Enclosure 1 Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

Petroleum Refinery 

Emissions Information Collection 

General Instructions 

Please provide the information requested in this enclosure and, if applicable, Enclosure 2 

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 2009 calendar year as the base year for all survey responses (e.g., 2009 emissions 

inventory, 2009 throughput, 2009 equipment configurations) unless another year is specified in 

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

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

the address noted below within 90 days of receipt of your Section 114 letter: 

• 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 16. 

• Part VI – Crude Oil Composition Analysis: Conduct an analysis of the 

composition of each type of crude at the refinery. 

Emissions testing according to Enclosure 2 is to be completed by facilities with process 

units selected for testing. The Section 114 letter you received indicates if a unit at your refinery 

has been selected for testing. For units requiring stack tests, emissions tests (consisting of three 

runs per test method required) are to be conducted according to Enclosure 2 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 Enclosure 2 for sampling the wastewater treatment 

system. The results of the emissions tests and other requested analyses should be returned to 

EPA within 6 months of receipt of this questionnaire. 

 

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. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

2 

The electronic version of the survey (Parts I, II, III, and IV of this Enclosure 1) is in 

Microsoft® Excel format and can be downloaded from the ICR website (http://icr2010.rti.org, 

click on “Petroleum Refineries”). 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 Mr. Bob Lucas at 

(919) 541-0884 or lucas.bob@epa.gov or 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 

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 any 

information claimed as CBI and the other containing all other information (hereafter referred to 

as “non-CBI”). These two packages should be sent to EPA separately, using two different 

mailing addresses. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

3 

Separating CBI and Non-CBI 

After you have completed and reviewed 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 only the CBI portion of your survey response. 

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 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 (http://icr2010.rti.org, click on “Petroleum 

Refineries”). 

• 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: 

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. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

4 

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. ____-____ 

Approval Expires __/__/__ 

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. ____-____ 

Approval Expires __/__/__ 

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 __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

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 

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) 

UV ultraviolet 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

8 

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. 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. Plant Name (as reported on U.S. DOE/EIA Form-820 (2009), “Annual Refinery Report,” 

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

_________________________________________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

4b. Does this facility report in EIA-820 the combined processing/production capacities for 

refining plants that are not contiguously located? Yes No

4c. If Yes, provide the name and location for each non-contiguous facility: _______________ 

_________________________________________________________________________ 

________________________________________________________________________ 

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

_________________________________________________________________________ 

_________________________________________________________________________ 

 

2

 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. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

10 

6. Provide mailing address if different: ___________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

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

survey: __________________________________________________________________ 

_________________________________________________________________________ 

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

 and e-mail address(es): _____________________________________________________ 

9. Dunn and Bradstreet number of your facility: ___________________________________ 

10. Annual revenue in 2009: $______________________ 

11. Number of employees at your facility: _________________________________________ 

12a. Are you part of a larger corporate entity? Yes No

12b. If Yes: Name of parent company: ____________________________________________ 

Number of employees in parent company: ___________________________ 

Corporate crude oil processing capacity: (bbl/stream day) 

12c. If Yes, 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.) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

11 

13. Circle all applicable code number(s) for the final products produced at the 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): ___________________________________________________ 
O

12 

14. Report the number of processes and 2009 process throughputs by completing the table below. 

Attachment 1 to this enclosure is a copy of the EPA’s 2005 National Scale Air Toxics Assessment (NATAInventory (NEI) data set for each of your refineries (if available) for your reference. When asked for a Uni

and 16, please use the same identifying number or code that is used in the NEI data set (if possible and/or adoes not show an entry for a particular unit, or you are not sure what units are included in the NEI data set, 

for each process unit. 

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 
O

13 

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). 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

14 

15. Provide location information for each of the major processing units at the facility. 

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. (See 

instructions to Part II, Annex A for additional details on latitude and longitude format.) 

Unit 1 Unit 2 Unit 3 Unit 4 

Processing Unit Lat Long Lat Long Lat Long Lat Long

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 regeneration 

Catalytic reforming unit – semi-regenerative 

Fuels solvent deasphalting 

Desulfurization/ hydrotreat – naphtha/CRU feed 

Desulfurization/ hydrotreat – gasoline 

Desulfurization/ hydrotreat – kerosene/ jet fuel 

Desulfurization/ hydrotreat – diesel 

Desulfurization/ hydrotreat – other distillate 

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 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 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

15 

PART II: PROCESS AND EMISSIONS INFORMATION 

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. When asked for a Unit ID in any section of 

Part II, please use the same identifying number or code that is used in 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. 

SECTION 1. ENERGY MANAGEMENT 

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

2. Complete Table 1-1 below to provide the total energy use by the refinery in 2009: 

TABLE 1-1. 2009 Fuel Consumption 

Fuel Units Fuel Consumption 

Crude Oil bbl 

LPG bbl 

Distillate Fuel Oil bbl 

Residual Fuel Oil bbl 

Still Gas MMcf 

Petroleum Coke Tons (US) 

Catalyst Coke Tons (US) 

Natural Gas MMcf 

Coal Tons (US) 

Purchased Electricity MWh 

Purchased Steam MM lb 

Other bbl 

Abbreviations: bbl = barrels 

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

MWh = Megawatt-hours 

MM lb = million pounds 

3. Does this refinery generate electricity on-site? Yes No

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

unit. Include energy recovery turbines used on process unit exhaust lines. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

16 

TABLE 1-2. Electricity Generation Information 

Unit ID 

Number Unit Description 

Capacity of 

Unit (MW) 

Primary 

Fuel 

Secondary 

Fuel 

Disposition of 

electricity1

 

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 

 

Abbreviations: 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”). 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

17 

2

 For disposition of steam, enter appropriate code number as follows: 

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

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

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

3

 Enter the code number for each energy efficiency measure used with this steam-generating unit; list all 

that apply: 

0 None 

1 Insulation on boiler 

2 Insulation on distribution lines 

3 Oxygen and intake air monitors to optimize fuel/air mixtures and limit excess oxygen 

4 Combustion air preheat from flue gas 

5 Boiler feed water preheat from flue gas 

6 Blowdown steam recovery system for low pressure needs 

7 Boiler maintenance program (to reduce scaling; maintain burners) 

8 Steam trap maintenance program 

9 Steam condensate return lines 

10 Steam expansion turbines 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

18 

5. Provide the information requested in Table 1-4 for each processing unit listed in 

Questions 14 and 15 of Part I (except wastewater treatment). 

