions be 

increased from 5 to 10 minutes for a 2-hour period. Smoking 

flares can contribute significantly to emissions of particulate 

matter 2.5 micrometers in diameter and smaller (PM2.5)emissions, 

and we are concerned that increasing the allowable period of 

visible emissions from 5 minutes to 10 minutes for every 2-hour 

period could result in an increase in the PM2.5 emissions from 

flares. 

As discussed later in this section, we are proposing 

additional operational and monitoring requirements for refinery 

flares which we expect will result in refineries installing 

equipment that can be used to fine-tune and control the amount 

of assist steam or air introduced at the flare tip such that 
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combustion efficiency of the flare will be maximized. These 

monitoring and control systems will assist refinery flare owners 

or operators operating near the incipient smoke point without 

exceeding the visible emissions limit. While combustion 

efficiency may be highest at the incipient smoke point, it is 

not significantly higher than the combustion efficiency achieved 

by these proposed operating limits, discussed in section 

IV.A.3.d of this preamble. As seen in the performance curves for 

flares (see technical memorandum, Petroleum Refinery Sector 

Rule: Operating Limits for Flares, in Docket ID Number EPA-HQOAR-2010-0682), there is very limited improvement in flare 

performance beyond the performance achieved at these proposed 

operating limits. We solicit comments and data on appropriate 

periods of visible emissions that would encourage operation at 

the incipient smoke point while not significantly increasing 

PM2.5 emissions. 

c. Flare Tip Velocity 

The General Provisions at 40 CFR 63.11(b) specify maximum 

flare tip velocities based on flare type (non-assisted, steamassisted, or air-assisted) and the net heating value of the 

flare vent gas. These maximum flare tip velocities are required 

to ensure that the flame does not “lift off” the flare, which 

could cause flame instability and/or potentially result in a 

portion of the flare gas being released without proper 
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combustion. We are proposing to remove the cross-reference to 

the General Provisions and consolidate the requirements for 

maximum flare tip velocity into Refinery MACT 1 and 2 as a 

single equation, irrespective of flare type (i.e., steamassisted, air-assisted or non-assisted). Based on our analysis 

of the various studies for air-assisted flares, we identified 

air-assisted test runs with high flare tip velocities that had 

high combustion efficiencies (see technical memorandum, 

Petroleum Refinery Sector Rule: Evaluation of Flare Tip Velocity 

Requirements, in Docket ID Number EPA-HQ-OAR-2010-0682). These 

test runs exceeded the maximum flare tip velocity limits for 

air-assisted flares using the linear equation in 40 CFR 

63.11(b)(8). When these test runs were compared with the test 

runs for non-assisted and steam-assisted flares, the airassisted flares appeared to have the same operating envelope as 

the non-assisted and steam-assisted flares. Therefore, we are 

proposing that air-assisted flares at refineries use the same 

equation that non-assisted and steam-assisted flares currently 

use to establish the flare tip velocity operating limit. 

In developing these proposed flare tip velocity 

requirements, we considered whether any adjustments to these 

velocity equations were necessary. The flare tip velocity 

equations require the input of the net heating value of the vent 

gas going to the flare, as opposed to the net heating value of 
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the gas mixture at the flare tip (i.e., the combustion zone 

gas). As discussed later in this section, we found that the 

performance of the flare was much more dependent on the net 

heating value of the gas mixture in the combustion zone than on 

the net heating value of only the vent gas going into the flare 

(excluding all assist media). We considered replacing the term 

in the velocity equation for the net heating value of the vent 

gas going into the flare with the net heating value of the gas 

mixture in the combustion zone. However, the steam addition 

rates were not reported for the tests conducted to evaluate 

flame stability as a function of flare tip velocity, so direct 

calculation of all the terms needed for calculating the net 

heating value in the combustion zone could not be made. At 

higher flare tip velocities, we expect that the steam assist 

rates would be small in comparison to the total vent gas flow 

rate, so there would not be a significant difference between the 

net heating value of the vent gas going into the flare and the 

combustion zone gas net heating value for the higher velocity 

flame stability tests. We request comment on the need and/or 

scientific reasons to use the flare vent gas net heating value 

versus the combustion zone net heating value when determining 

the maximum allowable flare tip velocity. 

In the 2012 flare peer review, we also discussed the effect 

of flame lift off and velocity on flare flame stability (see 
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technical report, Parameters for Properly Designed and Operated 

Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). In looking at 

ways of trying to prohibit flame instability, we examined the 

use of the Shore equation as a means to limit flare tip 

velocity. However, after receiving many comments on use of this 

equation from the peer reviewers, the uncertainty with how well 

the Shore equation models the large range of flare operation, 

and the limited dataset with which recent testing used high 

velocities (all recent test runs were performed at 10 feet per 

second or less), we determined that use of the existing velocity 

equation discussed above was still warranted. 

We are also proposing for Refinery MACT 1 and 2 to not 

include the special flare tip velocity equation in the General 

Provisions at 40 CFR 63.11(b)(6)(i)(A) for non-assisted flares 

with hydrogen content greater than 8 percent. This equation, 

which was developed based on limited data from a chemicals 

manufacturer, has very limited applicability for petroleum 

refinery flares in that it only provides an alternative for nonassisted flares with large quantities of hydrogen. Approximately 

90 percent of all refinery flares are either steam- or airassisted. Furthermore, we are proposing compliance alternatives 

in this section that we believe provide a better way for flares 

at petroleum refineries with high hydrogen content to comply 

with the rule while ensuring proper destruction performance of 
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the flare (see section IV.A.3.d of this preamble for additional 

details). Therefore, we are proposing to not include this 

special flare tip velocity equation as a compliance alternative 

for refinery flares. We request comment on the need to include 

this equation. If a commenter supports inclusion of this 

equation, we request that the commenter submit supporting 

documentation regarding the vent gas composition and flows and, 

if available, combustion efficiency determinations that indicate 

that this additional equation is needed and is appropriate for 

refinery flares. We also request documentation that the maximum 

allowable flare tip velocity predicted by this equation 

adequately ensures proper combustion efficiency. 

The General Provisions require an initial demonstration 

that a flare used as an APCD meets the applicable flare tip 

velocity requirement in 40 CFR 63.11(b). However, most refinery 

flares can have highly variable vent gas flows and a single 

initial demonstration is insufficient to demonstrate continuous 

compliance with the flare tip velocity requirement. 

Consequently, we are proposing to amend Refinery MACT 1 and 2 to 

require continuous monitoring to determine flare tip velocity, 

calculated by monitoring the flare vent gas volumetric flow rate 

and dividing by the cross-sectional area of the flare tip. As an 

alternative to installing continuous volumetric flow rate 

monitors, we are proposing that the owner or operator may elect 
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to install a pressure- and temperature-monitoring system and use 

engineering calculations to determine the flare tip velocity. 

d. Refinery Flare Operating and Monitoring Requirements 

The current requirements for flares in the General 

Provisions specify that the flare vent gas must meet a minimum 

net heating value of 200 British thermal units per standard 

cubic foot (Btu/scf) for non-assisted flares and 300 Btu/scf for 

air- and steam-assisted flares. Refinery MACT 1 and 2 reference 

these requirements, but neither the General Provisions nor 

Refinery MACT 1 and 2 include specific monitoring requirements 

to monitor the net heating value of the vent gas. Moreover, 

recent flare testing results indicate that this parameter alone 

does not adequately address instances when the flare may be 

over-assisted since it only considers the gas being combusted in 

the flare and nothing else (e.g., no assist media). However, 

many industrial flares use steam or air as an assist medium to 

protect the design of the flare tip, promote turbulence for the 

mixing, induce air into the flame and operate with no visible 

emissions. Using excessive steam or air results in dilution and 

cooling of flared gases and can lead to operating a flare 

outside its stable flame envelope, reducing the destruction 

efficiency of the flare. In extreme cases, over-steaming or 

excess aeration can actually snuff out a flame and allow 

regulated material to be released into the atmosphere completely 
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uncombusted. Since approximately 90 percent of all flares at 

refineries are either steam- or air-assisted, it is critical 

that we ensure the assist media be accounted for in some form or 

fashion. Recent flare test data have shown that the best way to 

account for situations of over-assisting is to consider the 

properties of the mixture of all gases at the flare tip in the 

combustion zone when evaluating the ability to combust 

efficiently. As discussed in the introduction to this section, 

the external peer review panel concurred with our assessment 

that the combustion zone properties at the flare tip are 

critical parameters to know in determining whether a flare will 

achieve good combustion. The General Provisions, however, solely 

rely on the net heating value of the flare vent gas. 

We are proposing to add definitions of two key terms 

relevant to refinery flare performance. First, we are proposing 

to define “flare vent gas” to include all waste gas, sweep gas, 

purge gas and supplemental gas, but not include pilot gas or 

assist media. We are proposing this definition because 

information about “flare vent gas” (e.g., flow rate and 

composition) is one of the necessary inputs needed to evaluate 

the make-up of the combustion zone gas. To that end, we are also 

proposing to define the “combustion zone gas” as flare vent gas 

plus the total steam-assist media and premix assist air that is 

supplied to the flare. 
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Based on our review of the recent flare test data, we have 

determined that the following combustion zone operational limits 

can be used to determine good combustion: net heating value 

(Btu/scf), lower flammability limit (LFL) or a total 

combustibles fraction (e.g., a simple carbon count). In this 

action, we are proposing these new operational limits, along 

with methods for determining these limits in the combustion zone 

at the flare tip for steam-assisted, air-assisted and nonassisted flares to ensure that there is enough combustible 

material readily available to achieve good combustion. 

For air-assisted flares, use of too much perimeter assist 

air can lead to poor flare performance. Based on our analysis, 

we found that including the flow rate of perimeter assist air in 

the calculation of combustion zone operational limits in itself 

does not identify all instances of excess aeration. The data 

suggest that the diameter of the flare tip, in concert with the 

amount of perimeter assist air, provides the inputs necessary to 

calculate whether or not this type of flare is over-assisted. 

Therefore, we are proposing that in addition to complying with 

combustion zone operational limits to ensure that there is 

enough combustible material available to adequately combust the 

gas and pass through the flammability region, air-assisted 

flares would also comply with an additional dilution parameter 

that factors in the flow rate of the flare vent gas, flow rates 
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of all assist media (including perimeter assist air), and 

diameter of flare tip to ensure that degradation of flare 

performance from excess aeration does not occur. This dilution 

parameter is consistent with the combustion theory that the more 

“time” the gas spends in the flammability region above the flare 

tip, the better it will combust. Also, since both the volume of 

the combustion zone (represented by the diameter here) and how 

quickly this gas is diluted to a point below the flammability 

region (represented by perimeter assist air flow rate) 

characterize this “time,” it makes sense that we propose such a 

term (see technical memorandum, Petroleum Refinery Sector Rule: 

Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR2010-0682). 

It should be noted that in the 2012 flare peer review 

report, we considered a limit for perimeter assist air via the 

stoichiometric air ratio. This stoichiometric air ratio is the 

ratio of the actual mass flow rate of assist air to the 

theoretical stoichiometric mass flow rate of air (based on 

complete chemical combustion of fuel to carbon dioxide (CO2) and 

water) needed to combust the flare vent gas. However, we are not 

proposing to include this term as part of the calculation 

methodology, as we have determined that the dilution parameter 

discussed in this section better assures that air-assisted flare 

performance is not degraded due to excess aeration. 
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The proposed rule allows the owner or operator flexibility 

to select the form of the combustion zone operational limit 

(i.e., net heating value, LFL, or total combustibles fraction) 

with which to comply in order to provide facilities the option 

of using monitors they may already have in place. The monitoring 

methods we are proposing take into account the combustible 

properties of all gas going to the flare (i.e., flare vent gas, 

assist gas, and premix air) that affects combustion efficiency, 

and they can be used to determine whether a flare has enough 

combustible material to achieve the desired level of control 

(and whether it is being over-assisted). These methods require 

the owner or operator to input the flow of the vent gas to the 

flare, the characteristics of the vent gas going to the flare 

(i.e., either a heat content (Btu/scf), LFL, or total 

combustible fuel content, depending on how the operational limit 

is expressed), and the flow of assist media added to the flare. 

To estimate the LFL, we are proposing to use a calculation 

method based on the Le Chatelier equation. The Le Chatelier 

calculation uses the reciprocal of the volume-weighted average 

over the LFL of the individual compounds in the gas mixture to 

estimate the LFL of the gas mixture. Although Le Chatelier’s 

equation was originally limited to binary mixtures of 

combustible gases, we are proposing a method that was developed 

by Karim, et al. (1985) and assumes a LFL of infinity for inert 
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gases. We are also aware of other methods and/or adjustments 

that can be made to the Le Chatelier equation in order to 

calculate a more accurate estimate of the LFL of a gas mixture 

(see technical memorandum, Parameters for Properly Designed and 

Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). We 

are soliciting comment on the use of this proposed method. 

Recent data indicate that one set of operational limits may 

not be sufficient for all refinery flares. Flares that receive 

vent gas containing significant levels of both hydrogen and 

olefins often exhibit lower combustion efficiencies than flares 

that receive vent gas with only one (or none) of these 

compounds. Therefore, we are proposing more stringent 

operational limits for flares that simultaneously receive vent 

gas containing significant levels of both hydrogen and olefins 

(see technical memorandum, Petroleum Refinery Sector Rule: 

Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR2010-0682). Although the minimum net heating value in the 

combustion zone (i.e., Btu/scf) is a good indicator of 

combustion efficiency, as noted in the flare peer review report, 

the LFL and combustibles concentration (or total combustibles) 

in the combustion zone are also good indicators of flare 

combustion efficiency. For some gas mixtures, such as gases with 

high hydrogen content, the LFL or combustibles concentration in 

the combustion zone may be better indicators of performance than 
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net heating value. Consequently, we are proposing operational 

limits expressed all three ways, along with associated 

monitoring requirements discussed later in this section. 

The three operating limits were established in such a way 

that each limit is protective on its own. As such, the owner or 

operator may elect to comply with any of the three alternative 

operating limits at any time, provided they use a monitoring 

system capable of determining compliance with each of the 

proposed alternative operating limits on which they rely (see 

technical memorandum, Petroleum Refinery Sector Rule: Operating 

Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). 

For example, the owner or operator may elect to install 

monitoring for only one of the three alternative operating 

limits, in which case the owner or operator must comply with 

that selected operating limit at all times. If the owner or 

operator installs a system capable of monitoring for all three 

of the alternative operating limits, the owner or operator can 

choose which of the three operating limits the source will rely 

on to demonstrate compliance. 

A summary of the operating limits specified in this 

proposed rule is provided in Table 3 of this preamble. We are 

proposing that owners or operators of flares used as APCD would 

conduct an initial performance test to determine the values of 

the parameters to be monitored (e.g., the flow rate and heat 
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content of the incoming flare vent gas, the assist media flow 

rate, and pre-mix air flow rate, if applicable) in order to 

demonstrate continuous compliance with the operational limits in 

Table 3. We are proposing to require owners or operators to 

record and calculate 15-minute block average values for these 

parameters. Our rationale for selecting a 15-minute block 

averaging period is provided in section IV.A.3.e of this 

preamble. 

Table 3. Operating Limits for Flares in this Proposed Action 

Operating 

Parametera

Operating Limits: Flares 

without Hydrogen-Olefin 

Interactionb

Operating Limits: Flares 

with Hydrogen-Olefin 

Interactionb

Combustion zone parameters for all flares 

NHVcz ≥270 Btu/scf ≥380 Btu/scf 

LFLcz ≤0.15 volume fraction ≤0.11 volume fraction 

Ccz ≥0.18 volume fraction ≥0.23 volume fraction 

Dilution parameters for flares using perimeter assist air 

NHVdil ≥22 Btu/ft2 ≥32 Btu/ft2

LFLdil ≤2.2 volume fraction/ft ≤1.6 volume fraction/ft 

Cdil ≥0.012 volume fraction-ft ≥0.015 volume fraction-ft a

 The operating parameters are: 

NHVcz = combustion zone net heating value 

LFLcz = combustion zone lower flammability limit 

Ccz = combustion zone combustibles concentration 

NHVdil = net heating value dilution parameter 

LFLdil = lower flammability limit dilution parameter 

Cdil = combustibles concentration dilution parameter b

 Hydrogen-Olefin interactions are assumed to be present when the 

concentration of hydrogen and olefins in the combustion zone exceed all three 

of the following criteria: 

(1) The concentration of hydrogen in the combustion zone is greater than 1.2 

percent by volume. 

(2) The cumulative concentration of olefins in the combustion zone is 

greater than 2.5 percent by volume. 

(3) The cumulative concentration of olefins in the combustion zone plus the 

concentration of hydrogen in the combustion zone is greater than 7.4 percent 

by volume. 

Btu/ft2

 = British thermal units per square foot. 
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We are soliciting comment on the appropriateness of the 

operating limits and dilution parameters in Table 3 of this 

preamble and whether they ensure that refinery flares operate in 

a manner that that will ensure compliance with the MACT 

requirements for vents to achieve a 98-percent organic HAP 

reduction. 

Combustion zone gas monitoring alternatives. As discussed 

previously in this section, we are proposing to define the 

combustion zone gas as the mixture of gas at the flare tip 

consisting of the flare vent gas, the total steam-assist media 

and premix assist air. In order to demonstrate compliance with 

the three combustion zone parameter operating limits of net 

heating value, LFL and total combustibles fraction, the owner or 

operator would need to monitor four things: (1) flow rate of the 

flare vent gas; (2) flow rate of total steam assist media; (3) 

flow rate of premix assist air and (4) specific characteristics 

associated with the flare vent gas (e.g., heat content, 

composition). In order to monitor the flow rates of the flare 

vent gas, total steam assist media, and premix assist air, we 

are proposing that refinery owners or operators use a continuous 

volumetric flow rate monitoring system or a pressure- and 

temperature-monitoring system with use of engineering 

calculations. We are also proposing use of either of these 

monitoring methods for purposes of determining the flow rate of 
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perimeter assist air (for compliance with the dilution 

parameter). However, the one component that will determine how 

many combustion zone parameter operating limits an owner or 

operator can comply with is the specific type of monitor used to 

characterize the flare vent gas. 

Monitoring the individual component concentrations of the 

flare vent gas using an on-line gas chromatograph (GC) along 

with monitoring vent gas and assist gas flow rates will allow 

the owner or operator to determine compliance with any of the 

three proposed combustion zone operating limits and any of the 

three proposed dilution operating limits (if using air-assisted 

flares). We considered requiring all refinery owners or 

operators of flares to only use a GC to monitor the flare vent 

gas composition but since facilities may have other non-GC 

monitors already in place (e.g., calorimeters), we are not 

proposing such a requirement at this time. However, use of a GC 

can improve refinery flare operation and management of 

resources. For example, use of a GC to characterize the flare 

vent gas can lead to product/cost savings for refiners because 

they could more readily identify and correct instances of 

product being unintentionally sent to a flare, either through a 

leaking pressure relief valve or other conveyance that is 

ultimately routed to the flare header system. In addition, an 

owner or operator that chooses to use a GC (in lieu of one of 
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the other proposed monitoring alternatives) will be more likely 

to benefit from the ability to continuously fine-tune their 

operations (by reducing assist gas addition and/or supplemental 

gas to the flare) in order to meet any one of the three 

operating limits. Furthermore, some facilities are already 

required to use a GC to demonstrate compliance with state flare 

requirements. We are soliciting comment on the additional 

benefits that using a GC offers and whether it would be 

reasonable to require a GC on all refinery flares. 

As an alternative to a continuous compositional monitoring 

system, we are proposing to allow the use of grab samples along 

with engineering calculations to determine the individual 

component concentration. Like the on-line GC, the grab sampling 

option relies on compound speciation and is therefore flexible 

to use with any form of the operational limits we are proposing. 

The disadvantage of this option is that if a grab sample 

indicates non-compliance with the operational limits, the 

permitting authority could presume non-compliance from the time 

of the previous grab sample indicating compliance, which would 

include all 15-minute periods in that time period. However, 

there are a number of situations where the refinery owner or 

operator may find this option advantageous. For example, some 

flares receive flows only from a specific process with a 

consistent composition and high heat content. In this case, the 
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owner or operator may elect to actively adjust the assist gas 

flow rates using the expected vent gas composition and rely on 

the analysis of the grab sample to confirm the expected vent gas 

composition. This alternative may also be preferred for flares 

that are used infrequently (non-routine flow flares) or that 

have flare gas recovery systems designed and operated to recover 

100 percent of the flare gas under typical conditions. For these 

flares, flaring events may be so seldom that the refinery owner 

or operator may prefer the uncertainty in proactive control to 

the higher cost of continuous monitors that would seldom be 

used. 

As an alternative to performing a compositional analysis 

with use of a GC (through either on-line monitoring or analysis 

of the grab sample), we are proposing that owners or operators 

of flares may elect to install a device that directly monitors 

vent gas net heating value (i.e., a calorimeter). If the owner 

or operator elects this monitoring method, we are proposing that 

they must comply with the operating limits that are based on the 

net heating value operating limit. Similarly, we are also 

proposing that owners or operators of flares may elect to 

install a device that directly monitors the total hydrocarbon 

content of the flare vent gas (as a measure of the combustibles 

concentration). If the owner or operator elects this monitoring 
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method, they must comply with the operating limits that are 

based on the combustibles concentration. 

e. Data Averaging Periods for Flare Gas Operating Limits 

We are proposing to use a 15-minute block averaging period 

for each proposed flare operating parameter (including flare tip 

velocity) to ensure that the flare is operated within the 

appropriate operating conditions. As flare vent gas flow rates 

and composition can change significantly over short periods of 

time, a short averaging time was considered to be the most 

appropriate for assessing proper flare performance. Furthermore, 

since flare destruction efficiencies can fall precipitously fast 

below the proposed operating limits, short time periods where 

the operating limits are not met could seriously impact the 

overall performance of the flare. With longer averaging times, 

there may be too much opportunity to mask these short periods of 

poor performance (i.e., to achieve the longer-term average 

operating limit while not achieving a high destruction 

efficiency over that time period because of short periods of 

poor performance). 

Moreover, a 15-minute averaging period is in line with the 

test data and the analysis used to establish the operating 

limits in this proposed rule. Ninety-three percent of the flare 

test runs used as a basis for establishing the proposed 

operating limits ranged in duration from 5 to 30 minutes, and 77 
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percent of the runs ranged in duration from 5 to 20 minutes. The 

failure analysis (discussed in section IV.A.3.f of this 

preamble) considered minute-by-minute test run data, but as 

there are limitations on how quickly compositional analyses can 

be conducted, many of the compositional data still reflect set 

values over 10- to 15-minute time intervals. Because the GC 

compositional analyses generally require 10 to 15 minutes to 

conduct, shorter averaging times are not practical. To be 

consistent with the available test data and to ensure there are 

no short periods of significantly poor performance, we are 

proposing 15-minute block averaging times. 

Given the short averaging times for the operating limits, 

we are proposing special calculation methodologies to enable 

refinery owners or operators to use “feed forward” calculations 

to ensure compliance with the operating limits on a 15-minute 

block average. Specifically, the results of the compositional 

analysis determined just prior to a 15-minute block period are 

to be used for the next 15-minute block average. Owners or 

operators of flares will then know the vent gas properties for 

the upcoming 15-minute block period and can adjust assist gas 

flow rates relative to vent gas flow rates to comply with the 

proposed operating limits. 

Owners or operators of flares that elect to use grab 

sampling and engineering calculations to determine compliance 
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must still assess compliance on a 15-minute block average. The 

composition of each grab sample is to be used for the duration 

of the episode or until the next grab sample is taken. We are 

soliciting comment on whether this approach is appropriate, and 

whether grab samples are needed on a more frequent basis to 

ensure compliance with the operating limits. 

f. Other Peer Review Considerations 

In an effort to better inform the proposed new requirements 

for refinery flares, in the spring of 2012 the EPA summarized 

its preliminary findings on operating parameters that affect 

flare combustion efficiency in a technical report and put this 

report out for a letter review. Based on the feedback received, 

the EPA considered many of the concerns peer reviewers expressed 

in their comments in the development of this proposal for 

refinery flares (see memorandum, Peer Review of “Parameters for 

Properly Designed and Operated Flares”, in Docket ID Number EPAHQ-OAR-2010-0682). While the more substantive issues have been 

previously discussed in sections IV.A.3.a through e of this 

preamble, the following discussion addresses other peer review 

considerations that the EPA either discussed in the peer review 

technical document or considered from comments received by the 

peer review panel that played a role in the development of this 

proposal. 
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Test data quality and analysis. For steam-assisted flares, 

we asked peer reviewers to comment on our criteria for excluding 

available flare test data from our analyses. In general, peer 

reviewers considered the EPA’s reasons for removing certain test 

data (prior to performing any final analysis) to be appropriate; 

however, one reviewer suggested the EPA complete an analysis of 

quality on the data before applying any criteria, and several 

reviewers commented on the level of scrutiny of the 10 data 

points specifically discussed in the technical report for not 

meeting the combustion zone LFL trend. These reviewers stated it 

appeared the EPA had scrutinized test data more if it were 

inconsistent with the LFL threshold conclusions made in the 

report. Although we felt it was appropriate to discuss specific 

test data not fitting the trend, we do agree with the reviewers 

that a more general and standard set of criteria should be 

applied to all test data prior to making any conclusion. In 

addition, other peer reviewers saw no reason why the EPA should 

exclude 0-percent combustion efficiency data points, or data 

points where smoking occurs, or single test runs when there was 

also a comparable average test run. Therefore, in response to 

these peer review comments, the EPA performed a validation and 

usability analysis on all available test data. This resulted in 

a change to the population of test data used in our final 

analysis (see technical memorandum, Flare Performance Data: 
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Summary of Peer Review Comments and Additional Data Analysis for 

Steam-Assisted Flares, in Docket ID Number EPA-HQ-OAR-2010-0682 

for a more detailed discussion of the data quality and 

analysis). 

To help determine appropriate operating limits, several 

peer reviewers suggested the EPA perform a false-positive-tofalse-negative comparison (or failure type) analysis between the 

potential parameters discussed in the technical report as 

indicators of flare performance. The reviewers suggested that 

the EPA attempt to minimize the standard error of all false 

positives (i.e., poor observed combustion efficiency when the 

correlation would predict good combustion) and false negatives 

(i.e., good observed combustion efficiency when the correlation 

would predict poor combustion). In response to these comments, 

the EPA has conducted a failure analyses of these parameters 

which helped form the basis for the operating limits we are 

proposing for flares (see technical memorandum, Petroleum 

Refinery Sector Rule: Operating Limits for Flares, in Docket ID 

Number EPA-HQ-OAR-2010-0682). 

Some peer reviewers contended that it is appropriate for 

the EPA to round each established operating limit to the nearest 

whole number, because using a decimal implies far more accuracy 

and reliability than can be determined from the test data. Based 

on these comments, we have given more consideration to the 
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number of significant figures used in the operating limits, and 

we are proposing to use two significant figures for the flare 

operating limits in these proposed amendments. 

Multiple peer reviewers performed additional analyses to 

try and determine the appropriateness of the limits raised in 

the technical report. Some peer reviewers tried to fit the data 

to a curve, others performed various failure analyses, while 

others looked at different metrics not discussed in the 

technical report (see memorandum, Peer Review of “Parameters for 

Properly Designed and Operated Flares”, in Docket ID Number EPAHQ-OAR-2010-0682). Based on the conclusions drawn from these 

various analyses, a range of combustion zone net heating value 

targets from 200 Btu/scf to 450 Btu/scf were identified as 

metrics that would provide a high level of certainty regarding 

good combustion in flares (Note: 450 Btu/scf was the assumed to 

be approximately equivalent to a combustion zone LFL of 10 

percent). We solicit comment on this range and the 

appropriateness for which the operating limits selected in this 

proposal will ensure compliance with the MACT requirements for 

vents at petroleum refineries. 

Effect of supplemental gas use. Most flares normally 

operate at a high turndown ratio, which means the actual flare 

gas flow rate is much lower than what the flare is designed to 

handle. In addition, steam-assisted flares have a manufacturers’ 
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minimum steam requirement in order to protect the flare tip. A 

combination of high turndown ratio and minimum steam requirement 

will likely require some owners or operators to add supplemental 

gas to achieve one of the combustion zone gas operating limits 

we are proposing here (e.g., combustion zone combustibles 

concentration (Ccz) ≥ 18 volume percent; combustion zone lower 

flammability limit (LFLcz) ≤ 15 volume percent; or combustion 

zone net heating value (NHVcz) ≥ 270 Btu/scf). However, finetuning the actual steam flow to the flare should significantly 

reduce the need for supplemental gas. We considered proposing a 

steam-to-vent gas ratio limitation on steam-assisted flares. 

however, a steam-to-vent gas ratio alone cannot fully address 

over-steaming because it would not account for the variability 

of chemical properties within the flare gas. We request that 

commenters on this issue provide supporting documentation on 

their potential to reduce steam as well as their use of 

supplemental gas to achieve the proposed operating limit(s), and 

how it could affect cost and potential emissions. We emphasize 

that the amount and cost of supplemental gas should be 

reflective of conditions after any excess steam use has been 

rectified. It would not be valuable to consider situations where 

large amounts of supplemental gas are added, while steam is 

simultaneously added far in excess of the amount recommended by 

the flare manufacturer or other guidance documents. 
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In assessing the combustion zone gas and looking at all the 

gas at the flare tip, another potential source of added heat 

content comes from the gas being used as fuel to maintain a 

continuously lit pilot flame. However, since pilot gas is being 

used as fuel for a continuous ignition source and is burned to 

create a flame prior to (or at the periphery of) the combustion 

zone, this gas does not directly contribute to the heat content 

or flammability of the gas being sent to the flare to be 

controlled under Refinery MACT 1 or 2. In addition, in looking 

at available test data, the pilot gas flow rate is generally so 

small that it does not significantly impact the combustion zone 

properties at all. Furthermore, by leaving pilot gas out of the 

combustion zone operating limit calculations, the equations 

become simplified and a requirement to continuously monitor 

pilot gas flow rate can be avoided. Therefore, we are proposing 

that the owner or operator not factor in the pilot gas 

combustible component (or net heating value) contribution when 

determining any of the three proposed combustion zone gas 

operating limits (Ccz, LFLcz, or NHVcz). 

Effects of wind on flame performance. Several published 

studies have investigated the significance of wind on the fluid 

mechanics of a flare flame (see technical memorandum, Parameters 

for Properly Designed and Operated Flares, in Docket ID Number 

EPA-HQ-OAR-2010-0682). These studies were conducted in wind 
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tunnels at crosswind velocities up to about 60 miles per hour 

(mph) and have illustrated that increased crosswind velocity can 

have a strong effect on flare flame dimensions and shape, 

causing the flame to become segmented or discontinuous, and 

wake-dominated (i.e., where the flame is bent over on the 

downwind side of a flare pipe and is imbedded in the wake of the 

flare tip), which may lead to poor flare performance due to fuel 

stripping. However, the majority of this research is confined to 

laboratory studies on flares with effective diameters less than 

3 inches, which have been shown not to be representative of 

industrial-sized flares. Research that does include performance 

tests conducted on flares scalable to refinery flares (i.e., 3-

inch, 4-inch, and 6-inch pipe flares) was conducted with flare 

tip velocities as low as 0.49 feet per second and crosswind 

velocities of about 26 mph and less; all tests resulted in good 

flare performance. Furthermore, there is no indication that 

crosswind velocities negatively impact flare performance in the 

recent flare performance tests. These tests were conducted on 

various sizes of industrial flares (i.e., effective diameters 

ranging between 12 and 54 inches) in winds of about 22 mph and 

less, and at relatively low flare tip velocities (i.e., 10 feet 

per second or less). (See Parameters for Properly Designed and 

Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682.) 
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We are aware of flare operating parameters that consider 

crosswind velocity; however, using the available flare 

performance test data, we were unable to determine a clear 

correlation that would be appropriate for all refinery flares. 

For example, the momentum flux ratio (MFR) is a measure of 

momentum strength of the flare exit gas relative to the 

crosswind (i.e., the product of flare exit gas density and 

velocity squared divided by the product of air density and 

crosswind velocity squared). The plume buoyancy factor is the 

ratio of crosswind velocity to the flare exit gas velocity, and 

considers the area of the flare pipe. The power factor is the 

ratio of the power of the crosswind to the power of combustion 

of the flare gas. Because the available flare performance test 

data have relatively low flare tip velocities, and crosswind 

velocities were relatively constant during each test run, we are 

unable to examine these parameters to the fullest extent. 

In light of the data available from performance tests 

(Gogolek et al., 2010), we asked peer reviewers whether the MFR 

could be used in crosswind velocities greater than 22 mph at the 

flare tip to indicate wake-dominated flame situations. We also 

asked for comment on observations that in the absence of 

crosswind greater than 22 mph, a low MFR does not necessarily 

indicate poor flare performance. Peer reviewers suggested that 

there are no data available from real industrial flares in winds 
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greater than 22 mph to support that MFR could be used to 

identify wake-dominated flame situations. In addition, we 

received no further peer review comments that have caused us to 

reconsider the observation we made in the April 2012 technical 

report that in the absence of crosswind greater than 22 mph, a 

low MFR does not necessarily indicate poor flare performance. We 

request comment with supporting data and rationale on any of 

these, or other parameters, as a measure of wind effects on 

flare combustion efficiency. 

We considered including observation requirements for 

detecting segmented or discontinuous wake-dominated flames, 

especially for winds greater than 22 mph (where limited test 

data is available). However, owners or operators of flares 

cannot control the wind speed, and it would be detrimental to 

increase the quantity of flared gases in high crosswind 

conditions in efforts to improve the MFR and reduce wakedominated flow conditions. Furthermore, there is no indication 

that crosswind velocities negatively impact flare performance in 

the recent flare performance tests. For these reasons, we are 

not proposing any flare operating parameter(s) to minimize wind 

effects on flare combustion efficiency. 

g. Impacts of the Flare Operating and Monitoring Requirements 

The EPA expects that the newly proposed requirements for 

refinery flares discussed in this section will affect all flares 
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at petroleum refineries. Based on data received as a result of 

the Refinery ICR, we estimate that there are 510 flares 

operating at petroleum refineries and that 285 of these receive 

flare vent gas flow on a regular basis (i.e., other than during 

periods of startup, shutdown, and malfunction). Costs were 

estimated for each flare for a given refinery, considering 

operational type (e.g., receive flare vent gas flow on a regular 

basis, use flare gas recovery systems to recover 100 percent of 

routine flare flow, handle events during startup, shutdown, or 

malfunction only, etc.) and current monitoring systems already 

installed on each individual flare. Costs for any additional 

monitoring systems needed were estimated based on installed 

costs received from petroleum refineries and, if installed costs 

were unavailable, costs were estimated based on vendor-purchased 

equipment. The baseline emission estimate and the emission 

reductions achieved by the proposed rule were estimated based on 

current vent gas and steam flow data submitted by industry 

representatives. The results of the impact estimates are 

summarized in Table 4 of this preamble. We note that the 

requirements for refinery flares we are proposing in this action 

will ensure compliance with the Refinery MACT standards when 

flares are used as an APCD. As such, these proposed operational 

and monitoring requirements for flares at refineries have the 

potential to reduce excess emissions from flares by 
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approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 

metric tonnes per year of CO2e. The VOC compounds are nonmethane, non-ethane total hydrocarbons. According to the 

Component 2 database from the Refinery ICR, there are 

approximately 50 individual HAP compounds included in the 

emission inventory for flares, but many of these are emitted in 

trace quantities. A little more than half of the HAP emissions 

from flares are attributable to hexane, followed next by 

benzene, toluene, xylenes, and 1,3-butadiene. For more detail on 

the impact estimates, see the technical memorandum Petroleum 

Refinery Sector Rule: Flare Impact Estimates in Docket ID Number 

EPA-HQ-OAR-2010-0682. 

Table 4. Nationwide Cost Impacts of Proposed Amendments to 

Ensure Proper Flare Performance 

Affected source 

Total capital investment 

(million $) 

Total annualized costs 

(million $/ yr) 

Flare Monitoring 147 36.3 

4. Vent Control Bypasses 

a. Relief Valve Discharges 

Refinery MACT 1 recognized relief valve discharges to be 

the result of malfunctions. Relief valves are designed to remain 

closed during normal operation and only release as the result of 

unplanned and/or unpredictable events. A release from a relief 

valve usually occurs during an over pressurization of the 

system. However, emissions vented directly to the atmosphere by 
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relief valves in organic HAP service contain HAP that are 

otherwise regulated under Refinery MACT 1. 

Refinery MACT 1 regulated relief valves through equipment 

leak provisions that applied only after the pressure relief 

occurred. In addition the rule followed the EPA’s then-practice 

of exempting startup, shutdown and malfunction (SSM) events from 

otherwise applicable emission standards. Consequently, with 

relief valve releases defined as unplanned and nonroutine and 

the result of malfunctions, Refinery MACT 1 did not restrict 

relief valve releases to the atmosphere but instead treated them 

the same as all malfunctions through the SSM exemption 

provision. 

In Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the 

Court determined that the SSM exemption violates the CAA. See 

section IV.E of this preamble for additional discussion. To 

ensure this standard is consistent with that decision, these 

proposed amendments remove the malfunction exemption in Refinery 

MACT 1 and 2 and provide that emissions of HAP may not be 

discharged to the atmosphere from relief valves in organic HAP 

service. To ensure compliance with this amendment, we are also 

proposing to require that sources monitor relief valves 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. Pressure release events 
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from relief valves to the atmosphere have the potential to emit 

large quantities of HAP. Where a pressure release occurs, it is 

important to identify and mitigate it as quickly as possible. 

For purposes of estimating the costs of this requirement, we 

assumed that operators would install electronic monitors on each 

relief valve that vents to the atmosphere to identify and record 

the time and duration of each pressure release. However, we are 

proposing to allow owners and operators to use a range of 

methods to satisfy these requirements, including the use of a 

parameter monitoring system (that may already be in place) on 

the process operating pressure that is sufficient to indicate 

that a pressure release has occurred as well as record the time 

and duration of that pressure release. Based on our cost 

assumptions, the nationwide capital cost of installing these 

electronic monitors is $9.54 million and the annualized capital 

cost is $1.36 million per year. 

As defined in the Refinery MACT standards, relief valves 

are valves used only to release unplanned, nonroutine 

discharges. A relief valve discharge results from an operator 

error, a malfunction such as a power failure or equipment 

failure, or other unexpected cause that requires immediate 

venting of gas from process equipment in order to avoid safety 

hazards or equipment damage. Even so, to the extent that there 

are atmospheric HAP emissions from relief valves, we are 
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required to follow the Sierra Club ruling to address those 

emissions in our rule, and we can no longer exempt them as 

permitted malfunction emissions as we did under Refinery MACT 1. 

Our information indicates that there are approximately 12,000 

pressure relief valves that vent to the atmosphere (based on the 

ICR responses) and that the majority of relief valves in the 

refining industry are not atmospheric, but instead are routed to 

flares (see letter from API, Docket Item Number EPA-HQ-OAR-2010-

0682-0012). We request comment on our approach and on 

alternatives to our approach to regulating releases from 

pressure relief valves and also request commenters to provide 

information supporting any such comments. 

b. Bypass Lines 

For a closed vent system containing bypass lines that can 

divert the stream away from the APCD to the atmosphere, Refinery 

MACT 1 requires the owner or operator to either: (1) install, 

maintain and operate a continuous parametric monitoring system 

(CPMS) for flow on the bypass line that is capable of detecting 

whether a vent stream flow is present at least once every hour, 

or (2) secure the bypass line valve in the non-diverting 

position with a car-seal or a lock-and-key type configuration. 

Under option 2, the owner or operator is also required to 

inspect the seal or closure mechanism at least once per month to 

verify the valve is maintained in the non-diverting position 
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(see 40 CFR 63.644(c) for more details). We are proposing under 

CAA section 112(d)(2) and (3) that the use of a bypass at any 

time to divert a Group 1 miscellaneous process vent is a 

violation of the emission standard, and to specify that if 

option 1 is chosen, the owner or operator would be required to 

install, maintain and operate a CPMS for flow that is capable of 

recording the volume of gas that bypasses the APCD. The CMPS 

must be equipped with an automatic alarm system that will alert 

an operator immediately when flow is detected in the bypass 

line. We are proposing this revision because, as noted above, 

APCD are not to be bypassed because doing so could result in a 

release of regulated organic HAP to the atmosphere. In Sierra 

Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court 

determined that standards under CAA section 112(d) must provide 

for compliance at all times and a release of uncontrolled HAP to 

the atmosphere is inconsistent with that requirement. 

c. In Situ Sampling Systems (Onstream Analyzers) 

The current Refinery MACT 1 definition of “miscellaneous 

process vent” states that “in situ sampling systems (onstream 

analyzers)” are not miscellaneous process vents. 40 CFR 63.641. 

For several reasons, we are proposing to remove “in situ 

sampling systems (onstream analyzers)” from the list of vents 

not considered miscellaneous process vents. First, the language 

used in this exclusion is inconsistent. We generally consider 
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“in situ sampling systems” to be non-extractive samplers or inline samplers. There are certain in situ sampling systems where 

the measurement is determined directly via a probe placed in the 

process stream line. Such sampling systems do not have an 

atmospheric vent, so excluding these from the definition of 

“miscellaneous process vent” is not meaningful. The 

parenthetical term “onstream analyzers” generally refers to 

sampling systems that feed directly to an analyzer located at 

the process unit, and has been interpreted to exclude the 

“onstream” analyzer’s vent from the definition of miscellaneous 

process vents. As these two terms do not consistently refer to 

the same type of analyzer, the provision is not clear. 

Second, we find that there is no technical reason to 

include analyzer vents in a list of vents not considered 

miscellaneous process vents. For extractive sampling systems and 

systems with purges, the equipment leak standards in Refinery 

MACT 1 require that the material be returned to the process or 

controlled. Thus, the only potential emissions from any sampling 

system compliant with the Refinery MACT 1 equipment leak 

provisions would be from the analyzer’s “exhaust gas” vent. The 

parenthetical term “onstream analyzers” indicates that the focus 

of the exemption is primarily on the analyzer (or analyzer vent) 

rather than the sampling system. This phrase has been 

interpreted to exclude the “onstream” analyzer’s vent from the 
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definition of miscellaneous process vents. Analyzer venting is 

expected to be routine (continuous or daily intermittent 

venting). 

We are proposing to delete this exclusion from the 

definition of “miscellaneous process vent” and to require these 

vents to meet the standards applicable to miscellaneous process 

vents at all times. We expect most analyzer vents to be Group 2 

miscellaneous process vents because analyzer vents are not 

expected to exceed the 72 pounds per day (lb/day) emissions 

threshold for Group 1 miscellaneous process vents. However, if 

there are larger analyzer vents that exceed the 72 lb/day 

emissions threshold for Group 1 miscellaneous process vents, 

these emission sources would need to be controlled as a Group 1 

miscellaneous process vent under this proposal. We solicit 

comment on the existence of any onstream analyzers that have VOC 

emissions greater than 72 lb/day and why such vents are not 

amenable to control. 

d. Refinery Flares and Fuel Gas Systems 

The current definition of “miscellaneous process vent” in 

Refinery MACT 1 states that “gaseous streams routed to a fuel 

gas system” are not miscellaneous process vents. Furthermore, 

the affected source subject to Refinery MACT 1 does not 

specifically include “emission points routed to a fuel gas 

system, as defined in §63.641 of this subpart.” The EPA allowed 
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these exemptions for streams routed to fuel gas systems because 

according to the 1994 preamble for Refinery MACT 1, “these vents 

are already controlled to the most stringent levels achievable” 

(59 FR 36141, July 15, 1994). Since gaseous streams routed to a 

fuel gas system are eventually burned as fuel, typically in a 

boiler or process heater, these combustion controls burning the 

gaseous streams as fuel effectively achieve this most stringent 

level of control (i.e., 98-percent organic HAP reduction or an 

outlet organic HAP concentration of 20 ppmv for all vent 

streams). However, there can be instances when gaseous streams 

from the fuel gas system that would otherwise be combusted in a 

boiler or process heater are instead routed to a flare (e.g., 

overpressure in the fuel gas system, used as flare sweep gas, 

used as flare purge gas). In cases where an emission source is 

required to be controlled in Refinery MACT 1 and 2 but is routed 

to a fuel gas system, we are proposing that any flare receiving 

gases from that fuel gas system must comply with the flare 

operating and monitoring requirements discussed in section 

IV.A.3 of this preamble. 

B. What are the results and proposed decisions based on our 

technology review? 

1. Refinery MACT 1 – 40 CFR Part 63, Subpart CC 

Refinery MACT 1 sources include miscellaneous process 

vents, storage vessels, equipment leaks, gasoline loading racks, 
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marine vessel loading operations, cooling towers/heat exchange 

systems, and wastewater. 

a. Miscellaneous Process Vents 

Many unit operations at petroleum refineries generate 

gaseous streams containing HAP. These streams may be routed to 

other unit operations for additional processing (e.g., a gas 

stream from a reactor that is routed to a distillation unit for 

separation) or they may be sent to a blowdown system or vented 

to the atmosphere. Miscellaneous process vents emit gases to the 

atmosphere, either directly or after passing through recovery 

and/or APCD. Under 40 CFR 63.643, the owner or operator must 

reduce organic HAP emissions from miscellaneous process vents 

using a flare that meets the equipment specifications in 40 CFR 

63.11 of the General Provisions (subpart A) or use APCD (e.g., 

thermal oxidizers, carbon adsorbers) to reduce organic HAP 

emissions by 98 weight-percent or to a concentration of 20 parts 

per million by volume (ppmv) dry basis, corrected to 3-percent 

oxygen. 

In the technology review, we did not identify any 

practices, processes or control technologies beyond those 

already required by Refinery MACT 1. Therefore, we are proposing 

that it is not necessary to revise Refinery MACT 1 requirements 

for miscellaneous process vents pursuant to CAA section 

112(d)(6). 
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b. Storage Vessels 

Storage vessels (also known as storage tanks) are used to 

store liquid and gaseous feedstocks for use in a process, as 

well as liquid and gaseous products coming from a process. Most 

storage vessels are designed for operation at atmospheric or 

near atmospheric pressures; high-pressure vessels are used to 

store compressed gases and liquefied gases. Atmospheric storage 

vessels are typically cylindrical with a vertical orientation, 

and they are constructed with either a fixed roof or a floating 

roof. Some, generally small, atmospheric storage vessels are 

oriented horizontally. High pressure vessels are either 

spherical or horizontal cylinders. 

Section 63.646(a) requires certain existing and new storage 

vessels to comply with 40 CFR 63.119 through 40 CFR 63.121 of 

the HON. Under 40 CFR 63.119 through 63.121, storage vessels 

must be equipped with an internal floating roof with proper 

seals, an external floating roof with proper seals, an external 

floating roof converted to an internal floating roof with proper 

seals or a closed vent system routed to an APCD that reduces HAP 

emissions by 95 percent. Storage vessels at existing sources 

that use floating roofs are not required under Refinery MACT 1 

to install certain fitting controls included in 40 CFR 63.1119 

of the HON (e.g., gaskets for automatic bleeder vents, slit 

fabric covers for sample wells, flexible fabric seals or 
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gasketed sliding covers for guidepoles and gasketed covers for 

other roof openings). See 40 CFR 63.646(c). 

In 2012, we conducted a general analysis to identify the 

latest developments in practices, processes and control 

technologies for storage vessels at chemical manufacturing 

facilities and petroleum refineries, and we estimated the 

impacts of applying those practices, processes and technologies 

to model storage vessels. (See Survey of Control Technology for 

Storage Vessels and Analysis of Impacts for Storage Vessel 

Control Options, January 20, 2012, Docket Item Number EPA-HQOAR-2010-0871-0027.) We used this analysis as a starting point 

for conducting the technology review for storage vessels at 

refineries. In this analysis, we identified fitting controls, 

particularly controls for floating roof guidepoles, and 

monitoring equipment (liquid level monitors and leak monitors) 

as developments in practices, processes and control technologies 

for storage vessels. In our refinery-specific review, we also 

noted that the Group 1 storage vessel size and vapor pressure 

thresholds in Refinery MACT 1 were higher than those for storage 

vessels in MACT standards for other similar industries. 

Therefore, we also evaluated revising the Group 1 storage vessel 

thresholds as a development in practices for storage vessels in 

the refining industry. 
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We used data from our 2011 ICR to evaluate the impacts of 

requiring the additional controls identified in the technology 

review for the petroleum refinery source category. The emission 

reduction options identified during the technology review are: 

(1) requiring guidepole controls and other fitting controls for 

existing external or internal floating roof tanks as required in 

the Generic MACT for storage vessels (40 CFR part 63, subpart 

WW) in 40 CFR 63.1063; (2) option 1 plus revising the definition 

of Group 1 storage vessel to include smaller capacity storage 

vessels and/or storage vessels containing materials with lower 

vapor pressures and (3) option 2 plus requiring additional 

monitoring to prevent roof landings, liquid level overfills and 

to identify leaking vents and fittings from tanks. We identified 

options 1 and 2 as developments in practices, processes and 

control technologies because these options are required for 

similar tanks in some chemical manufacturing MACT standards and 

we believe they are technologically feasible for storage vessels 

at refineries (e.g., Generic MACT, the HON). Option 3 is also an 

improvement in practices because these monitoring methods have 

been required for refineries by other regulatory agencies. 

Under option 1, we considered the impacts of requiring 

improved deck fittings and controls for guidepoles as is 

required for other chemical manufacturing sources in the Generic 

MACT. Specifically, we considered these controls for storage 
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vessels with existing internal or external floating roof tanks. 

This option also includes the inspection, recordkeeping, and 

reporting requirements set forth in the Generic MACT to account 

for the additional requirements for fitting controls. We are 

aware of recent waiver requests to EPA to allow in-service, topside inspections instead of the out-of-service inspections 

required on a 10-year basis for internal floating roof tanks for 

facilities that are currently subject to 40 CFR part 60, subpart 

Kb and Refinery MACT 1. The requirements of Generic MACT allow 

for this option if there is visual access to all the deck 

components. Under option 1, we considered the Generic MACT 

provisions for in-service, top-side inspection. We are 

requesting comment on whether or not these in-service 

inspections are adequate for identifying conditions that are 

indicative of deck, fitting, and rim seal failures; we are also 

requesting comment on methods to effectively accomplish top-side 

inspections. 

For option 2, we evaluated revising the definition of Group 

1 storage vessels to include smaller capacity storage vessels 

and/or storage vessels with lower vapor pressure, such that 

these additional storage vessels would be subject to the Group 1 

control requirements. For storage vessels at existing sources, 

Refinery MACT 1 currently defines Group 1 storage vessels to be 

those with a capacity of 177 cubic meters (46,760 gallons) or 
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greater, and a true vapor pressure of 10.4 kilopascals (1.5 

pounds per square inch absolute (psia)) or greater. Under 

option 2, we evaluated the impacts of changing the definition of 

Group 1 storage vessels to include storage vessels with a 

capacity of 151 cubic meters (40,000 gallons) or greater and a 

true vapor pressure of 5.2 kilopascals (0.75 psia) or greater, 

and also evaluated including storage vessels with a capacity of 

76 cubic meters (20,000 gallons) or greater (but less than 151 

cubic meters), provided the true vapor pressure of the stored 

liquid is 13.1 kilopascals (1.9 psia) or greater. These 

thresholds are consistent with storage vessel standards already 

required for the chemical industry (e.g., the HON). We believe 

the predominant effect of changing these thresholds will be 

fixed roof tanks at existing petroleum refineries shifting from 

Group 2 storage vessels to Group 1 storage vessels. These fixed 

roof tanks would thus need to be retrofitted with floating roofs 

or vented to an APCD in order to comply with the provisions for 

Group 1 storage vessels. We estimated the impacts of option 2 by 

assuming all uncontrolled fixed roof storage vessels that meet 

or exceed the proposed new applicability requirements for Group 

1 storage vessels (based on the information collected in the 

Refinery ICR) would install an internal floating roof with a 

single rim seal and deck fittings to the existing fixed roof 
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tank. The costs of these fixed roof retrofits were added to the 

costs determined for option 1 to determine the cost of option 2. 

Under option 3, we considered the impacts of including 

additional monitoring requirements for Group 1 storage vessels 

(in addition to fitting controls and fixed roof retrofits 

considered under options 1 and 2). The monitoring requirements 

evaluated include monitoring of internal or external floating 

roof tanks with EPA Method 21 (of 40 CFR part 60, Appendix A-7) 

or optical gas imaging for fittings, and requiring the use of 

liquid level overfill warning monitors and roof landing warning 

monitors. These costs were estimated based on the total number 

of Group 1 storage vessels considering the change in the 

applicability thresholds included in option 2. For further 

details on the assumptions and methodologies used in this 

analysis, see the technical memorandum titled Impacts for 

Control Options for Storage Vessels at Petroleum Refineries, in 

Docket ID Number EPA-HQ-OAR-2010-0682. 

Table 5 of this preamble presents the impacts for the three 

options considered. Although the options were considered 

cumulatively, the calculation of the incremental cost 

effectiveness allows us to assess the impacts of the incremental 

change between the options. As seen by the incremental cost 

effectiveness column in Table 5, both options 1 and 2 result in 

a net cost savings considering the VOC recovery credit for 
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product not lost to the atmosphere from the storage vessel.28 We 

seek comment on the appropriateness of the VOC recovery credit 

we used. The incremental cost effectiveness for option 3 exceeds 

$60,000 per ton of HAP removed. We consider option 3 not to be 

cost effective and are not proposing to require this additional 

monitoring. 

Based on this analysis, we consider option 2 to be cost 

effective. We are, therefore, proposing to revise Refinery MACT 

1 to cross-reference the corresponding storage vessel 

requirements in the Generic MACT (including requirements for 

guidepole controls and other fittings as well as inspection 

requirements), and to revise 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 1.9 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. 

 

28 The VOC recovery credit is $560 per ton, based on $1.75/gal price for 

generic refinery product (gasoline/diesel fuel). (See the technical 

memorandum titled Impacts for Control Options for Storage Vessels at 

Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682 for more 

details). 
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Table 5. Nationwide Emissions Reduction and Cost Impacts of 

Control Options for Storage Vessels at Petroleum Refineries 

Control 

Option 

Capital 

Cost 

(million 

$) 

Annualized 

Costs 

Without 

Recovery 

Credits 

(million 

$/yr) 

Emissions 

Reduction, 

VOC 

(tpy) 

Emissions 

Reduction, 

HAP 

(tpy) 

Cost 

Effectiveness 

($/ton 

HAP) 

Total 

Annualized 

Costs 

with VOC 

Recovery 

Credit 

(million 

$/yr) 

Overall 

Cost 

Effectiveness

with VOC 

Recovery 

Credit 

($/ton 

HAP) 

Incremental 

Cost 

Effectiveness 

with VOC 

Recovery 

Credit 

($/ton 

HAP) 

1 11.9 1.8 11,800 720 2,470 (4.8) (6,690) -- 

2 18.5 3.1 14,600 910 3,430 (5.0) (5,530) (1,140) 

3 36.4 9.6 16,000 1,000 9,580 0.56 560 61,500 

c. Equipment Leaks 

Equipment leaks are releases of process fluid or vapor from 

processing equipment, including pump and compressor seals, 

process valves, relief devices, open-ended valves and lines, 

flanges and other connectors, agitators and instrumentation 

systems. These releases occur primarily at the interface between 

connected components of equipment or in sealing mechanisms. 

Refinery MACT 1 requires the owner or operator of an 

existing source to comply with the equipment leak provisions in 

40 CFR part 60, subpart VV (Standards of Performance for 

Equipment Leaks of VOC in the Synthetic Organic Chemicals 

Manufacturing Industry) for all equipment in organic HAP 

service. The term “in organic HAP service” means that a piece of 

equipment either contains or contacts a fluid (liquid or gas) 

that is at least 5 percent by weight of total organic HAP. 
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Refinery MACT 1 specifies that the owner or operator of a new 

source must comply with the HON, as modified by Refinery MACT 1. 

The provisions for both new and existing sources require 

inspection (either through instrument monitoring using EPA 

Method 21 of 40 CFR part 60, Appendix A-7, or other method such 

as visible inspection) and repair of leaking equipment. For 

existing sources, the leak definition under 40 CFR part 60, 

subpart VV triggers repair at an instrument reading of 10,000 

parts per million (ppm) for all equipment monitored using EPA 

Method 21 of 40 CFR part 60, Appendix A-7 (i.e., pumps and 

valves; instrument monitoring of equipment in heavy liquid 

service and connectors is optional). For new sources, the 

Refinery MACT 1-modified version of the HON triggers repair of 

leaks for pumps at 2,000 ppm and for valves at 1,000 ppm. 

Refinery MACT 1 requires new and existing sources to install a 

cap, plug or blind flange, as appropriate, on open-ended valves 

or lines. Refinery MACT 1 does not require instrument monitoring 

of connectors for either new or existing sources. 

We conducted a general analysis to identify the latest 

developments in practices, processes and control technologies 

applicable to equipment leaks at chemical manufacturing 

facilities and petroleum refineries, and we estimated the 

impacts of applying the identified practices, processes and 

technologies to several model plants. (See Analysis of Emissions 
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Reduction Techniques for Equipment Leaks, December 21, 2011, 

Docket Item Number EPA-HQ-OAR-2010-0869-0029.) We used this 

general analysis as a starting point for conducting the 

technology review for equipment leaks at refineries, but did not 

identify any developments beyond those in the general analysis. 

We estimated the impacts of applying the practices, processes 

and technologies identified in the general analysis to equipment 

leaks in petroleum refinery processes using the information we 

collected through the 2011 Refinery ICR. In general, leak 

detection and repair (LDAR) programs have been used by many 

industries for years to control emissions from equipment leaks. 

Over the years, repair methods have improved and owners and 

operators have become more proficient at implementing these 

programs. The specific developments identified include: (1) 

requiring repair of leaks at a concentration of 500 ppm for 

valves and 2,000 ppm for pumps for new and existing sources 

(rather than 10,000 ppm for valves and pumps at existing sources 

and 1,000 for valves at new sources); (2) requiring monitoring 

of connectors using EPA Method 21 (of 40 CFR part 60, Appendix 

A-7) and repair of leaks for valves and pumps at a concentration 

of 500 ppm; and (3) allowing the use of optical gas imaging 

devices as an alternative method of monitoring. 

The first option we evaluated was to require repair based 

on a leak definition of 500 ppm for valves and a leak definition 
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of 2,000 ppm for pumps at both new and existing sources. The 

nationwide costs and emission reduction impacts of applying 

those lower leak definitions to equipment leaks at petroleum 

refineries are shown in Table 6 of this preamble. For further 

details on the assumptions and methodologies used in this 

analysis, see the technical memorandum titled Impacts for 

Equipment Leaks at Petroleum Refineries, in Docket ID Number 

EPA-HQ-OAR-2010-0682. The emissions reduction results in product 

not being lost by a leak; this additional product can be sold to 

generate revenue, referred to as a VOC recovery credit. Table 6 

shows costs and cost effectiveness both with and without the VOC 

recovery credit. Based on the estimated organic HAP emission 

reductions of 24 tpy and the cost effectiveness of $14,100 per 

ton of organic HAP (including VOC recovery credit), we consider 

lowering the leak definition not to be a cost-effective option 

for reducing HAP emissions. We are, therefore, proposing that it 

is not necessary to revise Refinery MACT 1 pursuant to CAA 

section 112(d)(6) to require repair of leaking valves at 500 ppm 

or greater and repair of leaking pumps at 2,000 ppm or greater. 
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Table 6. Nationwide Emissions Reduction and Cost Impacts of 

Monitoring and Repair Requirements at Lower Leak Definitions 

(500 ppm for Valves; 2,000 ppm for Pumps) 

Capital 

Cost 

(million 

$) 

Annualized 

Costs 

Without 

Recovery 

Credits 

(million 

$/yr) 

Emissions 

Reduction, 

VOC 

(tpy) 

Emissions 

Reduction, 

HAP 

(tpy) 

Cost 

Effectiveness 

($/ton 

VOC) 

Cost 

Effectiveness 

($/ton 

HAP) 

Total 

Annualized 

Costs 

with VOC 

Recovery 

Credit 

(million 

$/yr) 

Overall 

Cost 

Effectiveness with 

VOC 

Recovery 

Credit 

($/ton 

VOC) 

Overall 

Cost 

Effectiveness 

with VOC 

Recovery 

Credit 

($/ton 

HAP) 

1.22 0.53 342 24 1,550 22,100 0.34 987 14,100 

We note that we are aware that some owners and operators 

are required to repair leaking valves as low as 100 ppm and 

pumps as low as 500 ppm. However, we consider requiring repair 

of leaking valves at 500 ppm or greater and repair of leaking 

pumps at 2,000 ppm or greater not to be cost effective. As 

documented in Analysis of Emissions Reduction Techniques for 

Equipment Leaks (December 21, 2011, in Docket ID Number EPA-HQOAR-2010-0869), the cost effectiveness for this option would be 

even higher than the values shown in Table 6 of this preamble. 

