Component 1 Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Deleted: Enclosure

Petroleum Refinery 

Emissions Information Collection 

General Instructions 

 NOTE: The final version of this questionnaire will be in electronic format, not in 

hard copy. The majority of these instructions will be incorporated into the Section 114 

letter and available on the website.

Please provide the information requested in Components 1-3 and, if applicable, 

Component 4 for the facility listed in the Section 114 letter you received in the mail. If you 

received one Section 114 letter for multiple facilities, you must create a separate survey response 

for each facility.1

Use the 2010 calendar year as the base year for all survey responses (e.g., 2010 emissions 

inventory, 2010 throughput, 2010 equipment configurations) unless another year is specified in 

the instructions (e.g., for existing emissions test data). 

The following sections (Component 1) are to be completed by all facilities and returned 

to the address noted below by May 31, 2011: 

• Part I – General Facility Information: Provide information on the petroleum 

refinery at the facility level. 

• Part II – Process and Emissions Information: Provide detailed information on the 

process units and other emissions sources at the petroleum refinery. 

• Part III – Incidence Reports: Provide copies of reports filed as a result of specific 

incidents at the petroleum refinery and information on public complaints. 

• Part IV – Cost Information: Provide the age and cost to install and operate 

control equipment at the petroleum refinery. 

• Part V – Emissions Monitoring and Source Test Data: Provide results of all 

existing emissions data from tests or monitoring conducted on any of the 

processes or emission points included in Part II, Sections 2 through 17.

The following section (Component 2) is to be completed by all facilities and returned to 

the address noted below by June 30, 2011:

• Part VI – Emissions Inventory: Provide emissions estimates for the requested 

process units and other emissions sources at the petroleum refinery.

 

1

 For purposes of this information request, “facility” is defined as any stationary source or group of stationary 

sources located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a 

public roadway or other public right-of-way and under common ownership or common control. 

Deleted: this enclosure

Deleted: Enclosure 2

Deleted: 9

Deleted: 9

Deleted: 9

Deleted: 9

Deleted: Enclosure

Deleted: within 90 days of receipt of your Section 

114 letter

Deleted: 

Deleted: 16. 

Deleted: Crude Oil
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2 

The following section (Component 3) is to be completed by all facilities and returned to 

the address noted below by August 31, 2011:

• Part VII – Distillation Feed Composition Analysis: Conduct an analysis of the 

composition of the feed to each distillation column at the refinery. 

Component 4 (Part VIII), emissions testing, is to be completed by facilities with process 

units selected for testing. The Section 114 letter you received directs you to a website where you 

can find a list that indicates if a unit at your refinery has been selected for testing as well as 

detailed instructions on how the testing must be conducted. For units requiring stack tests, 

emissions tests (consisting of three runs per test method required) are to be conducted according 

to Part VIII for each unit. For fuel gas samples, triplicate grab samples are to be taken for each 

mix drum associated with a fuel gas system. Follow the instructions in Part VIII for sampling 

the wastewater treatment system. The results of the emissions tests and other requested analyses 

should be returned to EPA by August 31, 2011. 

The electronic version of the survey (Parts I, II, III, and IV of this Component 1) can be 

downloaded from the ICR website (https://refineryicr.rti.org). Detailed instructions for each part 

follow. NOTE: The final version of this questionnaire will be in electronic format, not in 

hard copy. The questions are provided in this document merely for convenience during the 

public comment period. 

If you are unable to respond to an item exactly as requested, please explain why you 

cannot respond and/or provide any information you believe may be related. For example, if you 

have a special or unique type of process unit and the questions in the section related to that 

process unit are not relevant to your specific unit, please provide information that would help 

EPA classify your process unit and account for its existence and operation in potential future 

rulemaking. 

Questions regarding this information request should be directed to Ms. Brenda Shine at 

(919) 541-3608 or shine.brenda@epa.gov. 

Confidential Business Information (CBI) 

If you believe that providing any specific information to us would reveal a trade secret, or 

would compromise confidential business information (CBI), please identify this information 

clearly in your response and submit your response as detailed in the next section. Also, please 

clearly label any flow diagrams or other attachments submitted with your survey that contain 

CBI. However, please do not label your entire response as CBI if only a portion includes trade 

secrets. 

The EPA’s procedures for handling CBI are described in the letter (and enclosures) 

accompanying this questionnaire. The EPA is likely to follow-up with a request for validation of 

CBI claims for facilities claiming large amounts of information as trade secret, especially 

information that is readily reported by other facilities without such claims. Any information 

EPA subsequently determines to constitute CBI or a trade secret under EPA’s CBI regulations at 

40 CFR part 2, subpart B, will be protected pursuant to those regulations and, for trade secrets, 

under 18 U.S.C. 1905. If no claim of confidentiality accompanies the information when it is 

Deleted: type of crude

Deleted: Emissions 

Deleted: according to Enclosure 2

Deleted: Enclosure 2

Deleted: Enclosure 2

Deleted: within 6 months of receipt of this 

questionnaire

Deleted: Enclosure 1) is in Microsoft® Excel 

format and

Field Code Changed

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).

Deleted: ¶

Deleted: Mr. Bob Lucas at (919) 541-0884 or 

lucas.bob@epa.gov or 
Form Approved __/__/__ 

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3 

received by EPA, it may be made available to the public by EPA without further notice pursuant 

to EPA regulations at 40 CFR 2.203. Because Clean Air Act (CAA) section 114(c) exempts 

emission data from claims of confidentiality, the emission data you provide will be made 

available to the public notwithstanding any claims of confidentiality. 

How to Submit Your Survey Response 

If your response to this information collection request includes data with a claim of CBI, 

you should follow the instructions in this section to ensure the protection of your data. Please 

note that if you submit CBI, you should separate your data into two packages, one containing 

your entire response, including any information claimed as CBI, and the other containing only

information that you do not claim as CBI (hereafter referred to as “non-CBI”). These two 

packages should be sent to EPA separately, using two different mailing addresses. 

Separating CBI and Non-CBI 

As you complete and review your survey response, identify the information you consider 

CBI. Clearly mark the CBI components as “Confidential” in your electronic survey response. If 

you are sending attachments, clearly mark the CBI portions of the diagrams/pages (e.g., highlight 

or circle) as such. 

Once you have marked the CBI, create a new survey response file that does not include 

this information. If you have attachments, remove the pages that contain CBI. The resulting 

files and attachments comprise your non-CBI survey response. Please check carefully to ensure 

that there is no CBI in these files. Send these files to EPA using one of the methods described 

under “Submitting Your Non-CBI Response.” 

Create a separate CD or DVD containing your entire survey response, including CBI. 

Include on the disk any pages of attachments to your survey response containing CBI, with the 

CBI portions of the diagrams/pages clearly marked (e.g., highlighted or circled). Clearly mark 

the disk with the words “Confidential Business Information.” Send only these CBI files under 

separate cover to the address provided under “Submitting CBI.” 

Submitting Your Non-CBI Response 

For the non-CBI portions of your survey response, including non-CBI attachments (and 

for survey responses that are entirely non-CBI), use one of the following methods to submit your 

survey response to EPA: 

• Upload your files to the ICR website. Detailed directions for uploading your files 

are provided on the ICR website (https://refineryicr.rti.org).

• E-mail an electronic copy of all requested files to refineryicr@epa.gov. 

• Mail a CD or DVD containing an electronic copy of all requested files to the EPA 

address shown below. If no electronic copy is available, mail a hard copy of all 

requested files to the address shown below: 

Deleted: all other

Deleted: 

Deleted: After

Deleted: have completed

Deleted: ed

Deleted: only the CBI portion of 

Field Code Changed

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).
Form Approved __/__/__ 

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4 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

U.S. EPA Mailroom (D205-01) 

Attention: Brenda Shine, Petroleum Refinery Sector Lead 

109 T.W. Alexander Drive 

Research Triangle Park, NC 27711 

EPA recommends sending your non-CBI files via Registered U.S. Mail using return 

receipt requested, Federal Express, or other method for which someone must provide a signature 

upon receipt. 

Submitting CBI 

Follow the instructions under “Separating CBI and Non-CBI” to create the portion of 

your survey response that contains CBI. Send only these CBI files under separate cover to: 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

U.S. EPA Mailroom (C404-02) 

Attn: Mr. Roberto Morales, Document Control Officer 

109 T.W. Alexander Drive 

Research Triangle Park, NC 27711 

For security purposes, EPA highly recommends sending your confidential files to Mr. 

Morales via Registered U.S. Mail using return receipt requested, Federal Express, or other 

method for which someone must provide a signature upon receipt. 

DO NOT ELECTRONICALLY TRANSMIT CONFIDENTIAL BUSINESS 

INFORMATION TO EPA. E-mail and facsimile are not secure forms of communication and 

should never be used to transmit CBI. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

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5 

ABBREVIATIONS 

20 lb/ton coke burn-off SO2 emissions limit in 40 CFR part 60, subpart J, of 9.8 kg/Mg (20 

lb/ton) coke burn-off (40 CFR 60.104(b)(2)) 

50/25 ppmv SO2 limit SO2 emissions limit in 40 CFR part 60, subpart Ja of 50 ppmv SO2, 

dry basis corrected to 0 percent excess air, on a 7-day rolling average 

basis and 25 ppmv, dry basis corrected to 0 percent excess air, on a 

365-day rolling average basis (40 CFR 60.102a(b)(3)) 

acfm actual cubic feet per minute 

APCD air pollution control device 

As arsenic 

ASTM American Society of Testing and Materials 

bbl barrels 

bbl/cd barrels per calendar day 

bbl/sd barrels per stream day 

bbl/yr barrels per year 

BOD biological oxygen demand 

BQ benzene quantity 

Btu/lb British thermal units per pound 

BWON Benzene Waste Operations NESHAP (40 CFR part 61, subpart FF) 

CAA Clean Air Act 

CAS Chemical Abstracts Service 

CBI confidential business information 

CCU catalytic cracking unit 

CEMS continuous emission monitoring system 

CERCLA Comprehensive Environmental Response, Compensation, and Liability 

Act 

CFR Code of Federal Regulations 

CO carbon monoxide 

COD chemical oxygen demand 

COS carbonyl sulfide 

CRU catalytic reforming unit 

DCU delayed coking unit 

DIAL Differential Absorption Light Detection and Ranging 

DMEA dimethylethanolamine 

E-cat equilibrium catalyst 

EPA U.S. Environmental Protection Agency 
Form Approved __/__/__ 

OMB Control No. ____-____ 

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6 

ESP electrostatic precipitators 

ETBE ethyl tert-butyl ether 

F/M ratio food to microorganism ratio 

FCU fluid coking unit 

ft feet 

gal/day gallons per day 

gal/min gallons per minute 

H2S hydrogen sulfide 

H2SO4 sulfuric acid 

HAP hazardous air pollutants 

HF hydrogen fluoride 

Hg mercury 

hr hours 

hr/yr hours per year 

ICR information collection request 

ID identification number or code 

Iso C5,C6 isopentane (aka 2-methylbutane), isohexane (aka 2-methylpentane) 

Lat/Long latitude and longitude 

lb/ft3

 pounds per cubic foot 

lb/hr pounds per hour 

lb/ton pounds per ton 

LDAR leak detection and repair 

LPG liquefied petroleum gas 

LT/cd long tons per calendar day 

MACT Maximum Achievable Control Technology 

MCRC maximum Claus recovery/conversion 

Mg/yr megagrams per year 

MLSS mixed liquor suspended solids 

MLVSS mixed liquor volatile suspended solids 

MM lb million pounds 

MMBtu/hr million British thermal units per hour 

MMcf million cubic feet 

MMcf/cd million cubic feet per calendar day 

MMgal/day million gallons per day 

MTBE methyl tert-butyl ether 

MW megawatts 

MWh megawatt-hours 
Form Approved __/__/__ 

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7 

NAD North American Datum 

NESHAP national emissions standards for hazardous air pollutants 

Ni nickel 

No. number 

NOX oxides of nitrogen 

NSPS new source performance standards 

OVA organic vapor analyzer 

PM particulate matter 

ppmv parts per million by volume 

ppmw parts per million by weight 

PSA pressure swing absorption 

PRD pressure relief device

psi pounds per square inch 

psia pounds per square inch absolute 

psig pounds per square inch gauge 

QA quality assurance 

QC quality control 

regen. regeneration 

SCC Source Classification Code 

scfm standard cubic feet per minute 

SCOT Shell Claus Off-gas Treating 

SCR selective catalytic reduction 

Se selenium 

SNCR selective non-catalytic reduction 

SO2 sulfur dioxide 

SOF Solar Occultation Flux 

SRU sulfur recovery unit 

STERPP storage tank emission reduction partnership program (72 FR 19891) 

TAB total annual benzene 

TAME tert-amyl methyl ether 

THC total hydrocarbons 

TOC total organic compounds 

tons/cd tons per calendar day 

tons/yr tons per year 

TRS total reduced sulfur 

U.S. DOE/EIA U.S. Department of Energy, Energy Information Administration 

ULNB ultra low NOX burner (high fraction staged fuel) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

8 

UV ultraviolet 

VOC volatile organic compounds 

wt% weight percent 

WWTS wastewater collection and treatment system 

WWTU wastewater collection or treatment unit 

°F degrees Fahrenheit 

% percent 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

9 

PART I: GENERAL FACILITY INFORMATION 

1. Facility ID number (EPA will provide this number): ______________________

2a. Plant Name (as reported on U.S. DOE/EIA Form-820 (2010), “Annual Refinery Report,” 

schedule 2, line 1, page 37, question 1): 

_________________________________________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

2b. Does this facility3

 report in EIA-820 the combined processing/production capacities for 

refining plants that are not contiguously located? Yes No

2c. If Yes, provide the facility ID for each non-contiguous facility: _____________________ 

_________________________________________________________________________ 

________________________________________________________________________ 

3. Complete street address of facility (physical location): ____________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

4. Provide mailing address if different: ___________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

5. Name and title of contact(s) able to answer technical questions about the completed 

survey: __________________________________________________________________ 

_________________________________________________________________________ 

6. Contact(s) telephone number(s): ______________________________________________ 

 and e-mail address(es): _____________________________________________________ 

7. Name of legal owner of facility: ______________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

8. Name of legal operator of facility, if different from legal owner: ____________________ 

_________________________________________________________________________ 

 

3

 For purposes of this information request, “facility” is defined as any stationary source or group of stationary 

sources located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a 

public roadway or other public right-of-way and under common ownership or common control.

Deleted: 1. Name of legal owner of facility2: ¶

¶

¶

¶

2. Name of legal operator of facility, if different 

from legal owner: ¶

¶

¶

3. Address of ____ legal owner or ____ operator: 

¶

¶

¶

¶

4a

Deleted: 9

Deleted: 4b

Deleted: 4c

Deleted: name and location

Deleted: 4d. If Yes, you must complete a separate 

survey response for each non-contiguous facility. 

Indicate the name of the facility for which the 

remainder of this survey response applies. ¶

__________________________________________

______________________________¶

5

Deleted: 6

Deleted: 7

Deleted: 8
Form Approved __/__/__ 

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10 

_________________________________________________________________________ 

9. Address of ____ legal owner or ____ operator: __________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

10. Dunn and Bradstreet number of your facility: ___________________________________ 

11. Annual revenue in 2010: $______________________ 

12. Number of employees at your facility: _________________________________________ 

13a. Are you part of a larger corporate entity or joint venture? Yes No

13b. If 13a is Yes, is the facility operated under a joint venture partnership? Yes No

 If Yes: Provide the name and % ownership of each joint venture partner and provide the 

number of employees for each joint venture partner with 50% or greater ownership: 

Partner name ______________ Percent ownership ______% No. employees ______

Partner name ______________ Percent ownership ______% No. employees ______

Partner name ______________ Percent ownership ______%

 If No: Name of parent company: _____________________________________________ 

Number of employees in parent company: ___________________________ 

Check the statement below that best applies: 

 The facility is fully independent of the parent organization (independent sources 

of capital, different Boards of Directors, etc.). 

 The parent organization provides some financial support. 

 Operations of the parent organization and this facility are fully integrated (full 

access to investment capital, same Board of Directors, etc.) 

14. Circle all the applicable code numbers that describe the type of refinery:

1 Topping refinery

2 Hydroskimming refinery

3 Upgrading refinery

4 Heavy oil/asphalt refinery

15. Provide the quantity of products produced at the refinery and their relative disposition 

(transport method) in 2010. Production values should be provided as reported to EIA on 

form EIA-810 form, except specify aromatics production quantities. Provide the relative 

disposition of products from readily available information; exact quantity information is 

not necessary. For products piped directly to an offsite marine vessel tank ship terminal 

Deleted: 10

Deleted: 9

Deleted: 

Deleted: 11

Deleted: 12a

Deleted: 12b

Deleted: Corporate crude oil processing capacity: 

(bbl/stream day) ¶

12c. If Yes, check

Deleted: 13. Circle all applicable code number(s) 

for the final 

Deleted: facility:¶

1 LPG¶

2 Automotive gasoline¶

3 Aviation fuels¶

4 No. 2 diesel fuel ¶

5 No. 4 diesel fuel (heavy fuel oil)¶

6 No. 6 diesel fuel (marine diesel/bunker C)¶

7 Lubricating/motor oil¶

8 Asphalt¶

9 Petroleum coke¶

10 Sulfur ¶

11 Ethylene¶

12 Aromatics (specify): 

__________________________________________

_____ ¶

13 Other petrochemicals (specify): 

______________________________________ ¶

14 Other (specify): 

__________________________________________

_________¶

¶
Form Approved __/__/__ 

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11 

or tank truck terminal that is located near the refinery and is owned, operated, or under 

common control of the refinery (or its corporate holdings), report the transportation 

method as tank ship or tank truck, respectively, rather than reporting this quantity as “% 

shipped by pipeline.” Report under “% shipped by pipeline” all products shipped via 

general use pipelines (regardless of secondary transportation methods that may be served) 

or products piped directly to other offsite facilities. 

Product/Refinery Output

Cumulative 

2010 

Production 

(1,000 bbls)

Disposition of Products by Transport Method

% used 

onsite

% 

shipped 

by tank 

ship

% 

shipped 

by 

barge

% 

shipped 

by tank 

truck

% 

shipped 

by rail 

car

% 

shipped 

by 

pipeline

Ethane

Ethylene

Propane

Propylene

Normal Butane

Butylene

Isobutane

Isobutylene

Unfinished Oils – Naphthas 

and lighter

Unfinished Oils – Kerosene 

and light gas oils

Unfinished Oils – Heavy gas 

oils

Unfinished Oils – Residuum

Finished Motor Gasoline -

Reformulated

Finished Motor Gasoline -

Conventional

Motor Gasoline Blending 

Components - Reformulated

Motor Gasoline Blending 

Components - Conventional

Aviation Gasoline – Finished 

and Blending Components

Special Naphthas (solvents)

Kerosene-type Jet Fuel

Kerosene

Distillate Fuel Oil – 15 ppm 

sulfur and under

Distillate Fuel Oil – greater 

than 15 ppm to 500 ppm 

sulfur 

Distillate Fuel Oil – greater 

than 500 ppm sulfur
Form Approved __/__/__ 

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Product/Refinery Output

Cumulative 

2010 

Production 

(1,000 bbls)

Disposition of Products by Transport Method

% used 

onsite

% 

shipped 

by tank 

ship

% 

shipped 

by 

barge

% 

shipped 

by tank 

truck

% 

shipped 

by rail 

car

% 

shipped 

by 

pipeline

Residual Fuel Oil – less than 

0.31% sulfur 

Residual Fuel Oil – 0.31% to 

1.0% sulfur 

Residual Fuel Oil – greater 

than 1% sulfur

Lubricants (total)

Asphalt and Road Oil

Wax

Petroleum Coke –

Marketable 

Petroleum Coke – Catalyst 

Still Gas

Petrochemical Feedstocks –

Naphtha <401°F end-point 

Petrochemical Feedstocks -

Other Oils ≥401°F end-point 

Aromatics – Benzene 

Aromatics – Toluene

Aromatics – Xylenes (total)

Aromatics – Other than BTX

Other Miscellaneous 

Products 
Form Approved __/__/__ 

OMB Control No. ____-____ 

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13 

16. Report the 2010 process capacities and actual throughput for each process unit by 

completing the table below. See definitions section for additional descriptions of the 

terms used. You may need to add “other” process units if your refinery contains 

significant processing units that are not covered by the processes listed. If 2010 

throughputs are not representative of normal operations (e.g., plant idled temporarily for 

economic reasons, change of ownership, or fire, etc.), add a note describing the reason for 

the unusual operation and provide an estimate of the expected “normal” 2010 processing 

rates had these issues not occurred.