TABLE 1-4. Steam Demand and Process Heater Capacity by Process Unit 

Unit ID 

Processing 

Unit Type1

Steam 

demand at 

capacity 

for the 

processing 

unit (lb/hr) 

Total 

number of 

process 

heaters 

Cumulative 

rated heat 

capacity of 

process heaters 

for process unit 

(MMBtu/hr) 

Number of 

process 

heaters 

with air 

preheat 

Cumulative rated 

heat capacity of 

process heaters 

with air preheat 

for process unit 

(MMBtu/hr) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

19 

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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

20 

SECTION 2. PROCESS HEATER DATA 

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

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

facility. 

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. 

TABLE 2-1. Process Heater General Information 

Process Heater ID 

Process unit served by 

process heater1

Process heater construction 

type2

Process heater draft type3

Primary fuel4

Secondary fuel4

Rated heat capacity 

(MMBtu/hr) 

Average heat input rate in 

2009 (MMBtu/hr) 

Total operating hours in 2009 

(hr) 

Operating hours while cofired in 2009 (hr) 

Operating hours in turndown 

in 2009 (hr) 

If subject to Federal 

regulation(s), provide the 

citation(s) 

If subject to State, local, or 

Tribal regulation(s), provide 

the citation(s) 

Type of PM controls5

Type of SO2 controls6

Type of NOX controls7

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

21 

Footnotes for Table 2-1: 

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

 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

22 

3

 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 (blast air-side fan only) 

5 Balanced draft/air preheat (both air- and exhaust-side fans) 

99 Other (specify) 

4

 Select from the following list of fuels. 

Code No. Fuel Type 

1 Natural gas 

2 Refinery fuel gas 

3 Distillate oil 

4 Heavy gas oil 

99 Other (specify) 

5

 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 

98 Management practice or work practice (specify) 

99 Other (specify) 

6

 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 heavy gas oil 

24 Wet scrubber/flue gas desulfurization 

25 Spray dryer absorber 

98 Management practice or work practice (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

23 

7

 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 (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

24 

SECTION 3. EQUIPMENT LEAKS 

 

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

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. Do you routinely monitor your fuel gas system for leaks? Yes No

4. Complete Table 3-1 for each process unit listed in Part I, Questions 14 and 15 (except 

wastewater treatment) and for each fuel gas and natural gas system at the facility. 

 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. 
O

25 

TABLE 3-1. Process-specific Equipment Component and Leak Detection Information 

Pumps Valves Flanges Connectors 

Openended 

lines 

Light 

liquid 

Heavy 

liquid Gas Light liquid Heavy liquid Gas Light liquid Heavy liquid Gas Light liquid Heavy liquid Any 

Unit ID 

Process Unit Type

1

Applicable Federal regulation(s)

2

If subject to State, local, or Tribal 

regulation(s), provide the citation(s) 

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv)

4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4

Number of Components 

Monitoring Frequency

3

Leak Definition (ppmv) 4
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

26 

Footnotes for Table 3-1: 

1

 Select 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

27 

2

 Select the Federal regulation to which the process unit is applicable from the following list of 

regulations. 

Code No. Federal 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 40 CFR part 60, subpart VV 

4 40 CFR part 60, subpart GGG 

5 40 CFR part 60, subpart VVa 

6 40 CFR part 60, subpart GGGa 

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

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

99 Other (specify) 

3

 Select from the following list of monitoring frequencies that best applies for the process unit, 

equipment component, and type of service. 

Code No. Monitoring Frequency 

0 None (unit/system not monitored for leaks) 

1 Less than annually 

2 Annually 

3 Semiannually 

4 Quarterly 

5 Monthly 

6 Biweekly 

7 Weekly or more frequently 

4

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

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

type of service. 

Code No. Leak Definition 

0 None (unit/system not monitored for leaks) 

1 10,000 ppmv 

2 5,000 ppmv 

3 2,000 ppmv 

4 1,000 ppmv 

5 500 ppmv 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

28 

6. Provide the information requested in Table 3-2 regarding pressure relief devices on each 

process unit listed in Part I, Questions 14 and 15 (except wastewater treatment) and for 

each fuel gas and natural gas system at the facility. 

TABLE 3-2. Pressure Relief Devices 

Unit ID 

Process Unit Type1

Total number of pressure 

relief devices 

Number of pressure relief 

devices routed to fuel gas 

system or control device 

Type of controls2

Number of pressure relief 

valves equipped with 

rupture disk or second valve 

If you monitor your 

pressure relief devices for 

leaks/releases, how many 

are monitored using a 

system designed to measure 

the duration of a release and 

the quantity of compounds 

released? 

If you have a monitoring 

system that measures the 

duration of a release and the 

quantity of compounds 

released, describe the system 

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

29 

Footnotes for Table 3-2: 

1

 Select from the following list of process 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 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

30 

2

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

Code No. Type of Control 

0 None 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

52 Carbon adsorber 

53 Flare 

98 Management practice or work practice (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

31 

SECTION 4. STORAGE TANKS 

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

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

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. 