The second option we considered was connector monitoring 

and repair. Several standards applying to chemical manufacturing 

facilities, including the HON, include requirements for 

connector monitoring using EPA Method 21 (of 40 CFR part 60, 

Appendix A-7) and requirements for repair of any connector leaks 

above 500 ppm VOC. Neither the Refinery MACT 1 nor the NSPS for 

equipment leaks from refineries (40 CFR part 60, subpart GGG and 

40 CFR part 60, subpart GGGa) currently require connector 
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monitoring and repair (provisions are provided for connector 

monitoring in Refinery MACT 1, but they are optional). We 

evaluated the costs and emissions reduction of requiring 

connector monitoring and repair requirements for equipment leaks 

at refineries. The nationwide costs and emission reduction 

impacts, both with and without VOC recovery credit, are shown in 

Table 7 of this preamble. For further details on the assumptions 

and methodologies used in this analysis, see the technical 

memorandum titled Impacts for Equipment Leaks at Petroleum 

Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682. Based on 

the high annualized cost ($13.9 million per year) and high cost 

effectiveness ($153,000 per ton of HAP) of connector monitoring 

and repair for equipment leaks at refineries, we are proposing 

that it is not necessary to revise Refinery MACT 1 pursuant to 

CAA section 112(d)(6) to require connector monitoring using EPA 

Method 21 (of 40 CFR part 60, Appendix A-7) and repair. 

Table 7. Nationwide Emissions Reduction and Cost Impacts of 

Applying Monitoring and Repair Requirements to Connectors at 

Petroleum Refineries (500 ppm) 

Capital 

Cost 

(million 

$) 

Annualized 

Costs 

Without 

Recovery 

Credits 

(million 

$/yr) 

Emissions 

Reduction, 

VOC 

(tpy) 

Emissions 

Reduction, 

HAP 

(tpy) 

Cost 

Effectiveness 

($/ton 

VOC) 

 Cost 

Effectiveness 

($/ton 

HAP) 

Total 

Annualized 

Costs 

with VOC 

Recovery 

Credit 

(million 

$/yr) 

Overall 

Cost 

Effectiveness

with VOC 

Recovery 

Credit 

($/ton 

VOC) 

Overall 

Cost 

Effectiveness 

with VOC 

Recovery 

Credit 

($/ton 

HAP) 

52.1 13.9 1,230 86 11,300 161,000 13.2 10,700 153,000 
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Another development identified was to provide optical gas 

imaging provisions (including the required instrument 

specifications, monitoring frequency, and repair threshold) as 

an alternative monitoring option where instrument monitoring 

using EPA Method 21 of 40 CFR part 60, Appendix A-7, is required 

in Refinery MACT 1. Since Refinery MACT 1 was issued, there have 

been developments in LDAR work practices using remote sensing 

technology for detecting leaking equipment. In this method of 

detecting leaks, an operator scans equipment using a device or 

system specially designed to use one of several types of remote 

sensing techniques, including optical gas imaging of infrared 

wavelengths, differential absorption light detection and ranging 

(DIAL), and solar occultation flux. 

The most common remote sensing instrument is a passive 

system that creates an image based on the absorption of infrared 

wavelengths (also referred to as a “camera”). A gas cloud 

containing certain hydrocarbons (i.e., leaks) will show up as 

black or white plumes (depending on the instrument settings and 

characteristics of the leak) on the optical gas imaging 

instrument screen. This type of instrument is the device on 

which our evaluation of optical gas imaging instruments is 

based, and the instrument to which we are referring when we use 

the term “optical gas imaging instrument.” These optical gas 

imaging instruments can be used to identify specific pieces of 
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equipment that are leaking. Other optical methods, such as DIAL 

and solar occultation flux, are used primarily to assess 

emissions downwind of a source. These methods cannot be used to 

identify specific leaking equipment; they would only measure the 

aggregate emissions from all equipment and any other source upwind of the measurement location. While we did review these 

technologies as discussed further (see the discussion under 

fenceline monitoring, section IV.B.1.h of this preamble), we do 

not consider DIAL and solar occultation flux methods to be 

suitable alternatives to EPA Method 21 for monitoring equipment 

leaks and are not considering them further in our technology 

review for equipment leaks. 

We expect that all refinery streams “in organic HAP 

service” will include at least one of the compounds visible with 

an optical gas imaging instrument, such as benzene, methane, 

propane or butane. Therefore, it is technically feasible to use 

an optical gas imaging instrument to detect leaks at petroleum 

refineries. The optical gas imaging device can monitor many more 

pieces of equipment than can be monitored using instrument 

monitoring over the same period of time, and we expect that 

specific requirements for using an optical gas imaging device to 

detect leaks without accompanying instrument monitoring could be 

an appropriate alternative to traditional leak detection methods 

(EPA Method 21, as specified in 40 CFR part 60, Appendix A-7). 
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Owners and operators currently have the option to use the 

Alternative Work Practice To Detect Leaks From Equipment (AWP) 

at 40 CFR 63.11(c), (d) and (e). This AWP includes provisions 

for using optical gas imaging in combination with annual 

monitoring using EPA Method 21 of 40 CFR part 60, Appendix A-7. 

In this proposal, we are considering the use of optical gas 

imaging without an accompanying requirement to conduct annual 

monitoring using EPA Method 21, and developing a protocol for 

using optical gas imaging techniques. We anticipate proposing 

the protocol as Appendix K to 40 CFR part 60. Rather than 

specifying the exact instrument that must be used, this protocol 

would outline equipment specifications, calibration techniques, 

required performance criteria, procedures for conducting surveys 

and training requirements for optical gas imaging instrument 

operators. This protocol would also contain techniques to verify 

that the instrument selected can image the most prevalent 

chemical in the monitored process unit. Because field conditions 

greatly impact detection of the regulated material using optical 

gas imaging, the protocol would describe the impact these field 

conditions may have on readings, how to address them and 

instances when monitoring with this technique is inappropriate. 

Finally, the protocol would also address difficulties with 

identifying equipment and leaks in dense industrial areas. 
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Pursuant to CAA section 112(d)(6), we are proposing to 

allow refineries to meet the LDAR requirements in Refinery MACT 

1 by monitoring for leaks via optical gas imaging in place of 

EPA Method 21 (of 40 CFR part 60, Appendix A-7), using the 

monitoring requirements to be specified in Appendix K to 40 CFR 

part 60. When Appendix K is proposed, we will request comments 

on that appendix and how those requirements would apply for 

purposes of this proposed action. We will not take final action 

adopting use of Appendix K to 40 CFR part 60 for optical gas 

imaging for refineries subject to Refinery MACT 1 until such 

time as we have considered any comments on that protocol as it 

would apply to refineries. We do not yet know the exact 

requirements of Appendix K to 40 CFR part 60, and this cannot 

provide a reliable estimate of potential costs at this time. 

However, we have calculated an initial estimate of the potential 

costs and emission reduction impacts, assuming that Appendix K 

to 40 CFR part 60 is similar to the AWP without the annual 

monitoring using EPA Method 21 of 40 CFR part 60, Appendix A-7. 

For more information on these potential impacts, see the 

technical memorandum titled Impacts for Equipment Leaks at 

Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682. 

d. Gasoline Loading Racks 

Loading racks are the equipment used to fill gasoline cargo 

tanks, including loading arms, pumps, meters, shutoff valves, 
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relief valves and other piping and valves. Emissions from 

loading racks may be released when gasoline loaded into cargo 

tanks displaces vapors inside these containers. Refinery MACT 1 

specifies that Group 1 gasoline loading racks at refineries must 

comply with the requirements of the National Emission Standards 

for Gasoline Distribution Facilities (Bulk Gasoline Terminals 

and Pipeline Breakout Stations) in 40 CFR part 63, subpart R. 

The standard specified in 40 CFR part 63, subpart R is an 

emission limit of 10 milligrams of total organic compounds per 

liter of gasoline loaded (mg/L). Additionally, 40 CFR part 63, 

subpart R requires all tank trucks and railcars that are loaded 

with gasoline to undergo annual vapor tightness testing in 

accordance with EPA Method 27 of 40 CFR part 60, Appendix A-8. 

For our technology review of Group 1 gasoline loading racks 

subject to Refinery MACT 1, we relied on two separate analyses. 

First, we previously conducted a technology review for gasoline 

distribution facilities (71 FR 17353, April 6, 2006), in which 

no new control systems were identified. Second, more recently, 

we conducted a general analysis to identify any developments in 

practices, processes and control technologies for transfer 

operations at chemical manufacturing facilities and petroleum 

refineries. (See Survey of Control Technology for Transfer 

Operations and Analysis of Impacts for Transfer Operation 

Control Options, January 20, 2012, Docket Item Number EPA-HQ-
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OAR-2010-0871-0021.) We identified several developments as part 

of this analysis and evaluated the impacts of applying the 

developments to gasoline loading racks subject to Refinery MACT 

1. We have not identified any developments beyond those in the 

second analysis. The identified developments include controlling 

loading racks above specific throughput thresholds by submerged 

loading and by venting displaced emissions from the transport 

vehicles through a closed vent system to an APCD that reduces 

organic regulated material emissions by at least 95 percent. 

We evaluated the emissions projected using this control 

technique for a range of different gasoline vapor pressures (to 

consider the different seasonal formulations of gasoline). We 

determined that submerged loading in combination with 95-percent 

control of displaced vapors would allow emissions of 12 to 42 

mg/L of gasoline loaded, depending on the vapor pressure of the 

gasoline (see Evaluation of the Stringency of Potential 

Standards for Gasoline Loading Racks at Petroleum Refineries in 

Docket ID Number EPA-HQ-OAR-2010-0682.) The current Refinery 

MACT 1 emission limit for gasoline loading is 10 mg/L of 

gasoline loaded. We did not identify any developments in 

practices, process and control technologies for gasoline loading 

racks that would reduce emissions beyond the levels already in 

Refinery MACT 1. Therefore, we are proposing that it is not 
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necessary to revise Refinery MACT 1 requirements for gasoline 

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

e. Marine Vessel Loading Operations 

Marine vessel loading operations load and unload liquid 

commodities in bulk, such as crude oil, gasoline and other 

fuels, and naphtha. The cargo is pumped from the terminal’s 

large, above-ground storage tanks through a network of pipes and 

into a storage compartment (tank) on the vessel. The HAP 

emissions are the vapors that are displaced during the filling 

operation. Refinery MACT 1 specifies that marine tank vessel 

loading operations at refineries must comply with the 

requirements in 40 CFR part 63, subpart Y (National Emission 

Standards for Marine Tank Vessel Loading Operations, “Marine 

Vessel MACT”). 

We previously completed a technology review of the Marine 

Vessel MACT (40 CFR part 63, subpart Y) and issued amendments to 

subpart Y in 2011 (76 FR 22595, Apr. 21, 2011). The analysis 

conducted for the marine vessel loading source category 

specifically considered loading of petroleum products such as 

conventional and reformulated gasoline. As such, the conclusions 

drawn from this analysis are directly applicable to marine 

vessel loading operations at petroleum refineries. We have not 

identified any developments beyond those addressed in that 

analysis. 
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The Marine Vessel MACT required add-on APCD for loading 

operations with HAP emissions equal to or greater than 10 tpy of 

a single pollutant or 25 tpy of cumulative pollutants (referred 

to as “10/25 tpy”). In our technology review of the Marine 

Vessel MACT standards, we considered the use of add-on APCD for 

marine vessel loading operations with HAP emissions less than 

10/25 tpy. We also evaluated the costs for lean oil absorption 

systems as add-on APCD under the Marine Vessel MACT technology 

review. Depending on the throughput of the vessel, costs ranged 

from $77,000 per ton HAP removed for barges to $510,000 per ton 

HAP removed for ships ($3,900 per ton VOC removed to $25,000 per 

ton VOC removed) (see Cost Effectiveness and Impacts of Lean Oil 

Absorption for Control of Hazardous Air Pollutants from Gasoline 

Loading - Promulgation in Docket Item Number EPA-HQ-OAR-2010-

0600-0401). We consider requiring add-on APCD for these smaller 

marine vessel loading operations not to be cost effective. 

As part of the technology review of 40 CFR part 63, subpart 

Y, we also considered requiring marine vessel loading operations 

with emissions less than 10/25 tpy and offshore operations to 

use submerged loading (also referred to as submerged filling). 

We did include this requirement in the Marine Vessel MACT. 

However, when we amended the Marine Vessel MACT, we specifically 

excluded marine vessel loading operations at petroleum 

refineries from these provisions, deferring the decisions to 
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include this requirement until we performed the technology 

review for Refinery MACT 1. The submerged filling requirement in 

40 CFR part 63, subpart Y cites the cargo filling line 

requirements developed by the Coast Guard in 46 CFR 153.282. We 

project that applying the submerged filling requirements to 

marine vessel loading operations at petroleum refineries will 

have no costs or actual emission reductions because marine 

vessels carrying bulk liquids, liquefied gases or compressed gas 

hazardous materials are already required by 46 CFR 153.282 to 

have compliant “submerged fill” cargo lines that also meet the 

requirements of the Marine Vessel MACT. While we do not 

anticipate that this requirement will affect actual emissions, 

it will lower the allowable emissions for these sources under 

Refinery MACT 1. Therefore, we are proposing, pursuant to CAA 

section 112(d)(6), to amend 40 CFR part 63, subpart Y to delete 

the exclusion for marine vessel loading operations at petroleum 

refineries, which would 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. 

f. Cooling Towers/Heat Exchange Systems 

Heat exchange systems include equipment necessary to cool 

heated non-contact cooling water prior to returning the cooling 
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water to a heat exchanger or discharging the water to another 

process unit, waste management unit or to a receiving water 

body. Heat exchange systems are designed as closed-loop 

recirculation systems with cooling towers or once-through 

systems that do not recirculate the cooling water through a 

cooling tower. Heat exchangers in heat exchange systems are 

constructed with tubes designed to prevent contact between hot 

process fluids and cooling water. Heat exchangers occasionally 

develop leaks that allow process fluids to enter the cooling 

water. The volatile HAP and other volatile compounds in these 

process fluids are then emitted to the atmosphere due to 

stripping in a cooling tower or volatilization from a cooling 

water pond or receiving water body. 

We established MACT standards for heat exchange systems at 

refineries in 2009 (see 74 FR 55686, October 28, 2009, as 

amended at 75 FR 37731, June 30, 2010). The EPA received a 

petition for reconsideration from the American Petroleum 

Institute (API) and granted reconsideration on certain issues. 

On June 20, 2013, we issued a final rule addressing the 

petition, clarifying rule provisions, and revising the 

monitoring provisions to provide additional flexibility (78 FR 

37133). We are not aware of any developments in processes, 

practices or control technologies beyond those we recently 

considered in our analysis of emission reduction techniques for 
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heat exchange systems, which can be found in the docket (Docket 

Item Number EPA-HQ-OAR-2003-0146-0229). Therefore, we are 

proposing that it is not necessary to revise Refinery MACT 1 

requirements for heat exchange systems pursuant to CAA section 

112(d)(6). 

g. Wastewater Treatment 

Wastewater collection includes components such as drains, 

manholes, trenches, junction boxes, sumps, lift stations and 

sewer lines. Wastewater treatment systems are divided into three 

categories: primary treatment operations, which include oilwater separators and equalization basins; secondary treatment 

systems, such as biological treatment units or steam strippers; 

and tertiary treatment systems, which further treat or filter 

wastewater prior to discharge to a receiving body of water or 

reuse in a process. 

Refinery MACT 1 requires wastewater streams at a new or 

existing refinery to comply with 40 CFR 61.340 through 61.355 of 

the NESHAP for Benzene Waste Operations (BWON) in 40 CFR part 

61, subpart FF. The BWON requires control of wastewater 

collection and treatment units for facilities with a total 

annual benzene quantity of greater than or equal to 10 megagrams 

per year (Mg/yr). Individual waste streams at refineries with a 

total annual benzene quantity greater than or equal to 10 Mg/yr 

are not required to adopt controls if the flow-weighted annual 
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average benzene concentration is less than 10 parts per million 

by weight (ppmw) or the flow rate is less than 0.02 liters per 

minute at the point of generation. The BWON requires affected 

waste streams to comply with one of several options for 

controlling benzene emissions from waste management units and 

for treating the wastes containing benzene (55 FR 8346, March 7, 

1990; 58 FR 3095, January 7, 1993). 

Although the BWON specifically regulates benzene only, 

benzene is considered a surrogate for organic HAP from 

wastewater treatment systems at petroleum refineries. Benzene is 

present in nearly all refinery process streams. It is an 

excellent surrogate for wastewater pollutants because its unique 

chemical properties cause it to partition into the wastewater 

more readily than most other organic chemicals present at 

petroleum refineries. We stated our rationale regarding the use 

of benzene as a surrogate for refinery HAP emissions from 

wastewater in the original preamble to Refinery MACT 1 (59 FR 

36133, July 15, 1994). 

We performed a technology review for wastewater treatment 

systems to identify different control technologies for reducing 

emissions from wastewater treatment systems. We also reviewed 

the current standards for wastewater treatment systems in 

different rules including the HON, the proposed NSPS for 

wastewater systems at petroleum refineries, and the BWON (See 
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Technology Review for Industrial Wastewater Collection and 

Treatment Operations at Petroleum Refineries, in Docket ID 

Number EPA-HQ-OAR-2010-0682.) We identified several developments 

in processes, practices and control technologies for wastewater 

treatment, and evaluated the cost and cost effectiveness of each 

of those developments: (1) requiring wastewater drain and tank 

controls at refineries with a total annual benzene (TAB) 

quantity of less than 10 Mg/yr; (2) requiring specific 

performance parameters for an enhanced biological unit (EBU) 

beyond those required in the BWON; and (3) requiring wastewater 

streams with a VOC content of 750 ppmv or higher to be treated 

by steam-stripping prior to any other treatment process for 

facilities with high organic loading rates (i.e., facilities 

with total annualized benzene quantity of 10 Mg/yr or more). 

These options are, for the most part, independent of each other, 

so the costs and cost effectiveness of each option are 

considered separately. 

Option 1 was evaluated because refineries with a total 

annual benzene quantity of less than 10 Mg/yr are not required 

to install additional controls on their wastewater treatment 

system. Thus, these refineries are limiting the amount of 

benzene produced in wastewater streams to less than 10 Mg/yr, 

which effectively limits their benzene emissions from wastewater 

to less than 10 Mg/yr. 
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Option 2 is intended to improve the performance of 

wastewater treatment systems that use an EBU, and thereby 

achieve additional emission reductions. The BWON, as it applies 

under Refinery MACT 1, has limited operational requirements for 

an EBU. Available data suggest that these systems are generally 

effective for degrading benzene and other organic HAP; however, 

without specific performance or operational requirements, the 

effectiveness of the EBU to reduce emissions can be highly 

variable. Under option 2, more stringent operating requirements 

are considered for the EBU at refineries. 

Option 3 considers segregated treatment of wastewater 

streams with a volatile organic content of greater than 750 

ppmw, or high-strength wastewater streams, directly in a steam 

stripper (i.e., not allowing these streams to be mixed and 

treated in the EBU). Preliminary investigations revealed direct 

treatment of wastewater by steam-stripping is only cost 

effective for high-strength wastewater streams of sufficient 

quantities. For more detail regarding the impact analysis for 

these control options, see Technology Review for Industrial 

Wastewater Collection and Treatment Operations at Petroleum 

Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682. 

Table 8 provides the nationwide impacts for the control 

options. Based on the costs and emission reductions for each of 

the options, we consider none of the options identified to be 
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cost effective for reducing emissions from petroleum refinery 

wastewater treatment systems. We are proposing that it is not 

necessary to revise Refinery MACT 1 to require additional 

controls for wastewater treatment systems pursuant to CAA 

section 112(d)(6). 

Table 8. Nationwide Emissions Reduction and Cost Impacts of 

Control Options Considered for Wastewater Treatment Systems at 

Petroleum Refineries 

Control 

Option 

Capital 

Cost 

(million $) 

Annualized 

Costs 

(million 

$/yr) 

Emissions 

Reduction, 

VOC (tpy) 

Emissions 

Reduction, 

HAP (tpy) 

Cost 

Effectiveness 

($/ton 

VOC) 

Cost 

Effectiveness 

($/ton 

HAP) 

1 19.7 4.2 592 158 7,100 26,600 

2 223 28.6 2,060 549 13,900 52,100 

3 142 50.7 3,480 929 14,500 54,500 

h. Fugitive Emissions 

The EPA recognizes that, in many cases, it is impractical 

to directly measure emissions from fugitive emission sources at 

refineries. Direct measurement of fugitive emissions from 

sources such as wastewater collection and treatment operations, 

equipment leaks and storage vessels can be costly and difficult, 

especially if required to be deployed on all sources of 

fugitives within a refinery and certainly on a national scale. 

This is a major reason why fugitive emissions associated with 

refinery processes are generally estimated using factors and 

correlations rather than by direct measurement. For example, 

equipment leak emissions are estimated using factors and 
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correlations between leak rates and concentrations from EPA 

Method 21 instrument monitoring. Fugitive emissions from 

wastewater collection and treatment are estimated based on 

process data, material balances and empirical correlations. 

Relying on these kinds of approaches introduces uncertainty into 

the emissions inventory for fugitive emission sources. 

For each of the individual fugitive emission points, we 

evaluated developments in processes, practices and control 

technologies for measuring and controlling fugitive emissions 

from these sources. For storage vessels, as discussed in section 

IV.B.1.b of this preamble, we are proposing to lower the size 

and vapor pressure threshold and to require additional fittings 

on tanks, similar to requirements for tanks in the chemical 

industry because we project a cost savings due to recovered 

product. However, we considered but are not proposing to require 

EPA Method 21 of 40 CFR part 60, Appendix A-7 or optical gas 

imaging monitoring to identify fugitive emissions from each 

individual storage vessel. For equipment leaks, as discussed in 

section IV.B.1.c of this preamble, we considered lowering the 

leak definition for equipment at petroleum refineries from the 

current Refinery MACT 1 level of 10,000 ppm for pumps and valves 

down to the 500 ppm definition that is used in all the other 

MACT standards applying to the chemical industry, as well as 

adding a requirement for connectors to be included in the LDAR 
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program because we consider these more stringent LDAR 

requirements to be technically feasible for the petroleum 

refining industry. Nevertheless, we rejected these options under 

the technology review as not being cost effective, based on 

costs projected by using the industry-reported emissions 

inventories. We are, however, proposing to adopt the use of 

optical gas imaging devices following 40 CFR part 60, Appendix K 

as an alternative to using EPA Method 21, which will be an 

alternative available to petroleum refiners that could offer 

cost savings, once the monitoring protocol set forth in Appendix 

K is promulgated. For wastewater treatment systems, as discussed 

in section IV.B.1.g of this preamble, we considered both 

lowering the threshold for refinery wastewater streams requiring 

control, as well as requiring refineries to comply with enhanced 

monitoring and operating limits for EBU, such as the 

requirements contained in most of the chemical sector MACT 

standards, because we consider these requirements to be 

technically feasible for the refining industry. However, like 

equipment leaks, we are rejecting further controls for 

wastewater because using the industry-reported emissions 

inventory, we determined that further wastewater requirements 

are not cost effective. 

Although we are not proposing to require a number of 

additional control options for fugitive emission sources because 
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we determined them not cost effective, we remain concerned 

regarding the potential for high emissions from these fugitive 

sources due to the difficulties in monitoring actual emission 

levels. For example, the regulations require infrequent 

monitoring of storage tank floating roof seals (visual 

inspections are required annually and direct inspections of 

primary seals are required only when the vessel is emptied and 

degassed, or no less frequently than once every 5 years for 

internal floating roofs or 10 years for external floating roofs 

with secondary seals). Given these inspection frequencies, tears 

or failures in floating roof seals may exist for years prior to 

being noticed, resulting in much higher emissions than expected 

or estimated for these sources in the emissions inventory. 

Similarly, water seals, which are commonly used to control 

emissions from wastewater collection drain systems, may be 

difficult to monitor (e.g., some are underground so visible 

emissions tests cannot be performed) and are subject only to 

infrequent inspections. During hot, dry months, these water 

seals may dry out, leaving an open pathway of vapors to escape 

from the collection system to the atmosphere. Significant 

emission releases may occur from these “dry” drains, which could 

persist for long periods of time prior to the next required 

inspection. 
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Because the requirements and decisions that we are 

proposing in this action are based upon the emissions inventory 

reported by facilities in response to the 2011 Refinery ICR, and 

considering the uncertainty with estimating emissions from 

fugitive emission sources, we believe that it is appropriate 

under CAA section 112(d)(6) to require refiners to monitor, and 

if necessary, take corrective action to minimize fugitive 

emissions, to ensure that facilities appropriately manage 

emissions of HAP from fugitive sources. In other words, in this 

action, we are proposing a HAP concentration to be monitored in 

the ambient air around a refinery, that if exceeded, would 

trigger corrective action to minimize fugitive emissions. The 

concentration action trigger would be set at a level such that 

no facility in the category would need to undertake additional 

corrective measures if the facility’s estimate of emissions from 

fugitive emissions is consistent with the level of fugitive 

emissions actually emitted. On the other hand, if a facility’s 

estimate of fugitive HAP emissions was not accurate, the owner 

or operator may need to take some corrective action to minimize 

fugitive emissions. This concentration trigger approach would 

provide the owner or operator with the flexibility to determine 

how best to reduce HAP emissions to ensure levels remain below 

the action trigger. The details of this proposed approach are 
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set forth in more detail in the following discussions in this 

preamble section. 

In light of the impracticality of directly monitoring many 

of these fugitive emission sources on a regular basis, which 

would help ensure these fugitive sources are properly 

functioning to the extent practical, we evaluated a fenceline 

monitoring program under CAA section 112(d)(6). In this section, 

we evaluate the developments in processes, practices and control 

technologies for measuring and controlling fugitive emissions 

from the petroleum refinery as a whole through fenceline 

monitoring techniques. Fenceline monitoring will identify a 

significant increase in emissions in a timely manner (e.g., a 

large equipment leak or a significant tear in a storage vessel 

seal), which would allow corrective action measures to occur 

more rapidly than it would if a source relied solely on the 

traditional infrequent monitoring and inspection methods. Small 

increases in emissions are not likely to impact the fenceline 

concentration, so a fenceline monitoring approach will generally 

target larger emission sources that have the most impact on the 

ambient pollutant concentration near the refinery. 

Historically, improved information through measurement data 

has often led to emission reductions. However, without a 

specific emission limitation, there may be no incentive for 

owners or operators to act on the additional information. 
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Therefore, as part of the fenceline monitoring approach, we seek 

to develop a not-to-be exceeded annual fenceline concentration, 

above which refinery owners or operators would be required to 

implement corrective action to reduce their fenceline 

concentration. We sought to develop a maximum fenceline 

concentration action level that is consistent with the emissions 

projected from fugitive sources compliant with the provisions of 

the refinery MACT standards as modified by the additional 

controls proposed in this action (e.g., additional fittings on 

storage vessels). 

This section details our technology review to identify 

developments in processes, practices and technologies for 

measuring air toxics at the fenceline of a facility. Upon 

selection of a specific fenceline monitoring method, we provide 

our rationale for the specific details regarding the fenceline 

monitoring approach, including requirements for siting the 

monitors, procedures for adjusting for background interferences, 

selection of the fenceline action level, and requirements for 

corrective action. 

Developments in monitoring technology and practices. The 

EPA reviewed the available literature and identified several 

different methods for measuring fugitive emissions around a 

petroleum refinery. These methods include: (1) passive diffusive 

tube monitoring networks; (2) active monitoring station 
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networks; (3) ultraviolet differential optical absorption 

spectroscopy (UV-DOAS) fenceline monitoring; (4) open-path 

Fourier transform infrared spectroscopy (FTIR); (5) DIAL 

monitoring; and (6) solar occultation flux monitoring. We 

considered these monitoring methods as developments in practices 

under CAA section 112(d)(6) for purposes of all fugitive 

emission sources at petroleum refineries. Each of these methods 

has its own strengths and weaknesses, which are discussed in the 

following paragraphs. 

Fenceline passive diffusive tube monitoring networks employ 

a series of diffusive tube samplers at set intervals along the 

fenceline to measure a time-integrated ambient air concentration 

at each sampling location. A diffusive tube sampler consists of 

a small tube filled with an adsorbent, selected based on the 

pollutant(s) of interest, and capped with a specially designed 

cover with small holes that allow ambient air to diffuse into 

the tube at a small, fixed rate. Diffusive tube samplers have 

been demonstrated to be a cost-effective, accurate technique for 

measuring ambient concentrations of pollutants resulting from 

fugitive emissions in a number of studies.29,30 In addition, 

 

29 McKay, J., M. Molyneux, G. Pizzella, V. Radojcic. Environmental Levels of 

Benzene at the Boundaries of Three European Refineries, prepared by the 

CONCAWE Air Quality Management Group’s Special Task Force on Benzene 

Monitoring at Refinery Fenceline (AQ/STF-45), Brussels, June 1999. 

30 Thoma, E.D., M.C. Miller, K.C. Chung, N.L. Parsons, B.C. Shine. 2011. 

Facility Fenceline Monitoring using Passive Sampling, J. Air & Waste Manage 

Assoc. 61: 834-842. 
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diffusive samplers are used in the European Union to monitor and 

maintain air quality, as described in European Union directives 

2008/50/EC and Measurement Standard EN 14662-4:2005 for benzene. 

The International Organization for Standardization developed a 

standard method for diffusive sampling (ISO/FDIS 16017-2). 

In 2009, the EPA conducted a year-long fenceline monitoring 

pilot project at Flint Hills West Refinery in Corpus Christi, 

Texas, to evaluate the viability and performance of passive 

diffusive sampling technology. Overall, we found the technology 

to be capable of providing cost effective, high spatial-density 

long-term monitoring. This approach was found to be relatively 

robust and implementable by modestly trained personnel and 

provided useful information on overall concentration levels and 

source identification using simple upwind and downwind 

comparisons.31 Combined with on-site meteorological measurements, 

2-week time-integrated passive monitoring has been shown to 

provide useful facility emission diagnostics. 

There are several drawbacks of time-integrated sampling, 

including the lack of immediate feedback on the acquired data 

and the loss of short-term temporal information. Additionally, 

time-integrated monitoring usually requires the collected sample 

to be transported to another location for analysis, leading to 

possible sample integrity problems (e.g., sample deterioration, 

 

31 Thoma, et al, 2011. 
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loss of analytes, and contamination from the surrounding 

environment). However, time-integrated monitoring systems are 

generally lower-cost and require less labor than time-resolved 

monitoring systems. Furthermore, while passive diffusive tube 

monitoring employs time-integrated sampling, these timeintegrated samples still represent much shorter time intervals 

(2 weeks) than many of the current source-specific monitoring 

and inspection requirements (annually or less frequently). 

Consequently, passive diffusive tube monitoring still allows 

earlier detection of significant fugitive emissions than 

conventional source-specific monitoring. 

Active monitoring station networks are similar to passive 

diffusive tube monitoring networks in that a series of discrete 

sampling sites are established; however, each sampling location 

uses a pump to actively draw ambient air at a known rate through 

an adsorption tube. Because of the higher sampling rate, 

adsorption tubes can be analyzed on a daily basis, providing 

additional time resolution compared to diffusive tube sampling 

systems. Alternatively, the active sampling system can directly 

feed an analyzer for even more time resolution. However, this 

direct analysis of ambient air generally has higher detection 

limits than when the organic vapors are collected and 

concentrated on an adsorption matrix prior to analysis. Active 

monitoring stations have been used for a variety of pollutants 
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in a variety of settings and the methods are well-established. 

However, compared to the passive diffusive tube monitoring 

stations, the sampling system is more expensive, more laborintensive, and generally requires highly-trained staff to 

operate. 

UV-DOAS fenceline monitoring is an “open-path” technology. 

An electromagnetic energy source is used to emit a beam of 

electromagnetic energy (ultraviolet radiation) into the air 

towards a detection system some distance from the energy source 

(typically 100 to 500 meters). The electromagnetic energy beam 

interacts with components in the air in the open path between 

the energy source and the detector. The detector measures the 

disruptions in the energy beam to determine an average pollutant 

concentration across the open path length. Because the UV-DOAS 

system can monitor integrated concentrations over a fairly long 

path-length, fewer monitoring “stations” (energy source/detector 

systems) would be needed to measure the ambient concentration 

around an entire refinery. However, each UV-DOAS monitoring 

system is more expensive than an active or passive monitoring 

station and generally requires significant instrumentation 

shelter to protect the energy source and analyzer when used for 

long-term (ongoing) measurements. Advantages of UV-DOAS systems 

include providing real-time measurement data with detection 

limits in the low parts per billion range for certain compounds. 
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Fog or other visibility issues (e.g., dust storm, high pollen, 

wildfire smoke) will interfere with the measurements. UV-DOAS 

systems have been used for fenceline monitoring at several U.S. 

petroleum refineries and petrochemical plants. UV-DOAS 

monitoring systems are specifically included as one of the 

measurement techniques suitable under EPA’s Other Test Method 10 

(OTM-10).32

Open-path FTIR is similar to UV-DOAS monitoring except that 

an infrared light source and detector system are used. Like the 

UV-DOAS monitoring approach, the open-path FTIR monitoring 

system will measure the average pollutant concentration across 

the open path length between the infrared source and detector. 

Path lengths and equipment costs for an open-path FTIR system 

are similar to those for a UV-DOAS system, and the open-path 

FTIR system provides real-time measurement data. The open-path 

FTIR system has spectral interferences with water vapor, CO and 

CO2, which can impact the lower detection limit for organic 

vapors. Open-path FTIR fenceline monitoring has also been used 

to measure ambient air concentrations around several petroleum 

refineries and petrochemical plants. Open-path FTIR is 

specifically included as a measurement technique in EPA’s OTM10. Although open-path FTIR can be used to measure a larger 

 

32 “Optical Remote Sensing for Emission Characterization from Non-Point 

Sources.” Final ORS Protocol, June 14, 2006. Available at: 

http://www.epa.gov/ttn/emc/prelim/otm10.pdf. 
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number of compounds than UV-DOAS, the detection limit of openpath FTIR for benzene is higher than for UV-DOAS, as noted in 

OTM-10. In other words, open-path FTIR is not as sensitive to 

benzene levels as is UV-DOAS. As benzene is an important 

pollutant from fugitive sources at petroleum refineries and can 

often be used as a surrogate for other organic HAP emissions, 

this high detection limit for benzene is a significant 

disadvantage. Thus, for the purposes of measuring organic HAP 

from fugitive sources at the fenceline of a petroleum refinery, 

a UV-DOAS monitoring system is expected to be more sensitive 

than an open-path FTIR system. As the cost and operation of 

open-path FTIR and UV-DOAS systems are very comparable, the 

benzene detection limit issue is a significant differentiator 

between these two methods when considering fenceline monitoring 

to measure fugitives around a petroleum refinery. 

DIAL monitoring systems employ a pulsed laser beam across 

the measurement path. Small portions of the light are 

backscattered due to particles and aerosols in the measurement 

path. This backscattered light is collected through a telescope 

system adjacent to the laser and measured via a sensitive light 

detector. The timing of the received light provides a measure of 

the distance of the emission plume. Two different wavelengths of 

light are pulsed in quick succession: one wavelength that is 

absorbed strongly by the pollutant of interest and one that is 
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not absorbed. The difference in the returned signal strength 

between these two light pulses provides a measure of the 

concentration of the pollutant. Thus, a unique advantage of the 

DIAL monitoring system is that it can provide spatially resolved 

pollutant concentrations in two dimensions. Measurements can be 

made in a relatively short period of time, so the method also 

provides good time resolution. 

The DIAL monitoring system has been used in a variety of 

studies to measure emissions from petroleum refinery and 

petrochemical sources. It is typically used for specific, 

shorter-term studies (one to several weeks in duration). The 

equipment is expensive, has limited availability in the U.S., 

and requires highly trained professionals to operate. Although 

DIAL monitoring is included as an appropriate method for EPA’s 

OTM-10, there are no known long-term applications of this 

technology for the purpose of fenceline monitoring. Given the 

limited availability of the equipment and qualified personnel to 

operate the equipment, we do not consider DIAL monitoring to be 

technically feasible for the purposes of ongoing, long-term 

fenceline monitoring. 

The last fenceline monitoring method evaluated was solar 

occultation flux. Solar occultation flux uses the sun as the 

light source and uses an FTIR or UV detector to measure the 

average pollutant concentration across the measurement path. In 
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this case, the measurement path is vertical. In order to measure 

the concentrations around an industrial source, the measurement 

device is installed in a specially equipped van, which is slowly 

driven along the perimeter of the facility. Measurement signal 

strength and a global positioning system (GPS) enables 

determination of pollutant concentrations along the perimeter of 

the site. This method provides more spatial resolution of the 

emissions than the UV-DOAS or open-path FTIR methods and is less 

expensive than a DIAL system. It has the advantage that only one 

monitoring system is needed per facility, assuming a mobile 

device is used. Disadvantages of this method include the need of 

full-time personnel to drive the equipment around the perimeter 

of the facility (or the need to buy a detector for each 

measurement location around the perimeter of the facility, if 

set locations are used), potential accessibility issues for some 

fenceline locations (e.g., no road near the fenceline), and the 

measurement method cannot be used at night or during cloudy 

periods. It would be possible to purchase numerous detection 

devices and establish fixed monitoring stations similar to the 

passive or active monitoring approaches described earlier, but 

this would be very expensive. Furthermore, any application of 

solar occultation flux is dependent on the sun, so this approach 

would mean significant periods each calendar day when the 

monitoring system would not be able to provide data. Based on 
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our evaluation of this technology, we determined that this 

method is not a reasonable approach for monitoring fenceline 

concentrations of pollutants around a petroleum refinery on a 

long-term, ongoing basis. We are soliciting comment on the 

application of alternative monitoring techniques previously 

discussed for purposes of fenceline monitoring at refineries. 

Costs associated with fenceline monitoring alternatives. 

Based on our review of available monitoring methods, we 

determined that the following monitoring methods were 

technically feasible and appropriate for monitoring organic HAP 

from fugitive emission sources at the fenceline of a petroleum 

refinery on a long-term basis: (1) passive diffusive tube 

monitoring networks; (2) active monitoring station networks; (3) 

UV-DOAS fenceline monitoring; and (4) open-path FTIR. While DIAL 

monitoring and solar occultation flux monitoring can be used for 

short-term studies, we determined that these methods were not 

appropriate for continuous monitoring at petroleum refineries. 

This section evaluates the costs of these technically feasible 

monitoring methods. As noted previously, the cost identified for 

the open-path monitoring methods (UV-DOAS and FTIR) are very 

similar. Therefore, we developed costs for only the UV-DOAS 

system because this method provides lower detection limits for 

pollutants of interest (specifically, benzene). 
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Costs for the fenceline monitoring methods are dependent on 

the sampling frequency (for passive and active monitoring 

locations) and the number of monitoring locations needed based 

on the size and geometry of the facility. For the open-path 

methods, we estimated that four monitoring systems (along the 

east, west, north and south fencelines) would be needed, 

regardless of the size of the refinery. Some fencelines at 

larger refineries may be too long for a single open path length, 

but we did not vary the number of detectors needed for the openpath systems based on refinery size in order to provide a 

reasonable lower-cost estimate for the open-path monitoring 

option. For small petroleum refineries (less than 750 acres), we 

estimated 12 passive or active monitoring stations would be 

sufficient. For medium-sized refineries (750 to 1,500 acres), we 

estimated 18 monitoring stations would be required; for large 

refineries (greater than 1,500 acres), we estimated that 24 

monitoring stations would be needed. For the passive diffusive 

tube monitoring we assumed a 2-week sampling interval; for 

active monitoring stations, we assumed a daily sampling 

frequency. 

We estimated the first year installation and equipment 

costs for the passive tube monitoring system could cost up to 

$100,000 for larger refineries (i.e., 24 sampling locations). 

Annualized costs for ongoing monitoring are projected to be 
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approximately $40,000 per year, assuming the ongoing sample 

analyses are performed in-house. Capital costs for active 

sampling systems were estimated to be approximately twice that 

of the passive system for the larger refinery. Ongoing costs 

were more than 10 times higher, however, due to the daily 

sampling frequency. Equipment costs for a single UV-DOAS system 

were estimated to be about $100,000, so a complete fenceline 

monitoring system (four systems plus shelters) was estimated to 

cost more than $500,000. A refinery using this technology for 

two fenceline locations estimated the annualized cost of 

calibrating and maintaining these systems approaches $1-million 

per year. (See Fenceline Monitoring Technical Support Document, 

in Docket ID Number EPA-HQ-OAR-2010-0682). 

Table 9 provides the nationwide costs of the monitoring 

approaches as applied to all U.S. petroleum refineries. 

Table 9. Nationwide Cost Impacts of Fenceline Monitoring Options 

at Petroleum Refineries 

Monitoring 

Option Monitoring Option Description 

Capital 

Cost 

(million 

$) 

Annual 

Operating 

Costs 

(million 

$/yr) 

Total 

Annualized 

Costs 

(million 

$/yr) 

1 Passive diffusive tube monitoring 

network 

12.2 3.83 5.58 

2 Active sampling monitoring network 20.6 30.2 33.1 

3 Open-path monitoring (UV-DOAS, 

FTIR) 

71.0 35.5 45.6 

The primary goal of a fenceline monitoring network is to 

ensure that owners and operators properly monitor and manage 
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fugitive HAP emissions. As explained further in this preamble 

section, we are proposing a concentration action trigger level 

that was derived by modeling fenceline benzene concentrations 

(as a surrogate for HAP) at each facility after full compliance 

with the refinery MACT standards, as amended by this proposed 

action. As such, we are proposing a fenceline trigger benzene 

concentration that all facilities in the category can meet, 

according to the emissions inventories reported in response to 

the 2011 Refinery ICR. Therefore, we do not project a HAP 

emission reduction that the fenceline monitoring network will 

achieve. However, if an owner or operator has underestimated the 

fugitive emissions from one or more sources, or if a leak 

develops or a tank seal or fitting fails, a fenceline monitoring 

system would provide for identification of such leaks much 

earlier than current monitoring requirements and, where 

emissions are beyond those projected from implementation of the 

MACT standards, would help ensure that such emissions are 

quickly addressed. We note that any costs for a fugitive 

monitoring system would be offset, to some extent, by product 

recovery since addressing these leaks more quickly than would 

otherwise occur based on the more infrequent monitoring required 

would reduce product losses. 

Based on the low cost and relative benefits of passive 

monitoring, which include the ability to generate time-
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integrated concentration measurements at low detection limits, 

coupled with relative ease of deployment and analysis, the EPA 

is proposing to require refineries to deploy passive timeintegrated samplers at the fenceline. These samplers would 

monitor the level of fugitive emissions that reach the fenceline 

from all fugitive emission sources at the facility. The EPA is 

proposing to require fugitive emission reductions if fenceline 

concentrations exceed a specified concentration action level, as 

described further below. These proposed fenceline monitoring 

requirements complement the EPA’s proposal to allow the use of 

the optical gas imaging camera as described in Appendix K of 40 

CFR part 60 as an alternative work practice for measuring 

emissions from equipment leaks, in lieu of monitoring with EPA 

Method 21 of 40 CFR part 60, Appendix A-7 (see section IV.B.1.c 

of this preamble for further discussion). Both approaches 

utilize low-cost methods to help ensure that total fugitives 

from a facility are adequately controlled. 

Because there is no current EPA test method for passive 

diffusive tube monitoring, as part of this action we are 

proposing specific monitor citing and sample collection 

requirements as EPA Method 325A of 40 CFR part 63, Appendix A, 

and specific methods for analyzing the sorbent tube samples as 

EPA Method 325B of 40 CFR part 63, Appendix A. We are proposing 

to establish an ambient concentration of benzene at the 
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fenceline that would trigger required corrective action. A brief 

summary of the proposed fenceline sampling requirements and our 

rationale for selecting the corrective action concentration 

levels are provided below. 

Siting, design and sampling requirements for fenceline 

monitors. The EPA is proposing that passive fenceline monitors 

collecting 2-week time-integrated samples be deployed to measure 

fenceline concentrations at refineries. We are proposing that 

refineries deploy passive samplers at 12 to 24 points circling 

the refinery perimeter. A primary requirement for a fenceline 

monitoring system is that it provides adequate spatial coverage 

for determination of representative pollutant concentrations at 

the boundary of the facility or operation. In an ideal scenario, 

fenceline monitors would be placed so that any fugitive plume 

originating within the facility would have a high probability of 

intersecting one or more monitors, regardless of wind direction. 

This proposed monitoring program would require that monitors be 

placed at 15 to 30 degree intervals along the perimeter of the 

refinery, depending on the size of the facility. For small 

refineries (less than 750 acres), monitors should be placed at 

30 degree intervals, for a total of 12 locations; for facilities 

that are larger than 750 acres and less than 1,500 acres, 

monitors should be placed at 20 degree intervals, at 18 

locations; and for facilities greater than 1,500 acres, monitors 
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should be placed at 15 degree intervals, accounting for 24 

locations. We have also established an alternative siting 

procedure where monitors can be placed every 2,000 feet along 

the fenceline of the refinery, which may be easier to implement, 

especially for irregularly-shaped facilities. In proposing these 

requirements for the number and location of required monitors, 

the EPA assumes that all portions of the facility are contiguous 

such that it is possible to define a single facility boundary or 

perimeter, although this perimeter may be irregular in shape. We 

request comment on how these monitoring requirements should be 

adapted for instances where one or more portions of the facility 

are not contiguous, and on the number and location of facilities 

for which special fenceline monitoring requirements to 

accommodate non-contiguous operations might apply. 

We are proposing that the highest concentration of benzene, 

as an annual rolling average measured at any individual monitor 

and adjusted for background (see below), would be compared 

against the concentration action level in order to determine if 

there are significant excess emissions of fugitive emissions 

that need to be addressed. Existing sources would be required to 

deploy samplers no later than 3 years after the effective date 

of the final rule; new sources would be required to deploy 

samplers by the effective date of the final rule or startup, 

whichever is later. Because the proposed concentration action 
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level is composed of 1 year’s worth of data, we are proposing 

that refinery owners and operators would be required to 

demonstrate compliance with the concentration action level for 

the first time 1 year following the compliance date, and 

thereafter on a 1-year rolling annual average basis (i.e., 

considering results from the most recent 26 consecutive 2-week 

sampling intervals and recalculating the average every 2 weeks). 

Benzene as an appropriate target analyte. Passive diffusive 

tube monitors can be used to determine the ambient concentration 

of a large number of compounds. However, different sorbent 

materials are typically needed to collect compounds with 

significantly different properties. Rather than require multiple 

tubes per monitoring location and require a full analytical 

array of compounds to be determined, which would significantly 

increase the cost of the proposed fenceline monitoring program, 

we are proposing that the fenceline monitors be analyzed 

specifically for benzene. Refinery owners or operators may elect 

to do more detailed speciation of the emissions, which could 

help identify the process unit that may be contributing to a 

high fenceline concentration, but we are only establishing 

monitoring requirements and action level requirements for 

benzene. We consider benzene to be an excellent surrogate for 

organic HAP from fugitive sources for multiple reasons. First, 

benzene is ubiquitous at refineries, and is present in nearly 
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all refinery process streams such that leaking components 

generally will leak benzene at some level (in addition to other 

compounds). Benzene is also present in crude oil and gasoline, 

so most storage tank emissions include benzene. As described 

previously in our discussion of wastewater treatment systems, 

benzene is also a very good surrogate for organic HAP emissions 

from wastewater and is already considered a surrogate for 

organic HAP emissions in the wastewater treatment system control 

requirements in Refinery MACT 1. Second, the primary releases of 

benzene occur at ground level as fugitive emissions from process 

equipment, storage vessels and wastewater collection and 

treatment systems, and the highest ambient benzene 

concentrations outside the facility will likely occur near the 

property boundary near ground level, so fugitive releases of 

benzene will be effectively detected at the ground-level 

monitoring sites. According to the emissions inventory we have 

relied on for this proposed action, 85 percent of benzene 

emissions from refineries result from ground-level fugitive 

emissions from equipment and wastewater collection and treatment 

(see the Component 2 database contained in Docket ID Number EPAHQ-OAR-2010-0682). Finally, benzene is present in nearly all 

process streams. Therefore, the presence of benzene at the 

fenceline is also an indicator of other air toxics emitted from 

fugitive sources at refineries. 
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For the reasons discussed above, we believe that benzene is 

the most appropriate pollutant to monitor. We believe that other 

compounds, such as PAH or naphthalene, would be less suitable 

indicators of total fugitive HAP for a couple of reasons. First, 

they are prevalent in stack emissions as well as fugitive 

emissions, so there is more potential for fenceline monitors to 

pick up contributions from non-fugitive sources. In contrast, 

almost all benzene comes from fugitive sources, so monitoring 

for benzene increases our confidence that the concentration 

detected at the fenceline is from fugitives. Second, as compared 

to benzene, these other compounds are expected to be present at 

lower concentrations and, therefore, would be more difficult to 

measure accurately using fenceline monitoring. We request 

comments on the suitability of selecting benzene or other HAP, 

including PAH or naphthalene, as the indicator to be monitored 

by fenceline samplers. We also request comment on whether it 

would be appropriate to require multiple HAP to be monitored at 

the fenceline considering the capital and annual cost for 

additional monitors, and if so, which pollutants should be 

monitored. 

Adjusting for background benzene concentrations. Under this 

proposed approach, absolute measurements along a facility 

fenceline cannot completely characterize which emissions are 

associated with the refinery and which are associated with other 
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background sources. The EPA recognizes that sources outside the 

refinery boundaries may influence benzene levels monitored at 

the fenceline. Furthermore, background levels driven by local 

upwind sources are spatially variable. Both of these factors 

could result in inaccurate estimates of the actual contribution 

of fugitive emissions from the facility itself to the 

concentration measured at the fenceline. Many refineries and 

petrochemical industries are found side-by-side along waterways 

or transport corridors. With this spatial positioning, there is 

a possibility that the local upwind neighbors of a facility 

could cause different background levels on different sides of 

the facility. To account for background concentrations (i.e., to 

remove the influence of benzene emissions from sources outside 

the refinery on monitored fenceline values), we are proposing to 

adjust monitored fenceline values to account for background 

concentrations as described below. We solicit comments on 

alternative approaches for making these adjustments for 

background benzene. 

Fenceline-deployed passive samplers measure concentrations 

that originate from both the observed facility and from off-site 

sources. The relative contribution of the facility versus offsite source(s) to the measured concentration depends on the 

emission levels of the observed facility and off-site sources 

(including both near-field and remote sources), transporting 
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wind direction and atmospheric dispersion. The ability to 

identify facility and off-site source contributions is reliant 

on the measurement scheme selected. The most basic (and lowest 

cost) approach involves different calculations using 2-week 

deployed samplers located only at the facility fenceline. 

Greater discrimination capability is found by adding passive 

samplers to specific areas of the facility, reducing the time 

duration of the passive samplers, and coupling measured 

meteorology information to the passive sampler analysis. 

Selective use of time-resolved monitoring or wind sector 

sampling approaches provides the highest source and background 

discrimination capability. The approach we are proposing seeks 

to remove off-site source contributions to the measured 

fenceline concentrations to the greatest extent possible using 

the most cost-effective measurement solutions. 

The highest fenceline concentration (HFC) for each 2-week 

sampling period can be expressed as: 

  HFC  Maximum MFCi OSCi

where: 

HFC = highest fenceline concentration, corrected for 

background. 

MFCi = measured fenceline concentration for the sampling 

period at monitoring location i. 
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OSCi = estimated off-site source contribution for the 

sampling period at monitoring location i. 

The off-site source contribution (OSC) consists of two 

primary components: (1) a slowly varying, spatially uniform 

background (UB) concentration and, in some cases, (2) potential 

near-field interfering sources. 

OSCi  UB  NFSi

where: 

UB = uniform background concentration. 

NFSi = near-field interfering source concentration 

contribution at monitoring location i. 

In some deployment scenarios (such as spatially isolated 

facilities), the major off-site source component can be 

identified as background concentrations that are uniform across 

the facility fenceline and neighboring area. In this scenario, a 

UB concentration level can be determined and subtracted from the 

measured fenceline concentrations for each sampling period. This 

can be accomplished through use of facility-measured or 

otherwise available, quality assured time-resolved (or wind 

sector-resolved) background monitoring data, or from placement 

of additional passive samplers at upwind locations away from the 

facility fenceline and other sources. 
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In other scenarios, such as where other industrial sources 

or a highway are located nearby, background concentrations are 

likely not uniform. These outside sources would influence some, 

but not perhaps not all, fenceline monitors and, therefore, the 

true “background” concentration would vary, depending where on 

the fenceline the measurement was taken. In this case, 

background is not uniform, and monitoring location-specific 

near-field interfering source (NFS) values would need to be 

determined. 

Due to the difficulties associated with determining 

location-specific NFS values, we are proposing to approximate 

OSC by using the lowest measured concentration (LMC) at the 

facility fenceline for that period. In this case, the HFC for 

the monitoring period, corrected for background, would be 

calculated as: 

HFC  C  HMC  LMC

where: 

ΔC = concentration difference between the highest and 

lowest measured concentrations for the sampling period. 

HMC = highest measured fenceline concentration for the 

sampling period. 

LMC = lowest measured fenceline concentration for the 

sampling period. 
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This alternative is directly applicable for all refinery 

locations and requires no additional, off-site, upwind monitors, 

the placement of which is impossible to prescribe a priori. Use 

of LMC provides a reasonable proxy for OSC in most cases, but 

can over- or underestimate OSC in some cases. In locations where 

there are few upwind source contributions and where wind 

direction is relatively consistent, upwind passive samples on 

the fenceline can provide a realistic approximation of the 

actual off-site background levels. As the meteorology becomes 

more complicated (e.g., mixed wind directions, higher percentage 

of calm winds), the LMC will reflect a progressively larger 

amount of emissions from the facility itself, so differential 

calculations may underestimate the true HFC for some monitoring 

periods (by inadvertently allowing some facility emissions to be 

subtracted as part of “background”). On the other hand, if a 

near-field source impacts the highest measured concentration 

monitoring location significantly, but contributes little to the 

monitoring location with the LMC, the LMC differential 

calculation (i.e., ΔC) could lead to an artificially elevated 

assessment of the highest fenceline concentration, corrected for 

background. 

Based on our examination of previous fenceline monitoring 

results, we expect that the use of the LMC differential will 

provide an accurate method by which to determine HFC. Therefore, 
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we are not proposing to limit the use of the LMC differential 

calculation in cases where there are no near-field sources and 

where mixed wind direction (or calm wind) is common. In these 

special cases, use of the UB concentration alone (no NFS term) 

may be more accurate than using LMC. We are seeking comment on 

how to identify conditions under which the LMC differential may 

underestimate the highest fenceline concentration, corrected for 

background, and the need to require facilities to determine and 

use UB rather than LMC in these cases. 

We also recognize that under different site-specific 

conditions, the NFS contribution may affect certain fenceline 

monitoring stations more than others, causing the LMC 

differential calculation to overestimate the facility’s 

contribution to the highest fenceline concentration. Therefore, 

we are also proposing to allow owners or operators of petroleum 

refineries to develop site-specific monitoring plans to 

determine UB and NFSi. 

If standard 2-week passive fenceline data and site analysis 

indicate potential near-field off-site source interferences at a 

section of the refinery, the proposal allows the owner or 

operator to conduct additional sampling strategies to determine 

a local background (OSC term) for use in the HFC calculation. 

The owner or operator would be required to report the basis for 

this correction, including analyses used to identify the sources 
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and contribution of benzene concentration to the passive sampler 

concentration, within 45 days of the date the owner or operator 

first measures an exceedance of the concentration action level. 

We envision that facilities would implement these 

additional strategies to refine fenceline concentration 

estimates only if appropriate given site-specific 

characteristics and only if HFC determined by the LMC approach 

is likely to exceed the concentration action level (see 

discussion below regarding this action level). Facilities with 

HFC below the concentration action level based on the simple LMC 

differential calculation would not be required to make any 

further demonstration of the influence of background sources on 

concentrations measured at the fenceline. For facilities where 

additional background adjustment is appropriate, optional 

strategies could include deployment of additional passive 

samplers at distances from the fenceline (toward and away from 

suspected NFS) and reducing the time intervals of passive 

deployments to increase time resolution and wind directioncomparison capability. In complex cases, such as two refineries 

sharing a common fenceline, wind-sector sampling or various 

forms of time-resolved monitoring may be required to ascertain 

the fenceline concentrations. 

We are proposing that owners or operators of petroleum 

refineries electing to determine monitoring location-specific 
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NFS concentrations must prepare and submit a site-specific 

monitoring plan. The monitoring plan is required to identify 

specific near-field sources, identify the location and type of 

monitors used to determine UB and NFS concentrations, identify 

the monitoring location(s) for which the NFS concentrations 

would apply, and delineate the calculations to be used to 

determine monitoring location specific NFS concentrations (for 

those monitoring locations impacted by the near-field source). 

We are proposing that the site-specific monitoring plan must be 

submitted to the Administrator for approval and receive approval 

prior to its use for determining HFC values. 

The EPA requests comment on the most appropriate 

approach(es) for adjusting measured fenceline concentrations for 

background contributions, including (in complex cases) where 

meteorology is highly variable or where one or more near-field 

off-site sources affect the measured fenceline concentration 

(MFC) at a refinery. We are also seeking comment on the adequacy 

of the proposed requirements for developing and approving sitespecific monitoring plans. 

Concentration action level. As mentioned above, the EPA is 

proposing to require refineries to take corrective action to 

reduce fugitive emissions if monitored fenceline concentrations 

exceed a specific concentration action level on on a rolling 

annual average basis (recalculated every two weeks). We selected 
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this proposed fenceline action level by modeling fenceline 

benzene concentrations using the emissions inventories reported 

in response to the 2011 Refinery ICR, assuming that those 

reported emissions represented full compliance with all refinery 

MACT requirements, adjusted for additional control requirements 

we are proposing in today’s action. Thus, if the reported 

inventories are accurate, all facilities should be able to meet 

the action trigger level. We estimated the long-term ambient 

post-control benzene concentrations at each petroleum refinery 

using the post-control emission inventory and EPA’s American 

Meteorological Society/EPA Regulatory Model dispersion modeling 

system (AERMOD). Concentrations were estimated by the model at a 

set of polar grid receptors centered on each facility, as well 

as surrounding census block centroid receptors extending from 

the facility outward to 50 km. For purposes of this modeling 

analysis, we assumed that the nearest off-site polar grid 

receptor was the best representation of each facility’s 

fenceline concentration in the post-control case, unless there 

was a census block centroid nearer to the fenceline than the 

nearest off-site polar grid receptor or an actual receptor was 

identified from review of the site map. In those instances, we 

estimated the fenceline concentration as the concentration at 

the census block centroid. Only receptors (either the polar or 

census block) that were estimated to be outside the facility 
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fenceline were considered in determining the maximum benzene 

level for each facility. We note that this analysis does not 

correlate to any particular metric related to risk. The maximum 

post-control benzene concentration modeled at the fenceline for 

any facility is 9 micrograms per cubic meter (μg/m3

) (annual 

average). (For further details of the analysis, see memo 

entitled Fenceline Ambient Benzene Concentrations Surrounding 

Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682.) 

The facility inventories generally project emissions with 

the required fugitive controls working as designed (e.g., no 

tears in seals for storage vessel floating roofs and water in 

all water drain seals). If facility inventories are correct, 

annual average benzene concentrations would not exceed 9 μg/m3

 at 

the fenceline of any facility. Because the modeling approach 

considers only the emissions from the refinery, with no 

contribution from background or near-field sources, this 

concentration is comparable to the highest modeled fenceline 

concentration after correcting for background concentrations, as 

described previously. The EPA is proposing to set the standard 

at this concentration action level. We also note that this 

modeling effort evaluated the annual average benzene 

concentration at the fenceline, so that this action level 

applies to the annual average fenceline concentration measured 

at the facility. 
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The EPA recognizes that, because it is difficult to 

directly measure emissions from fugitive sources, there is 

significant uncertainty in current emissions inventories for 

fugitives. Thus, there is the potential for benzene 

concentrations monitored at the fenceline to exceed modeled 

concentrations. However, given the absence of fenceline monitors 

at most facilities, there is very limited information available 

at present about fenceline concentrations and the extent to 

which they may exceed concentrations modeled from inventories. 

In the absence of additional data regarding the concentration of 

fugitive emissions of benzene at the fenceline, the EPA believes 

it is reasonable to rely on the maximum modeled fenceline value 

as the concentration action level. We are soliciting comment on 

alternative concentration action levels and other approaches for 

establishing the concentration action level. 

Due to differences in short-term meteorological conditions, 

short-term (i.e., two-week average) concentrations at the 

fenceline can vary greatly. Given the high variability in shortterm fenceline concentrations and the difficulties and 

uncertainties associated with estimating a maximum 2-week 

fenceline concentration given a limited number of years of 

meteorological data used in the modeling exercise, we determined 

that it would be inappropriate and ineffective to propose a 
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short-term concentration action level that would trigger 

corrective action based on a single 2-week sampling event. 

