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Subpart Y—Petroleum Refineries

§ 98.250 Definition of source category.

(a) A petroleum refinery is any facility engaged in 

producing gasoline, gasoline blending stocks, naphtha, kerosene, 

distillate fuel oils, residual fuel oils, lubricants, or asphalt 

(bitumen) through distillation of petroleum or through 

redistillation, cracking, or reforming of unfinished petroleum 

derivatives, except as provided in paragraph (b) of this 

section.

(b) For the purposes of this subpart, facilities that 

distill only pipeline transmix (off-spec material created when 

different specification products mix during pipeline 

transportation) are not petroleum refineries, regardless of the 

products produced.

(c) This source category consists of the following sources 

at petroleum refineries: Catalytic cracking units; fluid coking 

units; delayed coking units; catalytic reforming units; coke 

calcining units; asphalt blowing operations; blowdown systems; 

storage tanks; process equipment components (compressors, pumps, 

valves, pressure relief devices, flanges, and connectors) in gas 

service; marine vessel, barge, tanker truck, and similar loading 

operations; flares; sulfur recovery plants; and non-merchant 

hydrogen plants (i.e., hydrogen plants that are owned or under 

the direct control of the refinery owner and operator).
Page 2 of 60

§ 98.251 Reporting threshold.

You must report GHG emissions under this subpart if your 

facility contains a petroleum refineries process and the 

facility meets the requirements of either §98.2(a)(1) or (a)(2).

§ 98.252 GHGs to report.

You must report:

(a) CO2, CH4, and N2O combustion emissions from stationary 

combustion units and from each flare. Calculate and report the 

emissions from stationary combustion units under subpart C of 

this part (General Stationary Fuel Combustion Sources) by 

following the requirements of subpart C, except for emissions 

from combustion of fuel gas. For CO2 emissions from combustion of 

fuel gas, use either Equation C–5 in subpart C of this part or 

the Tier 4 methodology in subpart C of this part, unless either 

of the conditions in paragraphs (a)(1) or (2) of this section 

are met, in which case use either Equations C–1 or C–2a in 

subpart C of this part. For CH4 and N2O emissions from combustion 

of fuel gas, use the applicable procedures in §98.33(c) for the 

same tier methodology that was used for calculating CO2

emissions. (Use the default CH4 and N2O emission factors for 

“Fuel Gas” in Table C–2 of this part. For Tier 3, use either the 

default high heat value for fuel gas in Table C–1 of subpart C 

of this part or a calculated HHV, as allowed in Equation C–8 of 

subpart C of this part.) You may aggregate units, monitor common 
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stacks, or monitor common (fuel) pipes as provided in §98.36(c) 

when calculating and reporting emissions from stationary 

combustion units. Calculate and report the emissions from flares 

under this subpart.

(1) The annual average fuel gas flow rate in the fuel gas 

line to the combustion unit, prior to any split to individual 

burners or ports, does not exceed 345 standard cubic feet per 

minute at 60 °F and 14.7 pounds per square inch absolute and 

either of the conditions in paragraph (a)(1)(i) or (ii) of this 

section exist. Calculate the annual average flow rate using 

company records assuming total flow is evenly distributed over 

525,600 minutes per year.

(i) A flow meter is not installed at any point in the line 

supplying fuel gas or an upstream common pipe.

(ii) The fuel gas line contains only vapors from loading or 

unloading, waste or wastewater handling, and remediation 

activities that are combusted in a thermal oxidizer or thermal 

incinerator.

(2) The combustion unit has a maximum rated heat input 

capacity of less than 30 mmBtu/hr and either of the following 

conditions exist:

(i) A flow meter is not installed at any point in the line 

supplying fuel gas or an upstream common pipe; or
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(ii) The fuel gas line contains only vapors from loading or 

unloading, waste or wastewater handling, and remediation 

activities that are combusted in a thermal oxidizer or thermal 

incinerator.

(b) CO2, CH4, and N2O coke burn-off emissions from each 

catalytic cracking unit, fluid coking unit, and catalytic 

reforming unit under this subpart.

(c) CO2 emissions from sour gas sent off site for sulfur 

recovery operations under this subpart. You must follow the 

calculation methodologies from §98.253(f) and the monitoring and 

QA/QC methods, missing data procedures, reporting requirements, 

and recordkeeping requirements of this subpart.

(d) CO2 process emissions from each on-site sulfur recovery 

plant under this subpart.

(e) CO2, CH4, and N2O emissions from each coke calcining 

unit under this subpart.

(f) CO2 and CH4 emissions from asphalt blowing operations 

under this subpart.

(g) CH4 emissions from equipment leaks, storage tanks, 

loading operations, delayed coking units, and uncontrolled 

blowdown systems under this subpart.

(h) CO2, CH4, and N2O emissions from each process vent not 

specifically included in paragraphs (a) through (g) of this 

section under this subpart.
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(i) CO2 emissions from non-merchant hydrogen production 

process units (not including hydrogen produced from catalytic 

reforming units) following the calculation methodologies, 

monitoring and QA/QC methods, missing data procedures, reporting 

requirements, and recordkeeping requirements of subpart P of 

this part.

§ 98.253 Calculating GHG emissions.

(a) Calculate GHG emissions required to be reported in 

§98.252(b) through (i) using the applicable methods in 

paragraphs (b) through (n) of this section.

(b) For flares, calculate GHG emissions according to the 

requirements in paragraphs (b)(1) through (b)(3) of this 

section.

(1) Calculate the CO2 emissions according to the applicable 

requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of this 

section.

(i) Flow measurement. If you have a continuous flow monitor 

on the flare, you must use the measured flow rates when the 

monitor is operational and the flow rate is within the 

calibrated range of the measurement device to calculate the 

flare gas flow. If you do not have a continuous flow monitor on 

the flare and for periods when the monitor is not operational or 

the flow rate is outside the calibrated range of the measurement 
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device, you must use engineering calculations, company records, 

or similar estimates of volumetric flare gas flow.

(ii) Heat value or carbon content measurement. If you have 

a continuous higher heating value monitor or gas composition 

monitor on the flare or if you monitor these parameters at least 

weekly, you must use the measured heat value or carbon content 

value in calculating the CO2 emissions from the flare using the 

applicable methods in paragraphs (b)(1)(ii)(A) and 

(b)(1)(ii)(B).

(A) If you monitor gas composition, calculate the CO2

emissions from the flare using either Equation Y–1a or Equation 

Y–1b of this section. If daily or more frequent measurement data 

are available, you must use daily values when using Equation Y–

1a or Equation Y–1b of this section; otherwise, use weekly 

values.

Where:

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg).

n = Number of measurement periods. The minimum 

value for n is 52 (for weekly measurements); 

the maximum value for n is 366 (for daily 

measurements during a leap year).

p = Measurement period index.
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44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(Flare)p = Volume of flare gas combusted during 

measurement period (standard cubic feet per 

period, scf/period). If a mass flow meter is 

used, measure flare gas flow rate in kg/period 

and replace the term “(MW)p/MVC” with “1”.

(MW)p = Average molecular weight of the flare gas 

combusted during measurement period (kg/kgmole). If measurements are taken more 

frequently than daily, use the arithmetic 

average of measurement values within the day 

to calculate a daily average.

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 pounds per square inch 

absolute (psia) or 836.6 scf/kg-mole at 60 °F 

and 14.7 psia).

(CC)p = Average carbon content of the flare gas 

combusted during measurement period (kg C per 

kg flare gas). If measurements are taken more 

frequently than daily, use the arithmetic 

average of measurement values within the day 

to calculate a daily average.

Where:

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year).

n = Number of measurement periods. The minimum 

value for n is 52 (for weekly measurements); 

the maximum value for n is 366 (for daily 

measurements during a leap year).

p = Measurement period index.

(Flare)p = Volume of flare gas combusted during 

measurement period (standard cubic feet per 

period, scf/period). If a mass flow meter is 

used, you must determine the average molecular 

weight of the flare gas during the measurement 
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period and convert the mass flow to a 

volumetric flow.

44 = Molecular weight of CO2 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 psia or 836.6 scf/kgmole at 60 °F and 14.7 psia).

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg).

(%CO2)p = Mole percent CO2 concentration in the flare gas 

stream during the measurement period (mole 

percent = percent by volume).

y = Number of carbon-containing compounds other 

than CO2 in the flare gas stream.

x = Index for carbon-containing compounds other 

than CO2.

0.98 = Assumed combustion efficiency of a flare (mole 

CO2 per mole carbon).

(%CX)p = Mole percent concentration of compound “x” in 

the flare gas stream during the measurement 

period (mole percent = percent by volume)

CMNX = Carbon mole number of compound “x” in the 

flare gas stream (mole carbon atoms per mole 

compound). e.g., CMN for ethane (C2H6) is 2; 

CMN for propane (C3H8) is 3.