When asked for a Unit ID, please use the same identifying number or code that is used in 

EPA’s 2005 National Scale Air Toxics Assessment (NATA) National Emissions 

Inventory (NEI) data set (if possible and/or applicable). Instructions for locating the NEI 

data set for your refinery are located at the ICR website (https://refineryicr.rti.org). If the 

NEI does not show an entry for a particular unit, or you are not sure what units are 

included in the NEI data set, use a unique Unit ID for each process unit. 

Provide the coordinates (latitude and longitude) of the approximate process unit centroid 

in North American Datum (NAD) 83 with 6 digits to the right of the decimal point.d (If 

currently available coordinates have five digits to the right of the decimal point instead of 

six, those coordinates are acceptable.).

 

d

Latitude measure in decimal degrees of the angular distance on a meridian north or south of the equator. Positive 

(+) data point for North America. Example: +78.123456. For point sources, this represents the center of the source; 

for fugitive sources, this is the southwest corner if the fugitive angle is zero or the western most corner if the fugitive 

angle is greater than zero. Longitude measure in decimal degrees of the angular distance on a meridian east or west 

of the prime meridian. Negative (-) data point for North America. Example: -123.234561. For point sources this 

represents the center of the source; for fugitive sources, this is the southwest corner if the fugitive angle is zero, or 

the western most corner if the fugitive angle is greater than zero. 

Deleted: Attachment 1 to this enclosure is a copy 

of the 

Deleted: for each of your refineries (if available) 

for your reference. When asked for a Unit ID in 

Questions 15 and 16, please use the same identifying 

number or code that is used in the NEI data set 

Deleted: Processing Unit ... [1]

Deleted: (See instructions to Part II, Annex A for 

additional details on latitude and longitude format.)
Form Approved __/__/__ 

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Unit 

ID Process Type1

Unit 

Throughput

Capacity

(bbl/cd)2

Unit Actual 

Throughput

(bbl/cd)2

Unit 

Latitude Unit Longitude 

1

 See list following the last footnote for codes corresponding to unit types. If none of the codes describe your process, enter “99” 

and specify the type of process.

2

 Throughput by calendar day × 365 days = annual throughput for 2010.Throughput units are barrels per calendar day (bbl/cd) 

unless noted otherwise. 

For crude distillation through desulfurization units (process type codes 1 through 21), “throughput” is determined in terms 

of charged liquid material (excluding hydrogen gas inputs).

For catalytic cracking units, include both fresh and recycle feed.

For alkylation through coke calcining (process type codes 22 through 43), “throughput” is determined in terms of primary 

product produced (e.g., quantity of alkylate produced in alkylation unit).

For aromatics production, report the total quantity of all aromatics produced from various separation processes after 

catalytic reforming.

For hydrogen production, throughput units are million standard cubic feet per calendar day (MMcf/cd); use 32°F (0°C) 

and 1 atmosphere as “standard conditions” for H2 production.

For sulfur recovery, throughput units are long tons per calendar day (LT/cd). 1 LT = 1.12 short tons. Enter individual 

SRU trains in this table; you will be asked to identify the sulfur recovery plant for each train in Part II, Section 9.

For loading operations, “throughput” is the quantity of material loaded.

For fuel gas treatment, “throughput” is the quantity of fuel gas input to the unit. Throughput units are million standard

cubic feet per calendar day (MMcf/cd); use 60°F (15.56°C) and 1 atmosphere as “standard conditions” for fuel gas 

treatment.

For fuel blending, “throughput” is the quantity of blended product produced. 

For wastewater treatment, throughput units are million gallons per day (MMgal/day). If desired, you may report 

wastewater treatment units used to comply with Benzene Waste Operations NESHAP (40 CFR part 61, subpart FF)

“BWON” or sour water treatment units as separate wastewater treatment systems, but you are not required to do so. 

Inserted Cells

Deleted: 1

Deleted: 3

Deleted: 4

Deleted: Processing Unit

Deleted: Lat

Deleted: Long

Deleted: Lat

Deleted: Long

Deleted: Lat

Deleted: Long

Deleted Cells

Deleted: Lat

Deleted Cells

Deleted: Long

Deleted Cells

Deleted: Atmospheric crude distillation

Deleted: Vacuum distillation

Deleted: Delayed coking

Deleted: Fluid coking (traditional)

Deleted: Flexicoking

Deleted: Visbreaking, other thermal cracking

Deleted: Fluid catalytic cracking unit

Deleted: Non-fluid catalytic cracking unit

Deleted: Catalytic hydrocracking

Deleted: Catalytic reforming unit – continuous 

regen.

Deleted: Catalytic reforming unit – cyclic 

regeneration

Deleted: Catalytic reforming unit – semiregenerative

Deleted: Fuels solvent deasphalting

Deleted: Desulfurization/ hydrotreat – 

naphtha/CRU feed

Deleted: Desulfurization/ hydrotreat – gasoline

Deleted: Desulfurization/ hydrotreat – kerosene/ 

jet fuel

Deleted: Desulfurization/ hydrotreat – diesel

Deleted: Desulfurization/ hydrotreat – other 

distillate

Deleted: Desulfurization/ hydrotreat – residual

Deleted: Desulfurization/ hydrotreat – heavy gas 

oil

Deleted: Desulfurization/ hydrotreat – other ... [2]
Form Approved __/__/__ 

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15 

Code No. Type of Process

1 Atmospheric crude distillation

2 Vacuum distillation

3 Delayed coking

4 Fluid coking (traditional)

5 Flexicoking

6 Visbreaking, other thermal cracking

7 Fluid catalytic cracking unit

8 Non-fluid catalytic cracking unit

9 Catalytic hydrocracking

10 Catalytic reforming unit – continuous regeneration

11 Catalytic reforming unit – cyclic regeneration

12 Catalytic reforming unit – semi-regenerative

13 Fuels solvent deasphalting

14 Desulfurization/ hydrotreat – naphtha/reformer feed

15 Desulfurization/ hydrotreat – gasoline

16 Desulfurization/ hydrotreat – kerosene/jet fuel

17 Desulfurization/ hydrotreat – diesel

18 Desulfurization/ hydrotreat – other distillate

19 Desulfurization/ hydrotreat – residual

20 Desulfurization/ hydrotreat – heavy gas oil

21 Desulfurization/ hydrotreat – other

22 HF alkylation

23 H2SO4 alkylation

24 Aromatics production

25 Asphalt production

26 Isomerization – Isobutane

27 Isomerization – Iso C5,C6

28 Lubricants production

29 Petroleum coke storage

30 Hydrogen plant

31 Sulfur recovery unit (SRU)

32 Gas plant/light ends distillation/LPG production unit

33 Oxygenate plant – MTBE

34 Oxygenate plant – ETBE

35 Oxygenate plant – TAME

36 Oxygenate plant – other (specify)

37 Ethylene production

38 Ethylene dichloride production

39 Ethylene dibromide production

40 Propylene production

41 Acrylonitrile production

42 Other petrochemical or organic chemical production (specify chemical)

43 Coke calcining

44 Marine vessel loading/unloading

45 Truck/tank truck loading/unloading

46 Rail car loading/unloading

47 Container/other loading/unloading

48 Fuel gas treatment

49 Fuel blending

50 Wastewater treatment system

99 Other (specify)
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

16 

PART II: PROCESS AND EMISSIONS INFORMATION 

When asked for a Unit ID in any section of Part II, please use the same identifying number or 

code that is used in Part I, Question 16. 

SECTION 1. ENERGY MANAGEMENT 

1. Facility ID number (EPA will provide this number): ________________________ 

2. Complete Table 1-1 below to provide the total energy use and fuel consumption by the 

entire refinery in 2010 (as reported to EIA on forms EIA-810 and EIA-820):

TABLE 1-1. 2010 Fuel Consumption 

Fuel Units Fuel Consumption 

Crude Oil1 bbl 

LPG bbl 

Distillate Fuel Oil bbl 

Residual Fuel Oil bbl 

Still Gas bbl

Marketable Coke bbl

Catalyst Coke bbl

Natural Gas MMcf 

Coal Tons (US) 

Purchased Electricity MWh 

Purchased Steam MM lb 

Other (solid) Tons (US)

Other (liquid) bbl 

Other (gas) MMcf

Abbreviations: bbl = barrels 

MMcf = million cubic feet at 60°F and 1 atmosphere 

MWh = Megawatt-hours 

MM lb = million pounds 1

 Report only the quantity of crude oil consumed as fuel, not the quantity of crude oil fed to the 

atmospheric crude or vacuum distillation column.

3. Report the total quantity of hydrogen purchased [in million cubic feet at 32°F (0°C) and 1 

atmosphere] from off-site (merchant) hydrogen producers. Do not include captive 

hydrogen production included in Part I; more detail regarding captive hydrogen 

production units is requested in Part II, Section 10. 

4. Does this refinery have a facility energy management plan? Yes No

If Yes: Provide a brief description of the key elements of the plan and key energy 

reductions that have resulted from the implementation of the plan. 

Deleted: As noted in Part I, Attachment 1 to this 

enclosure is a copy of the EPA’s 2005 NATA NEI 

data set for your refinery (if available) for your 

reference. 

Deleted: the NEI data set (if possible and/or 

applicable). If the NEI does not show an entry for a 

particular unit, or you are not sure what units are 

included in the NEI data set, use a unique Unit ID 

for each process unit throughout Part II

Deleted: c

Deleted: response

Deleted: 2009:

Deleted: 9

Deleted: MMcf

Deleted: Petroleum

Deleted: Tons (US)

Deleted: Tons (US)

Deleted: 3
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

17 

5. Does this refinery generate electricity or steam on-site? Yes No

If Yes: Provide the information requested in Table 1-2 for each electricity-generating, 

steam generating, or combined heat and power unit. Include energy recovery turbines

and waste heat boilers used on process unit exhaust lines. 

TABLE 1-2. Electricity and Steam Generation Information 

rat

ion 

De Un

scr

ipt

Primary Fuel2

Secondary Fuel2

Energy Efficiency 

Measures3

Air preheat use4

Typical air preheat 

temperature when used (°F)

Is this unit a combined heat 

and power unit? (Yes/No)

Electricity 

Generation Steam Generation Capacity of Unit (MW) Disposition of electricity5 Boiler Heat Input Capacity (MMBtu/hr) Steam Generating Capacity (lb/hr) Pressure of Steam (psia) Disposition of steam6

Percent Steam to 

Blowdown7

 

Footnotes for Table 1-2:

Abbreviations: MW = megawatts 

MMBtu/hr = million British thermal units per hour 

lb/hr = pounds per hour 

psia = pounds per square inch absolute 

1

 For waste heat boiler, list process unit and “waste heat boiler” (e.g., “FCCU waste heat 

boiler”). 

Deleted: Unit ID Number 

Merged Cells

Deleted: Unit Description 

Merged Cells

Deleted: Primary Fuel

Deleted: Secondary Fuel

Inserted Cells

Inserted Cells

Deleted: electricity1

Inserted Cells

Deleted: Abbreviation: MW = megawatts¶ 1

 For disposition of electricity, enter appropriate code 

number as follows: ¶

Enter “1” if generated electricity is used only on-site. ¶

Enter “2” if generated electricity is used only off-site 

(e.g., sent to grid).¶

Enter “3” if generated electricity is used on-site with 

excess used off-site or sent to grid.¶

¶

4. Does this refinery generate steam onsite? Yes No¶

If Yes: Provide the information requested in Table 

1-3 for each steam-generating unit. ¶

TABLE 1-3. Steam Generation Information¶

Unit ID ... [3]
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

18 

2 Select from the following list of fuels.

Code No. Type of Fuel 

1 Natural gas

2 Refinery fuel gas (mixture of natural gas and still gas or process gas)

3 Still gas or process gas only (not mixed with natural gas)

4 Distillate fuel oil

5 Heavy gas oil

6 Low Btu fuel gas from flexicoking unit or other gasification process

7 Coal

8 Wood or other biomass fuel

99 Other (specify)

3 Select the energy efficiency measure(s) used with this unit from the following list. Select all 

that apply. 

Code No. Type of Energy Efficiency Measure

0 None 

1 Insulation on boiler 

2 Insulation on distribution lines 

3 Oxygen monitors used to control/limit excess oxygen

4 Intake air monitors to optimize fuel/air mixtures

5 Combustion air preheat from flue gas 

6 Boiler feed water preheat from flue gas 

7 Blowdown steam recovery system for low pressure needs 

8 Steam trap maintenance 

9 Steam condensate return lines (to return condensate (hot water) to boiler) 

10 Steam expansion turbines (to recover energy from high pressure steam when steam is 

needed at lower pressures)

11 Boiler maintenance program to reduce scaling (other than soot blowing)

12 Boiler maintenance program to maintain burners (other than soot blowing)

99 Other (specify)

4

 Select from the following list of air preheat descriptions the option that best applies for the unit.

Code No. Type of Air Preheat

0 No air preheater is present

1 Air preheater is present, but use less than 20% of the time

2 Air preheater is present and used 20% to 50% of the time

3 Air preheater is present and used more than 50% but less than 90% of the time

4 Air preheater is present and used 90% or more of the time 

5

 Select from the following list of dispositions. 

Code No. Type of Electricity Disposition

1 Generated electricity is used only on-site

2 Generated electricity is used only off-site (e.g., sent to grid)

3 Generated electricity is used on-site with excess used off-site or sent to grid

Deleted: For disposition of steam, enter 

appropriate code number as follows: ¶

Enter “

Deleted: ” if generated steam is used

Deleted: on-site. 

Deleted: Enter “2” if generated steam is used only 

off-site.¶

Enter “3” if generated steam is used on-site with 

excess used off-site.¶

Deleted: Enter

Deleted: code number for each

Deleted: steam-generating 

Deleted: ;

Deleted: : 

Deleted: and intake

Deleted: and limit excess oxygen

Deleted: 4

Deleted: 5

Deleted: 6

Deleted: 7 Boiler maintenance program (to 

reduce scaling; maintain burners)¶

Deleted: program

Deleted: )__________________
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

19 

6

 Select from the following list of dispositions. 

Code No. Type of Steam Disposition

1 Generated steam is used only on-site. 

2 Generated steam is used only off-site.

3 Generated steam is used on-site with excess used off-site.

7

 If the exact percentage is unknown, and you are unable to provide a reasonable estimate, 

answer “Unknown.”
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

20 

6. Provide the information requested in Table 1-3 for each processing unit listed in Question 

16 of Part I (except wastewater treatment systems, which are reported in Section 15). 

TABLE 1-3. Steam Demand by Process Unit 

Unit 

ID 

Average steam

demand for the 

processing unit 

during normal 

operation 

assuming the 

processing unit 

is operated at 

maximum 

capacity (lb/hr)1

1

 For cyclic processes, such as delayed coking unit, estimate the total steam use over a complete cycle 

and divide by the cycle time indicative of maximum processing rates.

Deleted: 5

Deleted: 4

Deleted: Questions 14 and 15

Deleted: 4

Deleted: and Process Heater Capacity 

Deleted: Processing Unit Type1

Deleted Cells

Deleted: Steam

Deleted: at capacity 

Deleted: Total number of process heaters

Deleted Cells

Deleted: Cumulative rated heat capacity of 

process heaters for process unit (MMBtu/hr) 

Deleted Cells

Deleted: Number of process heaters with air 

preheat

Deleted Cells

Deleted: Cumulative rated heat capacity of 

process heaters with air preheat for process unit 

(MMBtu/hr)

Deleted Cells

Deleted: ¶ ... [4]
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

21 

SECTION 2. PROCESS HEATER DATA 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide the information requested in Table 2-1 for each process heater at the 

facility that serves a process unit identified in Part I, Question 16. 

TABLE 2-1. Process Heater General Information 

Process Heater ID 

Unit ID for process unit served by 

process heater 

Process heater construction type1

Process heater draft type2

Is the process heater designed to be e 

co-fired? (Yes/No)

Rated heat input capacity (MMBtu/hr) 

Average heat input rate in 2010 

(MMBtu/hr)

Total operating hours in 2010 (hr) 

Air preheat use3

Typical air preheat temperature when 

used (°F)

Other energy efficiency measures4

Primary fuel5

Percent of total operating hours 

process heater fired with primary fuel 

in 2010

Secondary fuel5

Percent of total operating hours 

process heater fired with secondary 

fuel in 2010

Operating hours in turndown in 2010 

(hr) 

Applicable Federal air regulation(s)

6

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s) 

Type of PM controls7

Type of SO2 controls8

Type of NOX controls9

 

 

Deleted: c

Deleted: response

Deleted: 3. For each process heater listed in 

Table 2-1, also provide annual PM, SO2, NOX, CO, 

VOC, and HAP emission estimates (tons/yr) 

following the methods provided in the Emission 

Estimation Protocol for Petroleum Refineries using 

the emissions template in Annex A of this part. ¶

Deleted: Process 

Deleted: 1

Deleted: 2

Deleted: 3

Deleted: Primary fuel4

Deleted: Secondary fuel4

Deleted Cells

Deleted: 9

Deleted: 

Deleted: 9

Inserted Cells

Inserted Cells

Inserted Cells

Inserted Cells

Deleted: Operating

Deleted: while coDeleted: 2009 (hr)

Inserted Cells

Inserted Cells

Deleted: 

Deleted: 9

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 

Deleted: 5

Deleted: 

Deleted: 6

Deleted: 

Deleted: 7

Deleted: ¶ ... [5]
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

22 

Footnotes for Table 2-1: 

1

 Select from the following list of process heater construction types. 

Code No. Type of Construction 

1 Vertical cylinder 

2 Cabin or box 

99 Other (specify) 

2

 Select from the following list of process heater draft types. 

Code No. Type of Draft 

1 Natural draft 

2 Induced draft (exhaust-side fan only), upward firing 

3 Induced draft (exhaust-side fan only), downward firing 

4 Forced draft (combustion air-side fan only) 

5 Balanced draft (both air- and exhaust-side fans), but no air preheater

6 Balanced draft (both air- and exhaust-side fans) with air preheater

99 Other (specify) 

3

 For air preheat use, enter the appropriate code number the option that best describes the air 

preheat use: 

Code No. Type of Air Preheat

0 No air preheater is present

1 Air preheater is present, but use less than 20% of the time

2 Air preheater is present and used 20% to 50% of the time

3 Air preheater is present and used more than 50% but less than 90% of the time

4 Air preheater is present and used 90% or more of the time 

4 Select from the following list of energy efficiency measures (other than air preheat).

Code No. Type of Energy Efficiency Measure

0 None

1 Oxygen monitors used to control/limit excess oxygen

2 Intake air monitors to optimize fuel/air mixtures 

3 Maintenance program to reduce scaling (other than soot blowing)

4 Maintenance program to maintain burners (other than soot blowing)

5 Finned or dimpled tubes to increase heat transfer

99 Other (specify)

Deleted: 1 Select the process units served by the 

process heater from the following list.¶

Code No. Type of Process Unit¶

1 Atmospheric crude distillation¶

2 Vacuum distillation¶

3 Delayed coking¶

4 Fluid coking (traditional)¶

5 Flexicoking¶

6 Visbreaking, other thermal cracking¶

7 Fluid catalytic cracking unit¶

8 Non-fluid catalytic cracking unit¶

9 Catalytic hydrocracking¶

10 Catalytic reforming unit – continuous 

regeneration¶

11 Catalytic reforming unit – cyclic regeneration¶

12 Catalytic reforming unit – semi-regenerative¶

13 Fuels solvent deasphalting¶

14 Desulfurization/ hydrotreat – naphtha/reformer 

feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet fuel¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – other¶

22 HF alkylation¶

23 H2SO4 alkylation¶

24 Aromatics production¶

25 Asphalt production¶

26 Isomerization – Isobutane¶

27 Isomerization – Iso C5,C6 ¶

28 Lubricants production ¶

29 Petroleum coke storage¶

30 Hydrogen plant¶

31 Sulfur plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

99 Other (specify)¶

¶

2

Deleted: 3

Deleted: blast

Deleted: /air preheat

Deleted: )
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

23 

5 Select from the following list of fuels. 

Code No. Fuel Type 

1 Natural gas 

2 Refinery fuel gas (mixture of natural gas and still gas or process gas)

3 Still gas or process gas only (not mixed with natural gas)

4 Distillate fuel oil 

5 Heavy gas oil 

6 Low Btu fuel gas from flexicoking unit or other gasification process

99 Other (specify) 

6

 Select the Federal air regulation(s) to which the process heater is subject from the following list 

of regulations. Select all that apply, but include only regulations to which the process heater is 

subject according to the applicability of the regulation (i.e., do not select regulations that are 

referenced from the regulation(s) to which the process heater is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery NSPS (40 CFR part 60, subpart J)

2 Refinery NSPS (40 CFR part 60, subpart Ja)

3 CAA section 112(g) and section 112(j) (40 CFR part 63, subpart B)

99 Other (specify)

7

 Select from the following list of PM controls; list all that apply. 