One objective for this monitoring program is to identify 

fugitive emission releases more quickly, so that corrective 

action can be implemented in a more timely fashion than might 

otherwise occur without the fenceline monitoring requirement. We 

believe the proposed fenceline monitoring approach and a rolling 

annual average concentration action limit (i.e., using results 

from the most recent 26 consecutive 2-week samples and 

recalculating the average every 2 weeks) will achieve this 

objective. The proposed fenceline monitoring will provide the 

refinery owner or operator with fenceline concentration 

information once every 2 weeks. Therefore, the refinery owner or 

operator will be able to timely identify emissions leading to 

elevated fenceline concentrations. We anticipate that the 

refinery owners or operators will elect to identify and correct 

these sources early, in efforts to avoid exceeding the annual 

benzene concentration action level. 

An “exceedance” of the benzene concentration action level 

would occur when the rolling annual average highest fenceline 

concentration, corrected for background (determined as described 

previously), exceeds 9 μg/m3

. Upon exceeding the concentration 

action level, we propose that refinery owners or operators would 

be required to conduct analyses to identify sources contributing 
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to fenceline concentrations and take corrective action to reduce 

fugitive emissions to ensure fenceline benzene concentrations 

remain at or below 9 μg/m3

 (rolling annual average). 

Corrective action requirements. As described previously, 

the EPA is proposing that the owner or operator analyze the 

samples and compare the rolling annual average fenceline 

concentration, corrected for background, to the concentration 

action level. This section summarizes the corrective action 

requirements in this proposed rule. First, we are proposing that 

the calculation of the rolling annual average fenceline 

concentration must be completed within 30 days after the 

completion of each sampling episode. If the rolling annual 

average fenceline benzene concentration, corrected for 

background, exceeds the proposed concentration action level 

(i.e., 9 μg/m3

), the facility must, within 5 days of comparing 

the rolling annual average concentration to the concentration 

action level, initiate a root cause analysis to determine the 

primary cause, and any other contributing cause(s), of the 

exceedance. The facility must complete the root cause analysis 

and implement corrective action within 45 days of initiating the 

root cause analysis. We are not proposing specific controls or 

corrections that would be required when the concentration action 

level is exceeded because the cause of an exceedance could vary 

greatly from facility to facility and episode to episode, since 
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many different sources emit fugitive emissions. Rather, we are 

proposing to allow facilities to determine, based on their own 

analysis of their operations, the action that must be taken to 

reduce air concentrations at the fenceline to levels at or below 

the concentration action level, representing full compliance 

with all refinery MACT requirements, adjusted for additional 

control requirements we are proposing in today’s action. 

If, upon completion of the corrective action described 

above, the owner or operator exceeds the action level for the 

next two-week sampling episode following the completion of a 

first set of corrective actions, the owner or operator would be 

required to develop and submit to EPA a corrective action plan 

that would describe the corrective actions completed to date. 

This plan would include a schedule for implementation of 

emission reduction measures that the owner or operator can 

demonstrate is as soon as practical. This plan would be 

submitted to the Administrator for approval within 30 days of an 

exceedance occurring during the next two-week sampling episode 

following the completion of the initial round of corrective 

action. The EPA would evaluate this plan based on the ambient 

concentrations measured, the sources identified as contributing 

to the high fenceline concentration, the potential emission 

reduction measures identified, and the emission reduction 

measures proposed to be implemented in light of the costs of the 
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options considered and the reductions needed to reduce the 

ambient concentration below the action level threshold. To 

minimize burden on the state implementing agencies and provide 

additional resources for identifying potential emission sources, 

we are proposing not to delegate approval of this plan. The 

refinery owner or operator is not deemed out of compliance with 

the proposed concentration action level, provided that the 

appropriate corrective action measures are taken according to 

the time-frame detailed in an approved corrective action plan. 

The EPA requests comment on whether it is appropriate to 

establish a standard time frame for compliance with actions 

listed in a corrective action plan. We also request comment on 

whether the approval of the corrective action plan should be 

delegated to state, local and tribal governments. 

The EPA’s post-control dispersion modeling (described in 

section III.A of this preamble), which relies on reported 

emissions inventories from the 2011 Refinery ICR, adjusted to 

reflect compliance with the existing refinery MACT standards as 

modified by the additional controls proposed in this rulemaking, 

indicates that fugitive emissions at all refineries are low 

enough to ensure that fenceline concentrations of benzene do not 

exceed the proposed concentration action level. Assuming the 

reported inventories and associated modeling are accurate, we 

expect that few, if any, facilities will need to engage in 
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required corrective action. We do, however, expect that 

facilities may identify “poor-performing” sources (e.g., unusual 

leaks) from the fenceline monitoring data and, based on this 

additional information, will take action to reduce HAP emissions 

before they would have otherwise been aware of the issue through 

existing inspection and enforcement measures. 

By selecting a fenceline monitoring approach and by 

selecting benzene as the surrogate for organic HAP emissions, we 

believe that the proposed monitoring approach will effectively 

target refinery MACT-regulated fugitive emission sources. 

However, there may be instances where the fenceline 

concentration is impacted by a low-level miscellaneous process 

vent, heat exchange system or other similar source. As these 

sources are regulated under Refinery MACT 1 and the emissions 

from these sources were included in our post-control modeling 

file (from which the 9 μg/m3

 fenceline concentration action level 

was developed), sources would not be able to avoid taking 

corrective action by claiming the exceedance of the fenceline 

concentration was from one of these emission points rather than 

from fugitive emission sources. 

There may be instances in which the high fenceline 

concentration is impacted by a non-refinery emission source. The 

most likely instance of this would be leaks from HON equipment 

or HON storage vessels co-located at the refinery. However, we 
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consider the fenceline monitoring requirement to be specific to 

refinery emission sources. Therefore, we are proposing to allow 

refinery owners or operators to develop site-specific monitoring 

plans to determine the impact of these non-Refinery emission 

sources on the ambient benzene concentration measured at the 

fenceline. This monitoring plan would be identical to those used 

by refinery owners or operators that elect to determine 

monitoring location-specific NFS values for nearby off-site 

sources. In this case, however, the NFS is actually within the 

refinery fenceline. Upon approval and implementation of the 

monitoring plan, the refinery owner or operator would determine 

the highest fenceline concentration corrected for background; 

the background correction in this case includes a correction for 

the co-located non-Refinery emission source(s). 

The EPA requests comment on whether the corrective action 

requirements should be limited to exceedances of the fenceline 

concentration solely from refinery emission sources and whether 

a refinery owner or operator should be allowed to exceed the 

annual average fenceline concentration action level if they can 

demonstrate the exceedance of the action level is due to a nonrefinery emissions source. We also request comment on the 

requirements proposed for refinery owners or operators to 

demonstrate that the exceedance is caused by a non-refinery 

emissions source. Specifically, we request comment on whether 
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the “near-field source” correction is appropriate for on-site 

sources and whether there are other methods by which refinery 

owners or operators with co-located, non-refinery emission 

sources can demonstrate that their benzene concentrations do not 

exceed the proposed fenceline concentration action level. 

Additional requirements of the fenceline monitoring 

program. We are proposing that fenceline data at each monitor 

location be reported electronically for each semiannual period’s 

worth of sampling periods (i.e., 13 to 14 2-week sampling 

periods per semiannual period). These data would be reported 

within 45 days of the end of each semiannual period, and will be 

made available to the public through the EPA’s electronic 

reporting and data retrieval portal, in keeping with the EPA’s 

efforts to streamline and reduce reporting burden and to move 

away from hard copy submittals of data where feasible. 

We are proposing to require the reporting of raw fenceline 

monitoring data, and not just the HFC, on a semiannual basis; 

considering the fact that the fenceline monitoring standard is a 

new approach for fugitive emissions control, and it involves the 

use of new methods, both analytical and siting methods, this 

information is necessary for the EPA to evaluate whether this 

standard has been implemented correctly. Further, the 

information provided by the raw data, such as the need for 

additional or less monitoring sites, the range of measured 
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concentrations, the influence of background sources, and the 

ability to collect and compare data from all refineries, will 

inform us of further improvements we can make to the fenceline 

standard, monitoring and analytical methods, approaches for 

estimating refinery fugitive emissions, and guidance that may be 

helpful to improve implementation of the fenceline monitoring 

approach. We seek comment on suggestions for other ways we can 

monitor and improve the fenceline monitoring requirement. 

We are proposing that facilities be required to conduct 

fenceline monitoring on a continuous basis, in accordance with 

the specific methods described above, even if benzene 

concentrations, as measured at the fenceline, routinely are 

substantially lower than the concentration action level. In 

light of the low annual monitoring and reporting costs 

associated with the fenceline monitors (as described in the next 

section), and the importance of the fenceline monitors as a 

means of ensuring the control of fugitives achieves the expected 

emission levels, we believe it is appropriate to require 

collection of fenceline monitoring data on a continuous basis. 

However, the EPA recognizes that fugitive benzene emissions from 

some facilities may be so low as to make it improbable that 

exceedances of the concentration action level would ever occur. 

In the interest of reducing the cost burden on facilities 

to comply with this rule, the EPA solicits comment on approaches 
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for reducing or eliminating fenceline monitoring requirements 

for facilities that consistently measure fenceline 

concentrations below the concentration action level, and the 

measurement level that should be used to provide such relief. 

Such an approach would be consistent with graduated requirements 

for valve leak monitoring in Refinery MACT 1 and other equipment 

leak standards, where the frequency of required monitoring 

varies depending on the percent of leaking valves identified 

during the previous monitoring period (see, for example, 40 CFR 

63.648(c) and 40 CFR 63.168(d)). The EPA requests comment on the 

minimum time period facilities should be required to conduct 

fenceline monitoring; the level of performance, in terms of 

monitored fenceline concentrations, that would enable a facility 

to discontinue use of fenceline monitors or reduce the frequency 

of data collection and reporting; and any adjustments to the 

optical gas imaging camera requirements that would be necessary 

in conjunction with such changes to the fenceline monitoring 

requirements. 

i. Delayed Coking Units 

As noted in section IV.A of this preamble, we are 

soliciting comments on the need to establish MACT standards for 

DCU under CAA section 112(d)(2) and (3). Even if we were to 

assume that there is already an applicable MACT standard for 

DCU, a technology review of this emission source, as prescribed 
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under CAA section 112(d)(6), would lead us to propose a 

depressurization limit of 2 psig because of technology 

advancements since the MACT standards were originally issued and 

because it is cost effective. Industry representatives have 

pointed out that Refinery NSPS Ja requires DCU at new and 

modified sources to depressure to 5 psig, and they have 

indicated that EPA should not require a lower depressurization 

limit under a CAA section 112(d)(6) technology review. Further, 

industry representatives also provided summary-level information 

(available in Docket ID Number EPA-HQ-OAR-2010-0682 as 

correspondence from API entitled Coker Vent Potential Release 

Limit Preliminary Emission, Cost and Cost Effectiveness 

Estimates) on costs to depressure to 5 psig versus 2 psig. While 

the cost information does not show large differences for any 

particular facility to depressure at 5 psig versus 2 psig, the 

information does show a large range in potential costs between 

refineries. At this time, we do not have the detailed, refineryspecific cost breakdowns to compare against our cost 

assumptions, which were derived from data obtained for a 

facility that did install the necessary equipment to meet a 2 

psig limit. We also do not have detailed information on the 

design and operation of the DCU in industry’s cost study to 

evaluate whether there are any differences that would warrant 

subcategories. We solicit information on designs, operational 
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factors, detailed costs and emissions data for DCU, and we 

specifically solicit comments on what should be the appropriate 

DCU depressurization limit if we were to adopt such a 

requirement pursuant to CAA section 112(d)(6) rather than 

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

2. Refinery MACT 2 – 40 CFR Part 63, Subpart UUU 

The Refinery MACT 2 source category regulates HAP emissions 

from FCCU, CRU and SRU process vents. Criteria pollutant 

emissions from FCCU and SRU are regulated under 40 CFR part 60, 

subparts J and Ja (Refinery NSPS J and Refinery NSPS Ja, 

respectively). We conducted a technology review of Refinery NSPS 

J emission limits from 2005 to 2008 and promulgated new 

standards for FCCU and SRU (among other sources) in Refinery 

NSPS Ja on June 24, 2008 (73 FR 35838). Our current technology 

review of Refinery MACT 2 relies upon, but is not limited to, 

consideration of this recent technology review of Refinery NSPS 

J for FCCU and SRU. 

a. FCCU Process Vent 

The FCCU has one large atmospheric vent, the coke burn-off 

exhaust stream for the unit’s catalyst regenerator. HAP 

emissions from this FCCU process vent include metal HAP 

associated with entrained catalyst particles and organic HAP, 

mostly by-products of incomplete combustion from the coke burnoff process. As the control technologies associated with each of 
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these classes of pollutants are very different, the controls 

associated with each of these classes of pollutants are 

considered separately. 

Metal HAP emission controls. The current Refinery MACT 2 

includes several different compliance options, some based on PM 

as a surrogate for total metal HAP and some based on nickel (Ni) 

as a surrogate for total metal HAP. Refinery NSPS J was the 

basis of the PM emission limits and the metal HAP MACT floor in 

Refinery MACT 2. Refinery NSPS J limits PM from FCCU catalyst 

regeneration vents to 1.0 gram particulate matter per kilogram 

(g PM/kg) of coke burn-off, with an additional incremental PM 

allowance for liquid or solid fuel burned in an incinerator, 

waste heat boiler, or similar device. Refinery MACT 2 states 

that FCCU subject to Refinery NSPS J PM emission limits are 

required to demonstrate compliance with Refinery NSPS J PM 

emission limits as specified in Refinery NSPS J. As provided in 

Refinery NSPS J, ongoing compliance with the PM emission limits 

is determined by compliance with a 30-percent opacity limit, 

except for one 6-minute average per hour not to exceed 60-

percent opacity. FCCU not subject to Refinery NSPS J may elect 

to comply with the FCCU PM provisions in Refinery NSPS J. 

Alternatively, they may comply with a 1.0 g PM/kg of coke burnoff emission limit in Refinery MACT 2 (with no provision for an 

additional incremental PM allowance for liquid or solid fuel 
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burned in an incinerator, waste heat boiler, or similar device). 

Compliance with this limit in Refinery MACT 2 is demonstrated by 

either a 1-hour average site-specific opacity limit using a 

continuous opacity monitoring system (COMS) or APCD-specific 

daily average operating limits using CPMS. 

Refinery MACT 2 also includes two emission limit 

alternatives that use Ni, rather than PM, as the surrogate for 

metal HAP. The first of these Ni alternatives is a mass emission 

limit of 13 grams Ni per hour; the second nickel alternative is 

an emission limit of 1.0 milligrams Ni per kilogram of coke 

burn-off. Compliance with the Ni emission limits in Refinery 

MACT 2 is demonstrated by either a daily average site-specific 

Ni operating limit (using a COMS and weekly determination of Ni 

concentration on equilibrium FCCU catalyst), or APCD-specific 

daily average operating limits using CPMS and monthly average Ni 

concentration operating limit for the equilibrium FCCU catalyst. 

Under Refinery MACT 2, an initial performance demonstration 

(source test) is required to show that FCCU is compliant with 

the emission limits selected by the refinery owner or operator. 

No additional performance test is required for facilities 

already complying with Refinery NSPS J. The performance test is 

a one-time requirement; additional performance tests are only 

required if the owner or operator elects to establish new 

operating limits, or to modify the FCCU or control system in 
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such a manner that could affect the control system’s 

performance. 

Under the review for Refinery NSPS J, we conducted a 

literature review as well as a review of the EPA’s refinery 

settlements and state and local regulations affecting refineries 

to identify developments in practices, processes and control 

technologies to reduce PM emissions from refinery sources (see 

Summary of Data Gathering Efforts: Emission Control and Emission 

Reduction Activities, August 19, 2005, and Review of PM Emission 

Sources at Refineries, December 20, 2005, Docket Item Number 

EPA-HQ-OAR-2007-0011-0042). At that time, we identified 

regulations for PM from FCCU that were more stringent than the 

Refinery NSPS J requirements for PM, and we promulgated more 

stringent PM limits in Refinery NSPS Ja. Refinery NSPS Ja limits 

PM from FCCU catalyst regeneration vents to 1.0 g PM/kg of coke 

burn-off for modified or reconstructed FCCU, with no incremental 

allowance for PM-associated liquid or solid fuels burned in a 

post-combustion device. Furthermore, an emission limit of 0.5 g 

PM/kg of coke burn-off was established for FCCU constructed 

after May 14, 2007. 

In addition, the Refinery NSPS J review identified 

improvements in APCD monitoring practices, which were included 

in the Refinery NSPS Ja standards. Refinery NSPS J includes a 

30-percent opacity limit as the only ongoing monitoring 
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requirements for PM from the FCCU. This 30-percent opacity limit 

has shown to be lenient and high in comparison to recent federal 

rules that have included more stringent opacity limits (e.g., 40 

CFR part 60, subpart Db with 20-percent opacity), and recent 

state and local agency rules that omit opacity limits altogether 

in favor of operating limits for the emission control systems. 

Based on the Refinery NSPS J review, Refinery NSPS Ja does not 

include an opacity limit, but includes updated and more 

appropriate monitoring approaches, such as requiring bag leak 

detectors (BLD) for fabric filter control systems, and requiring 

CPMS for electrostatic precipitators (ESP) and wet scrubbers. 

Additionally, Refinery NSPS Ja includes an option to measure PM 

emissions directly using a PM CEMS. For this monitoring 

alternative, a direct PM concentration limit (equivalent to the 

conventional FCCU PM emission limit in terms of g PM/kg of coke 

burn-off) is included in the rule. Finally, in our review for 

Refinery NSPS J, we noted that, even with improved monitoring 

methods, periodic source testing is needed to verify the 

performance of the control system as it ages. In Refinery NSPS 

Ja, annual performance demonstrations are required for affected 

FCCU. The Refinery NSPS Ja standards for PM from FCCU reflect 

the latest developments in practices, processes and control 

technologies. In our current review of Refinery MACT 2, we did 

not identify any other developments in practices, processes or 
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control technologies since we promulgated Refinery NSPS Ja in 

2008. 

The conclusions of the technology review conducted for the 

Refinery NSPS J PM emission limits are directly applicable to 

Refinery MACT 2; the initial Refinery MACT 2 rule recognized 

this by providing that compliance with Refinery NSPS J would 

also be compliance with Refinery MACT 2. We considered the 

impacts of proposing to revise Refinery MACT 2 to incorporate 

the developments in monitoring practices and control 

technologies reflected in the Refinery NSPS Ja limits and 

monitoring provisions. 

As noted above, Refinery NSPS Ja includes a limit of 0.5 g 

PM/kg of coke burn-off for newly constructed sources. There 

would be no costs associated with requiring the lower emission 

limit of 0.5 g PM/kg of coke burn-off for Refinery MACT 2 new 

sources under CAA section 112(d)(6) because these sources would 

already be required to comply with that limit under Refinery 

NSPS Ja. Therefore, we are proposing that it is necessary 

pursuant to CAA section 112(d)(6) to revise Refinery MACT 2 to 

incorporate the Refinery NSPS Ja PM limit for new sources. 

We are also proposing to establish emission limits and 

monitoring requirements in Refinery MACT 2 that are consistent 

with those in Refinery NSPS Ja. This option would not impose any 

additional cost on sources already subject to Refinery NSPS Ja. 
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We note that for facilities subject to Refinery NSPS J, this 

would not lead to duplicative or conflicting monitoring 

requirements because Refinery NSPS J already includes a 

provision that allows affected facilities subject to Refinery 

NSPS J to instead comply with the provisions in Refinery NSPS Ja 

(see 40 CFR 60.100(e)). 

In addition, in conjunction with our proposal to revise 

Refinery MACT 2 to include the more stringent requirements in 

Refinery NSPS Ja, we are proposing to remove the less stringent 

compliance option of meeting the requirements of Refinery NSPS 

J. As described previously, Refinery NSPS J includes an 

incremental PM emissions allowance for post-combustion devices 

and relies on a 30-percent opacity limit that is outdated and 

has been demonstrated to be ineffective at identifying 

exceedances of the 1.0 g PM/kg coke burn-off emissions limit. 

We also reviewed the compliance monitoring requirements for 

the Refinery MACT 2 PM and Ni-based emission limits. As 

described previously, Refinery MACT 2 includes operating limits 

based on APCD operating parameters or site-specific opacity 

limits. There are differences between the monitoring approaches 

in Refinery MACT 2 for these limits and Refinery NSPS Ja 

monitoring approaches for the NSPS PM limit, so we evaluated 

whether it is necessary, pursuant to CAA section 112(d)(6), to 
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revise the monitoring provisions in Refinery MACT 2 consistent 

with the requirements in Refinery NSPS Ja. 

The first significant difference is in the averaging times 

used for the different operating limits. Refinery NSPS Ja 

requires a 3-hour rolling average for the operating limits for 

parametric monitoring systems; Refinery MACT 2 includes daily 

averaging of the operating limits. Typically, the averaging time 

for operating limits is based on the duration of the performance 

test used to establish those operating limits. As the 

performance test duration is 3 hours (three 1-hour test runs) 

and compliance with the PM (or Ni) emission limit is based on 

the average emissions during this 3-hour period, the most 

appropriate averaging period for these operating limits is 3 

hours. Using a daily average could allow poor performance (i.e., 

control equipment for shorter periods (e.g., 3-hour averages 

that are higher than the PM emissions limit in Refinery NSPS 

Ja). For example, assume an operating limit developed from a 

performance test has a value of 1 and that values exceeding this 

level would suggest that the control system is not operating as 

well as during the performance test (i.e., potentially exceeding 

the PM emission limit). If the control system is run for 18 

hours operating at a level of 0.9 and 6 hours at a level of 1.2, 

the unit would be in compliance with the daily operating limit 

even though the unit may have 6 consecutive hours during which 
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the operating limit was exceeded. Reducing the averaging time 

does not impact the types of monitors required; it merely 

requires the owner or operator of the unit to pay more careful 

attention to the APCD operating parameters. We are proposing 

that it is necessary, pursuant to CAA section 112(d)(6), to 

incorporate the use of 3-hour averages rather than daily 

averages for parameter operating limits in Refinery MACT 2 for 

both the PM and Ni limits, because this is a cost-effective 

development in monitoring practice. 

The site-specific opacity operating limit for PM in 

Refinery MACT 2 (for units not electing to comply with Refinery 

NSPS J) has a 1-hour averaging period, but the Ni operating 

limits (which use opacity monitoring) have a 24-hour averaging 

period. These averaging periods are inconsistent with the 

duration of the performance test, which is over a 3-hour period. 

We are proposing, pursuant to CAA section 112(d)(6), to 

incorporate the use of 3-hour averages for the site-specific 

opacity operating limit and the Ni operating limits rather than 

daily averages because this is a cost-effective development in 

monitoring practice. 

We also compared the APCD-specific operating parameters 

used in Refinery MACT 2 to those that we promulgated for 

Refinery NSPS Ja. The Refinery NSPS Ja rule includes monitoring 

approaches that are not included in Refinery MACT 2. These 
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include the option of using PM CEMS and requiring BLD for fabric 

filter control systems. Adding a PM CEMS as an option for 

demonstrating compliance with the Refinery MACT 2 PM limit 

(similar to what is provided in Refinery NSPS Ja) would not 

impact the costs of complying with Refinery MACT 2 because 

sources can choose whether or not to adopt this monitoring 

method. With respect to BLD, there is only one refinery that 

currently uses a baghouse (fabric filter) to control emissions 

from its FCCU (although one additional unit has indicated that 

it has plans to install a fabric filter control within the next 

few years). Under the existing requirements in Refinery MACT 2 

(assuming that the FCCU currently operating with a fabric filter 

has not elected to comply with the Refinery NSPS J PM emission 

limit option), it is required to comply with a site-specific 

opacity operating limit. For new, reconstructed, or modified 

FCCU, Refinery NSPS Ja requires use of BLD. While we generally 

consider the BLD to be superior to opacity monitors for ensuring 

fabric filter control systems are operating efficiently, it is 

difficult to determine what, if any, increment in assurance that 

the unit is properly controlled would be achieved by requiring 

the one facility currently operating a fabric filter control 

system and complying with a site-specific opacity operating 

limit to switch from a COMS to BLD. Therefore, we are proposing 

that it is not necessary to require the one existing FCCU with a 
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fabric filter control system to switch from COMS to a BLD system 

because this would require additional monitoring equipment (with 

additional costs) and little to no associated increase in 

assurance that the unit is properly controlled. Although we are 

not proposing to require existing sources using a fabric filter 

to use BLD, we are proposing to include BLD as an option to 

COMS; owners or operators of FCCU using fabric filter-type 

control systems at existing sources can elect (but are not 

required) to use BLD in lieu of COMS and the site-specific 

opacity operating limit. 

The Refinery NSPS Ja monitoring requirements for ESP 

include CPMS for monitoring and recording the total power and 

the secondary current to the entire system. The current MACT 

requires monitoring voltage and secondary current or monitoring 

only the total power to the APCD. While these monitoring 

requirements are similar, we consider that the Refinery NSPS Ja 

requirements will provide improved operation of the ESP. As the 

monitors required to measure these parameters are a routine part 

of ESP installations, we project no additional costs for 

monitoring equipment. We expect that a new performance test 

would be needed to ensure that both total power and secondary 

current are recorded during the source test. As discussed later 

in this section, we are proposing to require ongoing performance 

tests regardless of the monitoring option, so we are not 
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projecting any additional costs specific to revising the 

monitoring requirements for ESP. Because the Refinery NSPS Ja 

monitoring and operating requirements for ESP are expected to 

provide improved performance of the APCD with no incremental 

costs, we propose that it is necessary, pursuant to CAA section 

112(d)(6), to incorporate the total power and the secondary 

current operating limits into Refinery MACT 2. 

Refinery NSPS Ja provides a specific monitoring alternative 

to pressure drop for jet ejector-type wet scrubbers or any other 

type of wet scrubbers equipped with atomizing spray nozzles. 

Owners or operators of FCCU controlled by these types of wet 

scrubbers can elect to perform daily checks of the air or water 

pressure to the spray nozzle rather than monitor pressure. 

Refinery MACT 2 currently excludes these types of control 

systems from monitoring pressure drop but includes no specific 

monitoring to ensure the jet ejectors or atomizing spray nozzle 

systems are properly operating. Since proper functioning of the 

jet ejectors or atomizing spray nozzles is critical to ensuring 

these control systems operate at the level contemplated by the 

MACT, some monitoring/inspection requirement of these components 

is necessary to ensure compliance with the FCCU PM or Ni 

emission limit. The owner or operator of a jet ejector-type wet 

scrubber or other type of wet scrubber equipped with atomizing 

spray nozzles should be performing routine checks of these 
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systems, such as the daily checks of the air or water pressure 

to the spray nozzles, as required in Refinery NSPS Ja. These 

daily checks are consistent with good operational practices for 

wet scrubbers and should not add significant burden to the FCCU 

wet scrubber owner or operator. For these reasons, we propose it 

is necessary to require owners or operators of a jet ejectortype wet scrubber or other type of wet scrubber equipped with 

atomizing spray nozzles to perform daily checks of the air or 

water pressure to the spray nozzles pursuant to CAA section 

112(d)(6). 

Finally, in our action promulgating Refinery NSPS Ja, we 

noted that, even with improved monitoring methods, periodic 

source testing is needed to verify the performance of the 

control system as it ages. In Refinery NSPS Ja, annual 

performance demonstrations are required for new sources. FCCU 

subject to Refinery MACT 2 as new sources would also be subject 

to Refinery NSPS Ja and would have to comply with the annual 

testing requirements in Refinery NSPS Ja. However, Refinery MACT 

2 does not include periodic performance tests for any FCCU. We 

considered adding an annual testing requirement for FCCU subject 

to Refinery MACT 2. The annual nationwide cost burden exceeds $1 

million per year and we project only modest improvement in 

control performance resulting from the performance 

demonstrations. We considered requiring FCCU performance tests 
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once every 5 years (i.e., once per title V permit period). The 

nationwide annual cost of this additional testing requirement 

for FCCU is projected to be, on average, $213,000 per year. We 

consider this to be a reasonable minimum frequency for which 

affected sources should demonstrate direct compliance with the 

FCCU emission limits and that this cost is reasonable. 

Therefore, we propose that it is necessary, pursuant to CAA 

section 112(d)(6), to require a performance test once every 5 

years for all FCCU under to Refinery MACT 2. 

Organic HAP. Refinery MACT 2 uses CO as a surrogate for 

organic HAP and establishes an emission limit of 500 ppmv CO 

(dry basis). Some FCCU, referred to as complete-combustion FCCU, 

employ excess oxygen in the FCCU regenerator and are able to 

meet this emission limit without the need for a post-combustion 

device. Other FCCU, referred to as partial-combustion FCCU, do 

not supply enough air/oxygen for complete combustion of the coke 

to CO2 and, therefore, produce a significant quantity of CO in 

the regenerator exhaust. Partial-combustion FCCU are typically 

followed by a post-combustion unit, commonly referred to as a CO 

boiler, to burn the CO in the regenerator exhaust in order to 

meet the 500 ppmv CO limit (and to recover useful heat from the 

exhaust stream). 

In our review of Refinery NSPS J, we conducted a review of 

state and local regulations affecting refineries to identify 
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control strategies to reduce CO emissions or VOC emissions from 

refinery sources (see Review of VOC Emission Sources at 

Refineries, December 14, 2005, Docket Item Number EPA-HQ-OAR2007-0011-0043). We also conducted a review of federal, state 

and local regulations affecting refineries to identify control 

strategies to reduce CO emissions from refinery sources (see 

Review of CO Emission Sources at Refineries, December 22, 2005, 

Docket Item Number EPA-HQ-OAR-2007-0011-0044). We did not 

identify any developments in practices, processes and control 

technologies to reduce CO or VOC emissions from FCCU as part of 

the review of Refinery NSPS J, and we have not identified any 

developments in practices, processes and control technologies 

for FCCU that would reduce organic HAP since promulgation of 

Refinery MACT 2. We are proposing that it is not necessary to 

revise the regulatory provisions for organic HAP in the current 

MACT standards for FCCU, pursuant to CAA section 112(d)(6). 

Inorganic HAP. As mentioned previously, Refinery MACT 2 

includes a CO emission limit of 500 ppmv. Although this limit is 

expressly provided as a limit addressing organic HAP emissions, 

this emission limit is also expected to limit the emissions of 

oxidizable inorganic HAP, such as HCN. That is, the CO 

concentration limit was developed as an indicator of complete 

combustion for all oxidizable pollutants typically found in 

exhaust gas from the FCCU regenerator operated in partial burn 
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mode. We note that HCN concentrations in FCCU regenerator 

exhaust with high CO levels also have high HCN concentrations 

and that HCN concentrations in the regenerator exhaust from 

complete-combustion FCCU (those meeting the 500 ppmv CO limit 

without the need for a post-combustion device) are much lower 

than those from partial burn FCCU prior to a post-combustion 

device. Thus, we consider that the CO emission limit also acts 

as a surrogate for the control of oxidizable inorganic HAP, such 

as HCN. 

The source test data from the ICR effort revealed that HCN 

emissions from FCCU are greater than previous tests indicated, 

particularly for complete-combustion FCCU. The increase in HCN 

emissions was observed at units meeting lower NOX emission 

limits, which have recently been required by consent decrees, 

state and local requirements and Refinery NSPS Ja. The higher 

HCN emissions from complete-combustion FCCU appear to be 

directly related to operational changes made in efforts to meet 

these lower NOX emission limits (e.g., reduced excess oxygen 

levels in the regenerator and reduced regenerator bed 

temperatures). These higher HCN emissions were only observed in 

complete-combustion FCCU; FCCU that operated in partial burn 

mode followed by a CO boiler or similar post-combustion device 

had significantly lower HCN emissions subsequent to the postcombustion device. 
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Based on our review of the available ICR data and the 

technologies used in practice, we considered establishing 

specific emission limits for HCN. In order to comply with 

emission limits for HCN, owners or operators of completecombustion FCCU would either have to operate their FCCU 

regenerator at slightly higher temperatures and excess oxygen 

concentrations (to limit the formation of HCN in the 

regenerator) or employ a post-combustion device or thermal 

oxidizer to destroy HCN exhausted from the FCCU regenerator. 

However, each of these options comes with significant secondary 

energy and environmental impacts. First, both of these control 

strategies would yield a significant increase in NOX emissions. 

We anticipate that most FCCU owners or operators would have to 

install a selective catalytic reduction (SCR) system to meet 

their NOX emission limits, if applicable. Operation of the SCR 

would have energy impacts and may have additional secondary PM2.5

impacts (associated with ammonia slip from the SCR). We expect 

that modifying the regenerator operating characteristics is the 

most cost-effective option, although installing and using a 

thermal oxidizer may be necessary, depending on the operational 

characteristics of the regenerator and the HCN control 

requirement. Using a thermal oxidizer to treat FCCU regenerator 

exhaust, a gas stream that has limited heating value (due to the 

already low CO concentrations) would be much more expensive and 
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would have additional energy and secondary impacts associated 

with the auxiliary fuel needed for the device, as compared to 

modifying regenerator operating conditions. 

We first performed a screening analysis of the impacts of 

making only operational changes to the FCCU with the highest HCN 

concentrations. If this control option is not cost effective for 

these FCCU, it would not be cost effective for units that have 

lower HCN concentrations and lower HCN emissions. Similarly, if 

operating changes in the FCCU regenerator alone are not cost 

effective, then we can assume that installing a thermal oxidizer 

to achieve this same level of HCN emission reductions would also 

not be cost effective. We calculated the cost of changing the 

regenerator parameters and adding an SCR for the FCCU with the 

highest HCN emissions rate reported in the ICR, which is an 

annual emissions rate of 460 tpy. This is also the largest FCCU 

in operation in the United States and its territories. Based on 

the size of this unit, we project that an SCR would be expected 

to cost approximately $13-million and have annualized costs of 

approximately $4.0-million/yr. Thus, if the HCN emissions can be 

reduced by 95 percent, the cost effectiveness would be 

approximately $9,000 per ton of HCN. A smaller FCCU had similar 

HCN concentrations and annual HCN emissions of 141 tpy. Based on 

the size of this unit, we project an SCR would be expected to 

cost approximately $7-million and have annualized costs of 
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approximately $1.5-million/yr. Assuming a 95-percent reduction 

in HCN emissions, the cost effectiveness would be approximately 

$11,000 per ton of HCN. The second-highest emitting FCCU was 

larger than this unit, but had lower HCN concentrations. This 

third unit had emissions of 184 tpy. Based on the size of this 

unit, we expect that an SCR would cost approximately $9-million 

and have annualized costs of approximately $2.2-million/yr. 

Assuming a 95-percent reduction in HCN emissions, the cost 

effectiveness would be approximately $12,600 per ton of HCN. 

These costs are for the FCCU with the largest HCN emissions 

and the lowest control cost (assuming operational changes alone 

are insufficient to significantly reduce HCN emissions), and the 

average cost effectiveness for these units exceeds $10,000 per 

ton HCN emissions reduced. Based on the economies of scale and 

considering lower HCN concentrations for all other units, the 

costs per ton of HCN removed for a nationwide standard would be 

higher. If a post-combustion device is needed to achieve a 

specific HCN emissions limit, the costs would be even higher. 

Based on the cost, secondary energy and secondary 

environmental impacts of an HCN emission limit beyond that 

achieved by the CO emission limit as a surrogate for HCN, we are 

proposing, at this time, that it is not necessary, pursuant to 

CAA section 112(d)(6), to revise the MACT standard to establish 

a separate HCN standard. As our understanding of the mechanisms 
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of HCN and NOX formation improves and as catalyst additives 

evolve, it may be possible to achieve both low NOX and low HCN 

emissions without the use of an SCR and/or post-combustion 

controls. However, at this time our test data indicate an 

inverse correlation between these two pollutants. The three 

facilities with the highest HCN concentrations were the 

facilities with the lowest NOX concentrations, all of which were 

below 20 ppmv (dry basis, 0-percent excess air) during the 

performance tests. While a 20 ppmv NOX limit may be achievable, 

we anticipate that further reducing the NOX new source 

performance limits for FCCU would either increase PM2.5 secondary 

emissions (via the use of an SCR and its associated ammonia 

slip) or further increase HCN emissions (if combustion controls 

are used). 

b. CRU Process Vents 

A CRU is designed to reform (i.e., change the chemical 

structure of) naphtha into higher-octane aromatics. The 

reforming process uses a platinum or bimetal (e.g., platinum and 

rhenium) catalyst material. Small amounts of coke deposit on the 

catalyst during the catalytic reaction and this coke is burned 

off the catalyst to regenerate catalyst activity. There are 

three types of CRU classified by differences in how the units 

are designed and operated to effect reforming catalyst 

regeneration. Semi-regenerative reforming is characterized by 
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shutting down the reforming unit at specified intervals, or at 

the operator’s convenience, for in situ catalyst regeneration. 

Semi-regenerative CRU typically regenerate catalyst once every 8 

to 18 months, with the regeneration cycle lasting approximately 

2 weeks. Cyclic-regeneration reforming is characterized by 

continuous or continual reforming operation with periodic (but 

frequent) regeneration of catalyst in situ by isolating one of 

the reactors in the series, regenerating the catalyst, then 

returning the reactor to the reforming operation. The 

regeneration of the catalyst in a single reactor may occur 

numerous times per year (e.g., once a month), and the 

regeneration of each reactor may take 3 to 5 days to complete. 

Continuous-regeneration reforming units use moving catalyst bed 

reactors situated vertically (which is why they are often 

referred to as platforming units). Catalyst flows down the 

series of reactors. At the bottom of the last reactor, catalyst 

is continually isolated and sent to a special regenerator. After 

regeneration, the regenerated catalyst is continually fed to the 

first (top) reactor. Thus, continuous-regeneration reforming 

units are characterized by continuous-reforming operation along 

with continuous-regeneration operation. 

The catalytic reforming reaction is performed in a closed 

reactor system; there are no emissions associated with the 

processing portion of the CRU. There is a series of emission 
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points associated with the CRU catalyst regenerator. Regardless 

of the type of CRU used, there is a series of steps conducted to 

effect catalyst regeneration. These steps are: (1) initial 

depressurization/purge; (2) coke burn-off; (3) catalyst 

rejuvenation; and (4) reduction/final purge. The primary 

emissions during the depressurization/purge cycle are organic 

HAP. Inorganic HAP, predominately HCl and chlorine, are emitted 

during the coke burn-off and rejuvenation cycles. The reduction 

purge is mostly inert materials (nitrogen and/or hydrogen). 

Refinery MACT 2 contains organic HAP emission limits for the 

depressurization/purge cycle (purging prior to coke-burn-off) 

and inorganic HAP emission limits for the coke burn-off and 

catalyst rejuvenation cycles. Our technology review, summarized 

below, considers each of these emission limits separately. For 

additional details on the technology review for CRU, see 

Technology Review Memorandum for Catalytic Reforming Units at 

Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682. 

Organic HAP. Refinery MACT 2 requires the owner or operator 

to comply with either a 98-percent reduction of TOC or nonmethane TOC, or an outlet concentration of 20 ppmv or less (dry 

basis, as hexane, corrected to 3-percent oxygen). The emission 

limits for organic HAP for the CRU do not apply to emissions 

from process vents during depressuring and purging operations 

when the reactor vent pressure is 5 psig or less. Control 
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technologies used include directing the purge gas directly to 

the CRU process heater to be burned, recovering the gas to the 

facility’s fuel gas system, or venting to a flare or other APCD. 

The pressure limit exclusion was provided to allow atmospheric 

venting of the emissions when the pressure of the vessel fell 

below that needed to passively direct the purge gas to the APCD 

(most commonly the CRU process heater or flare). 

We did not identify any developments in practices, 

processes and control technologies for reducing organic HAP 

emissions from CRU. However, as noted in section IV.A.2 of this 

preamble, we are proposing to amend the pressure limit exclusion 

pursuant to CAA sections 112(d)(2) and (3) to clarify that this 

limit only applies during passive vessel depressuring. Also, as 

described in section IV.A.3 of this preamble, we are proposing 

revisions to Refinery MACT 1 and 2, pursuant to CAA sections 

112(d)(2) and (3), to ensure flares used as APCD meet the 

required destruction efficiency, which includes flares used to 

control the organic HAP emissions from the CRU 

depressurization/purge vent streams. 

Inorganic HAP. Refinery MACT 2 uses HCl as a surrogate for 

inorganic HAP during the coke burn-off and rejuvenation cycles. 

Refinery MACT 2 requires owners or operators of existing semiregenerative CRU to reduce uncontrolled emissions of HCl by 92-

percent by weight or to a concentration of 30 ppmv (dry basis, 
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corrected to 3-percent oxygen) during the coke burn-off and 

rejuvenation cycles. Owners or operators of new semiregenerative CRU, new or existing cyclic CRU, or new or existing 

continuous CRU are required to reduce uncontrolled emissions of 

HCl by 97-percent by weight or to a concentration of 10 ppmv 

(dry basis, corrected to 3-percent oxygen) during the coke burnoff and rejuvenation cycles. Technologies used to achieve these 

limits include caustic spray injection, wet scrubbers, and solid 

adsorption systems. We conducted a technology review for CRU by 

reviewing the ICR responses and scientific literature. We did 

not identify any developments in practices, processes and 

control technologies for reducing inorganic HAP emissions from 

CRU. We are proposing that it is not necessary to revise the 

current inorganic HAP MACT standards for CRU, pursuant to CAA 

section 112(d)(6). 

c. SRU Process Vents 

Most sulfur recovery plants at petroleum refineries use the 

Claus reaction to produce elemental sulfur. In the Claus 

reaction, two moles of hydrogen sulfide (H2S) react with one mole 

of SO2 in a catalytic reactor to form elemental sulfur and water 

vapor. Prior to the Claus reactors, one-third of the H2S in the 

sour gas feed to the sulfur plant must be oxidized to SO2 to have 

the correct proportion of H2S and SO2 for the Claus reaction. 

This oxidation step is performed in the “Claus burner.” The 
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remaining gas stream, after the elemental sulfur is condensed, 

is referred to as “tail gas.” HAP emissions in tail gas from 

sulfur recovery plants are predominately COS and CS2, which are 

primarily formed as side reactions of the Claus process. 

Refinery MACT 2 contains HAP standards for SRU that were 

based on the Refinery NSPS J SO2 and reduced sulfur compounds 

emission limits. Refinery NSPS J includes an emission limit of 

300 ppmv reduced sulfur compounds for a reduction control system 

not followed by an incinerator, and an emission limit of 250 

ppmv SO2 (dry basis, 0-percent excess air) for oxidative control 

systems or reductive control systems followed by incineration. 

These Refinery NSPS J limits apply only to Claus sulfur recovery 

plants with a sulfur recovery capacity greater than 20 long tons 

per day (LTD). These emission limits effectively required sulfur 

recovery plants to achieve 99.9-percent sulfur recovery. 

Refinery MACT 2 defines SRU as a process unit that recovers 

elemental sulfur from gases that contain reduced sulfur 

compounds and other pollutants, usually by a vapor-phase 

catalytic reaction of sulfur dioxide and hydrogen sulfide (see 

40 CFR 63.1579). This definition specifically excludes sulfur 

recovery processes that do not recover elemental sulfur, such as 

the LO-CAT II process, but does not necessarily limit 

applicability to Claus SRU. Refinery MACT 2 requires owners or 

operators of an SRU that is subject to Refinery NSPS J to meet 
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the Refinery NSPS J limits. Owners or operators of an SRU that 

is not subject to Refinery NSPS J can elect to meet the emission 

limits in Refinery NSPS J or meet a reduced sulfur compound 

limit of 300 ppmv (dry basis, 0-percent excess air) regardless 

of the type of control system or the presence of an incinerator. 

Unlike Refinery NSPS J, Refinery MACT 2 does not have a capacity 

applicability limit, so this 300 ppmv reduced sulfur compound 

limit is applicable to all SRU (as that term is defined), 

regardless of size. 

Upon completion of our technology review for Refinery NSPS 

J, we promulgated Refinery NSPS Ja, which includes new 

provisions for the sulfur recovery plant. First, Refinery NSPS 

Ja limits are now applicable to all sulfur recovery plants, not 

just Claus sulfur recovery plants. Second, emission limits were 

added for sulfur recovery plants with a capacity of 20 LTD or 

less, to require new, small sulfur recovery plants to achieve a 

target sulfur recovery efficiency of 99-percent. These limits 

are a factor of 10 higher than the emission limits for larger 

sulfur recovery plants (i.e., 3,000 ppmv reduced sulfur 

compounds for a reduction control system not followed by an 

incinerator and 2,500 ppmv SO2 for oxidative control systems or 

reductive control systems followed by incineration). Refinery 

NSPS J did not include emission limits for these smaller sulfur 

recovery plants. Third, new correlations were introduced to 
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provide equivalent emission limits for systems that use oxygenenriched air in their Claus burner. 

The technology review conducted for Refinery NSPS J focused 

on SO2 emissions. Under our current technology review for 

Refinery MACT 2, we considered the developments in practices, 

processes or control technologies identified in the Refinery 

NSPS J technology review as they pertain to HAP emissions and 

the existing Refinery MACT 2 requirements. 

We considered the new Refinery NSPS Ja limits for small 

sulfur recovery plants. While Refinery NSPS Ja establishes 

criteria pollutant emission limits for these smaller sulfur 

recovery plants that were previously unregulated for such 

emissions, these sources are already covered under Refinery MACT 

2. Refinery MACT 2 requires these SRU to meet a 300 ppmv reduced 

sulfur compound limit, which is more stringent than the 3,000 

ppmv limit established in Refinery NSPS Ja. 

We also considered the new correlations in Refinery NSPS Ja 

for SRU that use oxygen-enriched air in their Claus burner. In 

the technology review under Refinery NSPS J, we identified a 

change in practice in the operation of certain Claus SRU. At the 

time we promulgated Refinery MACT 2, we assumed that all units 

were using ambient air in the Claus burner, and we established 

the same emission limits as in Refinery NSPS J. Now, however, we 

understand that some facilities are using oxygen-enriched air. 
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This practice lowers the amount of inert gases introduced into 

the SRU and improves operational performance and reliability of 

the sulfur recovery plant. Air is approximately 20.9 percent by 

volume oxygen and 79.1-percent inert gases (predominately 

nitrogen with 1-percent argon and other inert gases). The inert 

gases introduced in the Claus burner become a significant 

portion of the overall tail gas flow. When oxygen enrichment is 

used in the Claus burner, there are fewer inert gases in the 

tail gas and a lower overall tail gas flow rate. The same molar 

flow rate of reduced sulfur compounds will be present in the 

tail gas, but without the additional flow of inerts from the 

ambient air, the concentration of the reduced sulfur compounds 

(or SO2) in the tail gas is higher. 

In developing Refinery NSPS Ja, we included a correlation 

equation that facilities can use to adjust the concentration 

limit based on the enriched-oxygen concentration used in the 

Claus burner. This equation is designed to allow the same mass 

of emissions for these units as is allowed for units using only 

ambient air. That is, the emission equation establishes a 

concentration limit for units using oxygen enrichment so that 

the mass emissions from the unit do not exceed the mass 

emissions allowed under the 250 ppmv SO2 (or 300 ppmv reduced 

sulfur compounds) emissions limits in Refinery NSPS J and in 

Refinery MACT 2. The new equation in Refinery NSPS Ja for large 
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sulfur recovery plants (those with sulfur recovery greater than 

20 LTD) provides an equivalent mass emissions rate of reduced 

sulfur HAP from the SRU as is currently required in Refinery 

MACT 2 while allowing a practice that improves the operational 

reliability of the unit. There are no costs to providing this 

option for units using oxygen-enriched air because: (1) it is an 

option that the owner or operator can elect to meet instead of 

the existing 250 ppmv SO2 emissions limit and (2) owners or 

operators of SRU that use oxygen-enriched air are expected to 

already routinely monitor the inlet air oxygen concentration for 

operational purposes. Therefore, we are proposing that it is 

necessary, pursuant to CAA section 112(d)(6), to amend Refinery 

MACT 2 sulfur recovery requirements to include this equation 

that addresses the use of oxygen-enriched air as a development 

in practice in SRU process operations. 

The emission limits for large sulfur recovery plants (those 

with sulfur recovery greater than 20 LTD) in Refinery NSPS Ja 

are equivalent to those in Refinery MACT 2. We are proposing to 

allow owners or operators subject to Refinery NSPS Ja limits for 

sulfur recovery plants with a capacity greater than 20 LTD to 

comply with Refinery NSPS Ja as a means of complying with 

Refinery MACT 2. 
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We have not identified any additional developments in 

practices, processes or control technologies for HAP from SRU 

since development of Refinery NSPS Ja. 

C. What are the results of the risk assessment and analyses? 

1. Inhalation Risk Assessment Results 

Table 10 of this preamble provides an overall summary of 

the results of the inhalation risk assessment. 

Table 10. Petroleum Refining Source Sector Inhalation Risk 

Assessment Results 

Maximum 

Individual 

Cancer Risk 

(-in-1 million)a

Estimated 

Population at 

Increased Risk 

Levels of 

Cancer 

Estimated 

Annual Cancer 

Incidence 

(cases per 

year) 

Maximum 

Chronic 

Non-cancer 

TOSHIb

Maximum 

Screening 

Acute Noncancer HQc

Actual Emissions 

60 

≥ 1-in-1 

million: 

5,000,000 

≥ 10-in-1 

million: 

100,000 

≥ 100-in-1 

million: 0 

0.3 0.9 

HQREL = 5 

(Nickel 

Compounds) 

Allowable Emissionsd

100 

≥ 1-in-1 

million: 

7,000,000e

≥ 10-in-1 

million: 

Greater than 

90,000e

≥ 100-in-1 

million: 0 

0.6 1 - 

a

 Estimated maximum individual excess lifetime cancer risk due to HAP 

emissions from the source category. 

b

 Maximum TOSHI. The target organ with the highest TOSHI for the Petroleum 

Refining source sector is the thyroid system for actual emissions and the 

neurological system for allowable emissions. 
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 The maximum off-site HQ acute value of 5 is driven by emissions of nickel 

from CCU. See section III.A.3 of this preamble for explanation of acute doseresponse values. Acute assessments are not performed on allowable emissions 

because of a lack of detailed hourly emissions data. However, because of the 

conservative nature of the actual annual to actual hourly emissions rate 

multiplier, allowable acute risk estimates will be comparable to actual acute 

estimates. 

d

 The development of allowable emission estimates can be found in the memo 

entitled Refinery Risk Estimates for Modeled “Allowable” Emissions, which can 

be found in Docket ID Number EPA-HQ-OAR-2010-0682. 

e

 Population risks from allowable emissions were only calculated for the model 

plant emissions (REM) approach. For the 138 facilities modeled using the 

modeled plant approach the population risks greater than 10-in-1 million was 

estimated to be 90,000. If we consider the second approach to determining 

allowable emissions (combined the results of the actual and REM emissions 

estimates) we estimate that the allowable population risks greater than 10-

in-1 million would be greater than 90,000 people. Further, the number of 

people above 1-in-1 million would also be higher than the 7,000,000 estimated 

using the REM model. 

The inhalation risk modeling performed to estimate risks 

based on actual emissions relied primarily on emissions data 

from the ICR, updated based on our quality assurance review as 

described in section III.A.1 of this preamble. 

The results of the chronic baseline inhalation cancer risk 

assessment indicate that, based on estimates of current actual 

emissions, the maximum individual lifetime cancer risk (MIR) 

posed by the refinery source category is 60-in-1 million, with 

benzene and naphthalene emissions from equipment leaks and 

storage tanks accounting for 98 percent of the MIR risk. The 

total estimated cancer incidence from refinery emission sources 

based on actual emission levels is 0.3 excess cancer cases per 

year or one case in every 3.3 years, with emissions of 

naphthalene, benzene, and 2-methylnaphthalene contributing 22 
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percent, 21 percent and 13 percent, respectively, to this cancer 

incidence. In addition, we note that approximately 100,000 

people are estimated to have cancer risks greater than 10-in-1 

million, and approximately 5,000,000 people are estimated to 

have risks greater than 1-in-1 million as a result of actual 

emissions from these source categories. When considering the 

MACT-allowable emissions, the maximum individual lifetime cancer 

risk is estimated to be up to 100-in-1 million, driven by 

emissions of benzene and naphthalene from refinery fugitives 

(e.g., storage tanks, equipment leaks and wastewater) and the 

estimated cancer incidence is estimated to be 0.6 excess cancer 

cases per year or one excess case in every 1.5 years. Greater 

than 90,000 people were estimated to have cancer risks above 10-

in-1 million and approximately 7,000,000 people were estimated 

to have cancer risks above 1-in-1 million considering allowable 

emissions from all petroleum refineries. 

The maximum modeled chronic non-cancer HI (TOSHI) value for 

the source sector based on actual emissions was estimated to be 

less than 1. When considering MACT-allowable emissions, the 

maximum chronic non-cancer TOSHI value was estimated to be about 

1. 

2. Acute Risk Results 

Our screening analysis for worst-case acute impacts based 

on actual emissions indicates the potential for five pollutants 
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– acetaldehyde, acrolein, arsenic, benzene and nickel - to 

exceed an HQ value of 1, with an estimated worst-case maximum HQ 

of 5 for nickel based on the REL values. This REL occurred at a 

facility reporting nickel emissions from the FCCU vent. One 

hundred thirty-six of the 142 petroleum refineries had an 

estimated worst-case HQ less than or equal to 1 for all HAP; 

except for the one facility that had an estimated REL of 5, the 

remaining 5 refineries with an REL above 1 had an estimated 

worst-case HQ less than or equal to 3. 

To better characterize the potential health risks 

associated with estimated worst-case acute exposures to HAP, and 

in response to a key recommendation from the SAB’s peer review 

of EPA’s RTR risk assessment methodologies, we examine a wider 

range of available acute health metrics than we do for our 

chronic risk assessments. This is in acknowledgement that there 

are generally more data gaps and inconsistencies in acute 

reference values than there are in chronic reference values. By 

definition, the acute CalEPA REL represents a health-protective 

level of exposure, with no risk anticipated below those levels, 

even for repeated exposures; however, the health risk from 

higher-level exposures is unknown. Therefore, when a CalEPA REL 

is exceeded and an AEGL-1 or ERPG-1 level is available (i.e., 

levels at which mild effects are anticipated in the general 

public for a single exposure), we have used them as a second 
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comparative measure. Historically, comparisons of the estimated 

maximum off-site 1-hour exposure levels have not been typically 

made to occupational levels for the purpose of characterizing 

public health risks in RTR assessments. This is because 

occupational ceiling values are not generally considered 

protective for the general public since they are designed to 

protect the worker population (presumed healthy adults) for 

short-duration increases in exposure (less than 15 minutes). As 

a result, for most chemicals, the 15-minute occupational ceiling 

values are set at levels higher than a 1-hour AEGL-1, making 

comparisons to them irrelevant unless the AEGL-1 or ERPG-1 

levels are also exceeded. Such is not the case when comparing 

the available acute inhalation health effect reference values 

for some of the pollutants considered in this analysis. 

The worst-case maximum estimated 1-hour exposure to 

acetaldehyde outside the facility fence line for the source 

categories is 1 mg/m3

. This estimated worst-case exposure exceeds 

the 1-hour REL by a factor of 2 (HQREL=2) and is well below the 

1-hour AEGL-1 (HQAEGL-1=0.01) and the ERPG-1 (HQERPG-1=0.05). 

The worst-case maximum estimated 1-hour exposure to 

acrolein outside the facility fence line for the source 

categories is 0.005 mg/m3

. This estimated worst-case exposure 

exceeds the 1-hour REL by a factor of 2 (HQREL=2) and is below 

the 1-hour AEGL-1 (HQAEGL-1=0.1) and the ERPG-1 (HQERPG-1=0.04). 
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The worst-case maximum estimated 1-hour exposure to nickel 

compounds outside the facility fence line for the source 

categories is 0.001 mg/m3

. This estimated worst-case exposure 

exceeds the 1-hour REL by a factor of 5 (HQREL=5). There are no 

AEGL, ERPG or short-term occupational values for nickel to use 

as comparison to the acute 1-hour REL value. 

The worst-case maximum estimated 1-hour exposure to arsenic 

compounds outside the facility fence line for the source 

categories is 0.0004 mg/m3

. This estimated worst-case exposure 

exceeds the 1-hour REL by a factor of 2 (HQREL=2). There are no 

AEGL, ERPG or short-term occupational values for arsenic to use 

as comparison to the acute 1-hour REL value. 

The maximum estimated 1-hour exposure to benzene outside 

the facility fence line is 2.7 mg/m3

. This estimated exposure 

exceeds the REL by a factor of 2 (HQREL=2), but is significantly 

below both the 1-hour ERPG-1 and AEGL-1 value (HQ ERPG-1 (or 

AEGL-1) = 0.02). This exposure estimate neither exceeds the 

AEGL-1/ERPG-1 values, nor does it exceed workplace ceiling level 

guidelines designed to protect the worker population for shortduration exposure (less than 15 minutes) to benzene, as 

discussed below. The occupational short-term exposure limit 

(STEL) standard for benzene developed by the Occupational Safety 

and Health Administration is 16 mg/m3

, “as averaged over any 15-
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minute period.”33 Occupational guideline STEL for exposures to 

benzene have also been developed by the American Conference of 

Governmental Industrial Hygienists (ACGIH)34 for less than 15 

minutes35 (ACGIH threshold limit value (TLV) – STEL value of 8.0 

mg/m3

), and by the National Institute for Occupational Safety and 

Health (NIOSH)36 “for any 15 minute period in a work day” (NIOSH 

REL – STEL of 3.2 mg/m3

). These shorter duration occupational 

values indicate potential concerns regarding health effects at 

exposure levels below the 1-hour AEGL-1 value. 

All other HAP and facilities modeled had worst-case acute 

HQ values less than 1, indicating that the HAP emissions are 

believed to be without appreciable risk of acute health effects. 

In characterizing the potential for acute non-cancer risks of 

concern, it is important to remember the upward bias of these 

exposure estimates (e.g., worst-case meteorology coinciding with 

a person located at the point of maximum concentration during 

the hour) and to consider the results along with the 

conservative estimates used to develop hourly emissions as 

 

33 29 CFR 1910.1028, Benzene.

34 ACGIH (2001) Benzene. In Documentation of the TLVs® and BEIs® with Other 

Worldwide Occupational Exposure Values. ACGIH, 1300 Kemper Meadow Drive, 

Cincinnati, OH 45240 (ISBN: 978-1-882417-74-1) and available online at 

http://www.acgih.org. 

35 The ACGIH definition of a TLV-STEL states that “Exposures above the TLV-TWA 

up to the TLV-STEL should be less than 15 minutes, should occur no more than 

four times per day, and there should be at least 60 minutes between 

successive exposures in this range.” 

36 NIOSH. Occupational Safety and Health Guideline for Benzene; 

http://www.cdc.gov/niosh/docs/81-123/pdfs/0049.pdf.
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described earlier, as well as the screening methodology. Refer 

to the memo in the docket for this rulemaking (Docket ID Number 

EPA-HQ-OAR-2010-0682, Derivation of hourly emission rates for 

petroleum refinery emission sources used in the acute risk 

analysis) for a detailed description of how the hourly emissions 

were developed for this source sector. 

3. Multipathway Risk Screening Results 

Results of the worst-case Tier I screening analysis 

indicate that PB-HAP emissions (based on estimates of actual 

emissions) from several facilities in this source sector exceed 

the screening emission rates for POM (PAH), CDDF, mercury 

compounds, and cadmium compounds. For the compounds and 

facilities that did not screen out at Tier I, we conducted a 

Tier II screen. The Tier II screen replaces some of the 

assumptions used in Tier I with site-specific data, including 

the land use around the facilities, the location of fishable 

lakes, and local wind direction and speed. The Tier II screen 

continues to rely on high-end assumptions about consumption of 

local fish and locally grown or raised foods (adult female 

angler at 99th consumption for fish37 and 90th percentile for 

 

37 Burger, J. 2002. Daily consumption of wild fish and game: Exposures of high 

end recreationists. International Journal of Environmental Health Research 

12:343-354 
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consumption of locally grown or raised foods38) and uses an 

assumption that the same individual consumes each of these foods 

in high end quantities (i.e., that an individual has high end 

ingestion rates for each food). The result of this analysis was 

the development of site-specific emission screening levels for 

POM, CDDF, mercury compounds, and cadmium compounds. It is 

important to note that, even with the inclusion of some sitespecific information in the Tier II analysis, the multi-pathway 

screening analysis is a still a very conservative, healthprotective assessment (e.g., upper-bound consumption of local 

fish, locally grown, and/or raised foods) and in all likelihood 

will yield results that serve as an upper-bound multi-pathway 

risk associated with a facility. 

While the screening analysis is not designed to produce a 

quantitative risk result, the factor by which the emissions 

exceed the screening value serves as a rough gauge of the 

“upper-limit” risks we would expect from a facility. Thus, for 

example, if a facility emitted a PB-HAP carcinogen at a level 2 

times the screening value, we can say with a high degree of 

confidence that the actual maximum cancer risks will be less 

than 2-in-1 million. Likewise, if a facility emitted a noncancer 

PB-HAP at a level 2 times the screening level, the maximum 

 

38 U.S. EPA. Exposure Factors Handbook 2011 Edition (Final). U.S. 

Environmental Protection Agency, Washington, DC, EPA/600/R-09/052F, 2011. 
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noncancer risks would represent a HQ less than 2. The high 

degree of confidence comes from the fact that the screens are 

developed using the very conservative (health-protective) 

assumptions that we describe above. 