TABLE 4-1. Storage Tank General Information 

For tanks with 

EFR or IFR

Tank ID 

Type of stored liquid1

Vapor pressure of stored liquid at average 

liquid storage temperature in 2009 (psi) 

Average liquid storage temperature in 2009 

(°F) 

Type of tank/controls2

Diameter (ft) 

Height (ft) 

Maximum liquid height (ft) 

Total throughput for all materials stored in 

the tank in 2009 (bbl) 

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

If subject to Federal regulation(s), provide 

the citation(s) 

If subject to State, local, or Tribal 

regulation(s), provide the citation(s) 

Year in which the tank was last degassed 

Type of control for last degassing event3

Was the tank cleaned during last degassing 

event? (Yes/No) 

Year in which you anticipate the next 

degassing event 

Minimum height of floating roof above 

the floor at the shell when landed 

Number of times floating roof landed 

in 2009 

Number of times the tank was emptied 

after roof landed in 2009 

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

32 

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 Intermediate naphtha 

4 Intermediate distillate oil 

5 Intermediate heavy gas oil 

6 Gasoline/blending stocks 

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) 

99 Other (specify) 

2

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

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 guidepolesa

5 External floating roof with solid guidepolesb

6 External floating roof, controlled guidepolesc

7 Internal floating roof, slotted guidepolesa

8 Internal floating roof with solid guidepolesb

9 Internal floating roof, controlled guidepolesc

10 External floating roof with geodesic dome roof 

11 Horizontal tank 

12 Pressurized/sphere tank 

99 Other (specify) 

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 __/__/__ 

33 

3

 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

34 

SECTION 5. CATALYTIC CRACKING UNIT 

 

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

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

values for each catalytic cracking unit (CCU) at the facility in the Table 5-1 below. 

TABLE 5-1. E-Cat and FCCU Fines Metal Concentration 

Concentration (parts per million by weight, ppmw) 

CCU ID 

Particle Type 

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. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

35 

TABLE 5-2. Catalytic Cracking Unit Information 

CCU ID 

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)? 

If subject to Federal 

regulation(s), provide the 

citation(s) 

If subject to State, local, or 

Tribal regulation(s), provide the 

citation(s) 

Nickel Concentration in 

Combined Feed (wt%) 

Vanadium Concentration in 

Combined Feed (wt%) 

Type of PM controls1

Type of SO2 controls2

Type of NOX controls3

 

Footnotes for Table 5-2: 

1

 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 

98 Management practice or work practice (specify) 

99 Other (specify) 

2

 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 

98 Management practice or work practice (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

36 

3

 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 (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

37 

SECTION 6. FLUID COKING UNIT 

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

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

facility. 

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. 

TABLE 6-1. Fluid Coking Unit Information 

If traditional coker If flexicoker 

FCU ID 

Feed Capacity (bbl/cd) 

Type of FCU (traditional or 

flexicoker) 

If subject to Federal regulation(s), 

provide the citation(s) 

If subject to State, local, or Tribal 

regulation(s), provide the citation(s) 

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 controls1

Type of SO2 controls2

Type of NOX controls3

Produced Coke Handling 

Controls and Disposition4

Low Btu gas production rate at 

capacity (scfm) 

Low Btu gas sulfur removal 

technique5

FCU dust/ash quantity 

produced (tons/cd) 

FCU dust/ash handling/disposal 

method6

 

Footnotes for Table 6-1: 

1

 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 

98 Management practice or work practice (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

38 

2

 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 

98 Management practice or work practice (specify) 

99 Other (specify) 

3

 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 (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

39 

4

 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) 

5

 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., DMEA) 

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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

40 

6

 Select from the following list of flexicoking dust/ash handling and disposal methods. 

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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

41 

SECTION 7. DELAYED COKING UNIT 

 

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

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. 

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. 

TABLE 7-1. Delayed Coking Unit Operating Information 

DCU ID 

Feed Capacity (bbl/cd) 

Coke Production Capacity (tons/cd) 

Number of Coke Drums 

Height of Single Coke Drum (ft) 

Diameter of Single Coke Drum (ft) 

Typical Coke Drum Outage (ft) 

If subject to Federal regulation(s), provide the 

citation(s)

If subject to State, local, or Tribal regulation(s), 

provide the citation(s)

Complete Coke Drum Cycle Time (hr)1

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) 

Coke Drum Pressure When First Vented to 

Atmosphere (psig) 

Coke Drum Temperature at Top of Drum When 

First Vented to Atmosphere (°F) 

Water Height in Coke Drum When First Vented 

to Atmosphere (ft) 

Water Quenching Cycle Description2

Typical Quench Water Flow Rate during 

Que

nchin

g Cycle (g

al/min)

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

Blowdown System Description3

Cutting Water Storage/Handling4

 

Footnotes for Table 7-1: 

1

 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. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

42 

2

 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) 

3

 Select from the following list of blowdown system descriptions. 

Code No. Condensed Water Disposition Code Letter 

Uncondensed Vapor Disposition 

When Not Sent 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 atmospheres 

 H Uncondensed vapors are vented directly 

to atmosphere 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

43 

4

 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) 

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

facility. You may list multiple DCU IDs 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 

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

Feed Source 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): ____________ 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

44 

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%. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

45 

SECTION 8. CATALYTIC REFORMING UNIT 

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

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

(CRU) at the facility. 

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. 

TABLE 8-1. Catalytic Reforming Unit Information 

CRU ID 

Feed Capacity (bbl/cd) 

Operating Pressure 

Hydrogen Production Rate 

(MMscf/cd) 

Type of CRU Regeneration 

(continuous, cyclic, or 

semi-regenerative) 

If subject to Federal regulation(s), 

provide the citation(s) 

If subject to State, local, or Tribal 

regulation(s), provide the citation(s) 

Average Annual Regeneration Time 

(hours/year) 

Average Annual Regeneration 

Frequency (cyclic and semi-regen 

units; regeneration cycles/year) 

Depressurization /Purge Cycle Vent 

Disposition/control1

Purge Process Type2

Coke Burn-off Cycle Vent 

Disposition/control3

Coke Burn-off Cycle Duration per 

Cycle 

Rejuvenation Cycle Vent 

Disposition/control4

Chloriding Agent5

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

46 

Footnotes for Table 8-1: 

1

 Select from the following list of purge controls. 

Code No. Type of Depressurization/Purge Control 

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 

99 Other (specify) 

2

 Select from the following list of purge processes. 

Code No. Type 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) 

3

 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 Chlorsorb 

98 Management practice or work practice (specify) 

99 Other (specify) 

4

 Select from the following list of rejuvenation controls. 