Code No. Type of PM Control 

0 None 

11 Fabric/cartridge filter (“baghouse”) 

12 Venturi/wet scrubber 

13 Electrostatic precipitator (ESP) 

14 Wet ESP 

96 Management practice or work practice to reduce PM (specify) 

99 Other (specify) 

8

 Select from the following list of SO2 controls; list all that apply. 

Code No. Type of SO2 Control 

0 None 

21 H2S limit in fuel gas 

22 TRS limit in fuel gas 

23 Low sulfur distillate or low sulfur heavy gas oil 

24 Wet scrubber/flue gas desulfurization 

25 Spray dryer absorber 

97 Management practice or work practice to reduce SO2 (specify) 

99 Other (specify) 

Deleted: 4

Deleted: 5

Deleted: 98

Deleted: 6

Deleted: 98
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

24 

9

 Select from the following list of NOX controls; list all that apply. 

Code No. Type of NOX Control 

0 None 

31 (External) flue gas recirculation 

32 Staged air low NOX burner 

33 Staged fuel low NOX burner 

34 Ultra low NOX burner (high fraction staged fuel) (ULNB) 

35 “Next generation” low NOX burner (ULNB with internal gas recirculation) 

36 Selective non-catalytic reduction (SNCR) 

37 Selective catalytic reduction (SCR) 

98 Management practice or work practice to reduce NOX (specify) 

99 Other (specify) 

Deleted: 7
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

25 

SECTION 3. EQUIPMENT LEAKS 

 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Do you own or have ready access to an optical or thermal imaging device for detecting 

equipment leaks? Yes No

If Yes: 

a. Provide the manufacturer and model number: ____________________________ 

b. How do you most often use the imaging device to detect equipment leaks? 

1 To comply with the alternative work practice for monitoring equipment for leaks (40 

CFR 63.11(c) and 40 CFR 60.18(g)) 

2 To check for leaks on a fairly routine basis (e.g., leaks that Method 21 monitoring may 

have missed, leaks from equipment not required to be monitored) 

3 To find leaks following non-routine operations (e.g., pressure integrity checks prior to 

startup) 

3. Complete Table 3-1 for each process unit listed in Part I, Question 16 (except wastewater 

treatment). The total equipment counts should be the total number of pieces of 

equipment in a process unit, not necessarily only those currently being monitored. Do 

not count pieces of equipment that are in vacuum service. You may provide reasonable 

estimates of equipment counts from existing information if the requested equipment 

counts are not directly available as requested in Table 3-1 for each process unit as defined 

in this ICR.

Deleted: c

Deleted: response

Deleted: Do you routinely monitor your fuel gas 

system for leaks? Yes No¶

4. 

Deleted: Questions 14 and 15

Deleted: ) and

Deleted: fuel gas and natural gas system at the 

facility. 

Deleted: 5. For each process unit and fuel gas and 

natural gas system listed in Table 3-1, provide 

annual VOC and HAP emission estimates (tons/yr) 

for equipment leaks following the methods provided 

in the Emission Estimation Protocol for Petroleum 

Refineries using the emissions template in Annex A 

of this part.¶
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

26 

TABLE 3-1. Equipment and Leak Detection Information for Process Units

it 

Applicable Federal air regulation(s)

1

If subjectto State, local, or Tribalair 

regulation(s), provide the citation(s) Average methane concentration in

process fluid that contacts equipment 

in gas service throughout the process Is the average methane concentration

based on sampling and analysis 

results or estimated (e.g., based on 

process knowledge)? For each of the following 

types of 

equipment, 

provide:

Pum

ps Valves Flanges

Connec

tors 

de

pre s

tch

gla

Gages

Diaphragms

Other

4

Light liquid

2

Heavy liquid

2

Gas

2

Light liquid

2

Heavy liquid

2

Gas

2

Light liquid

2

Heavy liquid

2

Gas

2

Light liquid

2

Heavy liquid

2

Number of 

Pieces of 

Equipment

Number of 

Pieces of 

Equipment 

Monitored5

Monitoring 

Frequency6

Leak 

Definition 

(ppmv)7

Number of 

Pieces of 

Equipment

Number of 

Pieces of 

Equipment 

Monitored5
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

27 

Monitoring 

Frequency6

Leak 

Definition 

(ppmv)7
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

28 

Footnotes for Table 3-1: 

1

 Select the Federal air regulation(s) to which the process unit is subject from the following list 

of regulations. Select all that apply, but include only regulations for equipment leaks to which 

the process unit is subject according to the applicability of the regulation (i.e., do not select 

regulations that are referenced from the regulation(s) to which the process unit is subject).

Code No. Federal Air Regulation 

0 None 

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements 

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements 

3 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGG)

4 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGGa)

5 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VV)

6 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VVa)

7 HON (40 CFR part 63, subpart H) existing source requirements 

8 HON (40 CFR part 63, subpart H) new source requirements 

9 MON (40 CFR part 63, subpart FFFF) existing source requirements

10 MON (40 CFR part 63, subpart FFFF) new source requirements

11 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements

12 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements

13 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements

14 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements

99 Other (specify) 

2

 Use the definitions of “gas service,” “light liquid service,” and “heavy liquid service” in the 

regulation to which your process unit is subject, if applicable. See the list of definitions for 

this ICR for definitions of these terms to use if your process unit is not subject to a regulation 

that includes definitions of these terms.

3

 The information requested for open-ended lines refers to leakage from the open-end of a pipe or 

valve and not to leakage from the associated valve packing or body flanges.

4

 Other equipment includes any other fugitive emissions source not already provided that is 

monitored similar to equipment. Specify the types of fugitive emission sources.

5

 Do not include difficult-to-monitor equipment in this count.

Deleted: from the following list of process unit 

types.¶

Code No. Type of Process Unit¶

1 Atmospheric crude distillation¶

2 Vacuum distillation¶

3 Delayed coking¶

4 Fluid coking (traditional)¶

5 Flexicoking¶

6 Visbreaking, other thermal cracking¶

7 Fluid catalytic cracking unit¶

8 Non-fluid catalytic cracking unit¶

9 Catalytic hydrocracking¶

10 Catalytic reforming unit – continuous 

regeneration¶

11 Catalytic reforming unit – cyclic regeneration¶

12 Catalytic reforming unit – semi-regenerative¶

13 Fuels solvent deasphalting¶

14 Desulfurization/ hydrotreat – naphtha/reformer 

feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet fuel¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – other¶

22 HF alkylation¶

23 H2SO4 alkylation¶

24 Aromatics production¶

25 Asphalt production¶

26 Isomerization – Isobutane¶

27 Isomerization – Iso C5,C6¶

28 Lubricants production ¶

29 Petroleum coke storage¶

30 Hydrogen plant¶

31 Sulfur plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

37 Marine vessel loading/unloading¶

38 Truck/tank truck loading/unloading¶

39 Rail car loading/unloading¶

50 Fuel gas system¶

51 Natural gas system¶

99 Other (specify)¶

¶

2

 Select 

Deleted: applicable

Deleted: 40 CFR part 60, subpart VV¶

4

Deleted: 5 40 CFR part 60, subpart VVa¶

6

Deleted: 3
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

29 

6

 Select from the following list of monitoring frequencies the option that best describes the 

frequency at which the majority of the equipment are monitored for the process unit, type of 

equipment, and type of service. (For “other,” if you specified multiple types of fugitive 

emission sources and they have different monitoring frequencies, select the shortest monitoring 

interval for such sources.)

Code No. Monitoring Frequency 

0 None (unit/system not monitored for leaks) 

1 No set interval (use only for sensory monitoring)

2 Less than annually 

3 Annually 

4 Semiannually 

5 Quarterly 

6 Monthly 

7 Biweekly 

8 Weekly or more frequently 

7

 Select from the following list of leak definitions the monitored concentration above which 

repairs are required (or routinely performed) for the process unit, type of equipment, and type 

of service. (For “other,” if you specified multiple types of fugitive emission sources and they 

have different leak definitions, select the lowest leak definition for such sources.)

Code No. Leak Definition 

0 None (unit/system not monitored for leaks) 

1 Detection by sensory monitoring

2 10,000 ppmv 

3 5,000 ppmv 

4 2,000 ppmv 

5 1,000 ppmv 

6 500 ppmv 

7 Less than 500 ppmv 

4. Complete Table 3-2 for each fuel gas and natural gas system at the facility. The 

equipment counts should be the total number of pieces of equipment the fuel gas and 

natural gas system at the facility (without double counting equipment included in Table 

3-1). You may provide reasonable estimates of equipment counts from existing 

information if the requested equipment counts are not directly available as requested for 

each fuel gas and natural gas system.

Deleted: applies

Deleted: equipment component, and 

Deleted: service.

Deleted: 1

Deleted: 2

Deleted: 3

Deleted: 4

Deleted: 5

Deleted: 6

Deleted: 7

Deleted: 4

Deleted: )

Deleted: component

Deleted: 2

Deleted: 3

Deleted: 4

Deleted: 5

Deleted: 6
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

30 

TABLE 3-2. Equipment and Leak Detection Information for Fuel Gas and Natural Gas Systems

Unit ID

Applicable Federal air regulation(s)

1

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s)

Average methane concentration in 

process fluid that contacts equipment 

in gas service throughout the process

Is the average methane concentration 

based on sampling and analysis 

results or estimated (e.g., based on 

process knowledge)?

For each of the following 

types of equipment, 

provide:

Pumps Valves Flanges Connectors

Open-ended lines

3

Compressors

Hatches

Sight glasses

Gages

Diaphragms

Other

4

Light liquid

2

Heavy liquid

2

Gas

2

Light liquid

2

Heavy liquid

2

Gas

2

Light liquid

2

Heavy liquid

2

Gas

2

Light liquid

2

Heavy liquid

2

Number of Pieces of 

Equipment

Number of Pieces of 

Equipment Monitored5

Monitoring Frequency6

Leak Definition (ppmv)7

Number of Pieces of 

Equipment

Number of Pieces of 

Equipment Monitored5

Monitoring Frequency6

Leak Definition (ppmv)7
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

31 

Footnotes for Table 3-2:

1

 Select the Federal air regulation to which the fuel gas or natural gas system is subject from the 

following list of regulations. Select all that apply, but include only regulations for equipment 

leaks to which the fuel gas or natural gas system is subject according to the applicability of the 

regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the 

fuel gas or natural gas system is subject).

Code No. Federal Air Regulation 

0 None

1 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGG)

2 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGGa)

3 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VV)

4 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VVa)

99 Other (specify)

2

 Use the definitions of “gas service,” “light liquid service,” and “heavy liquid service” in the 

regulation to which your process unit is subject, if applicable. See the list of definitions for 

this ICR for definitions of these terms to use if your process unit is not subject to a regulation 

that includes definitions of these terms.

3

 The information requested for open-ended lines refers to leakage from the open-end of a pipe or 

valve and not to leakage from the associated valve packing or body flanges.

4

 Other equipment includes any other fugitive emissions source not already provided that is 

monitored similar to equipment. Specify the types of fugitive emission sources.

5

 Do not include difficult-to-monitor equipment in this count.

6

 Select from the following list of monitoring frequencies the option that best applies for the fuel 

gas or natural gas system, type of equipment, and type of service. (For “other,” if you 

specified multiple types of fugitive emission sources and they have different monitoring 

frequencies, select the shortest monitoring interval for such sources.)

Code No. Monitoring Frequency

0 None (unit/system not monitored for leaks)

1 No set interval (use only for sensory monitoring)

2 Less than annually 

3 Annually

4 Semiannually

5 Quarterly

6 Monthly

7 Biweekly

8 Weekly or more frequently
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

32 

7

 Select from the following list of leak definitions the monitored concentration above which 

repairs are required (or routinely performed) for the process unit, type of equipment, and type 

of service. (For “other,” if you specified multiple types of fugitive emission sources and they 

have different leak definitions, select the lowest leak definition for such sources.)

Code No. Leak Definition

0 None (unit/system not monitored for leaks)

1 Detection by sensory monitoring

2 10,000 ppmv

3 5,000 ppmv

4 2,000 ppmv

5 1,000 ppmv

6 500 ppmv

7 Less than 500 ppmv
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

5. Provide the information requested in Table 3-3 regarding pressure relief devices (PRD) on each process unit listed in Part I, 

Question 16 (except wastewater treatment) and for each fuel gas and natural gas system at the facility. 

TABLE 3-

3. Pressure Relief Devices 

Unit ID, Fuel Gas 

System ID, or Natural 

Gas System ID

Total number of PRDNumber of PRD routed to fuel gas system or control device Atmospheric PRD Gas Liquid Gas Liquid

Numb

er of 

PRDof 

contro

Number of PRD

Type of controls1

Number of PRD

ed 

with 

ruptur

e disk Method 21 Monitoring for Leaks Monitoring of Releases

Number of PRD

Number equipped with rupture disk or 

second valve

Method 21 

Monitoring 

for Leaks

Moni

Number of PRD

Monitoring Frequency2

Leak Definition (ppmv)3

Number of PRD monitored 

using a system designed to 

measure the duration of a 

release and/or the quantity 

of compounds released 

Describe your monitoring

system

Number of PRD

Monitoring Frequency2

Leak Definition (ppmv)3

measure the duration of a Describe your monitoring
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 3-3: 

1

 Select from the following list of controls. List all that apply to PRD in the process unit, fuel 

gas system, or natural gas system.

Code No. Type of Control 

0 None 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

52 Carbon adsorber 

55 Flare 

61 Routed to fuel gas system

95 Management practice or work practice for VOC reduction (specify) 

99 Other (specify) 

2

 Select from the following list of Method 21 monitoring frequencies the option that best applies 

for the process unit, type of equipment, and type of service. Select “0” if the PRD are not 

monitored regularly on a set schedule (i.e., they are only monitored after a release to confirm 

that there are no detectable emissions).

Code No. Monitoring Frequency

0 None (unit/system not monitored for leaks using Method 21 (but may be monitored using 

sensory methods))

1 Less than annually 

2 Annually

3 Semiannually

4 Quarterly

5 Monthly

6 Biweekly

7 Weekly or more frequently

8 Only after releases

3

 Select from the following list of leak definitions the monitored concentration above which 

repairs are required (or routinely performed) for the process unit and type of service. Select 

“0” if the PRD are not monitored regularly on a set schedule (i.e., they are only monitored after 

a release to confirm that there are no detectable emissions).

Code No. Leak Definition

0 None (unit/system not monitored for leaks using Method 21 (but may be monitored using 

sensory methods))

1 10,000 ppmv

2 5,000 ppmv

3 2,000 ppmv

4 1,000 ppmv

5 500 ppmv

6 Less than 500 ppmv

Deleted: 2

Deleted: units.¶

Code No. Type of Process Unit¶

1 Atmospheric crude distillation¶

2 Vacuum distillation¶

3 Delayed coking¶

4 Fluid coking (traditional)¶

5 Flexicoking¶

6 Visbreaking, other thermal cracking¶

7 Fluid catalytic cracking 

Deleted: ¶

8 Non-fluid catalytic cracking unit¶

9 Catalytic hydrocracking¶

10 Catalytic reforming unit – continuous 

regeneration¶

11 Catalytic reforming unit – cyclic regeneration¶

12 Catalytic reforming unit – semi-regenerative¶

13 Fuels solvent deasphalting¶

14 Desulfurization/ hydrotreat – naphtha/reformer 

feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet

Deleted: ¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – other¶

22 HF alkylation¶

23 H2SO4 alkylation¶

24 Aromatics production¶

25 Asphalt production¶

26 Isomerization – Isobutane¶

27 Isomerization – Iso C5,C6¶

28 Lubricants production ¶

29 Petroleum coke storage¶

30 Hydrogen plant¶

31 Sulfur plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

37 Marine vessel loading/unloading¶

38 Truck/tank truck loading/unloading¶

39 Rail car loading/unloading¶

50 Fuel

Deleted: ¶

51 Natural

Deleted: 99 Other (specify)¶

¶

2

 Select from the following list of controls. List all 

that apply¶

Deleted: 53

Deleted: 98
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 4. STORAGE TANKS 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Does the facility receive unstabilized crude oil? Yes No

If Yes, provide the following information:

a. The quantity of unstabilized crude oil received in 2010: ______________ bbls

b. The pressure at which the unstabilized crude oil is received: __________ psia

3. Does the facility receive use methane to blanket any storage tanks? Yes No

If Yes, provide the quantity of methane used for storage tank blanketing:

____________________ MMscf at 60 °F and 1 atmosphere

4. Please provide information requested in Table 4-1 for each storage tank at the facility. 

TABLE 4-1. Storage Tank General Information 

Tank ID 

Type of stored liquid1

Maximum true vapor pressure of 

hydrocarbons in stored liquid in 2010 (psi) 

Temperature at which maximum true vapor 

pressure was calculated (°F)

Type of tank/controls2

Diameter (ft) 

Height (ft) 

Maximum liquid height (ft) 

Total throughput for all materials stored in 

the tank in 2010 (bbl) 

Is the tank a “drain-dry” tank? (Yes/No) 

Applicable Federal air regulation(s)

3

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s) 

Year in which the tank was last degassed 

Type of control for last degassing event4

Was the tank cleaned during last degassing 

event? (Yes/No) 

Year in which you anticipate the next 

degassing event5

For tanks with EFR or 

IFR

Type of primary rim seal6

Type of secondary rim seal7

Minimum height of floating roof above 

the floor at the shell when landed 

Number of times floating roof landed 

in 2010 

Number of times the tank was emptied 

after roof landed in 2010 

Deleted: c

Deleted: response

Deleted: 3. For each storage tank listed in Table 

4-1, also provide annual VOC and HAP emission 

estimates (tons/yr) following the methods provided 

in the Emission Estimation Protocol for Petroleum 

Refineries using the emissions template in Annex A 

of this part. ¶

Formatted Table

Deleted: 

Deleted: Vapor

Deleted: at average liquid storage temperature 

in 2009

Deleted: Average liquid storage temperature in 

2009 (°F)

Deleted: 9

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 3

Inserted Cells

Inserted Cells

Deleted: 

Deleted: 9

Deleted: 9

Inserted Cells

Inserted Cells

Deleted: ¶ ... [69]
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 4-1: 

1

 Report the type of liquid stored (or crude oil received) in the tank for the predominant use of 

the tank. Select from the following list of liquid types. 