Based on the Tier II screening analysis, one facility emits 

cadmium compounds above the Tier II screening level and exceeds 

that level by about a factor of 2. Twenty-three facilities emit 

CDDF as 2,3,7,8-tetrachlorodibenzo-p-dioxin toxicity equivalent 

(TEQ) above the Tier II screening level, and the facility with 

the highest emissions of dioxins exceeds the Tier II screening 

level by about a factor of 40. No facilities emit mercury 

compounds above the Tier II screening levels. Forty-four 

facilities emit POM as benzo(a)pyrene TEQ above the Tier II 

screening level, and the facility with the highest emissions of 

POM as benzo(a)pyrene TEQ exceeds its screening level by a 

factor of 30. 

Polychlorinated biphenyls (PCB) are PB-HAP that do not 

currently have multi-pathway screening values and so are not 

evaluated for potential non-inhalation risks. These HAP, 

however, are not emitted in appreciable quantities (0.001 tpy) 

from refinery operations, and we do not believe they contribute 

to multi-pathway risks for this source category. 

Results of the analysis for lead indicate that the maximum 

annual off-site ambient lead concentration was only 2 percent of 
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the NAAQS for lead, and even if the total annual emissions 

occurred during a 3-month period, the maximum 3-month rolling 

average concentrations would still be less than 8 percent of the 

NAAQS, indicating that there is no concern for multi-pathway 

risks due to lead emissions. 

4. Refined Multipathway Case Study 

To gain a better understanding of the uncertainty 

associated with the multipathway Tier I and II screening 

analysis, a refined multipathway case study using the TRIM.Fate 

model was conducted for a single petroleum refinery. The site, a 

refinery in St. John the Baptist Parish, Louisiana, was selected 

based upon its close proximity to nearby lakes and farms as well 

as having one of the highest potential multipathway risks for 

PAH based on the Tier II analysis. The refined analysis for this 

facility showed that the Tier II screen for each pollutant overpredicted the potential risk when compared to the refined 

analysis results. For this site, the Tier II screen for mercury 

indicated that mercury emissions were 3 times lower than the 

screening value, indicating a potential maximum HQ for mercury 

of 0.3. In the refined analysis, the potential HQ was 0.04 or 

about 7 times lower than that predicted by the Tier II screen. 

For cadmium emissions, the Tier II screen for this facility 

indicated that cadmium emissions were about 20 times lower than 

the screening value, indicating a potential maximum HQ for 
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mercury of 0.05. The results of the refined analysis for the 

selected site in Louisiana show a maximum cadmium HQ of 0.02 or 

about 3 times lower than that predicted by the Tier II screen. 

For PAH emissions, the site selected for the refined analysis 

had PAH emissions 20 times the PAH Tier II screening value, 

indicating a potential cancer risk of 20-in-1 million. When the 

more refined analysis was conducted for this site, the potential 

cancer risks were estimated to be 2-in-1 million or about 14 

times lower than predicted by the Tier II analysis. Finally, for 

the facility selected for the refined assessment, the emissions 

of CDDF as 2,3,7,8-tetrachlorodibenzo-p-dioxin TEQ are 5 times 

higher than the dioxin Tier II screening value, indicating a 

potential maximum cancer risk of 5–in-1 million. In the refined 

assessment, the cancer risk from dioxins was estimated to be 2-

in-1 million, about one-third of the estimate from the Tier II 

screen. 

Overall, the refined analysis predicts a potential lifetime 

cancer risk of 4-in-1 million to the maximum most exposed 

individual (MIR). The non-cancer HQ is predicted to be well 

below 1 for all target organs. The chronic inhalation cancer 

risk assessment estimated inhalation cancer risk around this 

same facility to be approximately 10-in-1 million, due in large 

part to emissions of naphthalene and 2-methylnaphthalene (both 

non-persistent, bioaccumulative, and toxic (PBT) HAP). Thus, 
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although highly unlikely, if around this facility the person 

with the highest chronic inhalation cancer risk is also the same 

person with the highest individual multipathway cancer risk, 

then the combined, worst-case MIR for that facility could 

theoretically be 10-in-1 million (risk estimates are expressed 

as 1 significant figure). 

While this refined assessment was performed on only a 

single facility, the results of this single refined analysis 

indicate that if refined analyses were performed for other 

sites, the risk estimates would consistently be lower than those 

estimated by the Tier II analysis. In addition, the risks 

predicted by the multipathway analyses at most facilities are 

considerably lower than the risk estimates predicted by the 

inhalation assessment, indicating that the inhalation risk 

results are in all likelihood the primary factor in our residual 

risk determination for this source category. 

Further details on the site-specific case study can be 

found in Appendix 10 of the Draft Residual Risk Assessment for 

the Petroleum Refining Source Sector, which is available in 

Docket ID Number EPA-HQ-OAR-2010-0682. 

5. Environmental Risk Screening Results 

As described in the Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector, which is available in Docket 

ID Number EPA-HQ-OAR-2010-0682, we conducted an environmental 
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risk screening assessment for the petroleum refineries source 

category. In the Tier I screening analysis for PB-HAP (other 

than lead, which was evaluated differently, as noted in section 

III.A.6 of this preamble), the individual modeled Tier I 

concentrations for one facility in the source category exceeded 

some of the ecological benchmarks for mercury. In addition, Tier 

I modeled concentrations for four facilities exceeded sediment 

and soil ecological benchmarks for PAH. Therefore, we conducted 

a Tier II assessment. 

In the Tier II screening analysis for PB-HAP, none of the 

individual modeled concentrations for any facility in the source 

category exceeded any of the ecological benchmarks (either the 

LOAEL or NOAEL). 

For lead compounds, we did not estimate any exceedances of 

the secondary lead NAAQS. Therefore, we did not conduct further 

assessment for lead compounds. 

For acid gases, the average modeled concentration around 

each facility (i.e., the average concentration of all off-site 

data points in the modeling domain) did not exceed any 

ecological benchmark. In addition, for both HCL and HF, each 

individual concentration (i.e., each off-site data point in the 

modeling domain) was below the ecological benchmarks for all 

facilities. 
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6. Facility-Wide Risk Results 

Table 11 of this preamble displays the results of the 

facility-wide risk assessment. 

Table 11. Petroleum Refining Facility-Wide Risk Assessment 

Results 

Number of facilities analyzed 142 

Cancer Risk: 

Estimated maximum facility-wide individual cancer risk 

(-in-1 million) 

70 

Number of facilities with estimated facility-wide 

individual cancer risk of 10-in-1 million or more 

54 

Number of petroleum refining operations contributing 50 

percent or more to facility-wide individual cancer risk of 

10-in-1 million or more 

50 

Number of facilities with facility-wide individual cancer 

risk of 1-in-1 million or more 

115 

Number of petroleum refining operations contributing 50 

percent or more to facility-wide individual cancer risk of 

1-in-1 million or more 

107 

Chronic Non-cancer Risk: 

Maximum facility-wide chronic non-cancer TOSHI 4 

Number of facilities with facility-wide maximum non-cancer 

TOSHI greater than 1 

5 

Number of petroleum refining operations contributing 50 

percent or more to facility-wide maximum non-cancer TOSHI 

of 1 or more 

0 

The maximum individual cancer whole-facility risk from all 

HAP emissions at any petroleum refinery is estimated to be 70-

in-1 million, based on actual emissions. Of the 142 facilities 

included in this analysis, 54 have facility-wide maximum 

individual cancer risks of 10-in-1 million or greater. At the 

majority of these facilities (50 of 54), the petroleum refinery 

operations account for over 50 percent of the risk. 
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There are 115 facilities with facility-wide maximum 

individual cancer risks of 1-in-1 million or greater. At the 

majority of these facilities (107 of 115), the petroleum 

refinery operations account for over 50 percent of the risk. The 

facility-wide maximum individual chronic non-cancer TOSHI is 

estimated to be 4, based on actual emissions. Of the 142 

refineries included in this analysis, five have a TOSHI value 

greater than 1. The highest non-cancer TOSHI results from 

emissions of chlorine from cooling towers. In each case, the 

petroleum refinery operations account for less than 20 percent 

of the TOSHI values greater than 1. 

Additional detail regarding the methodology and the results 

of the facility-wide analyses are included in the risk 

assessment documentation (Draft Residual Risk Assessment for the 

Petroleum Refining Source Sector), which is available in the 

docket for this rulemaking (Docket ID Number EPA-HQ-OAR-2010-

0682). 

7. What demographic groups might benefit from this regulation? 

To examine the potential for any environmental justice 

issues that might be associated with the source categories, we 

performed a demographic analysis of the population close to the 

facilities. In this analysis, we evaluated the distribution of 

HAP-related cancer and non-cancer risks from petroleum 

refineries across different social, demographic, and economic 
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groups within the populations living near facilities identified 

as having the highest risks. The methodology and the results of 

the demographic analyses are included in a technical report, 

Draft Risk and Technology Review – Analysis of Socio-Economic 

Factors for Populations Living Near Petroleum Refineries, 

available in the docket for this action (Docket ID Number EPAHQ-OAR-2010-0682). 

The results of the demographic analysis are summarized in 

Table 12 of this preamble. These results, for various 

demographic groups, are based on the estimated risks from actual 

emissions levels for the population living within 50 km of the 

facilities. 

Table 12. Petroleum Refining Demographic Risk Analysis Results 

 Nationwide 

Population with 

Cancer Risk at or 

Above 1-in-1 

Million 

Population with 

Chronic Hazard 

Index Above 1 

Total Population 312,861,265 5,204,234 0 

Race by Percent 

White 72 50 0 

All Other Races 28 50 0 

Race by Percent 

White 72 50 0 

African American 13 28 0 

Native American 1 1 0 

Other and 

Multiracial 14 21 0 

Ethnicity by Percent 

Hispanic 17 29 0 

Non-Hispanic 83 71 0 

Income by Percent 

Below Poverty 

Level 14 21 0 
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Above Poverty 

Level 86 79 0 

Education by Percent 

Over 25 and 

without High 

School Diploma 

15 23 0 

Over 25 and with 

a High School 

Diploma 

85 77 0 

The results of the demographic analysis indicate that 

emissions from petroleum refineries expose approximately 

5,000,000 people to a cancer risk at or above 1-in-1 million. 

Implementation of the provisions included in this proposal is 

expected to reduce the number of people estimated to have a 

cancer risk greater than 1-in-1 million due to HAP emissions 

from these sources from 5,000,000 people to about 4,000,000. Our 

analysis of the demographics of the population within 50 km of 

the facilities indicates potential disparities in certain 

demographic groups, including the African American, Other and 

Multiracial, Hispanic, Below the Poverty Level, and Over 25 

without a High School Diploma. The population living within 50 

km of the 142 petroleum refineries has a higher percentage of 

minority, lower income and lower education persons when compared 

to the nationwide percentages of those groups. For example, 50 

percent are in one or more minority demographic group, compared 

to 28 percent nationwide. As noted above, approximately 

5,000,000 people currently living within 50 km of a petroleum 
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refinery have a cancer risk greater than 1-in-1 million. We 

would expect that half of those people are in one or more 

minority demographic groups. 

Because minority groups make up a large portion of the 

population living near refineries, as compared with their 

representation nationwide, those groups would similarly see a 

greater benefit from the implementation of the controls proposed 

in this rule, if finalized. For example, we estimate that after 

implementation of the controls proposed in this action (i.e., 

post-controls), about 1,000,000 fewer people will be exposed to 

cancer risks greater than 1-in-1 million (i.e., 4,000,000 

people). Further, we estimate that approximately 500,000 people 

no longer exposed to a cancer risk greater than 1-in-1 million 

would be in a minority demographic group. The post-control risk 

estimates are discussed further in section III.A.5 of this 

preamble. 

Although the EPA’s proposed fenceline monitoring 

requirement is intended to ensure that owners and operators 

monitor, manage and, if necessary, reduce fugitive emissions of 

HAP, we also expect the collected fenceline data to help the EPA 

understand and identify emissions of benzene and other fugitive 

emissions that are impacting communities in close proximity to 

the facility. While currently-available emissions and monitoring 

data do not indicate that risks to nearby populations are 
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unacceptable (see section IV.D.1 of this preamble), we recognize 

that the collection of additional data through routine fenceline 

monitoring can provide important information to communities 

concerned with potential risks associated with emissions from 

fugitive sources. We note that the data we are proposing to 

collect on a semiannual basis may include exceedances of the 

fenceline action level that a facility could have addressed or 

could still be actively addressing at the time of the report. As 

noted in section IV.B.1.h of this preamble, directly monitoring 

fugitive emissions from each potential emissions source at the 

facility is impractical. Fenceline monitoring offers a costeffective alternative for monitoring fugitive emissions from the 

entire facility. The EPA’s proposal to require the electronic 

reporting of fenceline monitoring data on a semiannual basis 

will ensure that communities have access to data on benzene 

levels near the facility, which is directly relevant to the 

potential health risks posed by the facility. The proposed 

requirements for fenceline monitoring and corrective action when 

fugitive emissions from a facility exceed the specified 

corrective action level will serve as an important backstop to 

protect the health of the populations surrounding the facility, 

including minority and low-income populations. 
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D. What are our proposed decisions regarding risk acceptability, 

ample margin of safety and adverse environmental effects? 

1. Risk Acceptability 

As noted in section II.A.1 of this preamble, the EPA sets 

standards under CAA section 112(f)(2) using “a two-step 

standard-setting approach, with an analytical first step to 

determine an ‘acceptable risk’ that considers all health 

information, including risk estimation uncertainty, and includes 

a presumptive limit on maximum individual lifetime risk (MIR) of 

approximately 1 in 10 thousand[39].” (54 FR 38045, September 14, 

1989). 

In this proposal, we estimate risks based on actual 

emissions from petroleum refineries. We also estimate risks from 

allowable emissions; as discussed earlier, we consider our 

analysis of risk from allowable emissions to be conservative and 

as such to represent an upper bound estimate on risk from 

emissions allowed under the current MACT standards for the 

source categories. 

a. Estimated Risks from Actual Emissions 

The baseline inhalation cancer risk to the individual most 

exposed to emissions from sources regulated by Refinery MACT 1 

and 2 is 60-in-1 million based on actual emissions. The 

 

39 1-in-10 thousand is equivalent to 100-in-1 million. The EPA currently 

describes cancer risks as ‘n-in-1 million’. 
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estimated incidence of cancer due to inhalation exposures is 0.3 

excess cancer cases per year, or 1 case every 3.3 years. 

Approximately 5,000,000 people face an increased cancer risk 

greater than 1-in-1 million due to inhalation exposure to actual 

HAP emissions from these source categories, and approximately 

100,000 people face an increased risk greater than 10-in-1 

million and up to 60-in-1 million. The agency estimates that the 

maximum chronic non-cancer TOSHI from inhalation exposure is 0.9 

due to actual emissions of HCN from FCCU. 

The screening assessment of worst-case acute inhalation 

impacts from actual emissions indicates the potential for five 

pollutants – nickel, arsenic, acrolein, benzene and acetaldehyde 

- to exceed an HQ value of 1, with an estimated worst-case 

maximum HQ of 5 for nickel based on the REL values. One hundred 

thirty-six of the 142 petroleum refineries had an estimated 

worst-case HQ less than or equal to 1 for all HAP. One facility 

had an estimated worst-case maximum HQ of 5 and the remaining 

five refineries with an HQ above 1 had an estimated worst-case 

HQ less than or equal to 3. Considering the conservative, 

health-protective nature of the approach that is used to develop 

these acute estimates, it is highly unlikely that an individual 

would have an acute exposure above the REL. Specifically, the 

analysis is based on the assumption that worst-case emissions 

and meteorology would coincide with a person being at this exact 
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location for a period of time long enough to have an exposure 

level above the conservative REL value. 

The Tier II multipathway screening analysis of actual 

emissions indicated the potential for PAH emissions that are 

about 30 times the screening level for cancer, dioxin and furans 

emissions that are about 40 times the cancer screening level and 

cadmium emissions that are about 2 times the screening level for 

non-cancer health effects. No facility’s emissions were above 

the screening level for mercury. As we note above, the Tier II 

multipathway screen is conservative in that it incorporates many 

health-protective assumptions. For example, we choose inputs 

from the upper end of the range of possible values for the 

influential parameters used in the Tier II screen and we assume 

that the exposed individual exhibits ingestion behavior that 

would lead to a high total exposure. A Tier II exceedance cannot 

be equated with a risk value or a HQ or HI. Rather, it 

represents a high-end estimate of what the risk or hazard may 

be. For example, an exceedance of 2 for a non-carcinogen can be 

interpreted to mean that we have high confidence that the HI 

would be lower than 2. Similarly, an exceedance of 30 for a 

carcinogen means that we have high confidence that the risk is 

lower than 30-in-1-million. Our confidence comes from the 

conservative, or health-protective, assumptions that are used in 

the Tier II screen. 
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The refined analysis that we conducted for a specific 

facility showed that the Tier II screen for each pollutant overpredicted the potential risk when compared to the refined 

analysis results. That refined multipathway assessment showed 

that the Tier II screen resulted in estimated risks that are 

higher than the risks estimated by the refined analysis by 14 

times for PAH, 3 times for dioxins and furans, and 3 times for 

cadmium. The refined assessment results indicate that the 

multipathway risks are considerably lower than the estimated 

inhalation risks, and our refined multipathway analysis 

indicates that multipathway risks are low enough that, while 

they are considered in our proposed decisions, they do not weigh 

heavily into those decisions because risks for the source 

category are driven by inhalation. 

b. Estimated Risks from Allowable Emissions 

We estimate that the baseline inhalation cancer risk to the 

individual most exposed to emissions from sources regulated by 

Refinery MACT 1 and 2 is as high as 100-in-1 million based on 

allowable emissions. The EPA estimates that the incidence of 

cancer due to inhalation exposures could be as high as 0.6 

excess cancer cases per year, or 1 case approximately every 1.5 

years. About 7,000,000 people face an increased cancer risk 

greater than 1-in-1 million due to inhalation exposure to 

allowable HAP emissions from these source categories, and 
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greater than 90,000 people face an increased risk greater than 

10-in-1 million, and as high as 100-in-1 million. Further, we 

estimate that the maximum chronic non-cancer TOSHI from 

inhalation exposure values at all refineries is less than 1 

based on allowable emissions. 

The baseline risks summarized above do not account for 

additional risk reductions that we anticipate due to the MACT 

standards or the technology review requirements we are proposing 

in this action. 

c. Acceptability Determination 

In determining whether risk is acceptable, the EPA 

considered all available health information and risk estimation 

uncertainty as described above. As noted above, the agency 

estimated risk from actual and allowable emissions. While there 

are uncertainties associated with both the actual and allowable 

emissions, we consider the allowable emissions to be an upper 

bound, based on the conservative methods we used to calculate 

allowable emissions. 

The results indicate that both the actual and 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. The MIR based on actual 

emissions is 60-in-1 million, approximately 60 percent of the 

presumptive limit. Based on the results of the refined site-
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specific multipathway analysis summarized above and described in 

section IV.C.3 of this preamble, we also conclude that the 

ingestion cancer risk to the individual most exposed is 

significantly less than 100-in-1 million. In addition, the 

maximum chronic non-cancer TOSHI due to inhalation exposures is 

less than 1, and our refined multipathway analysis indicates 

that non-cancer ingestion risks are estimated to be less than 

non-cancer risk from inhalation. Finally, the evaluation of 

acute non-cancer risks was very conservative, and showed acute 

risks below a level of concern. 

In determining risk acceptability, we also evaluated 

population impacts because of the large number of people living 

near facilities in the source category. The analysis indicates 

that there are approximately 5 million people exposed to actual 

emissions resulting in a cancer risk greater than 1-in-1 

million, and a substantially smaller number of people (100,000) 

are exposed to a cancer risk of greater than 10-in-1 million but 

less than 100-in-1 million (with a maximum risk of 60-in-1 

million). The inhalation cancer incidence is approximately one 

case in every 3 years based on actual emissions. More detail on 

this risk analysis is presented in section IV.C and summarized 

in Tables 10 and 11 of this preamble. The results of the 

demographic analysis for petroleum refineries indicate that a 

greater proportion of certain minority groups and low-income 
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populations live near refineries than the national demographic 

profile. More detail on these population impacts is presented in 

section IV.C.7 of this preamble. We did not identify any 

sensitivity to pollutants emitted from these source categories 

particular to minority and low income populations. Considering 

the above information, we propose that the risks remaining after 

implementation of the existing NESHAP for the Refinery MACT 1 

and 2 source categories is acceptable. 

We also note that the estimated baseline risks for the 

refineries source categories include risks from emissions from 

DCU, which are a previously unregulated emission source. As 

discussed in section IV.A. of this preamble, we are proposing 

new MACT standards for these sources that would reduce emissions 

of HAP by 850 tpy. We estimate that these new standards would 

not affect the MIR, but would reduce the source category cancer 

incidence by 15 percent. 

We solicit comment on all aspects of our proposed 

acceptability determination. We note that while we are proposing 

that the risks estimated from actual and allowable emissions are 

acceptable, the risks based on allowable emissions are at the 

presumptive limit of acceptable risk. Furthermore, a significant 

number of people live in relative proximity to refineries across 

the country, and therefore a large population is exposed to 

risks greater than 1-in-1 million. In particular, we solicit 

Deleted: for all proximate 

populations

Comment [A1]: What does this mean? Did 

EPA really mean to say this? 
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comment on the methodology used to estimate allowable emissions. 

As noted above, we consider the allowable emissions to be an 

upper bound estimate based on the conservative methods used to 

calculate such emissions. We recognize, however, that some of 

the health information concerning allowable emissions arguably 

borders on the edge of acceptability. Specifically, the analysis 

of allowable emissions resulted in a MIR of 100-in-1 million, 

which is the presumptive limit of acceptability, a large number 

of people (7,000,000) estimated to be exposed at a cancer risk 

above 1-in-1 million, and an estimated high cancer incidence 

(one case approximately every 1.5 years). Although we believe 

that our allowable emissions represent an upper end estimate, we 

nonetheless solicit comment on whether the health information 

currently before the Agency should be deemed unacceptable. We 

also solicit comment on whether our allowable emissions analysis 

reflects a reasonable estimate of emissions allowed under the 

current MACT standards. Lastly, we solicit comment on the 

acceptability of risk considering individuals’ potential 

cumulative inhalation and ingestion pathway exposure. Please 

provide comments and data supporting your position. Such 

information will aid the Agency to make an informed decision on 

risk acceptability as it moves forward with this rulemaking. 

Deleted: 

Comment [A2]: Suggested addition 
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2. Ample Margin of Safety 

We next considered whether the existing MACT standards 

provide an ample margin of safety to protect public health. In 

addition to considering all of the health risks and other health 

information considered in the risk acceptability determination, 

in the ample margin of safety analysis we evaluated the cost and 

feasibility of available control technologies and other measures 

that could be applied in these source categories to further 

reduce the risks due to emissions of HAP. For purposes of the 

ample margin of safety analysis, we evaluated the changes in 

risk that would occur through adoption of a specific technology 

by looking at the changes to the risk due to actual emissions. 

Due to the nature of the allowable risk analysis, which is based 

on model plants and post processing to combine risk results40, we 

did not evaluate the risk reductions resulting from reducing 

allowable emissions at individual emission sources. Such an 

approach would require an unnecessarily complex analysis that 

would not provide any more useful information than the analysis 

we undertook using actual emissions. We note that while we did 

not conduct a specific analysis for allowable emissions, it is 

 

40 As described in the memorandum entitled Refinery Emissions and Risk 

Estimates for Modeled “Allowable” Emissions, available in Docket EPA-HQ-OAR2010-0682, the use of model plants and post-processing was for the purpose of 

ensuring that our analysis would provide a conservative estimate of actual 

emissions and thus a conservative estimate of risk. 
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reasonable to expect reductions in risk similar to those for 

actual emissions. 

As noted in our discussion of the technology review in 

section IV.B of this preamble, we identified a number of 

developments in practices, processes or control technologies for 

reducing HAP emissions from petroleum refinery processes. As 

part of the risk review, we evaluated these developments to 

determine if any of them could reduce risks and whether it is 

necessary to require any of these developments to provide an 

ample margin of safety to protect public health. 

We evaluated the health information and control options for 

all of the emission sources located at refineries, including: 

storage vessels, equipment leaks, gasoline loading racks, marine 

vessel loading operations, cooling towers/heat exchange systems, 

wastewater collection and treatment, FCCU, flares, miscellaneous 

process vents, CRU and SRU. For each of these sources, we 

considered chronic cancer and non-cancer risk metrics as well as 

acute risk. Regarding our ample margin of safety analyses for 

chronic non-cancer risk for the various emission sources, we 

note that the baseline TOSHIs are less than 1 for the entire 

source category and considerably less than 1 for all of the 

emission sources except for the FCCU (which had an TOSHI of 

0.9). Therefore, we did not quantitatively evaluate reductions 

in the chronic non-cancer TOSHI for sources other than FCCU in 
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the ample margin of safety analysis. Regarding our ample margin 

of safety analyses for acute risk for all of the various 

emission sources, we note that our analyses did not identify 

acute risks at a level of concern and, therefore, we did not 

quantitatively evaluate reductions in the acute HQ values for 

each individual emission source in the ample margin of safety 

analysis. Accordingly, the following paragraphs focus on cancer 

risk in the determination of whether the standards provide an 

ample margin of safety to protect public health. 

For storage vessels, as discussed in section IV.B of this 

preamble, we identified and evaluated three control options. 

Under the technology review, we determined that two of the 

options, which we call options 1 and 2, are cost effective. We 

are proposing option 2, which includes all of the requirements 

of option 1, as part of the technology review. The option 2 

controls that we are proposing under the technology review would 

result in approximately 910 tpy reduction in HAP (a 40-percent 

reduction from this emission source). As described in section 

IV.B of this preamble, not only are these controls cost 

effective, but we estimate a net cost savings because the 

emission reductions translate into reduced product loss. These 

controls would reduce the cancer risk to the individual most 

exposed from 60-in-1 million to 50-in-1 million based on actual 

emissions at the facility where storage tank emissions were 
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driving the risk. However, the MIR remains unchanged for the 

refinery source categories, at 60-in 1-million, because the 

facility with the next highest cancer risk is 60-in-1 million 

and this risk is driven by another emission source. The option 2 

controls also would reduce cancer incidence by approximately 2 

percent. Finally, we estimate that the option 2 controls reduce 

the number of people with a cancer risk greater than 10-in-1 

million storage tanks from 3,000 to 60 and reduce the number of 

people with a cancer risk greater than 1-in-1 million from 

storage tanks from 140,000 to 72,000. Since these controls 

reduce cancer incidence, and reduce the number of people exposed 

to cancer risks greater than 1-in-10 million and 1-in-1 million 

from storage tank emissions, and are cost effective, we propose 

that these controls are necessary to provide an ample margin of 

safety to protect public health. We also evaluated one 

additional control option for storage vessels, option 3, which 

incorporated both options 1 and 2 along with additional 

monitoring requirements. We estimate incremental HAP emission 

reductions (beyond those provided by option 2) of 90 tpy. The 

incremental cost effectiveness for option 3 exceeds $60,000 per 

ton, which we do not consider cost effective. In addition, the 

option 3 controls do not result in quantifiable reductions in 

the cancer risk to the individual most exposed or the cancer 

incidence beyond the reductions estimated for the option 2 
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controls. For these reasons, we propose that it is not necessary 

to require the option 3 controls in order to provide an ample 

margin of safety to protect public health. 

For equipment leaks, we identified and evaluated three 

control options discussed previously in the technology review 

section of this preamble (section IV.B). These options are: 

 Option 1 - monitoring and repair at lower leak 

definitions; 

 Option 2 - applying monitoring and repair requirements to 

connectors; and 

 Option 3 - optical gas imaging and repair. 

We estimate that these three independent control options 

reduce industry-wide emissions of organic HAP by 24 tpy, 86 tpy, 

and 24 tpy, respectively. We estimate that none of the control 

options would reduce the risk to the individual most exposed. We 

also estimate that the cancer incidence would not change 

perceptively if these controls were required. Finally, we 

estimate that the control options do not reduce the number of 

people with a cancer risk greater than 10-in-1 million or the 

number of people with a cancer risk greater than 1-in-1 million. 

As discussed above, the available control options for equipment 

leaks do not provide quantifiable risk reductions and, 
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therefore, we propose that these controls are not necessary to 

provide an ample margin of safety. 

For gasoline loading racks, we identified and evaluated one 

control option discussed previously in the technology review 

section of this preamble (section IV.B). As discussed earlier, 

this option is a new development that results in emissions that 

are higher than the current level required under Refinery MACT 

1. Since we estimate that no emission reductions would result 

from this new technology and thus no reduction in risk, we 

propose that this control option is not necessary to provide an 

ample margin of safety. 

For marine vessel loading operations, we identified and 

evaluated two control options discussed previously in the 

technology review section of this preamble (section IV.B). The 

first option would be to require submerged fill for small and 

offshore marine vessel loading operations. Based on actual 

emissions, we project no HAP emission reductions for this 

option, as all marine vessels that are used to transport bulk 

refinery liquids are expected to already have the required 

submerged fill pipes. Accordingly, we do not project any changes 

in risk. While we are proposing this option under the technology 

review, because the option is not projected to reduce emissions 

or risk, we propose that a submerged loading requirement is not 

necessary to provide an ample margin of safety. We also 
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identified and evaluated the use of add-on controls for gasoline 

loading at small marine vessel loading operations. In the 

technology review, we rejected this control option because the 

cost effectiveness exceeded $70,000 ton of HAP reduced. We 

estimate that this option would not result in quantifiable 

changes to any of the risk metrics. Because add-on controls 

would not result in quantifiable risk reductions and we do not 

consider the controls to be cost effective, we are proposing 

that add-on controls for gasoline loading at small marine vessel 

loading operations are not necessary to provide an ample margin 

of safety. 

For cooling towers and heat exchangers, we did not identify 

as part of our technology review any developments in processes, 

practices or controls beyond those that we considered in our 

beyond-the-floor analysis at the time we set the MACT standards. 

We note that we issued MACT standards for heat exchange systems 

in a final rule on October 28, 2009 (74 FR 55686), but existing 

sources were not required to comply until October 29, 2012. As a 

result, the reductions were not reflected in the inventories 

submitted in response to the ICR for refineries and therefore 

were not included in our risk analysis based on actual 

emissions. We estimate that these MACT standards will result in 

an industry-wide reduction of over 600 tons HAP per year (or 85 

percent). The projected contribution to risk associated with 
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cooling tower emissions after implementation of these MACT 

standards for heat exchange systems is approximately 1 percent. 

Because we did not identify any control options beyond those 

required by the current standards for cooling towers and heat 

exchange systems, we are proposing that additional controls for 

these systems are not necessary to provide an ample margin of 

safety. 

For wastewater collection and treatment systems, we 

identified and evaluated three options for reducing emissions. 

We estimate implementing these independent control options would 

result in emission reductions of 158 tpy (4 percent), 549 tpy 

(15 percent), and 929 tpy (25 percent), respectively. None of 

the control options would reduce the cancer risk to the 

individual most exposed from 60-in-1 million. Option 1 would 

reduce the cancer incidence by less than 1 percent, and we 

expect any reduction in cancer incidence that would result from 

options 2 or 3 to be small because this source accounts for 

about 10 percent of the cancer incidence from refineries as a 

whole and the most stringent control option would reduce 

emissions from these source by only 25 percent. Finally, we 

estimate that control option 1 would not reduce the number of 

people with a cancer risk greater than 10-in-1 million or the 

number of people with a cancer risk greater than 1-in-1 million. 

We expect any changes to the number of people with a cancer risk 
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greater than 1-in-1 million from implementation of options 2 or 

3 to be small for the same reasons mentioned above for cancer 

incidence. We estimate the cost effectiveness of these options 

to be $26,600 per ton, $52,100 per ton, and $54,500 per ton of 

organic HAP reduced, and we do not consider any of these options 

to be cost effective. Because of the very small reductions in 

risk and the lack of cost-effective control options, we propose 

that these controls are not necessary to provide an ample margin 

of safety. 

For FCCU, we did not identify any developments in 

processes, practices or control technologies for organic HAP. 

For inorganic HAP from FCCU, in the technology review, we 

identified and evaluated one control option for an HCN emissions 

limit and one control option for a PM emissions limit. The PM 

limit was adopted for new sources in Refinery NSPS Ja as part of 

our review of Refinery NSPS J. We considered the costs and 

emission reductions associated with requiring existing sources 

to meet the new source level for PM under Refinery NSPS Ja 

(i.e., 0.5 g PM/kg of coke burn-off rather than 1.0 g PM/kg). As 

indicated in our promulgation of Refinery NSPS Ja, the cost 

effectiveness of lowering the PM limit for existing sources to 

the level we are requiring for new sources was projected to be 

$21,000 per ton of PM reduced (see 73 FR 35845, June 24, 2008). 

Based on the typical metal HAP concentration in PM from FCCU, 
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the cost effectiveness of this option for HAP metals is 

approximately $1 million per ton of HAP reduced. We estimate 

that this control option would not reduce the cancer risk to the 

individual most exposed, would not change the cancer incidence, 

and would not change the number of people with estimated cancer 

risk greater than 1-in-1 million or 10-in-1 million. For the HCN 

emissions limit, we evaluated the costs of controlling HCN using 

combustion controls in combination with SCR. The cost 

effectiveness of this option was approximately $9,000 per ton of 

HCN. This control option would reduce the non-cancer HI from 0.9 

to 0.8 and would not change any of the cancer risk metrics. 

Based on the cost effectiveness of these options and the limited 

reduction in cancer and non-cancer risk (the non-cancer risk is 

below a level of concern based on the existing standards), we 

propose that additional controls for FCCU are not necessary to 

provide an ample margin of safety. 

Flares are used as APCD to control emissions from several 

emission sources covered by Refinery MACT 1 and 2. In this 

proposed rule, under CAA sections 112(d)(2) and (3), we are 

proposing operating and monitoring requirements to ensure flares 

achieve the 98-percent HAP destruction efficiency identified as 

the MACT Floor in the initial MACT rulemaking in 1995. Flares 

are critical safety devices that effectively reduce emissions 

during startup, shutdown, and process upsets or malfunctions. In 
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most cases, flares are the only means by which emissions from 

pressure relief devices can be controlled. Thus, we find that 

properly-functioning flares act to reduce HAP emissions, and 

thereby risk, from petroleum refinery operations. The changes to 

the flare requirements that we are proposing under CAA sections 

112(d)(2) and (3) will result in sources meeting the level 

required by the original standards, and we did not identify any 

control options that would further reduce the HAP emissions from 

flares. Therefore, we are proposing that additional controls for 

flares are not necessary to provide an ample margin of safety. 

For the remaining emission sources within the Refinery MACT 

1 and Refinery MACT 2 source categories, including miscellaneous 

process vents, CRU, and SRU, we did not identify any 

developments in processes practices and control technologies. 

Therefore, we are proposing that additional controls for these 

three Refinery MACT 1 and 2 emission sources are not necessary 

to provide an ample margin of safety. 

In summary, we propose that the original Refinery MACT 1 

and 2 MACT standards, along with the proposed requirements for 

storage vessels described above, provide an ample margin of 

safety to protect public health. We are specifically requesting 

comment on whether there are additional control measures for 

emission sources subject to Refinery MACT 1 and Refinery MACT 2 

that are necessary to provide an ample margin of safety to 
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protect public health. In particular, we are requesting that 

states identify any controls they have already required for 

these facilities, controls they are currently considering, or 

other controls of which they may be aware. 

While not part of our decisions regarding residual risk, we 

note that DCU are an important emission source with respect to 

risk from refineries. As described in section IV.A of this 

preamble, we are proposing new MACT standards under CAA sections 

112(d)(2) and (3) for DCU. For informational purposes, we also 

looked at the risk reductions that would result from 

implementation of those standards. We estimate no reduction in 

the cancer risk to the individual most exposed and a decrease in 

cancer incidence of 0.05 cases per year, or approximately 15 

percent. While our decisions on risk acceptability and ample 

margin of safety are supported even in the absence of these 

reductions, if we finalize the proposed requirements for DCU, 

they would further strengthen our conclusions that the standards 

provide an ample margin of safety to protect public health. 

3. Adverse Environmental Effects 

We conducted an environmental risk screening assessment for 

the petroleum refineries source category for lead, mercury, 

cadmium, PAH, dioxins and furans, HF, and HCl. For mercury, 

cadmium, PAH, and dioxins and furans, none of the individual 

modeled concentrations for any facility in the source category 
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exceeded any of the Tier II ecological benchmarks (either the 

LOAEL or NOAEL). For lead, we did not estimate any exceedances 

of the secondary lead NAAQS. For HF and HCl, the average modeled 

concentration around each facility (i.e., the average 

concentration of all off-site data points in the modeling 

domain) did not exceed any ecological benchmark. Based on these 

results, EPA proposes 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. 

E. What other actions are we proposing? 

We are proposing the following changes to Refinery MACT 1 

and 2 as described below: (1) revising the SSM provisions in 

order to ensure that the subparts are consistent with the court 

decision in Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), 

which vacated two provisions that exempted sources from the 

requirement to comply with otherwise applicable section 112(d) 

emission standards during periods of SSM; (2) proposing to 

clarify requirements related to open-ended valves or lines; (3) 

adding electronic reporting requirements in Refinery MACT 1 and 

2; and (4) updating the General Provisions cross-reference 

tables. 
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1. SSM 

In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 

(D.C. Cir. 2008), the United States Court of Appeals for the 

District of Columbia Circuit vacated portions of two provisions 

in the EPA’s CAA section 112 regulations governing the emissions 

of HAP during periods of SSM. Specifically, the Court vacated 

the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 

63.6(h)(1), holding that under section 302(k) of the CAA, 

emissions standards or limitations must be continuous in nature 

and that the SSM exemption violates the CAA's requirement that 

some section 112 standards apply continuously. 

We are proposing the elimination of the SSM exemption in 40 

CFR part 63, subparts CC and UUU. Consistent with Sierra Club v. 

EPA, we are proposing standards in these rules that apply at all 

times. We are also proposing 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) as explained in more detail below. For example, we 

are proposing to eliminate the incorporation of the General 

Provisions’ requirement that the source develop an SSM plan. We 

also are proposing to eliminate and revise certain recordkeeping 

and reporting requirements related to the SSM exemption as 

further described below. 
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The EPA has attempted to ensure that the provisions we are 

proposing to eliminate are inappropriate, unnecessary, or 

redundant in the absence of the SSM exemption. We are 

specifically seeking comment on whether we have successfully 

done so. 

In proposing the standards in this rule, the EPA has taken 

into account startup and shutdown periods and, for the reasons 

explained below, we are proposing alternate standards for those 

periods for a few select emission sources. We expect facilities 

can meet nearly all of the emission standards in Refinery MACT 1 

and 2 during startup and shutdown, including the amendments we 

are proposing in this action. For most of the emission sources, 

APCD are operating prior to process startup and continue to 

operate through process shutdown. 

For Refinery MACT 1 and 2, we identified three emission 

sources for which specific startup and shutdown provisions may 

be needed. First, as noted above, most APCD used to control 

metal HAP emissions from FCCU under Refinery MACT 2 (e.g., wet 

scrubber, fabric filter, cyclone) would be operating before 

emissions are routed to them and would be operating during 

startup and shutdown events in a manner consistent with normal 

operating periods, such that the monitoring parameter operating 

limits set during the performance test are maintained and met. 

However, we recognize that there are safety concerns associated 
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with operating an ESP during startup of the FCCU, as described 

in the following paragraphs. Therefore, we are proposing 

specific PM standards for startup of FCCU controlled with an ESP 

under Refinery MACT 2. 

During startup of the FCCU, “torch oil” (heavy oil 

typically used as feed to the unit via the riser) is injected 

directly into the regenerator and burned to raise the 

temperature of the regenerator and catalyst to levels needed for 

normal operation. Given the poor mixing of fuel and air in the 

regenerator during this initial startup, it is difficult to 

maintain optimal combustion characteristics, and high CO 

concentrations are common. Elevated CO levels pose an explosion 

threat due to the high electric current and potential for sparks 

within the ESP. Consequently, it is common practice to bypass 

the ESP during startup of the FCCU. Once torch oil is shut off 

and the regenerator is fueled by catalyst coke burn-off, the CO 

levels in the FCCU regenerator off-gas will stabilize and the 

gas can be sent to the ESP safely. 

When the ESP is offline, the operating limits for the ESP 

are meaningless. During much of the startup process, either 

catalyst is not circulating between the FCCU regenerator and 

reactor or the catalyst circulation rate is much lower than 

during normal operations. While the catalyst is not circulating 

or is circulating at reduced rates, the PM and metal HAP 
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emissions are expected to be much lower than during normal 

operations. Therefore, the cyclone separators that are internal 

to the FCCU regenerator should provide reasonable PM control 

during this initial startup. To ensure the internal cyclones are 

operating efficiently, we are proposing that FCCU using an ESP 

as the APCD meet a 30-percent opacity limit (on a 6-minute 

rolling average basis) during the period that torch oil is used 

during FCCU startup. This opacity limit was selected because it 

has been used historically to assess compliance with the PM 

emission limit for FCCU in Refinery NSPS J and because the 

emission limit can be assessed using manual opacity readings, 

eliminating the need to install a COMS. We note that Refinery 

NSPS J includes the exception for one 6-minute average of up to 

60-percent opacity in a 1-hour period primarily to accommodate 

soot blowing events. As no soot blowing should be performed 

prior to the ESP coming on-line, we are not including this 

exception to the proposed 30-percent opacity limit during 

startup for FCCU that are controlled by an ESP. 

Second, for emissions of organic HAP from FCCU under 

Refinery MACT 2, we also expect that APCD would be operating 

before emissions are routed to them, and would be operating 

during startup and shutdown events in a manner consistent with 

normal operating periods, such that the monitoring parameter 

operating limits set during the performance test are maintained 
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and met. However, many FCCU operate in “complete combustion” 

mode without a post-combustion device. In other words, for FCCU 

without a post-combustion device, organic HAP are controlled by 

the FCCU itself, so there is no separate APCD that could be 

operating during startup and demonstrating continuous compliance 

with the monitoring parameter operating limits. Therefore, we 

are proposing specific CO standards for startup of FCCU without 

a post-combustion device under Refinery MACT 2. 

As mentioned previously, “torch oil” is injected directly 

into the regenerator and burned during FCCU startup to raise the 

temperature of the regenerator and catalyst to levels needed for 

normal operation. During this period, CO concentrations often 

will exceed the 500 ppm emissions limit due to the poor mixing 

of fuel and air in the regenerator. The emissions limit is based 

on CO emissions, as a surrogate for organic HAP emissions, and 

the emission limit is evaluated using a 1-hour averaging period. 

This 1-hour averaging period does not provide adequate time for 

short-term excursions that occur during startup to be offset by 

lower emissions during normal operational periods. 

Based on available data during normal operations, ensuring 

adequate combustion (indicated by CO concentration levels below 

500 ppmv) minimizes organic HAP emissions. Low levels of CO in 

the exhaust gas are consistently achieved during normal 

operations when oxygen concentrations in the exhaust gas exceed 
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1-percent by volume (dry basis). Thus, maintaining an adequate 

level of excess oxygen for the combustion of fuel in the FCCU is 

expected to minimize organic HAP emissions. Emissions of CO 

during startup result from a series of reactions with the fuel 

source and are dependent on mixing, local oxygen concentrations, 

and temperature. While the refinery owner or operator has direct 

control over air blast rates, CO emissions may not always 

directly correlate with the air blast rate. Exhaust oxygen 

concentrations are expected to be more directly linked with air 

blast rates and are, therefore, more directly under control of 

the refinery owner or operator. We are proposing an excess 

oxygen concentration of 1 volume percent (dry basis) based on a 

1-hour average during startup. We consider the 1-hour averaging 

period for the oxygen concentration in the exhaust gas from the 

FCCU to be appropriate during periods of FCCU startup because 

air blast rates can be directly controlled to ensure adequate 

oxygen supply on a short-term basis. 

Third, we note that the SRU is unique in that it 

essentially is the APCD for the fuel gas system at the facility. 

The SRU would be operating if the refinery is operating, 

including during startup and shutdown events. There are 

typically multiple SRU trains at a facility. Different trains 

can be taken off-line as sour gas production decreases to 

maintain optimal operating characteristics of the operating SRU 
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during startup or shutdown of a set of process units. Thus, the 

sulfur recovery plant is expected to run continuously and would 

only shut down its operation during a complete turnaround or 

shutdown of the facility. For these limited situations, the 12-

hour averaging time provided for the SRU emissions limitation 

under Refinery MACT 2 may not be adequate time in which to shut 

down the unit without exceeding the emissions limitation. 

Therefore, we are proposing specific standards for SRU during 

periods of shutdown. 

We note also that, for SRU subject to Refinery NSPS J or 

electing to comply with Refinery NSPS J as provided in Refinery 

MACT 2, the emissions limit is in terms of SO2 concentration for 

SRU with oxidative control systems or reductive control systems 

followed by an incinerator. While the SO2 concentration limit 

provides a reasonable proxy of the reduced sulfur HAP emissions 

during normal operations, it does not necessarily provide a good 

indication of reduced sulfur HAP emissions during periods of 

shutdown. During periods of shutdown, the sulfur remaining in 

the unit is purged and combusted generally in a thermal oxidizer 

or a flare. Although the sulfur loading to the thermal oxidizer 

during shutdown may be higher than during normal operations 

(thereby causing an increase in the SO2 concentration and 

exceedance of the SO2 emissions limitation), appropriate 

operation of the thermal oxidizer will adequately control 
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emissions of reduced sulfur HAP. Thus, during periods of 

shutdown, the 300 ppmv reduced sulfur compound emission limit 

alternative (provided for SRU not subject to Refinery NSPS J) is 

a better indicator of reduced sulfur HAP emissions. In Refinery 

MACT 2, SRU that elect to comply with the 300 ppmv reduced 

sulfur compound emission limit (i.e., those not subject to 

Refinery NSPS J or electing to comply with Refinery NSPS J) and 

that use a thermal incinerator for sulfur HAP control are 

required to maintain a minimum temperature and excess oxygen 

level (as determined through a source test of the unit) to 

demonstrate compliance with the reduced sulfur compound emission 

limitation. 

In Refinery MACT 2, SRU subject to Refinery NSPS J (or that 

elect to comply with Refinery NSPS J) that use an incinerator to 

control sulfur HAP emissions are required to install an SO2 CEMS 

to demonstrate compliance with the SO2 emission limitation. For 

these units, it is impractical to require installation of a 

reduced sulfur compound monitor or to require a source test to 

establish operating parameters during shutdown of the SRU 

because of the few hours per year that the entire series of SRU 

trains are shutdown. Although the autoignition temperature of 

COS is unknown, based on the autoignition temperature of CS2

(between 200 and 250 °F) and the typical operating 

characteristics of thermal oxidizers used to control emissions 
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from SRU, we are proposing that, for periods of SRU shutdown, 

diverting the 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 1200 °F and a minimum 

outlet oxygen concentration of 2 volume percent (dry basis). We 

believe that this provides adequate assurance of compliance with 

the 300 ppmv reduced sulfur compound emission limitation for SRU 

because incineration at these temperatures was determined to be 

the MACT floor in cases where no tail gas treatment units were 

used (i.e., units not subject to Refinery NSPS J). 

For all other emission sources, we believe that the 

requirements that apply during normal operations should apply 

during startup and shutdown. For Refinery MACT 1, these emission 

sources include process vents, transfer operations, storage 

tanks, equipment leaks, heat exchange systems, and wastewater. 

Emission reductions for process vents and transfer operations, 

such as gasoline loading racks and marine tank vessel loading, 

are typically achieved by routing vapors to thermal oxidizers, 

carbon adsorbers, absorbers and flares. It is common practice to 

start an APCD prior to startup of the emissions source it is 

controlling, so the APCD would be operating before emissions are 

routed to it. We expect APCD would be operating during startup 

and shutdown events in a manner consistent with normal operating 
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periods, and that these APCD will be operated to maintain and 

meet the monitoring parameter operating limits set during the 

performance test. We do not expect startup and shutdown events 

to affect emissions from equipment leaks, heat exchange systems, 

wastewater, or storage tanks. Leak detection programs associated 

with equipment leaks and heat exchange systems are in place to 

detect leaks, and, therefore, it is inconsequential whether the 

process is operating under normal operating conditions or is in 

startup or shutdown. Wastewater emissions are also not expected 

to be significantly affected by startup or shutdown events 

because the control systems used can operate while the 

wastewater treatment system is in startup or shutdown. Working 

and breathing losses from storage tanks are the same regardless 

of whether the process is operating under normal operating 

conditions or if it is in a startup or shutdown event. Degassing 

of a storage tank is common for shutdown of a process; the 

residual emissions in a storage tank are vented as part of the 

cleaning of the storage tank. We evaluated degassing controls as 

a control alternative for storage vessels and do not consider 

these controls to be cost effective (see memorandum Survey of 

Control Technology for Storage Vessels and Analysis of Impacts 

for Storage Vessel Control Options, Docket Item Number EPA-HQOAR-2010-0871-0027). Based on this review, we are not proposing 
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specific standards for storage vessels during startup or 

shutdown. 

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

However, by contrast, malfunction is defined as a sudden, 

infrequent, and not reasonably preventable failure of air 

pollution control and monitoring equipment, process equipment or 

a process to operate in a normal or usual manner (see 40 CFR 

63.2). The EPA has determined that CAA section 112 does not 

require that emissions that occur during periods of malfunction 

be factored into development of section 112 standards. Under 

section 112, emissions standards for new sources must be no less 

stringent than the level “achieved” by the best-controlled 

similar source and for existing sources generally must be no 

less stringent than the average emission limitation “achieved” 

by the best-performing 12 percent of sources in the category. 

There is nothing in section 112 that directs the EPA to consider 

malfunctions in determining the level “achieved” by the bestperforming sources when setting emission standards. As the D.C. 

Circuit has recognized, the phrase “average emissions limitation 

achieved by the best performing 12 percent of” sources “says 

nothing about how the performance of the best units is to be 

calculated.” Nat'l Ass'n of Clean Water Agencies v. EPA, 734 

F.3d 1115, 1141 (D.C. Cir. 2013). While the EPA accounts for 
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variability in setting emissions standards, nothing in section 

112 requires the EPA to consider malfunctions as part of that 

analysis. A malfunction should not be treated in the same manner 

as the type of variation in performance that occurs during 

routine operations of a source. A malfunction is a failure of 

the source to perform in a “normal or usual manner” and no 

statutory language compels EPA to consider such events in 

setting standards based on “best performers.” 

Further, accounting for malfunctions in setting emissions 

standards would be difficult, if not impossible, given the 

myriad different types of malfunctions that can occur across all 

sources in the category, and given the difficulties associated 

with predicting or accounting for the frequency, degree, and 

duration of various malfunctions that might occur. As such, the 

performance of units that are malfunctioning is not “reasonably” 

foreseeable. See, e.g., Sierra Club v. EPA, 167 F. 3d 658, 662 

(D.C. Cir. 1999) (the EPA typically has wide latitude in 

determining the extent of data-gathering necessary to solve a 

problem. We generally defer to an agency’s decision to proceed 

on the basis of imperfect scientific information, rather than to 

“invest the resources to conduct the perfect study.”). See also, 

Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) 

(“In the nature of things, no general limit, individual permit, 

or even any upset provision can anticipate all upset situations. 
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After a certain point, the transgression of regulatory limits 

caused by ‘uncontrollable acts of third parties,’ such as 

strikes, sabotage, operator intoxication or insanity, and a 

variety of other eventualities, must be a matter for the 

administrative exercise of case-by-case enforcement discretion, 

not for specification in advance by regulation.”). In addition, 

emissions during a malfunction event can be significantly higher 

than emissions at any other time of source operation, and thus, 

accounting for malfunctions in setting standards could lead to 

standards that are significantly less stringent than levels that 

are achieved by a well-performing non-malfunctioning source. It 

is reasonable to interpret section 112 to avoid such a result. 

The EPA’s approach to malfunctions is consistent with CAA 

section 112 and is a reasonable interpretation of the statute. 

In the event that a source fails to comply with the 

applicable CAA section 112(d) standards as a result of a 

malfunction event, the EPA would determine an appropriate 

response based on, among other things, the good-faith efforts of 

the source to minimize emissions during malfunction periods, 

including preventative and corrective actions, as well as root 

cause analyses to ascertain and rectify excess emissions. The 

EPA would also consider whether the source’s failure to comply 

with the CAA section 112(d) standard was, in fact, sudden, 

infrequent, not reasonably preventable and was not instead 
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caused in part by poor maintenance or careless operation, as 

described in the definition of malfunction (see 40 CFR 63.2). 

Further, to the extent the EPA files an enforcement action 

against a source for violation of an emission standard, the 

source can raise any and all defenses in that enforcement action 

and the federal district court will determine what, if any, 

relief is appropriate. The same is true for citizen enforcement 

actions. Similarly, the presiding officer in an administrative 

proceeding can consider any defense raised and determine whether 

administrative penalties are appropriate. 

In several prior rules, the EPA had included an affirmative 

defense to civil penalties for violations caused by malfunctions 

in an effort to create a system that incorporates some 

flexibility, recognizing that there is a tension, inherent in 

many types of air regulation, to ensure adequate compliance 

while simultaneously recognizing that despite the most diligent 

of efforts, emission standards may be violated under 

circumstances entirely beyond the control of the source. 

Although the EPA recognized that its case-by-case enforcement 

discretion provides sufficient flexibility in these 

circumstances, it included the affirmative defense to provide a 

more formalized approach and more regulatory clarity. See 

Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 

1978) (holding that an informal case-by-case enforcement 
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discretion approach is adequate); but see Marathon Oil Co. v. 

EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977) (requiring a more 

formalized approach to consideration of “upsets beyond the 

control of the permit holder.”). Under the EPA’s regulatory 

affirmative defense provisions, if a source could demonstrate in 

a judicial or administrative proceeding that it had met the 

requirements of the affirmative defense in the regulation, civil 

penalties would not be assessed. Recently, the United States 

Court of Appeals for the District of Columbia Circuit vacated 

such an affirmative defense in one of the EPA’s section 112(d) 

regulations. NRDC v. EPA, No. 10-1371 (D.C. Cir. April 18, 2014) 

2014 U.S. App. LEXIS 7281 (vacating affirmative defense 

provisions in section 112(d) rule establishing emission 

standards for Portland cement kilns). The court found that the 

EPA lacked authority to establish an affirmative defense for 

private civil suits and held that under the CAA, the authority 

to determine civil penalty amounts lies exclusively with the 

courts, not the EPA. Specifically, the Court found: “As the 

language of the statute makes clear, the courts determine, on a 

case-by-case basis, whether civil penalties are ‘appropriate.’” 

See NRDC, 2014 U.S. App. LEXIS 7281 at *21 (“[U]nder this 

statute, deciding whether penalties are ‘appropriate’ in a given 

private civil suit is a job for the courts, not EPA.”).41 In 

 

41 The court’s reasoning in NRDC focuses on civil judicial actions. The Court 
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light of NRDC, the EPA is not including a regulatory affirmative 

defense provision in this rulemaking. As explained above, if a 

source is unable to comply with emissions standards as a result 

of a malfunction, the EPA may use its case-by-case enforcement 

discretion to provide flexibility, as appropriate. Further, as 

the D.C. Circuit recognized, in an EPA or citizen enforcement 

action, the court has the discretion to consider any defense 

raised and determine whether penalties are appropriate. Cf. 

NRDC, 2014 U.S. App. LEXIS 7281 at *24. (arguments that 

violation were caused by unavoidable technology failure can be 

made to the courts in future civil cases when the issue arises). 

The same logic applies to EPA administrative enforcement 

actions. 

a. General Duty 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entry for 63.6(e)(1)(i) by 

changing the “Yes” in the second column to a “No.” Similarly, we 

are proposing to revise the 40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for §63.6(e)(1)(i) by changing 

the “Yes” in the third column to a “No.” We are making this 

change because section 63.6(e)(1)(i) describes the general duty 

to minimize emissions and the current characterizes what the 

 

noted that “EPA's ability to determine whether penalties should be assessed 

for Clean Air Act violations extends only to administrative penalties, not to 

civil penalties imposed by a court.” Id.
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general duty entails during periods of SSM and that language is 

no longer necessary or appropriate in light of the elimination 

of the SSM exemption. We are proposing instead to add general 

duty regulatory text at 40 CFR 63.642(n) and 40 CFR 63.1570(c) 

that reflects the general duty to minimize emissions while 

eliminating the reference to periods covered by an SSM 

exemption. With the elimination of the SSM exemption, there is 

no need to differentiate between normal operations, startup and 

shutdown, and malfunction events in describing the general duty. 

Therefore the language the EPA is proposing does not include 

that language from 40 CFR 63.6(e)(1). 

We are also proposing to revise the 40 CFR part 63, subpart 

CC General Provisions table (Table 6) entry for 63.6(e)(1)(ii) 

by changing the “Yes” in the second column to a “No.” Similarly, 

we are also proposing to revise the 40 CFR part 63, subpart UUU 

General Provisions table (Table 44) entry for §63.6(e)(1)(ii) by 

changing the “Yes” in the third column to a “No.” Section 

63.6(e)(1)(ii) imposes requirements that are not necessary with 

the elimination of the SSM exemption or are redundant of the 

general duty requirement being added at 40 CFR 63.642(n) and 40 

CFR 63.1570(c). 

b. SSM Plan 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entries for 63.6(e)(3)(i) and 
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63.6(e)(3)(iii)–63.6(e)(3)(ix) by changing the “Yes” in the 

second column to a “No.” Similarly, we are proposing to revise 

the 40 CFR part 63, subpart UUU General Provisions table (Table 

44) entries for §63.6(e)(3)(i)-(iii), §63.6(e)(3)(iv), 

§63.6(e)(3)(v)-(viii), §63.6(e)(3)(ix) to be entries for 

63.6(e)(3)(i) and 63.6(e)(3)(iii)–63.6(e)(3)(ix) with “No” in 

the third column and §63.6(e)(3)(ii) with “Not Applicable” in 

the third column (that section is reserved). Generally, these 

paragraphs require development of an SSM plan and specify SSM 

recordkeeping and reporting requirements related to the SSM 

plan. As noted, the EPA is proposing to remove the SSM 

exemptions. Therefore, affected units will be subject to an 

emission standard during such events. The applicability of a 

standard during such events will ensure that sources have ample 

incentive to plan for and achieve compliance and thus the SSM 

plan requirements are no longer necessary. 

c. Compliance with Standards 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entry for 63.6(f)(1) by 

changing the “Yes” in the second column to a “No.” Similarly, we 

are proposing to revise the 40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for §63.6(f)(1) by changing 

the “Yes” in the third column to a “No.” The current language of 

40 CFR 63.6(f)(1) exempts sources from non-opacity standards 
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during periods of SSM. As discussed above, the court in Sierra 

Club vacated the exemptions contained in this provision and held 

that the CAA requires that some section 112 standard apply 

continuously. Consistent with Sierra Club, the EPA is proposing 

to revise standards in this rule to apply at all times. 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entry for 63.6(h)(1) by 

changing the “Yes” in the second column to a “No.” Similarly, we 

are proposing to revise the 40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for §63.6(h)(1) by changing 

the “Yes” in the third column to a “No.” The current language of 

40 CFR 63.6(h)(1) exempts sources from opacity standards during 

periods of SSM. As discussed above, the court in Sierra Club 

vacated the exemptions contained in this provision and held that 

the CAA requires that some section 112 standard apply 

continuously. Consistent with Sierra Club, the EPA is proposing 

to revise standards in this rule to apply at all times. 

d. Performance Testing 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entry for 63.7(e)(1) by 

changing the “Yes” in the second column to a “No.” Similarly, we 

are proposing to revise the 40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for §63.7(e)(1) by changing 

the “Yes” in the third column to a “No.” Section 63.7(e)(1) 
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describes performance testing requirements. The EPA is instead 

proposing to add performance testing requirements at 40 CFR 

63.642(d)(3) and 40 CFR 63.1571(b)(1). The performance testing 

requirements we are proposing differ from the General Provisions 

performance testing provisions in several respects. The 

regulatory text does not include the language in 40 CFR 

63.7(e)(1) that restated the SSM exemption. The regulatory text 

also does not preclude startup and shutdown periods from being 

considered “representative” for purposes of performance testing, 

however, the testing. However, the specific testing provisions 

proposed at 40 CFR 63.642(d)(3) and 40 CFR 63.1571(b)(1) do not 

allow performance testing during startup or shutdown. As in 40 

CFR 63.7(e)(1), performance tests conducted under this subpart 

may not be conducted during malfunctions because conditions 

during malfunctions are often not representative of normal 

operating conditions. The EPA is proposing to add language that 

requires the owner or operator to record the process information 

that is necessary to document operating conditions during the 

test and include in such record an explanation to support that 

such conditions represent normal operation. Section 63.7(e) 

requires that the owner or operator make available to the 

Administrator such records “as may be necessary to determine the 

condition of the performance test” available to the 

Administrator upon request, but does not specifically require 
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the information to be recorded. The regulatory text EPA is 

proposing to add to Refinery MACT 1 and 2 builds on that 

requirement and makes explicit the requirement to record the 

information. 

e. Monitoring 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entries for 63.8(c)(1)(i) and 

63.8(c)(1)(iii) by changing the “Yes” in the second column to a 

“No.” Similarly, we are proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table (Table 44) entry for 

§63.8(c)(1)(i) and §63.8(c)(1)(iii) by changing the “Yes” in the 

third column to a “No.” The cross-references to the general duty 

and SSM plan requirements in those subparagraphs are not 

necessary in light of other requirements of 40 CFR 63.8 that 

require good air pollution control practices (40 CFR 63.8(c)(1)) 

and that set out the requirements of a quality control program 

for monitoring equipment (40 CFR 63.8(d)). 

