Component 1 Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

Petroleum Refinery 

Emissions Information Collection 

PART I: GENERAL FACILITY INFORMATION 

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

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

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

_________________________________________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

2b. Does this facility1 report in EIA-820 the combined processing/production capacities for 

refining plants that are not contiguously located? Yes No

2c. If Yes, provide the Facility ID assigned by the Section 114 letter for each non-contiguous 

facility: _________________________________________________________________ 

_________________________________________________________________________ 

________________________________________________________________________ 

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

_________________________________________________________________________ 

_________________________________________________________________________ 

4. Provide mailing address if different: ___________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

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

survey: __________________________________________________________________ 

_________________________________________________________________________ 

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

 and e-mail address(es): _____________________________________________________ 

7. Name of legal owner of facility: ______________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

 

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 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

2 

_________________________________________________________________________ 

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

_________________________________________________________________________ 

_________________________________________________________________________ 

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

_________________________________________________________________________ 

_________________________________________________________________________ 

_________________________________________________________________________ 

10. Dun and Bradstreet number of your facility: ____________________________________ 

11. Annual revenue in 2010: $______________________ 

12. Number of employees at your facility: _________________________________________ 

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

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

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

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

Partner name ______________ Percent ownership ______% No. employees ______ 

Partner name ______________ Percent ownership ______% No. employees ______ 

Partner name ______________ Percent ownership ______% 

 If No: Name of parent company: _____________________________________________ 

Number of employees in parent company: ___________________________ 

Check the statement below that best applies: 

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

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

 The parent organization provides some financial support. 

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

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

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

1 Topping refinery 

2 Hydroskimming refinery 

3 Upgrading refinery 

4 Heavy oil/asphalt refinery 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

3 

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

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

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

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

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

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

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

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

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

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

or products piped directly to other offsite facilities. 

Product/Refinery Output 

Cumulative 

2010 

Production 

(1,000 bbl) 

Disposition of Products by Transport Method 

% used 

onsite 

% 

shipped 

by tank 

ship 

% 

shipped 

by 

barge 

% 

shipped 

by tank 

truck 

% 

shipped 

by rail 

car 

% 

shipped 

by 

pipeline 

Ethane 

Ethylene 

Propane 

Propylene 

Normal Butane 

Butylene 

Isobutane 

Isobutylene 

Unfinished Oils – Naphthas 

and lighter 

Unfinished Oils – Kerosene 

and light gas oils 

Unfinished Oils – Heavy gas 

oils 

Unfinished Oils – Residuum 

Finished Motor Gasoline - 

Reformulated 

Finished Motor Gasoline - 

Conventional 

Motor Gasoline Blending 

Components - Reformulated 

Motor Gasoline Blending 

Components - Conventional 

Aviation Gasoline – Finished 

and Blending Components 

Special Naphthas (solvents) 

Kerosene-type Jet Fuel 

Kerosene 

Distillate Fuel Oil – 15 ppm 

sulfur and under 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

4 

Product/Refinery Output 

Cumulative 

2010 

Production 

(1,000 bbl) 

Disposition of Products by Transport Method 

% used 

onsite 

% 

shipped 

by tank 

ship 

% 

shipped 

by 

barge 

% 

shipped 

by tank 

truck 

% 

shipped 

by rail 

car 

% 

shipped 

by 

pipeline 

Distillate Fuel Oil – greater 

than 15 ppm to 500 ppm 

sulfur 

 

Distillate Fuel Oil – greater 

than 500 ppm sulfur 

Residual Fuel Oil – less than 

0.31% sulfur 

Residual Fuel Oil – 0.31% to 

1.0% sulfur 

Residual Fuel Oil – greater 

than 1% sulfur 

Lubricants (total) 

Asphalt and Road Oil 

Wax 

Petroleum Coke – 

Marketable 

Petroleum Coke – Catalyst 

Still Gas 

Petrochemical Feedstocks – 

Naphtha <401°F end-point 

Petrochemical Feedstocks - 

Other Oils ≥401°F end-point 

Aromatics – Benzene 

Aromatics – Toluene 

Aromatics – Xylenes (total) 

Aromatics – Other than BTX 

Other Miscellaneous 

Products (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

5 

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

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

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

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

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

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

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

rates had these issues not occurred. 

When asked for a Unit ID, use a unique Unit ID for each process unit. When possible, 

use the same identifier from your permit or emissions inventory. 

Unit ID Process Type1

Unit Throughput 

Capacity (bbl/cd)2

Unit Actual Throughput (bbl/cd)2

1

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

and specify the type of process. 

2

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

unless noted otherwise. 

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

of charged liquid material (excluding hydrogen gas inputs). 

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

For alkylation through oxygenate plants, coke calcining, and chemical production (process type codes 22 through 36 and 

codes 39 through 45), “throughput” is determined in terms of primary product produced (e.g., quantity of alkylate 

produced in alkylation unit). 

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

catalytic reforming. 

For hydrogen plants, throughput units are million standard cubic feet per calendar day (MMcf/cd); use 32°F (0°C) and 1 

atmosphere as “standard conditions” for H2 plants. 

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

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

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

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

treatment. 

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

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

For wastewater collection and treatment systems (WWTS), throughput units are million gallons per day (MMgal/day). If 

desired, you may report wastewater treatment units used to comply with Benzene Waste Operations NESHAP (40 CFR 

part 61, subpart FF) “BWON” or sour water treatment units as separate WWTS, but you are not required to do so. 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

6 

Code No. Type of Process 

1 Atmospheric crude distillation 

2 Vacuum distillation 

3 Delayed coking 

4 Fluid coking (traditional) 

5 Flexicoking 

6 Visbreaking, other thermal cracking 

7 Fluid catalytic cracking unit 

8 Non-fluid catalytic cracking unit 

9 Catalytic hydrocracking 

10 Catalytic reforming unit – continuous regeneration 

11 Catalytic reforming unit – cyclic regeneration 

12 Catalytic reforming unit – semi-regenerative 

13 Fuels solvent deasphalting 

14 Desulfurization/ hydrotreating – naphtha/reformer feed 

15 Desulfurization/ hydrotreating – gasoline 

16 Desulfurization/ hydrotreating – kerosene/jet fuel 

17 Desulfurization/ hydrotreating – diesel 

18 Desulfurization/ hydrotreating – other distillate 

19 Desulfurization/ hydrotreating – residual 

20 Desulfurization/ hydrotreating – heavy gas oil 

21 Desulfurization/ hydrotreating – other 

22 HF alkylation 

23 H2SO4 alkylation 

24 Aromatics production 

25 Asphalt production 

26 Isomerization – Isobutane 

27 Isomerization – Iso C5,C6 

28 Lubricants production 

29 Petroleum coke storage 

30 Hydrogen plant 

31 Sulfur recovery unit (SRU) 

32 Gas plant/light ends distillation/LPG production unit 

33 Oxygenate plant – MTBE 

34 Oxygenate plant – ETBE 

35 Oxygenate plant – TAME 

36 Oxygenate plant – other (specify) 

37 Fuel gas treatment 

38 Fuel blending 

39 Coke calcining 

40 Ethylene production 

41 Ethylene dichloride production 

42 Ethylene dibromide production 

43 Propylene production 

44 Acrylonitrile production 

45 Other petrochemical or organic chemical production (specify chemical) 

50 Product loading – Marine vessel loading 

51 Product loading – Truck/tank truck loading 

52 Product loading – Rail car loading 

53 Product loading – Container/other loading 

60 Wastewater collection and treatment system (WWTS) 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

7 

PART II: PROCESS AND EMISSIONS INFORMATION 

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

code that is used in Part I, Question 16. 

SECTION 1. ENERGY MANAGEMENT 

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

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

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

TABLE 1-1. 2010 Fuel Consumption 

Fuel Units Fuel Consumption 

Crude Oil1 bbl 

LPG bbl 

Distillate Fuel Oil bbl 

Residual Fuel Oil bbl 

Still Gas bbl 

Marketable Coke bbl 

Catalyst Coke bbl 

Natural Gas MMcf 

Coal Tons (US) 

Purchased Electricity MWh 

Purchased Steam MM lb 

Other (solid) Tons (US) 

Other (liquid) bbl 

Other (gas) MMcf 

Abbreviations: bbl = barrels 

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

MWh = Megawatt-hours 

MM lb = million pounds 

1

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

atmospheric crude or vacuum distillation column. 