(B) If you monitor heat content but do not monitor gas 

composition, calculate the CO2 emissions from the flare using 

Equation Y–2 of this section. If daily or more frequent 

measurement data are available, you must use daily values when 

using Equation Y–2 of this section; otherwise, use weekly 

values.

Where:
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CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg).

n = Number of measurement periods. The minimum 

value for n is 52 (for weekly measurements); 

the maximum value for n is 366 (for daily 

measurements during a leap year).

p = Measurement period index.

(Flare)p = Volume of flare gas combusted during 

measurement period (million (MM) scf/period). 

If a mass flow meter is used, you must also 

measure molecular weight and convert the mass 

flow to a volumetric flow as follows: 

Flare[MMscf] = 0.000001 × Flare[kg] × 

MVC/(MW)p, where MVC is the molar volume 

conversion factor [849.5 scf/kg-mole at 68 °F 

and 14.7 psia or 836.6 scf/kg-mole at 60 °F 

and 14.7 psia depending on the standard 

conditions used when determining (HHV)p] and 

(MW)pis the average molecular weight of the 

flare gas combusted during measurement period 

(kg/kg-mole).

(HHV)p = Higher heating value for the flare gas 

combusted during measurement period (British 

thermal units per scf, Btu/scf = MMBtu/MMscf). 

If measurements are taken more frequently than 

daily, use the arithmetic average of 

measurement values within the day to calculate 

a daily average.

EmF = Default CO2 emission factor of 60 kilograms 

CO2/MMBtu (HHV basis).

(iii) Alternative to heat value or carbon content 

measurements. If you do not measure the higher heating value or 

carbon content of the flare gas at least weekly, determine the 

quantity of gas discharged to the flare separately for periods 

of routine flare operation and for periods of start-up, 
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shutdown, or malfunction, and calculate the CO2 emissions as 

specified in paragraphs (b)(1)(iii)(A) through (b)(1)(iii)(C) of 

this section.

(A) For periods of start-up, shutdown, or malfunction, use 

engineering calculations and process knowledge to estimate the 

carbon content of the flared gas for each start-up, shutdown, or 

malfunction event exceeding 500,000 scf/day.

(B) For periods of normal operation, use the average 

heating value measured for the fuel gas for the heating value of 

the flare gas. If heating value is not measured, the heating 

value may be estimated from historic data or engineering 

calculations.

(C) Calculate the CO2 emissions using Equation Y–3 of this 

section.

Where:

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg).

FlareNorm = Annual volume of flare gas combusted during 

normal operations from company records, 

(million (MM) standard cubic feet per year, 

MMscf/year).
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HHV = Higher heating value for fuel gas or flare gas 

from company records (British thermal units 

per scf, Btu/scf = MMBtu/MMscf).

EmF = Default CO2 emission factor for flare gas of 60 

kilograms CO2/MMBtu (HHV basis).

n = Number of start-up, shutdown, and malfunction 

events during the reporting year exceeding 

500,000 scf/day.

p = Start-up, shutdown, and malfunction event 

index.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(FlareSSM)p = Volume of flare gas combusted during indexed 

start-up, shutdown, or malfunction event from 

engineering calculations, (scf/event).

(MW)p = Average molecular weight of the flare gas, 

from the analysis results or engineering 

calculations for the event (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 psia or 836.6 scf/kgmole at 60 °F and 14.7 psia).

(CC)p = Average carbon content of the flare gas, from 

analysis results or engineering calculations 

for the event (kg C per kg flare gas).

(2) Calculate CH4 using Equation Y–4 of this section.

Where:

CH4 = Annual methane emissions from flared gas 

(metric tons CH4 /year).

CO2 = Emission rate of CO2 from flared gas calculated 

in paragraph (b)(1) of this section (metric 

tons/year).

EmFCH4 = Default CH4 emission factor for “Fuel Gas” from 

Table C–2 of subpart C of this part (General 
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Stationary Fuel Combustion Sources) (kg CH4

/MMBtu).

EmF = Default CO2 emission factor for flare gas of 60 

kg CO2/MMBtu (HHV basis).

0.02/0.98 = Correction factor for flare combustion 

efficiency.

16/44 = Correction factor ratio of the molecular 

weight of CH4 to CO2.

fCH4 = Weight fraction of carbon in the flare gas 

prior to combustion that is contributed by 

methane from measurement values or engineering 

calculations (kg C in methane in flare gas/kg 

C in flare gas); default is 0.4.

(3) Calculate N2O emissions using Equation Y–5 of this 

section.

Where:

N2O = Annual nitrous oxide emissions from flared gas 

(metric tons N2O/year).

CO2 = Emission rate of CO2 from flared gas calculated 

in paragraph (b)(1) of this section (metric 

tons/year).

EmFN2O = Default N2O emission factor for “Fuel Gas” from 

Table C–2 of subpart C of this part (General 

Stationary Fuel Combustion Sources) (kg 

N2O/MMBtu).

EmF = Default CO2 emission factor for flare gas of 60 

kg CO2/MMBtu (HHV basis).

(c) For catalytic cracking units and traditional fluid 

coking units, calculate the GHG emissions using the applicable 

methods described in paragraphs (c)(1) through (c)(5) of this 

section.
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(1) If you operate and maintain a CEMS that measures CO2

emissions according to subpart C of this part (General 

Stationary Fuel Combustion Sources), you must calculate and 

report CO2 emissions as provided in paragraphs (c)(1)(i) and 

(c)(1)(ii) of this section. Other catalytic cracking units and 

traditional fluid coking units must either install a CEMS that 

complies with the Tier 4 Calculation Methodology in subpart C of 

this part (General Stationary Combustion Sources), or follow the 

requirements of paragraphs (c)(2) or (3) of this section.

(i) Calculate CO2 emissions by following the Tier 4 

Calculation Methodology specified in §98.33(a)(4) and all 

associated requirements for Tier 4 in subpart C of this part 

(General Stationary Fuel Combustion Sources).

(ii) For catalytic cracking units whose process emissions 

are discharged through a combined stack with other CO2 emissions 

(e.g., co-mingled with emissions from a CO boiler) you must also 

calculate the other CO2 emissions using the applicable methods 

for the applicable subpart (e.g., subpart C of this part in the 

case of a CO boiler). Calculate the process emissions from the 

catalytic cracking unit or fluid coking unit as the difference 

in the CO2 CEMS emissions and the calculated emissions associated 

with the additional units discharging through the combined 

stack.
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(2) For catalytic cracking units and fluid coking units 

with rated capacities greater than 10,000 barrels per stream day 

(bbls/sd) that do not use a continuous CO2 CEMS for the final 

exhaust stack, you must continuously or no less frequently than 

hourly monitor the O2, CO2, and (if necessary) CO concentrations 

in the exhaust stack from the catalytic cracking unit 

regenerator or fluid coking unit burner prior to the combustion 

of other fossil fuels and calculate the CO2 emissions according 

to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) 

of this section:

(i) Calculate the CO2 emissions from each catalytic cracking 

unit and fluid coking unit using Equation Y–6 of this section.

Where:

CO2 = Annual CO2 mass emissions (metric tons/year).

Qr = Volumetric flow rate of exhaust gas from the 

fluid catalytic cracking unit regenerator or 

fluid coking unit burner prior to the 

combustion of other fossil fuels (dry standard 

cubic feet per hour, dscfh).

%CO2 = Hourly average percent CO2 concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume—dry basis).

%CO = Hourly average percent CO concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit

burner (percent by volume—dry basis). When 
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there is no post-combustion device, assume %CO 

to be zero.

44 = Molecular weight of CO2 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 psia or 836.6 scf/kgmole at 60 °F and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

n = Number of hours in calendar year.

(ii) Either continuously monitor the volumetric flow rate 

of exhaust gas from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner prior to the combustion 

of other fossil fuels or calculate the volumetric flow rate of 

this exhaust gas stream using either Equation Y–7a or Equation 

Y–7b of this section.

Where:

Qr = Volumetric flow rate of exhaust gas from the 

fluid catalytic cracking unit regenerator or 

fluid coking unit burner prior to the 

combustion of other fossil fuels (dscfh).

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or fluid 

coking unit burner, as determined from control 

room instrumentation (dscfh).

Qoxy = Volumetric flow rate of oxygen enriched air to 

the fluid catalytic cracking unit regenerator 

or fluid coking unit burner as determined from 

control room instrumentation (dscfh).

%O2 = Hourly average percent oxygen concentration in 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume—dry basis).
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%Ooxy = O2concentration in oxygen enriched gas stream 

inlet to the fluid catalytic cracking unit 

regenerator or fluid coking unit burner based 

on oxygen purity specifications of the oxygen 

supply used for enrichment (percent by volume—

dry basis).