Code No. Type of Stored Liquid 

1 Unstabilized crude oil 

2 Stabilized crude oil 

3 Ethane

4 Ethylene

5 Propane

6 Propylene

7 Normal Butane

8 Butylene

9 Isobutane

10 Isobutylene

11 Unfinished Oils – Naphthas and lighter

12 Unfinished Oils – Kerosene and light gas oils

13 Unfinished Oils – Heavy gas oils

14 Unfinished Oils – Residuum

15 Finished Motor Gasoline - Reformulated

16 Finished Motor Gasoline - Conventional

17 Motor Gasoline Blending Components - Reformulated

18 Motor Gasoline Blending Components - Conventional

19 Aviation Gasoline – Finished and Blending Components

20 Special Naphthas (solvents)

21 Kerosene-type Jet Fuel

22 Kerosene

23 Distillate Fuel Oil – 15 ppm sulfur and under

24 Distillate Fuel Oil – greater than 15 ppm to 500 ppm sulfur 

25 Distillate Fuel Oil – greater than 500 ppm sulfur

26 Residual Fuel Oil – less than 0.31% sulfur 

27 Residual Fuel Oil – 0.31% to 1.0% sulfur 

28 Residual Fuel Oil – greater than 1% sulfur

29 Lubricants (total)

30 Asphalt and Road Oil

31 Wax

32 Still Gas

33 Petrochemical Feedstocks – Naphtha <401°F end-point 

34 Petrochemical Feedstocks - Other Oils ≥401°F end-point 

35 Aromatics – Benzene 

36 Aromatics – Toluene

37 Aromatics – Xylenes (total)

38 Aromatics – Other than BTX

99 Other (specify) 

Deleted: 3 Intermediate naphtha¶

4 Intermediate distillate oil¶

Deleted: Intermediate heavy

Deleted: 6

Deleted: /blending stocks

Deleted: 7

Deleted: fuels

Deleted: 8 No. 2 diesel fuel¶

9 No. 4 diesel fuel (heavy fuel oil)¶

10 No. 6 diesel fuel (marine diesel/bunker C)¶

11 Lubricating/motor oil¶

12 Petroleum coke¶

13

Deleted: 14 Sulfur¶

15 Ethylene¶

16 LPG (propane/butane)¶

17

Deleted: 18

Deleted: petrochemicals (specify)
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2

 Report the type of tank and controls. Select from the following list of tank types and controls. 

See the list of definitions for this ICR for details on what is considered a controlled guidepole.

Code No. Type of Tank/Control 

1 Fixed roof tank vented to atmosphere 

2 Fixed roof tank vented to control device 

3 Fixed roof tank using vapor balancing 

4 External floating roof, slotted guidepoles 

5 External floating roof with solid guidepoles 

6 External floating roof, controlled guidepoles 

7 Internal floating roof, slotted guidepoles 

8 Internal floating roof with solid guidepoles 

9 Internal floating roof, controlled guidepoles 

10 External floating roof with geodesic dome roof 

11 Horizontal tank 

12 Pressurized/sphere tank 

99 Other (specify) 

3

 Select the Federal air regulation(s) to which the storage vessel is subject from the following list 

of regulations. Select all that apply, but include only regulations to which the storage vessel is 

subject according to the applicability of the regulation (i.e., do not select regulations that are 

referenced from the regulation(s) to which the storage vessel is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT (40 CFR part 63, subpart CC) new source requirements

3 HON (40 CFR part 63, subpart H) existing source requirements

4 HON (40 CFR part 63, subpart H) new source requirements

5 NSPS for Storage Vessels (40 CFR part 60, subpart K)

6 NSPS for Storage Vessels (40 CFR part 60, subpart Ka)

7 NSPS for Storage Vessels (40 CFR part 60, subpart Kb)

8 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements

9 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements

10 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements

11 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements

99 Other (specify)

4

 Report the type of control used for the most recent degassing event. Select from the following 

list of controls. 

Code No. Type of Degassing Control 

0 None; tank vented to atmosphere while being degassed 

54 Portable internal combustion engine 

55 Portable thermal oxidizer 

56 Portable condensation system 

57 Permanent onsite control device 

99 Other (specify) 

Deleted: a

Deleted: b

Deleted: c

Deleted: a

Deleted: b

Deleted: c

Deleted: a A guidepole that has slots or holes 

through the wall of the pole. The slots or holes 

allow the stored liquid to flow into the pole at liquid 

levels above the lowest operating level.¶

b

 A guidepole that has no slots or holes through the 

wall of the pole.¶

c

 Control measures described for storage tank 

emission reduction partnership program (STERPP) 

at 72 FR 19891.¶

¶
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

5

 Select the year in which you anticipate the next degassing event.

Code No. Year

0 2010

1 2011

2 2012

3 2013

4 2014

5 2015

6 2016

7 2017

8 2018

9 2019

10 2020 or later

6

 Select the type of primary rim seal.

Code No. Type of Rim Seal

0 None

1 Vapor-mounted seal; flexible wiper type

2 Vapor-mounted seal; resilient-filled type

3 Liquid-mounted seal

4 Mechanical-shoe seal

7

 Select the type of secondary rim seal.

Code No. Type of Rim Seal

0 None

1 Rim-mounted seal

2 Shoe-mounted seal

3 Vapor-mounted seal; flexible wiper type
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 5. CATALYTIC CRACKING UNIT 

 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide information requested in Table 5-1 for each catalytic cracking unit (CCU) 

at the facility. 

TABLE 5-2. Catalytic Cracking Unit Information 

Unit ID for CCU 

Fresh Feed Capacity (bbl/cd) 

Recycle /Resid Capacity (bbl/cd) 

Percent of CCU Feed that is 

Hydrotreated (%) 

Typical Coke Burn Rate at 

Capacity (tons/cd) 

Type of CCU (fluid, thermal, or 

other) 

Type of CCU Regenerator 

(complete, partial, or variable) 

Is there a CO boiler of other 

combustion device after CCU 

regenerator (Yes/No)? 

Applicable Federal air 

regulation(s)

1

If subject to State, local, or 

Tribal air regulation(s), provide 

the citation(s) 

2010 Weighted Average Sulfur

Concentration in Combined 

Feed (wt%)

2010 Weighted Average Nickel 

Concentration in Combined 

Feed (wt%) 

2010 Weighted Average 

Vanadium Concentration in 

Combined Feed (wt%) 

Type of PM controls2

Type of SO2 controls3

Type of NOX controls4

Footnotes for Table 5-2: 

1

 Select the Federal air regulation(s) to which the CCU is subject from the following list of 

regulations. Select all that apply, but include only regulations to which the CCU is subject 

according to the applicability of the regulation (i.e., do not select regulations that are 

referenced from the regulation(s) to which the CCU is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements

2 Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart J)

4 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

Deleted: c

Deleted: response

Deleted: If the facility has metal concentration for 

E-cat and/or fines, provide annual average values

Deleted: in the Table 5-1 below.

Deleted: TABLE 5-1. E-Cat and FCCU Fines 

Metal Concentration¶

CCU ID ... [70]

Formatted Table

Deleted: ID

Deleted: 

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Inserted Cells

Deleted: 

Deleted: 1

Deleted: 

Deleted: 2

Deleted: 

Deleted: 3
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2

 Select from the following list of PM controls; list all that apply. 

Code No. Type of PM Control 

0 None 

11 Fabric/cartridge filter (“baghouse”) 

12 Venturi/wet scrubber 

13 Electrostatic precipitator (ESP) 

14 Wet ESP 

15 Tertiary cyclone 

96 Management practice or work practice to reduce PM (specify) 

99 Other (specify) 

3

 Select from the following list of SO2 controls; list all that apply. 

Code No. Type of SO2 Control 

0 None 

24 Wet scrubber/flue gas desulfurization 

25 Spray dryer absorber 

26 DeSOx catalyst, meeting 50/25 ppmv SO2 limit 

27 DeSOx catalyst, meeting 20 lb/ton coke burn-off, but not 50/25 ppmv SO2 limit 

28 Low sulfur (0.3 wt% or less) feed 

97 Management practice or work practice to reduce SO2 (specify) 

99 Other (specify) 

4

 Select from the following list of NOX controls; list all that apply. 

Code No. Type of NOX Control 

0 None 

32 Staged air low NOX burner in CO boiler or other post-combustion device 

33 Staged fuel low NOX burner in CO boiler or other post-combustion device 

34 Ultra low NOX burner (high fraction staged fuel) (ULNB) in CO boiler or other postcombustion device 

35 “Next generation” low NOX burner (ULNB with internal gas recirculation)) in CO boiler 

or other post-combustion device 

36 Selective non-catalytic reduction (SNCR) 

37 Selective catalytic reduction (SCR) 

39 High-efficiency regenerator 

40 Low NOX combustion additives to replace Pt-based combustion additives 

41 Other low NOX catalyst additives 

42 LoTOX® scrubber 

98 Management practice or work practice to reduce NOX (specify) 

99 Other (specify) 

Deleted: 98

Deleted: 2

Deleted: 98

Deleted: 3
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

3. If the facility has metal concentration for E-cat and/or fines, provide annual average 

values for each CCU at the facility in the Table 5-2 below. 

TABLE 5-2. E-Cat and CCU Fines Metal Concentration

Unit ID for CCU

Particle Type

Concentration (parts per million by weight, ppmw)

Antimony

Arsenic

BerylliumCadmium

Chromium

Cobalt

Lead

Manganese

Mercury

Nickel

Selenium

Vanadium

E-cat

Fines

E-cat

Fines

E-cat

Fines

E-cat

Fines
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 6. FLUID COKING UNIT 

1. Facility ID number (EPA will provide this number): ______________________ 

 2. Please provide information requested in Table 6-1 for each fluid coking unit (FCU) at the 

facility. 

TABLE 6-1. Fluid Coking Unit Information 

Unit ID for FCU 

Feed Capacity (bbl/cd) 

Type of FCU (traditional or 

flexicoker) 

Applicable Federal air regulation(s)

1

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s) 

If traditional coker If flexicoker 

Coke Production Capacity 

(tons/cd) 

Typical Coke Burn Rate at 

Capacity (tons/cd) 

Is there a CO boiler or other 

combustion device after FCU 

regenerator (Yes/No)? 

Type of PM controls2

Type of SO2 controls3

Type of NOX controls4

Produced Coke Handling 

Controls and Disposition5

Low Btu gas production rate at 

capacity (scfm) 

Low Btu gas sulfur removal 

technique6

FCU dust/ash quantity 

produced (tons/cd) 

FCU dust/ash handling/disposal 

method7

Footnotes for Table 6-1: 

1

 Select the Federal regulation(s) to which the FCU is subject from the following list of 

regulations. Select all that apply, but include only regulations to which the FCU is subject 

according to the applicability of the regulation (i.e., do not select regulations that are 

referenced from the regulation(s) to which the FCU is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

Deleted: c

Deleted: response

Deleted: 3. For each FCU listed in Table 6-1, 

also provide criteria pollutant and HAP emission 

estimates (tons/yr) following the methods provided 

in the Emission Estimation Protocol for Petroleum 

Refineries using the emissions template in Annex A 

of this part. ¶

Formatted Table

Deleted: ID

Deleted: 

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 

Deleted: 1

Deleted: 

Deleted: 2

Deleted: 

Deleted: 3

Deleted: 4

Deleted: 

Deleted: 5

Deleted: 6
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2

 Select from the following list of PM controls; list all that apply. 

Code No. Type of PM Control 

0 None 

11 Fabric/cartridge filter (“baghouse”) 

12 Venturi/wet scrubber 

13 Electrostatic precipitator (ESP) 

14 Wet ESP 

15 Tertiary cyclone 

96 Management practice or work practice to reduce PM (specify) 

99 Other (specify) 

3

 Select from the following list of SO2 controls; list all that apply. 

Code No. Type of SO2 Control 

0 None 

24 Wet scrubber/flue gas desulfurization 

25 Spray dryer absorber 

28 Low sulfur (0.3 wt% or less) feed 

97 Management practice or work practice to reduce SO2 (specify) 

99 Other (specify) 

4

 Select from the following list of NOX controls; list all that apply. 

Code No. Type of NOX Control 

0 None 

32 Staged air low NOX burner in CO boiler or other post-combustion device 

33 Staged fuel low NOX burner in CO boiler or other post-combustion device 

34 Ultra low NOX burner (high fraction staged fuel) (ULNB) in CO boiler or other postcombustion device 

35 “Next generation” low NOX burner (ULNB with internal gas recirculation)) in CO boiler 

or other post-combustion device 

36 Selective non-catalytic reduction (SNCR) 

37 Selective catalytic reduction (SCR) 

39 High-efficiency regenerator 

40 Low NOX combustion additives to replace Pt-based combustion additives 

41 Other low NOX catalyst additives 

42 LoTOX® scrubber 

98 Management practice or work practice to reduce NOX (specify) 

99 Other (specify) 

Deleted: 98

Deleted: 2

Deleted: 98

Deleted: 3
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

5

 Select from the following list the combination that best describes the coke handling and 

disposition method. For example, select 5E if you use the coke on-site in coke calciner and 

you use an enclosed conveyor to a storage bin with walls (wind breaks) and you wet the coke 

to suppress fugitive dust emissions. 

Code No. Disposition Code Letter Storage/Handling Method 

1 Shipped off-site to coke calciner A Enclosed conveyer to silo for 

loading/processing 

2 Shipped off-site to be used as fuel B Open conveyer to silo for 

loading/processing 

3 Shipped off-site: some to coke 

calciner and some as fuel 

C Enclosed conveyer to open storage pile 

or bin, wind break only 

4 Shipped off-site: other or unknown 

use 

D Enclosed conveyer to open storage pile 

or bin, wetting only 

5 Processed in on-site coke calciner E Enclosed conveyer to open storage pile 

or bin, wind break and wetting 

6 Used on-site as fuel F Open conveyance to open storage pile or 

bin, wind break only 

7 Some used on-site as fuel, 

remainder sent off-site to coke 

calciner 

G Open conveyance to open storage pile or 

bin, wetting only 

8 Some used on-site as fuel, 

remainder sent off-site for use as 

fuel 

H Open conveyance to open storage pile or 

bin, wind break and wetting 

99 Other (specify) Z Other (specify) 

6

 Select from the following list of low Btu gas sulfur controls. 

Code No. Low Btu Gas Sulfur Control 

0 None 

1 Conventional amine scrubber (e.g., MEA, MDEA) 

2 Sterically-hindered amine scrubber (e.g., Flexsorb®) 

3 Selexol® 

4 Rectisol® 

5 COS hydrolysis + conventional amine scrubber 

6 COS hydrolysis + sterically-hindered amine scrubber 

7 COS hydrolysis + Selexol® 

8 COS hydrolysis + Rectisol® 

9 Sulfinol®

98 Management practice or work practice (specify) 

99 Other (specify) 

Deleted: 4

Deleted: 5

Deleted: DMEA

Deleted: FLEXSORB
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

7

 Select from the following list the method that best describes the flexicoking dust/ash handling 

and disposal method. 

Code No. Flexicoking Dust/Ash Handling and Disposal Methods 

1 Used on-site as fuel 

2 Disposed of in on-site landfill 

3 Disposed of in off-site landfill 

4 Shipped off-site for use as fuel 

5 Shipped off-site for metals recovery 

99 Other (specify) 

Deleted: 6

Deleted: of

Deleted: s
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 7. DELAYED COKING UNIT 

 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide information requested in Table 7-1 for each delayed coking unit (DCU) at 

the facility. For purposes of this information collection, a DCU consists of all drums 

connected to a single fractionator and the fractionator. 

TABLE 7-1. Delayed Coking Unit Operating Information 

f

c

it

a

Type of Coke Produced1

C

e 

g

l

r

u

s

t 

mW Water Height in Coke Drum When First Vented to 

Atmosphere (ft)

Cycle Time Quench 

W t

Applicable Federal air regulation(s)7 If subject to State, local, or Tribal air regulation(s),

id h i i ( )

Complete Coke Drum Cycle Time (hr)2

Coke Drum Feed Cycle Time (hr) 

Coke Drum Steam Purge Time (hr) 

Coke Drum Water Quenching Time (hr) 

Coke Drum Depressurization Vent Time (hr) 

Coke Drum Coke Cutting Time (hr) 

Coke Drum Preheat/Standby Time (hr) 

Water Quenching Cycle Description3

Typical Quench Water Flow Rate during 

Quenching Cycle (gal/min) 

Average Quench Water Make-up Rate (gal/day) 

Purged Steam Blowdown System Description4 Quench Water

Disposition5

C tti W t St /H dli 6

 

Deleted: c

Deleted: response

Deleted: 3. For each DCU listed in Table 7-1, 

also provide criteria pollutant and HAP emission 

estimates (tons/yr) following the methods provided 

in the Emission Estimation Protocol for Petroleum 

Refineries using the emissions template in Annex A 

of this part. ¶

Moved (insertion) [1]

Moved (insertion) [2]

Deleted: DCU ID

Merged Cells

Deleted: Feed Capacity (bbl/cd)

Merged Cells

Deleted: Coke Production Capacity (tons/cd)

Merged Cells

Moved up [1]: Number of Coke Drums

Merged Cells

Deleted: Height of Single Coke Drum (ft)

Merged Cells

Deleted: Diameter of Single Coke Drum (ft)

Merged Cells

Deleted: Typical Coke Drum Outage (ft)

Merged Cells

Deleted: If subject to Federal regulation(s), 

provide the citation(s)

Merged Cells

Deleted: If subject to State, local, or Tribal 

regulation(s), provide the citation(s)

Merged Cells

Deleted: 1

Deleted: Coke Drum Pressure When First 

Vented to Atmosphere (psig)

Deleted Cells

Deleted: Coke Drum Temperature at Top of 

Drum When First Vented to Atmosphere (°F)

Deleted Cells

Moved up [2]: Water Height in Coke Drum 

When First Vented to Atmosphere (ft)

Deleted Cells

Deleted: 2

Deleted: 3

Inserted Cells

Deleted: 4
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 7-1: 

1

 Select from the following list of produced coke types. 

Code No. Quench Water Source

1 Needle coke, anode grade

2 Needle coke, fuel grade

3 Sponge coke, anode grade

4 Sponge coke, fuel grade

5 Shot coke, anode grade

6 Shot coke, fuel grade

99 Other (specify)

2

 Complete coke drum cycle time is from the start of one feed cycle to the start of the next feed 

cycle for a single drum and should equal feed time + steam time + cooling time + venting time 

+ cutting time + preheat/standby time. 

3

 Select from the following list of water quenching cycle descriptions. 

Code No. Quench Water Source 

1 Use “tap” water (i.e., water purchased directly from utility or drinking water) 

2 Use process or recycled blowdown water 

3 Use recycled cutting water with “tap” water make-up 

4 Use recycled cutting water with process or blowdown water make-up 

5 Use treated water from sour water stripper 

6 Use treated water from wastewater treatment system 

99 Other (specify) 

Deleted: ¶ 2
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

4

 Select from the following list of blowdown system descriptions used to manage the steam 

exhausted during the steam purge and water quench cycles (prior to venting the vessel to 

atmosphere). 

Code No. Condensed Water Disposition Code Letter

Uncondensed Vapor Disposition 

When Not Sent Directly to DCU 

Fractionator 

1 Sent to wastewater treatment 

system 

A Not applicable; uncondensed vapors are 

always sent to DCU fractionator 

2 Sent to sour water stripper B Uncondensed vapors are sent to 

dedicated DCU flare 

3 Used to make steam C Uncondensed vapors are sent to flare 

header system to general facility flare 

4 Recycled to unit and used as 

quench water 

D Uncondensed vapors are sent to flare gas 

recovery system 

5 Used as coke cutting water E Uncondensed vapors are always sent 

directly to process heater or boiler 

6 Used as general process water F Uncondensed vapors are always sent 

directly to amine treatment unit or fuel 

gas system 

99 Other (specify) G Uncondensed vapors are controlled by 

oil scrubber or lean oil absorber prior to 

venting to atmosphere 

 H Uncondensed vapors are vented directly 

to atmosphere 

 Z Other (specify) 

5

 Select from the following list of quench water disposition (referring to water drained from the 

drum after the vessel is vented to the atmosphere). 

Code No. Quench Water Disposition

1 Sent to wastewater treatment system

2 Sent to sour water stripper

3 Used to make steam

4 Recycled to unit and used as quench water

5 Used as coke cutting water

6 Used as general process water

99 Other (specify)

Deleted: 3

Deleted: s

Deleted: 4
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

6

 Select from the following list of cutting water storage/handling method combinations. 