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

atmosphere] from off-site (merchant) hydrogen producers or from hydrogen plants 

located at, but not under the comment control of, the petroleum refinery. Do not report 

hydrogen from hydrogen plants owned or under common control of the petroleum 

refinery in this quantity; more detail regarding hydrogen plants owned or under common 

control is requested in Part II, Section 10. 

4. Does this refinery have a facility energy management plan? Yes No
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

8 

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

reductions that have resulted from the implementation of the plan. 

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

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

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

and waste heat boilers used on process unit exhaust lines. 

TABLE 1-2. Electricity and Steam Generation Information 

Generation Unit ID 

Unit Description1

Primary Fuel2

Secondary Fuel2

Energy Efficiency Measures3

Air preheat use4

Typical air preheat temperature 

when used (°F) 

Generation Unit Type5

Electricity 

Generation Steam Generation Capacity of Unit (MW) Disposition of electricity6 Boiler Heat Input Capacity (MMBtu/hr) Steam Generating Capacity (lb/hr) Pressure of Steam (psia) Disposition of steam7

Percent Steam to Blowdown8

 

Footnotes for Table 1-2: 

Abbreviations: MW = megawatts 

MMBtu/hr = million British thermal units per hour 

lb/hr = pounds per hour 

psia = pounds per square inch absolute 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

9 

1

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

boiler”). 

2

 Select from the following list of fuels. 

Code No. Type of Fuel 

0 None (i.e., waste heat only) 

1 Natural gas 

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

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

4 Distillate fuel oil 

5 Heavy gas oil 

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

7 Coal 

8 Wood or other biomass fuel 

99 Other (specify) 

3

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

that apply. 

Code No. Type of Energy Efficiency Measure 

0 None 

1 Insulation on boiler 

2 Insulation on distribution lines 

3 Oxygen monitors used to control/limit excess oxygen 

4 Intake air monitors to optimize fuel/air mixtures 

5 Combustion air preheat from flue gas 

6 Boiler feed water preheat from flue gas 

7 Blowdown steam recovery system for low pressure needs 

8 Steam trap maintenance 

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

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

needed at lower pressures) 

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

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

99 Other (specify) 

4

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

Code No. Type of Air Preheat 

0 No air preheater is present 

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

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

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

4 Air preheater is present and used 90% or more of the time 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

10 

5

 Select from the following list of unit types. 

Code No. Type of Unit 

1 Electricity generating unit 

2 Steam generating unit 

3 Combined heat and power unit 

6

 Select from the following list of dispositions. 

Code No. Type of Electricity Disposition 

1 Generated electricity is used only on-site 

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

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

7

 Select from the following list of dispositions. 

Code No. Type of Steam Disposition 

1 Generated steam is used only on-site. 

2 Generated steam is used only off-site. 

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

8

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

answer “Unknown.” 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

11 

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

16 of Part I (except WWTS, which are reported in Section 15). 

TABLE 1-3. Steam Consumption by Process Unit 

Unit ID 

Steam consumption for the processing unit in 2010 

(tons/yr) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

12 

SECTION 2. PROCESS HEATERS 

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

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

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

TABLE 2-1. Process Heater General Information 

Process Heater ID 

Unit ID for process unit served by 

process heater 

Process heater construction type1

Process heater draft type2

Is the process heater designed to be cofired? (Yes/No) 

Rated heat input capacity (MMBtu/hr) 

Average heat input rate in 2010 

(MMBtu/hr) 

Total operating hours in 2010 (hr) 

Air preheat use3

Typical air preheat temperature when 

used (°F) 

Other energy efficiency measures4

Primary fuel5

Percent of total operating hours 

process heater fired with primary fuel 

in 2010 

Secondary fuel5

Percent of total operating hours 

process heater fired with secondary 

fuel in 2010 

Operating hours while operating less 

than 25% of rated capacity in 2010(hr) 

Operating hours while operating at 25 

to 50% of rated capacity in 2010 (hr) 

Applicable Federal air regulation(s)6

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s) 

Type of PM controls7

Type of SO2 controls8

Type of NOX controls9

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

13 

Footnotes for Table 2-1: 

1

 Select from the following list of process heater construction types. 

Code No. Type of Construction 

1 Vertical cylinder 

2 Cabin or box 

99 Other (specify) 

2

 Select from the following list of process heater draft types. 

Code No. Type of Draft 

1 Natural draft 

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

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

4 Forced draft (combustion air-side fan only) 

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

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

99 Other (specify) 

3

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

preheat use. 

Code No. Type of Air Preheat 

0 No air preheater is present 

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

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

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

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

4

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

Code No. Type of Energy Efficiency Measure 

0 None 

1 Oxygen monitors used to control/limit excess oxygen 

2 Intake air monitors to optimize fuel/air mixtures 

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

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

5 Finned or dimpled tubes to increase heat transfer 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

14 

5

 Select from the following list of fuels. 

Code No. Fuel Type 

1 Natural gas 

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

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

4 Distillate fuel oil 

5 Heavy gas oil 

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

99 Other (specify) 

6

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

99 Other (specify) 

7

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

Code No. Type of PM Control 

0 None 

11 Fabric/cartridge filter (“baghouse”) 

12 Venturi/wet scrubber 

13 Electrostatic precipitator (ESP) 

14 Wet ESP 

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

99 Other (specify) 

8

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

Code No. Type of SO2 Control 

0 None 

21 H2S limit in fuel gas 

22 TRS limit in fuel gas 

23 Low sulfur distillate or low sulfur heavy gas oil 

24 Wet scrubber/flue gas desulfurization 

25 Spray dryer absorber 

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

15 

9

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

Code No. Type of NOX Control 

0 None 

31 (External) flue gas recirculation 

32 Staged air low NOX burner 

33 Staged fuel low NOX burner 

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

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

36 Selective non-catalytic reduction (SNCR) 

37 Selective catalytic reduction (SCR) 

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

16 

SECTION 3. EQUIPMENT LEAKS 

 

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

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

equipment leaks? Yes No

If Yes: 

a. Provide the manufacturer and model number: ____________________________ 

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

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

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

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

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

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

startup) 

4 Other 

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

The total equipment counts should be the total number of pieces of equipment in a 

process unit, not necessarily only those currently being monitored. Do not count pieces 

of equipment that are in vacuum service. You may provide reasonable estimates of 

equipment counts from existing information if the requested equipment counts are not 

directly available as requested in Table 3-1 for each process unit as defined in this ICR. 
OA

17 

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

Unit ID 

Applicable Federal air regulation(s)

1

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s) 

Average methane concentration in 

process fluid that contacts equipment 

in gas service throughout the process 

(ppmv) 

Is the average methane concentration 

based on sampling and analysis 

results or estimated (e.g., based on 

process knowledge)? 

For each of the following types 

of equipment, provide: 

Pump 

Seals Valves 

Flanges & 

Connectors

Open-ended lines

3

Light liquid

2

Heavy liquid

2

Gas

2

Light liquid

2

Heavy liquid

2

Gas and light liquid

2

Heavy liquid

2

Number of Pieces of 

Equipment 

Number of Pieces of 

Equipment Monitored5

Monitoring Frequency6

Leak Definition (ppmv)7

Number of Pieces of 

Equipment 

Number of Pieces of 

Equipment Monitored5

Monitoring Frequency6

Leak Definition (ppmv)7
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

18 

Footnotes for Table 3-1: 

1

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

99 Other (specify) 

2

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

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

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

that includes definitions of these terms. 

3

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

(e.g., downstream of a secondary valve) or from a cap on the pipe and not to leakage from the 

associated valve packing or body flanges. 

4

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

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

5

 Do not include difficult-to-monitor equipment in this count. 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

19 

6

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

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

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

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

interval for such sources.) 

Code No. Monitoring Frequency 

0 None (unit/system not monitored for leaks) 

1 No set interval (use only for sensory monitoring) 

2 Less than annually 

3 Annually 

4 Semiannually 

5 Quarterly 

6 Monthly 

7 Biweekly 

8 Weekly or more frequently 

7

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

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

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

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

Code No. Leak Definition 

0 None (unit/system not monitored for leaks) 

1 Detection by sensory monitoring 

2 10,000 ppmv 

3 5,000 ppmv 

4 2,000 ppmv 

5 1,000 ppmv 

6 500 ppmv 

7 Less than 500 ppmv 

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

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

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

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

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

each fuel gas and natural gas system. 
OA

20 

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

Unit 

ID 

Applicable 

Federal air 

regulation(s)1

If subject to 

State, local, or 

Tribal air 

regulation(s), 

provide the 

citation(s) 

Average 

methane 

concentration in 

process fluid 

that contacts 

equipment in 

gas service 

throughout the 

process (ppmv) 

Is the average 

methane 

concentration 

based on sampling 

and analysis 

results or 

estimated (e.g., 

based on process 

knowledge)? 