%CO2 = Hourly average percent CO2 concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume—dry basis).

%CO = Hourly average percent CO concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume—dry basis). When no 

auxiliary fuel is burned and a continuous CO 

monitor is not required under 40 CFR part 63 

subpart UUU, assume %CO to be zero.

Where:

Qr = Volumetric flow rate of exhaust gas from the 

fluid catalytic cracking unit regenerator or 

fluid coking unit burner prior to the 

combustion of other fossil fuels (dscfh).

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or fluid 

coking unit burner, as determined from control 

room instrumentation (dscfh).

Qoxy = Volumetric flow rate of oxygen enriched air to 

the fluid catalytic cracking unit regenerator 

or fluid coking unit burner as determined from 

control room instrumentation (dscfh).

%N2,oxy = N2concentration in oxygen enriched gas stream 

inlet to the fluid catalytic cracking unit 

regenerator or fluid coking unit burner based 

on measured value or maximum N2impurity 

specifications of the oxygen supply used for 

enrichment (percent by volume—dry basis).

%N2,exhaust = Hourly average percent N2concentration in the 

exhaust gas stream from the fluid catalytic 
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cracking unit regenerator or fluid coking unit 

burner (percent by volume—dry basis).

(iii) If you have a CO boiler that uses auxiliary fuels or 

combusts materials other than catalytic cracking unit or fluid 

coking unit exhaust gas, you must determine the CO2 emissions 

resulting from the combustion of these fuels or other materials 

following the requirements in subpart C and report those 

emissions by following the requirements of subpart C of this 

part.

(3) For catalytic cracking units and fluid coking units 

with rated capacities of 10,000 barrels per stream day (bbls/sd) 

or less that do not use a continuous CO2 CEMS for the final 

exhaust stack, comply with the requirements in paragraph 

(c)(3)(i) of this section or paragraphs (c)(3)(ii) and 

(c)(3)(iii) of this section, as applicable.

(i) If you continuously or no less frequently than daily 

monitor the O2, CO2, and (if necessary) CO concentrations in the 

exhaust stack from the catalytic cracking unit regenerator or 

fluid coking unit burner prior to the combustion of other fossil 

fuels, you must calculate the CO2 emissions according to the 

requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this 

section, except that daily averages are allowed and the 

summation can be performed on a daily basis.

(ii) If you do not monitor at least daily the O2, CO2, and 

(if necessary) CO concentrations in the exhaust stack from the 
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catalytic cracking unit regenerator or fluid coking unit burner 

prior to the combustion of other fossil fuels, calculate the CO2

emissions from each catalytic cracking unit and fluid coking 

unit using Equation Y–8 of this section.

Where:

CO2 = Annual CO2 mass emissions (metric tons/year).

Qunit = Annual throughput of unit from company records 

(barrels (bbls) per year, bbl/yr).

CBF = Coke burn-off factor from engineering 

calculations (kg coke per barrel of feed); 

default for catalytic cracking units = 7.3; 

default for fluid coking units = 11.

0.001 = Conversion factor (metric ton/kg).

CC = Carbon content of coke based on measurement or 

engineering estimate (kg C per kg coke); 

default = 0.94.

44/12 = Ratio of molecular weight of CO2 to C (kg CO2

per kg C).

(iii) If you have a CO boiler that uses auxiliary fuels or 

combusts materials other than catalytic cracking unit or fluid 

coking unit exhaust gas, you must determine the CO2 emissions 

resulting from the combustion of these fuels or other materials 

following the requirements in subpart C of this part (General 

Stationary Fuel Combustion Sources) and report those emissions 

by following the requirements of subpart C of this part.
Page 19 of 60

(4) Calculate CH4 emissions using either unit specific 

measurement data, a unit-specific emission factor based on a 

source test of the unit, or Equation Y–9 of this section.

Where:

CH4 = Annual methane emissions from coke burn-off 

(metric tons CH4 /year).

CO2 = Emission rate of CO2 from coke burn-off 

calculated in paragraphs (c)(1), (c)(2), 

(e)(1), (e)(2), (g)(1), or (g)(2) of this 

section, as applicable (metric tons/year).

EmF1 = Default CO2 emission factor for petroleum coke 

from Table C–1 of subpart C of this part 

(General Stationary Fuel Combustion Sources) 

(kg CO2/MMBtu).

EmF2 = Default CH4 emission factor for 

“PetroleumProducts” from Table C–2 of subpart 

C of this part (General Stationary Fuel 

Combustion Sources) (kg CH4 /MMBtu).

(5) Calculate N2O emissions using either unit specific 

measurement data, a unit-specific emission factor based on a 

source test of the unit, or Equation Y–10 of this section.

Where:

N2O = Annual nitrous oxide emissions from coke burnoff (mt N2O/year).

CO2 = Emission rate of CO2 from coke burn-off 

calculated in paragraphs (c)(1), (c)(2), 

(e)(1), (e)(2), (g)(1), or (g)(2) of this 

section, as applicable (metric tons/year).
Page 20 of 60

EmF1 = Default CO2 emission factor for petroleum coke 

from Table C–1 of subpart C of this part 

(General Stationary Fuel Combustion Sources) 

(kg CO2/MMBtu).

EmF3 =Default N2O emission factor for “PetroleumProducts” 

from Table C–2 of subpart C of this part (kg N2O/MMBtu).

(d) For fluid coking units that use the flexicoking design, 

the GHG emissions from the resulting use of the low value fuel 

gas must be accounted for only once. Typically, these emissions 

will be accounted for using the methods described in subpart C 

of this part (General Stationary Fuel Combustion Sources). 

Alternatively, you may use the methods in paragraph (c) of this 

section provided that you do not otherwise account for the 

subsequent combustion of this low value fuel gas.

(e) For catalytic reforming units, calculate the CO2

emissions using the applicable methods described in paragraphs 

(e)(1) through (e)(3) of this section and calculate the CH4 and 

N2O emissions using the methods described in paragraphs (c)(4) 

and (c)(5) of this section, respectively.

(1) If you operate and maintain a CEMS that measures CO2

emissions according to subpart C of this part (General 

Stationary Fuel Combustion Sources), you must calculate CO2

emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of 

this section. Other catalytic reforming units must either 

install a CEMS that complies with the Tier 4 Calculation 
Page 21 of 60

Methodology in subpart C of this part, or follow the 

requirements of paragraph (e)(2) or (e)(3) of this section.

(2) If you continuously or no less frequently than daily 

monitor the O2, CO2, and (if necessary) CO concentrations in the 

exhaust stack from the catalytic reforming unit catalyst 

regenerator prior to the combustion of other fossil fuels, you 

must calculate the CO2 emissions according to the requirements of 

paragraphs (c)(2)(i) through (c)(2)(iii) of this section.

(3) Calculate CO2 emissions from the catalytic reforming 

unit catalyst regenerator using Equation Y–11 of this section.

Where:

CO2 = Annual CO2 emissions (metric tons/year).

CBQ = Coke burn-off quantity per regeneration cycle 

or measurement period from engineering 

estimates (kg coke/cycle or kg 

coke/measurement period).

n = Number of regeneration cycles or measurement 

periods in the calendar year.

CC = Carbon content of coke based on measurement or 

engineering estimate (kg C per kg coke); 

default = 0.94.

44/12 = Ratio of molecular weight of CO2 to C (kg CO2

per kg C).

0.001 = Conversion factor (metric ton/kg).

(f) For on-site sulfur recovery plants and for sour gas 

sent off site for sulfur recovery, calculate and report CO2
Page 22 of 60

process emissions from sulfur recovery plants according to the 

requirements in paragraphs (f)(1) through (f)(5) of this 

section, or, for non-Claus sulfur recovery plants, according to 

the requirements in paragraph (j) of this section regardless of 

the concentration of CO2 in the vented gas stream. Combustion 

emissions from the sulfur recovery plant (e.g., from fuel 

combustion in the Claus burner or the tail gas treatment 

incinerator) must be reported under subpart C of this part 

(General Stationary Fuel Combustion Sources). For the purposes 

of this subpart, the sour gas stream for which monitoring is 

required according to paragraphs (f)(2) through (f)(5) of this 

section is not considered a fuel.

(1) If you operate and maintain a CEMS that measures CO2

emissions according to subpart C of this part, you must 

calculate CO2 emissions under this subpart by following the Tier 

4 Calculation Methodology specified in §98.33(a)(4) and all 

associated requirements for Tier 4 in subpart C of this part 

(General Stationary Fuel Combustion Sources). You must monitor 

fuel use in the Claus burner, tail gas incinerator, or other 

combustion sources that discharge via the final exhaust stack 

from the sulfur recovery plant and calculate the combustion 

emissions from the fuel use according to subpart C of this part. 