Code No. Cutting Water Source Code Letter Cutting Water Storage/Handling 

1 Use “tap” water A Uncovered gravity settling pond 

2 Use process or blowdown 

water 

B Covered gravity settling pond/tank 

3 Use recycled cutting water with 

“tap” water make-up 

C Mechanical filtration (e.g., centrifugal, 

filter press) to open storage tank or pond

4 Use recycled cutting water with 

process or blowdown water 

make-up 

D Mechanical filtration (e.g., centrifugal, 

filter press) to covered storage tank or 

pond 

5 Use treated water from sour 

water stripper 

E Directed to sour water stripper 

6 Use treated water from 

wastewater treatment system 

F Directed to wastewater treatment system

99 Other (specify) Z Other (specify) 

7 Select the Federal air regulation(s) to which the DCU is subject from the following list of 

regulations. Select all that apply, but include only regulations to which the DCU is subject 

according to the applicability of the regulation (i.e., do not select regulations that are 

referenced from the regulation(s) to which the DCU is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

3. Provide typical and maximum feed composition in Table 7-2 for each DCU at the 

facility. You may list Unit ID numbers for multiple DCU in a single column if the DCU 

have similar feed compositions. If the DCU at the facility have different feed 

compositions, provide the typical and maximum feed compositions separately for each 

set of similar DCU. 

TABLE 7-2. Delayed Coking Unit Feed Information 

Feed Source 

DCU ID(s): ____________ DCU ID(s): ____________ 

Typical 

% Feed1

Maximum 

% Feed2

Typical 

% Feed1

Maximum 

% Feed2

Atmospheric tower bottoms 

Heavy gas oil 

Vacuum tower bottoms 

Other residual gas oil 

Recovered materials 

- Recovered oil (e.g., slop oil) 

- Sludges from crude oil storage tanks 

- Sludges from other storage tanks 

- Biosolids from wastewater treatment 

system 

- Other sludges from wastewater 

treatment system 

Other (specify): ____________ 

Footnotes for Table 7-2: 

1

 Typical or average feed composition for DCU. The sum of all values in this column should be 

100%. 

2

 Maximum percent of each feed source that can be used in the DCU. The sum of all values in 

this column is expected to exceed 100%. 

Deleted: 4

Deleted: IDs
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 8. CATALYTIC REFORMING UNIT 

1. Facility ID number (EPA will provide this number): ______________________ 

 2. Please provide information requested in Table 8-1 for each catalytic reforming unit 

(CRU) at the facility. 

TABLE 8-1. Catalytic Reforming Unit Information 

Unit ID for CRU 

Feed Capacity (bbl/cd) 

Operating Pressure (psig)

Hydrogen Production Rate (purified 

basis) (MMscf/cd at 0°C and 1 atm) 

Type of CRU Regeneration 

(continuous, cyclic, or 

semi-regenerative) 

Applicable Federal air regulation(s)

1

If subject to State, local, or Tribal 

air regulation(s), provide the 

citation(s) 

Average Annual Regeneration 

Frequency (cyclic and semi-regen 

units; regeneration cycles/year)2

Average Annual Regeneration Time 

(hours/year)2

Depressurization /Purge Cycle Vent 

Disposition/control3

Purge Process Type4

Coke Burn-off Cycle Vent 

Disposition/control5

Coke Burn-off Cycle Duration per 

Cycle 

Rejuvenation Cycle Vent 

Disposition/control6

Reduction or Activation Cycle Vent 

Di i i / l7 Chloriding Agent8

 

Deleted: c

Deleted: response

Deleted: 3. For each CRU listed in Table 8-1, 

also provide criteria pollutant and HAP emission 

estimates (tons/yr) following the methods provided 

in the Emission Estimation Protocol for Petroleum 

Refineries using the emissions template in Annex A 

of this part. ¶

Deleted: ID

Deleted: 

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: Average Annual Regeneration Time 

(hours/year)

Deleted Cells

Inserted Cells

Deleted: 1

Deleted: 2

Deleted: 3

Deleted: 4

Inserted Cells

Deleted: 5
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 8-1: 

1 Select the Federal air regulation(s) to which the CRU is subject from the following list of 

regulations. Select all that apply, but include only regulations to which the CRU is subject 

according to the applicability of the regulation (i.e., do not select regulations that are 

referenced from the regulation(s) to which the CRU is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements

2 Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements

99 Other (specify)

2

 If the unit does not regenerate catalyst at least once a year, estimate the number of cycles based 

on the interval between cycles. If the interval between cycles varies, you may use the interval 

between the two most recent cycles. For example, if regeneration occurs once every two years, 

then the number of cycles per year would be 1 cycle ÷ 2 years = 0.5 cycles per year. The 

number of hours per year may be estimated by multiplying an average number of hours per 

cycle by the calculated number of cycles per year.

3 Select from the following list of purge controls. 

Code No. Type of Depressurization/Purge Control 

0 Directly to the atmosphere

1 To fuel gas system, then atmosphere 

2 To fuel gas system, then flare, then atmosphere 

3 To flare, then atmosphere 

4 To process heater or boiler, then atmosphere 

95 Management practice or work practice to reduce VOC (specify)

99 Other (specify) 

4

 Select from the following list of purge processes. 

Code No. Type of Purge Process 

1 Purge by sequential pressurizing/purging with nitrogen 

2 Purge using nitrogen and vacuum pump 

3 Purge by sequential pressurizing/purging with methane 

4 Purge using methane and vacuum pump 

99 Other (specify) 

Deleted: 2
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

5

 Select from the following list of coke burn-off controls. 

Code No. Type of Coke Burn-off Control 

1 None 

2 Caustic spray injection 

3 Packed-bed wet scrubber 

4 Tray tower wet scrubber 

5 ChlorsorbTM

94 Management practice or work practice to reduce HCl or chlorine releases (specify)

95 Management practice or work practice to reduce VOC (specify)

96 Management practice or work practice to reduce PM (specify) 

99 Other (specify) 

6

 Select from the following list of rejuvenation controls. 

Code No. Type of Rejuvenation Controls 

0 Directly to the atmosphere

1 To fuel gas system, then atmosphere

2 To fuel gas system, then flare, then atmosphere

3 To flare, then atmosphere

4 To process heater or boiler, then atmosphere

94 Management practice or work practice to reduce HCl or chlorine releases (specify) 

95 Management practice or work practice to reduce VOC (specify)

99 Other (specify) 

7

 Select from the following list of reduction or activation controls.

Code No. Type of Reduction or Activation Controls

0 Directly to the atmosphere

1 To fuel gas system, then atmosphere

2 To fuel gas system, then flare, then atmosphere

3 To flare, then atmosphere

4 To process heater or boiler, then atmosphere

94 Management practice or work practice to reduce HCl or chlorine releases (specify)

95 Management practice or work practice to reduce VOC (specify)

99 Other (specify)

8

 Select from the following list of chloriding agents. 

Code No. Type of Chloriding Agent 

1 Perchloroethylene 

2 Trichloroethene 

99 Other (specify) 

Deleted: 3

Deleted: 98

Deleted: 4

Deleted: 1 Purge by sequential 

pressurizing/purging with nitrogen¶

2 Purge using nitrogen and vacuum pump¶

98

Deleted: 5
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 9. SULFUR RECOVERY UNIT 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide information requested in Table 9-1 for each sulfur recovery unit (SRU) at 

the facility. 

TABLE 9-1. Sulfur Recovery Unit Information 

Unit ID for SRU 

Sulfur, Sulfur Cake or H2SO4

Production Capacity (long tons 

of sulfur/cd) 

Type of SRU1

Sulfur Recovery Plant (SRP) ID2

Applicable Federal air 

regulation(s)

3

If subject to State, local, or 

Tribal air regulation(s), provide 

the citation(s) 

Type of Tail Gas Treatment 

Unit4

Primary Sulfur Pit Controls 

Primary Sulfur Pit Maintenance 

Time in 2010 (hr/yr) 

SRU Back-up 

Controls/Reduction Measures5

Deleted: c

Deleted: response

Deleted: 3. For each SRU listed in Table 9-1, 

also provide criteria pollutant and HAP emission 

estimates (tons/yr) following the methods provided 

in the Emission Estimation Protocol for Petroleum 

Refineries using the emissions template in Annex A 

of this part. ¶

Formatted Table

Deleted: ID

Deleted: 

Deleted: 

Deleted: 

Inserted Cells

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 2

Deleted: 3
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 9-1: 

1

 Select from the following list of sulfur recovery units. 

Code No. Type of Sulfur Recovery Unit 

1 2-stage Claus 

2 3-stage Claus 

3 4-stage Claus 

4 SuperClaus® 

5 EuroClaus® 

6 SubDewPoint MCRC-SuperClaus® 

7 LoCat® 

8 Caustic scrubber 

9 Sulfuric acid plant 

99 Other (specify) 

2

 For purposes of this collection, multiple SRU are considered part of a single SRP when the 

units share the same source of sour gas. Sulfur recovery units that receive source gas from 

completely segregated sour gas treatment systems are considered part of separate SRP.

3

 Select the Federal air regulation(s) to which the SRU is subject from the following list of 

regulations. Select all that apply, but include only regulations to which the SRU is subject 

according to the applicability of the regulation (i.e., do not select regulations that are 

referenced from the regulation(s) to which the SRU is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements

2 Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart J)

4 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

4

 Select from the following list of tail gas treatment processes used during normal operation of 

the unit. List all that apply. 

Code No. Type of Tail Gas Treatment Unit 

0 None 

1 Incinerator 

2 Flare 

3 SCOT unit 

4 Beavon/amine 

5 Beavon/Stretford 

6 Cansolv® 

7 LoCat® 

8 Wellman-Lord 

99 Other (specify) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

5

 Select from the following list of SRU back-up measures. 

Code No. Type of SRU Back-up Control 

0 None 

1 Dedicated SRU flare 

2 General plant flare 

3 Divert to other SRU 

4 Sulfur shedding (reduce production of high sulfur fuel gas) 

98 Management practice or work practice (specify) 

99 Other (specify) 

Deleted: 3
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 10. HYDROGEN PLANT VENT 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide information requested in Table 10-1 for each hydrogen plant at the 

facility. 

TABLE 10-1. Hydrogen Plant and Vent Information 

Unit ID for Hydrogen Plant 

Hydrogen Production Capacity 

(purified basis) (MMscf/cd at 

0°C and 1 atm) 

Type of Hydrogen Production 

Unit1

Applicable Federal air 

regulation(s)

2

If subject to State, local, or 

Tribal air regulation(s), 

provide the citation(s) 

Hydrogen Purification Method 

Used3

Type of Feedstock Used4

Steam Generation Rate (lb/hr) 

PSA Purge/Off Gas Flow Rate 

(scfm) 

PSA Purge/Off Gas 

Disposition5

Reformer Deaerator Vent Flow 

Rate (scfm) 

Other Atmospheric Vent 

(Yes/No)? (If yes, report in 

Table 11-1) 

 

Footnotes for Table 10-1: 

1

 Select from the following list of hydrogen production units. 

Code No. Type of Hydrogen Production Unit 

1 Steam-methane reforming 

2 Partial oxidation 

3 Electrolysis 

4 Gasification 

99 Other (specify) 

Deleted: c

Deleted: response

Deleted: 3. For each hydrogen plant listed in 

Table 10-1, also provide criteria pollutant and HAP 

emission estimates (tons/yr) following the methods 

provided in the Emission Estimation Protocol for 

Petroleum Refineries using the emissions template in 

Annex A of this part. ¶

Formatted Table

Deleted: ID

Deleted: 

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 2

Deleted: 

Deleted: 3

Deleted: 4
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2

 Select the Federal air regulation(s) to which the hydrogen plant is subject from the following 

list of regulations. Select all that apply, but include only regulations to which the hydrogen 

plant is subject according to the applicability of the regulation (i.e., do not select regulations 

that are referenced from the regulation(s) to which the hydrogen plant is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

99 Other (specify)

3

 Select from the following list of hydrogen purification processes. 

Code No. Type of Hydrogen Purification Process 

1 Pressure-swing adsorption 

2 Membrane separation 

3 Cryogenic separation 

99 Other (specify) 

4

 Select from the following list of feedstocks. 

Code No. Type of Hydrogen Production Unit Feedstock 

1 Methane 

2 Refinery fuel gas 

3 Refinery fuel gas augmented with additional methane 

99 Other (specify) 

5

 Select from the following list of dispositions for the PSA Purge/Off Gas. 

Code No. Disposition of the PSA Purge/Off Gas 

1 Used as fuel in the reformer furnace 

2 Used as fuel elsewhere in the refinery 

3 Sent to flare 

4 Vented to atmosphere 

99 Other (specify) 

Deleted: 3

Deleted: 4
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 11. OTHER ATMOSPHERIC VENTS 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide information requested in Table 11-1 for each “other atmospheric vent” at 

the facility. “Other atmospheric vents” include any continuous or intermittent process 

vents located at the facility and under common control other than those vents specifically 

covered in Sections 5 through 10 of this part (Part II) vents associated with process heater 

or boiler exhausts, and wastewater vents. “Other atmospheric vents” include distillation 

tower vents; blowdown systems vents, knock-out pot vents, vacuum ejectors (hot well 

vents), analyzer vents as well as vents from MeroxTM treatment systems, fuel gas 

treatment units (if any), catalytic hydrocracking units (if any), asphalt blowing stills, and

coke calcining units. The focus of this section is primarily on vents directed directly to 

the atmosphere during normal operation, and vents recycled to process units, vents 

directed to a fuel gas system, or vents directed to a flare are not considered “other 

atmospheric vents”. Also, “other atmospheric vents” do not include pressure relief vents 

where venting occurs only during upset, startup, or shutdown events or vents associated 

with storage tanks. 

TABLE 11-1. Other Atmospheric Vent Information 

Atmospheric Vent 

ID 

Type of 

Atmospheric Vent1

Unit ID (if 

applicable) with 

which the Vent is 

Associated2

Applicable Federal 

air regulation(s)

3

If subject to State, 

local, or Tribal air 

regulation(s), 

provide the 

citation(s) 

Atmospheric Vent 

Operating Hours4

Atmospheric Vent 

Controls5

Deleted: c

Deleted: response

Deleted: on

Deleted: pots

Deleted: , and sampling systems

Deleted: oxygenate production

Deleted: ,

Deleted: , ethylene production units, and other 

Deleted: co-located at the facility. “Other 

Deleted: ” 

Deleted: vents associated with storage tanks or 

Deleted: . For “other atmospheric vents” 

controlled by flares, also complete Table 12-1 to 

describe the flare.

Deleted: 3. For each “other atmospheric vent” 

listed in Table 11-1 (except for vents controlled by a 

flare), also provide criteria pollutant and HAP 

emission estimates (tons/yr) following the methods 

provided in the Emission Estimation Protocol for 

Petroleum Refineries using the emissions template in 

Annex A of this part. Report the criteria pollutant 

and HAP emission estimates (tons/yr) from vents 

controlled by a flare as emissions from the flare 

following the methods provided in the Emission 

Estimation Protocol for Petroleum Refineries using 

the emissions template in Annex A of this part.¶

Formatted Table

Deleted: Description

Deleted: Type of 

Deleted: /Equipment to Which

Deleted: 1

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 2

Deleted: 3
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 11-1: 

1

 Select from the following list of processes and equipment the option that best describes the type 

of unit or equipment associated with this vent. 

Code No. Type of Other Atmospheric Vent 

1 Atmospheric crude distillation column/reflux condenser vent

2 Catalytic cracking unit distillation column/reflux condenser vent

3 Catalytic hydrocracking unit distillation column/reflux condenser vent

4 Catalytic reforming unit distillation column/reflux condenser vent

5 Coking unit distillation column/reflux condenser vent

6 Other distillation column/reflux condenser vent

7 Vacuum distillation column vacuum system exhaust vent

8 Hot well vent/vacuum jet exhaust

9 Other vacuum system exhaust

10 Drier regeneration vent

11 Coke calcining vent

12 Asphalt blowing still vent

13 Blow down system vent

14 Knock-out pot vent

15 Analyzer vent

16 Process tank (including surge control vessels, bottoms receivers, etc.)

99 Other (specify) 

2

 Enter the Unit ID associated with the vent only if the vent is associated with only one process 

unit. If the vent is in general use or used by multiple process units, leave this question blank. 

(Any further detail you wish to provide may be included in the “Notes” to this form.

3

 Select the Federal air regulation(s) to which the “other atmospheric vent” is subject from the 

following list of regulations. Select all that apply, but include only regulations to which the 

vent is subject according to the applicability of the regulation (i.e., do not select regulations 

that are referenced from the regulation(s) to which the vent is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart J)

4 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

Deleted: Unit/Equipment Associated with 

Deleted: Vacuum distillation¶

3 Delayed coking¶

4 Fluid coking (traditional)¶

5 Flexicoking¶

6 Visbreaking, other thermal cracking¶

7 Fluid catalytic 

Deleted: 8 Non-fluid catalytic cracking unit¶

9

Deleted: 10

Deleted: – continuous regeneration

Deleted: 11 Catalytic reforming unit – cyclic 

regeneration¶

12 Catalytic reforming unit – semi-regenerative¶

13 Fuels solvent deasphalting¶

14 Desulfurization/ hydrotreat – naphtha/reformer 

feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet fuel¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – other¶

22 HF alkylation¶

23 H2SO4 alkylation¶

24 Aromatics production¶

25 Asphalt production¶

26 Isomerization – Isobutane¶

27 Isomerization – Iso C5,C6 ¶

28 Lubricants production ¶

29 Petroleum coke storage¶

30 Hydrogen plant¶

31 Sulfur plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

37 Marine vessel loading/unloading¶

38 Truck/tank truck loading/unloading¶

39 Rail car loading/unloading¶

40 Blow down system¶

41 Knock-out pot¶

42 Analyzer¶

43

Deleted: jet

Deleted: 50 Wastewater treatment unit¶

51 Wastewater collection system (drain, junction 

box, etc.)¶

52 Soil remediation¶

60 Ethylene production¶

61 Ethylene dichloride production¶

62 Ethylene dibromide production¶

64 Propylene production¶

65 Acrylonitrile production¶

69 Other petrochemical or organic chemical 

production (specify chemical)¶

70
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

4

 Select from the following list of operating scenarios. 

Code No. Type of Operation 

1 Continuous (operates whenever the process is operating) 

2 Intermittent; 4,000 hours per year or more 

3 Intermittent; 2,000 hours or more but less than 4,000 hours per year 

4 Intermittent; 1,000 hours or more but less than 2,000 hours per year 

5 Intermittent; less than 1,000 hours per year 

5

 Select from the following list of control devices. List all that apply. 

Code No. Type of Control Device 

0 None 

11 Fabric/cartridge filter (“baghouse”) 

12 Venturi/wet scrubber 

13 Electrostatic precipitator (ESP) 

14 Wet ESP 

24 Wet scrubber/flue gas desulfurization 

36 Selective non-catalytic reduction (SNCR) 

37 Selective catalytic reduction (SCR) 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

52 Carbon adsorber 

95 Management practice or work practice to reduce VOC (specify)

96 Management practice or work practice to reduce PM (specify)

97 Management practice or work practice to reduce SO2 (specify)

98 Management practice or work practice to reduce NOX (specify) 

99 Other (specify) 

Deleted: 6 Only during startup or shutdown¶

7 Only during upsets¶

8 Only during startup, shutdown, or upsets¶

¶

3

Deleted: 53 Flare¶
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 12. FLARES 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide information requested in Table 12-1 for each flare at the facility. 