Code No. Type Rejuvenation Controls 

1 Purge by sequential pressurizing/purging with nitrogen 

2 Purge using nitrogen and vacuum pump 

98 Management practice or work practice (specify) 

99 Other (specify) 

5

 Select from the following list of chloriding agents. 

Code No. Type of Chloriding Agent 

1 Perchloroethylene 

2 Trichloroethene 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

47 

SECTION 9. SULFUR RECOVERY UNIT 

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

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

the facility. 

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. 

TABLE 9-1. Sulfur Recovery Unit Information 

SRU ID 

Sulfur, Sulfur Cake or H2SO4

Production Capacity (long tons 

of sulfur/cd) 

Type of SRU1

If subject to Federal 

regulation(s), provide the 

citation(s) 

If subject to State, local, or 

Tribal regulation(s), provide the 

citation(s) 

Type of Tail Gas Treatment 

Unit2

Sulfur Pit Controls 

Sulfur Pit Maintenance Time 

(hr/yr) 

SRU Back-up 

Controls/Reduction Measures3

 

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

48 

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

 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) 

3

 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

49 

SECTION 10. HYDROGEN PLANT VENT 

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

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

facility. 

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. 

TABLE 10-1. Hydrogen Plant and Vent Information 

Hydrogen Plant ID 

Hydrogen Production 

Capacity (MMscf/cd) 

Type of Hydrogen 

Production Unit1

If subject to Federal 

regulation(s), provide 

the citation(s) 

If subject to State, local, 

or Tribal regulation(s), 

provide the citation(s) 

Hydrogen Purification 

Method Used2

Type of Feedstock 

Used3 

Steam Generation Rate 

(lb/hr) 

PSA Purge/Off Gas Flow 

Rate (scfm) 

PSA Purge/Off Gas 

Disposition4 

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) 

2

 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

50 

3

 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) 

4

 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

51 

SECTION 11. OTHER ATMOSPHERIC VENTS 

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

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 other than those covered in Sections 5 through 10 of this part 

(Part II). “Other atmospheric vents” include vents on blowdown systems, knock-out 

pots, vacuum ejectors, and sampling systems as well as vents from oxygenate production 

units, coke calcining units, ethylene production units, and other process units co-located 

at the facility. “Other atmospheric vents” do not include vents associated with storage 

tanks or pressure relief vents where venting occurs only during upset, startup, or 

shutdown events. For “other atmospheric vents” controlled by flares, also complete 

Table 12-1 to describe the flare. 

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. 

TABLE 11-1. Other Atmospheric Vent Information 

Atmospheric Vent 

ID 

Description of 

Atmospheric Vent 

Type of 

Unit/Equipment to 

Which the Vent is 

Associated1

If subject to 

Federal 

regulation(s), 

provide the 

citation(s) 

If subject to State, 

local, or Tribal 

regulation(s), 

provide the 

citation(s) 

Atmospheric Vent 

Operating Hours2

Atmospheric Vent 

Controls3

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

52 

Footnotes for Table 11-1: 

1

 Select from the following list of processes and equipment that best describe the type of unit or 

equipment associated with this vent. 

Code No. Type of Unit/Equipment Associated with Vent 

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 

40 Blow down system 

41 Knock-out pot 

42 Analyzer 

43 Vacuum jet exhaust 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

53 

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 Coke calcining 

99 Other (specify) 

2

 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 

6 Only during startup or shutdown 

7 Only during upsets 

8 Only during startup, shutdown, or upsets 

3

 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 

53 Flare 

98 Management practice or work practice (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

54 

SECTION 12. FLARES 

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

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

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. 

TABLE 12-1. Flare Information 

Flare ID Number or 

Description 

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

If subject to Federal 

regulation(s), provide 

the citation(s) 

If subject to State, local, 

or Tribal regulation(s), 

provide the citation(s) 

Typical Lower Heating 

Value of Waste Gas 

(Btu/scf @ 60°F) 

Flare Operating Hours4

Flare Controls5

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

55 

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 from the following list of operating scenarios. 

Code No. Type of Operation 

1 Operates 4,000 hours per year or more 

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

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

4 Intermittent; less than 1,000 hours per year 

5 Only during startup or shutdown 

6 Only during upsets 

7 Only during startup, shutdown, or upsets 

5

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

Code No. Type of Control Device 

1 Amine treatment 

2 Flare gas recovery 

3 Flare minimization plan 

98 Other management practice or work practice (specify) 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

56 

SECTION 13. COOLING WATER SYSTEMS 

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

2. Please provide information requested in Table 13-1 for each cooling water system at the 

facility. 

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. 

TABLE 13-1. Cooling Water System Information 

Cooling System ID 

Number or Description 

Process Units Serviced 

by Cooling Water 

System1

Cooling Water System 

Operation2

Type of Cooling Water 

System3

If subject to Federal 

regulation(s), provide 

the citation(s) 

If subject to State, local, 

or Tribal regulation(s), 

provide the citation(s) 

Cooling Water Flow/ 

Recirculation Rate 

(gal/min) 

Water Make-up Rate 

(gal/min) 

Gas or Chemical 

Additive/Disinfection 

Method4

Gas or Chemical 

Addition Rate Value 

Gas or Chemical 

Addition Rate Units 

(volume or mass per 

time) 

Chemical Addition 

Location 

Monitoring Method and 

Frequency5

Leak Definition 

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

57 

Footnotes for Table 13-1: 

1

 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

58 

2

 Select from the following list of cooling water system operations. 

Code No. Type of Cooling Water System Operation 

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

than the minimum water pressure 

2 Services only heater exchangers in which the process fluid contains less than 5 wt% VOC 

3 Services only heater exchangers in which the process fluid contains at least 5 wt% VOC 

but less than 5 wt% organic HAP 

4 Services heater exchangers 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 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) 

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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

59 

SECTION 14. WASTEWATER COLLECTION AND TREATMENT 

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

2. Please provide the following information regarding the facility-wide wastewater 

collection and treatment system (WWTS). 