For each of the following types of 

equipment, provide: 

Number of Pieces of Equipment 

Number of Pieces of Equipment Monitored3

Monitoring Frequency4

Leak Definition (ppmv)5

Number of Pieces of Equipment 

Number of Pieces of Equipment Monitored3

Monitoring Frequency4

Leak Definition (ppmv)5

Number of Pieces of Equipment 

Number of Pieces of Equipment Monitored3

Monitoring Frequency4

Leak Definition (ppmv)5

Number of Pieces of Equipment 

Number of Pieces of Equipment Monitored3

Monitoring Frequency4

Leak Definition (ppmv)5
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

21 

Footnotes for Table 3-2: 

1

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

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

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

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

fuel gas or natural gas system is subject). 

Code No. Federal Air Regulation 

0 None 

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

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

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

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

99 Other (specify) 

2

 Use the definition of “gas service” in the regulation to which the fuel gas or natural gas system 

is subject, if applicable. See the list of definitions for this ICR for a definition of this term to 

use if the fuel gas or natural gas system is not subject to a regulation that includes a definition 

of this term. 

3

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

4

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

gas or natural gas system, type of equipment, and type of service. 

Code No. Monitoring Frequency 

0 None (unit/system not monitored for leaks) 

1 No set interval (use only for sensory monitoring) 

2 Less than annually 

3 Annually 

4 Semiannually 

5 Quarterly 

6 Monthly 

7 Biweekly 

8 Weekly or more frequently 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

22 

5

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

repairs are required (or routinely performed) for the fuel gas or natural gas system, type of 

equipment, and type of service. 

Code No. Leak Definition 

0 None (unit/system not monitored for leaks) 

1 Detection by sensory monitoring 

2 10,000 ppmv 

3 5,000 ppmv 

4 2,000 ppmv 

5 1,000 ppmv 

6 500 ppmv 

7 Less than 500 ppmv 
F

OMAp

23 

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

Question 16 (except WWTS). 

TABLE 3-3. Pressure Relief Devices 

Unit ID 

Total number of PRD 

Number of PRD 

routed to fuel gas 

system or control 

device Atmospheric PRD 

Gas Liquid Gas Liquid 

Number of PRD 

Type of controls

1

Number of PRD 

Type of controls

1

Number of PRD 

Number equipped with rupture disk or 

other non-reclosing device 

Method 21 

Periodic 

Monitoring Monitoring of Releases 

Number of PRD 

Number equipped with rupture disk or 

other non-reclosing device 

Method 21 

Periodic 

Monitoring M

Number of PRD 

Monitoring Frequency

2

Leak Definition (ppmv)

3

Number of PRD monitored 

using a system designed to 

measure the duration of a 

release and/or the quantity 

of compounds released 

Describe your monitoring 

system 

Number of PRD 

Monitoring Frequency

2

Leak Definition (ppmv)

3

Number of PRD monitored 

idid 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

24 

Footnotes for Table 3-3: 

1

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

gas system, or natural gas system. 

Code No. Type of Control 

0 None 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

52 Carbon adsorber 

55 Flare 

61 Routed to fuel gas system 

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

99 Other (specify) 

2

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

for the process unit, type of equipment, and type of service. Select “0” if none of the other 

options apply. 

Code No. Monitoring Frequency 

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

sensory methods)) 

1 Less than annually 

2 Annually 

3 Semiannually 

4 Quarterly 

5 Monthly 

6 Biweekly 

7 Weekly or more frequently 

8 Only after releases 

3

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

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

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

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

Code No. Leak Definition 

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

sensory methods)) 

1 10,000 ppmv 

2 5,000 ppmv 

3 2,000 ppmv 

4 1,000 ppmv 

5 500 ppmv 

6 Less than 500 ppmv 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

25 

SECTION 4. STORAGE TANKS 

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

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

If Yes, provide the following information: 

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

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

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

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

____________________ MMscf at 60 °F and 1 atmosphere 

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

has a capacity greater than 10,000 gal and holds liquid material (including wastewater) 

with a maximum true vapor pressure greater than 0.1 psi. 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

26 

TABLE 4-1. Storage Tank General Information 

Tank ID 

Type of stored liquid1

Maximum true vapor pressure of 

hydrocarbons in stored liquid in 2010 (psi) 

Temperature at which maximum true vapor 

pressure was calculated (°F) 

Type of tank/controls2

Diameter (ft) 

Height (ft) 

Maximum liquid height (ft) 

Total throughput for all materials stored in 

the tank in 2010 (bbl) 

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

Applicable Federal air regulation(s)3

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s) 

Year in which the tank was last degassed 

Type of control for last degassing event4

Was the tank cleaned during last degassing 

event? (Yes/No) 

Year in which you anticipate the next 

degassing event5

For tanks with EFR or 

IFR

Type of primary rim seal6

Type of secondary rim seal7

Minimum height of floating roof above 

the floor at the shell when landed 

Number of times floating roof landed 

in 2010 

Number of times the tank was emptied 

after roof landed in 2010 

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

27 

Footnotes for Table 4-1: 

1

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

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

Code No. Type of Stored Liquid 

1 Unstabilized crude oil 

2 Stabilized crude oil 

3 Ethane 

4 Ethylene 

5 Propane 

6 Propylene 

7 Normal Butane 

8 Butylene 

9 Isobutane 

10 Isobutylene 

11 Unfinished Oils – Naphthas and lighter 

12 Unfinished Oils – Kerosene and light gas oils 

13 Unfinished Oils – Heavy gas oils 

14 Unfinished Oils – Residuum 

15 Finished Motor Gasoline - Reformulated 

16 Finished Motor Gasoline - Conventional 

17 Motor Gasoline Blending Components - Reformulated 

18 Motor Gasoline Blending Components - Conventional 

19 Aviation Gasoline – Finished and Blending Components 

20 Special Naphthas (solvents) 

21 Kerosene-type Jet Fuel 

22 Kerosene 

23 Distillate Fuel Oil – 15 ppm sulfur and under 

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

25 Distillate Fuel Oil – greater than 500 ppm sulfur 

26 Residual Fuel Oil – less than 0.31% sulfur 

27 Residual Fuel Oil – 0.31% to 1.0% sulfur 

28 Residual Fuel Oil – greater than 1% sulfur 

29 Lubricants (total) 

30 Asphalt and Road Oil 

31 Wax 

32 Still Gas 

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

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

35 Aromatics – Benzene 

36 Aromatics – Toluene 

37 Aromatics – Xylenes (total) 

38 Aromatics – Other than BTX 

40 Sour water 

41 Slop oil 

42 Other wastewater 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

28 

2

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

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

Code No. Type of Tank/Control 

1 Fixed roof tank vented to atmosphere 

2 Fixed roof tank vented to control device 

3 Fixed roof tank using vapor balancing 

4 External floating roof, slotted guidepole 

5 External floating roof with solid guidepole 

6 External floating roof, controlled guidepole 

7 Internal floating roof, slotted guidepole 

8 Internal floating roof with solid guidepole 

9 Internal floating roof, controlled guidepole 

10 External floating roof with geodesic dome roof 

11 Horizontal tank 

12 Pressurized/sphere tank 

99 Other (specify) 

3

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

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

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

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

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

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

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

29 

4

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

list of controls. 

Code No. Type of Degassing Control 

0 None; tank vented to atmosphere while being degassed 

54 Portable internal combustion engine 

55 Portable thermal oxidizer 

56 Portable condensation system 

57 Permanent onsite control device 

99 Other (specify) 

5

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

Code No. Year 

0 2010 

1 2011 

2 2012 

3 2013 

4 2014 

5 2015 

6 2016 

7 2017 

8 2018 

9 2019 

10 2020 or later 

6

 Select the type of primary rim seal. 

Code No. Type of Rim Seal 

0 None 

1 Vapor-mounted seal; flexible wiper type 

2 Vapor-mounted seal; resilient-filled type 

3 Liquid-mounted seal 

4 Mechanical-shoe seal 

7

 Select the type of secondary rim seal. 

