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PART VI. EMISSIONS INVENTORY DATA 

The U.S. EPA is working to fulfill its obligation under CAA sections 111(b), 112(f)(2), and 

112(d)(6) to review residual risk from the petroleum refinery NESHAP subparts CC and UUU 

and to perform technology reviews of the petroleum refinery NESHAP subparts CC and UUU

and the petroleum refinery NSPS subpart J. Emission data sets provided by the individual 

refineries will be used for these reviews. Refer to the ICR website for instructions for obtaining

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 below, provide emission estimates (tons/yr) for the 2010 calendar year for 

individual HAP and criteria pollutants using the emissions template provided. You may report 

emissions by emission point rather than by unit, but you should identify which units are 

associated with each emission point. (Note: You do not have to report emissions one way or the 

other throughout the entire inventory. For example, you may report equipment leak emissions by 

process unit for the major process units and by geographical area for other areas of your 

refinery.)

• Each processing unit for which you provided an ID in Part I, Question 16

• Each process heater listed in Table 2-1 of Part II

• Each fuel gas and natural gas system for which you provided equipment leaks 

data in Table 3-2 of Part II

• Each storage tank listed in Table 4-1 of Part II

• Each “other atmospheric vent” listed in Table 11-1 of Part II (except for vents 

controlled by a flare) 

• Each flare listed in Table 12-1 of Part II, including those controlling emissions 

from “other atmospheric vents” listed in Table 11-1 of Part II

• Each solid waste management unit listed in Table 17-1 of Part II

Except as noted below, provide emission estimates following the methods provided in the 

Emission Estimation Protocol for Petroleum Refineries (Version 2.1 – Final ICR Draft). As 

noted in the Emission Estimation Protocol for Petroleum Refineries, for each unit for which 

there are multiple methodologies for estimating emissions, you must use the highest 

Methodology Rank in the Emission Estimation Protocol for Petroleum Refineries for which you 

have available 2010 data. For example, if Methodology Rank 1 for NOX is estimating emissions 

using a continuous emissions monitoring system (CEMS), and you have a NOX CEMS on that 

unit, you must use the CEMS results to estimate NOX emissions from that unit. However, if you 

did not have a NOX CEMS installed on that unit during 2010, you do not have available data to 

use Methodology Rank 1 for NOX; you must then consider whether you have available data to 

use Methodology Rank 2 for NOX from that unit. Similarly, if a particular methodology requires 

speciation of a stream and you do not have speciation data available, you are not required to 

conduct additional sampling and analysis (but if you do have speciation data available and no 

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higher ranking methodology can be used, you must use the methodology that calls for 

speciation).

For units and other emissions points not addressed in the Emission Estimation Protocol for 

Petroleum Refineries, you should provide the emissions estimates as your TRI or State inventory

or use engineering estimates and process knowledge for pollutants not required to be reported for 

TRI or State inventory. Also provide a brief explanation of the methodology you used in the 

“Comments” column of the emissions template provided. 

For wastewater treatment systems, also please provide a copy of the Refinery Wastewater 

Emissions Tool spreadsheet (provided as part of the Emission Estimation Protocol for Petroleum 

Refineries) completed for your refinery. 

Instructions for completing the emissions template are provided below. 

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

emissions are released into the environment. If this is an emission point for one

particular process unit or a flare, you may use the Unit ID as your Emission point ID (the 

response to Number 3 will be completed automatically if you do so). If you choose to 

report fugitive emissions by process unit, the Emission point ID should be “FUG-” plus 

the Unit ID (e.g., if you are reporting equipment leak emissions for a FCCU with a Unit 

ID of FCCU01, the Emission point ID is “FUG- FCCU01”).

2. Emission point description: Provide a description of the emissions point for easy 

reference (e.g., FCCU regenerator vent stack; catalytic reforming unit depressurization

vent; crude heater vent; facility-wide start-up and shutdown emissions).

3. Unit ID: Provide the identification number or code for the unit(s) associated with this 

emission point. Use the same identification number that you provided in Part II, Sections 

2 through 13, 15, and 16. For sulfur recovery, enter the SRU ID. For an emissions point 

that covers the entire facility, enter “All Units.” (Note that for flares, you are not 

required to identify the process units and/or vents routed to each flare; the response to 

this question is the Flare ID.