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

b. 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 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

60 

4. Circle the response below that best describes the first process unit in the wastewater 

treatment system that is uncovered or that is covered but not vented to a control device. 

1 Steam stripper 

2 Oil-water separator 

3 Dissolved air/gas flotation 

4 Equalization basin 

5 Neutralization basin 

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. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

61 

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

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

62 

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 

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 

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

OMB Control No. ____-____ 

Approval Expires __/__/__ 

63 

2

 Select from the following list the combination that best describes the monitoring parameters 

and frequencies for the unit. 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

64 

3

 Select from the following list of compliance applicability options. List all compliance 

applicability options that apply to the unit (if more than one option applies). 

Code No. Compliance Applicability 

0 The unit is not subject to any air standards. 

1 The unit is subject to BWON but exempted from control requirements under the 2 Mg 

exclusion. 

2 The unit is subject to BWON but exempted from control requirements as an “enhanced 

biodegradation unit.” 

3 The unit is subject to BWON control requirements. 

4 The unit is subject to and utilized for compliance with the Hazardous Organic NESHAP 

(40 CFR part 63, subpart G). 

5 The unit is subject to the Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ). 

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 __/__/__ 

65 

SECTION 15. SOLID WASTE MANAGEMENT 

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

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

_________________________________________________________________________ 

_________________________________________________________________________ 

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. 

TABLE 15-1. Solid Waste Management Unit Information 

Unit 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) 

If subject to Federal 

regulation(s), provide 

the citation(s) 

If subject to State, local, 

or Tribal 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 Used2

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

66 

Footnotes for Table 15-1: 

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 

99 Other (specify) 

2

 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) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

67 

SECTION 16. LOADING AND UNLOADING OPERATIONS 

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

2. Please provide the information requested in Table 16-1 for each loading and unloading 

operation at the facility. If you load/unload more than one commodity in a particular 

location (e.g., marine vessel berth, loading rack), use a separate line for each type of 

commodity loaded/unloaded at that location. 

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. 

TABLE 16-1. Loading and Unloading Information 

Unit (location) ID 

Type of vessel loaded/unoaded1

Type of liquid commodity 

loaded/unloaded2

Actual loading throughput 

(gal/yr) 

Capacity loading throughput 

(gal/yr) 

If subject to Federal 

regulation(s), provide the 

citation(s) 

If subject to State, local, or 

Tribal regulation(s), provide 

the citation(s) 

Typical annual operating 

hours (hr/yr) 

Year loading operation 

installed 

Does the facility or parent 

company own the vessels being 

loaded? (Yes/No) 

Type of control device or 

control technique3

Date control device or control 

technique was installed 

 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

68 

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 

99 Other (specify) 

2

 Select from the following list of liquid commodities. 

Code No. Type of Liquid Commodity 

1 Unstabilized crude oil 

2 Stabilized crude oil 

3 Intermediate naphtha 

4 Intermediate distillate oil 

5 Intermediate heavy gas oil 

6 Gasoline/blending stocks 

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) 

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 

53 Flare 

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 

83 Vapor balancing system 

98 Other management practice or work practice (specify) 

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

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69 

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 __/__/__ 

70 

ANNEX A to PART II. EMISSIONS INVENTORY DATA 

The U.S. EPA is working to fulfill its obligation under CAA sections 112(f)(2) and 112(d)(6) to 

review residual risk and perform a technology review of the petroleum refinery NESHAP 

subparts CC and UUU. Emission data sets provided by the individual refineries will be used for 

EPA’s residual risk and technology review (RTR). Attachment 1 to this enclosure is a copy of 

the EPA’s 2005 NATA NEI data set for each of your refineries (if available) for your reference. 

For each unit listed for which data was requested in Part II, provide emission estimates (tons/yr) 

for the 2009 calendar year for individual HAP and criteria pollutants following the methods 

provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions 

template provided in this annex. Instructions for completing the table are provided below. 

1. Unit ID: Use the same identification number that you provided in Part II, Sections 2 

through 16. 

2. Unit description: Provide a short description of the unit; if the name of the unit in your 

operating permit includes the type of unit, you may use that name as your description 

(e.g., FCCU 02, Tank 456). 

3. SCC: Attachment 2 to this enclosure provides source classification codes (SCC) 

extracted from the NEI database lookup tables. There have been updates (both additions 

and deletions) to the SCC over the years, and the list in Attachment 2 contains the current 

list of SCC that EPA would like you to use for this inventory. If a code that you have 

used in the past no longer appears in the applicable lookup table, please select the most 

appropriate code from those listed. 

4. Emission point ID: Provide the identification number or code for the location at which 

emissions are released into the environment. 

5. Emission point description: Provide a description of the location at which emissions are 

released into the environment. 

6. Pollutant name: Enter the name of the pollutant for which you are estimating emissions. 

You will need to enter only one pollutant per row; for most units, it will take multiple 

rows to provide emissions estimates for all pollutants. 

7. Pollutant CAS No. or Pollutant Code: See Table 1-1 of the Emission Estimation Protocol 

for Petroleum Refineries for a list of CAS numbers and Pollutant Codes for selected 

pollutants. 

8. 2009 emissions (tons): All emissions reported in this column should reflect the 

ACTUAL emissions during normal operation for the reported calendar year. (If you use 

a CEMS/CMS to monitor emissions of a particular pollutant, the readings for the entire 

year were within the calibrated span of the CEMS/CMS, and you have completed the 

CEMS Template or CMS Template for that monitor, then you may report the total 

emissions recorded by that CEMS/CMS in this column.) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

71 

9. Protocol methodology rank used: Provide the rank number from the appropriate chapter 

of the Emission Estimation Protocol for Petroleum Refineries that best describes how you 

estimated emissions for the unit and pollutant provided in this row. If any of your 

emissions sources is not included in the Emission Estimation Protocol for Petroleum 

Refineries (e.g., an ethylene unit), enter “N/A” 

10. 2009 non-routine emissions (tons): All emissions reported in this column should reflect 

the ACTUAL emissions during any non-routine operation for the reported calendar year, 

including startups, shutdowns, and other events. (If you use a CEMS/CMS to monitor 

emissions of a particular pollutant and the readings for part of the year were not within 

the calibrated span of the CEMS/CMS, estimate emissions of that pollutant from the 

process unit during that event.) 