Code No. Type of Rim Seal 

0 None 

1 Rim-mounted seal (if primary rim seal is mechanical-shoe seal) 

2 Shoe-mounted seal (if primary rim seal is mechanical-shoe seal) 

3 Vapor-mounted seal; flexible wiper type 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

30 

SECTION 5. CATALYTIC CRACKING UNITS 

 

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

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

at the facility. 

TABLE 5-1. Catalytic Cracking Unit Information 

Unit ID for CCU 

Fresh Feed Capacity (bbl/cd) 

Recycle /Resid Capacity (bbl/cd) 

Percent of CCU Feed that is 

Hydrotreated (%) 

Typical Coke Burn Rate at 

Capacity (tons/cd) 

Type of CCU (fluid, thermal, or 

other) 

Type of CCU Regenerator 

(complete, partial, or variable) 

Is there a CO boiler or other 

combustion device after CCU 

regenerator (Yes/No)? 

Applicable Federal air 

regulation(s)1

If subject to State, local, or 

Tribal air regulation(s), provide 

the citation(s) 

2010 Weighted Average Sulfur 

Concentration in Combined 

Feed (wt%) 

2010 Weighted Average Nickel 

Concentration in Combined 

Feed (wt%) 

2010 Weighted Average 

Vanadium Concentration in 

Combined Feed (wt%) 

Type of PM controls2

Type of SO2 controls3

Type of NOX controls4

 

Footnotes for Table 5-1: 

1

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

31 

2

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

Code No. Type of PM Control 

0 None 

11 Fabric/cartridge filter (“baghouse”) 

12 Venturi/wet scrubber 

13 Electrostatic precipitator (ESP) 

14 Wet ESP 

15 Tertiary cyclone 

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

99 Other (specify) 

3

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

Code No. Type of SO2 Control 

0 None 

24 Wet scrubber/flue gas desulfurization 

25 Spray dryer absorber 

26 DeSOx catalyst, meeting 50/25 ppmv SO2 limit 

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

28 Low sulfur feed (0.3 wt% or less) 

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

99 Other (specify) 

4

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

Code No. Type of NOX Control 

0 None 

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

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

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

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

or other post-combustion device 

36 Selective non-catalytic reduction (SNCR) 

37 Selective catalytic reduction (SCR) 

39 High-efficiency regenerator 

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

41 Other low NOX catalyst additives 

42 LoTOX® scrubber 

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

32 

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

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

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

Unit ID for CCU 

Particle Type 

Concentration (parts per million by weight, ppmw) 

Antimony 

Arsenic 

Beryllium Cadmium 

Chromium 

Cobalt 

Lead 

Manganese 

Mercury 

Nickel 

Selenium 

Vanadium 

 E-cat 

 Fines 

 E-cat 

 Fines 

 E-cat 

 Fines 

 E-cat 

 Fines 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

33 

SECTION 6. FLUID COKING UNITS 

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

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

facility. 

TABLE 6-1. Fluid Coking Unit Information 

Unit ID for FCU 

Feed Capacity (bbl/cd) 

Type of FCU (traditional or 

flexicoker) 

Applicable Federal air regulation(s)1

If subject to State, local, or Tribal air 

regulation(s), provide the citation(s) 

If traditional coker If flexicoker 

Coke Production Capacity 

(tons/cd) 

Typical Coke Burn Rate at 

Capacity (tons/cd) 

Is there a CO boiler or other 

combustion device after FCU 

regenerator (Yes/No)? 

Type of PM controls2

Type of SO2 controls3

Type of NOX controls4

Produced Coke Handling 

Controls and Disposition5

Low Btu gas production rate at 

capacity (scfm) 

Low Btu gas sulfur removal 

technique6

FCU dust/ash quantity 

produced (tons/cd) 

FCU dust/ash handling/disposal 

method7

 

Footnotes for Table 6-1: 

1

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

34 

2

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

Code No. Type of PM Control 

0 None 

11 Fabric/cartridge filter (“baghouse”) 

12 Venturi/wet scrubber 

13 Electrostatic precipitator (ESP) 

14 Wet ESP 

15 Tertiary cyclone 

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

99 Other (specify) 

3

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

Code No. Type of SO2 Control 

0 None 

24 Wet scrubber/flue gas desulfurization 

25 Spray dryer absorber 

28 Low sulfur feed (0.3 wt% or less) 

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

99 Other (specify) 

4

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

Code No. Type of NOX Control 

0 None 

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

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

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

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

or other post-combustion device 

36 Selective non-catalytic reduction (SNCR) 

37 Selective catalytic reduction (SCR) 

39 High-efficiency regenerator 

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

41 Other low NOX catalyst additives 

42 LoTOX® scrubber 

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

35 

5

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

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

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

to suppress fugitive dust emissions. 

Code No. Disposition Code Letter Storage/Handling Method 

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

loading/processing 

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

loading/processing 

3 Shipped off-site: some to coke 

calciner and some as fuel 

C Enclosed conveyer to open storage pile 

or bin, wind break only 

4 Shipped off-site: other or unknown 

use 

D Enclosed conveyer to open storage pile 

or bin, wetting only 

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

or bin, wind break and wetting 

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

bin, wind break only 

7 Some used on-site as fuel, 

remainder sent off-site to coke 

calciner 

G Open conveyance to open storage pile or 

bin, wetting only 

8 Some used on-site as fuel, 

remainder sent off-site for use as 

fuel 

H Open conveyance to open storage pile or 

bin, wind break and wetting 

99 Other (specify) Z Other (specify) 

6

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

Code No. Low Btu Gas Sulfur Control 

0 None 

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

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

3 Selexol® 

4 Rectisol® 

5 COS hydrolysis + conventional amine scrubber 

6 COS hydrolysis + sterically-hindered amine scrubber 

7 COS hydrolysis + Selexol® 

8 COS hydrolysis + Rectisol® 

9 Sulfinol® 

98 Management practice or work practice (specify) 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

36 

7

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

and disposal method. 

Code No. Flexicoking Dust/Ash Handling and Disposal Methods 

1 Used on-site as fuel 

2 Disposed of in on-site landfill 

3 Disposed of in off-site landfill 

4 Shipped off-site for use as fuel 

5 Shipped off-site for metals recovery 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

37 

SECTION 7. DELAYED COKING UNITS 

 

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

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

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

connected to a single fractionator and the fractionator. 

TABLE 7-1. Delayed Coking Unit Operating Information 

Unit ID for DCU 

Feed Capacity (bbl/cd) 

Coke Production Capacity (tons/cd) 

Type of Coke Produced1

Number of Coke Drums 

Height of Single Coke Drum (ft) 

Diameter of Single Coke Drum (ft) 

Typical Coke Drum Outage (ft) 

Typical Coke Drum Pressure When First Vented to 

Atmosphere (psig) 

Typical Coke Drum Temperature at Top of Drum 

When First Vented to Atmosphere (°F) 

Typical Water Height in Coke Drum When First 

Vented to Atmosphere (ft) 

Typical Cycle Time Quench Water 

Applicable Federal air regulation(s)7

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

provide the citation(s) 

Complete Coke Drum Cycle Time (hr)2

Coke Drum Feed Cycle Time (hr) 

Coke Drum Steam Purge Time (hr) 

Coke Drum Water Quenching Time (hr) 

Coke Drum Depressurization Vent Time (hr) 

Coke Drum Coke Cutting Time (hr) 

Coke Drum Preheat/Standby Time (hr) 

Water Quenching Cycle Description3

Typical Quench Water Flow Rate during 

Quenching Cycle (gal/min) 

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

Purged Steam Blowdown System Description4

Quench Water Disposition5

Cutting Water Source and Storage/Handling6

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

38 

Footnotes for Table 7-1: 

1

 Select from the following list of produced coke types. 

Code No. Quench Water Source 

1 Needle coke, anode grade 

2 Needle coke, fuel grade 

3 Sponge coke, anode grade 

4 Sponge coke, fuel grade 

5 Shot coke, anode grade 

6 Shot coke, fuel grade 

99 Other (specify) 

2

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

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

+ cutting time + preheat/standby time. 

3

 Select from the following list of water quenching cycle descriptions. 

Code No. Quench Water Source 

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

2 Use process or recycled blowdown water 

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

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

5 Use treated water from sour water stripper 

6 Use treated water from WWTS 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

39 

4

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

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

atmosphere). 