TABLE 12-1. Flare Information 

Flare ID Number or 

Description 

If the flare is dedicated to 

one processing unit, enter 

the Unit ID

Flare Diameter (ft) 

Flare release height (ft) 

Flare Location (Latitude) 

Flare Location (Longitude) 

Type of Flare1

Flare Assist Type2

Target Assist Ratio (if 

applicable) 

Type of Flare Pilot or 

Ignition System3

Applicable Federal air 

regulation(s)

4

If subject to State, local, or 

Tribal air regulation(s), 

provide the citation(s) 

Typical Lower Heating 

Value of Waste Gas 

(Btu/scf @ 60°F) 

Flare Operating Hours5

Flare Management Plan6

Flare Reduction Measures7

Deleted: c

Deleted: response

Deleted: 3. For each flare listed in Table 12-1, 

also provide criteria pollutant and HAP emission 

estimates (tons/yr) following the methods provided 

in the Emission Estimation Protocol for Petroleum 

Refineries using the emissions template in Annex A 

of this part.¶

Formatted Table

Inserted Cells

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 4

Deleted: Controls5

Inserted Cells
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 12-1: 

1

 Select from the following list of flares. 

Code No. Type of Flare 

1 Elevated flare 

2 Elevated flare, pressure assisted 

3 Ground level flare 

4 Ground level flare, pressure assisted 

99 Other (specify) 

2

 Select from the following list of flare assist types. 

Code No. Flare Assist Types 

1 Unassisted 

2 Steam assisted 

3 Air assisted 

99 Other (specify) 

3

 Select from the following list of flare pilot or ignition systems. 

Code No. Type of Flare Pilot or Ignition System 

1 Continuous pilot flame 

2 Spark ignition, every minute regardless of flow 

3 Spark ignition, triggered by flow sensor/monitor 

99 Other (specify) 

4 Select the Federal air regulation(s) to which the flare is subject from the following list of 

regulations. Select all that apply, but include only regulations to which the flare is subject 

according to the applicability of the regulation (i.e., do not select regulations that are 

referenced from the regulation(s) to which the flare is subject).

Code No. Federal Air Regulation 

0 None

1 General Provisions (40 CFR part 60, subpart A)

2 General Provisions (40 CFR part 63, subpart A)

3 Refinery NSPS (40 CFR part 60, subpart J)

4 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

5 Select from the following list of operating scenarios the option that best describes the operation 

of the flare. 

Code No. Type of Operation 

1 Combusts flare gas 4,000 hours per year or more 

2 Combusts flare gas 2,000 hours or more but less than 4,000 hours per year 

3 Combusts flare gas1,000 hours or more but less than 2,000 hours per year 

4 Combusts flare gas less than 1,000 hours per year 

5 Combusts flare gas only during startup or shutdown 

6 Combusts flare gas only during upsets 

7 Combusts flare gas only during startup, shutdown, or upsets 

6 Select from the following list of components of flare management plans the option that best 

describes the scope of the flare management for the flare; list all that apply.

Code No. Components of Flare Management Plan

0 Not applicable. Do not have a flare management plan for minimizing flaring from this 

flare. 

1 Simplified P&ID (process and instrument diagram) of flare header system 

2 Description of streams from process units that can be directed to the flare 

3 Procedures to reduce start-up and shutdown releases to the flare

4 Operational procedures for specific process units to reduce releases to the flare during 

normal process operations 

5 Procedures to reduce/minimize purge or sweep gas use

5 Procedure to conduct a root cause and corrective action analysis for flare events 

exceeding a set SO2 emission level

6 Procedures to conduct root cause and corrective action analysis for flare events exceeding 

a set flow rate level

7 Procedures for monitoring flow of gas to the flare

8 Procedures for monitoring Btu of flared gas

9 Procedures for monitoring sulfur content of flared gas

99 Other (specify)

Deleted: Operates 

Deleted: Intermittent; Operates

Deleted: Intermittent; 1

Deleted: Intermittent;

Deleted: Only

Deleted: Only

Deleted: Only

Deleted: 5
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

7 Select from the following list of flare reduction measures that are specifically used to reduce 

emissions from the flare. List all that apply. 

Code No. Type of Control Device 

1 Amine treatment of the flare gas (include only amine treatment used specifically to 

reduce SO2 emissions from the flare, not amine treatment systems used the fuel gas 

system)

2 Flare gas recovery system, but not designed to recover 100 percent of flare gas during 

normal operations

3 Flare gas recovery system designed to recover 100 percent of flare gas during normal 

operations

4 Root cause and corrective action analysis for flare events exceeding a set SO2 emission 

level

5 Root cause and corrective action analysis for flare events exceeding a set flow rate level

95 Other management practice or work practice to reduce VOC (specify)

96 Other management practice or work practice to reduce PM (specify)

97 Other management practice or work practice to reduce SO2 (specify)

98 Other management practice or work practice to reduce NOX (specify) 

99 Other (specify) 

Deleted: controls

Deleted: minimization plan¶
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 13. FUEL GAS TREATMENT UNIT

1. Facility ID number (EPA will provide this number): ______________________

 2. Please provide information requested in Table 13-1 for each fuel gas treatment unit at the 

facility.

TABLE 13-1. Fuel Gas Treatment Unit Information

Fuel Gas Treatment Unit ID

Unit ID for each process unit that generates 

fuel Gas treated in the treatment unit

Type of sulfur removal technique(s) used1

Fuel gas flow rate at treatment unit capacity 

(scfm)

Average fuel gas flow rate into the treatment 

unit (scfm)

Estimated operating hours in 2010

Types of sulfur compounds in the untreated 

fuel gas2

Estimated annual average H2S concentration 

in treated fuel gas exiting the treatment unit 

(ppmv)

Estimated annual average total sulfur 

concentration in the treated fuel gas exiting 

the treatment unit (ppmv)

Applicable SO2 federal air regulation(s) for 

combustion units that burn the fuel gas3

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s)

Are there any atmospheric vents in the system 

(Yes/No)? (If yes, report in Table 11-1)
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 13-1:

1

 Select from the following list of sulfur removal techniques; list all that apply.

Code No. Type of Sulfur Removal Technique

1 Absorption using MDEA solvent

2 Absorption using MEA solvent

3 Absorption using DEA solvent

4 Absorption using DIPA solvent

5 Absorption using DGA solvent

6 Absorption using blend of amine(s) and TG-10 solvent

7 Flexsorb® process

8 Selexol® process

9 Rectisol® process

10 Sulfinol® process

11 MeroxTM process

12 COS hydrolysis

13 Hot potassium carbonate

14 LoCat®

15 Caustic scrubber

16 Sodium hydrosulfide (NaSH) production process

99 Other (specify)

2

 Select from the following list of sulfur containing compounds; list all that apply.

Code No. Type of Sulfur Containing Compound

1 Hydrogen sulfide (H2S) 

2 Carbonyl sulfide (COS)

3 Carbon disulfide (CS2)

4 Mercaptans

5 Thioethers

99 Other (specify)

3

 Select the Federal regulation(s) to which the fuel gas combustion units are subject from the 

following list of regulations. Select all that apply, but include only regulations to which the 

fuel gas combustion units are subject according to the applicability of the regulation (i.e., do 

not select regulations that are referenced from the regulation(s) to which the combustion units 

are subject).

Code No. Federal Air Regulation for the Fuel Gas Combustion Units

0 None

1 Refinery NSPS (40 CFR part 60, subpart J)

2 Refinery NSPS (40 CFR part 60, subpart Ja)

3 Steam Generation NSPS (40 CFR part 60, subpart D)

4 Steam Generation NSPS (40 CFR part 60, subpart Db)

5 Steam Generation NSPS (40 CFR part 60, subpart Dc)

99 Other (specify)
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 14. HEAT EXCHANGE (COOLING WATER) SYSTEMS

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide information requested in Table 14-1 for each heat exchange (HE) system 

at the facility. 

TABLE 14-1. Cooling Water System Information 

HE System ID Number or 

Description 

Unit IDs for Process Units 

Serviced by Cooling Water 

System 

Cooling Water System 

Operation – Fluid Pressure1

Cooling Water System 

VOC/HAP Concentration2

Type of Cooling Water 

System3

Applicable Federal air 

regulation(s)

4

If subject to State, local, or 

Tribal air regulation(s), 

provide the citation(s) 

Cooling Water Flow/ 

Recirculation Rate 

(gal/min) 

Water Make-up Rate 

(gal/min) 

Gas or Chemical 

Additive/Disinfection 

Method5

Gas or Chemical Addition 

Rate Value 

Gas or Chemical Addition 

Rate Units (volume or mass 

per time) 

Chemical Addition 

Location 

 

Deleted: 13. 

Deleted: c

Deleted: response

Deleted: 13

Deleted: cooling water

Deleted: 3. For each cooling water system listed 

in Table 13-1, also provide criteria pollutant and 

HAP emission estimates (tons/yr) following the 

methods provided in the Emission Estimation 

Protocol for Petroleum Refineries using the 

emissions template in Annex A of this part.¶

Deleted: 13

Deleted: Cooling

Deleted: 1

Deleted: Operation2

Inserted Cells

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 4

Deleted: Monitoring Method and Frequency5

Deleted Cells

Deleted: Leak Definition

Deleted Cells
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 14-1: 

1

 Select from the following list of cooling water system operations. 

Code No. Type of Cooling Water System Operation – Fluid Pressure

1 Services only heat exchangers in which the maximum process fluid pressure is lower than 

the minimum water pressure 

2 Services at least one heat exchanger in which the maximum process fluid pressure is 

higher than the minimum water pressure

2

 Select from the following list of descriptions of the cooling water system VOC and HAP 

concentrations.

Code No. Cooling Water System VOC/HAP Concentration

1 Services only heat exchangers in which the process fluid contains less than 5 wt% VOC 

and less than 5 wt% organic HAP

2 Services at least one heat exchanger in which the process fluid contains at least 5 wt% 

VOC but no heat exchangers with 5 wt% or more organic HAP 

3 Services at least one heat exchanger in which the process fluid contains at least 5 wt% 

organic HAP 

3

 Select from the following list of types of cooling water systems. 

Code No. Type of Cooling Water System 

1 Once-through cooling water system 

2 Natural draft cooling tower 

3 Induced draft cooling tower (fans at outlet) 

4 Forced draft cooling tower (fans for inlet air) 

99 Other (specify) 

4

 Select the Federal air regulation(s) to which the cooling water system is subject from the 

following list of regulations. Select all that apply, but include only regulations to which the 

cooling water system is subject according to the applicability of the regulation (i.e., do not 

select regulations that are referenced from the regulation(s) to which the cooling water system 

is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 HON (40 CFR part 63, subpart H) existing source requirements

4 HON (40 CFR part 63, subpart H) new source requirements

99 Other (specify)

Deleted: 13

Deleted: Select from the following list of process 

units that best describe the process units serviced by 

the cooling water system. List all that apply.¶

Code No. Type of Process Unit¶

1 Atmospheric crude distillation¶

2 Vacuum distillation¶

3 Delayed coking¶

4 Fluid coking (traditional)¶

5 Flexicoking¶

6 Visbreaking, other thermal cracking¶

7 Fluid catalytic cracking unit¶

8 Non-fluid catalytic cracking unit¶

9 Catalytic hydrocracking¶

10 Catalytic reforming unit – continuous 

regeneration¶

11 Catalytic reforming unit – cyclic regeneration¶

12 Catalytic reforming unit – semi-regenerative¶

13 Fuels solvent deasphalting¶

14 Desulfurization/ hydrotreat – naphtha/reformer 

feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet fuel¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – other¶

22 HF alkylation¶

23 H2SO4 alkylation¶

24 Aromatics production¶

25 Asphalt production¶

26 Isomerization – Isobutane¶

27 Isomerization – Iso C5,C6 ¶

28 Lubricants production ¶

29 Petroleum coke storage¶

30 Hydrogen plant¶

31 Sulfur plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

40 Blow down system¶

99 Other (specify)¶

¶

2

Deleted: er

Deleted: 

Deleted: er

Deleted: 

Deleted: 3

Deleted: only heater exchangers

Deleted: less than

Deleted: 4

Deleted: heater exchangers
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

5

 Select from the following list of chemical additives. 

Code No. Type of Chemical Additive/Disinfection Method 

1 Chlorine from gas cylinders 

2 Sodium hypochlorite 

3 Calcium hypochlorite 

4 Chloramine 

5 Ozonation 

6 UV disinfection 

99 Other (specify) 

Deleted: 5 Select from the following list the 

combination that best describes the monitoring 

methods and frequencies for the unit. List all that 

apply. For example, select 1B and 4E if you conduct 

daily visual inspections and quarterly measurements 

using El Paso stripping column.¶

Code No. ... [71]
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 15. WASTEWATER COLLECTION AND TREATMENT 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide the following information for the facility. 

a. What is the daily average wastewater treatment system flow rate (or discharge rate if 

wastewater is treated off-site)?

b. What is the Total Annual Benzene (TAB) quantity for the facility? 

c. Indicate the Benzene Waste Operations NESHAP (BWON) (40 CFR part 61, subpart FF) 

compliance option selected by the facility. 

1 2 Mg/yr 

2 6 BQ 

3 Not applicable because TAB < 10 Mg/yr 

4 Other (specify) 

3. Please provide the following information about wastewater generated from tank 

drawdowns: 

a. Estimated quantity of wastewater generated via tank draw downs in 2010? ___ gallons

b. Quantity of benzene in wastewater generated via tank draw downs in 2010? ___ lbs

c. Average VOC content of wastewater generated via tank draw downs in 2010? ___ ppmw

4. Complete Table 15-1 to indicate the wastewater treatment processes used for each 

wastewater treatment system (identified in Part 1, Question 16) at the facility and the 

applicable air regulations for each selected unit.

Deleted: 14

Deleted: c

Deleted: response

Deleted: regarding

Deleted: -wide

Deleted: collection and 

Deleted: (WWTS). 

Deleted: a. 

Deleted: b

Deleted: 3. Please provide the information 

requested in Table 14-1 for the wastewater collection 

system components.¶

TABLE 14-1. Wastewater Collection System 

Components¶

Component ... [72]
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

TABLE 15-1. Wastewater Treatment Processes

Wastewater Treatment 

System ID

Type of 

Wastewater 

Treatment 

Process1

For Steam and 

Sour Water 

Strippers, also 

Provide Average 

Steam Usage 

Rates in 2010 

(lb/hr)

Applicable Federal air 

regulation(s)2

If subject to State, 

local, or Tribal air 

regulation(s), provide 

the citation(s)

Footnotes for Table 15-1: 

1

 Select from the following list of wastewater treatment processes.

Code No. Wastewater Treatment Process

0 None (no on-site wastewater treatment units present at facility)

1 Benzene/VOC steam stripper 

2 Oil-water separator 

3 Dissolved air/gas flotation 

4 Equalization basin/tank

5 Neutralization basin/tank

6 Activated-sludge biological treatment unit 

7 Aerated surface impoundment 

8 Non-aerated surface impoundment 

9 Anaerobic sludge digester 

10 Aerobic sludge digester 

11 Other biological treatment unit (trickling filter, rotating biological contactor) 

12 Primary clarifier 

13 Secondary clarifier 

14 Sour water stripper

Deleted: 14

Deleted: Collection System Components

Deleted: Component

Formatted Table

Deleted: Number Controlled

Deleted: Number Uncontrolled

Deleted: Control Technologies1

Inserted Cells

Deleted: Drain

Merged Cells

Deleted: Trench

Deleted: Manhole

Deleted: Junction Box

Deleted: Sump

Deleted: Lift Station

Deleted: Weir

Deleted: 14

Deleted: 6 Activated-sludge biological treatment 

unit¶

7 Aerated surface impoundment¶

8 Non-aerated surface impoundment¶

9 Anaerobic sludge digester¶

10 Aerobic sludge digester¶

11 Other biological treatment unit (trickling filter, 

rotating biological contactor)¶

12 Primary clarifier¶

13 Secondary clarifier¶

14 Other (specify)¶

¶

5. Please provide the information requested in 

Table 14-2 for each wastewater collection or 

treatment unit (WWTU) at the facility. For 

wastewater collection system components, you may 

aggregate all similar components as a single unit ID 

number (all drains, all sumps, all lift stations, all 

junction boxes, et cetera).¶

6. For each WWTU listed in Table 14-2, also 

provide criteria pollutant and HAP emission 

estimates (tons/yr) following the methods provided 

in the Emission Estimation Protocol for Petroleum 

Refineries using the emissions template in Annex A 

of this part.¶

TABLE 14-2. Wastewater Collection and 

Treatment Unit Information¶

WWTS ID Number ... [73]

Deleted: 99 Other (specify)¶
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2

 Select the Federal air regulation(s) to which the selected wastewater treatment unit

 is subject from the following list of regulations. Select all that apply, but include only 

regulations to which the wastewater treatment unit is subject according to the applicability of 

the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which 

the wastewater treatment unit is subject). 

Code No. Compliance Applicability 

0 The unit is not subject to any air standards. 

1 The unit is subject to BWON (40 CFR part 61, subpart FF) but exempted from control 

requirements. 

2 The unit is subject to BWON (40 CFR part 61, subpart FF) control requirements.

3 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

4 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

5 HON (40 CFR part 63, subpart H) existing source requirements

6 HON (40 CFR part 63, subpart H) new source requirements

7 Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)

5. Please provide the information requested in Table 15-2 for each process unit that 

routinely generates wastewater.

TABLE 15-2. Wastewater Generation Information

Process 

Unit ID

Average wastewater 

generation rate 

(gallons/operating day)

Average benzene 

concentration 

(ppmw)

Average concentration of 

organic HAP (ppmw)

Average VOC 

concentration 

(ppmw)

Deleted: from 

Deleted: following list

Deleted: combination that best describes the 

monitoring parameters and frequencies for the 

Deleted: . List all that apply. For example, select 

13A, 12B, and 22E if you continuously monitor 

dissolved oxygen concentration, perform daily 

MLVSS analyses, and perform quarterly benzene 

concentration analyses.¶

Code No. ... [74]

Deleted: compliance 

Deleted: options. List all compliance applicability 

options that apply to 

Deleted: unit (if more than one option applies

Deleted: under the 2 Mg exclusion.

Deleted: 

Deleted: but exempted from

Deleted: as an “enhanced biodegradation unit.”

Deleted: The unit is subject to BWON control 

requirements.¶

4 The unit is subject to and utilized for compliance 

with the Hazardous Organic NESHAP

Deleted: G).

Deleted: The unit is subject to the 

Deleted: ).

Deleted: 4 Select from the following list of 

emission reduction methods. List all options that 

apply to the unit (if more than one option applies).¶

Code No. Type of Emissions Reduction Method¶

0 None ¶

1 Wastewater is steam stripped or otherwise treated 

in accordance with the standards for treatment 

processes in 40 CFR 61.348 prior to unit.¶

2 Unit is covered and vented to a control device in 

compliance with the standards for closed vent 

systems and control devices in 40 CFR 61.349. ¶

98 Management practice or work practice (specify)¶

99 Other (specify)¶

¶
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

6. Please provide information requested in Table 15-3 for each “wastewater vent” at the 

facility. “Wastewater vents” include atmospheric vents associated with wastewater drain 

systems and gases purged from covered wastewater treatment systems.

TABLE 15-3. Wastewater Vent Information

Atmospheric 

Vent ID

Description 

of 

Atmospheric 

Vent1

Applicable

Federal air 

regulation(s)2

If subject to State, 

local, or Tribal air 

regulation(s), 

provide the 

citation(s)

Atmospheric 

Vent Operating 

Hours3

Atmospheric 

Vent 

Controls4

Footnotes for Table 15-3:

1

 Select from the following list of wastewater vents the option that best describes this vent.

Code No. Type of Unit/Equipment Associated with Vent

1 Drain system vent

2 Vent from wastewater treatment unit

99 Other (specify)
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2

 Select the Federal air regulation(s) to which the selected wastewater vent is subject from the 

following list of regulations. Select all that apply, but include only regulations to which the 

wastewater vent is subject according to the applicability of the regulation (i.e., do not select 

regulations that are referenced from the regulation(s) to which the wastewater treatment unit is 

subject).

Code No. Compliance Applicability

0 The vent is not subject to any air standards. 

1 The vent is subject to BWON (40 CFR part 61, subpart FF) but exempted from control 

requirements. 