4. SCC: Attachment 1 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 1 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. 

5. 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. 

6. 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. 

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Deleted: 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

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Deleted: 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

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7. 2010 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.) 

8. 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 a pollutant’s 

emissions for a given source are based on a mixture of different methodology ranks (e.g., 

calculating equipment leak emissions using line by line composition for some parts of a 

process and average composition for other parts), report the protocol methodology rank 

that contributed most to the total reported emissions. 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.” 

9. 2010 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 and report the value here. Enter 0 if there were not nonroutine operations for this source during 2010 or if non-routine emissions are not 

applicable for the source type (e.g., equipment leaks). You may use an emissions point 

ID representing “All Units” to report the non-routine emissions (see descriptions for 

Number 1 and Number 3).

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

during normal operation in any one hour of 2010. See the Emission Estimation Protocol 

for Petroleum Refineries for additional information on how to determine hourly 

emissions. 

11. Annual emissions allowed by NESHAP for emission points subject to emission limits

(tons/yr): Enter the annual emissions during normal operation allowed by the NESHAP 

to which this unit is subject. (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. 

Similarly, if the NESHAP limit is on a percent reduction basis, you may need to use 

information about the inlet to the control device to estimate the allowable emissions.) If 

this unit is not subject to any NESHAP for this pollutant, enter “N/A.” 

As an example, if you comply with the 1 lb per 1,000 lb coke burn-off limit for PM for an 

FCCU, determine and report the allowed annual PM emissions based on the annual 

quantity of coke burned in 2010 when reporting the allowed PM emissions and enter 

“N/A” when reporting the allowed nickel emissions. Alternatively, if you comply with 

the 0.029 lb/hr nickel emissions limit for an FCCU, enter “N/A” when reporting the 

allowed PM emissions and determine and report the allowed annual nickel emissions 

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Deleted: If this unit is not subject to any 

NESHAP for this pollutant, enter “N/A.”

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based on the operating hours of the unit in 2010 when reporting the allowed nickel 

emissions. 

12. Hourly emissions allowed by NESHAP for emission points subject to emission limits

(lb/hr): Enter the maximum hourly emissions during normal operation allowed by the 

NESHAP to which this unit is subject. For example, when reporting nickel emissions 

from an FCCU, enter “N/A” if you comply with a PM emissions limit but report the 

allowed hourly emissions rate if you comply with the nickel emission rate alternative. 

(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. Similarly, if the NESHAP limit is 

on a percent reduction basis, you may need to use information about the inlet to the 

control device to estimate the allowable emissions.) If this unit is not subject to any 

NESHAP for this pollutant, enter “N/A.”

As an example, if you comply with the 1 lb per 1,000 lb coke burn-off limit for PM for an 

FCCU, determine and report the allowed hourly PM emissions based on the maximum 

quantity of coke burned in an hour during 2010 when reporting the allowed PM 

emissions and enter “N/A” when reporting the allowed nickel emissions. Alternatively, if 

you comply with the 0.029 lb/hr nickel emissions limit for an FCCU, enter “N/A” when 

reporting the allowed PM emissions and enter “0.029” (lb/hr) when reporting the allowed 

nickel emissions.

13. 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” (see example for Number 11). 

14. 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” (see example for Number 12).

15. 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, 

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

waste ponds, coke drum cutting, coke transport and storage, or unpaved roads. 

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

15. 

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

Deleted: If this unit is not subject to any 

NESHAP for this pollutant, enter “N/A.”

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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. 

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

Number 15. 

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. 

18. 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 and prefers six digits to the right of the 

decimal point. (If currently available coordinates have five digits to the right of the 

decimal point instead of six, those coordinates are acceptable.) These data are critical 

inputs to the modeling files that EPA will use to determine the risk profile for the residual 

risk review process.1

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

of your answers to the previous questions. 