Code No. Condensed Water Disposition Code Letter 

Uncondensed Vapor Disposition 

When Not Sent Directly to DCU 

Fractionator 

1 Sent to WWTS 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 gas 

header system to general facility flare 

4 Recycled to unit and used as 

quench water 

D Uncondensed vapors are sent to flare gas 

recovery system 

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

directly to process heater or boiler 

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

directly to amine treatment unit or fuel 

gas system 

99 Other (specify) G Uncondensed vapors are controlled by 

oil scrubber or lean oil absorber prior to 

venting to atmosphere 

 H Uncondensed vapors are vented directly 

to atmosphere 

 Z Other (specify) 

5

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

drum after the vessel is vented to the atmosphere). 

Code No. Quench Water Disposition 

1 Sent to WWTS 

2 Sent to sour water stripper 

3 Used to make steam 

4 Recycled to unit and used as quench water 

5 Used as coke cutting water 

6 Used as general process water 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

40 

6

 Select from the following list of cutting water source and 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 WWTS F Directed to WWTS 

99 Other (specify) Z Other (specify) 

7

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

41 

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

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

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

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

set of similar DCU. 

TABLE 7-2. Delayed Coking Unit Feed Information 

Feed Source 

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

Typical 

% Feed1

Maximum 

% Feed2

Typical 

% Feed1

Maximum 

% Feed2

Atmospheric distillation column bottoms 

Heavy gas oil 

Vacuum distillation column 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 WWTS 

- Other sludges from WWTS 

Other (specify): ____________ 

Footnotes for Table 7-2: 

1

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

100%. 

2

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

this column is expected to exceed 100%. 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

42 

SECTION 8. CATALYTIC REFORMING UNITS 

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

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

(CRU) at the facility. 

TABLE 8-1. Catalytic Reforming Unit Information 

Unit ID for CRU 

Feed Capacity (bbl/cd) 

Operating Pressure (psig) 

Hydrogen Production Rate (purified 

basis) (MMcf/cd at 0°C and 1 atm) 

Applicable Federal air regulation(s)1

If subject to State, local, or Tribal 

air regulation(s), provide the 

citation(s) 

Average Annual Regeneration 

Frequency (cyclic and semi-regen 

units; regeneration cycles/year)2

Average Annual Regeneration Time 

(hours/year)2

Depressurization /Purge Cycle Vent 

Disposition/control3

Purge Process Type4

Coke Burn-off Cycle Vent 

Disposition/control5

Coke Burn-off Cycle Duration per 

Cycle 

Rejuvenation Cycle Vent 

Disposition/control6

Reduction or Activation Cycle Vent 

Disposition/control7

Chloriding Agent8

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

43 

Footnotes for Table 8-1: 

1

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

99 Other (specify) 

2

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

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

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

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

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

cycle by the calculated number of cycles per year. 

3

 Select from the following list of purge controls. 

Code No. Type of Depressurization/Purge Disposition or Control 

0 Directly to the atmosphere 

1 To fuel gas system, then atmosphere 

2 To fuel gas system, then flare, then atmosphere 

3 To flare, then atmosphere 

4 To process heater or boiler, then atmosphere 

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

99 Other (specify) 

4

 Select from the following list of purge processes. 

Code No. Type of Purge Process 

1 Purge by sequential pressurizing/purging with nitrogen 

2 Purge using nitrogen and vacuum pump 

3 Purge by sequential pressurizing/purging with methane 

4 Purge using methane and vacuum pump 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

44 

5

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

Code No. Type of Coke Burn-off Control 

1 None 

2 Caustic spray injection 

3 Packed-bed wet scrubber 

4 Tray tower wet scrubber 

5 ChlorsorbTM

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

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

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

99 Other (specify) 

6

 Select from the following list of rejuvenation controls. 

Code No. Type of Rejuvenation Controls 

0 Directly to the atmosphere 

1 To fuel gas system, then atmosphere 

2 To fuel gas system, then flare, then atmosphere 

3 To flare, then atmosphere 

4 To process heater or boiler, then atmosphere 

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

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

99 Other (specify) 

7

 Select from the following list of reduction or activation controls.

Code No. Type of Reduction or Activation Controls 

0 Directly to the atmosphere 

1 To fuel gas system, then atmosphere 

2 To fuel gas system, then flare, then atmosphere 

3 To flare, then atmosphere 

4 To process heater or boiler, then atmosphere 

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

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

99 Other (specify) 

8

 Select from the following list of chloriding agents. 

Code No. Type of Chloriding Agent 

1 Perchloroethylene 

2 Trichloroethene 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

45 

SECTION 9. SULFUR RECOVERY UNITS 

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

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

the facility. 

TABLE 9-1. Sulfur Recovery Unit Information 

Unit ID for SRU 

Sulfur, Sulfur Cake, or H2SO4

Production Capacity (LT/cd) 

Type of SRU1

Sulfur Recovery Plant (SRP) ID2

Applicable Federal air 

regulation(s)3

If subject to State, local, or 

Tribal air regulation(s), provide 

the citation(s) 

Type of Tail Gas Treatment 

Unit4

Controls for Primary Sulfur Pit 

Primary Sulfur Pit Maintenance 

Time in 2010 (hr/yr) 

SRU Back-up 

Controls/Reduction Measures5

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

46 

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 MCRCTM-SUPERCLAUS® 

7 Lo-Cat® 

8 Caustic scrubber 

9 Sulfuric acid plant 

99 Other (specify) 

2

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

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

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

3

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

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

99 Other (specify) 

4

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

the unit. List all that apply. 

Code No. Type of Tail Gas Treatment Unit 

0 None 

1 Incinerator 

2 Flare 

3 SCOT unit 

4 Beavon/amine 

5 Beavon/Stretford®

6 Cansolv® 

7 Lo-Cat® 

8 Wellman-Lord 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

47 

5

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

Code No. Type of SRU Back-up Control 

0 None 

1 Dedicated SRU flare 

2 General plant flare 

3 Divert to other SRU 

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

98 Management practice or work practice (specify) 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

48 

SECTION 10. HYDROGEN PLANT VENTS 

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

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

common control of the facility. 

TABLE 10-1. Hydrogen Plant and Vent Information 

Unit ID for Hydrogen Plant 

Hydrogen Production Capacity 

(purified basis) (MMcf/cd at 

0°C and 1 atm) 

Type of Hydrogen Production 

Unit1

Applicable Federal air 

regulation(s)2

If subject to State, local, or 

Tribal air regulation(s), 

provide the citation(s) 

Hydrogen Purification Method 

Used3

Type of Feedstock Used4

Steam Generation Rate (lb/hr) 

PSA Purge/Off Gas Flow Rate 

(scfm) 

PSA Purge/Off Gas 

Disposition5

Reformer Deaerator Vent Flow 

Rate (scfm) 

Other Atmospheric Vent 

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

Table 11-1) 

 

Footnotes for Table 10-1: 

1

 Select from the following list of hydrogen production units. 

Code No. Type of Hydrogen Production Unit 

1 Steam-methane reforming 

2 Partial oxidation 

3 Electrolysis 

4 Gasification 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

49 

2

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

99 Other (specify) 

3

 Select from the following list of hydrogen purification processes. 

Code No. Type of Hydrogen Purification Process 

1 Pressure-swing adsorption 

2 Membrane separation 

3 Cryogenic separation 

99 Other (specify) 

4

 Select from the following list of feedstocks. 

Code No. Type of Hydrogen Production Unit Feedstock 

1 Methane 

2 Refinery fuel gas 

3 Refinery fuel gas augmented with additional methane 

99 Other (specify) 

5

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

Code No. Disposition of the PSA Purge/Off Gas 

1 Used as fuel in the reformer furnace 

2 Used as fuel elsewhere in the refinery 

3 Sent to flare 

4 Vented to atmosphere 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

50 

SECTION 11. OTHER ATMOSPHERIC VENTS 

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

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

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

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

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

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

distillation column vents; blowdown systems vents, knock-out pot vents, vacuum ejectors 

(hot well vents), analyzer vents as well as vents from MeroxTM treatment systems, fuel 

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

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

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

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

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

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

with storage tanks. 

TABLE 11-1. Other Atmospheric Vent Information 

Atmospheric Vent 

ID 

Type of 

Atmospheric Vent1

Unit ID (if 

applicable) with 

which the Vent is 

Associated2

Applicable Federal 

air regulation(s)3

If subject to State, 

local, or Tribal air 

regulation(s), 

provide the 

citation(s) 

Atmospheric Vent 

Operating Hours4

Atmospheric Vent 

Controls5

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

51 

Footnotes for Table 11-1: 

1

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

of unit or equipment associated with this vent. 