2 The vent is subject to BWON (40 CFR part 61, subpart FF) control requirements.

3 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements

4 Refinery MACT (40 CFR part 63, subpart CC) new source requirements

5 HON (40 CFR part 63, subpart H) existing source requirements

6 HON (40 CFR part 63, subpart H) new source requirements

7 Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)

3

 Select from the following list of operating scenarios.

Code No. Type of Operation

1 Continuous (operates whenever the wastewater treatment process is operating)

2 Intermittent; 4,000 hours per year or more

3 Intermittent; 2,000 hours or more but less than 4,000 hours per year

4 Intermittent; 1,000 hours or more but less than 2,000 hours per year

5 Intermittent; less than 1,000 hours per year

4

 Select from the following list of control devices. List all that apply.

Code No. Type of Control Device

0 None

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

53 Single carbon adsorber canister

54 Two carbon adsorber canisters in series

95 Management practice or work practice to reduce VOC (specify)

99 Other (specify)
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 16. LOADING OPERATIONS 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Please provide the following information regarding products transported by marine 

vessels (tank ships and barges).

a. Select the option that best describes the marine vessel loading operations that are 

associated with the refinery’s shipments via marine vessels (as reported in Question 15 of 

Part I of this ICR).

0 None. There are no shipments made via marine vessels

1 Marine vessel operations are contiguous with the refinery.

2 Marine vessel operations are conducted on-shore but are not contiguous with the refinery.

3 Marine vessel operations are conducted off-shore (i.e., more than 0.5 miles from the 

coast).

b. For the marine vessel operations associated with the refinery’s shipments, are there 

vessels or barges loaded that contain non-segregated ballast water?

Yes No 

c. If Yes, is non-segregated ballasting water (from either on-site or off-site marine vessel 

loading operations) treated in the refinery’s wastewater treatment plant?

Yes No

3. Please provide the following information regarding products transported by tank truck or 

rail car.

a. Select the option that best describes the tank truck operations that are associated with the 

refinery’s shipments via tank truck (as reported in Question 15 of Part I of this ICR).

0 None. There are no shipments made via tank truck

1 Tank truck loading operations are conducted on-site (i.e., considered part of the refinery 

facility).

2 Tank truck loading operations are conducted off-site (not part of the contiguous refinery 

facility). 

b. Select the option that best describes the rail car operations that are associated with the 

refinery’s shipments via rail truck (as reported in Question 15 of Part I of this ICR).

0 None. There are no shipments made via rail car

1 Rail car loading operations are conducted on-site (i.e., considered part of the refinery 

facility).

2 Rail car loading operations are conducted off-site (not part of the contiguous refinery 

facility). 

Deleted: AND UNLOADING 

Deleted: c

Deleted: response
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

4. Please provide the information requested in Table 16-1 for each fixed location loading 

operation (e.g., dock, loading rack) at the facility (i.e., those considered part of the 

refinery facility). 

TABLE 16-1. Loading Information 

Unit ID for loading operation

Type of vessel loaded1

Capacity loading throughput 

(gal/yr) 

Applicable Federal air 

regulation(s)

2

If subject to State, local, or 

Tribal air regulation(s), 

provide the citation(s) 

Typical annual operating 

hours (hr/yr) 

Does the facility or parent

company own the vessels being 

l d d? (Y /N )

Type of control device or 

control technique3

Deleted: and unloading

Deleted: at the facility. If you load/unload more 

than one commodity in a particular location 

Deleted: marine vessel berth

Deleted: ), use a separate line for each type of 

commodity loaded/unloaded at that location.

Deleted: 3. For each loading/unloading location 

listed in Table 16-1, also provide criteria pollutant 

and HAP emission estimates (tons/yr) following the 

methods provided in the Emission Estimation 

Protocol for Petroleum Refineries using the 

emissions template in Annex A of this part.¶

Deleted: and Unloading

Formatted Table

Deleted: (location) 

Deleted: loaded/unoaded1

Deleted: Type of liquid commodity 

loaded/unloaded2

Deleted Cells

Deleted: Actual loading throughput (gal/yr)

Deleted Cells

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: Year loading operation installed

Deleted Cells

Deleted: Date control device or control 

technique was installed

Deleted Cells
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Footnotes for Table 16-1: 

1

 Select from the following list of vessels. List all that apply. 

Code No. Type of Vessel 

1 Tank ship 

2 Barge 

3 Truck/tank truck 

4 Rail car 

5 Containers with capacity less than 250 gallons

6 Containers with capacity from 250 gallons to less than 1,000 gallons

7 Containers with capacity from 1,000 gallons to less than 20,000 gallons

8 Containers with capacity greater than or equal to 20,000 gallons

99 Other (specify) 

2

 Select the Federal air regulation(s) to which the loading/unloading location is subject from the 

following list of regulations. Select all that apply, but include only regulations to which the 

loading/unloading location is subject according to the applicability of the regulation (i.e., do 

not select regulations that are referenced from the regulation(s) to which the loading/unloading 

location is subject).

Code No. Federal Air Regulation 

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 HON (40 CFR part 63, subpart H) existing source requirements

4 HON (40 CFR part 63, subpart H) new source requirements

5 Gasoline Loading NSPS (40 CFR part 60, subpart XX)

6 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements

7 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements

8 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements

9 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements

99 Other (specify) 

3

 Select from the following list of control devices and techniques; list all that apply. 

Code No. Type of Control 

0 None 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

52 Carbon adsorber 

55 Flare 

80 Submerged loading

82 Bottom loading 

83 Vapor balancing system 

95 Other management practice or work practice to reduce VOC (specify) 

99 Other (specify) 

Deleted: from the following list of liquid 

commodities.

Deleted: Type of Liquid Commodity

Deleted: 1 Unstabilized crude oil¶

2 Stabilized crude oil¶

3 Intermediate naphtha¶

4 Intermediate distillate oil¶

5 Intermediate heavy gas oil¶

6

Deleted: /blending stocks

Deleted: 7 Aviation fuels¶

8 No. 2 diesel fuel¶

9 No. 4 diesel fuel (heavy fuel oil)¶

10 No. 6 diesel fuel (marine diesel/bunker C)¶

11 Lubricating/motor oil¶

12 Petroleum coke¶

13 Asphalt¶

14 Sulfur¶

15 Ethylene¶

16 LPG (propane/butane)¶

17 Aromatics¶

18 Other petrochemicals (specify)¶

Deleted: 53

Deleted: 80 Submerged loading (i.e., loading 

from the top of the vessel; the fill pipe extends 

almost to the bottom of the vessel such that it is 

below the liquid level during most of the filling)¶

Deleted: 98

Deleted: 4. Are the vessels required to be cleaned 

periodically? Yes No¶

If Yes, what are the criteria for determining whether 

cleaning is needed?¶

¶

¶

¶

¶

5. Are vessel cleaning operations conducted at the 

refinery or are they conducted at a separate facility? 

Please explain.¶

¶

¶

¶

¶

6. Are there vessels or barges loaded at this facility 

that conduct non-segregated ballasting? What types 

of vessels or barges and what commodities conduct 

non-segregated ballasting? Is non-segregated 

ballasting water treated in the refinery’s wastewater 

treatment plant?¶

¶

¶

¶
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

SECTION 17. SOLID WASTE MANAGEMENT 

1. Facility ID number (EPA will provide this number): ______________________ 

2. Describe any pollution prevention methods used to reduce the quantity of solid waste

disposed of on-site and the percent and/or quantity of waste reduced (e.g., reduced sludge 

disposal from tank cleanings by 80% by recycling oily sludges to delayed coking unit). 

_________________________________________________________________________ 

_________________________________________________________________________ 

3. Please provide information requested in Table 17-1 for each active landfill, land 

application unit, waste pile, or composting operation at the facility. 

TABLE 17-1. Solid Waste Management Unit Information 

Solid Waste 

Management ID 

Number 

Type of Solid Waste 

Management Unit1

Description of Waste 

Managed in Unit 

Area of Solid Waste 

Management Unit (m2) 

Capacity of Solid Waste 

Management Unit (m3) 

Applicable Federal air 

regulation(s)

2

If subject to State, local, 

or Tribal air 

regulation(s), provide 

the citation(s) 

Waste Application or 

Disposal Rate (m3/yr) 

Bulk Density of Waste 

Applied or Disposed 

(g/cm3) 

Pretreatment or Control 

Methods Used3

Footnotes for Table 17-1: 

1

 Select from the following list of solid waste management system types. 

Code No. Type of Solid Waste Management Unit 

1 Hazardous waste (RCRA Subtitle C) landfill 

2 Industrial waste (RCRA Subtitle D) landfill 

3 Land application unit 

4 Waste pile 

5 Composting operation

Deleted: 15

Deleted: c

Deleted: response

Deleted: 2. Please provide information requested 

in Table 15-1 for each solid waste management unit 

(e.g., landfill, land application unit, or waste pile) at 

the facility. ¶

3

Deleted: 4. For each solid waste management 

unit listed in Table 15-1, also provide criteria 

pollutant and HAP emission estimates (tons/yr) 

following the methods provided in the Air Emission 

Models for Waste and Wastewater (EPA-453/R-94-

080A) using the emissions template in Annex A of 

this part.¶

Deleted: 15

Deleted: Unit

Formatted Table

Deleted: 

Deleted: 

Deleted: If subject to

Deleted: ), provide the citation(s)

Deleted: 

Deleted: 2

Deleted: 15
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2

 Select the Federal air regulation(s) to which the solid waste management unit is subject from 

the following list of regulations. Select all that apply, but include only regulations to which the 

solid waste management unit is subject according to the applicability of the regulation (i.e., do 

not select regulations that are referenced from the regulation(s) to which the solid waste 

management unit is subject).

Code No. Federal Air Regulation 

0 None

99 Other (specify) 

3

 Select from the following list of solid waste pretreatment or control methods. List all that 

apply. 

Code No. Type of Pretreatment or Control Method 

1 Dewatering 

2 Fixation (solidification/stabilization) 

3 Steam stripping 

4 Water for dust suppression 

5 Oil for dust suppression 

6 Foam for dust suppression 

7 Leachate collection 

8 Landfill gas collection 

99 Other (specify) 

Deleted: 2
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

PART III. INCIDENCE REPORTS 

1. Complete the following table for each non-routine emissions event during 2010. 

Date of 

release

Type of release 

(startup/shutdown; 

equipment or component 

malfunction) 

Description of release 

event 

Process 

units 

associated 

with the 

release 

Duration 

of the 

release 

event 

(hours) 

Pollutant 

name 

Pollutant 

CAS No.

or 

Pollutant 

Code

Quantity 

of 

pollutant 

released 

(lb) 

Quantity 

determination 

method 

(measured or 

calculated) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2. Complete the following table for each flare, air emission, or odor complaint received in 2010. 

Date of 

complaint 

Complainant 

name 

Complainant 

contact 

information 

Substance 

of 

complaint 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

83 

PART IV. COST DATA 

For any air pollution control devices (APCD), process changes, equipment changes/upgrades, 

and management or work practices implemented within the last 5 years for which you have 

readily available cost information, please provide those costs as described in this part. Include 

only process changes, equipment changes/upgrades, and management or work practices 

implemented to reduce emissions. Do not include projects needed to meet environmentally 

driven product specifications (e.g., low sulfur diesel projects, ethanol blending projects, and 

gasoline reformulation projects to remove MTBE). If you wish to provide more detail than 

requested in Table 2 (e.g., you wish to itemize total capital costs), you may provide your 

information in a separate spreadsheet. If you know an approximate cost for a control technique 

but do not have the level of detail requested in the tables, please provide the approximate cost 

and your best estimate of which of the components in the appropriate table were factored into 

that approximate cost (in lieu of completing the applicable table for that control technique). 

If any of the data requested in this part is considered CBI, follow the instructions in the section 

“Submitting CBI” under the heading “How to Submit Your Survey Response” in the 

introduction to this enclosure. 

1. Please complete Table 1 for any new APCD installed in the last 5 years on any of the 

process units or other emissions sources described in Part II for which you have readily 

available information. The EPA is particularly interested in costs of the following 

APCD: 

• Electrostatic precipitators 

• Wet scrubbers 

• Baghouses 

• SCR/SNCR for NOX control 

• Steam strippers 

• Carbon adsorbers 

• Thermal/catalytic oxidizers 

• Flares 

2. Please complete Table 2 for any process changes or equipment changes/upgrades 

performed in the last 5 years to any of the process units or other emissions sources 

described in Part II for which you have readily available information. The EPA is 

particularly interested in costs of the following process changes or equipment 

changes/upgrades: 

• Installation of low/ultra-low NOX burners 

• Installation of air preheat for process heaters/boilers 

• Catalyst additives for SOX control from FCCU 

Deleted: 10

Deleted: 10

Deleted: 10
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

84 

• Combustion promoters or catalyst additives for NOX control from FCCU 

• Amine treatment systems 

• Floating roofs, rim seals, and fittings seals on storage vessels

• Installation of geodesic dome for external floating roof tank 

• Installation of guidepole sleeves/wipers or other tank fitting gaskets 

3. Please provide any readily available costs for other techniques used at your refinery to 

reduce emissions of any pollutant. EPA is particularly interested in techniques that are 

not already included in Federal regulations. Provide as much detail in your cost estimate 

as possible (e.g., unit ID for the unit from which emissions are reduced, amount of time 

needed to complete the technique (labor costs), cost of any equipment needed on a 

temporary basis, cost of any monitoring devices needed to indicate when action is needed 

or to measure progress). Types of techniques that EPA is particularly interested in 

include: 

• Use of a portable or temporary control device (e.g., for degassing of storage 

tanks) 

• Monitoring devices (e.g., monitors that record the duration and quantity of 

compounds released from a PRD) 

• Pollution prevention techniques 

• Energy management programs identified in Part II, Section 1

• Other management practices or work practices that you identified in Part II 

Deleted: pressure relief device
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

85 

Table 1. Cost Data for APCD1

APCD ID

Unit ID associated with this APCD

APCD Type

2

APCD Size

3

New or retrofit APCD?

4

Year of APCD installation 

Expected APCD equipment life (yrs) 

Demolition Cost of previous APCD, if any ($) 

CAPITAL COSTS ANNUAL OPERATING COSTS10

Base year for capital costs 

Purchased 

equipment 

costs ($)5

Installation costs ($)

8

Total Installed Cost of APCD

9

Base year for operating costs 

Operating labor ($) 

Maintenance labor ($) 

Utilities ($) 

Waste disposal ($) 

Supplie

s and 

parts13

Monitoring, recordkeeping & reporting ($/yr) 

Other annual costs (itemize)14

Total annual operating & maintenance cost 15

Primary equipment ( $)

6

Auxiliary equipment ($)

7

Instrumentation and monitors ($) 

Sales tax and freight ($) 

Total purchased equipment costs ($) 

Electricity 

Water 

Steam 

Natural gas 

Liquid chemicals 

Solid chemicals 

Compressed Air 

Other (specify) 

Total utilities cost ($/yr)12

Description of most significant part

Number of years between replacement 

Replacement cost (with installation) ($) 

hr/yr 

$/yr 

hr/yr 

$/yr 

kWh/yr 

$/kWh 

gal/yr 

$/gal 

lb/yr 

$/lb 

scf/yr 

$/scf 

gal/yr 

$/gal 

lb/yr 

$/lb 

scf/yr 

$/scf 

amt/yr11

$/amt 

amt/yr11

$/yr 

1 

2 

3 

1 Columns that are sums of other columns are shaded gray. If you do not have the all detail requested but you do have an estimate for a subtotal, enter the subtotal in the appropriate 

shaded column and provide as much detail or explanation as you have available. 

2 See list following the last footnote for codes corresponding to APCD types. 3 Provide the numerical value as well as the units (e.g. scfm). 4 If the APCD was installed at the time the process unit or emission source was constructed, enter “New.” If the APCD was installed after the process unit or emission source began 

operation, enter “Retrofit.” 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

86 

5 Sum of equipment, auxiliary equipment, instrumentation/monitors, sales tax, and freight. 6 Primary equipment is the APCD itself. Examples include SCR with catalyst, carbon adsorber with carbon, packed scrubber tower with packing, fabric filter with bags, ESP, and 

steam stripper column with nozzles, manholes, and trays. 

7 Examples of auxiliary equipment include fans, pumps, motors, duct work, stacks, flame arrestors, and condensers and decanters for steam strippers. 8 Include all installation costs (e.g., foundations, supports, handling/erection, electrical, piping, insulation for ductwork and piping, painting, engineering, construction and field 

expenses, contractor fees, start-up, and testing. 

9 Sum of purchased equipment cost and installation cost. 10 Provide operating costs for the last 12 month period (calendar or fiscal year) for which the refinery has data. 11 Specify units. 12 For each utility that applies to this APCD, multiply the consumption rate (the first column for that utility) by the unit cost (the second column for that utility) to get the annual cost 

for each utility. Add the individual utility annual costs to get the total utilities cost. 

13 Include the most significant of the major supplies and replacement parts; examples include catalyst for SCR and catalytic incinerators, bags for fabric filters, and carbon for carbon 

adsorbers. 

14 An example might be catalyst regeneration. Note that this question is not asking for costs of maintenance materials, capital recovery, overhead, administration, property taxes, and 

insurance because EPA will estimate these costs as a function of other costs. 

15 Sum of annual costs for operating labor; maintenance labor; utilities; waste disposal; major supplies and replacement parts that are needed once per year or more frequently; 

monitoring, recordkeeping, and reporting; and any other items included under “other annual costs.” 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

87 

Code No. Type of APCD 

1 Amine treatment (e.g., installation of new amine treatment unit)

2 Caustic spray injection 3 Packed-bed wet scrubber 4 Tray tower wet scrubber 5 ChlorsorbTM11 Fabric/cartridge filter (“baghouse”) 12 Venturi/wet scrubber 13 Electrostatic precipitator (ESP) 14 Wet ESP 15 Tertiary cyclone 24 Wet scrubber/flue gas desulfurization 25 Spray dryer absorber 36 Selective non-catalytic reduction (SNCR) 37 Selective catalytic reduction (SCR) 42 LoTOX® scrubber 50 Thermal or catalytic incinerator/oxidizer 51 Condenser 52 Carbon adsorber 53 Single carbon adsorber canister54 Two carbon adsorber canisters in series55 Flare 56 Portable internal combustion engine 57 Portable thermal oxidizer 58 Portable condensation system 59 Permanent onsite control device for storage tanks 60 Flare gas recovery 83 Vapor balancing system 99 Other (specify) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

88 

Table 2. Cost Data for Process and Equipment Changes 

Unit ID 

Process or 

equipment 

change type1

Process or 

equipment 

change 

description2

Year of process 

or equipment 

change 

Number of days 

process shut 

down in order to 

make the change 

(days of lost 

production)3

Total capital 

cost, $4

Change in total 

annual 

operating cost, 

$/yr5

Emission 

reduction 

achieved (if 

quantified)6

1 See list following the last footnote for codes corresponding to process or equipment changes. If none of the codes describe your process or equipment change, enter “99” and specify 

the type of process or equipment change.

2 Describe the process or equipment change. Be as descriptive as possible. For example, for installation of low NOX or ultra low NOX burners for a process heater, note the number of 

new burners, their sizes, and the fuel options (e.g., fuel gas, oil). 

3 Enter number of days of lost production required to implement the process or equipment change. If the change occurred during scheduled downtime that would have occurred 

regardless of the process or equipment change, then do not include the scheduled downtime. Only the days of lost production that can be specifically attributed to the process or equipment change are of interest. 

4 Please distinguish between one-time capital and annual operating costs where appropriate. If a breakdown of the specific capital or annual cost items is available, please provide as a 

separate attachment. 

5 Provide changes in annual operating costs (if estimated). Otherwise, leave blank. Include annual operating costs that are an increase to prior operating costs (e.g., additional 

operating costs due to installation of low NOX burners). If the process or equipment change resulted in decreased annual operating costs, then indicate the cost decrease as a 

negative number. 

6 Describe the air pollutants affected and emissions reduction achieved. Indicate the basis for emissions reduction reported (e.g., air emissions testing before and after modification). 