Calculate the process emissions from the sulfur recovery plant 

as the difference in the CO2 CEMS emissions and the calculated 
Page 23 of 60

combustion emissions associated with the sulfur recovery plant 

final exhaust stack. Other sulfur recovery plants must either 

install a CEMS that complies with the Tier 4 Calculation 

Methodology in subpart C, or follow the requirements of 

paragraphs (f)(2) through (f)(5) of this section, or (for nonClaus sulfur recovery plants only) follow the requirements in 

paragraph (j) of this section to determine CO2 emissions for the 

sulfur recovery plant.

(2) Flow measurement. If you have a continuous flow monitor 

on the sour gas feed to the sulfur recovery plant or the sour 

gas feed sent for off-site sulfur recovery, you must use the 

measured flow rates when the monitor is operational to calculate 

the sour gas flow rate. If you do not have a continuous flow 

monitor on the sour gas feed to the sulfur recovery plant or the 

sour gas feed sent for off-site sulfur recovery, you must use 

engineering calculations, company records, or similar estimates 

of volumetric sour gas flow.

(3) Carbon content. If you have a continuous gas 

composition monitor capable of measuring carbon content on the 

sour gas feed to the sulfur recovery plant or the sour gas feed 

sent for off-site sulfur recovery, or if you monitor gas 

composition for carbon content on a routine basis, you must use 

the measured carbon content value. Alternatively, you may 

develop a site-specific carbon content factor using limited 
Page 24 of 60

measurement data or engineering estimates or use the default 

factor of 0.20.

(4) Calculate the CO2 emissions from each on-site sulfur 

recovery plant and for sour gas sent off-site for sulfur 

recovery using Equation Y–12 of this section.

Where:

CO2 = Annual CO2 emissions (metric tons/year).

FSG = Volumetric flow rate of sour gas (including 

sour water stripper gas) fed to the sulfur 

recovery plant or the sour gas feed sent offsite for sulfur recovery (scf/year).

44 = Molecular weight of CO2 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 psia or 836.6 scf/kgmole at 60 °F and 14.7 psia).

MFC = Mole fraction of carbon in the sour gas fed to 

the sulfur recovery plant or the sour gas feed 

sent off-site for sulfur recovery (kg-mole 

C/kg-mole gas); default = 0.20.

0.001 = Conversion factor, kg to metric tons.

(5) If tail gas is recycled to the front of the sulfur 

recovery plant and the recycled flow rate and carbon content is 

included in the measured data under paragraphs (f)(2) and (f)(3) 

of this section, respectively, then the annual CO2 emissions 

calculated in paragraph (f)(4) of this section must be corrected 

to avoid double counting these emissions. You may use 

engineering estimates to perform this correction or assume that 
Page 25 of 60

the corrected CO2 emissions are 95 percent of the uncorrected 

value calculated using Equation Y–12 of this section.

(g) For coke calcining units, calculate GHG emissions 

according to the applicable provisions in paragraphs (g)(1) 

through (g)(3) of this section.

(1) If you operate and maintain a CEMS that measures CO2

emissions according to subpart C of this part, you must 

calculate and report CO2 emissions under this subpart by 

following the Tier 4 Calculation Methodology specified in 

§98.33(a)(4) and all associated requirements for Tier 4 in 

subpart C of this part (General Stationary Fuel Combustion 

Sources). You must monitor fuel use in the coke calcining unit 

that discharges via the final exhaust stack from the coke 

calcining unit and calculate the combustion emissions from the 

fuel use according to subpart C of this part. Calculate the 

process emissions from the coke calcining unit as the difference 

in the CO2 CEMS emissions and the calculated combustion emissions 

associated with the coke calcining unit final exhaust stack. 

Other coke calcining units must either install a CEMS that 

complies with the Tier 4 Calculation Methodology in subpart C of 

this part, or follow the requirements of paragraph (g)(2) of 

this section.

(2) Calculate the CO2 emissions from the coke calcining unit 

using Equation Y–13 of this section.
Page 26 of 60

Where:

CO2 = Annual CO2 emissions (metric tons/year).

Min = Annual mass of green coke fed to the coke 

calcining unit from facility records (metric 

tons/year).

CCGC = Average mass fraction carbon content of green 

coke from facility measurement data (metric 

ton carbon/metric ton green coke).

Mout = Annual mass of marketable petroleum coke 

produced by the coke calcining unit from 

facility records (metric tons petroleum 

coke/year).

Mdust = Annual mass of petroleum coke dust removed 

from the process through the dust collection 

system of the coke calcining unit from 

facility records (metric ton petroleum coke 

dust/year). For coke calcining units that 

recycle the collected dust, the mass of coke 

dust removed from the process is the mass of 

coke dust collected less the mass of coke dust 

recycled to the process.

CCMPC = Average mass fraction carbon content of 

marketable petroleum coke produced by the coke 

calcining unit from facility measurement data 

(metric ton carbon/metric ton petroleum coke).

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(3) For all coke calcining units, use the CO2 emissions from 

the coke calcining unit calculated in paragraphs (g)(1) or 

(g)(2), as applicable, and calculate CH4 using the methods 

described in paragraph (c)(4) of this section and N2O emissions 

using the methods described in paragraph (c)(5) of this section.
Page 27 of 60

(h) For asphalt blowing operations, calculate CO2 and CH4

emissions according to the requirements in paragraph (j) of this 

section regardless of the CO2 and CH4 concentrations or according 

to the applicable provisions in paragraphs (h)(1) and (h)(2) of 

this section.

(1) For uncontrolled asphalt blowing operations or asphalt 

blowing operations controlled by vapor scrubbing, calculate CO2

and CH4 emissions using Equations Y–14 and Y–15 of this section, 

respectively.

Where:

CO2 = Annual CO2 emissions from uncontrolled asphalt 

blowing (metric tons CO2/year).

QAB = Quantity of asphalt blown (million barrels per 

year, MMbbl/year).

EFAB,CO2 = Emission factor for CO2 from uncontrolled 

asphalt blowing from facility-specific test 

data (metric tons CO2/MMbbl asphalt blown); 

default = 1,100.

Where:

CH4 = Annual methane emissions from uncontrolled 

asphalt blowing (metric tons CH4 /year).

QAB = Quantity of asphalt blown (million barrels per 

year, MMbbl/year).

EFAB,CH4 = Emission factor for CH4 from uncontrolled 

asphalt blowing from facility-specific test 

data (metric tons CH4 /MMbbl asphalt blown); 

default = 580.
Page 28 of 60

(2) For asphalt blowing operations controlled by thermal 

oxidizer or flare, calculate CO2 using either Equation Y–16a or 

Equation Y–16b of this section and calculate CH4 emissions using 

Equation Y–17 of this section, provided these emissions are not 

already included in the flare emissions calculated in paragraph 

(b) of this section or in the stationary combustion unit 

emissions required under subpart C of this part (General 

Stationary Fuel Combustion Sources).

Where:

CO2 = Annual CO2 emissions from controlled asphalt 

blowing (metric tons CO2/year).

0.98 = Assumed combustion efficiency of thermal 

oxidizer or flare.

QAB = Quantity of asphalt blown (MMbbl/year).

CEFAB = Carbon emission factor from asphalt blowing 

from facility-specific test data (metric tons

C/MMbbl asphalt blown); default = 2,750.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

Where:

CO2 = Annual CO2 emissions from controlled asphalt 

blowing (metric tons CO2/year).

QAB = Quantity of asphalt blown (MMbbl/year).

0.98 = Assumed combustion efficiency of thermal 

oxidizer or flare.

EFAB,CO2 = Emission factor for CO2 from uncontrolled 

asphalt blowing from facility-specific test 
Page 29 of 60

data (metric tons CO2/MMbbl asphalt blown); 

default = 1,100.

CEFAB = Carbon emission factor from asphalt blowing 

from facility-specific test data (metric tons 

C/MMbbl asphalt blown); default = 2,750.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

Where:

CH4 = Annual methane emissions from controlled 

asphalt blowing (metric tons CH4 /year).

0.02 = Fraction of methane uncombusted in thermal 

oxidizer or flare based on assumed 98% 

combustion efficiency.

QAB = Quantity of asphalt blown (million barrels per 

year, MMbbl/year).

EFAB,CH4 = Emission factor for CH4 from uncontrolled 

asphalt blowing from facility-specific test 

data (metric tons CH4 /MMbbl asphalt blown); 

default = 580.

(i) For delayed coking units, calculate the CH4 emissions 

from the depressurization of the coking unit vessel (i.e., the 

“coke drum”) to atmosphere using either of the methods provided 

in paragraphs (i)(1) or (i)(2), provided no water or steam is 

added to the vessel once it is vented to the atmosphere. You 

must use the method in paragraph (i)(1) of this section if you 

add water or steam to the vessel after it is vented to the 

atmosphere.