We are proposing to revise the 40 CFR part 63, subpart UUU 

General Provisions table (Table 44) entry for §63.8(d) to 

include separate entries for specific paragraphs of 40 CFR 

63.8(d), including an entry for §63.10(d)(3) with “No” in the 

third column. The final sentence in 40 CFR 63.8(d)(3) refers to 

the General Provisions’ SSM plan requirement which is no longer 

applicable. The EPA is proposing to add to the rule at 40 CFR 
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63.1576(b)(3) text that is identical to 40 CFR 63.8(d)(3) except 

that the final sentence is replaced with the following sentence: 

“The program of corrective action should be included in the plan 

required under §63.8(d)(2).” 

f. Recordkeeping 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entry for 63.10(b)(2)(i) by 

changing the “Yes” in the second column to a “No.” Section 

63.10(b)(2)(i) describes the recordkeeping requirements during 

startup and shutdown. These recording provisions are no longer 

necessary because the EPA is proposing that recordkeeping and 

reporting applicable to normal operations will apply to startup 

and shutdown. In the absence of special provisions applicable to 

startup and shutdown, such as a startup and shutdown plan, there 

is no reason to retain additional recordkeeping for startup and 

shutdown periods. 

We are proposing to revise the 40 CFR part 63, subpart UUU 

General Provisions table (Table 44) entry for §63.10(b) to 

include separate entries for specific paragraphs of 40 CFR 

63.10(b), including an entry for §63.10(b)(2)(i) with “No” in 

the third column. Section 63.10(b)(2)(i) describes the 

recordkeeping requirements during startup and shutdown. We are 

instead proposing to add recordkeeping requirements to 40 CFR 

63.1576(a)(2). When a source is subject to a different standard 
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during startup and shutdown, it will be important to know when 

such startup and shutdown periods begin and end in order to 

determine compliance with the appropriate standard. Thus, the 

EPA is proposing to add language to 40 CFR 63.1576(a)(2) 

requiring that sources subject to an emission standard during 

startup or shutdown that differs from the emission standard that 

applies at all other times must record the date, time, and 

duration of such periods. 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entry for 63.10(b)(2)(ii) by 

changing the “Yes” in the second column to a “No.” Similarly, we 

are proposing to revise the 40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for §63.10(b) to include 

separate entries for specific paragraphs of 40 CFR 63.10(b), 

including an entry for §63.10(b)(2)(ii) with “No” in the third 

column. Section 63.10(b)(2)(ii) describes the recordkeeping 

requirements during a malfunction. The EPA is proposing to add 

such requirements to 40 CFR 63.655(i)(11) and 40 CFR 

63.1576(a)(2). The regulatory text we are proposing to add 

differs from the General Provisions language that was crossreferenced, which provides the creation and retention of a 

record of the occurrence and duration of each malfunction of 

process, air pollution control, and monitoring equipment. The 

proposed text would apply to any failure to meet an applicable 
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standard and would require the source to record the date, time, 

and duration of the failure. The EPA is also proposing to add to 

40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2) a requirement that 

sources keep records that include a list of the affected source 

or equipment and actions taken to minimize emissions, an 

estimate of the quantity of each regulated pollutant emitted 

over the standard for which the source failed to meet a 

standard, and a description of the method used to estimate the 

emissions. Examples of such methods would include product-loss 

calculations, mass balance calculations, measurements when 

available, or engineering judgment based on known process 

parameters. The EPA is proposing to require that sources keep 

records of this information to ensure that there is adequate 

information to allow the EPA to determine the severity of any 

failure to meet a standard, and to provide data that may 

document how the source met the general duty to minimize 

emissions when the source has failed to meet an applicable 

standard. 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entry for 63.10(b)(2)(iv) by 

changing the “Yes” in the second column to a “No.” Similarly, we 

are proposing to revise the 40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for §63.10(b) to include 

separate entries for specific paragraphs of 40 CFR 63.10(b), 
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including an entry for §63.10(b)(2)(iv)-(v) with “No” in the 

third column. When applicable, 40 CFR 63.10(b)(2)(iv) requires 

sources to record actions taken during SSM events when actions 

were inconsistent with their SSM plan. The requirement is no 

longer appropriate because SSM plans will no longer be required. 

The requirement previously applicable under 40 CFR 

63.10(b)(2)(iv)(B) to record actions to minimize emissions and 

record corrective actions is now applicable by reference to 40 

CFR 63.655(i)(11)(iii) and 40 CFR 63.1576(a)(2)(iii). 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entry for 63.10(b)(2)(v) by 

changing the “Yes” in the second column to a “No.” Similarly, we 

are proposing to revise the 40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entry for §63.10(b) to include 

separate entries for specific paragraphs of 40 CFR 63.10(b), 

including an entry for §63.10(b)(2)(iv)-(v) with “No” in the 

third column. When applicable, 40 CFR 63.10(b)(2)(v) requires 

sources to record actions taken during SSM events to show that 

actions taken were consistent with their SSM plan. The 

requirement is no longer appropriate because SSM plans would no 

longer be required. 

We are proposing to revise the 40 CFR part 63, subpart UUU 

General Provisions table (Table 44) entry for §63.10(c)(9)-(15) 

to include separate entries for specific paragraphs of 40 CFR 
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63.10(c), including an entry for §63.10(c)(15) with “No” in the 

third column. The EPA is proposing that 40 CFR 63.10(c)(15) no 

longer apply. When applicable, the provision allows an owner or 

operator to use the affected source's SSM plan or records kept 

to satisfy the recordkeeping requirements of the SSM plan, 

specified in 40 CFR 63.6(e), to also satisfy the requirements of 

40 CFR 63.10(c)(10) through (12). The EPA is proposing to 

eliminate this requirement because SSM plans would no longer be 

required, and therefore 40 CFR 63.10(c)(15) no longer serves any 

useful purpose for affected units. 

g. Reporting 

We are proposing to revise the 40 CFR part 63, subpart CC 

General Provisions table (Table 6) entries for 63.10(d)(5)(i) 

and 63.10(d)(5)(ii) by combining them into one entry for 

63.10(d)(5) with a “No” in the second column. Similarly, we are 

proposing to revise the 40 CFR part 63, subpart UUU General 

Provisions table (Table 44) entries for 63.10(d)(5)(i) and 

63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) 

with a “No” in the third column. Section 63.10(d)(5) describes 

the reporting requirements for startups, shutdowns, and 

malfunctions. To replace the General Provisions reporting 

requirement, the EPA is proposing to add reporting requirements 

to 40 CFR 63.655(g)(12), 40 CFR 63.1575(c)(4), 40 CFR 

63.1575(d), and 40 CFR 63.1575(e). The General Provisions 
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requirement that was cross-referenced requires periodic SSM 

reports as a stand-alone report. In its place, we are proposing 

language that requires sources that fail to meet an applicable 

standard at any time to report the information concerning such 

events in the periodic report already required under each of 

these rules. We are proposing that the report must contain the 

number, date, time, duration, and the cause of such events 

(including unknown cause, if applicable), a list of the affected 

source or equipment, an estimate of the quantity of each 

regulated pollutant emitted over any emission limit, and a 

description of the method used to estimate the emissions. 

Examples of methods that can be used to estimate emissions 

would include product-loss calculations, mass balance 

calculations, measurements when available, or engineering 

judgment based on known process parameters. The EPA is proposing 

this requirement to ensure that there is adequate information to 

determine compliance, to allow the EPA to determine the severity 

of the failure to meet an applicable standard, and to provide 

data that may document how the source met the general duty to 

minimize emissions during a failure to meet an applicable 

standard. 

We will no longer require owners or operators to determine 

whether actions taken to correct a malfunction are consistent 

with an SSM plan, because SSM plans would no longer be required. 
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The proposed rule eliminates the cross-reference to 40 CFR 

63.10(d)(5)(i) that contains the description of the previously 

required SSM report format and submittal schedule from this 

section. These specifications are no longer necessary because 

the events will be reported in otherwise required reports with 

similar format and submittal requirements. 

As noted above, we are proposing to revise the 40 CFR part 

63, subpart CC General Provisions table (Table 6) entries for 

63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one 

entry for 63.10(d)(5) with a “No” in the second column. 

Similarly, we are proposing to revise the 40 CFR part 63, 

subpart UUU General Provisions table (Table 44) entries for 

63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one 

entry for 63.10(d)(5) with a “No” in the third column. Section 

63.10(d)(5)(ii) describes an immediate report for startups, 

shutdown, and malfunctions when a source fails to meet an 

applicable standard but does not follow the SSM plan. We are 

proposing to no longer require owners and operators to report 

when actions taken during a startup, shutdown, or malfunction 

were not consistent with an SSM plan, because such plans would 

no longer be required. 

2. Electronic Reporting 

In this proposal, the EPA is describing a process to 

increase the ease and efficiency of performance test data 
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submittal while improving data accessibility. Specifically, the 

EPA is proposing that owners and operators of petroleum 

refineries submit electronic copies of required performance test 

and performance evaluation reports by direct computer-tocomputer electronic transfer using EPA-provided software. The 

direct computer-to-computer electronic transfer is accomplished 

through the EPA’s Central Data Exchange (CDX) using the 

Compliance and Emissions Data Reporting Interface (CEDRI). The 

CDX is EPA’s portal for submittal of electronic data. The EPAprovided software is called the Electronic Reporting Tool (ERT) 

which is used to generate electronic reports of performance 

tests and evaluations. The ERT generates an electronic report 

package which will be submitted using the CEDRI. The submitted 

report package will be stored in the CDX archive (the official 

copy of record) and the EPA’s public database called WebFIRE. 

All stakeholders will have access to all reports and data in 

WebFIRE and accessing these reports and data will be very 

straightforward and easy (see the WebFIRE Report Search and 

Retrieval link at 

http://cfpub.epa.gov/webfire/index.cfm?action=fire.searchERTSubm

ission). A description and instructions for use of the ERT can 

be found at http://www.epa.gov/ttn/chief/ert/index.html and 

CEDRI can be accessed through the CDX website (www.epa.gov/cdx). 
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A description of the WebFIRE database is available at: 

http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. 

The proposal to submit performance test data electronically 

to the EPA applies only to those performance tests (and/or 

performance evaluations) conducted using test methods that are 

supported by the ERT. The ERT supports most of the commonly used 

EPA reference methods. A listing of the pollutants and test 

methods supported by the ERT is available at: 

http://www.epa.gov/ttn/chief/ert/index.html. 

We believe that industry would benefit from this proposed 

approach to electronic data submittal. Specifically, by using 

this approach, industry will save time in the performance test 

submittal process. Additionally, the standardized format that 

the ERT uses allows sources to create a more complete test 

report resulting in less time spent on data backfilling if a 

source failed to include all data elements required to be 

submitted. Also through this proposal industry may only need to 

submit a report once to meet the requirements of the applicable 

subpart because stakeholders can readily access these reports 

from the WebFIRE database. This also benefits industry by 

cutting back on recordkeeping costs as the performance test 

reports that are submitted to the EPA using CEDRI are no longer 

required to be retained in hard copy, thereby reducing staff 

time needed to coordinate these records. 
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Since the EPA will already have performance test data in 

hand, another benefit to industry is that fewer or less 

substantial data collection requests in conjunction with 

prospective required residual risk assessments or technology 

reviews will be needed. This would result in a decrease in staff 

time needed to respond to data collection requests. 

State, local and tribal air pollution control agencies 

(S/L/Ts) may also benefit from having electronic versions of the 

reports they are now receiving. For example, S/L/Ts may be able 

to conduct a more streamlined and accurate review of electronic 

data submitted to them. For example, the ERT would allow for an 

electronic review process, rather than a manual data assessment, 

therefore, making review and evaluation of the source provided 

data and calculations easier and more efficient. In addition, 

the public stands to benefit from electronic reporting of 

emissions data because the electronic data will be easier for 

the public to access. How the air emissions data are collected, 

accessed and reviewed will be more transparent for all 

stakeholders. 

One major advantage of the proposed submittal of 

performance test data through the ERT is a standardized method 

to compile and store much of the documentation required to be 

reported by this rule. The ERT clearly states what testing 

information would be required by the test method and has the 
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ability to house additional data elements that might be required 

by a delegated authority. 

In addition the EPA must have performance test data to 

conduct effective reviews of CAA sections 111 and 112 standards, 

as well as for many other purposes including compliance 

determinations, emission factor development and annual emission 

rate determinations. In conducting these required reviews, the 

EPA has found it ineffective and time consuming, not only for 

us, but also for regulatory agencies and source owners and 

operators, to locate, collect and submit performance test data. 

In recent years, stack testing firms have typically collected 

performance test data in electronic format, making it possible 

to move to an electronic data submittal system that would 

increase the ease and efficiency of data submittal and improve 

data accessibility. 

A common complaint heard from industry and regulators is 

that emission factors are outdated or not representative of a 

particular source category. With timely receipt and 

incorporation of data from most performance tests, the EPA would 

be able to ensure that emission factors, when updated, represent 

the most current range of operational practices. Finally, 

another benefit of the proposed data submittal to WebFIRE 

electronically is that these data would greatly improve the 

overall quality of existing and new emissions factors by 
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supplementing the pool of emissions test data for establishing 

emissions factors. 

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 would save industry, state, 

local and tribal agencies and the EPA significant time, money 

and effort while also improving the quality of emission 

inventories and air quality regulations. 

In addition, we are proposing that the fenceline data at 

each monitor location (as proposed above) would be reported 

electronically on a semiannual basis. All data reported 

electronically would be submitted to CDX through CEDRI and made 

available to the public. 

3. Technical Amendments to Refinery MACT 1 and 2 

a. Open-Ended Valves and Lines 

Refinery MACT 1 requires an owner or operator to control 

emissions from equipment leaks according to the requirements of 

either 40 CFR part 60, subpart VV or 40 CFR part 63, subpart H. 

For open-ended valves and lines, both subparts require that the 

open end be equipped with a cap, blind flange, plug or second 

valve that “shall seal the open end at all times.” However, 

neither subpart defines “seal” or explains in practical and 

enforceable terms what constitutes a sealed open-ended valve or 
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line. This has led to uncertainty on the part of the owner or 

operator as to whether compliance is being achieved. Inspections 

under the EPA’s Air Toxics LDAR initiative have provided 

evidence that while certain open-ended lines may be equipped 

with a cap, blind flange, plug or second valve, they are not 

operating in a “sealed” manner as the EPA interprets that term. 

In response to this uncertainty, we are proposing to amend 

40 CFR 63.648 to clarify what is meant by “seal.” This proposed 

amendment clarifies that, for the purpose of complying with the 

requirements of 40 CFR 63.648, open-ended valves and lines are 

“sealed” by the cap, blind flange, plug, or second valve when 

there are no detectable emissions from the open-ended valve or 

line at or above an instrument reading of 500 ppm. We solicit 

comment on this approach to reducing the compliance uncertainty 

associated with open-ended valves and lines and our proposed 

amendment. 

b. General Provisions Cross-Referencing 

We have reviewed the application of 40 CFR part 63, subpart 

A (General Provisions) to Refinery MACT 2. The applicable 

requirements of 40 CFR part 63, subpart A are contained in Table 

44 of 40 CFR part 63, subpart UUU. As a result of our review, we 

are proposing several amendments to Table 44 of 40 CFR part 63, 

subpart UUU (in addition to those discussed in section IV.E.1 of 

this preamble that address SSM) to bring the table up-to-date 
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with requirements of the General Provisions that have been 

amended since this table was created, to correct crossreferences, and to incorporate additional sections of the 

General Provisions that are necessary to implement other 

subparts that are cross-referenced by this rule. 

Although we reviewed the application of the General 

Provisions to Refinery MACT 1 and amended Table 6 of 40 CFR part 

63, subpart CC in 2009, we are proposing a few additional 

technical corrections to this table (in addition to those 

discussed in section IV.E.1 of this preamble that address SSM). 

We are not discussing the details of these proposed technical 

corrections in this preamble but the rationale for each change 

to Table 6 of 40 CFR part 63, subpart CC and Table 44 of 40 CFR 

part 63, subpart UUU (including the proposed amendments to 

address SSM discussed above), is included in Docket ID Number 

EPA-HQ-OAR-2010-0682. 

4. Amendments to Refinery NSPS J and Ja 

As discussed in section II.B.2 of this preamble, we are 

addressing a number of technical corrections and clarifications 

for Refinery NSPS J and Ja to address some of the issues raised 

in the petition for reconsideration and to improve consistency 

and clarity of the rule requirements. These issues are addressed 

in detail in API’s amended petition, dated August 21, 2008 (see 

Docket Item Number EPA-HQ-OAR-2007-0011-0246) and the meeting 
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minutes for a September 11, 2008 meeting between EPA and API 

(see Docket Item Number EPA-HQ-OAR-2007-0011-0266). 

a. The Depressurization Work Practice Standard for Delayed 

Coking Units 

HOVENSA and the Industry Petitioners raised several issues 

with the analysis conducted to support the DCU work practice 

standard in Refinery NSPS Ja. With the promulgation and 

implementation of the standards we are proposing for the DCU 

under Refinery MACT 1, the DCU work practice standards in 

Refinery NSPS Ja are not expected to result in any further 

decreases in emissions from the DCU. Any DCU that becomes 

subject to Refinery NSPS Ja would already be in compliance with 

Refinery MACT 1, which is a more stringent standard than the DCU 

work practice standards in Refinery NSPS Ja. As such, we are 

contemplating various ideas for harmonizing the requirements for 

the DCU in these two regulations. One option is to amend 

Refinery NSPS Ja to incorporate the same requirements being 

proposed for Refinery MACT 1 (the DCU work practice standard in 

Refinery NSPS Ja is less stringent than the proposed 

requirements for Refinery MACT 1). Another option we are 

contemplating is deleting the DCU work practice standard within 

Refinery NSPS Ja once the DCU standards in Refinery MACT 1 are 

promulgated and fully implemented. We believe deletion of this 

work practice standard is consistent with the objectives of 
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Executive Order 13563, “Improving Regulation and Regulatory 

Review.” We solicit comment on these options as well as any 

other comments regarding the interaction between the DCU 

requirements in these two rules (i.e., the need to keep the DCU 

work practice standard in Refinery NSPS Ja after promulgation of 

these revisions to Refinery MACT 1.) 

b. Technical Corrections and Clarifications 

In addition to their primary issues, the Industry 

Petitioners enumerated several points of clarification and 

recommended amendments to Refinery NSPS J and Ja. These issues 

are addressed in detail in API’s amended petition for 

reconsideration, dated August 21, 2008 (see Docket Item Number 

EPA-HQ-OAR-2007-0011-0246) and the meeting minutes for a 

September 11, 2008 meeting between EPA and API (see Docket Item 

Number EPA-HQ-OAR-2007-0011-0266). We are including several 

proposed amendments in this rulemaking to specifically address 

these issues. These amendments are discussed in the remainder of 

this section. We are addressing these issues now while we are 

proposing amendments for Refinery MACT 2 in an effort to improve 

consistency and clarity for sources regulated under both the 

NSPS and Refinery MACT 2. 

We are proposing a series of amendments to the requirements 

for sulfur recovery plants in 40 CFR 60.102a, to clarify the 

applicable emission limits for different types of sulfur 
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recovery plants based on whether oxygen enrichment is used. 

These amendments also clarify that emissions averaging across a 

group of emission points within a given sulfur recovery plant is 

allowed from each of the different types of sulfur recovery 

plants, and that emissions averaging is specific to the SO2 or 

reduced sulfur standards (and not to the H2S limit). The 10 ppmv 

H2S limit for reduction control systems not followed by 

incineration must be met on a release point-specific basis. 

These amendments are being made to clarify the original intent 

of the Refinery NSPS Ja requirements for sulfur recovery plants. 

We are proposing a series of corresponding amendments in 40 

CFR 60.106a to clarify the monitoring requirements, particularly 

when oxygen enrichment or emissions averaging is used. The 

monitoring requirements in Refinery NSPS Ja were incomplete for 

these provisions and did not specify all of the types of 

monitoring devices needed for implementation. We are also 

proposing in 40 CFR 60.106a to 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. The term “reduced 

sulfur compounds” is a defined term in Refinery NSPS Ja, and the 

emissions limit for sulfur recovery plants with reduction 

control systems not followed by incineration is specific to 
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“reduced sulfur compounds.” Therefore, the proposed amendments 

to the monitoring provisions provide clarification of the 

requirements by using a consistent, defined term. 

We are proposing amendments to 40 CFR 60.102a(g)(1) to 

clarify that CO boilers, while part of the FCCU affected 

facility, can also be fuel gas combustion devices (FGCD). 

Industry Petitioners suggested that the CO boiler should only be 

subject to the FCCU NOX and SO2 limits and should not be 

considered a FGCD. While Refinery NSPS Ja clearly states that 

the coke burn-off exhaust from the FCCU catalyst regenerator is 

not considered to be fuel gas, other fuels combusted in the CO 

boiler must meet the H2S concentration requirements for fuel gas 

like any other FGCD. This amendment is provided to clarify our 

original intent with respect to fuel gas. Industry Petitioners 

also noted that some CO boiler “furnaces” may be used as process 

heaters rather than steam-generating boilers. While we did not 

originally contemplate that CO furnaces would be used as process 

heaters, available data from the detailed ICR suggests that 

there are a few CO furnaces used as process heaters. These CO 

furnaces are all forced-draft process heaters, and the newly 

amended NOX emissions limit in Refinery NSPS Ja for forced-draft 

process heaters is 60 ppmv, averaged over a 30-day period. Given 

the longer averaging time of the process heater NOX limits, these 

two emission limits (for FCCU NOX and for process heater NOX) are 
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reasonably comparable and are not expected to result in a 

significant difference in the control systems selected for 

compliance. As such, we are not amending or clarifying the NOX

standards for the FCCU or process heaters at this time. We are, 

however, clarifying (through this response) that if an emission 

source meets the definition of more than one affected facility, 

that source would need to comply with all requirements 

applicable to the emissions source. 

We are proposing to revise the annual testing requirement 

in 40 CFR 60.104a(b) to clarify our original intent. Instead of 

requiring a PM performance test at least once every 12 months, 

the rule would require a PM performance test annually and 

specify that annually means once per calendar year, with an 

interval of at least 8 months but no more than 16 months between 

annual tests. This provision will ensure that testing is 

conducted at a reasonable interval while giving owners and 

operators flexibility in scheduling the testing. We are also 

proposing 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 per 

coke burn-off emissions limit (rather than just the PM limit) in 

40 CFR 60.102a(b)(1), to clarify that facilities electing to 

comply with the concentration limit using a PM CEMS would not 

also be required to install a COMS. We are also proposing to 
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amend 40 CFR 60.104a(j) to delete the requirements to measure 

flow for the H2S concentration limit for fuel gas, as these are 

not needed in the performance evaluation. 

We are proposing 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 are also proposing amendments to 40 CFR 60.105a(i) to 

include 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. These proposed 

amendments are necessary so that periods when the APCD operation 

is compromised are properly managed and/or reported. 

We are proposing amendments to 40 CFR 60.105(b)(1)(iv) and 

60.107a(b)(1)(iv) to allow using tubes with a maximum span 

between 10 and 40 ppmv, inclusive, when 1≤N≤10, where N = number 

of pump strokes rather than requiring use of tubes with ranges 

0–10/0–100 ppm (N = 10/1) because different length-of-stain tube 

manufacturers have different span ranges, and none of the 

commercially-available tubes have a specific span of 0–10/0–100 

ppm (N = 10/1). We are also proposing to amend 40 CFR 
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60.105(b)(3)(iii) and 40 CFR 60.107a(b)(3)(iii) to specify that 

the temporary daily stain sampling must be made using length-of 

stain tubes with a maximum span between 200 and 400 ppmv, 

inclusive, when 1≤N≤5, where N = number of pump strokes. This 

proposed amendment clarifies this monitoring requirement, 

ensures the proper tube range is used, and provides some 

flexibility in span range to accommodate different manufacturers 

of the length-of-stain tubes. We also propose to delete the last 

sentence in 40 CFR 60.105(b)(3)(iii), as there is no long-term 

H2S concentration limit in Refinery NSPS J. 

We are proposing to clarify that flares are subject to the 

performance test requirements. We are also proposing to clarify 

those performance test requirements in 40 CFR 60.107a(e)(1)(ii) 

and 40 CFR 60.107a(e)(2)(ii) to remove the distinction between 

flares with or without routine flow. The term “routine flow” is 

not defined and it is difficult to make this distinction in 

practice. 

F. What compliance dates are we proposing? 

Amendments to Refinery MACT 1 and 2 proposed in this 

rulemaking for adoption under CAA section 112(d)(2) and (3) and 

CAA section 112(d)(6) are subject to the compliance deadlines 

outlined in the CAA under section 112(i). For all of the 

requirements we are proposing under CAA section 112(d)(2) and 

(3) or CAA section 112(d)(6) except for storage vessels, which 
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we are also requiring under 112 (f)(2), we are proposing the 

following compliance dates. As provided in CAA section 112(i), 

new sources would be required to comply with these requirements 

by the effective date of the final amendments to Refinery MACT 1 

and 2 or startup, whichever is later. 

For existing sources, CAA section 112(i) provides that the 

compliance date shall be as expeditiously as practicable, but no 

later than 3 years after the effective date of the standard. In 

determining what compliance period is as expeditious as 

practicable, we consider the amount of time needed to plan and 

construct projects and change operating procedures. Under CAA 

section 112(d)(2) and (3), we are proposing new operating 

requirements for DCU. In order to comply with these new 

requirements, we project that most DCU owners or operators would 

need to install additional controls (e.g., steam ejector 

systems). Similarly, the proposed revision in the CRU pressure 

limit exclusions would require operational changes and, in some 

cases, additional controls. The addition of new control 

equipment would require engineering design, solicitation and 

review of vendor quotes, contracting and installation of the 

equipment, which would need to be timed with process unit outage 

and operator training. Therefore, we are proposing that it is 

necessary to provide 3 years after the effective date of the 
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final rule for these sources to comply with the DCU and CRU 

requirements. 

We are proposing new operating and monitoring requirements 

for flares under CAA section 112(d)(2) and (3). We anticipate 

that these requirements would require the installation of new 

flare monitoring equipment and we project most refineries would 

install new control systems to monitor and adjust assist gas 

(air or steam) addition rates. Similar to the addition of new 

control equipment, these new monitoring requirements for flares 

would require engineering evaluations, solicitation and review 

of vendor quotes, contracting and installation of the equipment, 

and operator training. Installation of new monitoring and 

control equipment on flares will require the flare to be taken 

out of service. Depending on the configuration of the flares and 

flare header system, taking the flare out of service may also 

require a significant portion of the refinery operations to be 

shut down. Therefore, we are proposing that it is necessary to 

provide 3 years after the effective date of the final rule for 

owners or operators to comply with the new operating and 

monitoring requirements for flares. 

Under CAA section 112(d)(2) and (3), we are proposing new 

vent control requirements for bypasses. These requirements would 

typically require the addition of piping and potentially new 

control requirements. As these vent controls would most likely 
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be routed to the flare, we are proposing to provide 3 years 

after the effective date of the final rule for owners or 

operators to afford coordination of these bypass modifications 

with the installation of the new monitoring equipment for the 

flares. 

Under our technology review, we are proposing to require 

fenceline monitoring pursuant to CAA section 112(d)(6). These 

proposed provisions would require refinery owners or operators 

to install a number of monitoring stations around the facility 

fenceline. While the diffusive tube sampling system is 

relatively low-tech and is easy to install, site-specific 

factors must be considered in the placement of the monitoring 

systems. We also assume all refinery owners or operators would 

invest in the analytical equipment needed to perform automated 

sample analysis on-site and time is needed to select an 

appropriate vendor for this equipment. Furthermore, additional 

monitoring systems may be needed to account for near-field 

contributing sources, for which the development and approval of 

a site-specific monitoring plan. Considering all of the 

requirements needed to implement the fenceline monitoring 

system, we are proposing to provide 3 years from the effective 

date of the final rule for refinery owners or operators to 

install and begin collecting ambient air samples around the 
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fenceline of their facility following an approved (if necessary) 

site-specific monitoring plan. 

As a result of our technology review for equipment leaks, 

we are proposing to allow the use of optical gas imaging devices 

in lieu of using EPA Method 21 of 40 CFR part 60, Appendix A-7 

without the annual compliance demonstration with EPA Method 21 

as required in the AWP (see 73 FR 73202, December 22, 2008), 

provided that the owner and operator follows the provisions of 

Appendix K to 40 CFR part 60. Facilities could begin to comply 

with the optical gas imaging alternative as soon as Appendix K 

to 40 CFR part 60 is promulgated. Alternatively, as is currently 

provided in the AWP, the refinery owner or operator can elect to 

use the optical gas imaging monitoring option prior to 

installation and use of the fenceline monitoring system, 

provided they conduct an annual compliance demonstration using 

EPA Method 21 as required in the AWP. 

Under our technology review for marine vessel loading 

operations, we are proposing to add a requirement for submerged 

filling for small and for offshore marine vessel loading 

operations. We anticipate that the submerged fill pipes are 

already in place on all marine vessels used to transport 

petroleum refinery liquids, so we are proposing that existing 

sources comply with this requirement on the effective date of 

the final rule. We request comment regarding the need to provide 
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additional time to comply with the submerged filling 

requirement; please provide in your comment a description of the 

vessels loaded that do not already have a submerged fill pipe, 

how these vessels comply with (or are exempt from) the Coast 

Guard requirements at 46 CFR 153.282, and an estimate of the 

time needed to add the required submerged fill pipes to these 

vessels. 

We are also proposing to require FCCU owners and operators 

currently subject to Refinery NSPS J (or electing that 

compliance option in Refinery MACT 2) to transition from the 

Refinery NSPS J option to one of the alternatives included in 

the proposed rule. We are also proposing altering the averaging 

times for some of the operating limits. A PM performance test is 

needed in order to establish these new operating limits prior to 

transitioning to the proposed requirements. Additionally, we are 

proposing that a PM performance test be conducted for each FCCU 

once every 5 years. We do not project any new control or 

monitoring equipment will be needed in order to comply with the 

proposed provisions; however, compliance with the proposed 

provisions is dependent on conducting a performance test. 

Establishing an early compliance date for the first performance 

test can cause scheduling issues as refinery owners or operators 

compete for limited number of testing contractors. Considering 

these scheduling issues, we propose to require the first 
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performance test for PM and compliance with the new operating 

limits be completed no later than 18 months after the effective 

date of the final rule. 

In this action, we are proposing revisions to the SSM 

provisions of Refinery MACT 1 and 2, including specific startup 

or shutdown standards for certain emission sources, and we are 

proposing electronic reporting requirements in Refinery MACT 1 

and 2. The proposed monitoring requirements associated with the 

new startup and shutdown standards are expected to be present on 

the affected source, so we do not expect that owners or 

operators will need additional time to transition to these 

requirements. Similarly, the electronic reporting requirements 

are not expected to require a significant change in operation or 

equipment, so these requirements should be able to be 

implemented more quickly than those that require installation of 

new control or monitoring equipment. Based on our review of 

these requirements, we propose that these requirements become 

effective upon the effective date of the final rule. 

Finally, we are proposing additional requirements for 

storage vessels under CAA sections 112(d)(6) and (f)(2). The 

compliance deadlines for standards developed under CAA section 

112(f)(2) are delineated in CAA sections 112(f)(3) and (4). As 

provided in CAA section 112(f)(4), risk standards shall not 

apply to existing sources until 90 days after the effective date 
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of the rule, but the Administrator may grant a waiver for a 

particular source for a period of up to 2 years after the 

effective date. While additional controls will be necessary to 

comply with the proposed new control and fitting requirements 

for storage vessels, the timing for installation of these 

controls is specified within the Generic MACT (40 CFR part 63, 

subpart WW). Therefore, we propose that these new requirements 

for storage vessels become effective 90 days following the 

effective date of the final rule. 

V. Summary of Cost, Environmental and Economic Impacts 

A. What are the affected sources, the air quality impacts and 

cost impacts? 

The sources affected by significant amendments to the 

petroleum refinery standards include storage vessels, equipment 

leaks, fugitive emissions and DCU subject to Refinery MACT 1. 

The proposed 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 proposed 

amendments and standards is estimated at $239 million, $82.8 

million from proposed amendments and $156 million from standards 

to ensure compliance. We estimate annualized costs to be 

approximately $4.53 million, which includes an estimated $14.4 

million credit for recovery of lost product and the annualized 
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cost of capital. We also estimate annualized costs of the 

proposed standards to ensure compliance to be approximately 

$37.9 million. The proposed amendments would achieve a 

nationwide HAP emission reduction of 1,760 tpy, with a 

concurrent reduction in VOC emissions of 18,800 tpy. Table 13 of 

this preamble summarizes the cost and emission reduction impacts 

of the proposed amendments, and Table 14 of this preamble 

summarizes the costs of the proposed standards to ensure 

compliance. 

Table 13. Nationwide Impacts of Proposed Amendments 

Affected 

source 

Total 

capital 

investment 

(million 

$) 

Total 

annualized 

cost 

without 

credit 

(million 

$/yr) 

Product 

recovery 

credit 

(million 

$/yr) 

Total 

annualized 

costs 

(million 

$/ yr) 

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 52.0 10.2 (6.20) 3.98 4,250 937 850 4,680 

Fugitive 

Emissions 

(Fenceline 

Monitoring) 12.2 5.58 -- 5.58 

Total 82.8 18.9 (14.4) 4.53 18,800 241 1,760 2,570 

Table 14. Nationwide Costs of Proposed Amendments to Ensure 

Compliance 

Affected source 

Total capital 

investment 

(million $) 

Total 

annualized 

cost without 

credit 

(million $/yr)

Product 

recovery 

credit 

(million 

$/yr) 

Total 

annualized 

costs 

(million $/ 

yr) 
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Relief Valve 

Monitoring 9.54 1.36 -- 1.36 

Flare Monitoring 147 36.3 -- 36.3 

FCCU Testing -- 0.21 -- 0.21 

Total 156 37.9 -- 37.9 

Note that any corrective actions taken in response to the 

fenceline monitoring program are not included in the impacts 

shown in Table 13. Any corrective actions associated with 

fenceline monitoring will result in additional emission 

reductions and additional costs. 

The impacts shown in Table 14 do not consider emission 

reductions associated with relief valve or flare monitoring 

provisions or emission reductions that may occur as a result of 

the additional FCCU testing requirements. The proposed 

operational and monitoring requirements for flares at refineries 

have the potential to reduce excess emissions from flares by 

approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 

metric tonnes per year of CO2e. When added to the reductions in 

CO2e achieved from proposed controls on DCU, these proposed 

amendments are projected to result in reductions of 670,000 

metric tonnes of CO2e due to reductions of methane emissions.42

 

42 The flare operational and monitoring requirements are projected to reduce 

methane emissions by 29,500 tpy while increasing CO2 emissions by 260,000 tpy, 

resulting in a net GHG reduction of 327,000 metric tonnes per year of CO2e, 

assuming a global warming potential of 21 for methane. Combined with methane 

emissions reduction of 18,000 tpy from the proposed controls on DCU, the 

overall GHG reductions of the proposed amendments is 670,000 metric tonnes 

per year of CO2e assuming a global warming potential of 21 for methane. 
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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 much less than 1 percent of 

their sales. For all firms, the minimum cost-to-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 costto-sales ratio is 0.62 percent; and the mean cost-to-sales ratio 

is 0.07 percent. 

More information and details of this analysis are 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 proposed rule (Docket ID Number EPA-HQ-OAR2010-0682). 
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C. What are the benefits? 

The proposed rule is anticipated to result in a reduction 

of 1,760 tons of HAP (based on allowable emissions under the 

MACT standards) and 18,800 tons of VOC emissions per year, not 

including potential emission reductions that may occur as a 

result of the proposed provisions for flares or 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. 

VI. Request for Comments 

We solicit comments on all aspects of this proposed action. 

In addition to general comments on this proposed action, we are 

also interested in additional data that may improve the risk 

assessments and other analyses. We are specifically interested 

in receiving any improvements to the data used in the sitespecific emissions profiles used for risk modeling. Such data 

should include supporting documentation in sufficient detail to 

allow characterization of the quality and representativeness of 

the data or information. Section VII of this preamble provides 

more information on submitting data. 
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VII. Submitting Data Corrections 

The site-specific emissions profiles used in the source 

category risk and demographic analyses and instructions are 

available on the RTR web page at: 

http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. The data files 

include detailed information for each HAP emissions release 

point for the facilities in the source categories. 

If you believe that the data are not representative or are 

inaccurate, please identify the data in question, provide your 

reason for concern and provide any “improved” data that you 

have, if available. When you submit data, we request that you 

provide documentation of the basis for the revised values to 

support your suggested changes. To submit comments on the data 

downloaded from the RTR page, complete the following steps: 

1. Within this downloaded file, enter suggested revisions 

to the data fields appropriate for that information. 

2. Fill in the commenter information fields for each 

suggested revision (i.e., commenter name, commenter 

organization, commenter email address, commenter phone number 

and revision comments). 

3. Gather documentation for any suggested emissions 

revisions (e.g., performance test reports, material balance 

calculations). 
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4. Send the entire downloaded file with suggested 

revisions in Microsoft® Access format and all accompanying 

documentation to Docket ID Number EPA-HQ-OAR-2010-0682 (through 

one of the methods described in the ADDRESSES section of this 

preamble). 

5. If you are providing comments on a single facility or 

multiple facilities, you need only submit one file for all 

facilities. The file should contain all suggested changes for 

all sources at that facility. We request that all data revision 

comments be submitted in the form of updated Microsoft® Excel 

files that are generated by the Microsoft® Access file. These 

files are provided on the RTR web Page at: 

http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. 

VIII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

Under Executive Order 12866 (58 FR 51735, October 4, 1993), 

this action is a “significant regulatory action” because it 

raises novel legal and policy issues. Accordingly, the EPA 

submitted this action to the Office of Management and Budget 

(OMB) for review under Executive Orders 12866 and 13563 (76 FR 

3821, January 21, 2011) and any changes made in response to OMB 
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recommendations have been documented in the docket for this 

action (Docket ID Number EPA-HQ-OAR-2010-0682). 

B. Paperwork Reduction Act 

The information collection requirements in this rule have 

been submitted for approval to OMB under the Paperwork Reduction 

Act, 44 U.S.C. 3501, et seq. 

Revisions and burden associated with amendments to 40 CFR 

part 63, subparts CC and UUU are discussed in the following 

paragraphs. OMB has previously approved the information 

collection requirements contained in the existing regulations in 

40 CFR part 63, subparts CC and UUU under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 3501, et seq., OMB control 

numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR 

part 9. 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 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 53,619 hours; the frequency of response is semiannual 

for all 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 
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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 $17 

million, which includes monitoring equipment for bypass valves, 

fenceline monitoring, relief valves, and flares), a total 

operation and maintenance component (about $16 million per year 

for fenceline and flare monitoring), and a labor cost component 

(about $4.5 million per year, the cost of the additional 53,619 

labor hours). 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 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 1844.05. Burden 

changes associated with these amendments would result from new 

testing, recordkeeping and reporting requirements being proposed 

with this action. The estimated average burden per response is 

26 hours; the frequency of response is both once and 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 $356,000 

per year over the first 3 years for the initial performance test 

and $213,000 per year starting in the fourth year), and a labor 
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cost component (approximately $238,000 per year for 2,860 

additional labor hours). 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. 

To comment on the agency’s need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes the 

ICR, under Docket ID Number EPA-HQ-OAR-2010-0682. Submit any 

comments related to the ICR to the EPA and OMB. See the 

ADDRESSES section at the beginning of this preamble for where to 

submit comments to the EPA. Send comments to OMB at the Office 

of Information and Regulatory Affairs, Office of Management and 

Budget, 725 17th Street, NW, Washington, DC 20503, Attention: 

Desk Office for the EPA. Since OMB is required to make a 

decision concerning the ICR between 30 and 60 days after [INSERT 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB 

is best assured of having its full effect if OMB receives it by 

[INSERT DATE 30 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER]. The final rule will respond to any OMB or public 

comments on the information collection requirements contained in 

this proposal. 
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C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities 

(SISNOSE). Small entities include small businesses, small 

organizations and small governmental jurisdictions. For purposes 

of assessing the impacts of this proposed 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-for-profit enterprise which is independently 

owned and operated and is not dominant in its field. 

After considering the economic impacts of this proposed 

rule on small entities, I certify that this action will not have 

a significant economic impact on a substantial number of small 

entities. The small entities subject to the requirements of this 

proposed rule are small refiners. We have determined that 36 

companies (59 percent of the 61 total) employ fewer than 1,500 
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workers and are considered to be small businesses. For small 

businesses, the average cost-to-sales ratio is about 0.05 

percent, the median cost-to-sales ratio is 0.02 percent and the 

maximum cost-to-sales ratio is 0.55 percent. The potential costs 

do not have a more significant impact on small refiners and 

because no small firms are expected to have cost-to-sales ratios 

greater than 1 percent, we determined that the cost impacts for 

this rulemaking will not have a SISNOSE. 

Although not required by the RFA to convene a Small 

Business Advocacy Review (SBAR) Panel; because the EPA has 

determined that this proposal would not have a significant 

economic impact on a substantial number of small entities, the 

EPA originally convened a panel to obtain advice and 

recommendations from small entity representatives potentially 

subject to this rule’s requirements. The panel was not formally 

concluded; however, a summary of the outreach conducted and the 

written comments submitted by the small entity representatives 

can be found in the docket for this proposed rule (Docket ID 

Number EPA-HQ-OAR-2010-0682). 

We continue to be interested in the potential impacts of 

the proposed rule on small entities and welcome comments on 

issues related to such impacts. 
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D. Unfunded Mandates Reform Act 

This proposed rule does not contain a federal mandate under 

the provisions of Title II of the Unfunded Mandates Reform Act 

of 1995 (UMRA), 2 U.S.C. 1531-1538 that may result in 

expenditures of $100 million or more for state, local and tribal 

governments, in the aggregate, or the private sector in any one 

year. As discussed earlier in this preamble, these amendments 

result in nationwide costs of $42.4 million per year for the 

private sector. Thus, this proposed rule is not subject to the 

requirements of sections 202 or 205 of the UMRA. 

This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments because it contains no requirements that apply to 

such governments and does not impose obligations upon them. 

E. Executive Order 13132: Federalism 

This rule 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, as specified in Executive Order 

13132. None of the facilities subject to this action are owned 

or operated by state governments, and, because no new 

requirements are being promulgated, nothing in this proposal 
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will supersede state regulations. Thus, Executive Order 13132 

does not apply to this rule. 

In the spirit of Executive Order 13132, and consistent with 

the EPA policy to promote communications between the EPA and 

state and local governments, the EPA specifically solicits 

comment on this proposed rule from state and local officials. 

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments 

This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). It 

will not have substantial direct effects on tribal governments, 

on the relationship between the federal government and Indian 

tribes, or on the distribution of power and responsibilities 

between the federal government and Indian tribes as specified in 

Executive Order 13175. Thus, Executive Order 13175 does not 

apply to this action. 

Although Executive Order 13175 does not apply to this 

action, the EPA consulted with tribal officials in developing 

this action. The EPA sent out letters to tribes nationwide to 

invite them to participate in a tribal consultation meeting and 

solicit their input on this rulemaking. The EPA conducted the 

tribal consultation meeting on December 14, 2011. Participants 

from eight tribes attended the meeting, but they were interested 

only in outreach, and none of the tribes had delegation for 
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consultation. The EPA presented all the information prepared for 

the consultation and conducted a question and answer session 

where participants asked clarifying questions about the 

information that was presented and generally expressed their 

support of the rulemaking requirements. 

The EPA specifically solicits additional comment on this 

proposed action 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 (62 FR 

19885, April 23, 1997) because it is not economically 

significant as defined in Executive Order 12866, and because the 

agency 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 sections III.A and B and sections IV.C and D of 

this preamble. 

The public is invited to submit comments or identify peerreviewed studies and data that assess effects of early life 

exposure to emissions from petroleum refineries. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

This action is not a “significant energy action” as defined 

under Executive Order 13211 (66 FR 28355, May 22, 2001), because 
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it is not likely to have significant adverse effect on the 

supply, distribution or use of energy. The overall economic 

impact of this proposed rule should be minimal for the refining 

industry and its consumers. 

I. National Technology Transfer and Advancement Act 

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) 

(15 U.S.C. 272 note) directs the EPA to use voluntary consensus 

standards (VCS) in its regulatory activities unless to do so 

would be inconsistent with applicable law or otherwise 

impractical. VCS are technical standards (e.g., materials 

specifications, test methods, sampling procedures, and business 

practices) that are developed or adopted by VCS bodies. The 

NTTAA directs the EPA to provide Congress, through OMB, 

explanations when the agency decides not to use available and 

applicable VCS. 

This proposed rulemaking involves technical standards. The 

EPA proposes to use ISO 16017-2, “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” as an acceptable alternative to EPA Method 325A. This 

method is available at http://www.iso.org. This method was 

chosen because it meets the requirements of EPA Method 301 for 
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equivalency, documentation and validation data for diffusive 

tube sampling. 

The EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 

potentially-applicable VCS and to explain why such standards 

should be used in this regulation. 

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 United 

States. 

The EPA has determined that this proposed 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 
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environmental effects on any population, including any minority, 

low-income or indigenous populations. Further, the EPA believes 

that implementation of the provisions of this rule will provide 

an ample margin of safety to protect public health of all 

demographic groups. 

To examine the potential for any environmental justice 

issues that might be associated with the refinery source 

categories associated with today’s proposed rule, we evaluated 

the percentages of various social, demographic and economic 

groups within the at-risk populations living near the facilities 

where these source categories 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 groups. In addition, the population living within 

50 km of the 142 petroleum refineries has a higher percentage of 

minority, lower income and lower education persons when compared 

to the nationwide percentages of those groups. These groups 

stand to benefit the most from the emission reductions achieved 

by this proposed rulemaking, and this proposed rulemaking is 

projected to result in 1 million fewer people exposed to risks 

greater than 1-in-1 million. 
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The EPA defines “Environmental Justice” to include 

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. To promote meaningful involvement, the 

EPA conducted numerous outreach activities and discussions, 

including targeted outreach (such as conference calls and 

webinars) to communities and environmental justice 

organizations. In addition, after the rule is proposed, the EPA 

will be conducting a webinar to inform the public about the 

proposed rule and to outline how to submit written comments to 

the docket. Further stakeholder and public input is expected 

through public comment and follow-up meetings with interested 

stakeholders. 
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Petroleum Refinery Sector Risk and Technology Review and New 

Source Performance Standards 

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List of Subjects in 40 CFR Part 60 

Environmental protection, Administrative practice and 

procedure, Air pollution control, Incorporation by reference, 

Intergovernmental relations, Reporting and recordkeeping 

requirements. 

List of Subjects in 40 CFR Part 63 

Environmental protection, Air pollution control, Hazardous 

substances, Incorporation by reference, Reporting and 

recordkeeping requirements, Volatile organic compounds. 

____________________________ 

Dated: 

____________________________ 

Gina McCarthy, 

Administrator.
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For the reasons stated in the preamble, title 40, chapter 

I, of the Code of Federal Regulations is proposed to be amended 

as follows: 

PART 60--[AMENDED] 

1. The authority citation for part 60 continues to read as 

follows: 

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

Subpart J--[AMENDED] 

2. Section 60.105 is amended by: 

a. Revising paragraph (b)(1)(iv) and 

b. Revising paragraph (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 
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Processors Association Standard 2377-86, Test for Hydrogen 

Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain 

Tubes,” 1986 Revision (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 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 paragraphs 

(a)(1) or (a)(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. 

* * * * * 
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Subpart Ja--[AMENDED] 

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, 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” to 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 
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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: 

a. Revising paragraphs (b)(1)(i) and (iii); 

b. Revising paragraph (f); and 

c. Revising paragraph (g)(1). 

The revisions 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. 

* * * * * 
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(iii) 1.0 g/kg (1 lb/1,000 lb) 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 for each affected FCU. 

* * * * * 

(f) Except as provided in paragraph (f)(3), each owner or 

operator of an affected sulfur recovery plant shall comply with 

the applicable emission limits in paragraphs (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 

paragraphs (f)(1)(i) or (f)(1)(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 paragraphs (f)(1)(i) or (f)(1)(ii) of this section 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 paragraphs (f)(1)(i) or 

(f)(1)(ii) of this section for each process train or release 

point individually. For a sulfur recovery plant with a design 
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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. 

 0.038   % 11.53 % 25.6 2

2 ELS  k1    O2   O  (Eq. 1) 

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 
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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 nonClaus 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. 

(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 paragraphs (f)(2)(i) or 

(f)(2)(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 
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the applicable emission limit in paragraphs (f)(2)(i) or 

(f)(2)(ii) of this section 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 

paragraphs (f)(2)(i) or (f)(2)(ii) of this section 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. 
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 0.38   % 115.3 % 256 2

2 ESS  k1    O2   O  (Eq. 2) 

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 nonClaus 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 
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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) 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) of this 

section for all fuel gas streams combusted in these units. 

* * * * * 

6. Section 60.104a is amended by: 

a. Revising the first sentence of paragraph (a); 

b. Revising paragraph (b); 

c. Revising paragraph (f) introductory text; 
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d. Revising paragraph (h) introductory text; 

e. Adding paragraph (h)(6); and 

f. 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. 

* * * * * 
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(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 60.102a(f)(2)(i) and the reduced sulfur 

compounds and H2S emissions limits for sulfur recovery plants in 

§§60.102a(f)(1)(ii), 60.102a(f)(1)(iii), 60.102a(f)(2)(ii) and 

60.102a(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 during 

the test runs using the procedures in §60.106a(a)(5) or (6). 

* * * * * 

7. Section 60.105a is amended by: 

a. Revising paragraph (b)(1)(i); 

a. Revising paragraph (b)(1)(ii)(A); 
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b. Revising paragraph (b)(2); 

c. Revising paragraph (h)(1); 

d. Revising paragraph (h)(3)(i) 

e. Revising paragraph (i)(1); 

f. Redesignating paragraphs (i)(2) through (6) as (i)(3) 

through (7); 

g. Adding paragraph (i)(2); and 

h. 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 
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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 §60.105a(h)(3). 

(i) The owner or operator shall install, operate, and 

maintain each CO2 and O2 monitor according to Performance 

Specification 3 of Appendix B to part 60. 

(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 part 60. The owner or operator shall use Method 3 

of Appendix A–3 to part 60 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 part 60. 
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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 part 60. The owner or operator 

shall use Method 10, 10A, or 10B of Appendix A–3 to part 60 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 part 60, 

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 part 60. The span value for this 

instrument is 1,000 ppmv CO. 
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* * * * * 

(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 part 60. 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 part 60 and employ the sample conditioning 

system of Method 10A of appendix A-4 to part 60, the alternative 

relative accuracy test procedure in section 10.1 of Performance 

Specification 2 of appendix B to part 60 may be used in place of 

the relative accuracy test. 

* * * * * 

(i) * * * 

(1) If a CPMS is used according to §60.105a(b)(1), all 3-

hour periods during which the average PM control device 

operating characteristics, as measured by the continuous 

monitoring systems under §60.105a(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 
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pressure readings are not corrected within 12 hours of 

identification. 

(2) If a bag leak detection system is used according to 

§60.105a(c), each day in which the cause of an alarm is not 

alleviated within the time period specified in §60.105a(c)(3). 

* * * * * 

(7) All 1-hour periods during which the average CO 

concentration as measured by the CO continuous monitoring system 

under §60.105a(h) 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 

§60.105a(h)(4) 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 paragraph (a)(2) introductory text; 

d. Revising paragraphs (a)(2)(i) and (ii); 

e. Revising the first sentence of paragraph (a)(2)(iii); 

f. Removing paragraphs (a)(2)(iv) and (v); 

g. Redesignating (a)(2)(vi) through (ix) as (a)(2)(iv) 

through (vii); 
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h. Revising the first sentence of paragraph (a)(3) 

introductory text; 

i. Revising paragraph (a)(3)(i); 

j. Adding paragraphs (a)(4) through (7); and 

k. 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 part 60. 

(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 part 

60. The owner or operator shall use Methods 3, 3A, or 3B of 

Appendix A–2 to part 60 for conducting the relative accuracy 
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evaluations. The method ANSI/ASME PTC 19.10–1981, “Flue and 

Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is 

an acceptable alternative to EPA Method 3B of Appendix A–2 to 

part 60. 

(vii) The owner or operator shall comply with the 

applicable quality assurance procedures of Appendix F to part 60 

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 

§60.102a(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 part 60. 
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(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 part 60. * * * 

* * * * * 

(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 §60.102a(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). 
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(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 part 60. 

(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 part 

60. The owner or operator shall use Methods 11 or 15 of appendix 

A–5 to part 60 or Method 16 of appendix A–6 to part 60 for 

conducting the relative accuracy evaluations. The method 

ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses,” 

(incorporated by reference—see §60.17) is an acceptable 

alternative to EPA Method 15A of appendix A–5 to part 60. 

(iv) The owner or operator shall install, operate, and 

maintain each O2 monitor according to Performance Specification 3 

of appendix B to part 60. 

(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 part 

60. The owner or operator shall use Methods 3, 3A, or 3B of 

appendix A–2 to part 60 for conducting the relative accuracy 
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evaluations. The method ANSI/ASME PTC 19.10–1981, “Flue and 

Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is 

an acceptable alternative to EPA Method 3B of appendix A–2 to 

part 60. 

(vii) The owner or operator shall comply with the 

applicable quality assurance procedures of appendix F to part 60 

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 part 60. 

(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 part 

60. The owner or operator shall use Methods 3, 3A, or 3B of 
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appendix A–2 to part 60 for conducting the relative accuracy 

evaluations. The method ANSI/ASME PTC 19.10–1981, “Flue and 

Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is 

an acceptable alternative to EPA Method 3B of appendix A–2 to 

part 60. 

(iv) The owner or operator shall comply with the applicable 

quality assurance procedures of appendix F to part 60 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 oxygenenriched 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. 
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(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) The owner or operator shall install locate the monitor 

in a position that provides a representative measurement of the 

total gas flow rate. 

(B) Use a flow sensor with a measurement sensitivity of no 

more than 5 percent of the flow rate 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. 
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(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: 



















   

air oxy

air oxy oxy

Q Q

Q O Q O 2,

2

20.9 %

% (Eq. 10) 

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 this section 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). 
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(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 §60.102a(f)(2)(i) or the reduced sulfur compounds emission 

limit in §60.102a(f)(1)(ii) or §60.102a(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) The owner or operator shall install locate the monitor 

in a position that provides a representative measurement of the 

total gas flow rate. 

(B) Use a flow sensor with a measurement sensitivity of no 

more than 5 percent of the flow rate 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. 
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(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: 

  

    c adj meas

O Q Q 20.920.9 % 2 (Eq. 11) 

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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 











 N

n

adj n

N

n

n adj n

ave

Q

C Q

C

1

,

1

,

 (Eq. 12) 

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 §60.102a(f)(2)(i)] or reduced sulfur 

compounds [if complying with the reduced sulfur compounds 

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

§60.102a(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 paragraphs (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). 
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(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: 

a. Revising paragraphs (a)(1)(i) and (ii); 

b. Revising paragraph (b)(1)(iv); 

c. Revising paragraph (b)(3)(iii); 

d. Revising paragraph (d)(3); 

e. Revising paragraph (e)(1) introductory text; 

f. Revising paragraph (e)(1)(ii); 

g. Revising paragraph (e)(2) introductory text; 

h. Revising paragraph (e)(2)(ii); 

i. Revising paragraph (e)(2)(vi)(C); 

j. Revising paragraph (e)(3); and 

k. Revising paragraph (h)(5). 

The revisions read as follows: 
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§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 part 60. 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 part 

60. The owner or operator shall use Methods 6, 6A, or 6C of 

appendix A-4 to part 60 for conducting the relative accuracy 

evaluations. The method ANSI/ASME PTC 19.10-1981, “Flue and 

Exhaust Gas Analyses,” (incorporated by reference—see §60.17) is 

an acceptable alternative to EPA Method 6 or 6A of appendix A-4 

to part 60. Samples taken by Method 6 of appendix A-4 to part 60 

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) * * * 
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(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, Test for Hydrogen 

Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain 

Tubes,” 1986 Revision (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-stain tubes with a 
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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 gas-fired 

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). 

 

 





  

i i

i i

d X MHC

X MEV

F

1,000,000

 (Eq. 13) 

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. 

* * * * * 
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(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 part 60. The owner or operator of each total 

reduced sulfur monitor shall use EPA Method 15A of Appendix A-5 

to part 60 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 part 60. The alternative relative accuracy 

procedures described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 (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 
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Page 419 of 809 

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 part 

60. The owner or operator shall use EPA Method 11, 15 or 15A of 

Appendix A-5 to part 60 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 part 60. The alternative relative 

accuracy procedures described in section 16.0 of Performance 

Specification 2 of Appendix B to part 60 (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 
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distribution of daily ratios based on the 10 individual daily 

ratios using Equation 14 of this section. 

AR Ratio SDev  Avg  2.262 (Eq. 14) 

Where: 

AR = Acceptable range of subsequent ratio determinations, 

unitless. 

RatioAvg = 10-day average total sulfur-to-H2S 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 
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Page 421 of 809 

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. 

* * * * * 

(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--[AMENDED] 

10. The authority citation for part 63 continues to read as 

follows: 

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

Subpart A—[Amended] 

11. Section 63.14 is amended by: 

a. Revising paragraph (g)(14); 
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b. Adding paragraphs (g)(85) and (86); 

c. Adding paragraph (i)(2); 

d. Adding paragraphs (l)(21) through (23); 

e. Adding paragraph (m)(3); and 

f. Adding paragraph (s). 

The revisions and additions read as follows: 

§63.14 Incorporation by reference. 

* * * * * 

(g) * * * 

(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). 

* * * * * 

(85) ASTM D6196-03 (Reapproved 2009), Standard Practice for 

Selection of Sorbents, Sampling, and Thermal Desorption Analysis 

Procedures for Volatile Organic Compounds in Air, IBR approved 

for appendix A to part 63: Method 325A, Sections 1.2 and 6.1, 

and Method 325B, Sections 1.3, 7.1.2, 7.1.3, and A.1.1. 

(86) ASTM UOP539-12, Refinery Gas Analysis by Gas 

Chromatography, IBR approved for §63.670(j). 

* * * * * 

(i) * * * 
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(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, IBR approved for appendix A to part 63: Method 

325A, Section 1.2, and Method 325B, Sections 1.3, 7.1.3, and 

A.1.1. 

* * * * * 

(l) * * * 

(21) 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 part 63: Method 325A, Section 8.3. 

(22) 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 2008, IBR approved for §63.658(d) and 

appendix A to part 63: Method 325A, Sections 8.1.4 and 10.0. 

(23) EPA-454/B-13-003, Office of Air Quality Planning and 

Standards (OAQPS), Quality Assurance Handbook for Air Pollution 

Measurement Systems, Volume II: Ambient Air Quality Monitoring 

Program, May 2013, IBR approved for §63.658(c) and appendix A to 

part 63: Method 325A, Section 4.1. 

(m) * * * 
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(3) ISO 16017-2:2003, Indoor, Ambient and Workplace Air—

Sampling and Analysis of Volatile Organic Compounds by Sorbent 

Tube/Thermal Desorption/Capillary Gas Chromatography—Part 2: 

Diffusive Sampling, First edition, June 11, 2003, IBR approved 

for appendix A to part 63: Method 325A, Sections 1.2, 6.1, and 

6.5, and Method 325B, Sections 1.3, 7.1.2, 7.1.3, and A.1.1. 

* * * * * 

(s) U.S. Department of the Interior, 1849 C Street, N.W., 

Washington, DC 20240, (202) 208-3100, www.doi.gov. 

(1) Bulletin 627, Bureau of Mines, Flammability 

Characteristics of Combustible Gases and Vapors, 1965, IBR 

approved for §63.670(l). 