11. Maximum hourly emissions (lb/hr): Enter the maximum actual emissions from the unit 

in any one hour of 2009. See the Emission Estimation Protocol for Petroleum Refineries

for additional information on how to determine hourly emissions. 

12. Annual emissions allowed by NESHAP (tons/yr): Enter the annual emissions during 

normal operation allowed by the NESHAP to which this unit is subject. If this unit is not 

subject to any NESHAP for this pollutant, enter “N/A.” (Note that if the NESHAP limit 

is on a concentration basis, you will need to use process data at maximum capacity to 

convert the limit to tons/yr.) 

13. Hourly emissions allowed by NESHAP (lb/hr): Enter the maximum hourly emissions 

during normal operation allowed by the NESHAP to which this unit is subject. If this 

unit is not subject to any NESHAP for this pollutant, enter “N/A.” (Note that if the 

NESHAP limit is on a concentration basis, you will need to use process data at maximum 

capacity to convert the limit to lb/hr.) 

14. Annual emissions allowed by permit (tons/yr): Enter the annual emissions during normal 

operation allowed by your operating permit (may be more stringent than the emissions 

limit under the applicable NESHAP). (Note that if the permit limit is on a concentration 

basis, you will need to use process data at maximum capacity to convert the limit to 

tons/yr.) If your permit does not have a numerical limit for emissions of this pollutant 

from this unit, enter “N/A.” 

15. Hourly emissions allowed by permit (lb/hr): Enter the maximum hourly emissions during 

normal operation allowed by your operating permit (may be more stringent than the 

emissions limit under the applicable NESHAP). (Note that if the permit limit is on a 

concentration basis, you will need to use process data at maximum capacity to convert 

the limit to lb/hr.) If your permit does not have a numerical limit for emissions of this 

pollutant from this unit, enter “N/A.” 

16. Type of Release (Point or Fugitive): Point releases are the emissions released from a 

facility unit that is included in the facility inventory through one or more stacks or vents. 

Fugitive releases are air pollutants released to the air other than those from stacks or 

vents, including small releases from leaking plant equipment such as valves, pump seals, 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

72 

flanges, or sampling connections, and large open area releases such as from landfills, 

waste ponds, or unpaved roads. 

17. Point Sources: Complete the columns listed below if you answered “Point” in Number 

16. 

Release Height (ft): Enter the height of the stack or vent from the ground. 

Internal Vent Diameter (ft): Enter the diameter of the stack or vent at the release height. 

Exit Temperature (°F): Enter the temperature of the exit gas stream 

Gas Flow Rate (acfm): Enter the flow rate of the exit gas stream. 

18. Fugitive Sources: Complete the columns listed below if you answered “Fugitive” in 

Number 16. 

Length (ft): Enter the dimension of the source in the east-west (x-) direction 

Width (ft): Enter the dimension of the source in the north-south (y-) direction 

Angle: The release angle is the orientation of the y-dimension relative to true North, 

measured positive for clockwise starting at 0 degrees (maximum 89 degrees). EPA will 

assume 0 degrees if it is not provided. 

19. Longitude and Latitude: Pay particular attention when entering emission release point 

stack parameters and locations. EPA requires latitude/longitude for each emission point 

provided in North American Datum (NAD) 83 with 6 digits to the right of the decimal 

point. These data are critical inputs to the modeling files that EPA will use to determine 

the risk profile for the residual risk review process.3

20. Comments: Provide any comments that you feel are necessary to qualify or explain any 

of your answers to the previous questions. 

 

3

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. 
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ANNEX A to PART II. EMISSIONS INVENTORY DATA 

Point Sources 

Unit ID 

Unit description 

SCC 

Emission point ID 

Emission point 

description 

Pollutant name 

Pollutant CAS No. or 

Pollutant Code 

2009 emissions (tons) 

Protocol methodology 

rank used 

2009 non-routine 

emissions (tons) 

Maximum hourly 

emissions (lb/hr) 

Annual emissions allowed 

by NESHAP (tons/yr) 

Hourly emissions allowed 

by NESHAP (lb/hr) 

Annual emissions allowed 

by permit (tons/yr) 

Hourly emissions allowed 

by permit (lb/hr) 

Type of Release 

(Point or Fugitive) 

Release Height 

(ft) 

Internal Vent 

Diameter (ft) 

Exit Temperature 

(°F) 

Gas Flow Rate 

(acfm) 

Length (ft) 
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74 

PART III. INCIDENCE REPORTS 

1. Complete the following table for each CERCLA air release notification made to the National Response Ce

Type of release 

(continuous or 

noncontinuous) Description of release event 

Process 

units 

associated 

with the 

release 

Duration of 

the release 

event 

(hours) 

Pollutant 

name 

Pollutant 

CAS No. 

Qua

pol

relea
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75 

2. Complete the following table for each flare, air emission, or odor complaint received over the past 5 years. 

If applicable, provide the... 

Complainant 

name 

Complainant 

contact 

information 

Date of 

complaint 

Substance of 

complaint 

Description of release 

event associated with 

complaint 

Process unit(s) 

associated with 

the release 

Dur

the 

e

(h
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

76 

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 10 years for which you have 

readily available cost information, please provide those costs as described in this part. 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 10 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 10 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 

• Combustion promoters or catalyst additives for NOX control from FCCU 

• Amine treatment systems 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

77 

• 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 pressure relief device) 

• Pollution prevention techniques 

• Other management practices or work practices that you identified in Part II 
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78 

Table 1. Cost Data for APCD1

CAPITAL COSTS ANNUAL OPERATING COSTS10

Purchased 

equipment 

costs ($)5 Utilities ($) 

Operating labor ($) 

Maintenance labor ($) 

Electricity 

Water 

Steam 

Natural gas 

Liquid chemicals 

Solid chemicals 

Compressed Air 

Other (specify) 

Waste disposal ($) 

Unit ID 

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 ($) 

Base year for capital costs 

Primary equipment ( $)

6

Auxiliary equipment ($)

7

Instrumentation and monitors ($) 

Sales tax and freight ($) 

Total purchased equipment costs ($) 

Installation costs ($)

8

Total Installed Cost of APCD

9

Base year for operating costs 

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 

Total utilities cost ($/yr)12

amt/yr11

$/

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 th

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 u

operation, enter “Retrofit.” 
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79 

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 

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

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 

for each utility. Add the individual utility annual costs to get the total utilities cost. 