(1) Use the process vent method in paragraph (j) of this 

section to calculate the CH4 emissions from the depressurization 

of the coke drum or vessel regardless of the CH4 concentration 
Page 30 of 60

and also calculate the CH4 emissions from the subsequent opening 

of the vessel for coke cutting operations using Equation Y–18 of 

this section. If you have coke drums or vessels of different 

dimensions, use the process vent method in paragraph (j) of this 

section and Equation Y–18 for each set of coke drums or vessels 

of the same size and sum the resultant emissions across each set 

of coke drums or vessels to calculate the CH4 emissions for all 

delayed coking units.

Where:

CH4 = Annual methane emissions from the delayed 

coking unit vessel opening (metric ton/year).

N = Cumulative number of vessel openings for all 

delayed coking unit vessels of the same 

dimensions during the year.

H = Height of coking unit vessel (feet).

PCV = Gauge pressure of the coking vessel when 

opened to the atmosphere prior to coke cutting 

or, if the alternative method provided in 

paragraph (i)(2) of this section is used, 

gauge pressure of the coking vessel when 

depressurization gases are first routed to the 

atmosphere (pounds per square inch gauge, 

psig).

14.7 = Assumed atmospheric pressure (pounds per 

square inch, psi).

fvoid = Volumetric void fraction of coking vessel 

prior to steaming (cf gas/cf of vessel); 

default = 0.6.

D = Diameter of coking unit vessel (feet).

16 = Molecular weight of CH4 (kg/kg-mole).
Page 31 of 60

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 psia or 836.6 scf/kgmole at 60 °F and 14.7 psia).

MFCH4 = Mole fraction of methane in coking vessel gas 

(kg-mole CH4 /kg-mole gas, wet basis); default 

value is 0.01.

0.001 = Conversion factor (metric ton/kg).

(2) Calculate the CH4 emissions from the depressurization 

vent and subsequent opening of the vessel for coke cutting 

operations using Equation Y–18 of this section and the pressure 

of the coking vessel when the depressurization gases are first 

routed to the atmosphere. If you have coke drums or vessels of 

different dimensions, use Equation Y–18 for each set of coke 

drums or vessels of the same size and sum the resultant 

emissions across each set of coke drums or vessels to calculate 

the CH4 emissions for all delayed coking units.

(j) For each process vent not covered in paragraphs (a) 

through (i) of this section that can reasonably be expected to 

contain greater than 2 percent by volume CO2 or greater than 0.5 

percent by volume of CH4 or greater than 0.01 percent by volume 

(100 parts per million) of N2O, calculate GHG emissions using 

Equation Y–19 of this section. You must also use Equation Y–19 

of this section to calculate CH4 emissions for catalytic 

reforming unit depressurization and purge vents when methane is 

used as the purge gas, CH4 emissions if you elected to use the 

method in paragraph (i)(1) of this section, and CO2 and/or CH4
Page 32 of 60

emissions, as applicable, if you elected this method as an 

alternative to the methods in paragraphs (f), (h), or (k) of 

this section.

Where:

EX = Annual emissions of each GHG from process vent 

(metric ton/yr).

N = Number of venting events per year.

P = Index of venting events.

(VR)p = Average volumetric flow rate of process gas 

during the event (scf per hour) from 

measurement data, process knowledge, or 

engineering estimates.

(MFX)p = Mole fraction of GHG x in process vent during 

the event (kg-mol of GHG x/kg-mol vent gas) 

from measurement data, process knowledge, or 

engineering estimates.

MWX = Molecular weight of GHG x (kg/kg-mole); use 44 

for CO2 or N2O and 16 for CH4.

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 psia or 836.6 scf/kgmole at 60 °F and 14.7 psia).

(VT)p = Venting time for the event, (hours).

0.001 = Conversion factor (metric ton/kg).

(k) For uncontrolled blowdown systems, you must calculate 

CH4 emissions either using the methods for process vents in 

paragraph (j) of this section regardless of the CH4 concentration 

or using Equation Y-20 of this section. Blowdown systems where 

the uncondensed gas stream is routed to a flare or similar 
Page 33 of 60

control device are considered to be controlled and are not 

required to estimate emissions under this paragraph (k).

Where:

CH4 = Methane emission rate from blowdown systems 

(mt CH4 /year).

QRef = Quantity of crude oil plus the quantity of 

intermediate products received from off site 

that are processed at the facility 

(MMbbl/year).

EFBD = Methane emission factor for uncontrolled blown 

systems (scf CH4 /MMbbl); default is 137,000.

16 = Molecular weight of CH4 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 psia or 836.6 scf/kgmole at 60 °F and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

(l) For equipment leaks, calculate CH4 emissions using the 

method specified in either paragraph (l)(1) or (l)(2) of this 

section.

(1) Use process-specific methane composition data (from 

measurement data or process knowledge) and any of the emission 

estimation procedures provided in the Protocol for Equipment 

Leak Emissions Estimates (EPA–453/R–95–017, NTIS PB96–175401).

(2) Use Equation Y–21 of this section.

Where:
Page 34 of 60

CH4 = Annual methane emissions from equipment leaks 

(metric tons/year).

NCD = Number of atmospheric crude oil distillation 

columns at the facility.

NPU1 = Cumulative number of catalytic cracking units, 

coking units (delayed or fluid), 

hydrocracking, and full-range distillation 

columns (including depropanizer and 

debutanizer distillation columns) at the 

facility.

NPU2 = Cumulative number of 

hydrotreating/hydrorefining units, catalytic 

reforming units, and visbreaking units at the 

facility.

NH2 = Total number of hydrogen plants at the 

facility.

NFGS = Total number of fuel gas systems at the 

facility.

(m) For storage tanks, except as provided in paragraph 

(m)(3) of this section, calculate CH4 emissions using the 

applicable methods in paragraphs (m)(1) and (m)(2) of this 

section.

(1) For storage tanks other than those processing 

unstabilized crude oil, you must either calculate CH4 emissions 

from storage tanks that have a vapor-phase methane concentration 

of 0.5 volume percent or more using tank-specific methane 

composition data (from measurement data or product knowledge) 

and the emission estimation methods provided in AP 42, Section 

7.1 (incorporated by reference, see §98.7) or estimate CH4

emissions from storage tanks using Equation Y–22 of this 

section.
Page 35 of 60

Where:

CH4 = Annual methane emissions from storage tanks 

(metric tons/year).

0.1 = Default emission factor for storage tanks 

(metric ton CH4 /MMbbl).

QRef = Quantity of crude oil plus the quantity of 

intermediate products received from off site 

that are processed at the facility 

(MMbbl/year).

(2) For storage tanks that process unstabilized crude oil, 

calculate CH4 emissions from the storage of unstabilized crude 

oil using either tank-specific methane composition data (from 

measurement data or product knowledge) and direct measurement of 

the gas generation rate or by using Equation Y–23 of this 

section.

Where:

CH4 = Annual methane emissions from storage tanks 

(metric tons/year).

Qun = Quantity of unstabilized crude oil received at 

the facility (MMbbl/year).

ΔP = Pressure differential from the previous 

storage pressure to atmospheric pressure 

(pounds per square inch, psi).

MFCH4 = Average mole fraction of CH4 in vent gas from 

the unstabilized crude oil storage tanks from 

facility measurements (kg-mole CH4 /kg-mole 

gas); use 0.27 as a default if measurement 

data are not available.
Page 36 of 60

995,000 = Correlation Equation factor (scf gas per MMbbl 

per psi).

16 = Molecular weight of CH4 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 °F and 14.7 psia or 836.6 scf/kgmole at 60 °F and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

(3) You do not need to calculate CH4 emissions from storage 

tanks that meet any of the following descriptions:

(i) Units permanently attached to conveyances such as 

trucks, trailers, rail cars, barges, or ships;

(ii) Pressure vessels designed to operate in excess of 

204.9 kilopascals and without emissions to the atmosphere;

(iii) Bottoms receivers or sumps;

(iv) Vessels storing wastewater; or

(v) Reactor vessels associated with a manufacturing process 

unit.

(n) For crude oil, intermediate, or product loading 

operations for which the vapor-phase concentration of methane is 

0.5 volume percent or more, calculate CH4 emissions from loading 

operations using vapor-phase methane composition data (from 

measurement data or process knowledge) and the emission 

estimation procedures provided in AP 42, Section 5.2 

(incorporated by reference, see §98.7). For loading operations 

in which the vapor-phase concentration of methane is less than 

0.5 volume percent, you may assume zero methane emissions.
Page 37 of 60

§ 98.254 Monitoring and QA/QC requirements.

(a) Fuel flow meters, gas composition monitors, and heating 

value monitors that are associated with sources that use a CEMS 

to measure CO2 emissions according to subpart C of this part or 

that are associated with stationary combustion sources must meet 

the applicable monitoring and QA/QC requirements in §98.34.