(2) [Reserved] 

Subpart Y – [AMENDED] 

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--[AMENDED] 

13. Section 63.640 is amended by: 

a. Revising paragraph (a) introductory text; 
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b. Revising paragraph (c) introductory text; 

c. Adding paragraph (c)(9); 

d. Revising paragraph (d)(5); 

e. Revising paragraph (h); 

f. Revising paragraph (k)(1); 

g. Revising paragraph (l) introductory text; 

h. Revising paragraph (l)(2) introductory text; 

i. Revising paragraph (l)(2)(i); 

j. Revising paragraph (l)(3) introductory text; 

k. Revising paragraph (m) introductory text; 

l. Revising paragraph (n) introductory text; 

m. Revising paragraphs (n)(1) through (5); 

n. Revising paragraph (n)(8) introductory text; 

o. Revising paragraph (n)(8)(ii); 

p. Adding paragraphs (n)(8)(vii) and (viii); 

q. Revising paragraphs (n)(9)(i); 

r. Adding paragraph (n)(10); 

s. Revising paragraph (o)(2)(i); 

t. Adding paragraph (o)(2)(i)(D); 

u. Revising paragraph (o)(2)(ii); 

v. Adding paragraph (o)(2)(ii)(C); and 

w. Revising paragraph (p)(2). 

The revisions and additions read as follows: 
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§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 (c)(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 of this subpart, provided that on and after [THE DATE 

3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas 

from that fuel gas system are in compliance with §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. 
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* * * * * 

(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 

63.661, 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. 

(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 (h)(3)(iii) of this section. 
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(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 
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determined according to paragraphs (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 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 

paragraphs (l)(2)(i) or (l)(2)(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 
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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 (l)(3)(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 
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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 subpart CC with other regulations for 

storage vessels. As applicable, paragraphs (n)(1), (n)(3), 

(n)(4), (n)(6), and (n)(7) of this section apply for Group 2 

storage vessels and paragraphs (n)(2) and (n)(5) of this section 

apply for Group 1 storage vessels. 

(1) After the compliance dates specified in paragraph (h) 

of this section, a Group 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 CFR 

part 61, subpart Y is required to comply only with the 

requirements of 40 CFR part 60, 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 
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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, subparts 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 
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provided in paragraphs (n)(8)(i) through (n)(8)(vi) of this 

section. Storage vessels described by paragraph (n)(2) electing 

to comply with part 60, subpart Kb of this chapter shall comply 

with subpart Kb except as provided in paragraphs (n)(8)(i) 

through (n)(8)(vii) 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 

subpart Kb or to inspect the vessel to determine compliance with 

§60.113b(a) of subpart Kb because the roof appears to be 

structurally unsound and poses an imminent danger to inspecting 

personnel, the owner or operator shall comply with the 

requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of 

subpart G (only up to the compliance date specified in paragraph 

(h) of this section for compliance with §63.660, as applicable) 

or either §63.1063(c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of 

subpart WW. 

* * * * * 

(vii) To be in compliance with §60.112b(a)(2)(ii) of this 

chapter, floating roof storage vessels must be equipped with 

guidepole controls as described in Appendix I: Acceptable 

Controls for Slotted Guidepoles Under the Storage Tank Emissions 

Reduction Partnership Program (65 FR 19891). 
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(viii) If a flare is used as a control device for a storage 

vessel, on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the owner or operator must meet the requirements of 

§63.670 instead of the requirements referenced from part 60, 

subpart Kb of this chapter for that flare. 

(9) * * * 

(i) If the owner or operator determines that it is unsafe 

to perform the seal gap measurements required in §60.113a(a)(1) 

of subpart Ka because the floating roof appears to be 

structurally unsound and poses an imminent danger to inspecting 

personnel, the owner or operator shall comply with the 

requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of 

subpart G (only up to the compliance date specified in paragraph 

(h) of this section for compliance with §63.660, as applicable) 

or either §63.1063(c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of 

subpart WW. 

* * * * * 

(10) Storage vessels described by paragraph (n)(1) of this 

section are to comply with 40 CFR part 61, subpart Y except as 

provided in paragraphs (n)(10)(i) through (n)(8)(vi) of this 

section. Storage vessels described by paragraph (n)(2) electing 

to comply with 40 CFR part 61, subpart Y shall comply with 
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subpart Y except as provided for in paragraphs (n)(10)(i) 

through (n)(10)(viii) of this section. 

(i) Storage vessels that are to comply with §61.271(b) of 

this chapter are exempt from the secondary seal requirements of 

§61.271(b)(2)(ii) of this chapter during the gap measurements 

for the primary seal required by §61.272(b) of this chapter. 

(ii) If the owner or operator determines that it is unsafe 

to perform the seal gap measurements required in §61.272(b) of 

this chapter or to inspect the vessel to determine compliance 

with §61.272(a) of this chapter because the roof appears to be 

structurally unsound and poses an imminent danger to inspecting 

personnel, the owner or operator shall comply with the 

requirements in either §63.120(b)(7)(i) or §63.120(b)(7)(ii) of 

subpart G (only up to the compliance date specified in paragraph 

(h) of this section for compliance with §63.660, as applicable) 

or either §63.1063(c)(2)(iv)(A) or §63.1063(c)(2)(iv)(B) of 

subpart WW. 

(iii) If a failure is detected during the inspections 

required by §61.272(a)(2) of this chapter or during the seal gap 

measurements required by §61.272(b)(1) of this chapter, and the 

vessel cannot be repaired within 45 days and the vessel cannot 

be emptied within 45 days, the owner or operator may utilize up 

to two extensions of up to 30 additional calendar days each. The 
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owner or operator is not required to provide a request for the 

extension to the Administrator. 

(iv) If an extension is utilized in accordance with 

paragraph (n)(10)(iii) of this section, the owner or operator 

shall, in the next periodic report, identify the vessel, provide 

the information listed in §61.272(a)(2) or §61.272(b)(4)(iii) of 

this chapter, and describe the nature and date of the repair 

made or provide the date the storage vessel was emptied. 

(v) Owners and operators of storage vessels complying with 

40 CFR part 61, subpart Y may submit the inspection reports 

required by §61.275(a), (b)(1), and (d) of this chapter as part 

of the periodic reports required by this subpart, rather than 

within the 60-day period specified in §61.275(a), (b)(1), and 

(d) of this chapter. 

(vi) The reports of rim seal inspections specified in 

§61.275(d) of this chapter are not required if none of the 

measured gaps or calculated gap areas exceed the limitations 

specified in §61.272(b)(4) of this chapter. Documentation of the 

inspections shall be recorded as specified in §61.276(a) of this 

chapter. 

(vii) To be in compliance with §61.271(b)(3) of this 

chapter, floating roof storage vessels must be equipped with 

guidepole controls as described in Appendix I: Acceptable 
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Controls for Slotted Guidepoles Under the Storage Tank Emissions 

Reduction Partnership Program (65 FR 19891). 

(viii) If a flare is used as a control device for a storage 

vessel, on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the owner or operator must meet the requirements of 

§63.670 instead of the requirements referenced from part 61, 

subpart Y of this chapter for that flare. 

(o) * * * 

(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 

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 

the requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable 

requirements of 40 CFR part 61, subpart FF and subpart G of this 

part, or the requirements of §63.670. 

(ii) Comply with paragraphs (o)(2)(ii)(A) through (C) of 

this section. 

* * * * * 
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(C) If a flare is used as a control device, on and after 

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 

the requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable 

requirements of 40 CFR part 61, subpart FF and subpart G of this 

part, or the requirements of §63.670. 

(p) * * * 

(2) Equipment leaks that are also subject to the provisions 

of 40 CFR part 60, subpart GGGa, are required to comply only 

with the provisions specified in 40 CFR part 60, subpart GGGa. 

Owners and operators of equipment leaks that are subject to the 

provisions of 40 CFR part 60, subpart GGGa and subject to this 

subpart may elect to monitor equipment leaks following the 

provisions in §63.661, provided that the equipment is in 

compliance with all other provisions of 40 CFR part 60, subpart 

GGGa. 

* * * * * 

14. Section 63.641 is amended by: 

a. Adding, in alphabetical order, new 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,” 
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“Flare supplemental gas,” “Flare sweep gas,” “Flare vent gas,” 

“Halogenated vent stream or halogenated stream,” “Halogens and 

hydrogen halides,” “Lower steam,” “Net heating value,” 

“Perimeter assist air,” “Pilot gas,” “Premix assist air,” “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 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 
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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 delayed coker vent to the unit’s blowdown 
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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 vent that is typically 

intermittent in nature, and usually occurs only 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, but instead is routed to the atmosphere 

through the delayed coking unit’s blowdown system. 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, 
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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, airassisted flares, steam-assisted 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 minimum amount of gas necessary to maintain 
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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 minimum amount of gas 

necessary 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), flare sweep gas, flare purge gas and 

flare supplemental gas, but does not include pilot gas, total 

steam or assist air. 

* * * * * 

Group 1 storage vessel means: 

(1) Prior to [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER]: 

(i) A storage vessel at an existing source that has a 

design capacity greater than or equal to 177 cubic meters and 

stored-liquid maximum true vapor pressure greater than or equal 

to 10.4 kilopascals and stored-liquid annual average true vapor 

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

pressure greater than or equal to 77 kilopascals and annual 

average HAP liquid concentration greater than 2 percent by 

weight total organic HAP. 

(2) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER]: 

(i) A storage vessel at an existing source that has a 

design capacity greater than or equal to 151 cubic meters 

(40,000 gallons) and stored-liquid maximum true vapor pressure 

greater than or equal to 5.2 kilopascals (0.75 pounds per square 

inch) and annual average HAP liquid concentration greater than 4 

percent by weight total organic HAP; 

(ii) A storage vessel at an existing source that has a 

design storage capacity greater than or equal to 76 cubic meters 

(20,000 gallons) and less than 151 cubic meters (40,000 gallons) 
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and stored-liquid maximum true vapor pressure greater than or 

equal to 13.1 kilopascals (1.9 pounds per square inch) and 

annual average HAP liquid concentration greater than 4 percent 

by weight total organic HAP; 

(iii) A storage vessel at a new source that has a design 

storage capacity greater than or equal to 151 cubic meters 

(40,000 gallons) and stored-liquid maximum true vapor pressure 

greater than or equal to 3.4 kilopascals (0.5 pounds per square 

inch) and annual average HAP liquid concentration greater than 2 

percent by weight total organic HAP; or 

(iv) A storage vessel at a new source that has a design 

storage capacity greater than or equal to 76 cubic meters 

(20,000 gallons) and less than 151 cubic meters (40,000 gallons) 

and stored-liquid maximum true vapor pressure greater than or 

equal to 13.1 kilopascals (1.9 pounds per square inch) and 

annual average HAP liquid concentration greater than 2 percent 

by weight total organic HAP. 

* * * * * 

Halogenated vent stream or halogenated stream means a 

stream determined to have a mass rate of halogen atoms of 0.45 

kilograms per hour or greater, determined by the procedures 

presented in §63.115(d)(2)(v). The following procedures may be 

used as alternatives to the procedures in §63.115(d)(2)(v)(A): 
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(1) Process knowledge that halogen or hydrogen halides are 

present in a vent stream and that the vent stream is 

halogenated, or 

(2) Concentration of compounds containing halogen and 

hydrogen halides measured by Method 26 or 26A of part 60, 

Appendix A–8 of this chapter, or 

(3) Concentration of compounds containing hydrogen halides 

measured by Method 320 of Appendix A of this part. 

Halogens and hydrogen halides means hydrogen chloride 

(HCl), chlorine (Cl2), hydrogen bromide (HBr), bromine (Br2), and 

hydrogen fluoride (HF). 

* * * * * 

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, 
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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 [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], any flares receiving gas from the fuel gas system are 

in compliance with §63.670; 

(2) Relief valve discharges regulated under §63.648; 

(3) Leaks from equipment regulated under §63.648; 

(4) [Reserved]; 

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

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER]. After this date, these 

sampling systems will be included in the definition of 

miscellaneous process vents; 

(6) Catalytic cracking unit catalyst regeneration vents; 

(7) Catalytic reformer regeneration vents; 
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(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). 

* * * * * 
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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 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 meeting the specifications of 

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

of §63.1063(a)(1)(ii), (a)(2), and (b); 

(iii) An external floating roof converted to an internal 

floating roof meeting the specifications of §63.1063(a)(1)(i) 

and (b); 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 (ppmv). 

(v) For purposes of emissions averaging, these four 

technologies are considered equivalent. 

(2) For all other storage vessels: 

(i) An internal floating roof meeting the specifications of 

§63.119(b) of subpart G except for §63.119(b)(5) and (b)(6); 

(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. 

* * * * * 
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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. Revising paragraph (b); 

b. Revising paragraph (d)(3); 

c. Revising paragraph (e); 

d. Revising paragraph (i); 

e. Revising paragraph (k) introductory text; 

f. Revising paragraph (k)(1); 

g. Revising paragraph (l) introductory text; 

h. Revising paragraph (l)(2); and 

i. 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) * * * 
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(3) 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 
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(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 or 63.661, 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 
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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 

or 63.661, 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 paragraph (a)(1) 

to read as follows: 
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§63.643 Miscellaneous process vent provisions. 

(a) * * * 

(1) Reduce emissions of organic HAP’s using a flare. On and 

after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall 

meet the requirements of §63.670. Prior to [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER], the flare shall meet the requirements of 

§63.11(b) of subpart A or the requirements of §63.670. 

* * * * * 

17. Section 63.644 is amended by: 

a. Revising paragraph (a) introductory text; 

b. Revising paragraph (a)(2); and 

c. Revising paragraph (c). 

The revisions 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), (a)(2), (a)(3), or (a)(4) of this section, 

depending on the type of combustion device used. All monitoring 

equipment shall be installed, calibrated, maintained, and 

operated according to manufacturer’s specifications or other 
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written procedures that provide adequate assurance that the 

equipment will monitor accurately and 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 [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], a device (including but not limited to a 

thermocouple, an ultraviolet beam sensor, or an infrared sensor) 

capable of continuously detecting the presence of a pilot flame 

is required, or the requirements of §63.670 shall be met. Where 

a flare is used on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], 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 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 is an emissions standards violation. Equipment such 

as low leg drains and equipment subject to §63.648 are not 

subject to this paragraph. 
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(1) Install, operate, calibrate, and maintain a continuous 

parameter monitoring system for flow, as specified in paragraphs 

(c)(1)(i) through (iii) of this section. 

(i) Install a continuous parameter monitoring system for 

flow at the entrance to any bypass line. The continuous 

parameter monitoring system must record the volume of the gas 

stream that bypassed the control device and must meet the 

applicable minimum accuracy, calibration and quality control 

requirements specified in table 13 of this subpart. 

(ii) Equip the continuous parameter monitoring system for 

flow with an alarm system that will alert an operator 

immediately and automatically when flow is detected in the 

bypass line. Locate the alarm such that an operator can easily 

detect and recognize the alert. 

(iii) Reports and records shall be generated as specified 

in §63.655(g) and (i). 

(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. 

* * * * * 
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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: 

a. Adding introductory text to §63.646; and 

b. Revising paragraph (b)(2). 

The revisions and additions 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. 
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* * * * * 

(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 consensusbased 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 

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 

the requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable 

requirements of part 61, subpart FF of this chapter, or the 

requirements of §63.670. 

* * * * * 

21. Section 63.648 is amended by: 

a. Revising paragraph (a) introductory text; 
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b. Adding paragraphs (a)(3) and (4); 

c. Revising paragraph (c) introductory text; 

d. Revising paragraph (c)(2)(ii); 

e. Adding paragraphs (c)(11) and (12); and 

f. Adding paragraph (j). 

The revisions and additions read as follows: 

§63.648 Equipment leak standards. 

(a) Each owner or operator of an existing source subject to 

the provisions of this subpart shall comply with the provisions 

of part 60, subpart VV of this chapter and paragraph (b) of this 

section except as provided in paragraphs (a)(1), (a)(2), and (c) 

through (i) of this section. Each owner or operator of a new 

source subject to the provisions of this subpart shall comply 

with subpart H of this part except as provided in paragraphs (c) 

through (i) of this section. As an alternative to the monitoring 

requirements of part 60, subpart VV of this chapter or subpart H 

of this part, as applicable, the owner or operator may elect to 

monitor equipment leaks following the provisions in §63.661. 

* * * * * 

(3) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of 

complying with the requirements of §60.482-6(a)(2) of this 

chapter, the term “seal” or “sealed” means that instrument 

monitoring of the open-ended valve or line conducted according 
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to the method specified in §60.485(b) and, as applicable, 

§60.485(c) of this chapter indicates no readings of 500 parts 

per million or greater. 

(4) If a flare is used as a control device, on and after 

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 

the requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable 

requirements of part 60, subpart VV of this chapter, or the 

requirements of §63.670. 

* * * * * 

(c) In lieu of complying with the existing source 

provisions of paragraph (a) in this section, an owner or 

operator may elect to comply with the requirements of §§63.161 

through 63.169, 63.171, 63.172, 63.175, 63.176, 63.177, 63.179, 

and 63.180 of subpart H of this part except as provided in 

paragraphs (c)(1) through (c)(12) and (e) through (i) of this 

section. 

* * * * * 

(2) * * * 

(ii) If an owner or operator elects to monitor connectors 

according to the provisions of §63.649, paragraphs (b), (c), or 

(d), then the owner or operator shall monitor valves at the 
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frequencies specified in table 9 of this subpart. If an owner or 

operator elects to comply with §63.649, the owner or operator 

cannot also elect to comply with §63.661. 

* * * * * 

(11) On and after [THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of 

complying with the requirements of §63.167(a)(2), the term 

“seal” or “sealed” means that instrument monitoring of the openended valve or line conducted according to the method specified 

in §63.180(b) and, as applicable, §63.180(c) of this chapter 

indicates no readings of 500 parts per million or greater. 

(12) If a flare is used as a control device, on and after 

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 

the requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], 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 

relief valves in organic HAP gas or vapor service instead of the 
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pressure relief device requirements of §60.482-4 or §63.165, as 

applicable. Except as specified in paragraph (j)(4) of this 

section, the owner or operator must also comply with the 

requirements specified in paragraph (j)(3) of this section for 

all relief valves in organic HAP service. 

(1) Operating requirements. Except during a pressure 

release, operate each relief valve 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 relief valves in 

organic HAP gas or vapor service, the owner or operator must 

comply with either paragraph (j)(2)(i) or (ii) of this section 

following a pressure release. 

(i) If the relief valve 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 relief valve returns to organic HAP gas 

or vapor service following a pressure release to verify that the 

relief valve is operating with an instrument reading of less 

than 500 ppm. 

(ii) If the relief valve consists of or includes a rupture 

disk, install a replacement disk as soon as practicable after a 

pressure release, but no later than 5 calendar days after the 
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pressure release. The owner or operator must also conduct 

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

as applicable, no later than 5 calendar days after the relief 

valve returns to organic HAP gas or vapor service following a 

pressure release to verify that the relief valve is operating 

with an instrument reading of less than 500 ppm. 

(3) Pressure release management. Except as specified in 

paragraph (j)(4) of this section, emissions of organic HAP may 

not be discharged to the atmosphere from relief valves in 

organic HAP service, and on or before [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the owner or operator shall comply with the 

requirements specified in paragraphs (j)(3)(i) and (ii) of this 

section for all relief valves in organic HAP service. 

(i) The owner or operator must equip each relief valve in 

organic HAP service with a device(s) or use a monitoring system 

that is capable of: 1) identifying the pressure release; 2) 

recording the time and duration of each pressure release; and 3) 

notifying operators immediately that a pressure release is 

occurring. The device or monitoring system may be either 

specific to the pressure relief device itself or may be 

associated with the process 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 
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rupture disk indicator, magnetic sensor, motion detector on the 

pressure relief valve stem, flow monitor, or pressure monitor. 

(ii) If any relief valve in organic HAP service vents or 

releases to atmosphere as a result of a pressure release event, 

the owner or operator must calculate the quantity of organic HAP 

released during each pressure release event and report this 

quantity as required in §63.655(g)(10)(iii). Calculations may be 

based on data from the relief valve monitoring alone or in 

combination with process parameter monitoring data and process 

knowledge. 

(4) Relief valves routed to a control device. If all 

releases and potential leaks from a relief valve in organic HAP 

service are routed through a closed vent system to a control 

device, the owner or operator is not required to comply with 

paragraphs (j)(1), (2) or (3) (if applicable) of this section. 

Both the closed vent system and control device (if applicable) 

must meet the requirements of §63.644. When complying with this 

paragraph, all references to “Group 1 miscellaneous process 

vent” in 63.644 mean “relief valve.” 

22. 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 
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loading rack classified under Standard Industrial Classification 

code 2911 located within a contiguous area and under common 

control with a petroleum refinery shall comply with subpart R, 

§§63.421, 63.422(a) through (c) and (e), 63.425(a) through (c) 

and (i), 63.425(e) through (h), 63.427(a) and (b), and 

63.428(b), (c), (g)(1), (h)(1) through (3), and (k). 

* * * * * 

(d) If a flare is used as a control device, on and after 

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 

the requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable 

requirements of subpart R of this part, or the requirements of 

§63.670. 

23. Section 63.651 is amended by revising paragraph (a) 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. 

* * * * * 
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(e) If a flare is used as a control device, on and after 

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 

the requirements of §63.670. Prior to [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare shall meet the applicable 

requirements of subpart Y of this part, or the requirements of 

§63.670. 

24. Section 63.652 is amended by: 

a. Revising paragraph (a); 

b. Removing and reserving paragraph (f)(2); 

c. Revising paragraph (g)(2)(iii)(B)(1); 

d. Revising paragraph (h)(3); 

e. Revising paragraph (k) introductory text; and 

f. Revising paragraph (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 
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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 of this subpart, as applicable, or a 

boiler or process heater meeting the criteria in §63.645(d) of 

this subpart or §63.116(b) of subpart G, the percentage of 

reduction shall be 98 percent. If a noncombustion control device 

is used, percentage of reduction shall be demonstrated by a 

performance test at the inlet and outlet of the device, or, if 

testing is not feasible, by a control design evaluation and 

documented engineering calculations. 

* * * * * 

(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: 
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(A) All references to §63.119(b) in §63.150(h)(3) of 

subpart G shall be replaced with: §63.119 (b) or §63.119(b) 

except for §63.119(b)(5) and (b)(6). 

(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) Sections 63.1063(a)(1)(i), (a)(2), and (b) or 

§§63.1063(a)(1)(i) and (b) shall apply instead of §63.119(b) in 

§63.150(h)(3) of subpart G. 

(B) Sections 63.1063(a)(1)(ii), (a)(2), and (b) shall apply 

instead of §63.119(c) in §63.150(h)(3) of subpart G. 

(C) Sections 63.1063(a)(1)(i), (a)(2), and (b) or 

§§63.1063(a)(1)(i) and (b) shall apply instead of §63.119(d) in 

§63.150(h)(3) of subpart G. 

* * * * * 

(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 
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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. 

* * * * * 

25. Section 63.653 is amended by: 

a. Revising paragraph (a) introductory text; 

b. Revising paragraphs (a)(3)(i) and (ii); and 

c. Revising paragraph (a)(7). 

The revisions 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, 
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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 
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and shall submit the information specified in §63.655(h)(4) in 

the Implementation Plan. 

* * * * * 

26. Section 63.655 is amended by: 

a. Revising paragraph (f) introductory text; 

b. Revising paragraph (f)(1) introductory text; 

c. Revising paragraph (f)(1)(i)(A) introductory text; 

d. Revising paragraphs (f)(1)(i)(A)(2) and (f)(1)(i)(A)(3); 

e. Revising paragraph (f)(1)(i)(B) introductory text; 

f. Revising paragraph (f)(1)(i)(B)(2); 

g. Revising paragraph (f)(1)(i)(D)(2); 

h. Revising paragraph (f)(1)(iv) introductory text; 

i. Revising paragraph (f)(1)(iv)(A); 

j. Adding paragraph (f)(1)(vii); 

k. Revising paragraph (f)(2) introductory text; 

l. Revising paragraph (f)(3) introductory text; 

m. Revising the first sentence of paragraph (f)(6); 

n. Revising paragraph (g) introductory text; 

o. Revising paragraphs (g)(1) through (5); 

p. Revising paragraph (g)(6)(iii); 

q. Revising paragraph (g)(7)(i); 

r. Adding paragraphs (g)(10) through (13); 

s. Removing and reserving paragraph (h)(1); 

t. Revising paragraph (h)(2) introductory text; 
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u. Revising paragraph (h)(2)(i)(B); 

v. Revising paragraph (h)(2)(ii); 

w. Adding paragraphs (h)(8) and (9); 

x. Revising paragraph (i) introductory text; 

y. Revising paragraph (i)(1); 

z. Revising paragraph (i)(1)(ii); 

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

bb. Redesignating paragraph (i)(4) as (i)(5); 

cc. Redesignating paragraph (i)(5) as (i)(6); 

dd. Adding paragraph (i)(4); 

ee. Revising newly redesignated paragraph (i)(5) 

introductory text; and 

ff. Adding paragraphs (i)(7) through (11). 

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 
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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 (f)(5) of this section at different 

times, and/or in different submittals, later submittals may 

refer to earlier submittals instead of duplicating and 

resubmitting the previously submitted information. Each owner or 

operator of a gasoline loading rack classified under Standard 

Industrial Classification Code 2911 located within a contiguous 

area and under common control with a petroleum refinery subject 

to the standards of this subpart shall submit the Notification 

of Compliance Status report required by subpart R of this part 

within 150 days after the compliance dates specified in 

§63.640(h) of this subpart. 

(1) The Notification of Compliance Status report shall 

include the information specified in paragraphs (f)(1)(i) 

through (f)(1)(vii) of this section. 
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(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 (f)(1)(i)(A)(3) of this section. This information is to 

be revised each time a Notification of Compliance Status report 

is submitted for a storage vessel subject to the compliance 

schedule specified in §63.640(h)(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 
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(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 of this subpart and §63.116(a) of subpart G of this 

part or §63.670(h) of this subpart, as applicable, and 

* * * * * 

(vii) For relief valves in organic HAP service, a 

description of the monitoring system to be implemented, 

including the relief valves 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. 
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(2) If initial performance tests are required by §§63.643 

through 63.653 of this subpart, the Notification of Compliance 

Status report shall include one complete test report for each 

test method used for a particular source. On and after [THE DATE 

3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], 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 (f)(3)(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. Six-month periods shall be the same 6-month periods 

specified in paragraph (g) of this section. The Notification of 
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Compliance Status report shall include the information specified 

in paragraphs (f)(1) through (f)(5) of this section. This 

information may be submitted in an operating permit application, 

in an amendment to an operating permit application, in a 

separate submittal, as part of the periodic report, or in any 

combination of these four. If the required information has been 

submitted before the date 60 days after the end of the 6-month 

period in which the addition of the Group 1 emission point took 

place, a separate Notification of Compliance Status report is 

not required within 60 days after the end of the 6-month period. 

If an owner or operator submits the information specified in 

paragraphs (f)(1) through (f)(5) of this section at different 

times, and/or in different submittals, later submittals may 

refer to earlier submittals instead of duplicating and 

resubmitting the previously submitted information. 

(g) The owner or operator of a source subject to this 

subpart shall submit Periodic Reports no later than 60 days 

after the end of each 6-month period when any of the information 

specified in paragraphs (g)(1) through (7) of this section or 

paragraphs (g)(9) through (12) 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 

paragraph (g)(1) through (7) of this section or paragraphs 
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(g)(9) through (12) of this section occurred during the 6-month 

period unless emissions averaging is utilized. Quarterly reports 

must be submitted for emission points included in emission 

averages, as provided in paragraph (g)(8) of this section. An 

owner or operator may submit reports required by other 

regulations in place of or as part of the Periodic Report 

required by this paragraph if the reports contain the 

information required by paragraphs (g)(1) through (12) of this 

section. 

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

information specified for Periodic Reports in paragraph (g)(2) 

through (g)(5) of this section. 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 
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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)(C) of this 

section, each Periodic Report shall include the date of the 

inspection, identification of each storage vessel in which a 

failure was detected, and a description of the failure. The 

Periodic Report shall also describe the nature of and date the 

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

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

(b)(4), (b)(5), or (b)(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 (b)(4) of 

subpart G. 
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(3) A description of any seal condition specified in 

§63.120(b)(5) or (b)(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. 
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(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). 

(B) An owner or operator who elects to use an extension in 

accordance with §63.1063(e)(2) or §63.1063(c)(2)(iv)(B) of 

subpart WW shall, in the next Periodic Report, submit the 

documentation required by those paragraphs. 

(4) An owner or operator who elects to comply with §63.646 

or §63.660 by using an external floating roof converted to an 

internal floating roof shall comply with the periodic reporting 

requirements of paragraph (g)(2)(i) of this section. 

(5) An owner or operator who elects to comply with §63.646 

or §63.660 by installing a closed vent system and control device 
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shall submit, as part of the next Periodic Report, the 

information specified in paragraphs (g)(5)(i) through 

(g)(5)(iii) 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 (e)(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 
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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 [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER] and prior to electing to comply with the 

requirements in §63.670, the Periodic Report shall describe each 

occurrence when the flare does not meet the general control 

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

part and shall include: Identification of the flare that does 

not meet the general requirements specified in §63.11(b) of 

subpart A of this part, and reasons the flare did not meet the 

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

part. 

(iv) If a flare is used on and after compliance with the 

requirements in §63.670 is elected, which can be no later than 

[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], the Periodic Report 

shall include the items specified in paragraph (g)(11) of this 

section. 
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(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) * * * 

(iii) For closed vent systems, include the records of 

periods when vent stream flow was detected in the bypass line or 

diverted from the control device, a flow indicator was not 

operating or a bypass of the system was indicated, as specified 

in paragraph (i)(4) of this section. 

(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 relief valves, Periodic Reports must include the 

information specified in paragraphs (g)(10)(i) through (iii) of 

this section. 

(i) For relief valves in organic HAP gas or vapor service, 

pursuant to §63.648(j), report any instrument reading of 500 ppm 
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or greater, more than 5 days after the relief valve returns to 

service after a pressure release. 

(ii) For relief valves in organic HAP gas or vapor service 

subject to §63.648(j)(2), report confirmation that all 

monitoring to show compliance was conducted within the reporting 

period. 

(iii) For relief valves in organic HAP service, report each 

pressure release to the atmosphere, including duration of the 

pressure release and estimate of quantity of substances 

released. 

(11) For flares subject to §63.670, Periodic Reports must 

include the information specified in paragraphs (g)(11)(i) 

through (iii) of this section. 

(i) Records as specified in paragraph (i)(9)(i) of this 

section for each period when regulated material is routed to a 

flare and a pilot flame is not present. 

(ii) Visible emission records as specified in paragraph 

(i)(9)(ii) 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 15-minute 

block average operating parameters determined following the 
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methods in §63.670(k) through (o) as applicable, and an 

indication of whether the three criteria in §63.670(e)(vi) were 

all met for that 15-minute block period. 

(iv) Records as specified in paragraph (i)(9)(x) of this 

section for each period when a halogenated vent stream as 

defined in §63.641 is discharged to the flare. 

(12) If a source fails to meet an applicable standard, 

report such events in the Periodic Report. Report the number of 

failures to meet an applicable standard. For each instance, 

report the date, time and duration of each failure. For each 

failure the report must include a list of the affected sources 

or equipment, an estimate of the quantity of each regulated 

pollutant emitted over any emission limit, and a description of 

the method used to estimate the emissions. 

(13) 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 (h)(2)(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), 

§63.120(a)(3), or §63.120(b)(10) of subpart G or §63.1063(d)(1) 
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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 (b)(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. 

* * * * * 

(8) For fenceline monitoring systems subject to §63.658, 

within 45 calendar days after the end of each semiannual 
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reporting period, each owner or operator shall submit the 

following information to the EPA’s Compliance and Emissions Data 

Reporting Interface (CEDRI) that is accessed through the EPA’s 

Central Data Exchange (CDX) (www.epa.gov/cdx). 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 episode during the semiannual 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 12-month rolling average concentration 

difference (Δc) values for benzene for the semiannual 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 [THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], if required to submit the 

results of a performance test or CEMS performance evaluation, 
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the owner or operator shall submit the results using EPA’s 

Electronic Reporting Tool (ERT) 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 

according to the method specified by either paragraph 

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

(A) For data collected using test methods supported by the 

EPA’s ERT as listed on the EPA’s ERT website 

(http://www.epa.gov/ttn/chief/ert/index.html), the owner or 

operator must submit the results of the performance test to the 

CEDRI accessed through the EPA’s CDX 

(http://cdx.epa.gov/epa_home.asp), unless the Administrator 

approves another approach. Performance test data must be 

submitted in a file format generated through the use of the 

EPA’s ERT. 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, 

including information claimed to be CBI, on a compact disc or 

other commonly used electronic storage media (including, but not 

limited to, flash drives) by registered letter to the EPA. The 

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

Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. 

The same ERT file with the CBI omitted must be submitted to the 

EPA via CDX as described earlier in this paragraph. 

(B) For data collected using test methods that are not 

supported by the EPA’s ERT as listed on the EPA’s ERT website, 

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 

according to the method specified by either paragraph 

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

(A) For data collection of relative accuracy test audit 

(RATA) pollutants that are supported by the EPA’s ERT as listed 

on the ERT website, the owner or operator must submit the 

results of the performance evaluation to the CEDRI that is 

accessed through the EPA’s CDX, unless the Administrator 

approves another approach. Performance evaluation data must be 

submitted in a file format generated through the use of the 

EPA’s ERT. 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 
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the use of the EPA’s ERT, including information claimed to be 

CBI, on a compact disc or other commonly used electronic storage 

media (including, but not limited to, flash drives) by 

registered letter to the EPA. The electronic media must be 

clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI 

Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old 

Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to the EPA via CDX as described 

earlier in this paragraph. 

(B) For any performance evaluation data with RATA 

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

the EPA’s ERT website, 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 

(11) 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 computerreadable form including, but not limited to, on paper, 

microfilm, computer, flash drive, floppy disk, magnetic tape, or 

microfiche. 
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(1) Each owner or operator subject to the storage vessel 

provisions in §63.646 shall keep the records specified in 

§63.123 of subpart G of this part except as specified in 

paragraphs (i)(1)(i) through (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 of 

this part 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. 

(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 
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to the atmosphere, or cause air intrusion into the control 

device, 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 any 

alarms triggered because flow was detected in the bypass line, 

including the date and time the alarm was triggered and the 

duration of the flow in the bypass line. The owner or operator 

shall also maintain records of all periods when the vent stream 

is diverted from the control device or air intrudes into the 

control device. 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. 

(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 
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concentration of organic HAP in the gas and the resulting 

emissions of organic HAP that bypassed the control device. 

(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 of the average pressure 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. 

(8) For fenceline monitoring systems subject to §63.658, 

each owner or operator shall keep the records specified in 

paragraphs (i)(8)(i) through (ix) of this section on an ongoing 

basis. 

(i) Coordinates of all passive monitors, including 

replicate samplers and field blanks, and 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. 
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(iii) Daily unit vector wind direction, calculated daily 

sigma theta, daily average temperature and daily average 

barometric pressure measurements. 

(iv) For each outlier determined in accordance with Section 

9.2 of Method 325A of Appendix A of this part, the sampler 

location of and the concentration of the outlier and the 

evidence used to conclude that the result is an outlier. 

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

location of and the concentration measured simultaneously by the 

background sampler, and the perimeter samplers to which it 

applies. 

(vi) Individual sample results, the calculated Δc for 

benzene for each sampling episode and the two samples used to 

determine it, whether background correction was used, and the 

12-month rolling average Δc calculated after each sampling 

episode. 

(vii) Method detection limit for each sample, including colocated 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. 

(9) For each flare subject to §63.670, each owner or 

operator shall keep the records specified in paragraphs 
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(i)(9)(i) through (vii) 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 periods 

during which the pilot flame is not present when regulated 

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

(ii) Daily visible emissions observations, as required in 

§63.670(c), as well as any observations required in §63.670(h). 

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. 

(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 
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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 or total hydrocarbon 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 

(m), as applicable. 

(vi) The 15-minute block average olefins, hydrogen, and 

olefins plus hydrogen concentration in the combustion zone used 

to determine if the criteria in §63.670(e)(4) are met. If 

process knowledge and engineering calculations are used, retain 

records of the information used in the assessment and records of 
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all compositional analyses required in §63.670(o)(ii). Identify 

all 15-minute block averages for which all three criteria in 

§63.670(e)(4) are met or are assumed to be met. 

(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) All periods during which a halogenated vent stream, as 

defined in §63.641, is discharged to the flare. Records shall 

include the start time and date of the event, the end time and 

date of the event, and an estimate of the cumulative flow of the 

halogenated vent stream over the duration of the event. 

(10) If the owner or operator elects to comply with 

§63.661, the owner or operator shall keep the records described 

in paragraphs (i)(10)(i) through (v) of this section. 

(i) The equipment and process units for which the owner or 

operator chooses to use the optical gas imaging instrument. 
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(ii) All records required by part 60, Appendix K of this 

chapter, as applicable. 

(iii) A video record to document the leak survey results. 

The video record must include a time and date stamp for each 

monitoring event. 

(iv) Identification of the equipment screened and the time 

and date of the screening. 

(v) Documentation of repairs attempted and repairs delayed. 

If repair of a leak is confirmed using the optical gas imaging 

instrument, then instead of the maximum instrument reading 

measured by Method 21 of part 60, Appendix A–7 of this chapter, 

the owner or operator shall keep a video record following repair 

to confirm the equipment is repaired. 

(11) Other records must be kept as specified in paragraphs 

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

(i) 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. 

(ii) 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. 
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(iii) Record actions taken to minimize emissions in 

accordance with §63.642(n), and any corrective actions taken to 

return the affected unit to its normal or usual manner of 

operation. 

27. Section 63.656 is amended by: 

a. Revising paragraph (c) introductory text; 

b. Revising paragraph (c)(1); and 

c. Adding paragraph (c)(5). 

The revisions and additions read as follows: 

§63.656 Implementation and enforcement. 

* * * * * 

(c) The authorities that cannot be delegated to state, 

local, or Tribal agencies are as specified in paragraphs (c)(1) 

through (5) of this section. 

(1) Approval of alternatives to the requirements in 

§§63.640, 63.642(g) through (l), 63.643, 63.646 through 63.652, 

63.654, 63.657 through 63.661, 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. 
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* * * * * 

(5) Approval of the corrective action plan under 

§63.658(h). 

28. Section 63.657 is added to read as follows: 

§63.657 Delayed coking unit decoking operation standards. 

(a) 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 is 2 pounds per square inch gauge 

(psig) or less prior to venting to the atmosphere, draining or 

deheading the coke drum at the end of the cooling cycle. 

(b) Each owner or operator of a delayed coking unit shall 

install, operate, calibrate, and maintain a continuous parameter 

monitoring system to determine the coke drum vessel pressure. 

The pressure monitoring system must be capable of measuring a 

pressure of 2 psig within ±0.5 psig. 

(c) The owner or operator of a delayed coking unit shall 

determine the coke drum vessel pressure on a 5-minute rolling 

average basis while the coke drum is vented to the closed 

blowdown system to demonstrate compliance the requirement in 

paragraph (a) of this section. Pressure 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 
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average coke drum vessel pressure for the purpose of compliance 

with the requirement in paragraph (a) of this section. 

29. 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. 

(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. General guidance for siting passive 

monitors can be found in EPA-454/R-98-004, Quality Assurance 

Handbook for Air Pollution Measurement Systems, Volume II: Part 

1: Ambient Air Quality Monitoring Program Quality System 

Development, August 1998 (incorporated by reference—see §63.14). 

Alternatively, the owner or operator may elect to place monitors 

at 2 kilometers intervals as measured along the property 

boundary, provided additional monitors are located, if 

necessary, as required in Section 8.2.2.5 in Method 325A of 

Appendix A of this part. 

(1) As it pertains to this subpart, known emission source, 

as used in Section 8.2.2.5 in Method 325A of Appendix A of this 

part for siting passive monitors means a wastewater treatment 

unit or a Group 1 storage vessel. 
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(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 plant, the background sampler(s) should be 

operated co-currently with the routine samplers. 

(3) The owner or operator shall collect at least one colocated duplicate sample for every 10 field samples per sampling 

episode and at least two field blanks per sampling episode, as 

described in Section 9.3 in Method 325A of Appendix A of this 

part. The co-located duplicates may be collected at any one of 

the perimeter sampling locations. 

(4) The owner or operator shall follow the procedure in 

Section 9.6 of Method 325B of Appendix A of this part to 

determine the detection limit of benzene for each sampler used 

to collect samples, background samples (if the owner or operator 

elects to do so), co-located samples and blanks. 

(d) The owner or operator shall use a dedicated 

meteorological station in accordance with Section 8.3 of Method 

325A of Appendix A of this part. 
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(1) The owner or operator shall collect and record hourly 

average meteorological data, including wind speed, wind 

direction and temperature. 

(2) The owner or operator shall follow the calibration and 

standardization procedures for meteorological measurements in 

EPA-454/B-08-002, Quality Assurance Handbook for Air Pollution 

Measurement Systems, Volume IV: Meteorological Measurements, 

Version 2.0 (Final), March 2008 (incorporated by reference—see 

§63.14). 

(e) The length of the sampling episode must be fourteen 

days, unless a shorter sampling episode is determined to be 

necessary under paragraph (g) or (i) of this section. A sampling 

episode is defined as the period during which the owner or 

operator collects the sample and does not include the time 

required to analyze the sample. 

(f) Within 30 days of completion of each sampling episode, 

the owner or operator shall determine whether the results are 

above or below the action level as follows: 

(1) For each sampling episode, the owner or operator shall 

determine the highest and lowest sample results for benzene from 

the sample pool and calculate the difference in concentration 

(Δc). 
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(i) The owner or operator shall adhere to the following 

procedures when one or more samples for the sampling episode are 

below the method detection limit for benzene: 

(A) If the lowest detected value of benzene is below 

detection, the owner or operator shall use zero as the lowest 

sample result when calculating Δc. 

(B) If all sample results are below the method detection 

limit, the owner or operator shall use the method detection 

limit as the highest sample result. 

(ii) If the owner or operator identifies an offsite upwind 

source or an onsite source excluded under §63.640(g) that 

contributes to the benzene concentration at any passive monitor 

and collects background samples according to an approved sitespecific monitoring plan, the owner or operator shall determine 

Δc using the calculation protocols outlined in the approved 

site-specific monitoring plan and in paragraph (i) of this 

section. 

(2) The owner or operator shall average the Δc values 

collected over the twelve months prior to and including the most 

recent sampling episode. The owner or operator shall update this 

value after receiving the results of each sampling episode. 

(3) The action level for benzene is 9 micrograms per cubic 

meter (μg/m3

). If the 12-month rolling average Δc value for 

benzene is less than 9 μg/m3

, the concentration is below the 
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action level. If the 12-month rolling average Δc value for 

benzene is equal to or greater than 9 μg/m3

, the concentration is 

above the action level, and the owner or operator shall conduct 

a root cause analysis and corrective action in accordance with 

paragraph (g) of this section. 

(g) Within 5 days of determining that the action level has 

been exceeded for any 12-month rolling average and no longer 

than 35 days after completion of the sampling episode, the owner 

or operator shall initiate a root cause analysis to determine 

the cause of such exceedance and to determine appropriate 

corrective action, as described in paragraphs (g)(1) through (4) 

of this section. The root cause analysis and corrective action 

analysis shall be completed 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 A7 of this chapter and repairing any leaks found. 

(2) Leak inspection using optical gas imaging as specified 

in §63.661 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 episodes 
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for Methods 325A and 325B of Appendix A of this part, or using 

active sampling techniques), or employing additional monitors to 

determine contributing offsite sources. 

(h) If, upon completion of the corrective actions described 

in paragraph (g) of this section, the action level is exceeded 

for the next sampling episode following the completion of the 

corrective action, the owner or operator shall develop a 

corrective action plan that describes the corrective action(s) 

completed to date, additional measures that the owner or 

operator proposes to employ to reduce fenceline concentrations 

below the action level, and a schedule for completion of these 

measures. The owner or operator shall submit the corrective 

action plan to the Administrator within 60 days after 

determining the action level was exceeded during the sampling 

episode following the completion of the initial corrective 

action. 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. 

(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 
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§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 sitespecific monitoring plan and receive approval of the sitespecific monitoring plan prior to using the near-field source 

alternative calculation for determining Δc provided in paragraph 

(i)(2) of this section. The site-specific monitoring plan shall 

include, at a minimum, the elements specified in paragraphs 

(i)(1)(i) through (v) of this section. 

(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 near-field 

source is present, identify for each monitoring location, the 

near field source or sources that are expected to contribute to 

fenceline concentration at that monitoring location. 

(iv) A description of (including sample calculations 

illustrating) the planned data reduction and calculations to 
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determine the near-field source concentration contribution for 

each monitoring location. 

(v) If more frequent monitoring is proposed or if a 

monitoring station other than a passive diffusive tub monitoring 

station is proposed, provide a detailed description of the 

measurement methods, measurement frequency, and recording 

frequency proposed for determining the uniform background or 

near-field source concentration contribution. 

(2) When an approved site-specific monitoring plan is used, 

the owner or operator shall determine Δc for comparison with the 

9 μg/m3

 action level using the requirements specified in 

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

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

following equation. 

Δci  MFCi  NFS i UB

where: 

Δci = The fenceline concentration, corrected for background, at 

measurement location i, micrograms per cubic meter 

(μg/m3

). 

MFCi = The measured fenceline concentration at measurement 

location i, μg/m3

. 

NFSi = The near-field source contributing concentration at 

measurement location i determined using the additional 

measurements and calculation procedures included in the 

site-specific monitoring plan, μg/m3

. For monitoring 

locations that are not included in the site-specific 

monitoring plan as impacted by a near-field source, use 

NFSi = 0 μg/m3

. 
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UB = The uniform background concentration determined using the 

additional measurements specified included in the sitespecific monitoring plan, μg/m3

. If no additional 

measurement location is specified in the site-specific 

monitoring plan for determining the uniform background 

concentration, use UB = 0 μg/m3

. 

(ii) When one or more samples for the sampling episode 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 

detection, 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 detection, the owner or operator shall 

use zero for the monitoring location concentration when 

calculating NFSi for that monitoring period. 

(C) If a fenceline monitoring location sample result is 

below the method detection limit, the owner or operator shall 

use the method detection limit as the sample result. 

(iii) Determine Δc for the monitoring period as the maximum 

value of Δci from all of the fenceline monitoring locations for 

that monitoring period. 
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(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. 

(ii) 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. 

(iii) 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. 
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(4) The approval by the Administrator of a site-specific 

monitoring plan will be based on the completeness, accuracy and 

reasonableness of the request process for a site-specific 

monitoring plan. Factors that the EPA 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 or if a 

monitoring station other than a passive diffusive tub monitoring 

station is proposed, the adequacy of the description of the 

measurement methods, measurement frequency, and recording 
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frequency proposed and the adequacy of the rationale for using 

the alternative monitoring frequency or method. 

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

recordkeeping and reporting requirements in §63.655(h) and (i). 

30. 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 subpart SS of this part according 

to the requirements in paragraphs (a) through (i) of this 

section. 

(a) As used in this section, all terms not defined in 

§63.641 shall have the meaning given them in subpart A, subpart 

WW, or subpart SS of this part. The definitions of “Group 1 

storage vessel” (item 2) and “storage vessel” in §63.641 shall 

apply in lieu of the definition of “storage vessel” in §63.1061. 

(1) An owner or operator may use good engineering judgment 

or test results to determine the stored liquid weight percent 

total organic HAP for purposes of group determination. Data, 

assumptions, and procedures used in the determination shall be 

documented. 
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(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 consensusbased 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) In addition to the options presented in 

§§63.1063(a)(2)(vii)(A), 63.1063(a)(2)(vii)(B), and 63.1064, an 
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external floating roof storage vessel may comply with 

§63.1063(a)(2)(vii) using a flexible enclosure system as 

described in item 6 of Appendix I: Acceptable Controls for 

Slotted Guidepoles Under the Storage Tank Emissions Reduction 

Partnership Program (65 FR 19893). 

(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 [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 

(2) All references to “promulgation of the referencing 

subpart” and “the promulgation date of the referencing subpart” 

in subpart WW of this part mean [THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. 

(3) All references to “promulgation date of standards for 

an affected source or affected facility under a referencing 

subpart” in subpart SS of this part mean [THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER]. 

(4) All references to “the proposal date of the relevant 

standard established pursuant to CAA section 112(f)” in subpart 
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SS of this part mean [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER]. 

(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 existing storage vessel fixed roof that meets 

the definition of Group 1 storage vessel (item 2) in §63.641 but 

not the definition of Group 1 storage vessel (item 1) in 

§63.641, the requirements of §63.1062 do not apply until the 

next time the storage vessel is completely emptied and degassed, 

or [THE DATE 10 YEARS AFTER PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], whichever occurs first. 

(e) Failure to perform inspections and monitoring required 

by this section shall constitute a violation of the applicable 

standard of this subpart. 

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

notification requirements do not apply. 

(g) References to the Notification of Compliance Status in 

§63.999(b) mean the Notification of Compliance Status required 

by §63.655(f). 
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(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 (c)(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 

§63.985(a)(3)(i) or (ii) for each closed vent system that 

contains bypass lines that could divert a vent stream to the 

atmosphere. Use of the bypass at any time to divert a Group 1 

storage vessel to the atmosphere is an emissions standards 

violation. Equipment such as low leg drains and equipment 

subject to §63.648 are not subject to this paragraph. 

(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 paragraph §63.984(a)(1) does not apply. 

31. Section 63.661 is added to read as follows: 
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§63.661 Alternative means of emission limitation: Monitoring 

equipment leaks using optical gas imaging. 

(a) Applicability. The owner or operator may only use an 

optical gas imaging instrument to screen for leaking equipment, 

as required by §63.648, if the requirements in paragraphs (a)(1) 

through (3) of this section are met. 

(1) The owner or operator may only use the optical gas 

imaging instrument as an alternative to provisions in §63.648 

that would otherwise require monitoring according to §60.485(b) 

or §63.180(b)(1) through (5), as applicable. The owner or 

operator shall continue to comply with all other requirements in 

§63.648 (e.g., weekly inspections of pumps; for relief valves, 

installation of a device that is capable of identifying and 

recording the time and duration of each pressure release, if 

applicable; sampling connection system requirements). 

(2) The owner or operator must be in compliance with the 

fenceline monitoring provisions of §63.658. 

(3) The optical gas imaging instrument must be able to meet 

all of the criteria and requirements specified in part 60, 

Appendix K of this chapter, and the owner or operator shall 

conduct monitoring according to part 60, Appendix K of this 

chapter. 
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(b) Compliance requirements. The owner or operator shall 

meet the requirements of paragraphs (b)(1) through (3) of this 

section. 

(1) The owner or operator shall identify the equipment and 

process units for which the optical gas imaging instrument will 

be used to identify leaks. 

(2) The owner or operator shall repair leaking equipment as 

required in the applicable section of part 60, subpart VV of 

this chapter or subpart H of this part. 

(3) Monitoring to confirm repair of leaking equipment must 

be conducted using the procedures referenced in paragraph (a)(2) 

of this section. 

(c) Recordkeeping. The owner or operator shall comply with 

the applicable requirements in §63.655(i). 

32. Section 63.670 is added to read as follows: 

§63.670 Requirements for flare control devices. 

On or before [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the owner or operator of a flare used as a control 

device for an emission point subject to this subpart shall meet 

the applicable requirements for flares as specified in 

paragraphs (a) through (q) of this section and the applicable 

requirements in §63.671. The owner or operator may elect to 

comply with the requirements of paragraph (r) of this section in 
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lieu of the requirements in paragraphs (g) through (o) of this 

section, as applicable. 

(a) Halogenated vent streams. The owner or operator shall 

not use a flare to control halogenated vent streams as defined 

in §63.641. 

(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. The pilot system must 

be equipped with an automated device to relight the pilot if 

extinguished. The owner or operator shall monitor for the 

presence of a pilot flame as specified in paragraph (h) of this 

section. 

(c) Visible emissions. Each flare must be designed for and 

operated with no visible emissions, except for periods not to 

exceed a total of 5 minutes during any 2 consecutive hours. The 

owner or operator shall monitor for visible emissions from the 

flare as specified in paragraph (i) of this section. 

(d) Flare tip velocity. For each flare, the owner or 

operator shall comply with either paragraph (d)(1) or (d)(2) of 

this section, provided the appropriate monitoring systems are 

in-place. If a total hydrocarbon analyzer is used for 

compositional analysis as allowed under section (g)(4) of this 

section, then the owner or operator must comply with paragraph 

(d)(1) of this section. 
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(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 when regulated material is being routed to the flare. 

The owner or operator shall monitor Vtip using the procedures 

specified in paragraph (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 at all times regulated 

material is being routed to the flare. The owner or operator 

shall monitor Vtip using the procedures specified in paragraph 

(i) and (k) of this section and monitor gas composition and 

determine NHVvg using the procedures specified in paragraphs (j) 

and (l) of this section. 

  850

1,212

10

  vg

max

NHV

Log V

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) Target combustion zone gas properties. For each flare, 

the owner or operator shall comply with the applicable 

requirements in either paragraph (f)(1), (2), or (3) of this 

section. The owner or operator may elect to comply with any of 
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these applicable requirements at any time (e.g., may elect to 

comply with the requirements in paragraph (e)(1) during certain 

flow conditions and comply with the requirements in paragraph 

(e)(2) or (e)(3) under different flow conditions) provided that 

the owner or operator has the appropriate monitoring equipment 

to determine compliance with the specified requirement. 

(1) The net heating value of flare combustion zone gas 

(NHVcz) must be greater than or equal to the target values in 

paragraphs (e)(1)(i) or (ii), as applicable, when regulated 

material is being routed to the flare. The owner or operator 

shall monitor and calculate NHVcz as specified in paragraph (m) 

of this section. 

(i) For flares meeting all three requirements in paragraph 

(e)(4) of this section, the target NHVcz value is 380 British 

thermal units per standard cubic feet (Btu/scf). 

(ii) For all flares other than those meeting all three 

requirements in paragraph (e)(4) of this section, the target 

NHVcz value is 270 Btu/scf. 

(2) The lower flammability limit of the combustion zone gas 

(LFLcz) must be less than or equal to the target values in 

paragraphs (e)(2)(i) or (ii), as applicable, when regulated 

material is being routed to the flare. The owner or operator 

shall monitor and calculate LFLcz as specified in paragraph (n) 

of this section. 
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(i) For flares meeting all three requirements in paragraph 

(e)(4) of this section, the target LFLcz value is 0.11 volume 

fraction. 

(ii) For all flares other than those meeting all three 

requirements in paragraph (e)(4) of this section, the target 

LFLcz value is 0.15 volume fraction. 

(3) The total volumetric fraction of hydrogen and 

combustible organic components present in the combustion zone 

gas (Ccz), as propane, must be greater than or equal to the 

target values in paragraphs (e)(3)(i) or (ii), as applicable, 

when regulated material is being routed to the flare. The owner 

or operator shall monitor and calculate Ccz as specified in 

paragraph (l) of this section. 

(i) For flares meeting all three requirements in paragraph 

(e)(4) of this section, the target Ccz value is 0.23 volume 

fraction as propane. 

(ii) For all flares other than those meeting all three 

requirements in paragraph (e)(4) of this section, the target Ccz

value is 0.18 volume fraction as propane. 

(4) More stringent combustion zone gas target properties 

apply only during those flare flow periods when all three 

conditions in paragraphs (e)(4)(i) through (iii) simultaneously 

exist. The owner or operator shall monitor and calculate 
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hydrogen and cumulative olefin combustion zone concentrations as 

specified in paragraph (o) of this section: 

(i) The concentration of hydrogen in the combustion zone is 

greater than 1.2 percent by volume. 

(ii) The cumulative concentration of olefins in the 

combustion zone is greater than 2.5 percent by volume. 

(iii) The cumulative concentration of olefins in the 

combustion zone plus the concentration of hydrogen in the 

combustion zone is greater than 7.4 percent by volume. 

(f) Target dilution parameters for flares with perimeter 

assist air. For each flare actively receiving perimeter assist 

air, the owner or operator shall comply with the applicable 

requirements in either paragraph (f)(1), (2), or (3) of this 

section in addition to complying with the target combustion zone 

gas properties as specified in paragraph (e) of this section. 

The owner or operator may elect to comply with any of these 

applicable requirements at any time (e.g., may elect to comply 

with the requirements in paragraph (f)(1) during certain flow 

conditions and comply with the requirements in paragraph (f)(2) 

or (f)(3) under different flow conditions) provided that the 

owner or operator has the appropriate monitoring equipment to 

determine compliance with the specified requirement. 

(1) The net heating value dilution parameter (NHVdil) must 

be greater than or equal to the target values in paragraphs 
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(f)(1)(i) or (ii), as applicable, when regulated material is 

being routed to the flare. The owner or operator shall monitor 

and calculate NHVdil as specified in paragraph (o) of this 

section. 

(i) For flares meeting all three requirements in paragraph 

(e)(4) of this section, the target NHVdil value is 31 British 

thermal units per square foot (Btu/ft2

). 

(ii) For all flares other than those meeting all three 

requirements in paragraph (e)(4) of this section, the target 

NHVdil value is 22 Btu/ft2

. 

(2) The lower flammability limit dilution parameter (LFLdil) 

must be less than or equal to the target values in paragraphs 

(f)(2)(i) or (ii), as applicable, when regulated material is 

being routed to the flare. The owner or operator shall monitor 

and calculate LFLdil as specified in paragraph (o) of this 

section. 

(i) For flares meeting all three requirements in paragraph 

(e)(4) of this section, the target LFLdil value is 1.6 volume 

fraction per foot (volume fraction/ft). 

(ii) For all flares other than those meeting all three 

requirements in paragraph (e)(4) of this section, the target 

LFLdil value is 2.2 volume fraction/ft. 

(3) The combustibles concentration dilution parameter (Cdil) 

must be greater than or equal to the target values in paragraphs 
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(f)(3)(i) or (ii), as applicable, when regulated material is 

being routed to the flare. The owner or operator shall monitor 

and calculate Cdil as specified in paragraph (o) of this section. 

(i) For flares meeting all three requirements in paragraph 

(e)(4) of this section, the target Cdil value is 0.015 volume 

fraction-ft. 

(ii) For all flares other than those meeting all three 

requirements in paragraph (e)(4) of this section, the target Ccz

value is 0.012 volume fraction-ft. 

(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 at a minimum of once 

per day 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, 
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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. 

(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. 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. 

(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 
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20 °C [68 °F] and a pressure of 1 atm). The flare vent gas flow 

rate monitoring system(s) must also be able to output flow in 

actual conditions for use in the flare tip velocity calculation. 

(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. 

MWt

Q Q mass

vol

 385.3 

where: 

Qvol = Volumetric flow rate, standard cubic feet per second. 

Qmass = Mass flow rate, pounds per second. 

385.3 = Conversion factor, standard cubic feet per pound-mole. 

MWt = Molecular weight of the gas at the flow monitoring 

location, pounds per 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 
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a continuous volumetric flow monitoring systems provided the 

molecular weight of the gas is known. For assist steam, use a 

molecular weight of 18 pounds per pound-mole. For assist air, 

use a molecular weight of 29 pounds per pound-mole. For flare 

vent gas, molecular weight must be determined using 

compositional analysis as specified in paragraph (j) of this 

section. 

(j) Flare vent gas composition monitoring. The owner or 

operator shall determine the concentration of individual 

components in the flare vent gas using either the methods 

provided in paragraphs (j)(1) or (j)(2) of this section, to 

assess compliance with the operating limits in paragraph (e) of 

this section and, if applicable, paragraphs (d) and (f) of this 

section. Alternatively, the owner or operator may elect to 

directly monitor the net heating value of the flare vent gas 

following the methods provided in paragraphs (j)(3) of this 

section or the combustibles concentration following the methods 

provided in paragraphs (j)(4) of this section.. The owner or 

operator electing to directly monitor the net heating value of 

the flare vent gas must comply with the net heating value 

operating limits in paragraph (e) and, if applicable, paragraph 

(f) of this section. The owner or operator electing to directly 

monitor the combustibles concentration in the flare vent gas 

must comply with the combustibles concentration operating limits 
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in paragraph (e) and, if applicable, paragraph (f) of this 

section, and must comply with the maximum velocity requirements 

in paragraph (d)(1) of this section. 

(1) Except as provided in paragraph (j)(5) 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 paragraph (j)(5) 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 A6, ASTM D1945-03 (Reapproved 2010) (incorporated by reference—

see §63.14), or ASTM UOP539-12 (incorporated by reference—see 

§63.14). 

(3) The owner or operator shall install, operate, 

calibrate, and maintain a monitoring system capable of 

continuously measuring, calculating, and recording NHVvg. at 

standard conditions. 
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(4) The owner or operator shall install, operate, 

calibrate, and maintain a monitoring system capable of 

continuously measuring, calculating, and recording total 

hydrocarbon content (as propane) as a surrogate for combustibles 

concentration. 

(5) Direct compositional monitoring is not required for 

pipeline quality natural gas streams. In lieu of monitoring the 

composition of a pipeline quality natural gas stream, the 

following composition can be used for any pipeline quality 

natural gas stream. 

(i) 93.2 volume percent (vol %) methane. 

(ii) 3.2 vol % ethane. 

(iii) 0.6 vol % propane. 

(iv) 0.3 vol % butane. 

(v) 2.0 vol % hydrogen. 

(vi) 0.7 vol % nitrogen.

(k) Calculation methods for 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. 
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This area does not include any stability tabs, stability rings, 

and upper steam or air tubes because vent gas does not exit 

through them. 