 

1

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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PART VI. EMISSIONS INVENTORY DATA 

Emission point ID

Emission point description

 Unit ID

 SCC

Pollutant name 

Pollutant CAS No. or 

Pollutant Code 

2010 emissions (tons) 

Protocol methodology 

rank used 

2010 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) 

Point Sources Fugitive Sources 

Longitude 

Latitude 

Comments 

Release Height (ft)

Internal Vent 

Diameter 

(ft)

Exit Temperature (°F)

Gas Flow Rate (acfm)

Length (ft) 

Width (ft) 

Angle 
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Attachment 1. Lists of SCC 

(This is an example of one of multiple tables that will be posted on the ICR website. Each type of emission source will have a table ofSCC on the ICR website.) 

List of Storage Tank SCC 

SCC SCC_L1 SCC_L2 SCC_L3 SCC_L4 40302001 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries

Fixed Roof Tanks Crude Oil 

40302002 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Gasoline 

40302003 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Jet Naphtha (JP-4 or Jet B) 

40302004 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Kerosene (including Jet 

Kerosene Jet A-1, Jet A, JP-5, or JP-8) 

40302005 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries

Fixed Roof Tanks Distillate Fuel (Diesel Fuel, 

 #2 Fuel Oil, or #3 Fuel Oil)

40302006 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Heavy Fuel Oil (# 4 Fuel Oil) 

40302007 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Residual or Heavy Gas Oil (# 

5 or #6 Fuel Oil) 

40302008 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries

Fixed Roof Tanks Unfinished or Intermediate 

Naphtha

40302009 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Fixed Roof Tanks Other (Specify) 

40302101 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Crude Oil 

40302102 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries

External Floating Roof Tanks (Without Geodesic Dome) 

Gasoline 

40302103 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Jet Naphtha (JP-4 or Jet B)
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SCC SCC_L1 SCC_L2 SCC_L3 SCC_L4 40302104 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Kerosene (including Jet Kerosene Jet A-1, Jet A, JP-5, or JP-8) 

40302105 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries

External Floating Roof Tanks (Without Geodesic Dome) 

Distillate Fuel (Diesel Fuel,  #2 Fuel Oil, or #3 Fuel Oil)

40302106 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Heavy Fuel Oil (# 4 Fuel Oil) 

40302107 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Residual or Heavy Gas Oil (# 5 or #6 Fuel Oil) 

40302108 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries

External Floating Roof Tanks (Without Geodesic Dome) 

Unfinished or Intermediate Naphtha

40302109 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (Without Geodesic Dome) 

Other (Specify) 

40302201 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Crude Oil 

40302202 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Gasoline 

40302203 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Jet Naphtha (JP-4 or Jet B) 

40302204 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Kerosene (including Jet Kerosene Jet A-1, Jet A, JP-5, or JP-8) 

40302205 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Distillate Fuel (Diesel Fuel,  #2 Fuel Oil, or #3 Fuel Oil) 

40302206 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries

External Floating Roof Tanks (With Geodesic Dome)

Heavy Fuel Oil (# 4 Fuel Oil) 

40302207 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Residual or Heavy Gas Oil (# 5 or #6 Fuel Oil) 

40302208 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

External Floating Roof Tanks (With Geodesic Dome) 

Unfinished or Intermediate Naphtha 
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SCC SCC_L1 SCC_L2 SCC_L3 SCC_L4 40302209 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries

External Floating Roof Tanks (With Geodesic Dome)

 Other (Specify) 

40302301 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Crude Oil 

40302302 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Gasoline 

40302303 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Jet Naphtha (JP-4 or Jet B) 

40302304 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Kerosene (including Jet 

Kerosene Jet A-1, Jet A, JP-5, or JP-8)

40302305 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Distillate Fuel (Diesel Fuel, 

 #2 Fuel Oil, or #3 Fuel Oil) 

40302306 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Heavy Fuel Oil (# 4 Fuel Oil) 

40302307 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Residual or Heavy Gas Oil (# 

5 or #6 Fuel Oil) 

40302308 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Unfinished or Intermediate 

Naphtha 

40302309 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

Internal Floating Roof Tanks Other (Specify) 

40302401 Petroleum and Solvent 

Evaporation 

Petroleum Product Storage at Refineries 

LPG Pressurized Tanks Examples: Propane Spheres, 

Butane Spheres