Code No. Type of Other Atmospheric Vent 

1 Atmospheric crude distillation column/reflux condenser vent 

2 Catalytic cracking unit distillation column/reflux condenser vent 

3 Catalytic hydrocracking unit distillation column/reflux condenser vent 

4 Catalytic reforming unit distillation column/reflux condenser vent 

5 Coking unit distillation column/reflux condenser vent 

6 Other distillation column/reflux condenser vent 

7 Vacuum distillation column vacuum system exhaust vent 

8 Hot well vent/vacuum jet exhaust 

9 Other vacuum system exhaust 

10 Drier regeneration vent 

11 Coke calcining vent 

12 Asphalt blowing still vent 

13 Blow down system vent 

14 Knock-out pot vent 

15 Analyzer vent 

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

99 Other (specify) 

2

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

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

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

3

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

52 

4

 Select from the following list of operating scenarios. 

Code No. Type of Operation 

1 Continuous (operates whenever the process is operating) 

2 Intermittent; 4,000 hours per year or more 

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

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

5 Intermittent; less than 1,000 hours per year 

5

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

Code No. Type of Control Device 

0 None 

11 Fabric/cartridge filter (“baghouse”) 

12 Venturi/wet scrubber 

13 Electrostatic precipitator (ESP) 

14 Wet ESP 

24 Wet scrubber/flue gas desulfurization 

36 Selective non-catalytic reduction (SNCR) 

37 Selective catalytic reduction (SCR) 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

52 Carbon adsorber 

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

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

53 

SECTION 12. FLARES 

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

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

TABLE 12-1. Flare Information 

Flare ID or Description 

If the flare is dedicated to 

one processing unit, enter 

the Unit ID 

Flare Diameter (ft) 

Flare release height (ft) 

Flare Location (Latitude) 

Flare Location (Longitude) 

Type of Flare1

Flare Assist Type2

Target Assist Ratio (if 

applicable) 

Type of Flare Pilot or 

Ignition System3

Applicable Federal air 

regulation(s)4

If subject to State, local, or 

Tribal air regulation(s), 

provide the citation(s) 

Typical Lower Heating 

Value of Waste Gas 

(Btu/scf @ 60°F) 

Flare Operating Hours5

Flare Management Plan6

Flare Reduction Measures7

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

54 

Footnotes for Table 12-1: 

1

 Select from the following list of flares. 

Code No. Type of Flare 

1 Elevated flare 

2 Elevated flare, pressure assisted 

3 Ground level flare 

4 Ground level flare, pressure assisted 

99 Other (specify) 

2

 Select from the following list of flare assist types. 

Code No. Flare Assist Types 

1 Unassisted 

2 Steam assisted 

3 Air assisted 

99 Other (specify) 

3

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

Code No. Type of Flare Pilot or Ignition System 

1 Continuous pilot flame 

2 Spark ignition, every minute regardless of flow 

3 Spark ignition, triggered by flow sensor/monitor 

99 Other (specify) 

4

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

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

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

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

Code No. Federal Air Regulation 

0 None 

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

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

55 

5

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

of the flare. 

Code No. Type of Operation 

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

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

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

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

5 Combusts flare gas only during startup or shutdown 

6 Combusts flare gas only during upsets 

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

6

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

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

Code No. Components of Flare Management Plan 

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

flare. 

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

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

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

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

normal process operations 

5 Procedures to reduce/minimize purge or sweep gas use 

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

exceeding a set SO2 emission level 

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

a set flow rate level 

8 Procedures for monitoring flow of gas to the flare 

9 Procedures for monitoring Btu of flared gas 

10 Procedures for monitoring sulfur content of flared gas 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

56 

7

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

emissions from the flare. List all that apply. 

Code No. Type of Control Device 

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

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

system) 

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

normal operations 

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

operations 

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

level 

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

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

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

57 

SECTION 13. FUEL GAS TREATMENT UNITS 

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

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

facility. 

TABLE 13-1. Fuel Gas Sulfur Treatment Unit Information 

Fuel Gas Treatment Unit ID 

If the fuel gas treatment unit is dedicated to 

one process unit, enter the Unit ID for the 

dedicated process unit 

Does this treatment unit receive gas from a 

coking unit? (Yes/No) 

Type of sulfur removal technique(s) used1

Fuel gas flow rate at treatment unit capacity 

(scfm) 

Average fuel gas flow rate into the treatment 

unit (scfm) 

Estimated operating hours in 2010 

Types of sulfur compounds in the untreated 

fuel gas2

Estimated annual average H2S concentration 

in treated fuel gas exiting the treatment unit 

(ppmv) 

Estimated annual average total sulfur 

concentration in the treated fuel gas exiting 

the treatment unit (ppmv) 

Applicable SO2 federal air regulation(s) for 

combustion units that burn the fuel gas3

If subject to State, local, or Tribal air 

regulation(s) for SO2 from combustion units 

that burn the fuel gas, provide the citation(s) 

Are there any atmospheric vents in the system 

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

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

58 

Footnotes for Table 13-1: 

1

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

Code No. Type of Sulfur Removal Technique 

1 Absorption using MDEA solvent 

2 Absorption using MEA solvent 

3 Absorption using DEA solvent 

4 Absorption using DIPA solvent 

5 Absorption using DGA solvent 

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

7 Flexsorb® process 

8 Selexol® process 

9 Rectisol® process 

10 Sulfinol® process 

11 MeroxTM process 

12 COS hydrolysis 

13 Hot potassium carbonate 

14 Lo-Cat® 

15 Caustic scrubber 

16 Sodium hydrosulfide (NaSH) production process 

99 Other (specify) 

2

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

Code No. Type of Sulfur Containing Compound 

1 Hydrogen sulfide (H2S) 

2 Carbonyl sulfide (COS) 

3 Carbon disulfide (CS2) 

4 Mercaptans 

5 Thioethers 

99 Other (specify) 

3

 Select the Federal regulation(s) for SO2 to which the fuel gas combustion units are subject from 

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

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

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

are subject). 

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

0 None 

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

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

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

59 

SECTION 14. HEAT EXCHANGE (COOLING WATER) SYSTEMS 

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

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

at the facility. 

TABLE 14-1. Cooling Water System Information 

HE System ID or 

Description 

Unit IDs for Process Units 

Serviced by Cooling Water 

System 

Cooling Water System 

Operation – Fluid Pressure1

Cooling Water System 

VOC/HAP Concentration2

Type of Cooling Water 

System3

Applicable Federal air 

regulation(s)4

If subject to State, local, or 

Tribal air regulation(s), 

provide the citation(s) 

Cooling Water Flow/ 

Recirculation Rate 

(gal/min) 

Water Make-up Rate 

(gal/min) 

Gas or Chemical 

Additive/Disinfection 

Method5

Gas or Chemical Addition 

Rate Value 

Gas or Chemical Addition 

Rate Units (volume or mass 

per time) 

Chemical Addition 

Location 

 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

60 

Footnotes for Table 14-1: 

1

 Select from the following list of cooling water system operations. 

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

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

the minimum water pressure 

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

higher than the minimum water pressure 

2

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

concentrations. 

Code No. Cooling Water System VOC/HAP Concentration 

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

and less than 5 wt% organic HAP 

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

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

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

organic HAP 

3

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

Code No. Type of Cooling Water System 

1 Once-through cooling water system 

2 Natural draft cooling tower 

3 Induced draft cooling tower (fans at outlet) 

4 Forced draft cooling tower (fans for inlet air) 

99 Other (specify) 

4

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

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

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

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

is subject). 

Code No. Federal Air Regulation 

0 None 

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

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

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

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

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

61 

5

 Select from the following list of chemical additives. 

Code No. Type of Chemical Additive/Disinfection Method 

1 Chlorine from gas cylinders 

2 Sodium hypochlorite 

3 Calcium hypochlorite 

4 Chloramine 

5 Ozonation 

6 UV disinfection 

99 Other (specify) 
Form Approved 03/28/2011 

OMB Control No. 2060-0657 

Approval Expires 03/31/2014 

62 

SECTION 15. WASTEWATER COLLECTION AND TREATMENT 

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

2. Please provide the following information for the facility. 

a. What is the daily average WWTS flow rate for all WWTS at the facility (or average 

discharge rate if wastewater is treated off-site)? 

b. What was the Total Annual Benzene (TAB) quantity for the facility in 2010? 