You may provide this information as a separate attachment to your response if you wish. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

89 

Code No. Type of Process or Equipment Change 

1 Amine treatment (change in existing amine treatment system operation)

21 H2S limit in fuel gas 

22 TRS limit in fuel gas 23 Low sulfur distillate or heavy gas oil 26 DeSOx catalyst, meeting 50/25 ppmv SO2 limit 

27 DeSOx catalyst, meeting 20 lb/ton coke burn-off, but not 50/25 ppmv SO2 limit 

28 Low sulfur (0.3 wt% or less) feed 31 (External) flue gas recirculation 32 Staged air low NOX burner 

33 Staged fuel low NOX burner 

34 Ultra low NOX burner (high fraction staged fuel) (ULNB) 

35 “Next generation” low NOX burner (ULNB with internal gas recirculation) 

39 High-efficiency regenerator 40 Low NOX combustion additives to replace Pt-based combustion additives 

41 Other low NOX catalyst additives 

70 Water seal 71 Fixed seal 72 Hard piping 80 Submerged loading (i.e., loading from the top of the vessel; the fill pipe extends almost to the bottom of the vessel such that it is 

below the liquid level during most of the filling) 

82 Bottom loading 99 Other (specify) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

90 

PART V. EMISSIONS MONITORING AND SOURCE TEST DATA 

In this section, emissions test data are requested. Please satisfy this request as completely as 

possible from existing information. No additional monitoring or emission testing is required by 

your company to respond to the data request in this section. Four types of existing emissions 

data are requested: 1) source test data, 2) qualified CEMS data, 3) biological treatment units 

data, and 4) ambient or remote sensing data. The emissions test data collected will provide 

valuable information on current emissions levels and will allow EPA to consider variability in 

emissions from refinery to refinery (and over time for a given emission unit and pollutant) in 

reviewing and setting emission standards. When submitting test data, EPA is requesting full test 

reports with field and lab data sheets and example calculations, not just summary reports. 

If any of the data requested in this part is considered CBI, follow the instructions in the section 

“Submitting CBI” under the heading “How to Submit Your Survey Response” in the 

introduction to this enclosure. 

1. Source Tests: Provide any existing emissions test reports from emissions tests conducted 

on any of the processes or emission points included in Part II, Sections 3 through 17 on or 

after January 1, 2005. Electronic (pdf) or hard copies are acceptable. Include the 

summary portion of the report and any appendices showing run-by-run test parameters, 

method detection limits, laboratory data, production data, example calculations, etc. If 

you have multiple tests for one pollutant from one process unit, submit only the most 

recent tests for that pollutant and process unit. (We are only requesting a maximum of 

the three most recent tests per unit for one pollutant, but you may submit more than three, 

particularly if additional tests reflect the effect of different operating conditions or 

equipment configurations.)

In addition, complete the source test log shown in Attachment 1 for each source test you 

submit. (Electronic copies of this table can be downloaded from the ICR website 

(https://refineryicr.rti.org).) Note that the information requested in the summary table 

includes: 

(A) APCD type (if not clear from the test report),

(B) a description of how the configuration of the emission unit, combustion controls, 

collection system, or APCD has changed since the test was conducted, if 

applicable,

(C) any notes specific to that emissions test (optional), and

(D) how often you are required to test the emission unit (optional).

2. Qualified CEMS Data: Provide qualified CEMS data for PM, CO, NOX, SO2, O2, and 

THC CEMS on any of the processes or emission points included in Part II, Sections 2 

through 17. Report daily averages for each day in 2010 using the Microsoft® Excel 

CEMS Template; an example template is shown in Attachment 2. The Excel templates 

are specific to each pollutant and type of unit, and each template is designed to 

Deleted: 16

Deleted: (

Deleted: ).

Deleted: summary table

Deleted: 3 of this enclosure

Field Code Changed

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).)

Deleted: emission rates measured,¶

(B)

Deleted: method or procedure used,

Deleted: (C) information on actual production or 

processing rates and on process conditions at the 

time the measurements were made, and¶

(D) a statement that any APCD (if present) were 

operating normally during the test, or if not, what the 

abnormal operating conditions were.¶

Deleted: 16

Deleted: 9

Deleted: 4
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

91 

accommodate data from one CEMS (including oxygen data). Electronic copies of the 

template can be downloaded from the ICR website (https://refineryicr.rti.org). 

Qualified CEMS data include: data from a PM CEMS that meets Performance 

Specification 11 or 15; data from a CO CEMS that meets Performance Specification 4; 

data from a SO2 and/or NOX CEMS that meets Performance Specification 2; data from a 

THC CEMS that meets Performance Specification 8A; or data from any CEMS meeting 

the accuracy and ongoing QA/QC requirements of 40 CFR part 60, Appendix F. Use 

only qualified CEMS data and determine the daily averages using by averaging the 

hourly CEMS values for each hour for which qualified CEMS data are available. If there 

are no qualified CEMS data for any hour in a given day, report “ND” (no data) for that 

daily average. 

3. Qualified CMS Data: Provide qualified CMS data for H2S, reduced sulfur, total reduced 

sulfur, hydrocarbon, and Btu CMS on fuel gas or flare gas lines. Report daily averages 

for each day in 2010 using the Microsoft® Excel CMS Template; an example template is 

shown in Attachment 2. The Excel templates are specific to each pollutant and type of 

unit, and each template is designed to accommodate data from one CMS. Electronic 

copies of the template can be downloaded from the ICR website 

(https://refineryicr.rti.org). 

Qualified CMS data include: data from a H2S CMS that meets Performance 

Specification 7; data from a reduced sulfur or total reduced sulfur CMS that meets 

Performance Specification 7; data from a hydrocarbon or Btu CMS (gas composition 

monitor) that meets Performance Specification 5; data from any CMS meeting the 

accuracy and ongoing QA/QC requirements of 40 CFR part 60, Appendix F; or data from 

any CMS for that has been calibrated per the manufacturer’s specifications within the 

past 12 months and is operated and maintained (including on-going QA/QC 

requirements) according to the manufacturer’s specifications. Use only qualified CMS 

data and determine the daily averages using by averaging the hourly CMS values for each 

hour for which qualified CMS data are available. If there are no qualified CMS data for 

any hour in a given day, report “ND” (no data) for that daily average.

4. Biological treatment unit: If you performed a biodegradation rate test or a complete 

mixing test on a biological treatment unit on or after January 1, 2000, provide a complete 

copy of the test report. 

5. Ambient and remote sensing: If you conducted ambient air monitoring or conducted a 

DIAL, SOF, or similar test at or around your facility on or after January 1, 2000, provide 

a complete copy of the test report for these studies. 

6. Equipment leak correlations: If you developed site-specific correlations for equipment 

leaks at your facility and you use those correlations to estimate emissions from 

equipment leaks, provide a complete copy of the report or other documentation 

describing the testing and development of the correlations. 

Field Code Changed

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).

Deleted: 9

Deleted: 4

Field Code Changed

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

1-1 

Attachment 1 Log of Source Tests Provided

Test 

Num

ber1

Unit 

ID(s)

If the APCD 

type(s) is not 

clear from the 

test report, enter 

the APCD type(s) 

Configurati

on changes2

OPTIONA

L: 

Process 

testing 

notes3

OPTIONAL: How often 

are you required to 

perform testing of this 

emission unit for the 

pollutants listed? 

OPTION

AL: 

Approxi

mate cost 

per test, $ 

1 Assign a test ID or number to each test report that you provide so that EPA can match your responses in this log to the correct test report. 2 If the configuration of the emission unit, combustion controls, collection system, or APCD changed since the test was conducted, describe the changes. If there are no configuration 

changes, enter “N/A” 

3 Use this column for notes or if helpful to specify the emission points tested (e.g., for equipment with multiple emission points, where only selected emission points/vents were tested) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2-1 

Attachment 2. Example CEMS Table 

NOX CEMS DATA 

Emission Unit ID: 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2-2 

CEMS 

Date 

(mm/dd/ 

yyyy) 

Daily 

production/ 

throughput

rate

(value)1

Daily 

production/ 

throughput

rate

(units) 

1-day average 

emission value 

for NOX

(as measured 

by the CEMS) 

Unit of 

measure 

recorded 

by 

CEMS

O2

conten

t (%)

Moisture 

content 

(%)

Data 

average 

affected 

by a 

startup, 

shutdow

n, or 

other 

event?1

OPTIONA

L: 

Emission 

value

(ppmvd @ 

7% O2)

OPTIONAL: 1-day average emission value 

for NOX in other units

1-day average 

emission value 

for NOX, 

corrected for 

%O2 (value) 

1-day 

average 

emission 

value for 

NOX, (units) 

% O2

correction 

(by volume, 

dry basis) 

01/01/201

0 

01/02/201

0 

01/03/201

0 

01/04/201

0 

01/05/201

0 

01/06/201

0 

01/07/201

0 

01/08/201

0 

......

12/25/201

0 

12/26/201

0 

12/27/201

0 

12/28/201

0 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2-3 

12/29/201

0 

12/30/201

0 

12/31/201

0 

1 Provide the process production rate, heat input rate, coke burn-off rate or other normalizing factor appropriate for the type of process. 2 If no, leave blank. If yes, respond “startup,” “shutdown,” or “event”; if you respond “event” please include a brief description of the event. 
Page 13: [1] Deleted Author 

Processing Unit 

Number 

of Units 

Unit 1 

ID 

Unit 1 

Throughput 

(bbl/cd)1

Unit 2 

ID 

Unit 2 

Throughput 

(bbl/cd)1

Unit 3 

ID 

Unit 3 

Throug

put 

(bbl/cd

Atmospheric crude distillation Vacuum distillation Delayed coking Fluid coking (traditional) Flexicoking Visbreaking, other thermal cracking Fluid catalytic cracking unit Non-fluid catalytic cracking unit Catalytic hydrocracking Catalytic reforming unit – continuous regen. Catalytic reforming unit – cyclic regenerationCatalytic reforming unit – semi-regenerative Fuels solvent deasphalting Desulfurization/ hydrotreat – naphtha/reformer feed Desulfurization/ hydrotreat – gasoline Desulfurization/ hydrotreat – kerosene/ jet fuel Desulfurization/ hydrotreat – diesel Desulfurization/ hydrotreat – other distillate 
Processing Unit 

Number 

of Units 

Unit 1 

ID 

Unit 1 

Throughput 

(bbl/cd)1

Unit 2 

ID 

Unit 2 

Throughput 

(bbl/cd)1

Unit 3 

ID 

Unit 3 

Throug

put 

(bbl/cd

Desulfurization/ hydrotreat – residual Desulfurization/ hydrotreat – heavy gas oil Desulfurization/ hydrotreat – other HF alkylation H2SO4 alkylation Aromatics production Asphalt production Isomerization – Isobutane Isomerization – Iso C5,C6 Lubricants production Petroleum coke storage Hydrogen plant2Sulfur plant3Gas plant (LPG production unit) Oxygenate plant – MTBE Oxygenate plant – ETBE Oxygenate plant – TAME Oxygenate plant – other (specify) Marine vessel loading/unloading Truck/tank truck loading/unloading Rail car loading/unloading Wastewater treatment4

1 Throughput units are barrels per calendar day (bbl/cd) unless noted otherwise. For crude distillation through desulfurization, “throughput” is determin

for alkylation through oxygenates, “throughput” is determined in terms of materials produced. 

2 Throughput units are million cubic feet per calendar day (MMcf/cd). 3 Throughput units are long tons per calendar day (LT/cd). 4 Throughput units are million gallons per day (MMgal/day). 

Section Break (Next Page)
15. Provide location information for each of the major processing units at the facility. 

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Desulfurization/ hydrotreat – other 

HF alkylation 

H2SO4 alkylation 

Aromatics production 

Asphalt production 

Isomerization – Isobutane 

Isomerization – Iso C5,C6 

Lubricants production 

Petroleum coke storage 

Hydrogen plant 

Sulfur plant 

Gas plant (LPG production unit) 

Oxygenate plant – MTBE 

Oxygenate plant – ETBE 

Oxygenate plant – TAME 

Oxygenate plant – other (specify) 

Marine vessel loading/unloading 

Truck/tank truck loading/unloading 

Rail car loading/unloading 

Wastewater treatment 

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Abbreviation: MW = megawatts 

1

 For disposition of electricity, enter appropriate code number as follows: 

Enter “1” if generated electricity is used only on-site. 

Enter “2” if generated electricity is used only off-site (e.g., sent to grid). 

Enter “3” if generated electricity is used on-site with excess used off-site or sent to grid. 

4. Does this refinery generate steam on-site? Yes No

If Yes: Provide the information requested in Table 1-3 for each steam-generating unit. 

TABLE 1-3. Steam Generation Information 

Unit ID 

Unit Description1

Boiler Heat Input 

Capacity 

(MMBtu/hr) 

Steam Generating 

Capacity (lb/hr) 

Pressure of Steam 

(psia) 

Primary Fuel 

Secondary Fuel 

Disposition of 

steam2

Energy Efficiency 

Measures3

Does this unit 

have air preheat? 

(Yes/No) 

Percent Steam to 

Blowdown 

 
 

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Footnotes for Table 1-4: 

1

 Select the process unit served by the process heaters from the following list. 

Code No. Type of Process Unit 

1 Atmospheric crude distillation 

2 Vacuum distillation 

3 Delayed coking 

4 Fluid coking (traditional) 

5 Flexicoking 

6 Visbreaking, other thermal cracking 

7 Fluid catalytic cracking unit 

8 Non-fluid catalytic cracking unit 

9 Catalytic hydrocracking 

10 Catalytic reforming unit – continuous regeneration 

11 Catalytic reforming unit – cyclic regeneration 

12 Catalytic reforming unit – semi-regenerative 

13 Fuels solvent deasphalting 

14 Desulfurization/ hydrotreat – naphtha/reformer feed 

15 Desulfurization/ hydrotreat – gasoline 

16 Desulfurization/ hydrotreat – kerosene/jet fuel 

17 Desulfurization/ hydrotreat – diesel 

18 Desulfurization/ hydrotreat – other distillate 

19 Desulfurization/ hydrotreat – residual 

20 Desulfurization/ hydrotreat – heavy gas oil 

21 Desulfurization/ hydrotreat – other 

22 HF alkylation 

23 H2SO4 alkylation 

24 Aromatics production 

25 Asphalt production 

26 Isomerization – Isobutane 

27 Isomerization – Iso C5,C6 

28 Lubricants production 

29 Petroleum coke storage 

30 Hydrogen plant 

31 Sulfur plant 

32 Gas plant (LPG production unit) 

33 Oxygenate plant – MTBE 

34 Oxygenate plant – ETBE 

35 Oxygenate plant – TAME 

36 Oxygenate plant – other (specify) 

99 Other (specify) 

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Process-specific 

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Process-specific 

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Number of pressure relief devices routed to fuel gas system or control device 

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Number of pressure relief valves equipped with rupture disk or second valve 

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If you monitor your pressure relief devices for leaks/releases, how many are 

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TABLE 5-1. E-Cat and FCCU Fines Metal Concentration 

CCU ID 

Particle Type 

Concentration (parts per million by weight, ppmw) 

Antimony 

Arsenic 

Beryllium Cadmium 

Chromium 

Cobalt 

Lead 

Manganese 

Mercury 

Nickel 

Selenium 

Vanadium 

 E-cat 

 Fines 

 E-cat 

 Fines 

 E-cat 

 Fines 

 E-cat 

 Fines 

3. Please provide information requested in Table 5-2 for each CCU at the facility. 

4. For each CCU listed in Table 5-2, also provide criteria pollutant and HAP emission 

estimates (tons/yr) following the methods provided in the Emission Estimation Protocol 

for Petroleum Refineries using the emissions template in Annex A of this part. 

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5

 Select from the following list the combination that best describes the monitoring methods and 

frequencies for the unit. List all that apply. For example, select 1B and 4E if you conduct 

daily visual inspections and quarterly measurements using El Paso stripping column. 

Code No. Monitoring Method Code Letter Monitoring Frequency 

1 Visual inspection A Continuous 

2 Chemical addition rates B Daily 

3 Measurement of redox potential C Weekly 

4 El Paso stripping column D Monthly 

5 TOC/VOC/Organic HAP water 

measurements 

E Quarterly 

99 Other (specify) Z Other (specify) 

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3. Please provide the information requested in Table 14-1 for the wastewater collection 

system components. 

TABLE 14-1. Wastewater Collection System Components 

Component 

Number 

Controlled 

Number 

Uncontrolled Control Technologies1

Drain 

Trench 

Manhole 

Junction Box 

Sump 

Lift Station 

Weir 

Footnotes for Table 14-1: 

1

 Select from the following list of control technologies. 

Code No. Type of Control Technology 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

52 Carbon adsorber 

53 Flare 

70 Water seal 

71 Fixed seal 

72 Hard piping 

90 Performance-based standard (specify) 

99 Other (specify) 

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6 Activated-sludge biological treatment unit 

7 Aerated surface impoundment 

8 Non-aerated surface impoundment 

9 Anaerobic sludge digester 

10 Aerobic sludge digester 

11 Other biological treatment unit (trickling filter, rotating biological contactor) 

12 Primary clarifier 

13 Secondary clarifier 

14 Other (specify) 

5. Please provide the information requested in Table 14-2 for each wastewater collection or 

treatment unit (WWTU) at the facility. For wastewater collection system components, 

you may aggregate all similar components as a single unit ID number (all drains, all 

sumps, all lift stations, all junction boxes, et cetera). 
6. For each WWTU listed in Table 14-2, also provide criteria pollutant and HAP emission 

estimates (tons/yr) following the methods provided in the Emission Estimation Protocol 

for Petroleum Refineries using the emissions template in Annex A of this part. 
TABLE 14-2. Wastewater Collection and Treatment Unit Information 

WWTS ID Number 

WWTU ID Number 

WWTU Type1

WWTU Design Flow 

Capacity (MMgal/day) 

Indicate Covered or 

Open 

If subject to Federal 

regulation(s), provide the 

citation(s) 

If subject to State, local, 

or Tribal regulation(s), 

provide the citation(s) 

WWTU Monitoring 

Method and Frequency2

WWTU Dimensions 

(surface area x water 

depth) 

Compliance 

Applicablity3

Emission Reduction 

Method4

 
Footnotes for Table 14-2: 

1

 Select from the following list of WWTU types. If the WWTU type is part of the wastewater 

collection system, enter “0” followed by the code letter that best describes the collection 

system component (e.g., select 0A for drains). 

Code No. Type of WWTU Code Letter Collection System Component 

0 Wastewater collection system A Drain 

 B Trench 

 C Manhole 

 D Junction box 

 E Sump 

 F Lift station 

 G Weir 

 Z Other (specify) 

1 Steam stripper 

2 Oil-water separator 

3 Dissolved air/gas flotation 

4 Equalization basin 

5 Neutralization basin 

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. List all that apply. For example, select 13A, 12B, and 22E if you continuously monitor 

dissolved oxygen concentration, perform daily MLVSS analyses, and perform quarterly 

benzene concentration analyses. 

Code No. Monitoring Parameter Code Letter Monitoring Frequency

0 None A Continuous 

1 Inlet water temperature B Daily 

2 Outlet water temperature C Weekly 

3 Inlet water flow rate D Monthly 

4 Outlet water flow rate E Quarterly 

5 Steam temperature Z Other (specify) 

6 Steam usage rate 

7 COD inlet concentration 

8 COD outlet concentration 

9 BOD inlet concentration 

10 BOD outlet concentration 

11 MLSS concentration 

12 MLVSS concentration 

13 Dissolved oxygen concentration 

14 Sludge age 

15 Solids retention time 

16 F/M ratio 

17 Oxygen uptake rate 

18 Wastewater flow rate 

19 Sludge wasting rate 

20 Volatile organic compounds (VOC) 

21 Organic hazardous air pollutants (Organic HAP) 

22 Benzene 

23 Phenol 

24 Hydrogen sulfide 

25 Oil and grease 

26 Inlet pH 

27 Outlet pH 

28 TSS inlet concentration 

29 TSS outlet concentration 

30 Phosphorus removal from effluent 

31 TOC concentration as an alternative to BOD 

32 Chlorine outlet concentration 

33 Chorine consumption 

99 Other (specify) 
3

 Select 

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