(b) All gas flow meters, gas composition monitors, and 

heating value monitors that are used to provide data for the GHG 

emissions calculations in this subpart for sources other than 

those subject to the requirements in paragraph (a) of this 

section shall be calibrated according to the procedures 

specified by the manufacturer, or according to the procedures in 

the applicable methods specified in paragraphs (c) through (g) 

of this section. In the case of gas flow meters, all gas flow 

meters must meet the calibration accuracy requirements in 

§98.3(i). All gas flow meters, gas composition monitors, and 

heating value monitors must be recalibrated at the applicable 

frequency specified in paragraph (b)(1) or (b)(2) of this 

section.

(1) You must recalibrate each gas flow meter according to 

one of the following frequencies. You may recalibrate at the 

minimum frequency specified by the manufacturer, biennially 

(every two years), or at the interval specified by the industry 

consensus standard practice used.
Page 38 of 60

(2) You must recalibrate each gas composition monitor and 

heating value monitor according to one of the following 

frequencies. You may recalibrate at the minimum frequency 

specified by the manufacturer, annually, or at the interval 

specified by the industry standard practice used.

(c) For flare or sour gas flow meters and gas flow meters 

used to comply with the requirements in §98.253(j), operate, 

calibrate, and maintain the flow meter according to one of the 

following. You may use the procedures specified by the flow 

meter manufacturer, or a method published by a consensus-based 

standards organization. Consensus-based standards organizations 

include, but are not limited to, the following: ASTM 

International (100 Barr Harbor Drive, P.O. Box CB700, West 

Conshohocken, Pennsylvania 19428–B2959, (800) 262–1373, 

http://www.astm.org), the American National Standards Institute 

(ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, 

(202) 293–8020, http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol Street, NW., 4th Floor, 

Washington, DC 20001, (202) 824–7000, http://www.aga.org), the 

American Society of Mechanical Engineers (ASME, Three Park 

Avenue, New York, NY 10016–5990, (800) 843–2763, 

http://www.asme.org), the American Petroleum Institute (API, 

1220 L Street, NW., Washington, DC 20005–4070, (202) 682–8000, 

http://www.api.org), and the North American Energy Standards 
Page 39 of 60

Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.api.org).

(d) Except as provided in paragraph (g) of this section, 

determine gas composition and, if required, average molecular 

weight of the gas using any of the following methods. 

Alternatively, the results of chromatographic analysis of the 

fuel may be used, provided that the gas chromatograph is 

operated, maintained, and calibrated according to the 

manufacturer's instructions; and the methods used for operation, 

maintenance, and calibration of the gas chromatograph are 

documented in the written Monitoring Plan for the unit under 

§98.3(g)(5).

(1) Method 18 at 40 CFR part 60, appendix A–6.

(2) ASTM D1945–03 Standard Test Method for Analysis of 

Natural Gas by Gas Chromatography (incorporated by reference, 

see §98.7).

(3) ASTM D1946–90 (Reapproved 2006) Standard Practice for 

Analysis of Reformed Gas by Gas Chromatography (incorporated by 

reference, see §98.7).

(4) GPA 2261–00 Analysis for Natural Gas and Similar 

Gaseous Mixtures by Gas Chromatography (incorporated by 

reference, see §98.7).

(5) UOP539–97 Refinery Gas Analysis by Gas Chromatography 

(incorporated by reference, see §98.7).
Page 40 of 60

(6) ASTM D2503–92 (Reapproved 2007) Standard Test Method 

for Relative Molecular Mass (Molecular Weight) of Hydrocarbons 

by Thermoelectric Measurement of Vapor Pressure (incorporated by 

reference, see §98.7).

(e) Determine flare gas higher heating value using any of 

the following methods. Alternatively, the results of 

chromatographic analysis of the fuel may be used, provided that 

the gas chromatograph is operated, maintained, and calibrated 

according to the manufacturer's instructions; and the methods 

used for operation, maintenance, and calibration of the gas 

chromatograph are documented in the written Monitoring Plan for 

the unit under §98.3(g)(5).

(1) ASTM D4809–06 Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method) (incorporated by reference, see §98.7).

(2) ASTM D240–02 (Reapproved 2007) Standard Test Method for 

Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (incorporated by reference, see §98.7).

(3) ASTM D1826–94 (Reapproved 2003) Standard Test Method 

for Calorific (Heating) Value of Gases in Natural Gas Range by 

Continuous Recording Calorimeter (incorporated by reference, see

§98.7).
Page 41 of 60

(4) ASTM D3588–98 (Reapproved 2003) Standard Practice for 

Calculating Heat Value, Compressibility Factor, and Relative 

Density of Gaseous Fuels (incorporated by reference, see §98.7).

(5) ASTM D4891–89 (Reapproved 2006) Standard Test Method 

for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion (incorporated by reference, see

§98.7).

(f) For gas flow meters used to comply with the 

requirements in §98.253(c)(2)(ii), install, operate, calibrate, 

and maintain each gas flow meter according to the requirements 

in 40 CFR 63.1572(c) and the following requirements.

(1) Locate the flow monitor at a site that provides 

representative flow rates. Avoid locations where there is 

swirling flow or abnormal velocity distributions due to upstream 

and downstream disturbances.

(2) [Reserved]

(3) Use a continuous monitoring system capable of 

correcting for the temperature, pressure, and moisture content 

to output flow in dry standard cubic feet (standard conditions 

as defined in §98.6).

(g) For exhaust gas CO2/CO/O2composition monitors used to 

comply with the requirements in §98.253(c)(2), install, operate, 

calibrate, and maintain exhaust gas composition monitors 

according to the requirements in 40 CFR 60.105a(b)(2) or 40 CFR 
Page 42 of 60

63.1572(c) or according to the manufacturer's specifications and 

requirements.

(h) Determine the mass of petroleum coke as required by 

Equation Y–13 of this subpart using mass measurement equipment 

meeting the requirements for commercial weighing equipment as 

described in Specifications, Tolerances, and Other Technical 

Requirements For Weighing and Measuring Devices, NIST Handbook 

44 (2009) (incorporated by reference, see §98.7). Calibrate the 

measurement device according to the procedures specified by NIST 

handbook 44 (incorporated by reference, see §98.7) or the 

procedures specified by the manufacturer. Recalibrate either 

biennially or at the minimum frequency specified by the 

manufacturer.

(i) Determine the carbon content of petroleum coke as 

required by Equation Y–13 of this subpart using any one of the 

following methods. Calibrate the measurement device according to 

procedures specified by the method or procedures specified by 

the measurement device manufacturer.

(1) ASTM D3176–89 (Reapproved 2002) Standard Practice for 

Ultimate Analysis of Coal and Coke (incorporated by reference, 

see §98.7).

(2) ASTM D5291–02 (Reapproved 2007) Standard Test Methods

for Instrumental Determination of Carbon, Hydrogen, and Nitrogen 
Page 43 of 60

in Petroleum Products and Lubricants (incorporated by reference, 

see §98.7).

(3) ASTM D5373–08 Standard Test Methods for Instrumental 

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory 

Samples of Coal (incorporated by reference, see §98.7).

(j) Determine the quantity of petroleum process streams 

using company records. These quantities include the quantity of 

asphalt blown, quantity of crude oil plus the quantity of 

intermediate products received from off site, and the quantity 

of unstabilized crude oil received at the facility.

(k) The owner or operator shall document the procedures 

used to ensure the accuracy of the estimates of fuel usage, gas 

composition, and heating value including but not limited to 

calibration of weighing equipment, fuel flow meters, and other 

measurement devices. The estimated accuracy of measurements made 

with these devices shall also be recorded, and the technical 

basis for these estimates shall be provided.

§ 98.255 Procedures for estimating missing data.

A complete record of all measured parameters used in the 

GHG emissions calculations is required (e.g., concentrations, 

flow rates, fuel heating values, carbon content values). 

Therefore, whenever a quality-assured value of a required 

parameter is unavailable (e.g., if a CEMS malfunctions during 

unit operation or if a required fuel sample is not taken), a 
Page 44 of 60

substitute data value for the missing parameter shall be used in 

the calculations.

(a) For stationary combustion sources, use the missing data 

procedures in subpart C of this part.

(b) For each missing value of the heat content, carbon 

content, or molecular weight of the fuel, substitute the 

arithmetic average of the quality-assured values of that 

parameter immediately preceding and immediately following the 

missing data incident. If the “after” value is not obtained by 

the end of the reporting year, you may use the “before” value 

for the missing data substitution. If, for a particular 

parameter, no quality-assured data are available prior to the 

missing data incident, the substitute data value shall be the 

first quality-assured value obtained after the missing data 

period.