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

compliance option selected by the facility. 

1 2 Mg/yr 

2 6 BQ 

3 Not applicable because original TAB < 10 Mg/yr 

4 Other (specify) 

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

drawdowns: 

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

b. Quantity of benzene in wastewater generated via tank draw downs in 2010: ___ lb 

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

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

WWTS (identified in Part 1, Question 16) at the facility and the applicable air regulations 

for each selected unit. 
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TABLE 15-1. Wastewater Treatment Processes 

Wastewater 

Treatment and 

Collection System 

ID 

Type of 

Wastewater 

Treatment 

Process1

For Steam and Sour Water 

Strippers, also provide the 

total of the average steam 

usage rates for each 

stripper of this type in 2010 

(lb/hr)2 

Applicable 

Federal air 

regulation(s)3

If subject to State, 

local, or Tribal air 

regulation(s), provide 

the citation(s) 

 

 

 

 

Footnotes for Table 15-1: 

1

 Select from the following list of wastewater treatment processes. 

Code No. Wastewater Treatment Process 

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

1 Benzene/VOC steam stripper 

2 Oil-water separator 

3 Dissolved air/gas flotation 

4 Equalization basin/tank 

5 Neutralization basin/tank 

6 Activated-sludge biological treatment unit 

7 Aerated surface impoundment 

8 Non-aerated surface impoundment 

9 Anaerobic sludge digester 

10 Aerobic sludge digester 

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

12 Primary clarifier 

13 Secondary clarifier 

14 Sour water stripper 

2

 For example, if you have two sour water strippers, add the average steam usage rate in pounds 

per hour in 2010 for the first sour water stripper to the average steam usage rate in pounds per 

hour in 2010 for the second sour water stripper and report the resulting sum in this column. 

3

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

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

regulations to which the wastewater treatment process is subject according to the applicability 
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of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to 

which the wastewater treatment process is subject). 

Code No. Federal Air Regulation 

0 None 

1 BWON (40 CFR part 61, subpart FF), but exempt from control requirements 

2 BWON (40 CFR part 61, subpart FF) 

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

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

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

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

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

99 Other (specify) 

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

routinely generates wastewater. Please provide your best estimate based on available 

information; no additional testing is required to complete this request. 

TABLE 15-2. Wastewater Generation Information 

Process 

Unit ID 

Average wastewater 

generation rate 

(gallons/operating day) 

Average benzene 

concentration 

(ppmw) 

Average concentration of 

organic HAP (ppmw) 

Average VOC 

concentration 

(ppmw) 

 

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

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

systems (including junction box vents) and gases purged from covered WWTS. 
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TABLE 15-3. Wastewater Vent Information 

Atmospheric 

Vent ID 

Description 

of 

Atmospheric 

Vent1

Applicable 

Federal air 

regulation(s)2

If subject to State, 

local, or Tribal air 

regulation(s), 

provide the 

citation(s) 

Atmospheric 

Vent Operating 

Hours3

Atmospheric 

Vent 

Controls4

 

Footnotes for Table 15-3: 

1

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

Code No. Type of Unit/Equipment Associated with Vent 

1 Drain system vent (including junction box vents) 

2 Vent from wastewater treatment unit 

99 Other (specify) 

2

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

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

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

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

Code No. Federal Air Regulation 

0 None 

1 BWON (40 CFR part 61, subpart FF), but exempt from control requirements 

2 BWON (40 CFR part 61, subpart FF) 

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

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

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

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

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

99 Other (specify) 
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3

 Select from the following list of operating scenarios. 

Code No. Type of Operation 

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

2 Intermittent; 4,000 hours per year or more 

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

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

5 Intermittent; less than 1,000 hours per year 

4

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

Code No. Type of Control Device 

0 None 

1 Water seal (e.g., for a junction box vent) 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

53 Single carbon adsorber canister 

54 Two carbon adsorber canisters in series 

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

99 Other (specify) 
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SECTION 16. PRODUCT LOADING OPERATIONS 

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

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

vessels (tank ships and barges). 

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

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

Part I of this ICR). 

0 None. There are no shipments made via marine vessels 

1 Marine vessel loading operations are contiguous with the refinery. 

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

refinery. 

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

the coast). 

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

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

Yes No 

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

loading operations) treated in the refinery’s WWTS? 

Yes No

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

rail car. 

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

with the refinery’s shipments via tank truck (as reported in Question 15 of Part I of this 

ICR). 

0 None. There are no shipments made via tank truck 

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

facility). 

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

facility). 

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

refinery’s shipments via rail truck (as reported in Question 15 of Part I of this ICR). 
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0 None. There are no shipments made via rail car 

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

facility). 

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

facility). 

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

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

the refinery facility). 

TABLE 16-1. Product Loading Information 

Unit ID for loading operation 

Type of vessel loaded1

Capacity loading throughput 

(gal/yr) 

Applicable Federal air 

regulation(s)2

If subject to State, local, or 

Tribal air regulation(s), 

provide the citation(s) 

Typical annual operating 

hours (hr/yr) 

Does the facility or parent 

company own the vessels being 

loaded? (Yes/No) 

Type of control device or 

control technique3

 
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Footnotes for Table 16-1: 

1

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

Code No. Type of Vessel 

1 Tank ship 

2 Barge 

3 Truck/tank truck 

4 Rail car 

5 Containers with capacity less than 250 gallons 

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

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

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

99 Other (specify) 

2

 Select the Federal air regulation(s) to which the loading operation is subject from the following 

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

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

regulations that are referenced from the regulation(s) to which the loading operation is subject). 

Code No. Federal Air Regulation 

0 None 

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

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

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

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

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

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

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

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

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

99 Other (specify) 

3

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

Code No. Type of Control 

0 None 

50 Thermal or catalytic incinerator/oxidizer 

51 Condenser 

52 Carbon adsorber 

55 Flare 

80 Submerged loading 

82 Bottom loading 

83 Vapor balancing system 

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

99 Other (specify) 
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PART III. NON-ROUTINE EMISSIONS 

Complete the following table for each non-routine emissions event during 2010 where the emissions exceeded nor

controls were bypassed, or the effectiveness of the normal controls was reduced. 

Date of 

release 

Type of release 

(startup/shutdown; 

equipment or component 

malfunction) 

Description of release 

event 

Process 

units 

associated 

with the 

release 

Duration 

of the 

release 

event 

(hours) 

Pollutant 

name 

Pollutant 

CAS No. 

or 

Pollutant 

Code 

Qu

pol

rel
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PART IV. COST DATA (Optional) 

Cost data for air pollution control devices (APCD), process changes, equipment 

changes/upgrades, and management or work practices implemented within the last 5 years are 

optionally requested. While you are not required to complete this part, EPA highly recommends 

that you provide available cost data so that we can more accurately determine the compliance 

costs of control alternatives that may be assessed during the review of the refinery emission 

standards. 

For any APCD, process changes, equipment changes/upgrades, and management or work 

practices implemented within the last 5 years for which you have readily available cost 

information, please provide those costs as described in this part. Include only process changes, 

equipment changes/upgrades, and management or work practices implemented to reduce 

emissions. Do not include projects needed to meet environmentally driven product 

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

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

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

separate spreadsheet. If you know an approximate cost for a control technique but do not have 

the level of detail requested in the tables, please provide the approximate cost and your best 

estimate of which of the components in the appropriate table were factored into that approximate 

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

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

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

for this ICR on the ICR website (https://refineryicr.rti.org). 

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

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

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

APCD: 

• Electrostatic precipitators 

• Wet scrubbers 

• Baghouses 

• SCR/SNCR for NOX control 

• Steam strippers 

• Carbon adsorbers 

• Thermal/catalytic oxidizers 

• Flares 

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

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

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

• Floating roofs, rim seals, and fittings seals on storage vessels 

• Installation of geodesic dome for external floating roof tank 

• Installation of guidepole sleeves/wipers or other tank fitting gaskets 

3. Please provide any readily available costs for other techniques used at your refinery to 

reduce emissions of any pollutant. EPA is particularly interested in techniques that are 

not already included in Federal regulations. Provide as much detail in your cost estimate 

as possible (e.g., unit ID for the unit from which emissions are reduced, amount of time 

needed to complete the technique (labor costs), cost of any equipment needed on a 

temporary basis, cost of any monitoring devices needed to indicate when action is needed 

or to measure progress). Types of techniques that EPA is particularly interested in 

include: 

• Use of a portable or temporary control device (e.g., for degassing of storage 

tanks) 

• Monitoring devices (e.g., monitors that record the duration and quantity of 

compounds released from a PRD) 

• Pollution prevention techniques 

• Energy management programs identified in Part II, Section 1 

• Other management practices or work practices that you identified in Part II 
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Table 1. Cost Data for APCD (Optional)1

APCD ID 

Unit ID associated with this APCD 

APCD Type

2

APCD Size

3

New or retrofit APCD?