(2) The owner or operator shall determine the cumulative 

volumetric flow of 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. 

(i) Use set 15-minute time periods starting at 12 midnight 

to 12:15 AM, 12:15 AM to 12:30 AM and so on concluding at 11:45 

PM to midnight when calculating 15-minute block average flow 

volumes. 

(ii) If continuous pressure/temperature monitoring 

system(s) and engineering calculations are used as allowed under 

paragraph (i)(4) of this section, the owner of operator shall, 

at a minimum, determine the 15-minute block average temperature 

and pressure from the monitoring system and use those values to 

perform the engineering calculations to determine the cumulative 

flow over the 15-minute block average period. Alternatively, the 

owner or operator may divide the 15-minute block average period 

into equal duration subperiods (e.g., three 5-minute periods) 

and determine the average temperature and pressure for each 

subperiod, perform engineering calculations to determine the 

flow for each subperiod, then add the volumetric flows for the 
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subperiods to determine the cumulative volumetric flow of vent 

gas for the 15-minute block average period. 

(3) The 15-minute block average Vtip shall be calculated 

using the following equation. 

 900  Area

Q V cum

tip

where: 

Vtip = Flare tip velocity, feet per second. 

Qcum = Cumulative volumetric flow over 15-minute block average 

period, 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 following the 

requirements in paragraph (j) and (l) of this section and 

calculate Vmax using the equation in paragraph (d)(2) of this 

section in order to compare Vtip to Vmax on a 15-minute block 

average basis. 

(l) Calculation methods for determining flare vent gas 

parameters. The owner or operator shall determine the net 

heating value, lower flammability limit, combustibles 

concentration vent gas (NHVvg, LFLvg, and Cvg, respectively) based 

on the composition monitoring data on a 15-minute block average 

basis according to the following requirements. 
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(1) Use set 15-minute time periods starting at 12 midnight 

to 12:15 AM, 12:15 AM to 12:30 AM and so on concluding at 11:45 

PM to midnight when calculating 15-minute block averages. 

(2) When a continuous monitoring system is used to 

determine flare vent gas composition, net heating value, or 

total hydrocarbon content: 

(i) Use the results from the first sample collected during 

an event, (for periodic flare vent gas flow events) for the 

first and second 15-minute block associated with that event. 

(ii) For all other 15-minute block periods, 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 the 

purpose of this requirement, use the time that the results 

become available rather than the time the sample was collected. 

For example, if a sample is collected at 12:25 AM and the 

analysis is completed at 12:38 AM, the results are available at 

12:38 AM and these results would be used to determine compliance 

during the 15-minute block period from 12:45 AM to 1:00 AM. 

(3) 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. 
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(ii) Use the results from subsequent grab sampling events 

for all 15 minute periods starting with the 15-minute block in 

which the sample was collected and ending with the 15-minute 

block prior to the 15-minute block in which the next grab sample 

is collected. For the purpose of this requirement, use the time 

the sample was collected rather than the time the analytical 

results become available. 

(4) The owner or operator shall determine NHVvg from 

compositional analysis data by using the following equation. If 

the owner or operator uses a monitoring system(s) capable of 

continuously measuring, calculating, and recording NHVvg, as 

provided in paragraph (j)(3) of this section, the owner or 

operator shall use the NHVvg as determined by the continuous NHVvg

monitor. 





n

i

vg iNHVi NHV x

1

where: 

NHVvg = Net heating value of flare vent gas, Btu/scf. 

i = Individual component in flare vent gas. 

n = Number of components in flare vent gas. 

xi = Concentration of component i in flare vent gas, volume 

fraction. 

NHVi = Net heating value of component i according to table 12 of 

this subpart, Btu/scf. If the component is not specified 

in table 12 of this subpart, the heats of combustion may 

be determined using any published values where the net 
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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. 

(5) The owner or operator shall calculate LFLvg using the 

following equation: 

 













  n

i i

vg

LFL

χ

LFL

i

1

1

where: 

LFLvg = Lower flammability limit of flare vent gas, volume 

fraction. 

n = Number of components in the vent gas. 

i = Individual component in the vent gas. 

χi = Concentration of component i in the vent gas, volume 

percent (vol %). 

LFLi = Lower flammability limit of component i according to 

table 12 of this subpart, vol %. If the component is not 

specified in table 12 of this subpart, the owner or 

operator shall use the LFL value as published in Appendix 

A of Flammability Characteristics of Combustible Gases 

and Vapors, U.S. Bureau of Mines, Bulletin 627, 1965 

(incorporated by reference—see §63.14). All inerts, 

including nitrogen, shall be assumed to have an infinite 

lower flammability limit (e.g., LFLN2 = ∞, so that χN2/ 

LFLN2 = 0). 

(6) The owner or operator shall calculate Cvg using the 

following equation. If the owner or operator uses a total 

hydrocarbon analyzer, the owner or operator may substitute the 

“∑χi” term in the following equation with the total volumetric 

hydrocarbon concentration present in the flare vent gas (vol % 
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as propane), and the owner or operator may choose to ignore the 

concentration of hydrogen in the flare vent gas. 

100%

1 3 



 



  



 



 





h

n

i

i i

vg

χ

CMN χ

C

where: 

Cvg = Total volumetric fraction of hydrogen and combustible 

organic components present in the flare vent gas, volume 

fraction. For the purposes of Cvg, carbon dioxide is not 

considered to be a combustible organic component, but 

carbon monoxide may be included in Cvg. 

n = Number of individual combustible organic components in 

flare vent gas. 

i = Individual combustible organic component in flare vent 

gas. 

χi = Concentration of combustible organic component i in flare 

vent gas, vol %. 

CMNi = Carbon mole number of combustible organic component i in 

flare vent gas, mole carbon atoms per mole of compound. 

E.g., CMN for ethane (C2H6) is 2; CMN for propane (C3H8) 

is 3. 

χh = Concentration of hydrogen in flare vent gas, vol %. 

100% = Constant, used to convert volume percent to volume 

fraction. 

(m) Calculation methods for determining combustion zone 

parameters. The owner or operator shall determine the net 

heating value, lower flammability limit and combustibles 

concentration of the combustion zone gas (NHVcz, LFLcz, and Ccz, 

respectively) based on the vent gas and assist gas flow rates on 

a 15-minute block average basis according to the following 
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requirements. For periods when there is no assist steam flow or 

premix assist air flow, the combustion zone parameters are equal 

to the vent gas parameters. 

(1) The owner or operator shall calculate NHVcz using the 

following equation: 

  vg s a,premix

vg vg

cz Q Q Q

Q NHV

NHV

 

 

where: 

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

NHVvg = Net heating value of flare vent gas for the 15-minute 

block period, Btu/scf. 

Qvg = Cumulative volumetric flow of flare vent gas during the 

15-minute block period, scf. 

Qs = Cumulative volumetric flow of total steam during the 

15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air during 

the 15-minute block period, scf. 

(2) The owner or operator shall calculate LFLcz using the 

following equation: 

 

vg

vg vg s a,premix

cz Q

LFL Q Q Q LFL

   

where: 

LFLcz = Lower flammability limit of combustion zone gas, volume 

fraction. 

LFLvg = Lower flammability limit of flare vent gas determined 

for the 15-minute block period, volume fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during the 

15-minute block period, scf. 
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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. 

(3) The owner or operator shall calculate Ccz using the 

following equation: 

  vg s a,premix

vg vg

cz Q Q Q

Q C

C

 

 

where: 

Ccz = Combustibles concentration in the combustion zone gas, 

volume fraction. 

Cvg = Combustibles concentration of flare vent gas determined 

for the 15-minute block period, volume fraction. 

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. 

(n) Calculation methods for determining dilution 

parameters. The owner or operator shall determine the net 

heating value, lower flammability limit and combustibles 

concentration dilution parameters (NHVdil, LFLdil, and Cdil, 

respectively) based on the vent gas and perimeter assist air 

flow rates on a 15-minute block average basis according to the 

following requirements only during periods when perimeter assist 

air is used. For 15-minute block periods when there is no 
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Page 544 of 809 

cumulative volumetric flow of perimeter assist air, the dilution 

parameters do not need to be calculated. 

(1) The owner or operator shall calculate NHVdil using the 

following equation: 

  vg s a,premix a,perimeter

vg vg

dil Q Q Q Q

Q Diam NHV

NHV

  

  

where: 

NHVdil = Net heating value of combustion zone gas, Btu/ft2

NHVvg = Net heating value of flare vent gas determined for 

the 15-minute block period, Btu/scf. 

Qvg = Cumulative volumetric flow of flare vent gas during 

the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the 

flare tip for flare vent gas flow, ft. Use the area 

as determined in paragraph (k)(1) of this section 

and determine the diameter as Diam  2 Area π

Qs = Cumulative volumetric flow of total steam during the 

15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air 

during the 15-minute block period, scf. 

Qa,perimiter = Cumulative volumetric flow of perimeter assist air 

during the 15-minute block period, scf. 

(2) The owner or operator shall calculate LFLdil using the 

following equation: 

 

Q Diam

LFL Q Q Q Q LFL

vg

vg vg s a,premix a,perimeter

dil 

    

where: 

LFLdil = Lower flammability limit of combustion zone gas, ft-
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 545 of 809 1

. 

LFLvg = Lower flammability limit of flare vent gas 

determined for the 15-minute block period, volume 

fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during 

the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the 

flare tip for flare vent gas flow, ft. Use the area 

as determined in paragraph (k)(1) of this section 

and determine the diameter as Diam  2 Area π

Qs = Cumulative volumetric flow of total steam during the 

15-minute block period, scf. 

Qa,premix = Cumulative volumetric flow of premix assist air 

during the 15-minute block period, scf. 

Qa,perimiter = Cumulative volumetric flow of perimeter assist air 

during the 15-minute block period, scf. 

(3) The owner or operator shall calculate Cdil using the 

following equation: 

  vg s a,premix a,perimeter

vg vg

dil Q Q Q Q

Q Diam C

C

  

  

where: 

Ccz = Combustibles concentration in the combustion zone 

gas, volume fraction. 

Cvg = Combustibles concentration of flare vent gas 

determined for the 15-minute block period, volume 

fraction. 

Qvg = Cumulative volumetric flow of flare vent gas during 

the 15-minute block period, scf. 

Diam = Effective diameter of the unobstructed area of the 

flare tip for flare vent gas flow, ft. Use the area 

as determined in paragraph (k)(1) of this section 

and determine the diameter as Diam  2 Area π
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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) Special provisions for assessing olefins and hydrogen 

combustion zone concentrations. The owner or operator shall 

determine the olefins and hydrogen content of the flare vent gas 

and calculate the combustion zone concentrations for the 

purposes of assessing the criteria in paragraph (e)(4) of this 

section on a 15-minute block average according to the following 

requirements. 

(1) The olefins concentration shall be determined as the 

cumulative sum of the following flare gas constituents: 

ethylene, acetylene, propylene, propadiene, all isomers of n- or 

iso-butene, and all isomers of butadiene. 

(2) If individual component concentrations are determined 

following the methods specified in paragraphs (j)(1) or (j)(2) 

of this section, the measured vent gas concentrations shall be 

used to determine the hydrogen, olefins, and hydrogen plus 

olefins concentration in the combustion zone using the following 

general equation. The methods specified in paragraphs (l)(1) 

through (3) of this section, as applicable, shall be used to 
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assign the vent gas concentration results to a specific 15-

minute block period. 

  vg s a,premix

vg vg

cz Q Q Q

Q A

A

 

 

where: 

Acz = Concentration of target compound(s) “A” (representing 

either the olefins concentration, the hydrogen 

concentration, or the sum of the olefins and hydrogen 

concentration) in the combustion zone gas, volume 

fraction. 

Avg = Concentration of target compound(s) “A” (representing 

either the olefins concentration, the hydrogen 

concentration, or the sum of the olefins and hydrogen 

concentration) in the flare vent gas determined for the 

15-minute block period, volume fraction. 

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. 

(3) If NHVvg or total hydrocarbon monitoring systems are 

used as provided in paragraphs (j)(3) or (j)(4) of this section, 

the owner or operator may elect to determine the hydrogen and 

olefins concentrations using any of the following methods. 

(i) The owner or operator may elect to assume the hydrogen 

concentration, the olefins concentration, and the olefins plus 

hydrogen concentration in the combustion zone gas exceed all 

three criteria in (e)(4) at all times without making specific 

measurements of olefins or hydrogen concentrations. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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(ii) The owner or operator may elect to use process 

knowledge and engineering calculations to determine the highest 

flare vent gas concentrations of olefins and hydrogen that can 

reasonably be expected to be discharged to the flare and the 

highest concentration of olefins plus hydrogen that can 

reasonably be expected to be discharged to the flare while the 

flare vent gas concentrations exceed the target combustion zone 

concentrations in paragraphs (e)(4)(i) and (ii) of this section 

at the same time. The owner or operator shall take daily flare 

vent gas samples for fourteen days or for 7 flaring events, 

whichever results in the greatest number of grab samples to 

verify that the calculated values are representative of the 

highest concentrations that reasonably be expected to be 

discharged to the flare. 

(A) If the highest flare vent gas concentrations of 

olefins, hydrogen, and olefins plus hydrogen that can reasonably 

be expected to be discharged to the flare do not exceed all 

three combustion zone concentration criteria in paragraph (e)(4) 

of this section, for example, if the flare does not service any 

process units that contain olefins, then the engineering 

assessment is sufficient to document that all three criteria in 

paragraph (e)(4) of this section are not met and that the more 

stringent operating limits do not apply at any time. 
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(B) If the highest flare vent gas concentrations of 

olefins, hydrogen, and olefins plus hydrogen that can reasonably 

be expected to be discharged to the flare exceed all three 

combustion zone concentration criteria in paragraph (e)(4), then 

the owner or operator will use the concentrations determined 

from the engineering analysis as the vent gas concentrations 

that exist in the vent gas at all times and use the equation in 

paragraph (o)(2) of this section to determine the combustion 

zone concentrations of olefins, 

(C) If the operation of process units connected to the 

flares change or new connections are made to the flare and these 

changes can reasonably be expected to alter the highest vent gas 

concentrations of olefins, hydrogen, and/or olefins plus 

hydrogen received by the flare, a new engineering assessment and 

sampling period for verification will be conducted following the 

requirements of paragraph (o)(3)(ii) of this section. 

(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 sitespecific operating limits that shall apply specifically to a 

selected flare. Site-specific operating limits include 
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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 

test 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 sitespecific test plan and receive approval of the site-specific 

test plan prior to conducting any flare performance test 

intended for use in developing site-specific operating limits. 

The site-specific test 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 test plan, the owner 

or operator shall conduct a performance test for the flare 

following the procedures described in the site-specific test 

plan. 

(i) The design and dimensions of the flare, flare type 

(air-assisted only, steam-assisted only, air- and steamassisted, pressure-assisted, or non-assisted), and description 
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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 test. 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. 
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(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 test. 

A sufficient number of test runs shall be conducted to identify 

the point at which the combustion/destruction efficiency of the 

flare deteriorates. 

(viii) If the flare can receive vent gases containing 

olefins and hydrogen above the levels specified for the 

combustion zone gas in paragraph (e)(4) of this section, a 

sufficient number of tests must be conducted while exceeding 

these limits to assess whether more stringent operating limits 

are required under these conditions. 

(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. 
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(i) The design and dimensions of the flare, flare type 

(air-assisted only, steam-assisted only, air- and steamassisted, 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 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. 
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(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 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 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 test 

conducted following the methods in an approved site-specific 
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test plan for an operating limit(s) that shall apply 

specifically to that flare. 

(ii) The request must be submitted to the Administrator for 

approval. The owner or operator must continue to comply with the 

applicable standards for flares in this subpart until the 

requirements in 40 CFR 63.6(g)(1) are met and a notice is 

published in the Federal Register allowing use of such an 

alternative means of emission limitation. 

(iii) The request shall also be submitted to the following 

address: U.S. Environmental Protection Agency, Office of Air 

Quality Planning and Standards, Sector Policies and Programs 

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

Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, 

NC 27711. Electronic copies in lieu of hard copies may also be 

submitted to refineryrtr@epa.gov. 

(iv) If the Administrator finds any deficiencies in the 

request, the request must be revised to address the deficiencies 

and be re-submitted for approval within 45 days of receipt of 

the notice of deficiencies. The owner or operator must comply 

with the revised request as submitted until it is approved. 

(4) The approval process for a request for a flare-specific 

operating limit(s) is described in paragraphs (r)(4)(i) through 

(iii) of this section. 
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(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 test 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 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. 
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(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) All monitoring equipment must meet the 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 maintenance periods, instrument adjustments 

or checks to maintain precision and accuracy, calibration 

checks, and zero and span adjustments, the owner or operator 
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Page 558 of 809 

shall operate all CPMS and collect data continuously 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, the owner or operator shall comply with 

the out-of-control procedures described in paragraphs (c) of 

this section. The CPMS monitoring plan must be submitted to the 

Administrator for approval upon request. 

(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. The owner or operator shall have the 

CPMS monitoring plan readily available on-site at all times and 

shall submit a copy of the CPMS monitoring plan to the 

Administrator upon request by the Administrator. The CPMS 

monitoring plan must contain the information listed in 

paragraphs (b)(1) through (5) of this section. 
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(1) Identification of the specific flare being monitored 

and the flare type (air-assisted 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 (c)(3)(i) through (viii) of this 

section. 

(i) Manufacturer and model number for all monitoring 

equipment components. 

(ii) Performance specifications, as provided by the 

manufacturer, and any differences expected for this installation 

and operation. 

(iii) The location of the CPMS sampling probe or other 

interface and a justification of how the location meets the 

requirements of paragraph (a)(1) of this section. 

(iv) Placement of the CPMS readout, or other indication of 

parameter values, indicating how the location meets the 

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

(v) Span of the analyzer. The span must encompass all 

expected concentrations and meet the requirements of paragraph 

(b)(10) of this section. 
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(vi) How data outside of the analyzer’s span 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-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. 

(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 
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(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 

(c)(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 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. 
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(c) Out-of-control periods. For each CPMS, 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), midlevel (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-of-control 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-ofcontrol 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. 
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(d) CPMS data reduction. The owner or operator shall reduce 

data from a CPMS 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 the compounds that exist in 

the flare gas stream. All of the calibration gases may be 

combined in one cylinder. If multiple calibration gases are 
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necessary to cover all compounds, the owner or operator must 

calibrate the instrument on all of the gases. 

(ii) The owner or operator must use a surrogate calibration 

gas consisting of C1 through C7 normal hydrocarbons. All of the 

calibration gases may be combined in one cylinder. If multiple 

calibration gases are necessary to cover all compounds, the 

owner or operator must calibrate the instrument on all of the 

gases. 

(3) If the owner or operator chooses to use a surrogate 

calibration gas under paragraph (e)(2)(ii) of this section, the 

owner or operator must comply with the following paragraphs. 

(i) Use the response factor for the nearest normal 

hydrocarbon (i.e., n-alkane) in the calibration mixture to 

quantify unknown components detected in the analysis. 

(ii) Unknown compounds that elute after n-heptane must 

either be identified and quantified using an identical compound 

standard, or the owner or operator must extend the calibration 

range to include the additional normal hydrocarbons necessary to 

perform the unknown hydrocarbon quantitation procedure. 

34. Table 6 is amended by: 

a. Revising the entry “63.5(d)(1)(ii)”; 

b. Revising the entry “63.5(f)”; 

c. Removing the entry “63.6(e)”; 
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d. Adding, in numerical order, the entries “63.6(e)(1)(i) 

and (ii)” and “63.6(e)(1)(iii)”; 

e. Revising the entries “63.6(e)(3)(i)” and 

“63.6(e)(3)(iii)–63.6(e)(3)(ix)”; 

f. Revising the entry “63.6(f)(1)”; 

g. Removing the entry “63.6(f)(2) and (3)”; 

h. Adding, in numerical order, the entries “63.6(f)(2)” and 

“63.6(f)(3)”; 

i. Removing the entry “63.6(h)(1) and 63.6(h)(2)”; 

j. Adding, in numerical order, the entries “63.6(h)(1)” and 

“63.6(h)(2)”; 

k. Revising the entry “63.7(b)”; 

l. Revising the entry “63.7(e)(1)”; 

m. Removing the entry “63.8(a)”; 

n. Adding, in numerical order, the entries “63.8(a)(1) and 

(2),” “63.8(a)(3)” and “63.8(a)(4)”; 

o. Revising the entry “63.8(c)(1)”; 

p. Adding, in numerical order, the entries “63.8(c)(1)(i)” 

and “63.8(c)(1)(iii)”; 

q. Revising the entries “63.8(c)(4)” and “63.8(c)(5)–

63.8(c)(8)”; 

r. Revising the entries “63.8(d)” and “63.8(e)”; 

s. Revising the entry “63.8(g)”; 
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t. Revising the entries “63.10(b)(2)(i)” and 

“63.10(b)(2)(ii)”; 

u. Revising the entries “63.10(b)(2)(iv)” and 

“63.10(b)(2)(v)”; 

v. Revising the entry “63.10(b)(2)(vii)”; 

w. Removing the entry “63.10(c)(9)–63.10(c)(15)”; 

x. 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)”; 

y. Removing the entries “63.10(d)(5)(i)” and 

“63.10(d)(5)(ii)”; 

z. Adding, in numerical order, the entry “63.10(d)(5)”; 

aa. Removing the entry “63.11–63.16”; 

bb. Adding, in numerical order, the entries “63.11” and 

“63.12–63.16”; 

cc. Removing footnote b. 

The revisions and additions read as follows: 

Table 6—General Provisions Applicability to Subpart CCa 

Reference 

Applies 

to 

subpart 

CC Comment 

* * * * * 

63.5(d)(1)(ii) Yes Except that for affected sources subject to 

subpart CC, emission estimates specified in 

§63.5(d)(1)(ii)(H) are not required, and 

§63.5(d)(1)(ii)(G) and (I) are Reserved and do 

not apply. 

* * * * * 

63.5(f) Yes Except that the cross-reference in §63.5(f)(2) 

to §63.9(b)(2) does not apply. 
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* * * * * 

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 

subpart CC does not require a site-specific 

test plan. 

63.6(f)(3) Yes Except the cross-references to §63.6(f)(1) and 

§63.6(e)(1)(i) are changed to §63.642(n). 

* * * * * 

63.6(h)(1) No 

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

* * * * * 

63.7(b) Yes Except subpart CC 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 §63.8(c)(iii). 

63.8(c)(1)(i) No See §63.642(n). 

63.8(c)(1)(iii) No 

* * * * * 

63.8(c)(4) Yes Except that for sources other than flares, 

subpart CC specifies the monitoring cycle 

frequency specified in §63.8(c)(4)(ii) is “once 

every hour” rather than “for each successive 

15-minute period.” 

63.8(c)(5)–

63.8(c)(8) 

No Subpart CC specifies continuous monitoring 

system requirements. 
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63.8(d) No Subpart CC specifies quality control procedures 

for continuous monitoring systems. 

63.8(e) Yes 

* * * * * 

63.8(g) No Subpart CC 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 See §63.655(i)(11) 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 to 

minimize emissions and correct the failure. 

* * * * * 

63.10(b)(2)(iv) No 

63.10(b)(2)(v) No 

* * * * * 

63.10(b)(2)(vii) No §63.655(i) of subpart CC specifies records to 

be kept for parameters measured with continuous 

monitors. 

* * * * * 

63.10(c)(9) No Reserved. 

63.10(c)(10)–

63.10(c)(11) 

No See §63.655(i)(11) for malfunctions 

recordkeeping requirements. 

63.10(c)(12)–

63.10(c)(15) 

No 

* * * * * 

63.10(d)(5) No See §63.655(g)(12) for malfunctions 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 

a

Wherever subpart A specifies “postmark” dates, submittals may be sent by 

methods other than the U.S. Mail (e.g., by fax or courier). Submittals shall 

be sent by the specified dates, but a postmark is not required. 

35. Table 10 is amended by: 

a. Redesignating the entry “Flare” as “Flare (if meeting 

the requirements of 63.643 and 63.644)”; 
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b. Adding the entry “Flare (if meeting the requirements of 

63.670 and 63.671)” after the 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: 

Table 10—Miscellaneous Process Vents—Monitoring, Recordkeeping 

and Reporting Requirements for Complying With 98 Weight-Percent 

Reduction of Total Organic HAP Emissions or a Limit of 20 Parts 

Per Million by Volume 

Control device 

Parameters to be 

monitoreda

Recordkeeping and reporting 

requirements for monitored 

parameters 

* * * * * 

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)—PRg. 

All control 

devices 

Volume of the gas stream 

diverted to the 

atmosphere from the 

control device 

(63.644(c)(1)) or 

1. Continuous recordsc. 

 2. Record and report the times 

and durations of all periods 

when the vent stream is diverted 

through a bypass line or the 

monitor is not operating—PRg

. 

 Monthly inspections of 

sealed valves 

(63.644(c)(2)) 

1. Records that monthly 

inspections were performed. 

 2. Record and report all monthly 

inspections that show the valves 

are not closed or the seal has 

been changed—PRg

. a

 Regulatory citations are listed in parentheses. 

* * * * * 

c

 “Continuous records” is defined in §63.641. 

* * * * * 
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 PR = Periodic Reports described in §63.655(g). 

* * * * * 

i

 Process vents that are routed to refinery fuel gas systems are not regulated 

under this subpart provided that on and after [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

any flares receiving gas from that fuel gas system are in compliance with 

§63.670. No monitoring, recordkeeping, or reporting is required for boilers 

and process heaters that combust refinery fuel gas. 

36. Table 11 is added to read as follows: 

Table 11—Compliance Dates and Requirements 

If the 

construction/ 

reconstruction 

datea

 is... 

Then the owner or 

operator must comply 

with... 

And the owner or 

operator must 

achieve 

compliance... 

Except as 

provided in... 

(1) After 

[INSERT THE DATE 

OF PUBLICATION 

OF THESE 

PROPOSED 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(i) Requirements for 

new sources in 

§§63.640 through 

63.642, §63.647, 

§§63.650 through 

63.653, and §§63.656 

through 63.660 

(a) Upon initial 

startup or [THE 

DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

whichever is later 

(1) §63.640(k), 

(l) and (m) 

(ii) The new source 

requirements in 

§63.654 for heat 

exchange systems 

(a) Upon initial 

startup or October 

28, 2009, 

whichever is later 

(1) §63.640(k), 

(l) and (m) 

(2) After 

September 4, 

2007 but on or 

before [INSERT 

THE DATE OF 

PUBLICATION OF 

THESE PROPOSED 

AMENDMENTS IN 

THE FEDERAL 

REGISTER] 

(i) Requirements for 

new sources in 

§§63.640 through 

63.653 and 63.656b,c

(a) Upon initial 

startup 

(1) §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, through 

63.658b

(a) On or before 

[THE DATE 3 YEARS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER] 

(1) §63.640(k), 

(l) and (m) 

(iii) Requirements 

for new sources in 

§63.660c

(a) On or before 

[THE DATE 90 DAYS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER] 

(1) §63.640(k), 

(l) and (m) 
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(iv) The new source 

requirements in 

§63.654 for heat 

exchange systems 

(a) Upon initial 

startup or October 

28, 2009, 

whichever is later 

(1) §63.640(k), 

(l) and (m) 

(3) After July 

14, 1994 but on 

or before 

September 4, 

2007 

(i) Requirements for 

new sources in 

§§63.640 through 

63.653 and 63.656d,e

(a) Upon initial 

startup or August 

18, 1995, 

whichever is later 

(1) §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, through 

63.658d

(a) On or before 

[THE DATE 3 YEARS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER] 

(1) §63.640(k), 

(l) and (m) 

(iii) Requirements 

for new sources in 

§63.660e

(a) On or before 

[THE DATE 90 DAYS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER] 

(1) §63.640(k), 

(l) and (m) 

(iv) The existing 

source requirements 

in §63.654 for heat 

exchange systems 

(a) On or before 

October 29, 2012 

(1) §63.640(k), 

(l) and (m) 

(4) On or before 

July 14, 1994 

(i) Requirements for 

existing sources in 

§§63.640 through 

63.653 and 63.656f,g

(a) On or before 

August 18, 1998 

(1) §63.640(k), 

(l) and (m) 

(2) §63.6(c)(5) 

of subpart A of 

this part or 

unless an 

extension has 

been granted by 

the Administrator 

as provided in 

§63.6(i) of 

subpart A of this 

part 

(ii) Requirements 

for existing sources 

in §§63.640 through 

63.645, §§63.647 

through 63.653, and 

§§63.656 through 

63.658f

(a) On or before 

[THE DATE 3 YEARS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER] 

(1) §63.640(k), 

(l) and (m) 

(iii) Requirements 

for existing sources 

in §63.660g

(a) On or before 

[THE DATE 90 DAYS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER] 

(1) §63.640(k), 

(l) and (m) 
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(iii) The existing 

source requirements 

in §63.654 for heat 

exchange systems 

(a) On or before 

October 29, 2012 

(1) §63.640(k), 

(l) and (m) 

a

 For purposes of this table, the construction/reconstruction date means the 

date of construction or reconstruction of an entire affected source or the 

date of a process unit addition or change meeting the criteria in §63.640(i) 

or (j). If a process unit addition or change does not meet the criteria in 

§63.640(i) or (j), the process unit shall comply with the applicable 

requirements for existing sources. 

b

 Between the compliance dates in items (2)(i)(a) and (2)(ii)(a) of this 

table, the owner or operator may elect to comply with either the requirements 

in item (2)(i) or item (2)(ii) of this table. The requirements in item (2)(i) 

of this table no longer apply after demonstrated compliance with the 

requirements in item (2)(ii) of this table. 

c

 Between the compliance dates in items (2)(i)(a) and (2)(iii)(a) of this 

table, the owner or operator may elect to comply with either the requirements 

in item (2)(i) or item (2)(iii) of this table. The requirements in item 

(2)(i) of this table no longer apply after demonstrated compliance with the 

requirements in item (2)(iii) of this table. 

d

 Between the compliance dates in items (3)(i)(a) and (3)(ii)(a) 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. 

e

 Between the compliance dates in items (3)(i)(a) and (3)(iii)(a) of this 

table, the owner or operator may elect to comply with either the requirements 

in item (3)(i) or item (3)(iii) of this table. The requirements in item 

(3)(i) of this table no longer apply after demonstrated compliance with the 

requirements in item (3)(iii) of this table. 

f

 Between the compliance dates in items (4)(i)(a) and (4)(ii)(a) of this 

table, the owner or operator may elect to comply with either the requirements 

in item (4)(i) or item (4)(ii) of this table. The requirements in item (4)(i) 

of this table no longer apply after demonstrated compliance with the 

requirements in item (4)(ii) of this table. 

g

 Between the compliance dates in items (4)(i)(a) and (4)(iii)(a) of this 

table, the owner or operator may elect to comply with either the requirements 

in item (4)(i) or item (4)(iii) of this table. The requirements in item 

(4)(i) of this table no longer apply after demonstrated compliance with the 

requirements in item (4)(iii) of this table. 

37. Table 12 is added to read as follows: 

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 
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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 0 274 4.0 

Methane CH4 16.04 1 896 5.0 

MethylAcetylene C3H4 40.06 3 2,088 1.7 

Nitrogen N2 28.01 0 0 ∞

Oxygen O2 32.00 0 0 ∞

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 ∞

38. Table 13 is added to read as follows: 

Table 13—Calibration and Quality Control Requirements for CPMS 

Parameter Accuracy requirements Calibration requirements 

Temperature ±1 percent over the 

normal range of 

temperature measured 

or 2.8 degrees 

Celsius (5 degrees 

Fahrenheit), 

whichever is greater, 

for non-cryogenic 

temperature ranges. 

±2.5 percent over the 

normal range of 

temperature measured 

Performance evaluation annually 

and following any period of 

more than 24 hours throughout 

which the temperature exceeded 

the maximum rated temperature 

of the sensor, or the data 

recorder was off scale. Visual 

inspections and checks of CPMS 

operation every 3 months, 

unless the CPMS has a redundant 

temperature sensor. 

Select a representative 
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or 2.8 degrees 

Celsius (5 degrees 

Fahrenheit), 

whichever is greater, 

for cryogenic 

temperature ranges. 

measurement location. 

Flow Rate ±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 rate. 

±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 

rate. 

±5 percent over the 

normal range measured 

for mass flow rate. 

Performance evaluation annually 

and following any period of 

more than 24 hours throughout 

which the flow rate exceeded 

the maximum rated flow rate of 

the sensor, or the data 

recorder was off scale. Checks 

of all mechanical connections 

for leakage monthly. Visual 

inspections and checks of CPMS 

operation every 3 months, 

unless the CPMS has a redundant 

flow sensor. 

Select a representative 

measurement location where 

swirling flow or abnormal 

velocity distributions due to 

upstream and downstream 

disturbances at the point of 

measurement are minimized. 

Pressure ±5 percent over the 

normal range measured 

or 0.12 kilopascals 

(0.5 inches of water 

column), whichever is 

greater. 

Checks for obstructions at least 

once each process operating day 

(e.g., pressure tap pluggage). 

Performance evaluation annually 

and 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. Checks of all 

mechanical connections for 

leakage monthly. Visual 

inspection of all components 

for integrity, oxidation and 

galvanic corrosion every 3 

months, unless the CPMS has a 

redundant pressure sensor. 

Select a representative 

measurement location that 

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 
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Page 575 of 809 

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. 

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. 

Net Heating 

Value by Total 

Hydrocarbon 

Monitor 

Calibration drift ≤ 3% 

of instrument span at 

each level. 

Cylinder Gas Audit 

Accuracy ≤ 5% of 

instrument span at 

each level. 

Calibration drift check daily. 

Follow the procedure in 

Sections 4.1 and 4.2 of 

Procedure 1 in 40 CFR part 60, 

Appendix F. 

Cylinder gas audit quarterly. 

Follow the procedure in Section 

5.1.2 of Procedure 1 in 40 CFR 

part 60, Appendix F, except the 

audit shall be performed every 

quarter. 

For both the calibration drift and 

error tests, the calibration 

gases should be injected into 

the sampling system as close to 

the sampling probe outlet as 

practical and must pass through 

all filters, scrubbers, 

conditioners, and other monitor 

components used during normal 

sampling. 

Select a measurement location that 

meets the requirements of 

Section 3.1 of Performance 

Specification 8A of Appendix B 

to 40 CFR part 60. 
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Subpart UUU – [Amended] 

39. Section 63.1562 is amended by: 

(a) Revising paragraph (b)(3) and 

(b) Revising paragraph (f)(5). 

The revisions 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 [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], any flares receiving gas from the fuel gas system are 

in compliance with §63.670. 

40. Section 63.1564 is amended by: 

a. Revising paragraph (a)(1) introductory text; 

b. Revising paragraph (a)(1)(i); 

c. Revising paragraph (a)(1)(ii); 

d. Revising paragraph (a)(1)(iv); 
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e. Adding paragraph (a)(5); 

f. Revising paragraph (b)(4)(i); 

g. Revising paragraph (b)(4)(ii); 

h. Revising paragraph (b)(4)(iv); 

i. 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) 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 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 (iv) of this section: 

(i) You can elect to comply with the PM per coke burn-off 

emission limit (Option 1); 

(ii) You can elect to comply with the PM concentration 

emission limit (Option 2); 

* * * * * 

(iv) You can elect to comply with the Ni per coke burn-off 

emission limit (Option 4). 

* * * * * 
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(5) During periods of startup only, if your catalytic 

cracking unit is followed by an electrostatic precipitator, 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 

paragraphs (a)(1) and (2) of this section; or 

(ii) You can elect to maintain the opacity in the exhaust 

gas from your catalyst regenerator at or below 30 percent 

opacity on a 6-minute average basis. 

(b) * * * 

(4) * * * 

(i) If you elect Option 1 in paragraph (a)(1)(i) of this 

section, compute the PM emission rate (lb/1,000 lb of coke burnoff) for each run using Equations 1, 2, and 3 (if applicable) of 

this section and the site-specific opacity limit, if applicable, 

using Equation 4 of this section as follows: 

    c r a r %CO %O K Qoxy %Oxy

%CO R K1

Q %CO2 %CO K2Q K3Q 2 2 3 2





 



    

 



    

 (Eq. 1) 

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 

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 (a)(2), 

as applicable, to calculate Qr; 
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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 (kgmin)/(hr-dscm-%) (0.0186 (lb-min)/(hr-dscf-%)); 

K2 = Material balance and conversion factor, 2.088 (kgmin)/(hr-dscm) (0.1303 (lb-min)/(hr-dscf)); 

K3 = Material balance and conversion factor, 0.0994 (kgmin)/(hr-dscm-%) (0.0062 (lb-min)/(hr-dscf-%)); 

Qoxy = Volumetric flow rate of oxygen-enriched air stream to 

regenerator, as determined from instruments in the 

catalytic cracking unit control room, dscm/min 

(dscf/min); and 

%Oxy = Oxygen concentration in oxygen-enriched air stream, 

percent by volume (dry basis). 

c

s sd

R

K C Q E    (Eq. 2) 

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 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 
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Page 580 of 809 

lb/(1,000 lb)). 

1.0 K' R

H E A

c

s 













   (Eq. 3) 

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 [THE 

DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], A=0.18 

g/million cal (0.10 lb/million Btu). On or after [THE 

DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], 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)). 















  

st

st PMEmR Opacity Limit Opacity 1lb / 1000 lb coke burn

 (Eq. 4) 

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. 
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(ii) If you elect Option 2 in paragraph (a)(1)(ii) 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)(iv) 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: 

c

Ni sd

Ni R

C Q E 2

  (Eq. 8) 

Where: 

ENi2 = Normalized mass emission rate of Ni, mg/kg coke (lb/1,000 

lb coke). 

st

st

2 Opacity NiEmR2 Opacity   1.0mg/kgcoke

 (Eq. 9) 

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. 
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c st

mon st

2 2 st R

Q Ni Operating Limit Opacity E-Cat

,

,    (Eq. 10) 

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) During periods of startup only, if you elect to comply 

with the alternative limit in paragraph (a)(5)(ii) of this 

section, determine continuous compliance by: collecting opacity 

readings using either a continuous opacity monitoring system 

according to §63.1572 or manual opacity observations following 

EPA Method 9 in Appendix A-4 to part 60 of this chapter; and 

maintaining each 6-minute average opacity at or below 30 

percent. 

41. Section 63.1565 is amended by: 

a. Adding paragraph (a)(5); 

b. Adding paragraph (b)(1)(iv); and 

c. Adding paragraph (c)(3). 

The additions read as follows: 
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§63.1565 What are my requirements for organic HAP emissions from 

catalytic cracking units? 

(a) * * * 

(5) During periods of startup only, if your catalytic 

cracking unit is not followed by a CO boiler, thermal oxidizer, 

incinerator, flare or similar combustion device, 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). 

(b) * * * 

(1) * * * 

(iv) If you elect to comply with the alternative limit for 

periods of startup in paragraph (a)(5)(ii) of this section, you 

must also install, operate, and maintain a continuous parameter 

monitoring system to measure and record the oxygen content 

(percent, dry basis) in the catalyst regenerator vent. 

* * * * * 

(c) * * * 

(3) Demonstrate continuous compliance with the alternative 

limit in paragraph (a)(5)(ii) of this section by collecting the 
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Page 584 of 809 

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). 

42. Section 63.1566 is amended by: 

a. Revising paragraph (a)(1) introductory text; 

b. Revising paragraph (a)(1)(i); and 

c. Revising paragraph (a)(4). 

The revisions 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 [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], the flare must meet the requirements 

of §63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must meet the control device requirements 

in §63.11(b) or the requirements of §63.670. 

* * * * * 
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(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: 

a. Revising paragraph (a)(1) introductory text; 

b. Revising paragraph (a)(1)(i); 

c. Adding paragraph (a)(4); 

d. Revising paragraph (b)(1); and 

e. Adding paragraph (c)(3). 

The revisions and additions 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 in 

§60.102a(f)(1) of this chapter, you must meet the emission 
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Page 586 of 809 

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 in §60.102a(f)(1) of this chapter (Option 1); 

or 

* * * * * 

(4) During periods of shutdown only, 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 shutdown purge gases to a 

flare. On and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must meet the requirements of §63.670. 

Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 shutdown purge gases to a 

to a thermal oxidizer or incinerator operated at a minimum 

hourly average temperature of 1,200 degrees Fahrenheit and a 
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Page 587 of 809 

minimum hourly average outlet oxygen (O2) concentration of 2 

volume percent (dry basis). 

(b) * * * 

(1) Install, operate, and maintain a continuous monitoring 

system according to the requirements in §63.1572 and Table 31 of 

this subpart. Except: 

(i) If you elect to comply with the alternative limit for 

periods of shutdown in paragraph (a)(4)(ii) of this section, 

then on and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you must also install, operate, calibrate, and 

maintain monitoring systems as specified in §§63.670 and 63.671. 

Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must either 

install, operate, and maintain 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 install, operate, 

calibrate, and maintain monitoring systems as specified in 

§§63.670 and 63.671. 

(ii) If you elect to comply with the alternative limit for 

periods of shutdown in paragraph (a)(4)(iii) of this section, 

you must also install, operate, and maintain continuous 
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Page 588 of 809 

parameter monitoring system to measure and record the 

temperature and oxygen content (percent, dry basis) in the vent 

from the thermal oxidizer or incinerator. 

* * * * * 

(c) * * * 

(3) Demonstrate continuous compliance with the alternative 

limit in paragraph (a)(4)(ii) of this section by meeting the 

requirements of either paragraph (c)(3)(i) or (ii) of this 

section. 

(i) On and after [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you must meet the requirements of paragraphs 

(c)(3)(i)(A) through (C) of this section. 

(A) Collect the flare monitoring data according to §§63.670 

and 63.671. 

(B) Keep the records specified in §63.655(i)(9). 

(C) Maintain the selected operating parameters as specified 

in §63.670. 

(ii) Prior to [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], you must either meet the requirements of paragraph 

(c)(3)(i) of this section or meet the requirements of paragraphs 

(c)(3)(ii)(A) through (D) of this section. 
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(A) Collect the flare monitoring data according to 

§63.1572. 

(B) Record for each 1-hour period whether the monitor was 

continuously operating and the pilot light was continuously 

present during each 1-hour period. 

(C) Maintain the net heating value of the gas being 

combusted at or above the applicable limits in §63.11. 

(D) Maintain the exit velocity at or below the applicable 

maximum exit velocity specified in §63.11. 

(4) Demonstrate continuous compliance with the alternative 

limit in paragraph (a)(4)(iii) of this section by collecting the 

hourly average temperature and oxygen concentration monitoring 

data according to §63.1572; maintaining the hourly average 

temperature at or above 1,200 degrees Fahrenheit; and 

maintaining the hourly average oxygen concentration at or above 

2 volume percent (dry basis). 

44. Section 63.1570 is amended by: 

a. Revising paragraph (a); 

b. Revising paragraph (b); 

c. Revising paragraph (c); 

d. Revising paragraph (d); and 

e. Removing and reserving paragraph (g). 

The revisions read as follows: 
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§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 
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log detailing the operation and maintenance of the process and 

emissions control equipment. 

* * * * * 

45. Section 63.1571 is amended by: 

a. Adding paragraph (a)(5); 

b. Revising paragraph (b)(1); 

c. Removing paragraph (b)(4); 

d. Redesignating paragraph (b)(5) as (b)(4); 

e. Revising paragraph (d)(2); and 

f. Revising 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) Conduct a performance test for PM or Ni, as applicable, 

from catalytic cracking units at least once every 5 years for 

those units monitored with CPMS, BLD, or COMS. You must conduct 

the first periodic performance test no later than [THE DATE 18 

MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER]. Those units monitoring PM 

concentration with a PM CEMS are not required to conduct a 

periodic PM performance test. 

(b) * * * 
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(1) Conduct performance tests under such conditions as the 

Administrator specifies to you based on representative 

performance of the affected source for the period being tested. 

Representative conditions exclude periods of startup and 

shutdown unless specified by the Administrator or an applicable 

subpart. 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 such 

conditions represent normal operation. 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. Section 63.1564(b)(2) allows 

you to adjust the laboratory measurements of the equilibrium 

catalyst Ni concentration to the maximum level. You must make 

this adjustment using Equation 2 of this section as follows: 
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st

st

Ecat

NiEmR2

Ecat-Limit  1.0mg/kgcokeburn- off

 (Eq. 2) 

Where: 

NiEmR2st = Average Ni emission rate calculated as the 

arithmetic average Ni emission rate using Equation 8 

of §63.1564 for each performance test run, mg/kg 

coke burn-off. 

* * * * * 

(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, liquidto-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: 
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a. Revising paragraph (c) introductory text; 

b. Revising paragraph (c)(1); 

c. Revising paragraphs (c)(3) and (4); and 

d. Revising paragraphs (d)(1) and (2). 

The revisions 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 [THE DATE 

3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], you must install, operate, 

calibrate, and maintain monitoring systems as specified in 

§§63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 

REGISTER], 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 
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colormetric tube sampling systems are used. You must meet the 

requirements in Table 41 of this subpart for BLD systems. 

* * * * * 

(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 
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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); 

c. Revising newly redesignated paragraph (c) introductory 

text; 

d. Revising newly redesignated paragraph (d) introductory 

text; 

e. Revising newly redesignated paragraph (f) introductory 

text; and 

f. Revising newly redesignated paragraph (g)(1). 

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; 
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(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 paragraph 

(c)(1) or (2) of this section for a catalytic reforming unit. 

* * * * * 

(d) Can I use another type of monitoring system? You may 

request approval from your permitting authority to 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. Your request must contain a 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 
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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 (a)(3) 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 
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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. 

* * * * * 

49. Section 63.1575 is amended by: 

a. Revising paragraph (d) introductory text; 

b. Revising paragraph (d)(1) and (2); 

c. Adding paragraph (d)(4); 

d. Revising paragraph (e) introductory text; 

e. Removing and reserving paragraph (e)(1); 

f. Revising paragraph (e)(4); 

g. Revising paragraph (e)(6); 

h. Revising paragraphs (f)(1) and (2); 

i. Removing and reserving paragraph (h); and 

j. 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 
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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)(1) through (13) of this section. 

* * * * * 
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(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 (c)(1)(i) 

or (c)(1)(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 
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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 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. 
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* * * * * 

(k) Electronic submittal of performance test and CEMS 

performance evaluation data. On and after [THE DATE 3 YEARS 

AFTER DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER] , if required to submit the results of a 

performance test or CEMS performance evaluation, you must submit 

the results using EPA’s Electronic Reporting Tool (ERT) 

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 according to the method 

specified by either paragraph (k)(1)(i) or (k)(1)(ii) of this 

section. 

(i) For data collected using test methods supported by the 

EPA’s ERT as listed on the EPA’s ERT website 

(http://www.epa.gov/ttn/chief/ert/index.html), you must submit 

the results of the performance test to the Compliance and 

Emissions Data Reporting Interface (CEDRI) accessed through the 

EPA’s Central Data Exchange (CDX) 

(http://cdx.epa.gov/epa_home.asp), unless the Administrator 

approves another approach. Performance test data must be 

submitted in a file format generated through use of the EPA’s 

ERT. If you claim that some of the performance test information 
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being submitted is confidential business information (CBI), you 

must submit a complete file generated through the use of the 

EPA’s ERT, including information claimed to be CBI, on a compact 

disc or other commonly used electronic storage media (including, 

but not limited to, flash drives) by registered letter to the 

EPA. The electronic media must be clearly marked as CBI and 

mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE 

Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. 

The same ERT file with the CBI omitted must be submitted to the 

EPA via CDX as described earlier in this paragraph. 

(ii) For data collected using test methods that are not 

supported by the EPA’s ERT as listed on the EPA’s ERT website, 

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 test required by §63.1571(a) and (b), you 

must submit the results of the performance evaluation according 

to the method specified by either paragraph (k)(2)(i) or 

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

(i) For data collection of relative accuracy test audit 

(RATA) pollutants that are supported by the EPA’s ERT as listed 

on the ERT website, the owner or operator must submit the 

results of the performance evaluation to the CEDRI that is 

accessed through the EPA’s CDX, unless the Administrator 
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approves another approach. Performance evaluation data must be 

submitted in a file format generated through the use of the 

EPA’s ERT. 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, including information claimed to be 

CBI, on a compact disc or other commonly used electronic storage 

media (including, but not limited to, flash drives) by 

registered letter to the EPA. The electronic media must be 

clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI 

Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old 

Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to the EPA via CDX as described 

earlier in this paragraph. 

(ii) For any performance evaluation data with RATA 

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

the EPA’s ERT website, 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: 

a. Revising paragraph (a)(2); 

b. Revising paragraph (b)(3); and 

c. Revising paragraph (b)(5). 

The revisions read as follows: 
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§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) * * * 
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(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 section introductory text and 

b. 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 this part 

(§§63.1 through 63.15), and in this section as listed. If the 

same term is defined in subpart A and in this section, it shall 
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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. 

* * * * * 

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. 

* * * * * 
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52. Table 1 to subpart UUU of part 63 is revised to read as 

follows: 

Table 1 to Subpart UUU of Part 63—Metal HAP Emission Limits for 

Catalytic Cracking Units 

As stated in §63.1564(a)(1), you shall meet each emission 

limitation in the following table that applies to you. 

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 

PM emissions must not exceed 1.0 gram per 

kilogram (g/kg) (1.0 lb/1,000 lb) of coke 

burn-off. Before [THE DATE 18 MONTHS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], 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) 

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 1: PM per coke burnoff limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or in 40 CFR 60.102a(b)(1) 

PM emissions must not exceed the limits 

specified in Item 1 of this table. 

5. Option 2: PM concentration 

limit, not subject to the NSPS 

for PM in 40 CFR 60.102 or in 

40 CFR 60.102a(b)(1) 

PM emissions must not exceed 0.040 gr/dscf 

corrected to 0 percent excess air. 

6. Option 3: Ni lb/hr limit, 

not subject to the NSPS for PM 

in 40 CFR 60.102 or in 40 CFR 

60.102a(b)(1) 

Nickel (Ni) emissions must not exceed 13,000 

milligrams per hour (mg/hr) (0.029 lb/hr). 
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7. Option 4: Ni per coke burnoff limit, not subject to the 

NSPS for PM in 40 CFR 60.102 

or in 40 CFR 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: 

Table 2 to Subpart UUU of Part 63—Operating Limits for Metal HAP 

Emissions From Catalytic Cracking Units 

As stated in §63.1564(a)(2), you shall meet each operating 

limit in the following table that applies to you. 

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 

a. Continuous 

opacity monitoring 

system used to 

comply with the 30 

percent opacity 

limit in 40 CFR 

60.102 before [THE 

DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER]. 

Not applicable Not applicable. 

 b. Continuous 

opacity monitoring 

system used to 

comply with a 

site-specific 

opacity limit 

Cyclone, 

fabric filter, 

or 

electrostatic 

precipitator 

Maintain the 3-hour 

rolling average 

opacity of emissions 

from your catalyst 

regenerator vent no 

higher than the sitespecific opacity limit 

established during the 

performance test. 
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 c. Continuous 

parameter 

monitoring 

systems. 

Electrostatic 

precipitator 

Maintain the daily 

average coke burn-off 

rate or daily average 

flow rate no higher 

than the limit 

established in the 

performance test; and 

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 Maintain the 3-hour 

rolling average 

pressure drop above 

the limit established 

in the performance 

test; and maintain the 

3-hour rolling average 

liquid-to-gas ratio 

above the limit 

established in the 

performance test. 

 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. 

2. Subject to NSPS 

for PM in 40 CFR 

60.102a(b)(1)(i) 

a. PM CEMS Not applicable 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 sitespecific opacity limit 

established during the 

performance test. 
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 c. Continuous 

parameter 

monitoring systems 

Electrostatic 

precipitator 

Maintain the daily 

average coke burn-off 

rate or daily average 

flow rate no higher 

than the limit 

established in the 

performance test; and 

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 Maintain the 3-hour 

rolling average 

pressure drop above 

the limit established 

in the performance 

test; and maintain the 

3-hour rolling average 

liquid-to-gas ratio 

above the limit 

established in the 

performance test. 

 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. 
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4. Option 1: PM per 

coke burn-off limit 

not subject to the 

NSPS for PM in 40 

CFR 60.102 or 40 CFR 

60.102a(b)(1) 

a. Continuous 

opacity monitoring 

system used to 

comply with a 

site-specific 

opacity limit 

Cyclone, 

fabric filter, 

or 

electrostatic 

precipitator 

Maintain the 3-hour 

rolling average 

opacity of emissions 

from your catalyst 

regenerator vent no 

higher than the sitespecific opacity limit 

established during the 

performance test. 

Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the hourly 

average opacity of 

emissions from your 

catalyst generator 

vent no higher than 

the site-specific 

opacity limit 

established during the 

performance test. 

 b. Continuous 

parameter 

monitoring systems 

i. 

Electrostatic 

precipitator 

(1) Maintain the daily 

average gas flow rate 

or daily average coke 

burn-off rate no 

higher than the limit 

established in the 

performance test. 

 (2) Maintain the 3-

hour rolling average 

total power and 

secondary current 

above the limit 

established in the 

performance test. 

Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average voltage and 

secondary current (or 

total power input) 

above the limit 

established in the 

performance test. 
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 ii. Wet 

scrubber 

(1) Maintain the 3-

hour rolling average 

pressure drop above 

the limit established 

in the performance 

test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average pressure drop 

above the limit 

established in the 

performance test (not 

applicable to a wet 

scrubber of the nonventuri jet-ejector 

design). 

 (2) Maintain the 3-

hour rolling average 

liquid-to-gas ratio 

above the limit 

established in the 

performance test. 

Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average liquid-to-gas 

ratio above the limit 

established in the 

performance test. 

 c. 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. 

5. Option 2: PM 

concentration limit 

not subject to the 

NSPS for PM in 40 

CFR 60.102 or 40 CFR 

60.102a(b)(1) 

PM CEMS Any Not applicable. 
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6. 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 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], 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) Maintain the daily 

average gas flow rate 

or daily average coke 

burn-off rate no 

higher than the limit 

established during the 

performance test. 

 (2) Maintain the 

monthly rolling 

average of the 

equilibrium catalyst 

Ni concentration no 

higher than the limit 

established during the 

performance test. 

 (3) Maintain the 3-

hour rolling average 

total power and 

secondary current 

above the limit 

established in the 

performance test. 

Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average voltage and 

secondary current (or 

total power input) 

above the established 

during the performance 

test. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 616 of 809 

 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) Maintain the 3-

hour rolling average 

pressure drop above 

the limit established 

in the performance 

test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average pressure drop 

above the limit 

established during the 

performance test (not 

applicable to a nonventuri wet scrubber 

of the jet-ejector 

design). 

 (3) Maintain the 3-

hour rolling average 

liquid-to-gas ratio 

above the limit 

established in the 

performance test. 

Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average liquid-to-gas 

ratio above the limit 

established during the 

performance test. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 617 of 809 

7. 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, 

baghouse, 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 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], 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) Maintain the 3-

hour rolling average 

total power and 

secondary current 

above the limit 

established in the 

performance test. 

Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average voltage and 

secondary current (or 

total power input) 

above the limit 

established during the 

performance test. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 618 of 809 

 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) Maintain the 3-

hour rolling average 

pressure drop above 

the limit established 

in the performance 

test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average pressure drop 

above the limit 

established during the 

performance test (not 

applicable to a nonventuri wet scrubber 

of the jet-ejector 

design). 

 (3) Maintain the 3-

hour rolling average 

liquid-to-gas ratio 

above the limit 

established in the 

performance test. 

Alternatively, before 

[THE DATE 18 MONTHS 

AFTER THE DATE OF 

PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], you may 

maintain the daily 

average liquid-to-gas 

ratio above the limit 

established during the 

performance test. 

54. Table 3 to subpart UUU of part 63 is revised to read as 

follows: 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 619 of 809 

Table 3 to Subpart UUU of Part 63—Continuous Monitoring Systems 

for Metal HAP Emissions From Catalytic Cracking Units 

As stated in §63.1564(b)(1), you shall meet each 

requirement in the following table that applies to you. 

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 

a. Cyclone Continuous opacity monitoring 

system to measure and record the 

opacity of emissions from each 

catalyst regenerator vent. 

 b. Electrostatic 

precipitator 

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 device1 and the total 

power and secondary current to 

the control device. 

 c. Wet scrubber Continuous parameter monitoring 

system to measure and record the 

pressure drop across the 

scrubber2, coke burn-off rate or 

the gas flow rate entering or 

exiting the control device1

, and 

total liquid (or scrubbing 

liquor) flow rate to the control 

device. Alternatively, before 

[THE DATE 3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], continuous opacity 

monitoring system to measure and 

record the opacity of emissions 

from each catalyst regenerator 

vent. 

 d. Fabric Filter Continuous bag leak detection 

system to measure and record 

increases in relative particulate 

loading from each catalyst 

regenerator vent or a continuous 

opacity monitoring system to 

measure and record the opacity of 

emissions from each catalyst 

regenerator vent. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 620 of 809 

2. Subject to NSPS for PM 

in 40 CFR 

60.102a(b)(1)(i) electing 

to meet the PM per coke 

burn-off limit. 

a. Cyclone Continuous opacity monitoring 

system to measure and record the 

opacity of emissions from each 

catalyst regenerator vent. 

 b. Electrostatic 

precipitator 

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 device1

, 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 

scrubber2

, the coke burn-off rate 

or the gas flow rate entering or 

exiting the control device1, 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) 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 See 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 1: PM per coke 

burn-off limit not 

subject to the NSPS for 

PM in 40 CFR 60.102 or 40 

CFR 60.120a(b)(1). 

Any See item 1 of this table. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 621 of 809 

7. Option 2: PM 

concentration limit not 

subject to the NSPS for 

PM in 40 CFR 60.102 or 40 

CFR 60.120a(b)(1) 

Any See item 3 of this table. 

8. Option 3: Ni lb/hr 

limit not subject to the 

NSPS for PM in 40 CFR 

60.102 or in 40 CFR 

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 or the gas 

flow rate entering or exiting the 

control device1

. 

 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 or the gas 

flow rate entering or exiting the 

control device1

; or continuous 

parameter monitoring systems to 

measure and record the coke burnoff rate or the gas flow rate 

entering or exiting the control 

device1

 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 

scrubber2

, gas flow rate entering 

or exiting the control device1

, 

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 8.a of this table. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 622 of 809 

9. Option 4: Ni lb/1,000 

lbs of coke burn-off 

limit not subject to the 

NSPS for PM in 40 CFR 

60.102 or in 40 CFR 

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 device1

. 

 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 or the gas 

flow rate entering or exiting the 

control device1

; or continuous 

parameter monitoring systems to 

measure and record the coke burnoff rate or the gas flow rate 

entering or exiting the control 

device1

 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 

scrubber2

, gas flow rate entering 

or exiting the control device1

, 

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 9.a of this table. 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: 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 623 of 809 

Table 4 to Subpart UUU of Part 63—Requirements for Performance 

Tests for Metal HAP Emissions From Catalytic Cracking Units Not 

Subject to the New Source Performance Standard (NSPS) for 

Particulate Matter (PM) 

As stated in §63.1564(b)(2), you shall meet each 

requirement in the following table that applies to you. 

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, 2F in Appendix 

A-1 to part 60 of 

this chapter, or 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.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 624 of 809 

 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. 

 

2. Option 1: PM 

per coke burnoff limit, not 

subject to the 

NSPS for PM in 

40 CFR 60.102 or 

in 40 CFR 

60.102a(b)(1) 

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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 625 of 809 

3. Option 2: PM 

concentration 

limit, not 

subject to the 

NSPS for PM in 

40 CFR 60.102 or 

in 40 CFR 

60.102a(b)(1) 

a. Measure PM 

concentration. 

Method 5, 5B, or 5F 

(40 CFR part 60, 

Appendix A-3) to 

determine PM 

concentration and 

associated moisture 

content for units 

without wet 

scrubbers. Method 5 

or 5B (40 CFR part 

60, Appendix A-3) 

to determine PM 

concentration 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). 

4. Option 3: Ni 

lb/hr limit, not 

subject to the 

NSPS for PM in 

40 CFR 60.102 or 

in 40 CFR 

60.102a(b)(1) 

a. Measure 

concentration of 

Ni. 

Method 29 (40 CFR 

part 60, Appendix 

A-8). 

 b. Compute Ni 

emission rate 

(lb/hr). 

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 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 sitespecific 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 hourly 

average opacity from 

all the 6-minute 

averages. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 626 of 809 

 (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 

from all the 

readings. 

5. Option 4: Ni 

per coke burnoff limit, not 

subject to the 

NSPS for PM in 

40 CFR 60.102 or 

in 40 CFR 

60.102a(b)(1) 

a. Measure 

concentration of 

Ni. 

Method 29 (40 CFR 

part 60, Appendix 

A-8). 

 b. Compute Ni 

emission rate 

(lb/1,000 lb of 

coke burn-off). 

Equations 1 and 8 

of §63.1564. 

 c. Determine the 

equilibrium 

catalyst Ni 

concentration. 

See item 4.c. of 

this table. 

You must obtain 1 

sample for each of 

the 3 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 627 of 809 

 d. If you use a 

continuous 

opacity 

monitoring 

system, establish 

your sitespecific 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 hourly 

average opacity from 

all the 6-minute 

averages. 