(c) For missing CO2, CO, O2, CH4, or N2O concentrations, gas 

flow rate, and percent moisture, the substitute data values 

shall be the best available estimate(s) of the parameter(s), 

based on all available process data (e.g., processing rates, 

operating hours, etc.). The owner or operator shall document and 

keep records of the procedures used for all such estimates.

(d) For hydrogen plants, use the missing data procedures in 

subpart P of this part.

§ 98.256 Data reporting requirements.
Page 45 of 60

In addition to the reporting requirements of §98.3(c), you 

must report the information specified in paragraphs (a) through 

(q) of this section.

(a) For combustion sources, follow the data reporting 

requirements under subpart C of this part (General Stationary 

Fuel Combustion Sources).

(b) For hydrogen plants, follow the data reporting 

requirements under subpart P of this part (Hydrogen Production).

(c)–(d) [Reserved]

(e) For flares, owners and operators shall report:

(1) The flare ID number (if applicable).

(2) A description of the type of flare (steam assisted, 

air-assisted).

(3) A description of the flare service (general facility 

flare, unit flare, emergency only or back-up flare).

(4) The calculated CO2, CH4, and N2O annual emissions for 

each flare, expressed in metric tons of each pollutant emitted.

(5) A description of the method used to calculate the CO2

emissions for each flare (e.g., reference section and equation 

number).

(6) If you use Equation Y–1a of this subpart, an indication 

of whether daily or weekly measurement periods are used, the 

annual volume of flare gas combusted (in scf/year) and the 

annual average molecular weight (in kg/kg-mole), the molar 
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volume conversion factor (in scf/kg-mole), and annual average 

carbon content of the flare gas (in kg carbon per kg flare gas).

(7) If you use Equation Y–1b of this subpart, an indication 

of whether daily or weekly measurement periods are used, the 

annual volume of flare gas combusted (in scf/year), the molar 

volume conversion factor (in scf/kg-mole), the annual average CO2

concentration (volume or mole percent), the number of carbon 

containing compounds other than CO2 in the flare gas stream, and 

for each of the carbon containing compounds other than CO2 in the 

flare gas stream:

(i) The annual average concentration of the compound 

(volume or mole percent).

(ii) The carbon mole number of the compound (moles carbon 

per mole compound).

(8) If you use Equation Y–2 of this subpart, an indication 

of whether daily or weekly measurement periods are used, the 

annual volume of flare gas combusted (in million (MM) scf/year), 

the annual average higher heating value of the flare gas (in 

mmBtu/mmscf), and an indication of whether the annual volume of 

flare gas combusted and the annual average higher heating value 

of the flare gas were determined using standard conditions of 68 

°F and 14.7 psia or 60 °F and 14.7 psia.

(9) If you use Equation Y–3 of this subpart, the annual 

volume of flare gas combusted (in MMscf/year) during normal 
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operations, the annual average higher heating value of the flare 

gas (in mmBtu/mmscf), the number of SSM events exceeding 500,000 

scf/day, the volume of gas flared (in scf/event), the average 

molecular weight (in kg/kg-mole), the molar volume conversion 

factor (in scf/kg-mole), and carbon content of the flare gas (in 

kg carbon per kg flare) for each SSM event over 500,000 scf/day.

(10) The fraction of carbon in the flare gas contributed by 

methane used in Equation Y–4 of this subpart and the basis for 

its value.

(f) For catalytic cracking units, traditional fluid coking 

units, and catalytic reforming units, owners and operators shall 

report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit (fluid catalytic 

cracking unit, thermal catalytic cracking unit, traditional 

fluid coking unit, or catalytic reforming unit).

(3) Maximum rated throughput of the unit, in bbl/stream 

day.

(4) The calculated CO2, CH4, and N2O annual emissions for 

each unit, expressed in metric tons of each pollutant emitted.

(5) A description of the method used to calculate the CO2

emissions for each unit (e.g., reference section and equation 

number).
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(6) If you use a CEMS, the relevant information required 

under §98.36 for the Tier 4 Calculation Methodology, the CO2

annual emissions as measured by the CEMS (unadjusted to remove 

CO2 combustion emissions associated with additional units, if 

present) and the process CO2 emissions as calculated according to 

§98.253(c)(1)(ii). Report the CO2 annual emissions associated 

with sources other than those from the coke burn-off in

accordance with the applicable subpart (e.g., subpart C of this 

part in the case of a CO boiler).

(7) If you use Equation Y–6 of this subpart, the annual 

average exhaust gas flow rate, %CO2, %CO, and the molar volume 

conversion factor (in scf/kg-mole).

(8) If you use Equation Y–7a of this subpart, the annual 

average flow rate of inlet air and oxygen-enriched air, %O2, 

%Ooxy, %CO2, and %CO.

(9) If you use Equation Y–7b of this subpart, the annual 

average flow rate of inlet air and oxygen-enriched air, %N2,oxy, 

and %N2,exhaust.

(10) If you use Equation Y–8 of this subpart, the coke 

burn-off factor, annual throughput of unit, and the average 

carbon content of coke and the basis for the value.

(11) Indicate whether you use a measured value, a unitspecific emission factor, or a default emission factor for CH4

emissions. If you use a unit-specific emission factor for CH4,
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report the unit-specific emission factor for CH4, the units of 

measure for the unit-specific factor, the activity data for 

calculating emissions (e.g., if the emission factor is based on 

coke burn-off rate, the annual quantity of coke burned), and the 

basis for the factor.

(12) Indicate whether you use a measured value, a unitspecific emission factor, or a default emission factor for N2O 

emissions. If you use a unit-specific emission factor for N2O, 

report the unit-specific emission factor for N2O, the units of 

measure for the unit-specific factor, the activity data for 

calculating emissions (e.g., if the emission factor is based on 

coke burn-off rate, the annual quantity of coke burned), and the 

basis for the factor.

(13) If you use Equation Y–11 of this subpart, the number 

of regeneration cycles or measurement periods during the 

reporting year, the average coke burn-off quantity per cycle or 

measurement period, and the average carbon content of the coke.

(g) For fluid coking unit of the flexicoking type, the 

owner or operator shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit.

(3) Maximum rated throughput of the unit, in bbl/stream 

day.
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(4) Indicate whether the GHG emissions from the low heat 

value gas are accounted for in subpart C of this part or 

§98.253(c).

(5) If the GHG emissions for the low heat value gas are 

calculated at the flexicoking unit, also report the calculated 

annual CO2, CH4, and N2O emissions for each unit, expressed in 

metric tons of each pollutant emitted, and the applicable 

equation input parameters specified in paragraphs (f)(7) through 

(f)(13) of this section.

(h) For on-site sulfur recovery plants and for emissions 

from sour gas sent off-site for sulfur recovery, the owner and 

operator shall report:

(1) The plant ID number (if applicable).

(2) For each on-site sulfur recovery plant, the maximum 

rated throughput (metric tons sulfur produced/stream day), a 

description of the type of sulfur recovery plant, and an 

indication of the method used to calculate CO2 annual emissions 

for the sulfur recovery plant (e.g., CO2 CEMS, Equation Y–12, or 

process vent method in §98.253(j)).

(3) The calculated CO2 annual emissions for each on-site 

sulfur recovery plant, expressed in metric tons. The calculated 

annual CO2 emissions from sour gas sent off-site for sulfur 

recovery, expressed in metric tons.
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(4) If you use Equation Y–12 of this subpart, the annual 

volumetric flow to the on-site and off-site sulfur recovery 

plant (in scf/year), the molar volume conversion factor (in 

scf/kg-mole), and the annual average mole fraction of carbon in 

the sour gas (in kg-mole C/kg-mole gas).

(5) If you recycle tail gas to the front of an on-site

sulfur recovery plant, indicate whether the recycled flow rate 

and carbon content are included in the measured data under 

§98.253(f)(2) and (3). Indicate whether a correction for CO2

emissions in the tail gas was used in Equation Y–12. If so, then 

report the value of the correction, the annual volume of 

recycled tail gas (in scf/year) and the annual average mole 

fraction of carbon in the tail gas (in kg-mole C/kg-mole gas). 

Indicate whether you used the default (95%) or a unit specific 

correction, and if a unit specific correction is used, report 

the approach used.

(6) If you use a CEMS, the relevant information required 

under §98.36 for the Tier 4 Calculation Methodology, the CO2

annual emissions as measured by the CEMS and the annual process 

CO2 emissions calculated according to §98.253(f)(1). Report the 

CO2 annual emissions associated with fuel combustion in 

accordance with subpart C of this part (General Stationary Fuel 

Combustion Sources).
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(7) If you use the process vent method in §98.253(j) for a 

non-Claus sulfur recovery plant, the relevant information 

required under paragraph (l)(5) of this section.

(i) For coke calcining units, the owner and operator shall 

report:

(1) The unit ID number (if applicable).