4

Year of APCD installation 

Expected APCD equipment life (yrs) 

Demolition cost for previous APCD, if any ($) 

CAPITAL COSTS ANNUAL OPERATING COSTS10

Base year for capital costs 

Purchased 

equipment 

costs ($)5

Installation costs ($)

8

Total Installed Cost of APCD

9

Base year for operating costs 

Operating labor ($) 

Maintenance labor ($) 

Utilities ($) 

Waste disposal ($) 

Primary equipment ( $)

6

Auxiliary equipment ($)

7

Instrumentation and monitors ($) 

Sales tax and freight ($) 

Total purchased equipment costs ($) 

Electricity 

Water 

Steam 

Natural gas 

Liquid chemicals 

Solid chemicals 

Compressed Air 

Other (specify) 

Total utilities cost ($/yr)12

hr/yr 

$/yr 

hr/yr 

$/yr 

kWh/yr 

$/kWh 

gal/yr 

$/gal 

lb/yr 

$/lb 

scf/yr 

$/scf 

gal/yr 

$/gal 

lb/yr 

$/lb 

scf/yr 

$/scf 

amt/yr11

$/amt 

amt/yr11

$/yr 

1 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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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 the most significant item of the major supplies and replacement parts; examples include catalyst for SCR and catalytic incinerators, bags for fa

carbon adsorbers. 

14 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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Code No. Type of APCD 

1 Amine treatment (e.g., installation of new amine treatment unit) 

2 Caustic spray injection 3 Packed-bed wet scrubber 4 Tray tower wet scrubber 5 ChlorsorbTM

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 Single carbon adsorber canister 54 Two carbon adsorber canisters in series 55 Flare 56 Portable internal combustion engine 57 Portable thermal oxidizer 58 Portable condensation system 59 Permanent onsite control device for storage tanks 60 Flare gas recovery 83 Vapor balancing system 99 Other (specify) 
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Table 2. Cost Data for Process and Equipment Changes (Optional) 

Unit ID 

Process or 

equipment 

change type1

Process or 

equipment 

change 

description2

Year of process 

or equipment 

change 

Number of days 

process shut 

down in order to 

make the change 

(days of lost 

production)3

Total capital 

cost, $4

Change in 

annua

operating 

$/yr5

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 

the type of process or equipment change. 

2 Describe the process or equipment change. Be as descriptive as possible. For example, for installation of low NOX or ultra low NOX burners for a pro

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

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

4 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. 

5 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. 

6 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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Code No. Type of Process or Equipment Change 

1 Amine treatment (change in existing amine treatment system operation) 21 H2S limit in fuel gas 

22 TRS limit in fuel gas 23 Low sulfur distillate or heavy gas oil 26 DeSOx catalyst, meeting 50/25 ppmv SO2 limit 

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

28 Low sulfur feed (0.3 wt% or less) 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 fill loading 82 Bottom loading 99 Other (specify) 
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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. Five types of existing emissions 

data are requested: 1) source test data, 2) qualified CEMS data, 3) qualified CMS data, 4) 

biological treatment units data, and 5) 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 instructions 

for this ICR on the ICR website (https://refineryicr.rti.org). 

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 5 through 16 and 

for boilers included in Table 1-2 (of Part II) 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 test for that pollutant and process unit. 

(We are only requesting the most recent test per unit for one pollutant, but you may 

submit more than one test, particularly if additional tests reflect the effect of different 

operating conditions or equipment configurations.) 

In addition, complete the source test log shown below for each source test you submit. 

(Electronic copies of this table can be downloaded from the ICR website 

(https://refineryicr.rti.org).) Note that the information requested in the summary table 

includes: 

(A) test number (use any unique identifier you choose for each test) 

(B) APCD type (if not clear from the test report), 

(C) a description of how the configuration of the emission unit, combustion controls, 

collection system, or APCD has changed since the test was conducted, if 

applicable, 

(D) any notes specific to that emissions test (optional), and 

(E) how often you are required to test the emission unit (optional). 

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 5 through 

16 and for boilers included in Table 1-2 (of Part II). Report daily averages for each day 

in 2010 using the Microsoft® Excel CEMS Daily Template available on the ICR website 
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(https://refineryicr.rti.org). A separate Excel CEMS Daily Template should be completed 

for each pollutant and type of unit. 

Qualified CEMS data include: data from a PM CEMS that meets Performance 

Specification 11 or 15; data from a CO CEMS that meets Performance Specification 4; 

data from a SO2 and/or NOX CEMS that meets Performance Specification 2; data from a 

THC CEMS that meets Performance Specification 8A; or data from any CEMS meeting 

the accuracy and ongoing QA/QC requirements of 40 CFR part 60, Appendix F. Use 

only qualified CEMS data and determine the daily averages using by averaging the 

hourly CEMS values for each hour for which qualified CEMS data are available. If there 

are no qualified CEMS data for any hour in a given day, report “ND” (no data) for that 

daily average. 

In addition, complete the log shown below for each set of CEMS data you submit. 

(Electronic copies of this table can be downloaded from the ICR website 

(https://refineryicr.rti.org).) Note that the information requested in the summary table 

includes: 

(A) ID number for the set of CEMS data (use a unique identifier for each set of data; 

each identifier should include the pollutant monitored) and 

(B) APCD type. 

You may complete other fields in the log if you wish to provide additional data. 

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. Only CMS data listed in 

the previous sentence are requested; no other type of CMS data are requested. Report 

daily averages for each day in 2010 using the Microsoft® Excel CMS Daily Template 

available on the ICR website (https://refineryicr.rti.org). A separate Excel CMS Daily 

Template should be completed for each pollutant and type of unit. 

Qualified CMS data include: data from a H2S CMS that meets Performance 

Specification 7; data from a reduced sulfur or total reduced sulfur CMS that meets 

Performance Specification 7; data from a hydrocarbon or Btu CMS (gas composition 

monitor) that meets Performance Specification 5; data from any CMS meeting the 

accuracy and ongoing QA/QC requirements of 40 CFR part 60, Appendix F; or data from 

any CMS for that has been calibrated per the manufacturer’s specifications within the 

past 12 months and is operated and maintained (including on-going QA/QC 

requirements) according to the manufacturer’s specifications. Use only qualified CMS 

data and determine the daily averages using by averaging the hourly CMS values for each 

hour for which qualified CMS data are available. If there are no qualified CMS data for 

any hour in a given day, report “ND” (no data) for that daily average. 

In addition, complete the log shown below for each set of CMS data you submit. 

(Electronic copies of this table can be downloaded from the ICR website 

(https://refineryicr.rti.org).) Note that the information requested in the summary table 

includes: 
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(A) ID number for the set of CMS data (use a unique identifier for each set of data; 

each identifier should include the parameter monitored) and 

(B) APCD type. 

You may complete other fields in the log if you wish to provide additional data. 

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. (See the guidance provided on the ICR website 

(https://refineryicr.rti.org) for more information about biodegradation rate tests and 

complete mixing tests.) 

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. 
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PART V. LOG OF SOURCE TESTS AND MONITORING DATA PROVIDE

Test or 

Monitoring 

Data ID1

Unit 

ID(s) 

If the APCD type(s) is not 

clear from the test report, 

enter the APCD type(s) 

Configuration 

changes2

OPTIONAL: 

Process testing 

notes3

OPTIONAL: How often are 

required to perform testing o

emission unit for the pollutants 

1 Assign a unique ID or number to each test report, CEMS data set, or CMS data set that you provide so that EPA can match your responses in this log to 

monitoring data. For CEMS data and CMS data, the identifier should include the pollutant or other parameter being monitored. 

2 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” 

3 Use this column for notes or if helpful to specify the emission points tested (e.g., for equipment with multiple emission points, where only selected em