 (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 from all 

the readings. 

 e. Record the 

catalyst addition 

rate for each 

test and schedule 

for the 10-day 

period prior to 

the test. 

 

6. If you elect 

Option 1 in item 

4 in Table 1, 

Option 3 in item 

6 in Table 1, or 

Option 4 in item 

7 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 628 of 809 

 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. 

 (2) You must 

determine and record 

the 3-hr average gas 

flow rate from all 

the readings. 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

you may determine 

and record the 

maximum hourly 

average gas flow 

rate from all the 

readings. 

 c. Electrostatic 

precipitator: 

voltage and 

secondary current 

(or total power 

input). 

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. 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 629 of 809 

 (2) You must 

determine and record 

the 3-hr average 

total power to the 

system and the 3-hr 

average secondary 

current. 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

you may determine 

and record the 

minimum hourly 

average voltage and 

secondary current 

(or total power 

input) from all the 

readings. 

 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 630 of 809 

 (2) You must 

determine and record 

the 3-hr average 

pressure drop from 

all the readings. 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

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. 

 (2) You must 

determine and record 

the hourly average 

liquid-to-gas ratio 

from all the 

readings. 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

you may determine 

and record the 

hourly average gas 

flow rate and total 

water (or scrubbing 

liquid) flow rate 

from all the 

readings. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 631 of 809 

 (3) You must 

determine and record 

the 3-hr average 

liquid-to-gas ratio. 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

you may determine 

and record the 

minimum liquid-togas 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. 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

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). 

2

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, 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, 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 632 of 809 

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. 

56. Table 5 to subpart UUU of part 63 is revised to read as 

follows: 

Table 5 to Subpart UUU of Part 63—Initial Compliance With Metal 

HAP Emission Limits for Catalytic Cracking Units 

As stated in §63.1564(b)(5), you shall meet each 

requirement in the following table that applies to you. 

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 

PM emissions must not 

exceed 1.0 gram per 

kilogram (g/kg) (1.0 

lb/1,000 lb) of coke 

burn-off. Before [THE 

DATE 18 MONTHS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

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 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 

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 burnoff 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 633 of 809 

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), 

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 or, 

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 burnoff 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)(ii), 

electing to meet the PM 

per coke burn-off 

limit. 

PM emissions must not 

exceed 1.0 g/kg coke 

burn-off (1 lb/1000 lb 

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 0.5 kg/1,000 kg 

(0.5 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), 

If a PM CEMS is used, 

0.020 grain per dry 

standard cubic feet 

You have already conducted 

a performance test to 

demonstrate initial 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 634 of 809 

electing to meet the PM 

concentration limit. 

(gr/dscf) corrected to 0 

percent excess air. 

compliance with the NSPS 

and the measured PM 

concentration is less than 

or equal to 0.020 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. 

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, 

0.040 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 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 1: PM per 

coke burn-off limit not 

subject to the NSPS for 

PM in 40 CFR 60.102 or 

40 CFR 60.120a(b)(1) 

PM emissions must not 

exceed 1.0 gram per 

kilogram (g/kg) (1.0 

lb/1,000 lb) of coke 

burn-off. Before [THE 

DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

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 

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), 

over the period of the 

initial performance test, 

is no higher than 1.0 g/kg 

coke burn-off (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 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 635 of 809 

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 

continuous opacity 

monitoring system, your 

performance evaluation 

shows the system meets the 

applicable requirements in 

§63.1572. 

7. Option 2: PM 

concentration limit, 

not subject to the NSPS 

for PM in 40 CFR 60.102 

or in 40 CFR 

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), 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. 

8. Option 3: not 

subject to the NSPS for 

PM 

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 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. 

9. 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 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 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 636 of 809 

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: 

Table 6 to Subpart UUU of Part 63—Continuous Compliance With 

Metal HAP Emission Limits for Catalytic Cracking Units 

As stated in §63.1564(c)(1), you shall meet each 

requirement in the following table that applies to you. 

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 

a. PM emissions must not 

exceed 1.0 gram per 

kilogram (g/kg) (1.0 

lb/1,000 lb) of coke 

burn-off. Before [THE 

DATE 18 MONTHS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 637 of 809 

 ii. Maintaining PM emission 

rate below 1.0 g/kg (1.0 

lb/1,000 lb) of coke burnoff. 

 iii. Conducting a 

performance test before 

[THE DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER] 

and once every five years 

thereafter. 

 iv. Collecting the 

applicable continuous 

parametric monitoring 

system data according to 

§63.1572 and maintaining 

each rolling 3-hr average 

above or below (as 

applicable) the average 

determined during the 

performance test. 

 v. Collecting the 

continuous opacity 

monitoring data for each 

catalyst regenerator vent 

according to §63.1572 and 

maintaining each 6-minute 

average at or below the 

site-specific opacity 

determined during the 

performance test. 

Alternatively, before [THE 

DATE 18 MONTHS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS IN 

THE FEDERAL REGISTER], 

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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 638 of 809 

 vi. Before [THE DATE 18 

MONTHS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], 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 0.5 g/kg (0.5 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 0.5 g/kg (0.5 lb 

PM/1,000 lb) of coke burnoff; conducting a 

performance test once every 

year; collecting the 

applicable continuous 

parametric monitoring 

system data according to 

§63.1572 and maintaining 

each rolling 3-hr average 

above or below (as 

applicable) the average 

determined during the 

performance test; 

collecting the continuous 

opacity monitoring data for 

each regenerator vent 

according to §63.1572 and 

maintaining each 6-minute 

average at or below the 

site-specific opacity 

determined during the 

performance test. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 639 of 809 

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 1.0 g/kg coke 

burn-off (1 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 1.0 g/kg (1.0 

lb/1,000 lb) of coke burnoff; conducting a 

performance test once every 

year; collecting the 

applicable continuous 

parametric monitoring 

system data according to 

§63.1572 and maintaining 

each rolling 3-hr average 

above or below (as 

applicable) the average 

determined during the 

performance test; 

collecting the continuous 

opacity monitoring data for 

each regenerator vent 

according to §63.1572 and 

maintaining each 6-minute 

average at or below the 

site-specific opacity 

determined during the 

performance test. 

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, 

0.020 grain per dry 

standard cubic feet 

(gr/dscf) corrected to 0 

percent excess air. 

Maintaining PM 

concentration below 0.020 

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, 

0.040 gr/dscf corrected 

to 0 percent excess air. 

Maintaining PM 

concentration below 0.040 

gr/dscf corrected to 0 

percent excess air. 

6. Option 1: PM per 

coke burn-off limit, 

not subject to the NSPS 

for PM in 40 CFR 60.102 

or in 40 CFR 

60.102a(b)(1) 

See item 1 of this table See item 1 of this table. 

7. Option 2: PM 

concentration limit, 

not subject to the NSPS 

for PM in 40 CFR 60.102 

or in 40 CFR 

60.102a(b)(1) 

PM emissions must not 

exceed 0.040 gr/dscf 

corrected to 0 percent 

excess air. 

See item 5 of this table. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 640 of 809 

8. Option 3: Ni lb/hr 

limit, not subject to 

the NSPS for PM in 40 

CFR 60.102 or in 40 CFR 

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); conducting a 

performance test before 

[THE DATE 18 MONTHS AFTER 

THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER] 

and once every five years 

thereafter; and collecting 

the applicable continuous 

parametric monitoring 

system data according to 

§63.1572 and maintaining 

each rolling 3-hr average 

above or below (as 

applicable) the average 

determined during the 

performance test. 

9. Option 4: Ni per 

coke burn-off limit, 

not subject to the NSPS 

for PM in 40 CFR 60.102 

or in 40 CFR 

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; 

conducting a performance 

test before [THE DATE 18 

MONTHS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER] and once 

every five years 

thereafter; and collecting 

the applicable continuous 

parametric monitoring 

system data according to 

§63.1572 and maintaining 

each rolling 3-hr average 

above or below (as 

applicable) the average 

determined during the 

performance test. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 641 of 809 

58. Table 7 to subpart UUU of part 63 is revised to read as 

follows: 

Table 7 to Subpart UUU of Part 63—Continuous Compliance With 

Operating Limits for Metal HAP Emissions From Catalytic Cracking 

Units 

As stated in §63.1564(c)(1), you shall meet each 

requirement in the following table that applies to you. 

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 

a. Continuous 

opacity 

monitoring 

system used to 

comply with 30 

percent opacity 

limit. 

Not applicable. Complying with Table 

6 of this subpart. 

 b. Continuous 

parametric 

monitoring 

systems – 

electrostatic 

precipitator 

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 3-hr 

rolling average gas 

flow rate monitoring 

data according to 

§63.1572; and 

maintaining the 3-hr 

rolling average gas 

flow rate at or 

below the limit 

established during 

the performance 

test. 

 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 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 642 of 809 

test. 

 c. Continuous 

parametric 

monitoring 

systems – wet 

scrubber 

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 

maintaining the 3-hr 

rolling average 

pressure drop at or 

above the limit 

established during 

the performance 

test. 

 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. 

 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. 

 e. Continuous 

opacity 

monitoring 

system, used 

for sitespecific 

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 limit 

established during 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 643 of 809 

the performance 

test. 

2. Subject to NSPS 

for PM in 40 CFR 

60.102a(b)(1)(ii), 

electing to meet the 

PM per coke burn-off 

limit. 

Any Any See items 1.b, 1.c, 

1.d, and 1.e of this 

table. 

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. 

4. Option 1: PM per 

coke burn-off limit, 

not subject to the 

NSPS for PM in 40 

CFR 60.102 or in 40 

CFR 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; and 

maintaining the 3-hr 

rolling average 

opacity at or below 

the site-specific 

limit. 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

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 

gas flow rate 

entering or 

exiting the 

control device 

must not exceed 

the operating 

limit established 

during the 

performance test.

Collecting the 

hourly and 3-hr 

rolling average gas 

flow rate monitoring 

data according to 

§63.1572; and 

maintaining the 3-hr 

rolling average gas 

flow rate at or 

below the limit 

established during 

the performance 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 644 of 809 

test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the 

hourly and daily 

average gas flow 

rate monitoring data 

according to 

§63.15721

; and 

maintaining the 

daily average gas 

flow rate at or 

below the limit 

established during 

the performance 

test. 

 ii. The average 

voltage and 

secondary current 

(or total power 

input) 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 [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

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 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 645 of 809 

the limit 

established during 

the performance 

test. 

 c. Continuous 

parameter 

monitoring 

systems—wet 

scrubber. 

i. 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 

maintaining the 3-hr 

rolling average 

pressure drop at or 

above the limit 

established during 

the performance 

test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

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. 

 ii. 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 646 of 809 

Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

collecting the 

hourly average gas 

flow rate and water 

(or scrubbing 

liquid) flow rate 

monitoring data 

according to 

§63.15721

; 

determining and 

recording the hourly 

average liquid-togas ratio; 

determining and 

recording the daily 

average liquid-togas ratio; and 

maintaining the 

daily average 

liquid-to-gas ratio 

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. 

 e. Continuous 

opacity 

monitoring 

system, used 

for sitespecific 

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 limit 

established during 

the performance 

test. 

5. Option 2: PM PM CEMS Not applicable. Complying with Table 
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Page 647 of 809 

concentration limit, 

not subject to the 

NSPS for PM in 40 

CFR 60.102 or in 40 

CFR 60.102a(b)(1). 

6 of this subpart. 

6. 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 site-specific 

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 week2

; 

collecting the 

hourly average gas 

flow rate monitoring 

data according to 

§63.15721

; and 

determining and 

recording the hourly 

average Ni operating 

value using Equation 

11 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 sitespecific Ni 

operating limit 

established during 

the performance 

test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

determining and 

recording the daily 

average Ni operating 

value and 

maintaining the 

daily average Ni 

operating value 

below the sitespecific Ni 

operating limit 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 648 of 809 

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 4.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 4.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 week2; 

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 

pressure drop 

must not fall 

below the 

operating limit 

established in 

the performance 

test. 

See item 4.c.i of 

this table. 

 ii. The average 

liquid-to-gas 

ratio must not 

fall below the 

See item 4.c.ii of 

this table. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 649 of 809 

operating limit 

established 

during the 

performance test.

 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 week2; 

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 

Increases in 

relative 

particulate. 

See item 4.d of this 

table. 

 e. Continuous 

opacity 

monitoring 

system, used 

for sitespecific 

opacity limit - 

Cyclone or 

electrostatic 

precipitator 

The average 

opacity must not 

exceed the 

opacity 

established 

during the 

performance test.

See item 4.e of this 

table. 

7. 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 site-specific 

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 

gas flow rate 

monitoring data 

according to 

§63.15721

; 

determining and 

recording 

equilibrium catalyst 

Ni concentration at 

least once a week2

; 

and determining and 

recording the hourly 
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Page 650 of 809 

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 sitespecific Ni 

operating limit 

established during 

the performance 

test. Alternatively, 

before [THE DATE 18 

MONTHS AFTER THE 

DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

determining and 

recording the daily 

average Ni operating 

value and 

maintaining the 

daily average Ni 

operating value 

below the sitespecific Ni 

operating limit 

established during 

the performance 

test. 

 b. Continuous 

parameter 

monitoring 

systems—

electrostatic 

precipitator. 

i. The daily 

average gas flow 

rate to the 

control device 

must not exceed 

the level 

established in 

the performance 

test. 

See item 4.b.i of 

this table. 

 ii. The daily 

average voltage 

and secondary 

current (or total 

power input) must 

not fall below 

the level 

established in 

the performance 

test. 

See item 4.b.ii of 

this table. 
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Page 651 of 809 

 iii. The monthly 

rolling average 

equilibrium 

catalyst Ni 

concentration 

must not exceed 

the level 

established 

during the 

performance test.

See item 6.b.iii of 

this table. 

 c. Continuous 

parameter 

monitoring 

systems—wet 

scrubber. 

i. The daily 

average pressure 

drop must not 

fall below the 

operating limit 

established in 

the performance 

test. 

See item 4.c.i of 

this table. 

 ii. The daily 

average liquidto-gas ratio must 

not fall below 

the operating 

limit established 

during the 

performance test.

See item 4.c.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 6.c.iii of 

this table. 

 d. BLD – fabric 

filter 

Increases in 

relative 

particulate. 

See item 4.d of this 

table. 

 e. Continuous 

opacity 

monitoring 

system, used 

for sitespecific 

opacity limit - 

Cyclone or 

electrostatic 

precipitator 

The average 

opacity must not 

exceed the 

opacity 

established 

during the 

performance test.

See item 4.e of this 

table. 

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. 

2

The equilibrium catalyst Ni concentration must be measured by the procedure, 

Determination of Metal Concentration on Catalyst Particles (Instrumental 
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Page 652 of 809 

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 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. 

59. Table 8 to subpart UUU of part 63 is amended by 

revising the entry for item 2 to read as follows: 

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 . . . 

* * * * * 

2. Not subject to the 

NSPS for CO in 40 CFR 

60.103 

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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 

the flare must meet the requirements of §63.670. Prior 

to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 amended by 

revising the entry for item 2 to read as follows: 
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Page 653 of 809 

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 . . . 

* * * * * 

2. Not 

subject to 

the NSPS for 

CO in 40 CFR 

60.103 

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 [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], the flare must 

meet the requirements of 

§63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 654 of 809 

61. Table 10 to subpart UUU of part 63 is amended by 

revising the entry for item 2 to read as follows: 

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 . . . 

* * * * * 

2. Not 

subject to 

the NSPS for 

CO in 40 CFR 

60.103 

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. 

 c. Flare On and after [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the monitoring systems 

required in §§63.670 and 63.671. 

Prior to [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 655 of 809 

 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. 

62. Table 11 to subpart UUU of part 63 is amended by 

revising 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 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 656 of 809 

 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. 

 f. If you use a flare, 

conduct visible 

emission observations. 

Method 22 (40 

CFR part 60, 

appendix A). 

On and after [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], meet 

the requirements of 

§63.670. Prior to [THE 

DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 657 of 809 

 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 [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the 

flare must meet the 

requirements of §63.670. 

Prior to [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], 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 amended by 

revising the entry for item 2 to read as follows: 

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 . . . 

* * * * * 

2. Not 

subject to 

the NSPS for 

CO in 40 CFR 

60.103 

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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 658 of 809 

 b. If you use a flare, 

visible emissions must 

not exceed a total of 5 

minutes during any 2 

operating hours. 

On and after [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare meets the 

requirements of §63.670. Prior to 

[THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], 

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 amended by 

revising the entry for item 2 to read as follows: 

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 . . 

. 

* * * * * 

2. Not 

subject to 

the NSPS for 

CO in 40 CFR 

60.103 

i. 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 above. 

 ii. 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). 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 659 of 809 

 iii. Visible 

emissions from a 

flare must not 

exceed a total of 5 

minutes during any 

2-hour period. 

Control 

device-flare

On and after [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION 

OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], 

meeting the requirements of 

§63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], 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 amended by 

revising the entry for item 2 to read as follows: 

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 

. . . 

* * * * * 

2. Not 

subject to 

the NSPS 

for CO in 

40 CFR 

60.103 

a. Continuous 

emission monitoring 

system 

Not applicable Complying with Table 13 

of this subpart. 

 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. 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 660 of 809 

 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. 

 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 [THE DATE 3 

YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE 

FEDERAL REGISTER], 

meeting the requirements 

of §63.670. Prior to 

[THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION 

OF THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 

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. 

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 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

Review *** 

Page 661 of 809 

* * * * * 

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 [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], vent emissions to a flare that 

meets the requirements of §63.670. Prior to [THE DATE 

3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], the flare must meet the 

requirements of §63.670. Prior to [THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL REGISTER], 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: 
*** E.O. 12866 - Revised Version – Do Not Cite, Quote, or Release During 

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Page 662 of 809 

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 [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], the 

monitoring systems required in §§63.670 and 

63.671. Prior to [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], 

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: 

a. Revising the column headings and 

b. Revising the entry for item 1. 

The revisions 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)

On and after [THE DATE 

3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], the flare 
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Page 663 of 809 

must meet the 

requirements of 

§63.670. Prior to [THE 

DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER],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 [THE DATE 

3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE 

FINAL RULE AMENDMENTS 

IN THE FEDERAL 

REGISTER], the flare 

must meet the 

requirements of 

§63.670. Prior to [THE 

DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF 

THE FINAL RULE 

AMENDMENTS IN THE 

FEDERAL REGISTER], 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 

* * * * * 
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Page 664 of 809 

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 [THE DATE 3 YEARS AFTER 

THE DATE OF PUBLICATION OF THE FINAL 

RULE AMENDMENTS IN THE FEDERAL 

REGISTER], the flare meets the 

requirements of §63.670. Prior to [THE 

DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], 

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: 

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 [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], 

meeting the requirements of §63.670. Prior 

to [THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE AMENDMENTS 

IN THE FEDERAL REGISTER], maintaining 

visible emissions from a flare below a 

total of 5 minutes during any 2 

consecutive hours, or meeting the 

requirements of §63.670. 

* * * * * 
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Page 665 of 809 

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 [THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE AMENDMENTS IN THE 

FEDERAL REGISTER], meeting the 

requirements of §63.670. Prior to 

[THE DATE 3 YEARS AFTER THE DATE 

OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL 

REGISTER], 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: 

a. Revising the entry for item 2 and 

b. Revising the entry for item 3. 

The revisions read as follows: 

Table 22 to Subpart UUU of Part 63—Inorganic HAP Emission Limits 

for Catalytic Reforming Units 

* * * * * 
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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 semiregenerative, 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: 

a. Revising the entry for item 2; 

b. Revising the entry for item 3; 

c. Revising the entry for item 4; and 

d. Revising footnote 2. 

The revisions read as follows: 

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. 
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Page 667 of 809 

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 burnoff 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 burnoff 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: 

a. Revising the entry for item 2.a and 

b. Revising the entry for item 4.a. 

The revisions read as follows: 

Table 25 to Subpart UUU of Part 63—Requirements for Performance 

Tests for Inorganic HAP Emissions From Catalytic Reforming Units 

* * * * * 
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Page 668 of 809 

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. 

 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. 
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Page 669 of 809 

 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. 

* * * * *

* * * * * 

76. Table 28 to subpart UUU of part 63 is amended by: 

a. Revising the entry for item 5 and 

b. Revising footnote 1. 

The revisions 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 . 

. . 

* * * * * 

5. Moving-bed a. The daily average Collecting the hourly and daily 
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Page 670 of 809 

gas-solid 

adsorption 

system (e.g., 

ChlorsorbTM

System 

temperature of the gas 

entering or exiting the 

adsorption system must not 

exceed the limit 

established during the 

performance test 

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. 

* * * * * 

77. Table 29 to subpart UUU of part 63 is revised to read 

as follows: 

Table 29 to Subpart UUU of Part 63—HAP Emission Limits for 

Sulfur Recovery Units 

As stated in §63.1568(a)(1), you shall meet each emission 

limitation in the following table that applies to you. 
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Page 671 of 809 

For . . . 

You shall meet this emission limit for 

each process vent . . . 

1. Each new or existing Claus 

sulfur recovery unit part of a 

sulfur recovery plant with design 

capacity greater than 20 long tons 

per day and subject to the NSPS for 

sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 CFR 

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. 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 in 40 CFR 

60.102a(f)(1): Option 1 (Elect 

NSPS). 

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. 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 in 40 CFR 

60.102a(f)(1): Option 2 (TRS 

limit). 

300 ppmv of total reduced sulfur (TRS) 

compounds, expressed as an equivalent SO2

concentration (dry basis) at zero percent 

oxygen. 

78. Table 30 to subpart UUU of part 63 is revised to read 

as follows: 

Table 30 to Subpart UUU of Part 63—Operating Limits for HAP 

Emissions From Sulfur Recovery Units 

As stated in §63.1568(a)(2), you shall meet each operating 

limit in the following table that applies to you. 
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Page 672 of 809 

For . . . 

If use this 

type of 

control 

device 

You shall meet this operating 

limit. . . 

1. Each new or existing Claus 

sulfur recovery unit part of a 

sulfur recovery plant with 

design capacity greater than 20 

long tons per day and subject 

to the NSPS for sulfur oxides 

in 40 CFR 60.104(a)(2) or in 40 

CFR 60.102a(f)(1). 

Not 

applicable 

Not applicable. 

2. 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 in 40 CFR 60.102a(f)(1): 

Option 1 (Elect NSPS). 

Not 

applicable 

Not applicable. 

3. 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 in 40 CFR 60.102a(f)(1): 

Option 2 (TRS limit), if using 

continuous emissions monitoring 

systems. 

Not 

applicable 

Not applicable. 

4. 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 in 40 CFR 60.102a(f)(1): 

Option 2 (TRS limit), if using 

continuous parameter monitoring 

systems. 

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. 

79. Table 31 to subpart UUU is revised to read as follows: 

Table 31 to Subpart UUU of Part 63—Continuous Monitoring Systems 

for HAP Emissions From Sulfur Recovery Units 

As stated in §63.1568(b)(1), you shall meet each 

requirement in the following table that applies to you. 
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Page 673 of 809 

For . . . For this limit . . 

You shall install and 

operate this continuous 

monitoring system . . . 

1. Each new or existing 

Claus sulfur recovery 

unit part of a sulfur 

recovery plant with 

design capacity greater 

than 20 long tons per day 

and subject to the NSPS 

for sulfur oxides in 40 

CFR 60.104(a)(2) or in 40 

CFR 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 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 

Complete either item 1.a 

or item 1.b; and you must 

also install and operate a 

continuous emission 

monitoring system to 

measure and record the O2

concentration for the 

inlet air/oxygen supplied 

to the system. 

2. Option 1: Elect NSPS. 

Each new or existing 

sulfur recovery unit 

(Claus or other type, 

regardless of size) not 

a. 250 ppmv (dry basis) 

of SO2 at zero percent 

excess air if you use 

an oxidation or 

reduction control 

Continuous emission 

monitoring system to 

measure and record the 

hourly average 

concentration of SO2 (dry 
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Page 674 of 809 

subject to the NSPS for 

sulfur oxides in 

paragraph (a) (2) of 40 

CFR 60.104 or in 40 CFR 

60.102a(f)(1). 

system followed by 

incineration 

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 

Complete either item 2.a 

or item 2.b; and you must 

also install and operate a 

continuous emission 

monitoring system to 

measure and record the O2

concentration for the 

inlet air/oxygen supplied 

to the system. 

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 in 40 CFR 

60.102a(f)(1). 

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 
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Page 675 of 809 

combustion zone 

temperature of each 

thermal incinerator and 

the oxygen content 

(percent, dry basis) in 

the vent stream of the 

incinerator. 

80. Table 32 to subpart UUU of part 63 is revised to read 

as follows: 

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 

As stated in §63.1568(b)(2) and (3), you shall meet each 

requirement in the following table that applies to you. 

For . . . You must . . . Using . . .

According to these 

requirements . . . 

1. Each new 

and existing 

sulfur 

recovery 

unit: Option 

1 (Elect 

NSPS). 

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. 

 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. 

Data from 

continuous 

emission 

monitoring 

system. 

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). 

2. Each new 

and existing 

sulfur 

Measure the 

concentration of 

reduced sulfur (or SO2

Data from 

continuous 

emission 

Collect TRS data every 15 

minutes for 24 

consecutive operating 
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Page 676 of 809 

recovery 

unit: Option 

2 (TRS 

limit), using 

CEMS 

if you use an 

instrument to convert 

the reduced sulfur to 

SO2). 

monitoring 

system. 

hours. Reduce the data to 

1-hour averages computed 

from four or more data 

points equally spaced 

over each 1-hour period. 

3. Each new 

and existing 

sulfur 

recovery 

unit: Option 

2 (TRS 

limit), if 

using 

continuous 

parameter 

monitoring 

systems 

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, 2F, 

or 2G in 

appendix A 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 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 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 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 
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Page 677 of 809 

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: 

Table 33 to Subpart UUU of Part 63—Initial Compliance With HAP 

Emission Limits for Sulfur Recovery Units 

As stated in §63.1568(b)(5), you shall meet each 

requirement in the following table that applies to you. 
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For . . . 

For the following 

emission limit . . . 

You have demonstrated 

initial compliance if . . 

. 

1. Each new or 

existing Claus sulfur 

recovery unit part of 

a sulfur recovery 

plant with design 

capacity greater than 

20 long tons per day 

and subject to the 

NSPS for sulfur oxides 

in 40 CFR 60.104(a)(2) 

or in 40 CFR 

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 
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Page 679 of 809 

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 in 40 CFR 

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 

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 
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Page 680 of 809 

control system without 

incineration 

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. 

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 in 40 CFR 

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: 

Table 34 to Subpart UUU of Part 63—Continuous Compliance With 

HAP Emission Limits for Sulfur Recovery Units 

As stated in §63.1568(c)(1), you shall meet each 

requirement in the following table that applies to you. 
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For . . . 

For this emission limit . 

. . 

You shall demonstrate 

continuous compliance by 

. . . 

1. Each new or existing 

Claus sulfur recovery 

unit part of a sulfur 

recovery plant with 

design capacity greater 

than 20 long tons per 

day and subject to the 

NSPS for sulfur oxides 

in 40 CFR 60.104(a)(2) 

or in 40 CFR 

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) 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 

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. 

2. Option 1: Elect NSPS. 

Each new or existing 

sulfur recovery unit 

(Claus or other type, 

regardless of size) not 

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), 

Collecting the hourly 

average SO2 data (dry 

basis, percent excess 

air) according to 

§63.1572; determining 
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subject to the NSPS for 

sulfur oxides in 40 CFR 

60.104(a)(2) or in 40 

CFR 60.102a(f)(1). 

if you use an oxidation or 

reduction control system 

followed by incineration. 

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 

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 in 40 

CFR 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 
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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: 

Table 35 to Subpart UUU of Part 63—Continuous Compliance With 

Operating Limits for HAP Emissions From Sulfur Recovery Units 

As stated in §63.1568(c)(1), you shall meet each 

requirement in the following table that applies to you. 

For . . . 

For this operating 

limit . . . 

You shall demonstrate 

continuous compliance by 

. . . 

1. Each new or existing 

Claus sulfur recovery unit 

part of a sulfur recovery 

plant with design capacity 

greater than 20 long tons 

per day and subject to the 

NSPS for sulfur oxides in 

paragraph 40 CFR 

60.104(a)(2) or in 40 CFR 

60.102a(f)(1). 

Not applicable Meeting the requirements 

of Table 34 of this 

subpart. 

2. Option 1: Elect NSPS Each 

new or existing sulfur 

recovery unit (Claus or 

other type, regardless of 

size) not subject to the 

Not applicable Meeting the requirements 

of Table 34 of this 

subpart. 
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Page 684 of 809 

NSPS for sulfur oxides in 40 

CFR 60.104(a)(2) or in 40 

CFR 60.102a(f)(1). 

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 in 40 

CFR 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. 

84. Table 40 to subpart UUU of part 63 is revised to read 

as follows: 

Table 40 to Subpart UUU of Part 63—Requirements for 

Installation, Operation, and Maintenance of Continuous Opacity 

Monitoring Systems and Continuous Emission Monitoring Systems 

As stated in §63.1572(a)(1) and (b)(1), you shall meet each 

requirement in the following table that applies to you. 

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. CO2, O2, and CO monitors for coke 

burn-off rate 

The requirements in 40 CFR 

60.105a(b)(2). 

4. 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. 
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5. 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. 

6. 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. 

7. 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. 

8. 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 for 

certifying the reduced sulfur monitor 

and 3A or 3B 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. 

9. TRS continuous emission 

monitoring system for sulfur 

recovery unit; this monitor must 

include an O2 monitor for correcting 

Performance specification 5 (40 CFR part 

60, Appendix B). 
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Page 686 of 809 

the data for excess air. 

10. 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. 

11. O2 monitor for oxygen 

concentration in inlet or supply. 

Install, operate, and maintain each O2

monitor according to Performance 

Specification 3 of Appendix B to part 

60; the span value for the O2 monitor 

must be selected between 20 and 100 

percent; conduct performance evaluations 

for O2 monitor according to Performance 

Specification 3 of Appendix B to part 

60, and must use Method 3A or 3B of 

Appendix A-2 to part 60 for conducting 

relative accuracy evaluations; comply 

with applicable quality assurance 

procedures of Appendix F to part 60 for 

each monitor, including annual accuracy 

determinations for each O2 monitor and 

daily calibration drift determinations. 

85. Table 41 to subpart UUU of part 63 is revised to read 

as follows: 

Table 41 to Subpart UUU of Part 63—Requirements for 

Installation, Operation, and Maintenance of Continuous Parameter 

Monitoring Systems 

As stated in §63.1572(c)(1), you shall meet each 

requirement in the following table that applies to you. 

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 
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Page 687 of 809 

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. BLD Follow the requirements in 40 CFR 60.105a(c). 

5. Voltage, 

secondary current, 

or total power input 

sensors 

Use meters with an accuracy of at least ± 5 percent over 

the operating range. 

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 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; and record the results of each 

calibration check and inspection. 

6. Pressure/Pressure 

drop1

 sensors 

Locate the pressure sensor(s) in a position that 

provides a representative measurement of the pressure; 

minimizes or eliminates pulsating pressure, vibration, 

and internal and external corrosion. 

Use a gauge with an accuracy of at least ± 5 percent 

over the operating range or 0.5 inches of water 

column, whichever is greater. 

Check pressure tap for plugs at least once a week; using 

a manometer, check gauge calibration quarterly and 

transducer calibration monthly; conduct calibration 

checks following any period of more than 24 hours 

throughout which the sensor exceeds the manufacturer’s 

specified maximum operating pressure range or install 

a new pressure sensor; at least monthly, inspect all 

components for integrity, all electrical connections 

for continuity, and all mechanical connections for 

leakage; record the results of each calibration check 

and inspection. 

7. 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. 
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Page 688 of 809 

Use a flow rate sensor with an accuracy of at least ±5 

percent, or 0.5 gallons per minute for liquid flow, or 

10 cubic feet per minute for gas flow, whichever is 

greater. 

Conduct a flow sensor calibration check at least 

semiannually; conduct calibration checks following any 

period of more than 24 hours throughout which the 

sensor exceeds the manufacturer’s specified maximum 

operating range or install a new flow sensor; at least 

monthly, inspect all components for leakage; record 

the results of each calibration check and inspection. 

8. 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 of the temperature being 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 sensor exceeds the 

manufacturer’s specified maximum operating temperature 

range, or install a new temperature sensor; at least 

monthly, inspect all components for integrity and all 

electrical connections for continuity, oxidation, and 

galvanic corrosion; record the results of each 

calibration check and inspection. 

9. Oxygen content 

sensors2

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. 

Conduct calibration checks at least quarterly; conduct 

calibration checks following any period of more than 

24 hours throughout which the sensor exceeds the 

manufacturer’s specified maximum operating range, or 

install a new oxygen sensor; at least monthly, 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. 

2

This does not replace the requirements for oxygen monitors that are required 

to use continuous emissions monitoring systems. These requirements apply to 

oxygen sensors that are continuous parameter monitors, such as those that 

monitor combustion zone oxygen concentration and regenerator exit oxygen 

concentration. 
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Page 689 of 809 

86. Table 43 to subpart UUU is revised to read as follows: 

Table 43 to Subpart UUU of Part 63—Requirements for Reports 

As stated in §63.1575(a), you shall meet each requirement 

in the following table that applies to you. 

You must 

submit . . 

. The report must contain . . . 

You shall submit the 

report . . . 

1. A 

compliance 

report 

If there are not 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-ofcontrol, 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 [THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION OF THE FINAL RULE 

AMENDMENTS IN THE FEDERAL REGISTER], 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 amended to read 

as follows: 

Table 44 to Subpart UUU of Part 63—Applicability of NESHAP 

General Provisions to Subpart UUU 

As stated in §63.1577, you shall meet each requirement in 

the following table that applies to you. 

Citation Subject 

Applies to 

subpart 

UUU Explanation 

§63.1(a)(1)–(4) General Applicability Yes 

§63.1(a)(5) [Reserved] Not 
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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 subpart UUU 

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 subpart UUU. 

§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 of subpart UUU 

specifies that if the 

same term is defined in 

subparts A and UUU, it 

shall have the meaning 

given in subpart UUU. 

§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 
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§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 subpart UUU 

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. 

§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 Subpart UUU 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 crossreference to 

§63.9(b)(2) does not 

apply. 

§63.6(a) Compliance with 

Standards and 

Maintenance—

Applicability 

Yes 
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§63.6(b)(1)–(4) Compliance Dates for 

New and Reconstructed 

Sources 

Yes 

§63.6(b)(5) Yes Except that subpart UUU 

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 subpart UUU 

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 

Yes 
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Requirements 

§63.6(f)(2)(iii)(D) Yes 

§63.6(f)(2)(iv)–(v) Yes 

§63.6(f)(3) Yes Except the crossreferences to 

§63.6(f)(1) and 

§63.6(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 Subpart UUU 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 

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 

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 

§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 
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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 subpart UUU 

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 subpart UUU 

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 

§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 

RequirementsApplicability 

Yes 
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§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 Subpart UUU 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 

§63.8(c)(2)–(3) Monitoring System 

Installation 

Yes Except that subpart UUU 

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 
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§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 subpart UUU 

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 Subpart UUU 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 Yes 
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of Compliance 

§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 subpart UUU 

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 

§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 

No 
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During SSM 

§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 Subpart UUU 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. 
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§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 Subpart UUU 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 

88. Appendix A to subpart UUU of part 63 is amended by: 

a. Revising the first sentence of section 2.1 and 

b. Revising section 7.1.3. 

The revisions read as follows: 
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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 low-range 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. 

* * * * * 

Appendix A to Part 63--[AMENDED] 

89. Appendix A to part 63 is amended by adding Method 325A 

to read as follows: 

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 
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compounds (VOCs) at 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 and corresponding uptake rates 

listed in Method 325B, Table 12.1. Additional compounds or 

alternative sorbents must be evaluated as described in Appendix 

A of Method 325B unless the compound or sorbent has already been 

validated and reported in one of the following national/ 

international standard methods: ISO 16017-2:2003 (incorporated 

by reference—see §63.14), ASTM D6196-03(2009) (incorporated by 

reference—see §63.14), or BS EN 14662-4:2005 (incorporated by 

reference—see §63.14), or 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 
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micrograms per cubic meter (μg/m3

) to at least 500 μg/m3 when 

industry standard (3.5 inch long x 0.25 inch outside diameter 

(o.d.) x 5 mm inner diameter (i.d.)) stainless steel sorbent 

tubes packed with Carbograph 1 TDTM, Carbopack BTM, or Carbopack 

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 over 

an extended period of time using multiple sampling episodes 

(e.g., 26 x 14-day sampling episodes). The duration of each 

sampling period must be 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 
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passive samplers, including determination of the number of 

passive samplers needed for each survey and placement of 

samplers along the fenceline or facility 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. 
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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 the facility fenceline or property boundaries and 

collection of local meteorological data. It may be used to 

determine average concentration of VOC at a facility fenceline 

or property boundaries 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 gradient-based 
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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. 

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 Retention volume is the maximum mass of VOC that can 
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be collected before the capacity of the sorbent is exceeded and 

back diffusion of the VOC from the tube occurs. 

3.8 Sampling episode is the length of time each passive 

sampler is exposed during field monitoring. The sampling episode 

for this method is 14 days. 

3.9 Sorbent tube (Also referred to as tube, PS tube, 

sorbent tube, and sampling tube) is a stainless steel or inert 

coated stainless steel tube. Standard PS tube dimensions for 

this method are 3.5-inch (89 mm) long x 0.25-inch (6.4 mm) o.d. 

stainless steel tubes with an i.d. of 5 mm, a cross-sectional 

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 x 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 
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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. General guidance for siting can be found in 

EPA-454/B-13-003, Quality Assurance Handbook for Air Pollution 

Measurement Systems, Volume II: Ambient Air Quality Monitoring 

Program, May 2013 (Reference 3)(incorporated by reference—see 

§63.14). 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 
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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 

excludes 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 powder-free 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 
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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 oC will reduce the retention 

volume (i.e., 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 
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deploy passive sampling monitoring equipment at a facility 

fenceline or 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 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 that 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 Appendix A to Method 325B. Guidance on 

sorbent selection can also be obtained from relevant national 

and international standard methods such as ASTM D6196-03(2009) 

(Reference 14)(incorporated by reference—see §63.14) and ISO 

16017-2:2003 (Reference 13)(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 long-term storage cap. Each 
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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). 

Figure 6.1. PS Tube with Weather Protector 

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 
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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, Appendix A or ISO 16017-

2:2003 (Reference 13) (incorporated by reference—see §63.14). 

The supporting evaluation and verification data described in 

Method 325B, Appendix 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 
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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, Quality Assurance Handbook for Air Pollution 

Measurement Systems, Volume IV: Meteorological Measurements, 

Version 2.0 (Final), March 2008 (Reference 11) (incorporated by 
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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 

boundary. You will place passive samplers on the facility 

property boundary at different angles circling the geometric 

center of the facility based on the size of the area (or 

subarea) or at different distances based on the size and 

boundary 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. 

8.2.2 Option 1 for Determining Sampling Locations. 

8.2.2.1 For facilities with a regular (circular, 
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triangular, rectangular, or square) shape, determine the 

geographic center of the facility. 

8.2.2.1.1 For regularly shaped facilities with an area of 

less than or equal to 750 acres, measure angles around the 

center point of 30 degrees for a total of twelve 30 degree 

measurements. 

8.2.2.1.2 For regularly shaped facilities covering an area 

greater than 750 acres but less than or equal to 1,500 acres, 

measure from the center point angles of 20 degrees for a total 

of eighteen 20 degree measurements. 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. 

8.2.2.1.4 Place samplers securely on a pole or supporting 

structure at 1.5 to 3 meters above ground level at each point 

just beyond the intersection where the measured angle intersects 

the property boundary. 

8.2.2.1.5 Extra samplers must be placed near known sources 

of VOCs at the test facility. In the case that a potential 

emission source is within 50 meters of the property boundary and 

the source location is between two monitors, measure the 
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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) to provide sufficient coverage of all 

area sources. 

Figure 8.1. Facility with a Regular Shape Between 750 and 1,500 

Acres in Area 

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 

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.

Additional monitors
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subareas. 

8.2.2.2.1 If a subarea is less than or equal to 750 acres 

(e.g., Figure 8.2), measure angles of 30 degrees from the center 

point for a total of twelve 30 degree measurements. 

Figure 8.2. Facility Divided into Three Subareas 

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 8.3), measure angles 

of 20 degrees from the center point for a total of eighteen 20 

degree measurements. 

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. 

8.2.2.3 Locate each sampling point just beyond the 

intersection of the measured angle and the outer property 
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boundary. 

8.2.2.4 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 more 

than one point along the subarea’s outer boundary. 

Figure 8.3. Facility Divided into Two Subareas 

8.2.3 Option 2 for Determining Sampling Locations. 

8.2.3.1 For facilities with a boundary length of less than 

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 boundary length greater than 

24,000 feet, sampling locations are spaced 2,000 250 feet apart. 

8.2.3.4 Place samplers securely on a pole or supporting 
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structure at 1.5 to 3 meters above ground level. 

8.2.3.5 Extra samplers must be placed near known sources 

of VOCs at the test facility. In the case that a potential 

emission source is within 50 meters of the property 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 

8.4, the facility added three additional monitors (i.e., light 

shaded sampler locations) to provide sufficient coverage of all 

area sources. 

Figure 8.4. Facility with a Boundary Length of 24,000 feet 

8.3 Siting a Meteorological Station. A dedicated 

meteorological station is required at or near the facility you 
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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, 

Meteorological Monitoring Guidance for Regulatory Modeling 

Applications, February 2000 (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. 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 from large paved areas. 

8.3.4 Collect and record meteorological data, including 

wind speed, wind direction, and temperature and average data on 

an hourly basis. Collect daily unit vector wind direction data 
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plus average temperature and barometric pressure measurements of 

the sampled air to enable calculation of concentrations at 

standard conditions. 

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 from 

48 hours 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. The 

sampling tubes must 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 
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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 at a height of 1.5 to 2 

meters 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 at at 

least one monitoring location during each field monitoring 

exercise. 

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. 
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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.) 

8.5.9 Expose the sampling tubes for the 14-day sampling 

period. 

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. 

One field blank tube is required for every 10 sampled tubes on a 

monitoring exercise. No less than two field blanks should be 

collected, regardless of the size of the monitoring study. 

Record the tube number(s) for the field blank(s) on the field 

sample data sheet. 

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 
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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 
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(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-CCDD-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. 

8.6.6 Collect daily unit vector wind direction data plus 

average temperature and barometric pressure measurements to 

enable calculation of concentrations at standard conditions. You 

must supply this information to the laboratory with the samples. 

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 
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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 
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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, Quality 

Assurance Handbook for Air Pollution Measurement Systems, Volume 

IV: Meteorological Measurements, Version 2.0 (Final), 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) can be calculated 

for any specified period at each PS location using Equation 

12.1. 

N

PS

PS ip

i

 Eq. 12.1 

Where: 

PSi = Annual average for location i. 
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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 farfield 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 facility-specific “hot spots.” 

12.3 Evaluate Trends. You may evaluate trends and patterns 

in the PS data over multiple sampling episodes 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 
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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. 

12.3.3 Information on published or documented events onand off-site may also be included in the associated sampling 

episode 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 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. 

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 
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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 

Measurement 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-HandbookVol-II.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. 
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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_Meteor

ological_Measurements.pdf. 

13. ISO 16017-2:2003, Indoor, ambient and workplace air - 

Sampling and analysis of volatile organic compounds by sorbent 
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tube/thermal desorption/capillary gas chromatography. Part 2: 

Diffusive sampling. 

14. ASTM D6196-03(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 

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 

III. CUSTODY INFORMATION 

COLLECTED BY: ___________________ 

Relinquished to Shipper - 

Name: _______________ Date: ________________ Time _________ 

Sample 

ID 

(Tube) 

# Sorbent 

Sample 

or 

blank 

Start 

Date 

Start 

Time 

Stop 

Date

Stop 

Time

Location

(gps) 

Ambient 

Temp. 

(F) 

Barometric 

Pressure 

(in. Hg) 

 

 
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Received by Laboratory - 

Name _______________ Date: ________________ Time _________ 

Sample condition upon receipt: 

________________________________________________________________ 

Analysis Required: 

________________________________________________________________ 

________________________________________________________________ 

Comments: 

________________________________________________________________ 

________________________________________________________________

________________________________________________________________ 

Figure 17.1. Example Field Data Form and Chain of Custody 

90. Appendix A to part 63 is amended by adding Method 325B 

to read as follows: 

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 
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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 Carbopack X or equivalent 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 a given compound or 

set 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 Appendix A to this method unless the compound or 

sorbent has already been validated and reported in one of the 

following national/international standard methods: ISO 16017-

2:2003(incorporated by reference—see §63.14), ASTM D6196-

03(2009) (incorporated by reference—see §63.14), or BS EN 14662-
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4:2005 (incorporated by reference—see §63.14), or in the peerreviewed 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/multidetector instrumentation. 

2.3 Key steps of this method as implemented for each 

sample tube include: Stringent leak testing under stop flow, 
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recording ambient temperature conditions, adding internal 

standards, purging the tube, thermally desorping the sampling 

tube, refocusing on a focusing trap, desorping 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 
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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 back diffusion becomes significant – 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 Calibration verification sample. 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 
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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 μm 

or less and with a stationary phase film thickness of 5 μm 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 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. 

3.10 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. 

3.11 o.d. is outer diameter. 

3.12 ppbv is parts per billion by volume. 

3.13 Retention volume is the volume of gas required to 

move an analyte vapor plug through the sorbent tube at a given 

temperature during active (pumped) sampling. Note that retention 

volume provides another measure of the strength of 

sorbent:sorbate (analyte) affinity and is closely related to 

breakthrough volume – See discussion in Section 3.2 above. 
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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 means 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 polymer Tenax®

 when sampling high concentration (100-500 

ppb) ozone atmospheres (Reference 5). 
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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 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. 
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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. 

Figure 6.1. Cross Section View of Passive Sorbent Tube 

6.2 Tube Conditioning Apparatus. 
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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 only be used for tube 

conditioning only 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 TD-compatible 

electronic (radio frequency identification (RFID)) tube labels. 

6.3.2 To avoid contamination, do not make ink markings of 
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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 non-greased, 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-
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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 on-column 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 
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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 

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 
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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 g or less 

of p-bromofluorobenzene is analyzed. 
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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 Appendix 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 Carbopack 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(incorporated 

by reference—see §63.14) or ASTM D6196-03(2009) (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 Appendix A to this method unless 
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the compound or sorbent has already been validated and reported 

in one of the following national/ international standard 

methods: ISO 16017-2:2003 (incorporated by reference—see 

§63.14), ASTM D6196-03(2009) (incorporated by reference—see 

§63.14), or BS EN 14662-4:2005 (incorporated by reference—see 

§63.14) – or in the peer-reviewed open literature. A summary 

table and the supporting evaluation data demonstrating the 

selected sorbent meets the requirements in Appendix 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 Appendix A 

to this method. 

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. 
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7.1.6 Repack/replace the sorbent tubes or demonstrate tube 

performance following the requirements in Appendix A to this 

method at least yearly 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 
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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 μl 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 non-interfering solvents such as methanol. 
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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 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 
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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

Carbopack C

Anasorb GCB2 

Carbograph 1 TD 

Carbotrap

Carbopack B

Anasorb GCB1 

>400 350 100 mL/min 

TenaxTA 350 330 100 mL/min 
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CarbopackX 

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 samplers will also be 

required: Laboratory blanks as specified in Section 9.3.2 (two 

per sampling episode minimum), field blanks as specified in 

Section 9.3.4 (two per sampling episode minimum), calibration 
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verification tubes as specified in Section 10.9.4. (at least one 

per analysis sequence or every 24 hours), and paired (duplicate) 

samples as specified in Section 9.4 (at least one pair of 

duplicate samples 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 long-term 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 
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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 Analytical System Blank. The analytical system must be 

demonstrated to be contaminant free by carrying out an analysis 

without a sorbent tube – i.e., by desorbing an empty tube or by 

desorbing the focusing trap alone. Since no internal standards 

can be added directly to the empty tube, the system blank must 
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have less than or equal to 0.2 ppbv or three times the detection 

limit for each target compound, whichever is larger based on the 

response factors for the continuing calibration verification 

sample. Perform a system 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. Flag all sample data from analytical sequences 

that fail the system blank check and provide a narrative on how 

the failure affects the data use. 

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 (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 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. 
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9.3 Field and Laboratory Blanks. 

9.3.1 Field and laboratory 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 At least two laboratory blanks are required per 

monitoring episode. These laboratory blanks must be stored in 

the laboratory under clean controlled ambient temperature 

conditions throughout the monitoring period. Analyze one 

laboratory blank at the beginning and one at the end of the 

associated field sample runs. 

9.3.3 Laboratory blank/artifact levels must meet the 

requirements of Section 9.2.2 (see also Table 17.1). Flag all 

data that do not meet this criterion with a note that associated 

results are estimated, and likely to be biased high due to 

laboratory blank background. 

9.3.4 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 (see Method 325B). 

The long-term storage caps must be in place and must be stored 

outside the shipping container at the sampling location (see 

Method 325B). 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 
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monitoring exercise and no less than two field blanks should be 

collected, regardless of the size of the monitoring study. 

9.3.5 Field blanks must contain no greater than one-third 

of the measured target analyte or compliance limit for field 

samples (see Table 17.1). 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 (collocated) 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 Appendix A to this method and the statistical 

approach presented in Method 301. 

9.6 Limit of Detection. Determine the limit of detection 

under the analytical conditions selected (see Section 11.3) 

using the procedure in Section 15 of Method 301. The limit of 

detection 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 
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multiply this value by three. The results should demonstrate 

that the method is able to measure analytes such as benzene at 

concentrations as low as 10 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 routine, single-level calibration verification 

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. 

  100   Spiked Value

Spiked Value Measured Value Analytical Bias Eq. 9.1 

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 daily single-level 

calibration verification checks may also be applied for this 
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purpose. 

 

100   A

A1 A2

Analytical Precision Eq. 9.2 

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. 

 

100   F

F1 F2

Field Precision Eq. 9.3 

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. 
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9.10.2 Compound recovery through the TD system can 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 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 g 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 
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been met. 

Table 9.1 GC/MS Tuning Criteria1

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 1

 All 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 Calibrations Checks at the Start of a 

Sequence. Run single-level calibration checks 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 routine 

calibration check should be near the mid-point of the multilevel calibration range. 

9.13.2 Quantitation software must be updated with response 

factors determined from the daily calibration standard. The 

percent deviation between the initial calibration and the daily 

calibration check for all compounds must be within 30 percent. 

9.14 Calibration Verification at the End of a Sequence. 

Run another single level standard after running each sequence of 
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samples. The initial calibration check for a subsequent set of 

samples may be used as the final calibration check 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 calibration 

verification. 

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 
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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 
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product lifetime. 

10.4.2 Introduce precise 0.5 to 5.0 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 μl aliquots of liquid 

standards to the sampling end of sorbent tubes in a flow of 

carrier gas using a precision syringe and an unheated injector 

(Section 6.6). The flow of gas should be sufficient to 

completely vaporize the liquid standard. 

Note: If the analytes of interest are higher boiling than 
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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 μL 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 μL) 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 and 

allowed to warm to the temperature of the injection body. The 

liquid is then quickly injected. The result is the cool liquid 

contacts the hot syringe tip and the sample is completely forced 

into the injector and onto the sorbent cartridge. A bias occurs 
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with this method when sample is drawn continuously up into the 

syringe to the specified volume 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. 
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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 and 

relevant parts of Section 9.5. 

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 
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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 

single-level calibration verification 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 Single-level calibrations checks must be carried 
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out on a regular routine basis as described in Section 9.6. 

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 MWb

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-

trifluoroethane 

 

1,1-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 

a

 Pressure in millimeters of mercury. 

b

 Molecular weight. 

11.0 Analytical Procedure 
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11.1 Preparation for Sample Analysis. 

11.1.1 Each sequence of analyses must be ordered as 

follows: 

11.1.1.1 A calibration verification. 

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 A single-level calibration verification standard 

tube after 10 field samples. 

11.1.1.7 A single-level calibration verification standard 

tube 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 
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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. 
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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 
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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 
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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 

μg samples will require a split ratio in the order of ~50:1 and 

200 μg 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. 
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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 Whenever the thermal desorption - GC/MS 

analytical method is changed or major equipment maintenance is 

performed, you must conduct a new five-level calibration (see 

Section 10.6.3). System calibration remains valid as long as 

results from subsequent routine, single-level calibration 

verification standards are within 30 percent of the most recent 

5-point calibration (see Section 10.9.5). Include relevant 

routine, single-level calibration data in the supporting 

information in the data report for each set of samples. 

11.3.2.5 Document, flag and explain all sample results 

that exceed the calibration range. Report flags and provide 
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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 episode. 

12.1.3 Keep records of sorbent tube packing if tubes are 

manually prepared in the 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. 
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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 daily unit vector wind direction, daily average temperature, 

and daily average barometric pressure for the sample collection 

period. See Section 8.6.5 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 episode. 

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: 

 

  is s

s is

A M

A M

RF 

  Eq. 12.1 
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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: 

 

  1

1

2









n

RF RF

SD

n

i

i

RF Eq. 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: 

% DEV  SDRF  RF 100 Eq. 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: 

    100

2  

  R1 R2 /

R1 R2 RPD Eq. 12.4 
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Where: 

R1, R2 = Values that are being compared (i.e., response 

factors in calibration verification). 

12.2.2 Determine the equivalent concentration of compounds 

in atmospheres as follows. 

12.2.3 For passive sorbent tube samples, calculate the 

concentration of the target compound(s) in the sampled air, in 

μg/m3

 by using Equation 12.5 (Reference 21). 

6 10   U t

m C meas

m Eq. 12.5 

Where: 

Cm = The concentration of target compound in the air sampled 

(μg/m3

). 

mmeas = The mass of the compound as measured in the sorbent tube 

(μg). 

U = The diffusive uptake rate (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 limits of 

detection 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. 
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Table 12.1: Validated Sorbents and Uptake Rates for Selected 

Clean Air Act Compounds 

Compound 

Carbopack X Uptake Rate 

(ml/min)a

1,1-Dichloroethene 0.57±0.14 

3-Chloropropene 0.51±0.3 

1,1-Dichloroethane 0.57±0.1 

1,2-Dichloroethane 0.57±0.08 

1,1,1-Trichloroethane 0.51±0.1 

Benzene 0.66±0.06 

Carbon tetrachloride 0.51±0.06 

1,2-Dichloropropane 0.52±0.1 

Trichloroethene 0.5±0.05 

1,1,2-Trichloroethane 0.49±0.13 

Toluene 0.52±0.14 

Tetrachloroethene 0.48±0.05 

Chlorobenzene 0.51±0.06 

Ethylbenzene 0.46±0.07 

m,p-Xylene 0.46±0.09 

Styrene 0.5±0.14 

o-Xylene 0.46±0.12 

p-Dichlorobenzene 0.45±0.05 

a

 Reference 3, McClenny, J. Environ. Monit. 7:248-256. 

12.2.4 Correct target concentrations determined at the 

sampling site temperature and atmospheric pressure to standard 

conditions (25 C and 760 mm mercury) using Equation 12.6 

(Reference 22). 





 



  













   760

298.2 2

3

ss

ss

NTP

P

t

U U Eq. 12.6 

Where: 

tss = The temperature at the sampling site (K). 

Pss = The pressure at the sampling site (mm Hg). 
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13.0 Method Performance 

The performance of this procedure for VOC not listed in 

Table 12.1 is determined using the procedure in Appendix A of 

this Method. 

13.1 The valid range for measurement of VOC is 

approximately 0.5 μg/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 subpart-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. 
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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 
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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 Carbopack X solid adsorbent followed by 

thermal 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," 
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Page 786 of 809 

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 
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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 tert-Butyl 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, 
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Page 788 of 809 

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. ASTM D4597-10, Standard Practice for Sampling 

Workplace Atmospheres to collect Gases or Vapors with Solid 

Sorbent Diffusive Samplers. 

22. 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. 

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: Indoor, ambient and workplace air – 

Sampling and analysis of volatile organic compounds by sorbent 

tube/thermal desorption/capillary gas chromatography – Part 2: 
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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 

Bromofluorobenzen

e 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 

System Blank 

Analysis 

Dailya following 

bromofluorobenzene 

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 

Flag Data for 

possible 

invalidation

 
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calibration 

validation a

 Every 24 hours 

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 

III. CUSTODY INFORMATION 

COLLECTED BY: ___________________ 

Relinquished to Shipper - 

Name: _______________ Date: ________________ Time _________ 

Received by Laboratory - 

Name _______________ Date: ________________ Time _________ 

Sample condition upon receipt: 

________________________________________________________________ 

Analysis Required: 

________________________________________________________________ 

________________________________________________________________ 

Sample 

ID 

(Tube) 

# Sorbent 

Sample 

or 

blank 

Start 

Date 

Start 

Time 

Stop 

Date

Stop 

Time

Location

(gps) 

Ambient 

Temp. 

(F) 

Barometric 

Pressure 

(in. Hg) 

 

 
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Comments: 

________________________________________________________________ 

________________________________________________________________

________________________________________________________________ 

Figure 17.1. Example Field Data From and Chain of Custody 

Figure 17.2. Schematic of Thermal Desorption Flow Path During 

Leak Testing 
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Figure 17.3. Schematic of Thermal Desorption Flow During Purge 

of Air (Top) and Addition of IS Gas to the Sorbent Tube (Bottom) 
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Figure 17.4. Schematic of Thermal Desorption Flow Path During 

Primary (Tube) Desorption (Top) and Secondary (Trap) Desorption 

and Transfer to the GC (Bottom) 
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APPENDIX 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 Appendix, 

unless the compound or sorbent has already been validated and 

reported in one of the following national/international standard 

methods: ISO 16017-2:2003 (incorporated by reference—see 

§63.14), ASTM D6196-03(2009) (incorporated by reference—see 

§63.14), or BS EN 14662-4:2005 (incorporated by reference—see 

§63.14), or in peer-reviewed 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 Appendix 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 Appendix. 

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 
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determine the sorbent tube uptake rate and to confirm compound 

capture and recovery. 

A.2 Summary of Method 

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 for an example exposure chamber). 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 active SUMMA canister sampling. 

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. 
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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, organicfree 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 
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SUMMA canisters. 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 high-pressure gas cylinders. 

A.6 Equipment and Supplies 

A.6.1 You must use an exposure chamber of sufficient size 

to simultaneously generate a minimum of four exposed 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 
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• 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 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 
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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 measure the relative 

humidity in the test gas as part of the record of the passive 

sorbent sampler evaluation. 

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. 
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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 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 50 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 equal 100 

percent of the volume of the chamber per minute (i.e., one 

chamber air change per minute) and 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 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 
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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 hourly 

intervals or at the beginning, middle, and end of the exposure 

time, whichever is greater. 

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.1. Example Sorbent Tube Exposure Chamber 
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Figure A.2. Example Tube Retaining Rack in Exposure Chamber 

A.9 Quality Control 

A.9.1 Monitor and record the exposure chamber temperature 

and RH during PSD exposures. 
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A.9.2 Measure the flow rates of standards and purified 

house 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. 

A.10.2.2 To verify exposure chamber concentrations using 

SUMMA canisters, 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 
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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 greater than 0.5 mL/min 
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(1 ng/ppm-min). 

Note: For example, there is a maximum deviation comparing 

Perkin-Elmer passive type sorbent tubes packed with Carbopack 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) 

Carbopack X 

(2 week) 

0.61±0.11a 0.1 ppbv 0.67a 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 Carbopack X 

solid adsorbent followed by thermal desorption/GC/MS analysis– laboratory 

studies. J. Environ. Monit. 7:248-256. 

A.13.2 Data Analysis and Calculations for Method 

Evaluation 

A.13.2.1 Calculate the theoretical concentration of VOC 

standards using Equation A.1. 

s

t a

i

f C

FR FR

FR C  



 





  Eq. 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). 
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A.13.2.3 Determine the uptake rate of the target gas being 

evaluated using Equation A.2. 

e t

x

C T

M

U

  Eq. A.2 

Where: 

Mx = The mass of analyte measured on the sampling tube (g). 

Ce = The theoretical exposure chamber concentration (g/mL). 

Tt = The exposure time (minutes). 

A.13.2.4 Estimate the variance (relative standard 

deviation (RSD)) of the inter-sampler results at each condition 

tested using Equation A.3. RSD for the sampler is estimated by 

pooling the variance estimates from each test run. 

   

 

n

i

i

n

X X S

1

2

2

 Eq. A.3 

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. 

X

S RSDx

2

%  100 Eq. A.4 

A.13.2.5 Determine the 95 percent confidence interval for 
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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. 

n

RSD  t  f   0.95

95%

%

 Eq. A.5 

Where: 

95% = 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. 

RA Xi  X A  95% Eq. A.6 

Where: 

RA = Relative accuracy. 

X i = The mean value of all Xi.

X A = The average concentration of analyte measured by the 

active measurement method. 
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95% = 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.