13 Include major supplies and replacement parts; examples include catalyst for SCR and catalytic incinerators, bags of fabric filters, and carbon for carbo14 An example might be catalyst regeneration. Note that this question is not asking for costs of maintenance materials, capital recovery, overhead, admin

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 ye

monitoring, recordkeeping, and reporting; and any other items included under “other annual costs.” 
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80 

Code No. Type of APCD 

1 Amine treatment 2 Caustic spray injection 3 Packed-bed wet scrubber 4 Tray tower wet scrubber 5 Chlorsorb 11 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 Flare 54 Portable internal combustion engine 55 Portable thermal oxidizer 56 Portable condensation system 57 Permanent onsite control device for storage tanks 60 Flare gas recovery 83 Vapor balancing system 99 Other (specify) 
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81 

Table 2. Cost Data for Process and Equipment Changes 

Unit ID 

Process or 

equipment change 

description1

Year of process or equipment change 

Number of days 

process shut down 

in order to make 

the change (days 

of lost 

production)2

Total capital cost, 

$3

Change in total 

annual operating 

cost, $/yr4

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 

describe your process or equipment change. Be as descriptive as possible. For example, for installation of low NOX or ultra low NOX burners for a p

of new burners, their sizes, and the fuel options (e.g., fuel gas, oil). 

2 Enter number of days of lost production required to implement the process or equipment change. If the change occurred during scheduled downtime th

regardless of the process or equipment change, then do not include the scheduled downtime. Only the days of lost production that can be specifically 

equipment change are of interest. 

3 Please distinguish between one-time capital and annual operating costs where appropriate. If a breakdown of the specific capital or annual cost items i

separate attachment. 

4 Provide changes in annual operating costs (if estimated). Otherwise, leave blank. Include annual operating costs that are an increase to prior operating 

operating costs due to installation of low NOX burners). If the process or equipment change resulted in decreased annual operating costs, then indicat

negative number. 

5 Describe the air pollutants affected and emissions reduction achieved. Indicate the basis for emissions reduction reported (e.g., air emissions testing be

You may provide this information as a separate attachment to your response if you wish. 
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82 

Code No. Type of Process or Equipment Change 

1 Amine treatment 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 

below the liquid level during most of the filling) 

82 Bottom loading 99 Other (specify) 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

83 

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 16 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 (maximum of three tests per unit for one 

pollutant). 

In addition, complete the source test summary table shown in Attachment 3 of this 

enclosure for each source test you submit. (Electronic copies of this table can be 

downloaded from the ICR website (http://icr2010.rti.org, click on “Petroleum 

Refineries”).) Note that the information requested in the summary table includes: 

(A) emission rates measured, 

(B) the test method or procedure used, 

(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. 

2. Qualified CEMS Data: Provide qualified CEMS data for PM, CO, NOX, SO2, and THC 

CEMS on any of the processes or emission points included in Part II, Sections 2 through 

16. Report daily averages for each day in 2009 using the Microsoft® Excel CEMS 

Template; an example template is shown in Attachment 4. The Excel templates are 

specific to each pollutant and type of unit, and each template is designed to accommodate 

data from one CEMS (including oxygen data). Electronic copies of the template can be 

downloaded from the ICR website (http://icr2010.rti.org, click on “Petroleum 

Refineries”). 
Form Approved __/__/__ 

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84 

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. 

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 2009 using the Microsoft® Excel CMS Template; an example template is 

shown in Attachment 4. 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 (http://icr2010.rti.org, 

click on “Petroleum Refineries”). 

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. 

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. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

85 

PART VI. SUMMARY OF TEST PROCEDURES, METHODS, AND 

REPORTING REQUIREMENTS FOR CRUDE OIL COMPOSITION ANALYSIS 

The EPA petroleum refinery test program is requesting variability data for crude oil-based HAP. 

This part provides an overview of approved methods, target pollutants and units of measure, and 

reporting requirements for the crude oil composition analysis. All recipients must complete and 

submit test results within 90 days of receipt. 

The crude oil composition analyses requested include: mercury, chlorine, sulfur, and metals 

(e.g., antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and 

selenium). 

You will need to collect at least three samples of each crude oil received by your refinery, 

composite these samples, and then analyze and report each composited sample. Directions for 

collecting, preparing, and analyzing the crude oil samples are outlined below. 

Note: If you do not refine any crude oil at your facility, provide a list of the intermediate 

feedstocks that are refined by your facility and perform the analyses described below for those 

intermediate feedstocks in lieu of the crude oil composition analysis. 

1. How to collect a crude oil sample: Table 1 outlines a summary of how samples should be 

collected. 

Table 1. Summary of Sample Collection Procedures 

Sampling Location Sampling Procedures 

Site-Specific Sampling and Analysis 

Manual Sampling Follow collection methods outlined in ASTM D4057 

Automatic Sampling Follow collection methods outlined in ASTM D4177 

Crude Oil Supplier Analysis 

Crude Oil Supplier If you will be using crude oil analysis from a crude oil supplier in lieu of 

site-specific sampling and analysis, the crude oil supplier must collect the 

sample as specified above and prepare the sample according to methods 

specified in Steps 2 and 3 of this part. 

2. Prepare sample for analysis: To prepare your samples for mercury and selected metal 

analyses, use SW-846-3020A or any SW-846 sample digestion procedures giving 

measures of total metal. For other analyses, use the guidance in ASTM D7455-08 for 

appropriate sample preparation. 