(2) Maximum rated throughput of the unit, in metric tons 

coke calcined/stream day.

(3) The calculated CO2, CH4, and N2O annual emissions for 

each unit, expressed in metric tons of each pollutant emitted.

(4) A description of the method used to calculate the CO2

emissions for each unit (e.g., reference section and equation 

number).

(5) If you use Equation Y–13 of this subpart, annual mass 

and carbon content of green coke fed to the unit, the annual 

mass and carbon content of marketable coke produced, the annual 

mass of coke dust removed from the process through dust 

collection systems, and an indication of whether coke dust is 

recycled to the unit (e.g., all dust is recycled, a portion of 

the dust is recycled, or none of the dust is recycled).

(6) If you use a CEMS, the relevant information required 

under §98.36 for the Tier 4 Calculation Methodology, the CO2

annual emissions as measured by the CEMS and the annual process 

CO2 emissions calculated according to §98.253(g)(1).
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(7) Indicate whether you use a measured value, a unitspecific emission factor or a default for CH4 emissions. If you 

use a unit-specific emission factor for CH4, the unit-specific 

emission factor for CH4, the units of measure for the unitspecific factor, the activity data for calculating emissions 

(e.g., if the emission factor is based on coke burn-off rate, 

the annual quantity of coke burned), and the basis for the 

factor.

(8) Indicate whether you use a measured value, a unitspecific emission factor, or a default emission factor for N2O 

emissions. If you use a unit-specific emission factor for N2O, 

report the unit-specific emission factor for N2O, the units of 

measure for the unit-specific factor, the activity data for 

calculating emissions (e.g., if the emission factor is based on 

coke burn-off rate, the annual quantity of coke burned), and the 

basis for the factor.

(j) For asphalt blowing operations, the owner or operator 

shall report:

(1) The unit ID number (if applicable).

(2) The quantity of asphalt blown (in million bbl) at the 

unit in the reporting year.

(3) The type of control device used to reduce methane (and 

other organic) emissions from the unit.
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(4) The calculated annual CO2 and CH4 emissions for each 

unit, expressed in metric tons of each pollutant emitted.

(5) If you use Equation Y–14 of this subpart, the CO2

emission factor used and the basis for the value.

(6) If you use Equation Y–15 of this subpart, the CH4

emission factor used and the basis for the value.

(7) If you use Equation Y–16 of this subpart, the carbon 

emission factor used and the basis for the value.

(8) If you use Equation Y–16b of this subpart, the CO2

emission factor used and the basis for its value and the carbon 

emission factor used and the basis for its value.

(9) If you use Equation Y–17 of this subpart, the CH4

emission factor used and the basis for the value.

(10) If you use Equation Y-19 of this subpart, the relevant 

information required under paragraph (l)(5) of this section.

(k) For delayed coking units, the owner or operator shall 

report:

(1) The cumulative annual CH4 emissions (in metric tons of 

CH4) for all delayed coking units at the facility.

(2) A description of the method used to calculate the CH4

emissions for each unit (e.g., reference section and equation 

number).

(3) The total number of delayed coking units at the 

facility, the total number of delayed coking drums at the 
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facility, and for each coke drum or vessel: The dimensions, the 

typical gauge pressure of the coking drum when first vented to 

the atmosphere, typical void fraction, the typical drum outage 

(i.e. the unfilled distance from the top of the drum, in feet), 

the molar volume conversion factor (in scf/kg-mole), and annual 

number of coke-cutting cycles.

(4) For each set of coking drums that are the same 

dimensions: The number of coking drums in the set, the height 

and diameter of the coke drums (in feet), the cumulative number 

of vessel openings for all delayed coking drums in the set, the 

typical venting pressure (in psig), void fraction (in cf gas/cf 

of vessel), and the mole fraction of methane in coking gas (in 

kg-mole CH4/kg-mole gas, wet basis).

(5) The basis for the volumetric void fraction of the coke 

vessel prior to steaming and the basis for the mole fraction of 

methane in the coking gas.

(6) If you use Equation Y-19 of this subpart, the relevant 

information required under paragraph (l)(5) of this section for 

each set of coke drums or vessels of the same size.

(l) For each process vent subject to §98.253(j), the owner 

or operator shall report:

(1) The vent ID number (if applicable).

(2) The unit or operation associated with the emissions.
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(3) The type of control device used to reduce methane (and 

other organic) emissions from the unit, if applicable.

(4) The calculated annual CO2, CH4, and N2O emissions for 

each vent, expressed in metric tons of each pollutant emitted.

(5) The annual volumetric flow discharged to the atmosphere 

(in scf), and an indication of the measurement or estimation 

method, annual average mole fraction of each GHG above the 

concentration threshold or otherwise required to be reported and 

an indication of the measurement or estimation method, the molar 

volume conversion factor (in scf/kg-mole), and for intermittent 

vents, the number of venting events and the cumulative venting 

time.

(m) For uncontrolled blowdown systems, the owner or 

operator shall report:

(1) An indication of whether the uncontrolled blowdown 

emission are reported under §98.253(k) or §98.253(j) or a 

statement that the facility does not have any uncontrolled 

blowdown systems.

(2) The cumulative annual CH4 emissions (in metric tons of 

CH4) for uncontrolled blowdown systems.

(3) For uncontrolled blowdown systems reporting under 

§98.253(k), the total quantity (in million bbl) of crude oil 

plus the quantity of intermediate products received from off 

site that are processed at the facility in the reporting year, 
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the methane emission factor used for uncontrolled blowdown 

systems, the basis for the value, and the molar volume 

conversion factor (in scf/kg-mole).

(4) For uncontrolled blowdown systems reporting under 

§98.253(j), the relevant information required under paragraph 

(l)(5) of this section.

(n) For equipment leaks, the owner or operator shall 

report:

(1) The cumulative CH4 emissions (in metric tons of each 

pollutant emitted) for all equipment leak sources.

(2) The method used to calculate the reported equipment 

leak emissions.

(3) The number of each type of emission source listed in 

Equation Y–21 of this subpart at the facility.

(o) For storage tanks, the owner or operator shall report:

(1) The cumulative annual CH4 emissions (in metric tons of 

CH4) for all storage tanks, except for those used to process 

unstabilized crude oil.

(2) For storage tanks other than those processing 

unstabilized crude oil:

(i) The method used to calculate the reported storage tank 

emissions for storage tanks other than those processing 

unstabilized crude (i.e., either AP 42, Section 7.1 
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(incorporated by reference, see §98.7), or Equation Y–22 of this 

section).

(ii) The total quantity (in MMbbl) of crude oil plus the 

quantity of intermediate products received from off site that 

are processed at the facility in the reporting year.

(3) The cumulative CH4 emissions (in metric tons of CH4) for 

storage tanks used to process unstabilized crude oil or a 

statement that the facility did not receive any unstabilized 

crude oil during the reporting year.

(4) For storage tanks that process unstabilized crude oil:

(i) The method used to calculate the reported unstabilized 

crude oil storage tank emissions.

(ii) The quantity of unstabilized crude oil received during 

the calendar year (in MMbbl).

(iii) The average pressure differential (in psi).

(iv) The molar volume conversion factor (in scf/kg-mole).

(v) The average mole fraction of CH4 in vent gas from 

unstabilized crude oil storage tanks and the basis for the mole 

fraction.

(vi) If you did not use Equation Y–23, the tank-specific 

methane composition data and the annual gas generation volume 

(scf/yr) used to estimate the cumulative CH4 emissions for

storage tanks used to process unstabilized crude oil.

(5) [Reserved]
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(6) [Reserved]

(7) [Reserved]

(p) For loading operations, the owner or operator shall 

report:

(1) The cumulative annual CH4 emissions (in metric tons of 

each pollutant emitted) for loading operations.

(2) The quantity and types of materials loaded by vessel 

type (barge, tanker, marine vessel, etc.) that have an 

equilibrium vapor-phase concentration of methane of 0.5 volume 

percent or greater, and the type of vessels in which the 

material is loaded.

(3) The type of control system used to reduce emissions 

from the loading of material with an equilibrium vapor-phase 

concentration of methane of 0.5 volume percent or greater, if 

any (submerged loading, vapor balancing, etc.).

(q) Name of each method listed in §98.254 or a description 

of manufacturer's recommended method used to determine a 

measured parameter.

§ 98.257 Records that must be retained.

In addition to the records required by §98.3(g), you must 

retain the records of all parameters monitored under §98.255. If 

you comply with the combustion methodology in §98.252(a), then 

you must retain under this subpart the records required for the 
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Tier 3 and/or Tier 4 Calculation Methodologies in §98.37 and you 

must keep records of the annual average flow calculations

§ 98.258 Definitions.

All terms used in this subpart have the same meaning given 

in the Clean Air Act and subpart A of this part.