3. Analyzing crude oil sample: Table 2 outlines a list of approved methods for analyzing 

crude oil samples. If you would like to use a method not on this list, and the list does not 

meet the definition of “equivalent” provided in Section 5 of this document, please contact 

EPA for approval of an alternative method. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

86 

Table 2. List of Analytical Methods for Crude Oil Analysis 

Analyte Method 

Target 

Reported Units 

of Measure 

Higher Heating Value ASTM-5865-03a, ASTM D240, ASTM E711-87 (1996) Btu/lb 

Density/API Gravity ASTM D287-92, ASTM D1217-993, ASTM D1481-93, 

ASTM D4052-96 

lb/ft3

 AND 

API Gravity 

Mercury Concentration SW-846-7470A, EPA Method 1631E, SW-846-1631E, 

SW-846-1631, EPA 821-R-01-013, or equivalent ppm 

Total Selected Metals 

Concentration 

SW-846-6020, -6020A, , SW-846-6010B, SW-846-

7740 for Se, SW-846-7060 or -7060A for As ppm 

Chlorine Concentration ASTM E776-87 (1996, 2004, or 2009), SW-846-9250, 

SW-846-5050, -9056, -9076, or -9250 ppm 

Sulfur Concentration ASTM D129-00 (2005), ASTM D1552-01 or -08, 

ASTM D2622-98 or -10 ppm 

4. Reporting crude oil analysis data: You must report the analysis results separately for 

each of the composited samples in a Microsoft ® Excel Crude Oil Analysis Template. 

This Excel template can be downloaded from the ICR website (http://icr2010.rti.org, 

click on “Petroleum Refineries”). The template asks you to identify the country of origin 

and crude type (e.g., Texas sweet) for crude analysis. If you conducted composition 

analysis on more than one type of crude oil, you must make a copy of the worksheet and 

update the crude oil type in each worksheet order to distinguish between the separate 

crude oil composition analyses. 

You must keep the following records for 3 years: 

• Documentation that crude oil samples were obtained in accordance with the above 

sampling protocol; 

• Documentation of the proper chain of custody for each crude oil sample; 

• Description of the QA/QC procedures followed in preparing each crude oil 

sample for analysis and performing the required analysis; and 

• The results of the analyses performed on each crude oil sample. 
Form Approved __/__/__ 

OMB Control No. ____-____ 

Approval Expires __/__/__ 

1-1 

Attachment 1. 2005 NEI Data for Each Refinery 

(To be pulled from the NEI data and compiled for each refinery. This page could be a cover 

page and/or each refinery table could have a cover page, or the NEI table may just have a header 

or footer that identifies it as part of Attachment 1) 
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Attachment 2. Lists of SCC 

(This is an example of one of multiple tables that will be in this Attachment. Each type of emission source will haAttachment.) 

Table 2-1. List of Storage Tank SCC 

SCC SCC_L1 SCC_L2 SCC_L3 SCC_40302001 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Crude 

40302002 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Gasoli

40302003 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Jet Na

40302004 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Kerose

Keroseor JP-8

40302005 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Distill

 #2 Fu

40302006 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Heavy 

40302007 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Residu

5 or #6 

40302008 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Unfini

Napht

40302009 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Other 

40302101 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Crude 

40302102 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Gasoli

40302103 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Jet Na
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SCC SCC_L1 SCC_L2 SCC_L3 SCC_40302104 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

KeroseKeroseor JP-8

40302105 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Distill #2 Fu

40302106 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Heavy 

40302107 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Residu5 or #6 

40302108 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

UnfiniNapht

40302109 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Other 

40302201 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Crude 

40302202 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Gasoli

40302203 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Jet Na

40302204 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

KeroseKeroseor JP-8

40302205 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Distill #2 Fu

40302206 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Heavy 

40302207 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Residu5 or #6 

40302208 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

UnfiniNapht
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2-3 

SCC SCC_L1 SCC_L2 SCC_L3 SCC_40302209 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

 Other 

40302301 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Crude 

40302302 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Gasol

40302303 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Jet Na

40302304 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Kerose

Keroseor JP-8

40302305 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Distill

 #2 Fu

40302306 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Heavy 

40302307 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Residu

5 or #6 

40302308 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Unfini

Napht

40302309 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Other 

40302401 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

LPG Pressurized Tanks Examp

Butane 
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Attachment 3. Source Test Summary Table 

Unit 

ID(s) 

APCD 

Type(s) 

Date of test 

report 

Pollutants 

tested1

Test 

method(s) 

used2

Are these 

inlet or 

outlet data 

(or both)? 

Configuration 

changes3

Process testing 

notes 

(optional)4

OPTION

often a

required t

testing 

emission u

pollutan

1 List the pollutants tested. Separate multiple pollutants by commas. 2 Enter the EPA test method number (e.g., M5, M7E). Be very specific if the method used was not an EPA method. 3 If the configuration of the emission unit, combustion controls, collection system, or APCD changed since the test was conducted, describe the changes

changes, enter “N/A” 

4 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 em
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Attachment 4. Example CEMS Table 

NOX CEMS DATA 

Emission Unit ID: APCD_ID: 

OPTIONAL: 1-day average 

in units other th

CEMS 

Date 

(mm/dd/ 

yyyy) 

Daily 

Production 

Rate 

(value) 

Daily 

Production 

Rate 

(units) 

1-day average 

emission value 

for NOX

(ppmdv, 

corrected for 

%O2) 

% O2

correction 

(by volume, 

dry basis) 

Data average 

affected by a 

startup, 

shutdown, or 

other event?1

1-day average 

emission value 

for NOX, 

corrected for 

%O2 (value) 

1-day av

emission 

for N

(uni

01/01/2009 01/02/2009 01/03/2009 01/04/2009 01/05/2009 01/06/2009 01/07/2009 01/08/2009 01/09/2009 

...... 

12/25/2009 12/26/2009 12/27/2009 12/28/2009 12/29/2009 12/30/2009 12/31/2009 

1 If no, leave blank. If yes, respond “startup,” “shutdown,” or “event”; if you respond “event” please include a brief description of the event.